Pepco 8-K Other Events

Exhibit 99.3

Management’s Report on Internal Control over Financial Reporting, Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and Related Notes Thereto, and Exhibits and Financial Statement Schedules

Management’s Report on Internal Control over Financial Reporting

The management of Pepco Holdings is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management of Pepco Holdings assessed Pepco Holdings’ internal control over financial reporting as of December 31, 2012 based on the framework inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of Pepco Holdings concluded that Pepco Holdings’ internal control over financial reporting was effective as of December 31, 2012.

PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the consolidated financial statements of Pepco Holdings included in the 2012 Annual Report on Form 10-K, has also issued its attestation report on the effectiveness of Pepco Holdings’ internal control over financial reporting, which is included herein.

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Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of

Pepco Holdings, Inc.

In our opinion, the consolidated financial statements listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Pepco Holdings, Inc. and its subsidiaries at December 31, 2012 and December 31, 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Washington, D.C.

February 28, 2013, except for the effects of discontinued operations described in Note 19 to the consolidated financial statements, as to which the date is August 30, 2013, and for the effects of the revision described in Note 2 to the consolidated financial statements, as to which the date is August 6, 2013.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Year Ended December 31,	2012			2011			2010
	(millions of dollars, except per share data)
Operating Revenue
Power Delivery	$	4,378		$	4,650		$	5,114
Pepco Energy Services		256			330			304
Other		41			32			42
Total Operating Revenue		4,675			5,012			5,460
Operating Expenses
Fuel and purchased energy		2,123			2,537			3,127
Other services cost of sales		170			172			140
Other operation and maintenance		901			895			857
Restructuring charge		—			—			30
Depreciation and amortization		454			425			392
Other taxes		432			451			434
Gains on early terminations of finance leases held in trust		(39	)		(39	)		—
Deferred electric service costs		(5	)		(63	)		(108	)
Impairment losses		12			—			—
Effects of Pepco divestiture-related claims		—			—			11
Total Operating Expenses		4,048			4,378			4,883
Operating Income		627			634			577
Other Income (Expenses)
Interest and dividend income		1			1			—
Interest expense		(266	)		(253	)		(292	)
Gain (loss) from equity investments		1			(3	)		(1	)
Loss on extinguishment of debt		—			—			(189	)
Impairment losses		(1	)		(5	)		—
Other income		35			32			22
Total Other Expenses		(230	)		(228	)		(460	)
Income from Continuing Operations Before Income Tax Expense		397			406			117
Income Tax Expense (Benefit) Related to Continuing Operations		138			148			(2	)
Net Income from Continuing Operations		259			258			119
Income (Loss) from Discontinued Operations, net of Income Taxes		26			(1	)		(87	)
Net Income	$	285		$	257		$	32
Basic Share Information
Weighted average shares outstanding – Basic (millions)		229			226			224
Earnings per share of common stock from Continuing Operations – Basic	$	1.13		$	1.14		$	0.53
Earnings (loss) per share of common stock from Discontinued Operations – Basic		0.12			—			(0.39	)
Earnings per share – Basic	$	1.25		$	1.14		$	0.14
Diluted Share Information
Weighted average shares outstanding – Diluted (millions)		230			226			224
Earnings per share of common stock from Continuing Operations – Diluted	$	1.12		$	1.14		$	0.53
Earnings (loss) per share of common stock from Discontinued Operations – Diluted		0.12			—			(0.39	)
Earnings per share – Diluted	$	1.24		$	1.14		$	0.14

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Year Ended December 31,	2012			2011			2010
	(millions of dollars)
Net Income	$	285		$	257		$	32
Other Comprehensive Income (Loss) from Continuing Operations
Losses on treasury rate locks reclassified into income		—			1			18
Pension and other postretirement benefit plans		(14	)		(11	)		—
Other comprehensive (loss) income, before income taxes		(14	)		(10	)		18
Income tax (benefit) expense related to other comprehensive income		(6	)		(4	)		7
Other comprehensive (loss) income from continuing operations, net of income taxes		(8	)		(6	)		11
Other Comprehensive Income from Discontinued Operations, Net of Income Taxes		23			49			124
Comprehensive Income	$	300		$	300		$	167

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS	December 31, 2012			December 31, 2011
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	25		$	109
Restricted cash equivalents		10			11
Accounts receivable, less allowance for uncollectible accounts of $34 million and $43 million, respectively		804			835
Inventories		153			125
Prepayments of income taxes		59			74
Deferred income tax assets, net		28			59
Prepaid expenses and other		150			190
Assets held for disposition		38			126
Total Current Assets		1,267			1,529
INVESTMENTS AND OTHER ASSETS
Goodwill		1,407			1,407
Regulatory assets		2,614			2,196
Investment in finance leases held in trust		1,237			1,349
Income taxes receivable		217			84
Restricted cash equivalents		17			15
Assets and accrued interest related to uncertain tax positions		18			37
Derivative assets		8			—
Other		163			163
Assets held for disposition		—			1
Total Investments and Other Assets		5,681			5,252
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		13,625			12,855
Accumulated depreciation		(4,779	)		(4,635	)
Net Property, Plant and Equipment		8,846			8,220
TOTAL ASSETS	$	15,794		$	15,001

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY	December 31, 2012			December 31, 2011
	(millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	965		$	732
Current portion of long-term debt and project funding		569			112
Accounts payable and accrued liabilities		554			488
Capital lease obligations due within one year		8			8
Taxes accrued		75			110
Interest accrued		47			47
Liabilities and accrued interest related to uncertain tax positions		9			3
Derivative liabilities		4			12
Other		272			273
Liabilities associated with assets held for disposition		40			151
Total Current Liabilities		2,543			1,936
DEFERRED CREDITS
Regulatory liabilities		501			526
Deferred income taxes, net		3,208			2,895
Investment tax credits		20			22
Pension benefit obligation		449			424
Other postretirement benefit obligations		454			469
Liabilities and accrued interest related to uncertain tax positions		15			32
Derivative liabilities		11			3
Other		191			191
Liabilities associated with assets held for disposition		2			19
Total Deferred Credits		4,851			4,581
LONG-TERM LIABILITIES
Long-term debt		3,648			3,794
Transition bonds issued by ACE Funding		256			295
Long-term project funding		12			13
Capital lease obligations		70			78
Total Long-Term Liabilities		3,986			4,180
COMMITMENTS AND CONTINGENCIES (NOTE 16)
EQUITY
Common stock, $.01 par value – authorized 400,000,000 shares, 230,015,427 and 227,500,190 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,383			3,325
Accumulated other comprehensive loss		(48	)		(63	)
Retained earnings		1,077			1,040
Total Equity		4,414			4,304
TOTAL LIABILITIES AND EQUITY	$	15,794		$	15,001

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Year Ended December 31,	2012			2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	285		$	257		$	32
(Income) loss from discontinued operations, net of income taxes		(26	)		1			87
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		454			425			392
Non-cash rents from cross-border energy lease investments		(50	)		(55	)		(55	)
Gains on early terminations of finance leases held in trust		(39	)		(39	)		—
Non-cash charge to reduce equity value of PHI’s cross-border energy lease investments		—			7			2
Effects of Pepco divestiture-related claims		—			—			11
Deferred income taxes		274			140			345
Losses on treasury rate locks reclassified into income		—			1			18
Impairment losses		12			—			—
Other		(15	)		(16	)		(19	)
Changes in:
Accounts receivable		(2	)		56			(113	)
Inventories		(28	)		(8	)		(3	)
Prepaid expenses		(12	)		(4	)		(1	)
Regulatory assets and liabilities, net		(174	)		(148	)		(154	)
Accounts payable and accrued liabilities		40			(51	)		114
Pension contributions		(200	)		(110	)		(100	)
Pension benefit obligation, excluding contributions		65			53			68
Cash collateral related to derivative activities		88			9			13
Income tax-related prepayments, receivables and payables		(122	)		11			(213	)
Other assets and liabilities		16			43			51
Assets held for disposition or sale		26			114			338
Net Cash From Operating Activities		592			686			813
INVESTING ACTIVITIES
Investment in property, plant and equipment		(1,216	)		(941	)		(802	)
Department of Energy capital reimbursement awards received		40			52			13
Proceeds from sale of Conectiv Energy wholesale power generation business		—			—			1,640
Proceeds from early terminations of finance leases held in trust		202			161			—
Changes in restricted cash equivalents		(1	)		(10	)		(2	)
Net other investing activities		6			(9	)		7
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		—			—			(138	)
Net Cash (Used By) From Investing Activities		(969	)		(747	)		718
FINANCING ACTIVITIES
Dividends paid on common stock		(248	)		(244	)		(241	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		51			47			47
Redemption of preferred stock of subsidiaries		—			(6	)		—
Issuances of long-term debt		450			235			383
Reacquisitions of long-term debt		(176	)		(70	)		(1,726	)
Issuances of short-term debt, net		233			198			4
Cost of issuances		(9	)		(10	)		(7	)
Net other financing activities		(8	)		(1	)		(6	)
Net financing activities associated with Conectiv Energy assets held for sale		—			—			(10	)
Net Cash From (Used By) Financing Activities		293			149			(1,556	)
Net (Decrease) Increase In Cash and Cash Equivalents		(84	)		88			(25	)
Cash and Cash Equivalents of Discontinued Operations		—			—			(1	)
Cash and Cash Equivalents at Beginning of Year		109			21			46
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	25		$	109		$	20
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $8 million, $11 million and $9 million, respectively)	$	253		$	240		$	310
Cash paid (received) for income taxes		—			4			(13	)
Non-cash activities:
Reclassification of property, plant and equipment to regulatory assets		88			—			—
Reclassification of asset removal costs regulatory liability to accumulated depreciation		61			—			—

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(millions of dollars, except shares)	Common Stock				Premium on Stock		Accumulated Other Comprehensive (Loss) Income			Retained Earnings			Total
	Shares		Par Value
BALANCE, DECEMBER 31, 2009		222,269,895	$	2	$	3,227	$	(241	)	$	1,236		$	4,224
Net Income		—		—		—		—			32			32
Other comprehensive income		—		—		—		135			—			135
Dividends on common stock ($1.08 per share)		—		—		—		—			(241	)		(241	)
Issuance of common stock:
Original issue shares, net		1,041,482		—		16		—			—			16
Shareholder DRP original shares		1,770,875		—		31		—			—			31
Net activity related to stock-based awards		—		—		1		—			—			1
BALANCE, DECEMBER 31, 2010		225,082,252		2		3,275		(106	)		1,027			4,198
Net Income		—		—		—		—			257			257
Other comprehensive income		—		—		—		43			—			43
Dividends on common stock ($1.08 per share)		—		—		—		—			(244	)		(244	)
Issuance of common stock:
Original issue shares, net		854,124		—		17		—			—			17
Shareholder DRP original shares		1,563,814		—		30		—			—			30
Net activity related to stock-based awards		—		—		3		—			—			3
BALANCE, DECEMBER 31, 2011		227,500,190		2		3,325		(63	)		1,040			4,304
Net Income		—		—		—		—			285			285
Other comprehensive income		—		—		—		15			—			15
Dividends on common stock ($1.08 per share)		—		—		—		—			(248	)		(248	)
Issuance of common stock:
Original issue shares, net		854,060		—		19		—			—			19
Shareholder DRP original shares		1,661,177		—		32		—			—			32
Net activity related to stock-based awards		—		—		7		—			—			7
BALANCE, DECEMBER 31, 2012		230,015,427	$	2	$	3,383	$	(48	)	$	1,077		$	4,414

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PEPCO HOLDINGS, INC.

(1) ORGANIZATION

Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a 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 electricity and natural gas retail supply business. Pepco Energy Services constitutes a separate segment for financial reporting purposes.

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

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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 Office Service in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) 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, and

• 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.

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.

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments. This activity constitutes a third operating segment for financial reporting purposes, which is designated as “Other Non-Regulated.” For a discussion of PHI’s cross-border energy lease investments, see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” and Note (20), “Subsequent Event.”

Discontinued Operations

Pepco Energy Services

In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business, which was comprised of the retail electric and natural gas supply businesses. Pepco Energy Services implemented the wind-down by not entering into any new retail electric or natural gas supply contracts while continuing to perform under its existing retail electric and natural gas supply contracts through their respective expiration dates. On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, Pepco Energy Services completed the wind-down of its retail electric supply business in the second quarter of 2013 by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013. The operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations 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 electric and natural gas supply businesses has been consolidated in Note (19), “Discontinued Operations.”

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Conectiv Energy

In April 2010, the Board of Directors approved a plan for the disposition of PHI’s competitive wholesale power generation, marketing and supply business, which had been conducted through subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy). On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.64 billion. The disposition of Conectiv Energy’s remaining assets and businesses, consisting of its load service supply contracts, energy hedging portfolio, certain tolling agreements and other assets not included in the Calpine sale, has been completed. The former operations of Conectiv Energy have been classified as a discontinued operation and are no longer treated as a separate segment for financial reporting purposes.

(2) SIGNIFICANT ACCOUNTING POLICIES

Consolidation Policy

The accompanying consolidated financial statements include the accounts of Pepco Holdings and its wholly owned subsidiaries. All material intercompany balances and transactions between subsidiaries have been eliminated. Pepco Holdings uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies in which it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held, are consolidated in proportion to PHI’s percentage interest in the facility.

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 years ended December 31, 2012, 2011 and 2010, were approximately $206 million, $218 million and $292 million, respectively, of which approximately $201 million, $206 million and $270 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

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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 December 31, 2012, PHI, through its DPL subsidiary, has entered into 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 $27 million, $18 million and $12 million for the years ended December 31, 2012, 2011 and 2010, 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 $2 million and $1 million for the years ended December 31, 2012 and 2011, 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 $4 million to distribution customers during the year ended December 31, 2012. 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 is accounting for this arrangement as an agency transaction.

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

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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 (14), “Derivative Instruments and Hedging Activities,” and Note (15), “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.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (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, the calculation of 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, 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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Storm Restoration Costs

The respective service territories of Pepco, DPL and ACE were affected by a rapidly moving thunderstorm with hurricane-force winds, known as a “derecho,” on June 29, 2012, and Hurricane Sandy on October 29, 2012. Both of these storms resulted in widespread customer outages in each of the service territories and caused extensive damage to the electric transmission and distribution systems of each utility.

Total incremental storm restoration costs incurred by PHI for the derecho and Hurricane Sandy through December 31, 2012 were $138 million, with $66 million incurred for repair work and $72 million incurred as capital expenditures. Costs incurred for repair work of $56 million were deferred as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland and New Jersey, and $10 million was charged to Other operation and maintenance expense. As of December 31, 2012, total incremental storm restoration costs include $33 million of estimated costs for unbilled restoration services provided by certain outside contractors. Actual costs for these services may vary from the estimates. PHI’s utility subsidiaries are pursuing recovery of these incremental storm restoration costs in their respective jurisdictions in their electric distribution base rate cases.

General and Auto Liability

During 2011, PHI’s utility subsidiaries reduced their self-insurance reserves for general and auto liability claims by approximately $4 million, based on obtaining an actuarial estimate of the unpaid losses attributed to general and auto liability claims for each of PHI’s utility subsidiaries. A similar evaluation was performed during 2012 and a reduction of less than $1 million was made to these reserves.

Accrual of Interest Associated with 1996 to 2002 Federal Income Tax Returns

In November 2010, PHI reached final settlement with the Internal Revenue Service (IRS) with respect to its federal tax returns for the years 1996 to 2002 for all issues except its cross-border energy lease investments. PHI also reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In connection with these activities, PHI has recalculated the estimated interest due for the tax years 1996 to 2002. These calculations resulted in the reversal of $15 million (after-tax) of previously accrued estimated interest due to the IRS which was recorded as an income tax benefit in the fourth quarter of 2010. PHI recorded a further $17 million (after-tax) income tax benefit in the second quarter of 2011.

Network Service Transmission Rates

In May of each year, each of PHI’s utility subsidiaries provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) effective for the service year beginning June 1 of the current year and ending May 31 of the following year. The network service transmission rate includes a true-up for costs incurred in the prior service year not yet reflected in rates charged to customers.

Investments in Finance Leases Held in Trust

As further discussed in Note (8), “Leasing Activities,” Note (12), “Income Taxes,” Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” and Note (20), Subsequent Event,” PHI maintains a portfolio of cross-border energy lease investments. The book equity value of these cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income are based on the estimated timing and amount of all cash flows related to the cross-border energy lease investments, including income

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tax-related cash flows. These investments are more commonly referred to as sale-in lease-out, or SILO, transactions. PHI currently derives tax benefits from these investments to the extent that rental income is exceeded by depreciation deductions based on the purchase price of the assets and interest deductions on the non-recourse debt financing (obtained to fund a substantial portion of the purchase price of the assets). The IRS has announced broadly its intention to disallow the tax benefits recognized by all taxpayers on these types of investments. More specifically, the IRS has disallowed interest and depreciation deductions claimed by PHI related to its cross-border energy lease investments on its 2001 through 2008 federal income tax returns, which currently are under audit and the IRS has sought to recharacterize the leases as loan transactions as to which PHI would be subject to original issue discount income.

In the last several years, IRS challenges to certain cross-border energy lease investment transactions have been the subject of litigation. PHI believes that its tax position with regard to its cross-border energy lease investments was appropriate based on applicable statutes, regulations and case law. However, after evaluating the court rulings available at the time, there have been several decisions in favor of the IRS that were factored into PHI’s decision to adjust the values of the cross-border energy lease investments at certain points in time.

Revenue Recognition

Regulated Revenue

Power Delivery recognizes revenue upon distribution of electricity and gas to its customers, including unbilled revenue for services rendered but not yet billed. PHI’s unbilled revenue was $182 million and $179 million as of December 31, 2012 and 2011, respectively, and these amounts are included in Accounts receivable. PHI’s utility subsidiaries calculate unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature and estimated line losses (estimates of electricity and gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material.

Taxes related to the consumption of electricity and gas by the utility customers, such as fuel, energy, or other similar taxes, are components of the tariff rates charged by PHI’s utility subsidiaries and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes are recorded in Other taxes. Excise tax related generally to the consumption of gasoline by PHI and its subsidiaries in the normal course of business is charged to operations, maintenance or construction, and is not material.

Pepco Energy Services Revenue

Pepco Energy Services has recognized revenue upon distribution of electricity and gas to customers, including amounts for electricity and gas delivered, but not yet billed. Sales and purchases of electric power to independent system operators are netted hourly and classified as operating revenue or operating expenses, as appropriate. Unrealized derivative gains and losses are recognized in current earnings as revenue if the derivatives do not qualify for hedge accounting or normal purchases or normal sales treatment under FASB guidance on derivatives and hedging (ASC 815). Revenue for Pepco Energy Services’ energy savings services business is recognized using the percentage-of-completion method, for its construction activities, which recognizes revenue as work is completed on the contract. Revenues from its operation and maintenance activities and measurement and verification activities in its energy savings services business are recognized when earned.

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Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in PHI’s gross revenues were $356 million, $378 million and $362 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Accounting for Derivatives

PHI and its subsidiaries use derivative instruments primarily to manage risk associated with commodity prices and interest rates. Risk management policies are determined by PHI’s Corporate Risk Management Committee (CRMC). The CRMC monitors interest rate fluctuation, commodity price fluctuation and credit risk exposure, and sets risk management policies that establish limits on unhedged risk.

PHI accounts for its derivative activities in accordance with FASB guidance on derivatives and hedging. Derivatives are recorded on the consolidated balance sheets as Derivative assets or Derivative liabilities and measured at fair value unless designated as normal purchases or normal sales.

Changes in the fair value of derivatives held by Pepco Energy Services, DPL or ACE that do not qualify for hedge accounting or are not designated as hedges are presented on the consolidated statements of income as Fuel and purchased energy expense or Operating revenue, respectively. Changes in the fair value of derivatives held by DPL and ACE are deferred as regulatory assets or liabilities under the accounting guidance for regulated activities.

The gain or loss on a derivative that qualifies as a cash flow hedge of an exposure to variable cash flows of a forecasted transaction is initially recorded in Accumulated Other Comprehensive Loss (AOCL) (a separate component of equity) to the extent that the hedge is effective and is subsequently reclassified into earnings, in the same category as the item being hedged, when the gain or loss from the forecasted transaction occurs. If it is probable that a forecasted transaction will not occur, the deferred gain or loss in AOCL is immediately reclassified to earnings. Gains or losses related to any ineffective portion of cash flow hedges are also recognized in earnings immediately as Operating revenue or as Fuel and purchased energy expense.

Changes in the fair value of derivatives designated as fair value hedges, as well as changes in the fair value of the hedged asset, liability or firm commitment, are recorded as Operating revenue in the consolidated statements of income.

The impact of derivatives that are marked to market through current earnings, the ineffective portion of cash flow hedges, and the portion of fair value hedges that flows to current earnings are presented on a net basis in the consolidated statements of income as Operating revenue or as Fuel and purchased energy expense. When a hedging gain or loss is realized, it is presented on a net basis in the same line item as the underlying item being hedged. Unrealized derivative gains and losses are presented gross on the consolidated balance sheets except where contractual netting agreements are in place with individual counterparties. See Note (14), “Derivative Instruments and Hedging Activities,” for more information about the components of unrealized and realized gains and losses on derivatives.

The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, pricing services and external broker quotes are used to determine fair value. For some custom and complex instruments, internal models are used to interpolate broker-quality price information. For certain long-dated instruments, broker or exchange data are extrapolated, or capacity prices are forecasted, for future periods where limited market information is available. Models are also used to estimate volumes for certain transactions. See Note (14), “Derivative Instruments and Hedging Activities,” for more information about the types of derivatives employed by PHI and Note (15), “Fair Value Disclosures,” for the methodologies used to value them.

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PHI designates certain commodity forwards as normal purchases or normal sales, which are not required to be recorded in the financial statements until they are settled. These commodity forwards are used in normal operations, settle physically and follow standard accrual accounting. Unrealized gains and losses on these contracts are not recorded in the financial statements. Examples of these commodity forwards include purchases by Pepco Energy Services of natural gas or electricity for delivery to customers. Normal sales transactions include agreements by Pepco Energy Services to deliver natural gas and electric power to customers. Normal purchases and normal sales transactions are separately presented on a gross basis when they settle, with normal sales recorded as Operating revenue and normal purchases recorded as Fuel and purchased energy expenses.

Stock-Based Compensation

PHI recognizes compensation expense for stock-based awards, modifications or cancellations based on the grant-date fair value. Compensation expense is recognized over the requisite service period. In addition, compensation expense recognized includes the cost for all stock-based awards granted prior to, but not yet vested as of January 1, 2006, measured at the grant-date fair value. A deferred tax asset and deferred tax benefit are also recognized concurrently with compensation expense for the tax effect of the deduction of stock options and restricted stock awards, which are deductible only upon exercise and vesting.

Historically, PHI’s compensation awards had included both time-based restricted stock awards that vest over a three-year service period and performance-based restricted stock units that were earned based on performance over a three-year period. Beginning in 2011, stock-based compensation awards have been granted primarily in the form of restricted stock units. The compensation expense associated with these awards is calculated based on the estimated fair value of the awards at the grant date and is recognized over the service or performance period.

PHI estimates the fair value of stock option awards on the date of grant using the Black-Scholes-Merton option pricing model. This model uses assumptions related to expected term, expected volatility, expected dividend yield, and the risk-free interest rate. PHI uses historical data to estimate award exercises and employee terminations within the valuation model; groups of employees that have similar historical exercise behavior are considered separately for valuation purposes.

PHI’s current policy is to issue new shares to satisfy vested awards of restricted stock units.

Income Taxes

PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement, which was approved by the Securities and Exchange Commission (SEC) in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss amounts.

The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on PHI’s and its subsidiaries’ federal and state income tax returns. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. See Note (12), “Income

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Taxes,” for a listing of primary deferred tax assets and liabilities. The portions of Pepco’s, DPL’s and ACE’s deferred tax liabilities applicable to their utility operations that have not been recovered from utility customers represent income taxes recoverable in the future and are included in Regulatory assets on the consolidated balance sheets. See Note (7), “Regulatory Matters – Regulatory Assets and Regulatory Liabilities,” for additional information.

PHI recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions and tax-related penalties in income tax expense. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

Investment tax credits are amortized to income over the useful lives of the related property.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less.

Restricted Cash Equivalents

The Restricted cash equivalents included in Current Assets and the Restricted cash equivalents included in Investments and Other Assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities.

Accounts Receivable and Allowance for Uncollectible Accounts

Pepco Holdings’ Accounts receivable balances primarily consist of customer accounts receivable, other accounts receivable, and accrued unbilled revenue generated by subsidiaries in Power Delivery and at Pepco Energy Services. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

PHI maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of income. PHI determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors, such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Although management believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, PHI records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

Inventories

Inventory is valued at the lower of cost or market value. Included in Inventories are generation, transmission and distribution materials and supplies, natural gas and fuel oil.

PHI utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

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The cost of natural gas, including transportation costs, is included in inventory when purchased and charged to Fuel and purchased energy expense when used.

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. Substantially all of Pepco Holdings’ goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to 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 performed its annual impairment test on November 1, 2012 and its goodwill was not impaired as described in Note (6), “Goodwill.”

Regulatory Assets and Regulatory Liabilities

The operations of Pepco are regulated by the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC). The operations of DPL are regulated by the DPSC and the MPSC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC. The operations of ACE are regulated by the NJBPU. The transmission of electricity by Pepco, DPL, and ACE is regulated by FERC.

The FASB guidance on regulated operations (ASC 980) applies to Power Delivery. It allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, then the regulatory asset would be eliminated through a charge to earnings.

Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers of Pepco and DPL. Effective November 2009, the DCPSC approved a BSA for Pepco’s retail customers. For customers to whom the BSA applies, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco and DPL recognize either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia 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 (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.

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Leasing Activities

Pepco Holdings’ lease transactions include plant, office space, equipment, software, vehicles and elements of PPAs. In accordance with FASB guidance on leases (ASC 840), these leases are classified as either leveraged leases, operating leases or capital leases.

Leveraged Leases

Income from investments in leveraged lease transactions, in which PHI is an equity participant, is accounted for using the financing method. In accordance with the financing method, investments in leased property are recorded as a receivable from the lessee to be recovered through the collection of future rentals. Income is recognized over the life of the lease at a constant rate of return on the positive net investment. Each quarter, PHI reviews the carrying value of each lease, which includes a review of the underlying financial assumptions, the timing and collectibility of cash flows, and the credit quality of the lessee. Changes to the underlying assumptions, if any, would be accounted for in accordance with FASB guidance on leases and reflected in the carrying value of the lease effective for the quarter within which they occur.

Operating Leases

An operating lease in which PHI or a subsidiary is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, PHI’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

Capital Leases

For ratemaking purposes, capital leases in which PHI or a subsidiary is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life.

Arrangements Containing a Lease

PPAs contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, PHI determines the appropriate lease accounting classification.

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation. For non-regulated property, the cost and accumulated depreciation of the property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition.

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The annual provision for depreciation on electric and gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The table below provides system-wide composite annual depreciation rates for the years ended December 31, 2012, 2011 and 2010.

	Transmission and Distribution									Generation
	2012			2011			2010			2012			2011			2010
Pepco		2.5	%		2.6	%		2.6	%		—			—			—
DPL		2.7	%		2.8	%		2.8	%		—			—			—
ACE		3.0	%		3.0	%		2.8	%		—			—			—
Pepco Energy Services (a)		—			—			—			6.4	%		10.2	%		16.9	%

(a) Percentages reflect accelerated depreciation of the Benning Road and Buzzard Point generating facilities retired during 2012.

In 2010, subsidiaries of PHI received awards from the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. Pepco was awarded $149 million to fund a portion of the costs incurred for the implementation of an advanced metering infrastructure (AMI) system (a system that collects, measures and analyzes energy usage data from advanced digital electric and gas meters known as smart meters), direct load control, distribution automation and communications infrastructure in its Maryland and District of Columbia service territories. ACE was awarded $19 million to fund a portion of the costs incurred for the implementation of direct load control, distribution automation and communications infrastructure in its New Jersey service territory. PHI has elected to recognize the awards as a reduction in the carrying value of the assets acquired rather than grant income over the service period.

Long-Lived Asset Impairment Evaluation

Pepco Holdings evaluates long-lived assets to be held and used, such as generating property and equipment, and real estate, for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets held for sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its fair value including costs to sell.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), PHI’s utility subsidiaries can capitalize the capital costs of financing the construction of plant and equipment as Allowance for Funds Used During Construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of income.

Pepco Holdings recorded AFUDC for borrowed funds of $7 million, $11 million and $8 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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Pepco Holdings recorded amounts for the equity component of AFUDC of $14 million, $15 million and $10 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Amortization of Debt Issuance and Reacquisition Costs

Pepco Holdings defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When PHI utility subsidiaries refinance existing debt or redeem existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized over the life of the original or new issue.

Asset Removal Costs

In accordance with FASB guidance, asset removal costs are recorded by PHI utility subsidiaries as regulatory liabilities. At December 31, 2012 and 2011, $324 million and $388 million of asset removal costs, respectively, are included in Regulatory liabilities in the accompanying consolidated balance sheets.

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors the PHI Retirement Plan, a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through a nonqualified retirement plan and provides certain postretirement health care and life insurance benefits for eligible retired employees.

Pepco Holdings accounts for the PHI Retirement Plan, the nonqualified retirement plans, and the retirement health care and life insurance benefit plans in accordance with FASB guidance on retirement benefits (ASC 715).

See Note (10), “Pension and Other Postretirement Benefits,” for additional information.

Reclassifications and Adjustments

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

Pepco Energy Services Derivative Accounting Adjustment

During 2011, PHI recorded an adjustment associated with an increase in the value of certain derivatives from October 1, 2010 to December 31, 2010, which had been erroneously recorded in other comprehensive income at December 31, 2010. This adjustment resulted in a decrease in Loss from Discontinued Operations, net of Income Taxes of $2 million for the year ended December 31, 2011.

DPL Operating Revenue Adjustment

During 2012, DPL recorded an adjustment to correct an overstatement of unbilled revenue in its natural gas distribution business related to prior periods. The adjustment resulted in a decrease in Operating revenue of $1 million for the year ended December 31, 2012.

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DPL Default Electricity Supply Revenue and Cost Adjustments

During 2011, DPL recorded adjustments to correct certain errors associated with the accounting for Default Electricity Supply revenue and costs. These adjustments primarily arose from the under-recognition of allowed returns on the cost of working capital and resulted in a pre-tax decrease in Other operation and maintenance expense of $11 million for the year ended December 31, 2011.

ACE BGS Deferred Electric Service Costs Adjustments

In 2012, ACE recorded an adjustment to correct errors associated with its calculation of deferred electric service costs. This adjustment resulted in an increase of $3 million to deferred electric service costs, all of which relates to periods prior to 2012.

Operating Expenses

During 2010, Pepco recorded an adjustment to correct certain errors related to other taxes which resulted in a decrease to Other taxes expense of $5 million (pre-tax) for the year ended December 31, 2010.

As further described in Note (9), “Property, Plant and Equipment,” in the fourth quarter of 2010, PHI recorded an accrual of $4 million for the obligations associated with the planned deactivation of Pepco Energy Services’ two oil-fired generating facilities. Of this amount, $1 million should have been recorded in each of 2009, 2008 and 2007.

Income Tax Expense Related to Continuing Operations

During 2011, PHI recorded adjustments to correct certain income tax errors related to prior periods associated with the interest on uncertain tax positions. The adjustment resulted in an increase in income tax expense of $2 million for the year ended December 31, 2011.

During 2010, PHI recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in a decrease in income tax expense of $5 million for the year ended December 31, 2010.

Revision to Prior Period Financial Statements

PCI Deferred Income Tax Liability Adjustment

Since 1999, PCI had not recorded a deferred tax liability related to a temporary difference between the financial reporting basis and the tax basis of an investment in a wholly owned partnership. In the second quarter of 2013, PHI re-evaluated this accounting treatment and found it to be in error, requiring an adjustment related to prior periods. PHI determined that the cumulative adjustment required, representing a charge to earnings of $32 million, related to a period prior to the year ended December 31, 2008 (the earliest period for which selected consolidated financial data were presented in the table entitled “Selected Financial Data” in Part II, Item 6 of PHI’s 2012 Annual Report on Form 10-K). Consistent with PHI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, the accompanying consolidated financial statements reflect the correction of this error as an adjustment to shareholders’ equity for the earliest period presented. The adjustment to correct the error did not affect PHI’s consolidated statements of income, comprehensive income and cash flows for each of the three years in the period ended December 31, 2012, and only affected PHI’s reported balances of deferred income tax liabilities and retained earnings as reflected in the consolidated balance sheets as of December 31, 2012 and 2011 and the reported balances of retained earnings and total equity as reflected in the consolidated statements of equity for each of the three years in the period ended December 31, 2012. The adjustment is not considered to be material to PHI’s reported balances of retained earnings and total equity reflected in the PHI consolidated financial statements included in PHI’s 2012 Annual Report on Form 10-K. The table below illustrates the effects of the revision on reported balances in PHI’s consolidated financial statements.

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	As Filed			Adjustment			As Revised
	(millions of dollars)
December 31, 2012
Deferred income tax liabilities, net	$	3,176		$	32		$	3,208
Total deferred credits		4,819	(a)		32			4,851
Retained earnings		1,109			(32	)		1,077
Total equity		4,446			(32	)		4,414
December 31, 2011
Deferred income tax liabilities, net	$	2,863		$	32		$	2,895
Total deferred credits		4,549	(a)		32			4,581
Retained earnings		1,072			(32	)		1,040
Total equity		4,336			(32	)		4,304
December 31, 2010
Retained earnings	$	1,059		$	(32	)	$	1,027
Total equity		4,230	(b)		(32	)		4,198
December 31, 2009
Retained earnings	$	1,268		$	(32	)	$	1,236
Total equity		4,256	(b)		(32	)		4,224

(a) The amount of total deferred credits differs from the amount originally reported in PHI’s 2012 Form 10-K due to certain reclassifications.

(b) The amount represents total shareholders’ equity, which excludes a non-controlling interest of $6 million.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Goodwill (ASC 350)

The FASB issued new guidance that changes the annual and interim assessments of goodwill for impairment. The new guidance modifies the required annual impairment test by giving entities the option to perform a qualitative assessment of whether it is more likely than not that goodwill is impaired before performing a quantitative assessment. The new guidance also amends the events and circumstances that entities should assess to determine whether an interim quantitative impairment test is necessary. As of January 1, 2012, PHI has adopted the new guidance and concluded it did not have a material impact on its consolidated financial statements.

Fair Value Measurements and Disclosures (ASC 820)

The FASB issued new guidance on fair value measurement and disclosures that was effective beginning with PHI’s March 31, 2012 consolidated financial statements. The new measurement guidance did not have a material impact on PHI’s consolidated financial statements and the new disclosure requirements are in Note (15), “Fair Value Disclosures,” of PHI’s consolidated financial statements.

Comprehensive Income (ASC 220)

The FASB issued new disclosure requirements for reporting comprehensive income that were effective beginning with PHI’s March 31, 2012 consolidated financial statements. PHI did not have to change the presentation of its comprehensive income because it had already reported comprehensive income in two separate but consecutive statements of income and comprehensive income. PHI also has provided the new required disclosures of the income tax effects of items in other comprehensive income and amounts reclassified from other comprehensive income to income on a quarterly basis in Note (17), “Accumulated Other Comprehensive Loss.”

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Balance Sheet (ASC 210)

The FASB issued new disclosure requirements for derivatives that will include information about the gross exposures 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. The new disclosures are effective beginning with PHI’s March 31, 2013 consolidated financial statements. PHI does not expect this guidance to have a material impact on its consolidated financial statements.

Comprehensive Income (ASC 220)

In February 2013, the FASB issued new disclosure requirements for reclassifications from accumulated other comprehensive income. The new disclosure requirements are effective for PHI beginning with its March 31, 2013 consolidated financial statements and will require 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 will include 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 does not expect this guidance to have a material impact on its consolidated financial statements.

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(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at December 31, 2012 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 years ended December 31, 2012, 2011 and 2010, is as follows:

	Year Ended December 31, 2012
	(millions of dollars)
	Power Delivery		Pepco Energy Services			Other Non- Regulated			Corporate and Other(a)			PHI Consolidated
Operating Revenue	$	4,378	$	256	(b)	$	52		$	(11	)	$	4,675
Operating Expenses (c)		3,847		271	(b)(d)		(34	)(e)		(36	)		4,048
Operating Income		531		(15	)		86			25			627
Interest Income		1		1			4			(5	)		1
Interest Expense		219		2			11			34			266
Impairment Losses		—		—			(1	)		—			(1	)
Other Income		32		1			—			3			36
Preferred Stock Dividends		—		—			3			(3	)		—
Income Tax Expense (Benefit)		110		(7	)		35	(f)		—			138
Net Income (Loss) from Continuing Operations		235		(8	)		40	(e)		(8	)		259
Total Assets		12,149		342			1,361			1,904			15,756
Construction Expenditures	$	1,168	$	11		$	—		$	37		$	1,216

(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 $(11) million for Operating Revenue, $(10) million for Operating Expenses, $(21) million for Interest Income, $(18) million for Interest Expense and $(3) million for Preferred Stock Dividends.

(b) Includes $9 million of intra-company revenues (and associated costs) previously eliminated in consolidation which will continue to be recognized from third parties subsequent to the completion of the wind-down of the Pepco Energy Services’ retail electric and natural gas supply businesses.

(c) Includes depreciation and amortization expense of $454 million, consisting of $416 million for Power Delivery, $14 million for Pepco Energy Services, $2 million for Other Non-Regulated and $22 million for Corporate and Other.

(d) Includes impairment losses of $12 million pre-tax ($7 million after-tax) at Pepco Energy Services associated primarily with investments in landfill gas-fired electric generation facilities, and the combustion turbines at Buzzard Point.

(e) Includes $39 million pre-tax ($9 million after-tax) gain from the early termination of finance leases held in trust.

(f) Includes a $16 million charge related to the recognition of the tax consequences associated with the early termination of finance leases held in trust.

	Year Ended December 31, 2011
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other(a)			PHI Consolidated
Operating Revenue	$	4,650	$	330	$	48	(b)	$	(16	)	$	5,012
Operating Expenses (c)		4,150		301		(30	)(b)(d)		(43	)		4,378
Operating Income		500		29		78			27			634
Interest Income		1		1		4			(5	)		1
Interest Expense		208		2		13			30			253
Impairment Losses		—		—		—			(5	)		(5	)
Other Income (Expenses)		29		2		(4	)		2			29
Preferred Stock Dividends		—		—		3			(3	)		—
Income Tax Expense (e)		112		8		27			1			148
Net Income (Loss) from Continuing Operations		210		22		35	(d)		(9	)		258
Total Assets		11,008		529		1,499			1,838			14,874
Construction Expenditures	$	888	$	14	$	—		$	39		$	941

(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 $(16) million for Operating Revenue, $(15) million for Operating Expense, $(22) million for Interest Income, $(22) million for Interest Expense, and $(3) million for Preferred Stock Dividends.

(b) Includes $15 million of intra-company revenues (and associated costs) previously eliminated in consolidation which will continue to be recognized from third parties subsequent to the completion of the wind-down of the Pepco Energy Services’ retail electric and natural gas supply businesses.

(c) Includes depreciation and amortization expense of $425 million, consisting of $394 million for Power Delivery, $16 million for Pepco Energy Services, $2 million for Other Non-Regulated, and $13 million for Corporate and Other.

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

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

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	Year Ended December 31, 2010
	(millions of dollars)
	Power Delivery			Pepco Energy Services			Other Non- Regulated			Corporate and Other(a)			PHI Consolidated
Operating Revenue	$	5,114		$	304	(b)	$	54		$	(12	)	$	5,460
Operating Expenses (c)(d)		4,611	(e)		280	(b)		6			(14	)		4,883
Operating Income		503			24			48			2			577
Interest Income		2			1			3			(6	)		—
Interest Expense		207			2			12			71			292
Other Income (Expenses)		20			2			(2	)		1			21
Loss on Extinguishment of Debt		—			—			—			(189	)(f)		(189	)
Preferred Stock Dividends		—			—			3			(3	)		—
Income Tax Expense (Benefit)		112	(g)		9			9			(132	)(h)		(2	)
Net Income (Loss) from Continuing Operations		206			16			25			(128	)		119
Total Assets		10,621			511			1,537			1,582			14,251
Construction Expenditures	$	765		$	7		$	—		$	30		$	802

(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 $(12) million for Operating Revenue, $(10) million for Operating Expense, $(36) million for Interest Income, $(36) million for Interest Expense, and $(3) million for Preferred Stock Dividends.

(b) Includes $17 million of intra-company revenues (and associated costs) previously eliminated in consolidation which will continue to be recognized from third parties subsequent to the completion of the wind-down of the Pepco Energy Services’ retail electric and natural gas supply businesses.

(c) Includes depreciation and amortization expense of $392 million, consisting of $357 million for Power Delivery, $23 million for Pepco Energy Services, $1 million for Other Non-Regulated, and $11 million for Corporate and Other.

(d) Includes restructuring charge of $30 million, consisting of $29 million for Power Delivery and $1 million for Corporate and Other.

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

(f) Includes $174 million ($104 million after-tax) related to loss on extinguishment of debt and $15 million ($9 million after-tax) related to the reclassification of treasury rate lock losses from AOCL to income related to cash tender offers for debt made in 2010.

(g) Includes $12 million of net Federal and state income tax benefits primarily related to adjustments of accrued interest on uncertain and effectively settled tax positions.

(h) Includes $14 million of state tax benefits resulting from the restructuring of certain PHI subsidiaries and $17 million of state income tax benefits associated with the loss on extinguishment of debt, partially offset by a charge of $3 million to write off deferred tax assets related to the subsidy pursuant to the prescription drug benefit (Medicare Part D) under the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Medicare Act).

(6) GOODWILL

Substantially all of PHI’s $1.4 billion goodwill balance as of December 31, 2012 and 2011 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.

In order to estimate the fair value of its Power Delivery reporting unit, PHI uses two valuation techniques: an income approach and a market approach. The income approach estimates fair value based on a discounted cash flow analysis using estimated future cash flows and a terminal value that is consistent with Power Delivery’s long-term view of the business. This approach uses a discount rate based on the estimated weighted average cost of capital (WACC) for the Power Delivery reporting unit. PHI determines the estimated WACC by considering market-based information for the cost of equity and cost of debt that is appropriate for Power Delivery as

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of the measurement date. The market approach estimates fair value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. PHI has consistently used this valuation framework to estimate the fair value of Power Delivery.

The estimation of fair value is dependent on a number of factors that are derived from the Power Delivery reporting unit’s business forecast, including but not limited to interest rates, growth assumptions, returns on rate base, operating and capital expenditure requirements, and other factors, changes in which could materially affect the results of impairment testing. Assumptions used in the models were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the Power Delivery reporting unit include utility sector market performance, sustained adverse business conditions, changes in forecasted revenues, higher operating and maintenance capital expenditure requirements, a significant increase in the cost of capital and other factors.

In addition to estimating the fair value of its Power Delivery reporting unit, PHI estimated the fair value of its other reporting units (Pepco Energy Services and Other Non-Regulated) at November 1, 2012. The sum of the fair value of all reporting units was reconciled to PHI’s market capitalization at November 1, 2012 to corroborate estimates of the fair value of its reporting units. The sum of the estimated fair values of all reporting units exceeded the market capitalization of PHI at November 1, 2012. PHI believes that the excess of the estimated fair value of PHI’s reporting units as compared to PHI’s market capitalization reflects a control premium that is reasonable when compared to control premiums observed in historical acquisitions in the utility industry and giving consideration to the current economic environment.

PHI’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2012 and 2011 were as follows:

	2012						2011
	Gross Amount		Accumulated Impairment Losses		Carrying Amount		Gross Amount		Accumulated Impairment Losses		Carrying Amount
	(millions of dollars)
Beginning balance as of January 1	$	1,425	$	18	$	1,407	$	1,425	$	18	$	1,407
Impairment losses		—		—		—		—		—		—
Ending balance as of December 31	$	1,425	$	18	$	1,407	$	1,425	$	18	$	1,407

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(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2012 and 2011 are as follows:

	2012		2011
	(millions of dollars)
Regulatory Assets
Pension and OPEB costs (a)	$	1,171	$	1,037
Securitized stranded costs (a)		416		481
Smart Grid (a)		229		142
Deferred energy supply costs (a)		183		126
Recoverable income taxes		177		145
Incremental storm restoration costs		89		28
MAPP abandonment costs (a)		88		—
Deferred debt extinguishment costs (a)		53		57
Recoverable workers compensation and long-term disability costs		31		34
Deferred losses on gas derivatives		4		17
Other		173		129
Total Regulatory Assets	$	2,614	$	2,196
Regulatory Liabilities
Asset removal costs	$	324	$	388
Deferred energy supply costs		78		33
Deferred income taxes due to customers		45		48
Excess depreciation reserve		11		26
Other		43		31
Total Regulatory Liabilities	$	501	$	526

(a) A return is generally earned on these deferrals.

A description for each category of regulatory assets and regulatory liabilities follows:

Pension and OPEB Costs: Represents unrecognized net actuarial losses, prior service cost (credit) and transition liability for Pepco Holdings’ defined benefit pension and other postretirement benefit (OPEB) plans that are expected to be recovered by Pepco, DPL and ACE in rates. The utilities have historically included these items as a part of its cost of service in its customer rates. This regulatory asset is adjusted at least annually when the funded status of Pepco Holdings’ defined benefit pension and OPEB plans are re-measured. See Note (10), “Pension and Other Postretirement Benefits,” for more information about the components of the unrecognized pension and OPEB costs.

Securitized Stranded Costs: Certain contract termination payments under a contract between ACE and an unaffiliated NUG and costs associated with the regulated operations of ACE’s

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electricity generation business are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by ACE Funding to securitize the recoverability of these stranded costs. These bonds mature between 2013 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds.

Smart Grid:Represents AMI costs associated with the installation of smart meters and the early retirement of existing meters throughout Pepco’s and DPL’s service territories that are recoverable from customers. Approval of AMI has been deferred by the NJBPU for ACE in New Jersey.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco, DPL and ACE that are probable of recovery in rates. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by Pepco, DPL and ACE to customers.

Recoverable Income Taxes: Represents amounts recoverable from Power Delivery’s customers for tax benefits applicable to utility operations of Pepco, DPL and ACE previously recognized in income tax expense before the companies were ordered to account for the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2012 and 2011, including Hurricane Sandy, the June 2012 derecho, Hurricane Irene and the 2011 severe winter storm (for Pepco), for which recovery through regulated utility rates is considered probable in the Maryland and New Jersey jurisdictions. Pepco’s and DPL’s costs related to Hurricane Irene and Pepco’s costs related to the 2011 severe winter storm are being amortized and recovered in rates over a five-year period. ACE’s costs related to Hurricane Irene are being amortized and recovered in rates over a three-year period.

MAPP Abandonment Costs: Represents the probable recovery of abandoned costs prudently incurred in connection with the Mid-Atlantic Power Pathway (MAPP) project which was terminated by PJM on August 24, 2012. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. The regulatory asset will be reduced as the result of sale or alternative use of these assets. These assets are currently earning a return of 12.8%.

Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment of Pepco, DPL and ACE associated with issuances of debt for which recovery through regulated utility rates is considered probable, and if approved, will be amortized to interest expense during the authorized rate recovery period.

Recoverable Workers’ Compensation and Long-Term Disability Costs: Represents accrued workers’ compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable through the Gas Cost Rate approved by the DPSC.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

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Asset Removal Costs: The depreciation rates for Pepco and DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, Pepco and DPL have recorded regulatory liabilities for their estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of Pepco and DPL that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Excess Depreciation Reserve: The excess depreciation reserve was recorded as part of an ACE New Jersey rate case settlement. This excess reserve is the result of a change in estimated depreciable lives and a change in depreciation technique from remaining life to whole life that caused an over-recovery for depreciation expense from customers when the remaining life method had been used. The excess is being amortized as a reduction in Depreciation and amortization expense over an 8.25 year period, which began in June 2005 and expires in 2013.

Other: Includes miscellaneous regulatory liabilities.

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 BSA was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. In October 2012, the MPSC modified the BSA so that a BSA surcharge is not permitted to be collected for revenues lost during the first 24 hours of a major storm. For further information on the BSA in Maryland, see “Maryland – BSA Proceeding” below.

• 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.

In an effort to reduce the shortfall in revenues due to the delay in time or lag between when costs are incurred and when they are reflected in rates (regulatory lag), Pepco and DPL had proposed, in each of their respective jurisdictions, (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases, and (ii) the use of fully forecasted test years in future rate cases (which reflect forward-looking costs in lieu of costs incurred over historical test years, and if approved, would be more reflective of current costs and would mitigate the effects of regulatory lag). These proposals were generally not adopted in any of the jurisdictions in which they were filed, as discussed below in connection with the discussions of Pepco’s and DPL’s respective electric distribution base rate proceedings.

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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 2011, DPL made its 2011 GCR filing. The filing included the second year of the effect of a two-year amortization of under-recovered gas costs proposed by DPL in its 2010 GCR filing (the settlement approved by the DPSC in its 2010 GCR case included only the first year of the proposed two-year amortization). The rates proposed in the 2011 GCR would result in a GCR decrease of approximately 5.6%. On August 21, 2012, the DPSC issued a final order approving the rates as filed.

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.

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. The filing included a request for DPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. In January 2012, the DPSC entered an order suspending the full increase and allowing a temporary rate increase of $2.5 million to go into effect on January 31, 2012, subject to refund and pending final DPSC approval. In July 2012, in accordance with an agreement with DPSC staff, DPL placed an additional $22.3 million of the requested rate increase into effect, also subject to refund and pending final DPSC order. On November 29, 2012, the DPSC approved a proposed settlement agreement entered into by DPL and the other parties to the proceeding that provides for an annual rate increase of $22 million, based on an ROE of 9.75%. The settlement agreement also permits DPL to collect from its standard offer service (SOS) customers (retail customers who do not elect to purchase electricity from a competitive supplier but instead purchase such electricity from DPL at regulated rates) approximately $3.4 million related to various state and local taxes that were assessed upon DPL’s SOS customers, but actually paid by DPL rather than by the SOS customers upon whom they were assessed. These taxes would be collected over a three-year period. In addition, the settlement agreement allows for the phase-in of the recovery of costs associated with DPL’s AMI system. The settlement agreement does not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it does provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag. DPL refunded the billed amounts that exceeded the increase approved by the DPSC in February 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

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increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. In compliance with state law and DPSC regulations, DPL also is requesting from the DPSC approval of a Utility Facilities Relocation Charge rider for recovery of future costs associated with the relocation of certain gas delivery service facilities that may be requested by the Delaware Department of Transportation. A final DPSC decision is expected by the third quarter of 2013.

District of Columbia

In July 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually (subsequently reduced to approximately $39 million), based on a requested ROE of 10.75%, of which approximately $9 million was sought so that Pepco could recover its costs associated with the AMI system. The filing included a request for DCPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. On September 26, 2012, the DCPSC issued its decision approving a rate increase of $24 million, based on an ROE of 9.5%, of which approximately $9 million allows Pepco to recover costs associated with the AMI system. The DCPSC denied Pepco’s request for approval of a RIM, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases. In addition, the DCPSC approved an adjustment by Pepco to normalize operation and maintenance expenses associated with storm restoration efforts to its three-year average, but added approximately $2 million of costs associated with Hurricane Irene from August 2011 in the calculation of the three-year average storm costs.

Maryland

DPL Electric Distribution Base Rates

In December 2011, DPL submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $25.2 million (subsequently reduced by DPL to $23.5 million), based on a requested ROE of 10.75%. The filing included a request for MPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $11.3 million, based on an ROE of 9.81%. The MPSC reduced DPL’s depreciation rates, which is expected to lower annual depreciation and amortization expenses by an estimated $4.1 million. The order did not approve DPL’s request to implement a 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 DPL’s rate base to reflect the actual costs of reliability plant additions outside the test year. The order also authorizes DPL to recover in rates over a five-year period $4.3 million of the $4.6 million of incremental storm restoration costs associated with Hurricane Irene that had been deferred previously as a regulatory asset by DPL. The new revenue rates and lower depreciation rates were effective on July 20, 2012.

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%. The filing included a request for MPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. 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%. The MPSC also directed Pepco to reduce the amount of the rate increase by approximately $1.6 million, the annual costs of certain energy advisory programs, resulting in a final rate increase of approximately $16.5 million. Pepco would be required to seek recovery of these annual costs through the EmPower Maryland Program (a demand-side management program) surcharge. The MPSC reduced Pepco’s depreciation rates, which is expected to lower annual depreciation and

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amortization expenses by an estimated $27.3 million. The lower depreciation rates resulted from, among other things, the rebalancing of excess reserves for estimated future removal costs identified in a depreciation study conducted as part of the rate case filing. The order did not approve Pepco’s request to implement a 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 Pepco’s rate base to reflect the actual costs of reliability plant additions outside the test year. The order authorizes Pepco to recover in rates over a five-year period $18.5 million of incremental storm restoration costs associated with major weather events in 2011, including $9.7 million of the $9.9 million of incremental storm restoration costs associated with Hurricane Irene that had been deferred previously as a regulatory asset by Pepco and $8.8 million of incremental storm restoration costs incurred by Pepco associated with a severe winter storm in the first quarter of 2011 that had been expensed previously through other operation and maintenance expense in 2011. The incremental storm restoration costs of $8.8 million were reversed and deferred as a regulatory asset in the third quarter of 2012. The order also authorizes Pepco to recover the actual cost of 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 surcharge 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 surcharge, if approved, would become effective January 1, 2014 and would 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 targets. Pepco requests that any credits/charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the end of the second quarter of 2013.

BSA Proceeding

As in effect for electric utilities in Maryland prior to October 26, 2012, including Pepco and DPL, a utility was not permitted to collect a BSA surcharge for distribution revenues lost as a result of major storm outages, beginning 24 hours after the commencement of a major storm, if electric service is not restored to the pre-major storm levels within 24 hours of the start of the storm. On October 26, 2012, the MPSC issued an order that no longer permits certain Maryland utilities, including Pepco and DPL, to collect a BSA surcharge for revenues lost during the first 24 hours of a major storm.

New Jersey

Electric Distribution Base Rates

In August 2011, ACE filed a petition with the NJBPU to increase its electric distribution rates by the net amount of approximately $54.6 million (which was increased to approximately $74.3 million on February 24, 2012, to reflect the 2011 test year), based on a requested ROE of

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10.75%. The modified net increase consists of a rate increase proposal of approximately $90.3 million, less a deduction from base rates of approximately $16 million through a credit rider expected to expire August 31, 2013, which is designed to refund to customers certain excess depreciation reserve funds as previously directed by the NJBPU (the Excess Depreciation Rider). ACE also proposed an increase of approximately $6.3 million in sales-and-use taxes related to the increase in base rates. On October 23, 2012, the NJBPU approved a stipulation of settlement signed by the parties (the New Jersey Settlement), which provides for an annual increase in ACE’s electric distribution base rates by the net amount of approximately $28 million, based on an ROE that, as part of the overall settlement, is deemed to be 9.75%. The net increase consists of a rate increase of approximately $44 million, less a deduction from base rates of approximately $16 million through the Excess Depreciation Rider. Upon expiration of the Excess Depreciation Rider, ACE will not realize an increase in operating income because the resulting increase in revenues will be offset by a substantially equivalent increase in depreciation expense. The New Jersey Settlement also provides for an increase of approximately $2 million in sales-and-use taxes related to the increase in base rates, and allows ACE to fully amortize over a three-year period the approximately $7.7 million in costs incurred as a result of Hurricane Irene in August 2011. The new rates became effective for utility services rendered on and after November 1, 2012.

On December 11, 2012, ACE filed with the NJBPU an application, 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 obligation to serve the public) in the amount of approximately $1.7 million. The requested rate increase is for the purposes of continuing to implement reliability-related investments, recovering system restoration costs associated with the June derecho storm and Hurricane Sandy, and providing an opportunity to earn a reasonable rate of return on its investment. An NJBPU decision is expected by the fourth quarter of 2013.

Infrastructure Investment Program

In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery by ACE of its infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism of a base rate filing. The IIP was designed to stimulate the New Jersey economy and provide incremental employment in ACE’s service territory by increasing the infrastructure expenditures to a level above otherwise normal budgeted levels. In an October 18, 2011 petition (subsequently amended December 16, 2011) filed with the NJBPU, ACE requested an extension and expansion to the IIP. The New Jersey Settlement approved by the NJBPU provided for full cost recovery of ACE’s initial IIP, as approved by the NJBPU in 2009, but required ACE to withdraw its request for extension and expansion to the IIP, without prejudice to file such request again in the future. On November 8, 2012, ACE withdrew its request for extension and expansion to the IIP.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, ACE filed 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

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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. The net impact of adjusting the charges as proposed (consisting of both the annual impact of the proposed 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, 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. 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 rates are deemed “provisional” because ACE’s filing will not be updated for actual revenues and expenses (if necessary) for May and June 2012 until after July 1, 2012, and a review of the final underlying costs for reasonableness and prudence will be completed after such filing.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether the EDCs in Maryland 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 certain Maryland EDCs, including Pepco and DPL, 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 acknowledges certain of the EDCs’ concerns about the requirements of the contract and directs them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specifies that the EDCs entering into the contract will recover the associated costs, in amounts proportional to their relative SOS loads, 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, Pepco, DPL, and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals have been consolidated in the Circuit Court for Baltimore City and have been stayed pending the issuance of a final order from the MPSC approving the form of contract, including the payment obligations of the utilities in the event the utilities do not recover the costs for such payments from their customers.

Until the final form of the contract with the winning bidder and associated cost recovery are approved, PHI cannot predict (i) the extent of the negative effect that the order and, once finalized, 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 order 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

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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. DPL will consider the Grid Resiliency Task Force recommendations in its next electric distribution base rate case expected to be filed with the MPSC in the first quarter of 2013.

In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force. The 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 has been extended to early March 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 (14), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest based on concerns about the potential cost to distribution customers. The dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration.

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 constitutionality of the New Jersey law under which the SOCAs were established. 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 tentatively scheduled to begin in March 2013.

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, PHI’s total capital expenditures related to the MAPP project were approximately $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, on December 21, 2012, PHI submitted a filing to FERC seeking recovery of approximately $88 million of abandoned MAPP capital expenditures. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred,

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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 have been submitted in response to the December 21, 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 abandonment costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. PHI cannot at this time estimate when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, PHI had placed in service approximately $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 approximately $88 million of capital expenditures to a regulatory asset. 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 the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

(8) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

PHI has a portfolio of cross-border energy lease investments (the lease portfolio) consisting of hydroelectric generation facilities, coal-fired electric generation facilities and natural gas distribution networks located outside of the United States. Each lease investment is comprised of a number of leases. As of December 31, 2012 and 2011, the lease portfolio consisted of six and seven investments with a net investment value of $1.2 billion and $1.3 billion, respectively.

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

	2012			2011
	(millions of dollars)
Scheduled lease payments to PHI, net of non-recourse debt	$	1,852		$	2,120
Less: Unearned and deferred income		(615	)		(771	)
Investment in finance leases held in trust		1,237			1,349
Less: Deferred income tax liabilities		(756	)		(793	)
Net investment in finance leases held in trust	$	481		$	556

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Income recognized from cross-border energy lease investments, excluding the gains on the terminated leases discussed below, was comprised of the following for the years ended December 31:

	2012		2011			2010
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in Other Revenue)	$	50	$	55		$	55
Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments		—		(7	)		(2	)
Pre-tax income from PHI’s cross-border energy lease investments after adjustment		50		48			53
Income tax expense related to PHI’s cross-border energy lease investments		10		10			14
Net income from PHI’s cross-border energy lease investments	$	40	$	38		$	39

During 2012, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the seven remaining lease investments. The early terminations of the leases were negotiated at the request of the lessees. PHI received net cash proceeds of $202 million (net of a termination payment of $520 million used to retire the non-recourse debt associated with the terminated leases) and recorded a pre-tax gain of $39 million, representing the excess of the net cash proceeds over the carrying value of the lease investments.

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

With respect to the terminated leases, PHI had previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. Because the leases were terminated in each case earlier than full term, management decided not to pursue these opportunities and recognized the related tax consequences by recording income tax charges in the amounts of $16 million and $22 million for the years ended December 31, 2012 and 2011, respectively. The after-tax gains on the lease terminations were $9 million and $3 million for the years ended December 31, 2012 and 2011, respectively, including the income tax charges discussed above and an income tax provision at the statutory Federal rate of $14 million for each early lease termination. As of December 31, 2012, PHI had no intent to terminate early any other leases in the lease portfolio and maintained its assertion that the foreign earnings recognized at the end of the lease term with respect to certain of these remaining leases will remain invested abroad. See Note (20), “Subsequent Event,” regarding an expected change in management’s intent.

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 tax benefits generated by the transactions, PHI is required to recalculate the value of its net investment. In that regard, PHI modified its tax cash flow assumptions both in 2011 and 2010

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and recorded non-cash pre-tax charges of $7 million and $2 million, respectively, to reduce the carrying value of its net investment. The tax cash flow assumptions changed in 2011 as a result of the enactment of tax regulations in the District of Columbia to implement the mandatory unitary combined reporting method and in 2010 as a result of an overall reassessment of tax cash flow assumptions. These charges as a result of the reassessments were recorded as reductions in cross-border energy lease investment revenue in each of 2011 and 2010.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion inConsolidated 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 it can no longer support its current assessment with respect to the likely outcome of tax positions associated with the cross-border energy lease investments and expects to record an after-tax non-cash charge of between $355 million and $380 million 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. While the IRS could require PHI to pay a penalty of up to 20 percent 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 will be included in the charge expected to be recorded in the first quarter of 2013.

For additional information concerning these cross-border energy lease investments, see Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” and Note (20), “Subsequent Event.”

Scheduled lease payments from the cross-border energy lease investments are net of non-recourse debt. Minimum lease payments receivable from the cross-border energy lease investments are zero for each year 2013 through 2017, and $1,237 million thereafter.

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 December 31, 2012, all lessees were in compliance with the terms and conditions of their lease agreements.

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

Lessee Rating (a)	2012		2011
	(millions of dollars)
Rated Entities
AA/Aa and above	$	766	$	737
A		471		612
Total		1,237		1,349
Non Rated Entities		—		—
Total	$	1,237	$	1,349

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

Lease Commitments

Pepco leases its consolidated control center, which is an integrated energy management center used by Pepco to centrally control the operation of its transmission and distribution systems. This lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments, which totaled $152 million. The lease requires semi-annual payments of approximately $8 million over a 25-year period that began in December 1994, and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under FASB guidance on regulated operations, the amortization of leased assets is modified so that the total interest expense charged on the obligation and amortization expense of the leased asset is equal to the rental expense allowed for rate-making purposes. The amortization expense is included within Depreciation and amortization in the consolidated statements of income. This lease is treated as an operating lease for rate-making purposes.

Capital lease assets recorded within Property, Plant and Equipment at December 31, 2012 and 2011, in millions of dollars, are comprised of the following:

	Original Cost		Accumulated Amortization		Net Book Value
At December 31, 2012
Transmission	$	76	$	37	$	39
Distribution		76		37		39
General		3		3		—
Total	$	155	$	77	$	78
At December 31, 2011
Transmission	$	76	$	33	$	43
Distribution		76		33		43
General		3		3		—
Total	$	155	$	69	$	86

The approximate annual commitments under all capital leases are $15 million for each year 2013 through 2017, and $32 million thereafter.

Rental expense for operating leases was $52 million, $46 million and $45 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Total future minimum operating lease payments for Pepco Holdings as of December 31, 2012, are $43 million in 2013, $40 million in 2014, $38 million in 2015, $36 million in 2016, $35 million in 2017 and $369 million thereafter.

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(9) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2012
Generation	$	107	$	97	$	10
Distribution		8,320		2,954		5,366
Transmission		2,783		866		1,917
Gas		458		137		321
Construction work in progress		692		—		692
Non-operating and other property		1,265		725		540
Total	$	13,625	$	4,779	$	8,846
At December 31, 2011
Generation	$	108	$	82	$	26
Distribution		7,832		2,848		4,984
Transmission		2,462		834		1,628
Gas		429		133		296
Construction work in progress		742		—		742
Non-operating and other property		1,282		738		544
Total	$	12,855	$	4,635	$	8,220

The non-operating and other property amounts include balances for general plant, intangible plant, distribution plant and transmission plant held for future use as well as other property held by non-utility subsidiaries. Utility plant is generally subject to a first mortgage lien.

Pepco Holdings’ utility subsidiaries use separate depreciation rates for each electric plant account. The rates vary from jurisdiction to jurisdiction.

Jointly Owned Plant

PHI’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At December 31, 2012 and 2011, PHI’s subsidiaries had a net book value ownership interest of $13 million in transmission and other facilities in which various parties also have ownership interests. PHI’s share of the operating and maintenance expenses of the jointly-owned plant is included in the corresponding expenses in the consolidated statements of income. PHI is responsible for providing its share of the financing for the above jointly-owned facilities.

Deactivation of Pepco Energy Services’ Generating Facilities

During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. The facilities were located in Washington, D.C. and had a generating capacity of approximately 790 megawatts. During the years ended December 31, 2012 and 2011, PHI has recorded decommissioning costs of $3 million and $2 million, respectively, related to these generating facilities.

Long-Lived Asset Impairment

At December 31, 2012, PHI recorded impairment losses of $12 million ($7 million after-tax) at Pepco Energy Services associated primarily with its investments in landfill gas-fired electric generation facilities and the reduction in the estimated net realizable value of the combustion turbines at Buzzard Point. PHI performed a long-lived asset impairment test on the landfill

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generation facilities of Pepco Energy Services as a result of a sustained decline in energy prices. The asset value of the facilities was written down to their estimated fair value because the future expected cash flows of the facilities were not sufficient to provide recovery of the facilities’ carrying value. PHI estimated the fair value of the facilities by calculating the present value of expected future cash flows using an appropriate discount rate. Both the expected future cash flows and the discount rate used primarily unobservable inputs.

Asset Retirement Obligations

PHI recognizes liabilities related to the retirement of long-lived assets in accordance with ASC 410. In connection with Pepco Energy Services’ decommissioning of the Buzzard Point and Benning Road generation facilities, PHI has recorded an asset retirement obligation of $9 million as of December 31, 2012 on its consolidated balance sheet.

The sale of the Conectiv Energy wholesale power generation business to Calpine did not include a coal ash landfill site located at the Edge Moor generating facility, which PHI intends to close. The preliminary estimate of the costs to PHI to close the coal ash landfill ranges from approximately $2 million to $3 million, plus annual post-closure operations, maintenance and monitoring costs for 30 years. PHI has recorded an asset retirement obligation of $6 million on its consolidated balance sheet related to the Edge Moor landfill.

(10) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pension Benefits and Other Postretirement Benefits

Pepco Holdings sponsors the PHI Retirement Plan, which covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings’ subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans.

Pepco Holdings provides certain postretirement health care and life insurance benefits for eligible retired employees. Most employees hired on January 1, 2005 or later will not have company subsidized retiree medical coverage; however, they will be able to purchase coverage at full cost through PHI.

Net periodic benefit cost 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 benefit cost.

Pepco Holdings accounts for the PHI Retirement Plan, nonqualified retirement plans, and its postretirement health care and life insurance benefits for eligible employees in accordance with FASB guidance on retirement benefits. PHI’s financial statement disclosures are also prepared in accordance with FASB guidance on retirement benefits.

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At December 31,	Pension Benefits						Other  Postretirement Benefits
	2012			2011			2012			2011
	(millions of dollars)
Change in Benefit Obligation
Projected benefit obligation at beginning of year	$	2,124		$	1,970		$	750		$	704
Service cost		35			35			7			5
Interest cost		107			107			35			37
Amendments		—			18			—			7
Actuarial loss		341			176			24			36
Benefits paid (a)		(113	)		(182	)		(41	)		(40	)
Termination benefits		—			—			—			1
Projected benefit obligation at end of year	$	2,494		$	2,124		$	775		$	750
Change in Plan Assets
Fair value of plan assets at beginning of year	$	1,694		$	1,632		$	281		$	275
Actual return on plan assets		252			127			38			—
Company contributions		206			117			43			46
Benefits paid (a)		(113	)		(182	)		(41	)		(40	)
Fair value of plan assets at end of year	$	2,039		$	1,694		$	321		$	281
Funded Status at end of year (plan assets less plan obligations)	$	(455	)	$	(430	)	$	(454	)	$	(469	)

(a) Other Postretirement Benefits paid is net of Medicare Part D subsidy receipts of $4 million and $2 million in 2012 and in 2011, respectively.

At December 31, 2012, PHI Retirement Plan assets were $2.0 billion and the accumulated benefit obligation was approximately $2.3 billion. At December 31, 2011, PHI’s Retirement Plan assets were approximately $1.7 billion and the accumulated benefit obligation was approximately $2.0 billion.

The following table provides the amounts recognized in PHI’s consolidated balance sheets as of December 31, 2012 and 2011:

	Pension Benefits						Other  Postretirement Benefits
	2012			2011			2012			2011
	(millions of dollars)
Regulatory asset	$	934		$	794		$	237		$	243
Current liabilities		(6	)		(6	)		—			—
Pension benefit obligation		(449	)		(424	)		—			—
Other postretirement benefit obligations		—			—			(454	)		(469	)
Deferred income taxes, net		22			15			—			—
Accumulated other comprehensive loss, net of tax		32			24			—			—
Net amount recognized	$	533		$	403		$	(217	)	$	(226	)

45

Amounts included in AOCL (pre-tax) and Regulatory assets at December 31, 2012 and 2011 consist of:

	Pension Benefits				Other  Postretirement Benefits
	2012		2011		2012			2011
	(millions of dollars)
Unrecognized net actuarial loss	$	979	$	822	$	238		$	247
Unamortized prior service cost (credit)		9		11		(1	)		(5	)
Unamortized transition liability		—		—		—			1
Total	$	988	$	833	$	237		$	243
Accumulated other comprehensive loss ($32 million and $24 million, net of tax, at December 31, 2012 and 2011, respectively)	$	54	$	39	$	—		$	—
Regulatory assets		934		794		237			243
Total	$	988	$	833	$	237		$	243

The estimated net actuarial loss and prior service cost for the defined benefit pension plans that will be amortized from AOCL or regulatory assets into net periodic benefit cost over the next reporting year are $68 million and $1 million, respectively. The estimated net actuarial loss and prior service credit for the OPEB plan that will be amortized from AOCL or regulatory assets into net periodic benefit cost over the next reporting year are $15 million and $4 million, respectively.

The table below provides the components of net periodic benefit costs recognized for the years ended December 31, 2012, 2011 and 2010:

	Pension Benefits									Other  Postretirement Benefits
	2012			2011			2010			2012			2011			2010
	(millions of dollars)
Service cost	$	35		$	35		$	35		$	7		$	5		$	5
Interest cost		107			107			110			35			37			39
Expected return on plan assets		(132	)		(128	)		(117	)		(18	)		(19	)		(16	)
Amortization of prior service cost		1			—			—			(4	)		(5	)		(5	)
Amortization of net actuarial loss		64			47			42			14			14			13
Recognition of benefit contract		—			—			—			—			—			—
Plan amendments		—			—			1			—			—			—
Termination benefits		—			—			3			1			1			6
Net periodic benefit cost	$	75		$	61		$	74		$	35		$	33		$	42

46

The table below provides the split of the combined pension and other postretirement net periodic benefit costs among subsidiaries for the years ended December 31, 2012, 2011 and 2010:

	2012		2011		2010
	(millions of dollars)
Pepco	$	39	$	43	$	40
DPL		23		23		28
ACE		24		21		23
Other subsidiaries		24		7		25
Total	$	110	$	94	$	116

The following weighted average assumptions were used to determine the benefit obligations at December 31:

	Pension Benefits						Other  Postretirement Benefits
	2012			2011			2012			2011
Discount rate		4.15	%		5.00	%		4.10	%		4.90	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%
Health care cost trend rate assumed for current year		—			—			8.00	%		8.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		—			—			5.00	%		5.00	%
Year that the cost trend rate reaches the ultimate trend rate		—			—			2018			2017

Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects, in millions of dollars:

	1-Percentage- Point  Increase		1-Percentage- Point  Decrease
Increase (decrease) in total service and interest cost	$	2	$	(1	)
Increase (decrease) in postretirement benefit obligation	$	33	$	(27	)

The following weighted average assumptions were used to determine the net periodic benefit cost for the years ended December 31:

	Pension Benefits									Other  Postretirement Benefits
	2012			2011			2010			2012			2011			2010
Discount rate		5.00	%		5.65	%		6.40	%		4.90	%		5.60	%		6.30	%
Expected long-term return on plan assets		7.25	%		7.75	%		8.00	%		7.25	%		7.75	%		8.00	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%

47

PHI utilizes an analytical tool developed by its actuaries to select the discount rate. The analytical tool utilizes a high-quality bond portfolio with cash flows that match the benefit payments expected to be made under the plans.

The expected long-term rate of return on pension plan assets and postretirement benefit plan assets was 7.25% and 7.75% as of December 31, 2012 and 2011, respectively. PHI uses a building block approach to estimate the expected rate of return on plan assets. Under this approach, the percentage of plan assets in each asset class according to PHI’s target asset allocation, at the beginning of the year, is applied to the expected asset return for the related asset class. PHI incorporates long-term assumptions for real returns, inflation expectations, volatility and correlations among asset classes to determine expected returns for a given asset allocation. The pension and postretirement benefit plan assets consist of equity, fixed income, real estate and private equity investments, and when viewed over a long-term horizon, are expected to yield a return on assets of 7.25% at December 31, 2012. PHI periodically reviews its asset mix and rebalances assets back to the target allocation.

In addition, for the 2012 Other Postretirement Benefit Plan valuation, the health care cost trend rate was 8.0% from 2012 to 2013, declining 0.5% per year to a rate of 5.0% for 2018 to 2019 and beyond. The 2011 valuation assumption was 8.0% from 2011 to 2012, declining 0.5% per year to a rate of 5.0% for 2017 to 2018 and beyond.

Benefit Plan Modifications

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

During 2011, PHI’s Board also approved a new, non-qualified Supplemental Executive Retirement Plan (SERP) which replaced PHI’s two pre-existing supplemental retirement plans, effective August 1, 2011. As of the effective date of the new SERP, the Conectiv SERP and the PHI Combined SERP were closed to new participants. The establishment of the new SERP is consistent with PHI’s efforts to align retirement benefits for PHI and its subsidiaries with current market practices and to provide similarly situated participants with retirement benefits that are the same or similar in value as compared to the benefits provided under the prior SERPs.

During 2011, PHI approved an increase in the medical benefit limits for certain employees in its postretirement health care benefit plan to align the limits with those provided to other employees. The amendment affects approximately 1,400 employees, of which 400 are retirees and 1,000 are active union employees. The effective date of the plan modification is January 1, 2012.

The additional liabilities and expenses for the benefit plan modifications described above did not have a material impact on PHI’s overall consolidated financial condition, results of operations or cash flows.

48

Plan Assets

Investment Policies and Strategies

In developing its allocation policy for the assets in the PHI Retirement Plan and the other postretirement benefit plan, PHI examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, PHI evaluated the risk and return tradeoffs of alternative asset classes and asset mixes given long-term historical relationships as well as prospective capital market returns. PHI also conducted an asset-liability study to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. PHI developed its asset mix guidelines by incorporating the results of these analyses with an assessment of its risk posture, and taking into account industry practices. PHI periodically evaluates its investment strategy to ensure that plan assets are sufficient to meet the benefit obligations of the plans. As part of the ongoing evaluation, PHI may make changes to its targeted asset allocations and investment strategy.

PHI’s pension investment strategy is designed to meet the following investment objectives:

• Generate investment returns that, in combination with funding contributions from PHI, provide adequate funding to meet all current and future benefit obligations of the plan.

• Provide investment results that meet or exceed the assumed long-term rate of return, while maintaining the funded status of the plan at acceptable levels.

• Improve funded status over time.

• Decrease contribution and expense volatility as funded status improves.

To achieve these investment objectives, PHI’s investment strategy divides the pension program into two primary portfolios:

Return-Seeking Assets – These assets are intended to provide investment returns in excess of pension liability growth and reduce existing deficits in the funded status of the plan. The category includes a diversified mix of U.S. large and small cap equities, non-U.S. developed and emerging market equities, real estate, and private equity.

Liability-Hedging Assets – These assets are intended to reflect the sensitivity of the plan’s liabilities to changes in discount rates. This category includes a diversified mix of long duration, primarily investment grade credit and U.S. treasury securities.

During 2011, PHI modified its pension investment policy and strategy to reduce the effects of future volatility of the fair value of its pension assets relative to its pension liabilities. The new asset-liability management strategy was implemented during 2011. Under the new asset-liability management strategy, the plan’s allocation to fixed income investments, primarily high quality, longer-maturity fixed income securities was increased, with a reduction in the allocation to equity investments. As a result of this modification, during 2011, PHI allocated approximately 54% of its pension plan assets to longer-maturity fixed income investments, 38% to public equity investments and 8% to alternative investments (real estate, private equity). At December 31, 2010, the PHI pension trust’s asset allocation included 40% in fixed income investments (intermediate maturity fixed income), 53% in public equity investments and 7% in alternative investments (real estate, private equity). PHI anticipates further increases in the allocation to fixed income investments, with a corresponding reduction in the allocation to equity and alternative investments as the funded status of its plan increases.

49

The change in overall investment strategy may result in a lower expected long-term rate of return assumption because of the shift in allocation from equities and alternative investments to fixed income. PHI’s 2012 pension costs are based on a 7.25% expected long-term rate of return assumption.

The PHI Retirement Plan asset allocations at December 31, 2012 and 2011, by asset category, were as follows:

	Plan Assets at December 31,						Target Plan Asset Allocation
Asset Category	2012			2011			2012			2011
Equity		30	%		36	%		32	%		38	%
Fixed Income		62	%		56	%		62	%		54	%
Other (real estate, private equity)		8	%		8	%		6	%		8	%
Total		100	%		100	%		100	%		100	%

PHI’s other postretirement benefit plan asset allocations at December 31, 2012 and 2011, by asset category, were as follows:

	Plan Assets at December 31,						Target Plan Asset Allocation
Asset Category	2012			2011			2012			2011
Equity		62	%		62	%		60	%		60	%
Fixed Income		36	%		36	%		35	%		35	%
Cash		2	%		2	%		5	%		5	%
Total		100	%		100	%		100	%		100	%

PHI will rebalance the plan asset portfolios when the actual allocations fall outside the ranges outlined in the investment policy or as funded status improves over a reasonable period of time.

Risk Management

Pension and other postretirement benefit plan assets may be invested in separately managed accounts in which there is ownership of individual securities, shares of commingled funds or mutual funds, or limited partnerships. Commingled funds and mutual funds are subject to detailed policy guidelines set forth in the fund’s prospectus or fund declaration, and limited partnerships are subject to the terms of the partnership agreement.

Separate account investment managers are responsible for achieving a level of diversification in their portfolio that is consistent with their investment approach and their role in PHI’s overall investment structure. Separate account investment managers must follow risk management guidelines established by PHI unless authorized in writing by PHI.

Derivative instruments are permissible in an investment portfolio to the extent they comply with policy guidelines and are consistent with risk and return objectives. Under no circumstances may such instruments be used speculatively or to leverage the portfolio. Separately managed accounts are prohibited from holding securities issued by the following firms:

• PHI and its subsidiaries,

• PHI’s pension plan trustee, its parent or its affiliates,

• PHI’s pension plan consultant, its parent or its affiliates, and

• PHI’s pension plan investment manager, its parent or its affiliates

50

Fair Value of Plan Assets

As defined in the FASB guidance on fair value measurement and disclosures (ASC 820), 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. The FASB’s fair value framework includes a hierarchy that prioritizes the inputs to valuation techniques 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). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument. Investments are classified within the fair value hierarchy as follows:

Level 1: Investments are valued using quoted prices in active markets for identical instruments.

Level 2: Investments are valued using other significant observable inputs (e.g., quoted prices for similar investments, interest rates, credit risks, etc).

Level 3: Investments are valued using significant unobservable inputs, including internal assumptions.

There were no significant transfers between level 1 and level 2 during the years ended December 31, 2012 and 2011.

The following tables present the fair values of PHI’s pension and other postretirement benefit plan assets by asset category within the fair value hierarchy levels, as of December 31, 2012 and 2011:

	Fair Value Measurements at December 31, 2012
	(millions of dollars)
Asset Category	Total		Quoted Prices in  Active Markets  for Identical Instruments (Level  1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Pension Plan Assets:
Equity
Domestic (a)	$	367	$	169	$	170	$	28
International (b)		254		250		1		3
Fixed Income (c)		1,256		—		1,243		13
Other
Private Equity		56		—		—		56
Real Estate		74		—		—		74
Cash Equivalents (d)		32		32		—		—
Pension Plan Assets Subtotal		2,039		451		1,414		174
Other Postretirement Plan Assets:
Equity (e)		199		171		28		—
Fixed Income (f)		115		115		—		—
Cash Equivalents		7		7		—		—
Postretirement Plan Assets Subtotal		321		293		28		—
Total Pension and Other Postretirement Plan Assets	$	2,360	$	744	$	1,442	$	174

(a) Predominantly includes domestic common stock and commingled funds.

(b) Predominantly includes foreign common and preferred stock and warrants.

(c) Predominantly includes corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds.

(d) Predominantly includes cash investment in short-term investment funds.

(e) Includes domestic and international commingled funds.

(f) Includes fixed income commingled funds.

51

	Fair Value Measurements at December 31, 2011
	(millions of dollars)
Asset Category	Total		Quoted Prices in  Active Markets  for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Pension Plan Assets:
Equity
Domestic (a)	$	411	$	165	$	221	$	25
International (b)		196		192		2		2
Fixed Income (c)		939		—		930		9
Other
Private Equity		64		—		—		64
Real Estate		65		—		—		65
Cash Equivalents (d)		19		19		—		—
Pension Plan Assets Subtotal		1,694		376		1,153		165
Other Postretirement Plan Assets:
Equity (e)		174		150		24		—
Fixed Income (f)		101		101		—		—
Cash Equivalents		6		6		—		—
Postretirement Plan Assets Subtotal		281		257		24		—
Total Pension and Other Postretirement Plan Assets	$	1,975	$	633	$	1,177	$	165

(a) Predominantly includes domestic common stock and commingled funds.

(b) Predominantly includes foreign common and preferred stock and warrants.

(c) Predominantly includes corporate bonds, government bonds, municipal bonds, and commingled funds.

(d) Predominantly includes cash investment in short-term investment funds.

(e) Includes domestic and international commingled funds.

(f) Includes fixed income commingled funds.

There were no significant concentrations of risk in pension and OPEB plan assets at December 31, 2012 and 2011.

Valuation Techniques Used to Determine Fair Value

Equity

Equity securities are primarily comprised of securities issued by public companies in domestic and foreign markets plus investments in commingled funds, which are valued on a daily basis. PHI can exchange shares of the publicly traded securities and the fair values are primarily sourced from the closing prices on stock exchanges where there is active trading, therefore they would be classified as level 1 investments. If there is less active trading, then the publicly traded securities would typically be priced using observable data, such as bid ask prices, and these measurements would be classified as level 2 investments. Investments that are not publicly traded and valued using unobservable inputs would be classified as level 3 investments.

Commingled funds with publicly quoted prices and active trading are classified as level 1 investments. For commingled funds that are not publicly traded and have ongoing subscription and redemption activity, the fair value of the investment is the net asset value (NAV) per fund share, derived from the underlying securities’ quoted prices in active markets, and are classified as level 2 investments. Investments in commingled funds with redemption restrictions that use NAV are classified as level 3 investments.

52

Fixed Income

Fixed income investments are primarily comprised of fixed income securities and fixed income commingled funds. The prices for direct investments in fixed income securities are generated on a daily basis. Like the equity securities, fair values generated from active trading on exchanges are classified as level 1 investments. Prices generated from less active trading with wider bid ask prices are classified as level 2 investments. If prices are based on uncorroborated and unobservable inputs, then the investments are classified as level 3 investments.

Commingled funds with publicly quoted prices and active trading are classified as level 1 investments. For commingled funds that are not publicly traded and have ongoing subscription and redemption activity, the fair value of the investment is the NAV per fund share, derived from the underlying securities’ quoted prices in active markets, and are classified as level 2 investments. Investments in commingled funds with redemption restrictions that use NAV are classified as level 3 investments.

Other – Private Equity and Real Estate

Investments in private equity and real estate funds are primarily invested in privately held real estate investment properties, trusts and partnerships, as well as equity and debt issued by public or private companies. As a practical expedient, PHI’s interest in the fund or partnership is estimated at NAV. PHI’s interest in these funds cannot be readily redeemed due to the inherent lack of liquidity and the primarily long-term nature of the underlying assets. Distribution is made through the liquidation of the underlying assets. PHI views these investments as part of a long-term investment strategy. These investments are valued by each investment manager based on the underlying assets. The majority of the underlying assets are valued using significant unobservable inputs and often require significant management judgment or estimation based on the best available information. Market data includes observations of the trading multiples of public companies considered comparable to the private companies being valued. The funds utilize valuation techniques consistent with the market, income and cost approaches to measure the fair value of certain real estate investments. As a result, PHI classifies these investments as level 3 investments.

The investments in private equity and real estate funds require capital commitments, which may be called over a specific number of years. Unfunded capital commitments as of December 31, 2012 and 2011 totaled $15 million and $28 million, respectively.

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (level 3) for investments in the pension plan for the years ended December 31, 2012 and 2011 are shown below:

	Fair Value Measurements Using Significant Unobservable Inputs
	(Level 3)
	(millions of dollars)
	Equity			Fixed Income			Private Equity			Real Estate			Total Level 3
Beginning balance as of January 1, 2012	$	27		$	9		$	64		$	65		$	165
Transfer in (out) of Level 3		—			2			—			—			2
Purchases		4			2			4			5			15
Sales		(4	)		(1	)		—			—			(5	)
Settlements		(1	)		1			(8	)		(5	)		(13	)
Unrealized gain/(loss)		4			—			(11	)		8			1
Realized gain		1			—			7			1			9
Ending balance as of December 31, 2012	$	31		$	13		$	56		$	74		$	174

53

	Fair Value Measurements Using Significant Unobservable Inputs
	(Level 3)
	(millions of dollars)
	Equity			Fixed Income			Private Equity			Real Estate			Total Level 3
Beginning balance as of January 1, 2011	$	30		$	3		$	62		$	55		$	150
Transfer in (out) of Level 3		—			—			—			—			—
Purchases		2			—			11			9			22
Sales		(5	)		(1	)		—			—			(6	)
Settlements		—			7			(11	)		(6	)		(10	)
Unrealized (loss)/gain		(1	)		—			(4	)		9			4
Realized gain/(loss)		1			—			6			(2	)		5
Ending balance as of December 31, 2011	$	27		$	9		$	64		$	65		$	165

Cash Flows

Contributions – PHI Retirement Plan

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. During 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. During 2011, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $40 million, $40 million and $30 million, respectively, which brought plan assets to the funding target level for 2011 under the Pension Protection Act.

On January 9, 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, which is expected to bring the PHI Retirement Plan assets to at least the funding target level for 2013 under the Pension Protection Act.

Contributions – Other Postretirement Benefit Plan

In 2012 and 2011, Pepco contributed $5 million and $7 million, respectively, DPL contributed $7 million and $6 million, respectively, and ACE contributed $7 million and $7 million, respectively, to the other postretirement benefit plan. In 2012 and 2011, contributions of $13 million were made by other PHI subsidiaries.

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Expected Benefit Payments

Estimated future benefit payments to participants in PHI’s pension and other postretirement benefit plans, which reflect expected future service as appropriate, are as follows:

Years	Pension Benefits		Other Postretirement Benefits		Expected Medicare Part  D Subsidies
	(millions of dollars)
2013	$	122	$	46	$	—
2014		127		47		—
2015		133		49		—
2016		137		49		—
2017		140		49		—
2018 through 2022	$	764	$	245	$	—

Medicare Prescription Drug Improvement and Modernization Act of 2003

On December 8, 2003, the Medicare Act became effective. The Medicare Act introduced Medicare Part D, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Pepco Holdings sponsors postretirement health care plans that provide prescription drug benefits that PHI plan actuaries have determined are actuarially equivalent to Medicare Part D. In 2012 and 2011, Pepco Holdings received $4 million and $2 million, respectively, in Federal Medicare prescription drug subsidies. PHI will not be receiving the Part D subsidy in 2013 and beyond due to the implementation of an Employer Group Waiver Plan which is not eligible for Part D reimbursements.

Pepco Holdings Retirement Savings Plan

Pepco Holdings has a defined contribution retirement savings plan. Participation in the plan is voluntary. All participants are 100% vested and have a nonforfeitable interest in their own contributions and in the Pepco Holdings’ company matching contributions, including any earnings or losses thereon. Pepco Holdings’ matching contributions were $12 million, $11 million and $11 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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(11) DEBT

Long-Term Debt

The components of long-term debt are shown below.

		At December 31,
Interest Rate	Maturity	2012		2011
		(millions of dollars)
First Mortgage Bonds
Pepco:
4.95% (a)(b)	2013	$	200	$	200
4.65% (a)(b)	2014		175		175
3.05%	2022		200		—
6.20% (a)(b)(c)	2022		110		110
5.375% (a)	2024		—		38
5.75% (a)(b)	2034		100		100
5.40% (a)(b)	2035		175		175
6.50% (a)(b)(c)	2037		500		500
7.90%	2038		250		250
ACE:
6.63%	2013		69		69
7.63%	2014		7		7
7.68%	2015 - 2016		17		17
7.75%	2018		250		250
6.80% (a)	2021		39		39
4.35%	2021		200		200
5.60% (a)	2025		—		4
4.875% (a)(b)(c)	2029		23		23
5.80% (a)(b)	2034		120		120
5.80% (a)(b)	2036		105		105
DPL:
6.40%	2013		250		250
5.22% (a)	2016		100		100
5.20% (a)	2019		—		31
0.75%-4.90% (a)(e)	2026		—		35
4.00%	2042		250		—
Total First Mortgage Bonds			3,140		2,798
Unsecured Tax-Exempt Bonds
DPL:
1.80% (d)	2025		—		15
2.30% (f)	2028		—		16
5.40%	2031		78		78
Total Unsecured Tax-Exempt Bonds		$	78	$	109

(a) Represents a series of first mortgage bonds issued by the indicated company (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued for the benefit of the company. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the company’s obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligations in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes or the company’s obligations in respect of the tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds obligations effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.

(b) Represents a series of Collateral First Mortgage Bonds issued by the indicated company that in accordance with its terms will, at such time as there are no first mortgage bonds of the issuing company outstanding (other than Collateral First Mortgage Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.

(c) Represents a series of Collateral First Mortgage Bonds as to which the indicated company has agreed in connection with the issuance of the corresponding series of senior notes that, notwithstanding the terms of the Collateral First Mortgage Bonds described in footnote (b) above, it will not permit the release of the Collateral First Mortgage Bonds as security for the series of senior notes for so long as the senior notes remain outstanding, unless the company delivers to the senior note trustee comparable secured obligations to secure the senior notes.

(d) On July 1, 2010, DPL purchased this series of tax-exempt bonds issued for the benefit of DPL by the Delaware Economic Development Authority (DEDA) pursuant to a mandatory repurchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. While DPL held the bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. On December 1, 2010, DPL resold the bonds to the public, at which time the interest rate on the bonds was changed from 5.50% to a fixed rate of 1.80%. The bonds were purchased by DPL on June 1, 2012 pursuant to a mandatory purchase obligation and then retired.

(e) These bonds bearing an interest rate of 4.90% were repurchased. On June 1, 2011, DPL resold these bonds that were subject to mandatory repurchase on May 1, 2011 at an interest rate of 0.75%. The bonds were purchased by DPL on June 1, 2012 pursuant to a mandatory purchase obligation and then retired.

(f) On July 1, 2010, DPL purchased this series of tax-exempt bonds issued for the benefit of DPL by DEDA pursuant to a mandatory repurchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. While DPL held the bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. On December 1, 2010, DPL resold the bonds to the public, at which time the interest rate on the bonds was changed from 5.65% to a fixed rate of 2.30%. The bonds were purchased by DPL on June 1, 2012 pursuant to a mandatory purchase obligation and then retired.

NOTE: Schedule is continued on next page.

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	Maturity	At December 31,
Interest Rate		2012			2011
		(millions of dollars)
Medium-Term Notes (unsecured)
DPL:
7.56% - 7.58%	2017	$	14		$	14
6.81%	2018		4			4
7.61%	2019		12			12
7.72%	2027		10			10
Total Medium-Term Notes (unsecured)			40			40
Recourse Debt
PCI:
6.59% - 6.69%	2014		11			11
Notes (secured)
Pepco Energy Services:
5.90% - 7.46%	2017-2024		15			15
Notes (unsecured)
PHI:
2.70%	2015		250			250
5.90%	2016		190			190
6.125%	2017		81			81
7.45%	2032		185			185
DPL:
5.00%	2014		100			100
5.00%	2015		100			100
Total Notes (unsecured)			906			906
Total Long-Term Debt			4,190			3,879
Net unamortized discount			(13	)		(12	)
Current portion of long-term debt			(529	)		(73	)
Total Net Long-Term Debt		$	3,648		$	3,794
Transition Bonds Issued by ACE Funding
4.46%	2016	$	19		$	29
4.91%	2017		75			102
5.05%	2020		54			54
5.55%	2023		147			147
Total			295			332
Net unamortized discount			—			—
Current portion of long-term debt			(39	)		(37	)
Total Net Long-Term Transition Bonds issued by ACE Funding		$	256		$	295

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The outstanding First Mortgage Bonds issued by each of Pepco, DPL and ACE are subject to a lien on substantially all of the issuing company’s property, plant and equipment.

For a description of the Transition Bonds issued by ACE Funding, see Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Transition Funding, LLC.” The aggregate amounts of maturities for long-term debt and Transition Bonds outstanding at December 31, 2012, are $568 million in 2013, $334 million in 2014, $409 million in 2015, $338 million in 2016, $135 million in 2017, and $2,701 million thereafter.

PHI’s long-term debt is subject to certain covenants. As of December 31, 2012, PHI and its subsidiaries were in compliance with all such covenants.

Long-Term Project Funding

As of December 31, 2012 and 2011, Pepco Energy Services had total outstanding long-term project funding (including current maturities) of $13 million and $15 million, respectively, related to energy savings contracts performed by Pepco Energy Services. The aggregate amounts of maturities for the project funding debt outstanding at December 31, 2012, are $1 million for 2013, $2 million for each year 2014 and 2015, $1 million for each year 2016 and 2017, and $6 million thereafter.

Bond Issuances

During 2012, Pepco issued $200 million of 3.05% first mortgage bonds due April 1, 2022. Net proceeds from the issuance of the long-term debt were used primarily (i) to repay Pepco’s outstanding commercial paper that was issued to temporarily fund capital expenditures and working capital, (ii) to fund the redemption, prior to maturity, of all of the $38.3 million outstanding of the 5.375% pollution control revenue refunding bonds due in 2024 issued by the Industrial Development Authority of the City of Alexandria, Virginia (IDA), on Pepco’s behalf and (iii) for general corporate purposes.

During 2012, DPL issued $250 million of 4.00% first mortgage bonds due June 1, 2042. Net proceeds from the issuance of the long-term debt were used primarily (i) to repay $215 million of DPL’s outstanding commercial paper that was issued (a) to temporarily fund capital expenditures and working capital and (b) to fund the redemption in June 2012, prior to maturity, of $65.7 million in aggregate principal amount of three series of outstanding tax-exempt pollution control refunding revenue bonds issued by DEDA for DPL’s benefit; (ii) to fund the redemption, prior to maturity, of $31 million of tax-exempt bonds issued by DEDA for DPL’s benefit; and (iii) for general corporate purposes.

Bond Redemptions

During 2012, all of the $38.3 million of the outstanding 5.375% pollution control revenue refunding bonds issued by IDA for Pepco’s benefit were redeemed. In connection with the redemption, Pepco redeemed all of the $38.3 million outstanding of its 5.375% first mortgage bonds due in 2024 that secured the obligations under the pollution control bonds.

During 2012, DPL funded the redemption by DEDA, prior to maturity, of $65.7 million of outstanding tax-exempt pollution control refunding revenue bonds issued by DEDA for DPL’s benefit, as described above. Of the pollution control refunding revenue bonds redeemed, $34.5 million in aggregate principal amount bore interest at 0.75% per year and matured in 2026, $15.0 million in aggregate principal amount bore interest at 1.80% per year and matured in 2025, and $16.2 million in aggregate principal amount bore interest at 2.30% per year and matured in 2028. In connection with such redemption, on June 1, 2012, DPL redeemed, prior to maturity, all of the

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$34.5 million in aggregate principal amount outstanding of its 0.75% first mortgage bonds due 2026 that secured the obligations under one of the series of pollution control refunding revenue bonds redeemed by DEDA.

During 2012, DPL redeemed, prior to maturity, $31 million of 5.20% tax-exempt pollution control refunding revenue bonds due 2019, issued by DEDA for DPL’s benefit. Contemporaneously with this redemption, DPL redeemed $31 million of its outstanding 5.20% first mortgage bonds due 2019 that secured the obligations under the pollution control bonds.

During 2012, ACE redeemed, prior to maturity, $4 million of 5.60% tax-exempt pollution control revenue bonds due 2025 issued by the Industrial Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit. Contemporaneously with this redemption, ACE redeemed, prior to maturity, $4 million of its outstanding 5.60% first mortgage bonds due 2025 that secured the obligations under the pollution control bonds.

Short-Term Debt

PHI and its regulated utility subsidiaries have traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. A detail of the components of PHI’s short-term debt at December 31, 2012 and 2011 is as follows:

	2012		2011
	(millions of dollars)
Commercial paper	$	637	$	586
Variable rate demand bonds		128		146
Term loan agreement		200		—
Total	$	965	$	732

Commercial Paper

PHI, Pepco, DPL and ACE maintain ongoing commercial paper programs to address short-term liquidity needs. As of December 31, 2012, 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, Pepco, DPL and ACE had $264 million, $231 million, $32 million and $110 million, respectively, of commercial paper outstanding at December 31, 2012. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2012 was 0.87%, 0.43%, 0.43% and 0.41%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2012 was ten, five, four and three days, respectively.

PHI, Pepco and DPL had $465 million, $74 million and $47 million, respectively, of commercial paper outstanding at December 31, 2011. ACE had no commercial paper outstanding at December 31, 2011. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2011 was 0.64%, 0.35%, 0.34% and 0.33%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE in 2011 was eleven, two, two and six days, respectively.

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Variable Rate Demand Bonds

PHI’s utility subsidiaries DPL and ACE, each have outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. PHI expects that any bonds submitted for purchase will be remarketed successfully due to the creditworthiness of the issuer and, as applicable, the credit support, and because the remarketing resets the interest rate to the then-current market rate. The bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of December 31, 2012, $105 million of VRDBs issued by DPL (of which $72 million was secured by Collateral First Mortgage Bonds issued by DPL) and $23 million of VRDBs issued by ACE were outstanding.

The VRDBs outstanding at December 31, 2012 mature as follows: 2014 to 2017 ($49 million), 2024 ($33 million) and 2028 to 2029 ($46 million). The weighted average interest rate for VRDBs was 0.34% during 2012 and 0.44% during 2011.

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 at December 31, 2012 was $650 million for PHI, $350 million for Pepco and $250 million for each of 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 (LIBOR) plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial 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

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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 December 31, 2012.

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 December 31, 2012 and 2011, 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 $861 million and $994 million, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of $477 million and $711 million at December 31, 2012 and 2011, respectively.

Term Loan Agreement

During 2012, PHI entered into a $200 million term loan agreement, pursuant to which PHI has borrowed (and may not reborrow) $200 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to 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 December 31, 2012, outstanding borrowings under the loan agreement bore interest at an annual rate of 1.095%, 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 April 23, 2013.

PHI used the net proceeds of the borrowings under the term loan agreement to repay outstanding commercial paper obligations 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 December 31, 2012.

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Loss on Extinguishment of Debt

During 2010, PHI recorded a pre-tax loss on extinguishment of debt of $189 million ($113 million after-tax), which is further discussed below.

During 2010, PHI purchased, pursuant to a cash tender offer, $640 million in principal amount of its 6.45% Senior Notes due 2012 (6.45% Notes), redeemed the remaining $110 million of outstanding 6.45% Notes, and purchased, pursuant to a cash tender offer, $129 million of its 6.125% Senior Notes due 2017 (6.125% Notes) and $65 million of 7.45% Senior Notes due 2032 (7.45% Notes). In connection with these transactions, PHI recorded a pre-tax loss on extinguishment of debt of $120 million.

During 2010, PHI purchased, pursuant to a cash tender offer, an additional $40 million of outstanding 6.125% Notes. In addition, PHI redeemed all of its $200 million 6% Notes due 2019 and $10 million of its 5.9% Notes due 2016. PHI recorded a pre-tax loss on extinguishment of debt of approximately $54 million in 2010 in connection with this transaction.

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

(12) INCOME TAXES

PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement that was approved by the SEC in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.

The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below.

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Provision for Consolidated Income Taxes – Continuing Operations

	For the Year Ended December 31,
	2012			2011			2010
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(92	)	$	8		$	(281	)
State and local		(41	)		4			(52	)
Total Current Tax (Benefit) Expense		(133	)		12			(333	)
Deferred Tax Expense (Benefit)
Federal		216			121			300
State and local		58			19			34
Investment tax credit amortization		(3	)		(4	)		(3	)
Total Deferred Tax Expense		271			136			331
Total Consolidated Income Tax Expense Related to Continuing Operations	$	138		$	148		$	(2	)

Reconciliation of Consolidated Income Tax Expense – Continuing Operations

	For the Year Ended December 31,
	2012					2011					2010
	(millions of dollars)
Income tax at Federal statutory rate	$	139		35.0	%	$	142		35.0	%	$	41		35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		19		4.8	%		22		5.4	%		(2	)	(1.7	)%
Asset removal costs		(11	)	(2.8	)%		(7	)	(1.7	)%		(3	)	(2.6	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(8	)	(2.0	)%		(11	)	(2.7	)%		(6	)	(5.1	)%
Change in state deferred tax balances as a result of restructuring		—		—			—		—			(6	)	(5.1	)%
Cross-border energy lease investments		12		3.0	%		16		3.9	%		(5	)	(4.3	)%
Deferred tax basis adjustments		(1	)	(0.2	)%		2		0.5	%		(3	)	(2.6	)%
Depreciation		(1	)	(0.2	)%		—		—			(3	)	(2.6	)%
Investment tax credit amortization		(3	)	(0.8	)%		(4	)	(1.0	)%		(4	)	(3.4	)%
Reversal of valuation allowances		—		—			—		—			(8	)	(6.8	)%
State tax benefits related to prior years’ asset dispositions		—		—			(4	)	(1.0	)%		—		—
Other, net		(8	)	(2.0	)%		(8	)	(1.9	)%		(3	)	(2.5	)%
Consolidated Income Tax Expense Related to Continuing Operations	$	138		34.8	%	$	148		36.5	%	$	(2	)	(1.7	)%

Year ended December 31, 2012

The effective income tax rate for the year ended December 31, 2012 reflects charges related to the recognition of the tax consequences associated with the early termination of cross-border energy leases in the third quarter of 2012 of $16 million as discussed in Note (8), “Leasing Activities.”

In addition, the effective income tax rate for the year ended December 31, 2012 includes income tax benefits of $10 million 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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The rate for the year ended December 31, 2012 also reflects an increase in deductible asset removal costs for Pepco in 2012 related to a higher level of asset retirements.

Year ended December 31, 2011

PHI’s effective income tax rate in 2011 was significantly affected by changes in estimates and interest related to uncertain and effectively settled tax positions. In 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement (discussed below) for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, PHI recorded an additional tax benefit of $17 million (after-tax) which was recorded in the second quarter of 2011. Further, PHI recalculated interest on its uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the IRS in 2006, which resulted in additional tax expense of $3 million (after-tax).

As discussed further in Note (8), “Leasing Activities,” during the second quarter of 2011, PHI terminated early its interest in certain cross-border energy leases prior to the end of their stated terms. As a result, PHI recognized a $22 million charge related to the tax consequences associated with the early terminations.

In addition, as discussed further in Note (16), “Commitments and Contingencies – District of Columbia Tax Legislation,” on June 14, 2011, the Council of the District of Columbia approved the Fiscal Year 2012 Budget Support Act of 2011 (the Budget Support Act). The Budget Support Act includes a provision that requires corporate taxpayers in the District of Columbia to calculate taxable income allocable or apportioned to the District by reference to the income and apportionment factors applicable to commonly controlled entities organized within the United States that are engaged in a unitary business. Previously, only the income of companies with direct nexus to the District of Columbia was taxed. As a result of the change, during 2011 PHI recorded additional state income tax expense of $2 million.

Year ended December 31, 2010

In April 2010, as part of an ongoing effort to simplify PHI’s organizational structure, certain of PHI’s subsidiaries were converted from corporations to single member limited liability companies. In addition to increased organizational flexibility and reduced administrative costs, converting these entities to limited liability companies allows PHI to include income or losses in the former corporations in a single state income tax return, thus increasing the utilization of state income tax attributes. As a result of inclusions of income or losses in a single state return as discussed above, PHI recorded an $8 million benefit by reversing valuation allowances on certain state net operating losses and an additional benefit of $6 million resulting from changes to certain state deferred income tax benefits. In addition, conversion to limited liability companies caused PHI’s separate company losses (primarily related to the loss on the extinguishment of debt) to be subjected to state income taxes in new jurisdictions, resulting in minimal consolidated state taxable income in 2010.

In November 2010, PHI reached final settlement with the IRS with respect to its federal tax returns for the years 1996 to 2002 for all issues except its cross-border energy lease investments. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and

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reallocations, PHI recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in the reversal of $15 million (after-tax) of estimated interest due to the IRS. This reversal was recorded as an income tax benefit in the fourth quarter of 2010 and PHI recorded an additional tax benefit of $17 million (after-tax) in the second quarter of 2011 when the IRS finalized its calculation of the amount due. Offsetting the 2010 benefit was the reversal of $6 million (after-tax) of erroneously accrued state interest receivable recorded in the first quarter of 2010 and $2 million (after-tax) of other adjustments.

Also in the fourth quarter of 2010, PHI corrected the tax accounting for software amortization. Accordingly, a regulatory asset was established and income tax expense was reduced by $4 million.

Components of Consolidated Deferred Tax Liabilities (Assets)

	At December 31,
	2012			2011
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	2,299		$	1,871
Deferred electric service and electric restructuring liabilities		110			131
Cross-border energy lease investments		756			793
Federal and state net operating losses		(394	)		(220	)
Valuation allowances on state net operating losses		21			21
Pension and other postretirement benefits		128			130
Deferred taxes on amounts to be collected through future rates		58			47
Other		204	(a)		64	(a)
Total Deferred Tax Liabilities, net		3,182	(a)		2,837	(a)
Deferred tax assets included in Current Assets		28			59
Deferred tax liabilities included in Other Current Liabilities		(2	)		(1	)
Total Consolidated Deferred Tax Liabilities, net non-current	$	3,208	(a)	$	2,895	(a)

(a) The amounts for Other, Total Deferred Tax Liabilities, net, and Total Consolidated Deferred Tax Liabilities, net non-current, are presented after the effect of the revision to prior period financial statements discussed in Note (2), “Significant Accounting Policies – Revision to Prior Period Financial Statements.”

The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to PHI’s utility operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a Regulatory asset on the balance sheet. Federal and state net operating losses generally expire over 20 years from 2029 to 2032.

The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on Pepco’s, DPL’s and ACE’s property continue to be amortized to income over the useful lives of the related property.

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Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2012			2011			2010
	(millions of dollars)
Beginning balance as of January 1,	$	357		$	395		$	246
Tax positions related to current year:
Additions		1			2			150
Reductions		—			—			—
Tax positions related to prior years:
Additions		79			20			35
Reductions		(235	)		(57	)		(36	)
Settlements		(2	)		(3	)		—
Ending balance as of December 31,	$	200		$	357		$	395

Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate

Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Unrecognized tax benefits at December 31, 2012 included $36 million that, if recognized, would lower the effective tax rate.

Interest and Penalties

PHI recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2012, 2011 and 2010, PHI recognized $23 million of pre-tax interest income ($14 million after-tax), $23 million of pre-tax interest income ($14 million after-tax), and $2 million of pre-tax interest income ($1 million after-tax), respectively, as a component of income tax expense related to continuing operations. As of December 31, 2012, 2011 and 2010, PHI had accrued interest receivable of $10 million, accrued interest payable of $4 million and accrued interest payable of $12 million, respectively, related to effectively settled and uncertain tax positions.

Possible Changes to Unrecognized Tax Benefits

It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of PHI’s uncertain tax positions will significantly increase or decrease within the next 12 months. The possible resolution of the cross-border energy lease investments issue, the 2003 to 2008 Federal audits or state audits could impact the balances and related interest accruals significantly. See Note (16), “Commitments and Contingencies” and Note (20), “Subsequent Event,” for additional discussion.

Tax Years Open to Examination

PHI’s Federal income tax liabilities for Pepco legacy companies for all years through 2002, and for Conectiv legacy companies for all years through 2002, have been determined by the IRS, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. PHI has not reached final settlement with the IRS with respect to the cross-border energy lease deductions. The open tax years for the significant states where PHI files state income tax returns (District of Columbia, Maryland, Delaware, New Jersey, Pennsylvania and Virginia) are the same as for the Federal returns.

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Resolution of Certain IRS Audit Matters

In 2010, PHI resolved all tax matters that were raised in IRS audits related to the 2001 and 2002 tax years except for the cross-border energy lease issue. Adjustments recorded relating to these resolved tax matters resulted in a $1 million increase in income tax expense exclusive of interest.

Other Taxes

Other taxes for continuing operations are shown below. The annual amounts include $426 million, $445 million and $427 million for the years ended December 31, 2012, 2011 and 2010, respectively, related to Power Delivery, which are recoverable through rates.

	2012		2011		2010
	(millions of dollars)
Gross Receipts/Delivery	$	135	$	145	$	145
Property		75		71		70
County Fuel and Energy		160		170		154
Environmental, Use and Other		62		65		65
Total	$	432	$	451	$	434

(13) STOCK-BASED COMPENSATION, DIVIDEND RESTRICTIONS, AND CALCULATIONS OF EARNINGS PER SHARE OF COMMON STOCK

Stock-Based Compensation

Pepco Holdings maintains a Long-Term Incentive Plan (LTIP) and a 2012 Long-Term Incentive Plan (2012 LTIP), the objective of each of which is to increase shareholder value by providing long-term and equity incentives to reward officers, key employees and non-employee directors of Pepco Holdings and its subsidiaries and to increase the ownership of Pepco Holdings common stock by such individuals. Any officer, key employee or non-employee director of Pepco Holdings or its subsidiaries may be designated as a participant. Under these plans, awards to officers, key employees and non-employee directors may be in the form of restricted stock, restricted stock units, stock options, performance shares and/or units, stock appreciation rights, unrestricted stock and dividend equivalents. At inception, 10 million and 8 million shares of common stock were authorized for issuance under the LTIP and the 2012 LTIP, respectively. The LTIP expired in accordance with its terms in 2012 and no new awards may be granted thereunder.

Total stock-based compensation expense recorded in the consolidated statements of income for the years ended December 31, 2012, 2011 and 2010 was $11 million, $6 million and $5 million, respectively, all of which was associated with restricted stock and restricted stock unit awards.

No material amount of stock compensation expense was capitalized for the years ended December 31, 2012, 2011 and 2010.

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Restricted Stock and Restricted Stock Unit Awards

Description of awards

A number of programs have been established under the LTIP and the 2012 LTIP involving the issuance of restricted stock and restricted stock unit awards, including awards of performance-based restricted stock units, time-based restricted stock and restricted stock units, and retention restricted stock and restricted stock units. A summary of each of these programs is as follows:

	Number of Shares			Total Number of Shares			Weighted Average Grant Date Fair Value
Balance at January 1, 2012
Time-based restricted stock		241,689					$	16.74
Time-based restricted stock units		170,531						18.87
Performance-based restricted stock units		765,139						19.28
Total					1,177,359
Granted during 2012
Unrestricted stock award		5,305						18.85
Time-based restricted stock units		342,673						19.69
Performance-based restricted stock units		412,503						21.13
Total					760,481
Vested during 2012
Unrestricted stock award		(5,305	)					18.85
Time-based restricted stock		(107,054	)					16.96
Time-based restricted stock units		—						—
Performance-based restricted stock units		(145,246	)					17.02
Total					(257,605	)
Forfeited during 2012
Time-based restricted stock		(28	)					17.72
Time-based restricted stock units		—						—
Performance-based restricted stock units		—						—
Total					(28	)
Balance at December 31, 2012
Time-based restricted stock		134,607						16.56
Time-based restricted stock units		513,204						19.42
Performance-based restricted stock units		1,032,396						20.34
Total					1,680,207

• Under the performance-based program, performance criteria are selected and measured over the specified performance period. Depending on the extent to which the performance criteria are satisfied, the participants are eligible to earn shares of common stock at the end of the performance period, ranging from 25% to 200% of the target award, and dividend equivalents accrued thereon.

• Generally, time-based restricted stock and restricted stock unit award opportunities have a requisite service period of up to three years and, with respect to restricted stock awards, participants have the right to receive dividends on the shares during the vesting period. Under restricted stock unit awards, dividends are credited quarterly in the form of additional restricted stock units, which are paid when vested at the end of the service period.

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• In January, April and September 2012, retention awards in the form of 150,330 time-based and performance-based restricted stock units and 5,305 shares of unrestricted stock were granted to certain PHI executives. The time-based retention awards have a vesting period of three years, and the performance-based retention awards have a one-year performance period and are subject to the continued employment of the executive at the end of the performance period.

• In May and September 2012, restricted stock units were granted to each non-employee director under the 2012 LTIP. A total of 40,749 units were granted and vest over a service period whch ends upon the first to occur of (i) one year after the date of grant or (ii) the date of the next annual meeting of stockholders.

Activity for the year

The 2012 activity for non-vested, time-based restricted stock, restricted stock units and performance-based restricted stock unit awards, including retention awards, is summarized in the table below. For performance-based restricted stock unit awards, the table reflects awards projected to achieve 100% of targeted performance criteria for the 2010-2012, 2011-2013 and 2012-2014 award cycles.

Grants included in the table above reflect 2012 grants of performance-based and retention restricted stock units, time-based and retention restricted stock units and unrestricted stock awards. PHI recognizes compensation expense related to performance-based restricted stock unit awards and time-based restricted stock and restricted stock unit awards based on the fair value of the awards at date of grant. The fair value is based on the market value of PHI common stock at the date the award opportunity is granted. The estimated fair value of the performance-based awards is also a function of PHI’s projected future performance relative to established performance criteria and the resulting payout of shares based on the achieved performance levels. PHI employed a Monte Carlo simulation to forecast PHI’s performance relative to the performance criteria and to estimate the potential payout of shares under the performance-based awards.

The following table provides the weighted average grant date fair value of those awards granted during each of the years ended December 31, 2012, 2011 and 2010:

	2012		2011		2010
Weighted average grant-date fair value of each award of time-based restricted stock and unrestricted stock awards granted during the year	$	18.85	$	—	$	16.55
Weighted average grant-date fair value of each time-based restricted stock unit granted during the year	$	19.69	$	18.87	$	—
Weighted average grant-date fair value of each performance-based restricted stock unit granted during the year	$	21.13	$	19.56	$	20.11

As of December 31, 2012, there was approximately $13 million of future compensation cost (net of estimated forfeitures) related to non-vested restricted stock awards and restricted stock unit awards granted under the LTIP and the 2012 LTIP that PHI expects to recognize over a weighted-average period of approximately two years.

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Stock options

Stock options to purchase shares of PHI’s common stock granted under the LTIP and the 2012 LTIP must have an exercise price at least equal to the fair market value of the underlying stock on the grant date. Stock options generally become exercisable on a specified vesting date or dates. All stock options must have an expiration date of no greater than ten years from the date of grant. No options have been granted under the LTIP since 2002. As of January 1, 2012, 30,925 options were outstanding at a weighted average exercise price of $20.75 and a weighted-average remaining contractual term of 0.03 years. As of December 31, 2012, all outstanding stock options under predecessor plans have expired. Total intrinsic value and tax benefits recognized for stock options exercised in 2011 and 2010 were immaterial. No options were exercised in 2012.

Non-employee directors were entitled, under the terms of the LTIP, to a grant on May 1 of each year of a nonqualified stock option for 1,000 shares of common stock. However, the Board of Directors previously determined not to make these grants and the LTIP expired by its terms on August 1, 2012.

Directors’ Deferred Compensation

Under the Pepco Holdings’ Executive and Director Deferred Compensation Plan, Pepco Holdings non-employee directors may elect to defer all or part of their cash retainer and meeting fees. Deferred retainer or meeting fees, at the election of the director, can be credited with interest at the prime rate or the return on selected investment funds or can be deemed invested in phantom shares of Pepco Holdings common stock on which dividend equivalent accruals are credited when dividends are paid on the common stock (or a combination of these options). All deferrals are settled in cash. The amount deferred by directors for each of the years ended December 31, 2012, 2011 and 2010 was not material.

Compensation expense recognized in respect of dividends and the increase in fair value for each of the years ended December 31, 2012, 2011 and 2010 was not material. The deferred compensation balance under this program was approximately $1 million at December 31, 2012 and 2011.

A separate deferral option under the 2012 LTIP gives non-employee directors the right to elect to defer the receipt of common stock upon vesting of restricted stock unit awards.

Dividend Restrictions

PHI, on a stand-alone basis, generates no operating income of its own. Accordingly, its ability to pay dividends to its shareholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of PHI’s direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and, in the case of ACE, the regulatory requirement that it obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of mortgage bonds and other long-term debt issued by the subsidiaries, and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Pepco, DPL and ACE have no shares of preferred stock outstanding at December 31, 2012. Currently, the capitalization ratio limitation to which ACE is subject and the restriction in the ACE charter do not limit ACE’s ability to pay common stock dividends. PHI had approximately $1,077 million and $1,040 million of retained earnings free of restrictions at December 31, 2012 and 2011, respectively. These amounts represent the total retained earnings balances at those dates.

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For the years ended December 31, Pepco Holdings received dividends from its subsidiaries as follows:

Subsidiary	2012		2011		2010
	(millions of dollars)
Pepco	$	35	$	25	$	115
DPL		—		60		23
ACE		35		—		35
Total	$	70	$	85	$	173

Calculations of Earnings per Share of Common Stock

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

	For the Years  Ended December 31,
	2012		2011			2010
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	259	$	258		$	119
Net income (loss) from discontinued operations		26		(1	)		(87	)
Net income	$	285	$	257		$	32
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		229		226			224
Adjustment to shares outstanding		—		—			—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		229		226			224
Net effect of potentially dilutive shares (a)		1		—			—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		230		226			224
Basic earnings per share of common stock from continuing operations	$	1.13	$	1.14		$	0.53
Basic earnings (loss) per share of common stock from discontinued operations		0.12		—			(0.39	)
Basic earnings per share	$	1.25	$	1.14		$	0.14
Diluted earnings per share of common stock from continuing operations	$	1.12	$	1.14		$	0.53
Diluted earnings (loss) per share of common stock from discontinued operations		0.12		—			(0.39	)
Diluted earnings per share	$	1.24	$	1.14		$	0.14

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted earnings per share as they are considered to be anti-dilutive were zero, 14,900 and 280,266 for the years ended December 31, 2012, 2011 and 2010, respectively.

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Equity Forward Transaction

During 2012, PHI entered into an equity forward transaction in connection with a public offering of 17,922,077 shares of PHI common stock. The use of an equity forward transaction substantially eliminates future equity price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with PHI’s capital investment and regulatory plans. PHI believed that the equity forward transaction substantially eliminated future equity price risk because the forward sale price was determinable as of the date that PHI entered into the equity forward transaction and was only reduced pursuant to the contractual terms of the equity forward transaction through the settlement date, which reductions were not affected by a future change in the market price of the 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.

The equity forward transaction had no initial fair value since it was entered into at the then market price of the common stock. PHI did not receive any proceeds from the sale of common stock until the equity forward transaction was settled, and at that time PHI recorded the proceeds in equity. PHI concluded that the equity forward transaction was an equity instrument based on the accounting guidance in ASC 480 and ASC 815, and that it qualified for an exception from derivative accounting under ASC 815 because the forward sale transaction was indexed to its own stock.

As allowed by the terms of the transaction, PHI physically settled the equity forward transaction on February 27, 2013 by issuing 17,922,077 shares of common stock at $17.39 per share to the forward counterparty. The proceeds of approximately $312 million were used to pay down outstanding commercial paper, a portion of which was issued in order to make capital contributions to the utilities, and for general corporate purposes.

During 2012, the equity forward transaction was reflected in PHI’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PHI’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the equity forward transaction less the number of shares that could be purchased by PHI in the market (based on the average market price during that reporting period) using the proceeds receivable upon settlement of the equity forward transaction (based on the adjusted forward sale price at the end of that reporting period). The excess number of shares is weighted for the portion of the reporting period in which the equity forward transaction is outstanding. For the year ended December 31, 2012, the equity forward transaction had a dilutive effect of $0.01 on PHI’s earnings per share.

Shareholder Dividend Reinvestment Plan

PHI maintains a Shareholder Dividend Reinvestment Plan (DRP) through which shareholders may reinvest cash dividends. In addition, existing shareholders can make purchases of shares of PHI common stock through the investment of not less than $25 each calendar month nor more than $200,000 each calendar year. Shares of common stock purchased through the DRP may be new shares or, at the election of PHI, shares purchased in the open market or in negotiated transactions. Approximately 2 million new shares were issued and sold under the DRP in each of 2012, 2011 and 2010.

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Pepco Holdings Common Stock Reserved and Unissued

The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2012:

Name of Plan	Number of Shares(a)
DRP		1,786,871
Conectiv Incentive Compensation Plan (b)		1,093,701
Potomac Electric Power Company Long-Term Incentive Plan (b)		298,543
Pepco Holdings Long-Term Incentive Plan (b)		7,665,981
Pepco Holdings 2012 Long-Term Incentive Plan		8,000,000
Pepco Holdings Non-Management Directors Compensation Plan		457,211
Pepco Holdings Retirement Savings Plan		604,075
Total		19,906,382

(a) Excludes up to 31 million shares authorized by the Board of Directors on February 23, 2012 for potential issuance pursuant to the terms of the equity forward transaction.

(b) No further awards will be made under this plan.

(14) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Derivatives are used by Power Delivery to hedge commodity price risk, as well as by PHI, from time to time, to hedge interest rate risk.

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. 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 natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled.

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. 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. As further described in Note (11), “Debt,” $15 million of these pre-tax losses ($9 million after-tax) was reclassified into income during 2010.

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The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2012 and 2011:

	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 assets (non-current assets)	$	—	$	8		$	8		$	—	$	8
Total Derivative assets		—		8			8			—		8
Derivative liabilities (current liabilities)		—		(4	)		(4	)		—		(4	)
Derivative liabilities (non-current liabilities)		—		(11	)		(11	)		—		(11	)
Total Derivative liabilities		—		(15	)		(15	)		—		(15	)
Net Derivative liability	$	—	$	(7	)	$	(7	)	$	—	$	(7	)

	As of December 31, 2011
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative liabilities (current liabilities)	$	—	$	(14	)	$	(14	)	$	2	$	(12	)
Derivative liabilities (non-current liabilities)		—		(3	)		(3	)		—		(3	)
Total Derivative liabilities		—		(17	)		(17	)		2		(15	)
Net Derivative (liability) asset	$	—	$	(17	)	$	(17	)	$	2	$	(15	)

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. The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2012		December 31, 2011
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	—	$	2

(a) Includes cash deposits on commodity brokerage accounts.

As of December 31, 2012 and 2011, all PHI 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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Derivatives Designated as Hedging Instruments

Cash Flow Hedges

Power Delivery

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered from customers based on the fuel adjustment clause approved by the DPSC. The following table indicates the net unrealized derivative losses arising during the period that were deferred as Regulatory assets 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 years ended December 31, 2012, 2011 and 2010 associated with cash flow hedges:

	For the Year Ended December 31,
	2012		2011			2010
	(millions of dollars)
Net unrealized loss arising during the period	$	—	$	—		$	(9	)
Net realized loss recognized during the period		—		(5	)		(13	)

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 December 31, 2012 and 2011. Cash flow hedges are marked to market on the consolidated balance sheet with corresponding adjustments to AOCL for the effective portion of cash flow hedges. 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:

	As of December 31, 2012
Contracts	Accumulated Other Comprehensive  Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Interest rate	$	10	$	1		236 months
Total	$	10	$	1
	As of December 31, 2011
Contracts	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Interest rate	$	10	$	1		248 months
Total	$	10	$	1

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Other Derivative Activity

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 losses arising during the period that were deferred as Regulatory assets 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 years ended December 31, 2012 and 2011 associated with these derivatives:

	For the Year Ended December 31,
	2012			2011			2010
	(millions of dollars)
Net unrealized loss arising during the period	$	(6	)	$	(13	)	$	(20	)
Net realized loss recognized during the period		(16	)		(22	)		(26	)

As of December 31, 2012 and 2011, 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:

	December 31, 2012			December 31, 2011
Commodity	Quantity		Net Position	Quantity		Net Position
DPL – Natural gas (one Million British Thermal Units(MMBtu))		3,838,000	Long		6,161,200		Long
ACE – Capacity (MWs)		180	Long		—		—

Contingent Credit Risk Features

The primary contracts used by Power Delivery 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

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as those designated as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If DPL’s 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 December 31, 2012 and 2011, were $4 million and $15 million, respectively, before giving effect to offsetting transactions or collateral under master netting agreements. As of those dates, DPL had posted no cash collateral against its gross derivative liability, resulting in net liabilities of $4 million and $15 million, respectively. If DPL’s debt ratings had been downgraded below investment grade as of December 31, 2012 and 2011, DPL’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 $2 million and $15 million, respectively, and DPL would have been required to post collateral with the counterparties of approximately $2 million and $15 million, respectively, in addition to that which was posted as of December 31, 2012 and 2011. 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. As of December 31, 2012 and 2011, the aggregate amount of cash plus borrowing capacity under the credit facility available to meet the future liquidity needs of PHI’s utility subsidiaries was $477 million and $711 million, respectively.

(15) 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 December 31, 2012 and 2011. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	Fair Value Measurements at 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 (d)	$	8	$	—	$	—	$	8
Cash equivalents
Treasury fund		27		27		—		—
Executive deferred compensation plan assets
Money market funds		17		17		—		—
Life insurance contracts		60		—		42		18
	$	112	$	44	$	42	$	26
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	4	$	—	$	—	$	4
Capacity (d)		11		—		—		11
Executive deferred compensation plan liabilities
Life insurance contracts		28		—		28		—
	$	43	$	—	$	28	$	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 value of derivative assets and 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.

(d) Represents derivatives associated with ACE SOCAs.

	Fair Value Measurements at December 31, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury fund	$	114	$	114	$	—	$	—
Executive deferred compensation plan assets
Money market funds		18		18		—		—
Life insurance contracts		60		—		43		17
	$	192	$	132	$	43	$	17
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	17	$	2	$	—	$	15
Executive deferred compensation plan liabilities
Life insurance contracts		28		—		28		—
	$	45	$	2	$	28	$	15

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2011.

(b) The fair value of derivative assets and 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.

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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.

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 December 31, 2012. 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.

• ACE used a discounted cash flow methodology to estimate the fair value of the capacity derivatives embedded in the SOCAs. ACE utilized an external consulting firm 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

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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 table below summarizes 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 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
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 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 years ended December 31, 2012 and 2011 are shown below:

	Year Ended December 31, 2012
	Natural Gas			Life Insurance Contracts			Capacity
	(millions of dollars)
Beginning balance as of January 1	$	(15	)	$	17		$	—
Total gains (losses) (realized and unrealized):
Included in income		—			4			—
Included in accumulated other comprehensive loss		—			—			—
Included in regulatory liabilities		(2	)		—			(3	)
Purchases		—			—			—
Issuances		—			(3	)		—
Settlements		13			—			—
Transfers in (out) of level 3		—			—			—
Ending balance as of December 31	$	(4	)	$	18		$	(3	)

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	Year Ended December 31, 2011
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(23	)	$	19
Total gains (losses) (realized and unrealized):
Included in income		—			6
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(10	)		—
Purchases		—			—
Issuances		—			(3	)
Settlements		18			(5	)
Transfers in (out) of level 3		—			—
Ending balance as of December 31	$	(15	)	$	17

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

	Year Ended December 31,
	2012		2011
	(millions of dollars)
Total net gains included in income for the period	$	4	$	6
Change in unrealized gains relating to assets still held at reporting date	$	4	$	6

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 December 31, 2012 are shown in the table 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.

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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 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 estimated fair values of PHI’s debt instruments at December 31, 2011 are shown below:

	December 31, 2011
	Carrying Amount		Fair Value
	(millions of dollars)
Long-term debt	$	3,867	$	4,577
Transition Bonds issued by ACE Funding		332		380
Long-term project funding		15		15

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

(16) COMMITMENTS AND CONTINGENCIES

General Litigation and Other Matters

In 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.” Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepco’s property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings were not entirely clear, it appeared that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant. In the intervening years, most of the cases were voluntarily dismissed by the plaintiffs prior to their respective trial dates. At the beginning of the first quarter of 2012, there were approximately 90

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cases pending against Pepco in the Maryland State Courts (excluding those tendered to Mirant Corporation (Mirant) for defense and indemnification in connection with the sale by Pepco of its generation assets to Mirant in 2000), with an aggregate amount of monetary damages sought of approximately $360 million. In March 2012, the parties to these consolidated proceedings (each represented by the same law firm) filed a stipulation of dismissal, by which the plaintiffs voluntarily dismissed Pepco as a defendant, eliminating any reasonably possible liability Pepco may have had with respect to these proceedings.

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 letters also claim compounded interest totaling an additional 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. At this time, Pepco Energy Services has concluded that a loss is reasonably possible with respect to this matter, but Pepco Energy Services cannot estimate an amount or range of reasonably possible loss associated with these claims because the discussions with the school districts are in the early stages.

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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 December 31, 2012 are summarized as follows:

			Legacy Generation
	Transmission and Distribution		Regulated			Non- Regulated		Other		Total
	(millions of dollars)
Beginning balance as of January 1	$	15	$	8		$	5	$	2	$	30
Accruals		—		—			—		—		—
Payments		—		(1	)		—		—		(1	)
Ending balance as of December 31		15		7			5		2		29
Less amounts in Other current liabilities		2		2			—		2		6
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. 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 estimates the additional cost for future response measures will be approximately $6 million. ACE believes that EPA sent similar general notice letters to three other companies and various individuals.

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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.

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Benning Road Site

In September 2010, PHI received a letter from EPA stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified the Benning Road location, consisting of a 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 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 and RI/FS field work commenced in January 2013.

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.

The release falls within the regulatory jurisdiction of multiple federal and state agencies. 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.

In March 2011, the Virginia Department of Environmental Quality (VADEQ) requested documentation regarding the release and the preparation of an emergency response report, which Pepco submitted to the agency in April 2011. In March 2011, Pepco received a notice of violation from VADEQ and in December 2011, entered into a consent decree with VADEQ, pursuant to which Pepco paid a civil penalty of approximately $40,000. The U.S. Coast Guard assessed a $5,000 penalty against Pepco for the release of oil into the waters of the United States, which Pepco has paid.

During March 2011, EPA conducted an inspection of the Potomac River substation to review compliance with federal regulations regarding Spill Prevention, Control, and Countermeasure (SPCC) plans for facilities using oil-containing equipment in proximity to surface waters. EPA identified several potential violations of the SPCC regulations relating to SPCC plan content, recordkeeping, and secondary containment. As a result of the oil release, Pepco submitted a revised SPCC plan to EPA in August 2011 and 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 and, after receiving such approval, will submit a further revised SPCC plan to EPA. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system. In April 2012, EPA advised Pepco that it is not seeking civil penalties at this time for alleged non-compliance with SPCC regulations.

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

Fauquier County Landfill Site

In October 2011, Pepco Energy Services received a notice of violation from the VADEQ, which advised Pepco Energy Services of information on which VADEQ may rely to institute an administrative or judicial enforcement action in connection with alleged violation of Virginia air pollution control laws and regulations at the facility of Pepco Energy Services’ subsidiary Fauquier County Landfill Gas, L.L.C. in Warrenton, Virginia. The notice of violation was based on an on-site VADEQ inspection during which VADEQ observed certain alleged deficiencies relating to the facility’s permit to construct and operate. In February 2012, Pepco Energy Services signed a proposed consent order sent by VADEQ, pursuant to which Pepco Energy Services agreed to perform certain remedial actions and agreed to pay a civil charge of approximately $10,000.

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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 $1.2 billion as of December 31, 2012. 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 2006-2008 income tax return audits continue to be in process with the IRS Office of Appeals and the IRS case manager, respectively, and are not presently a part of the U.S. Court of Federal Claims litigation discussed above.

PHI’s current annual tax benefits from these lease investments are approximately $43 million. After taking into consideration the $74 million paid with the 2001-2002 audit (as discussed above), the net federal and state tax benefits received for the remaining leases from January 1, 2001, the earliest year that remains open to audit, to December 31, 2012, has been approximately $489 million. 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 estimates that, as of December 31, 2012, it would be obligated to pay approximately $600 million in additional federal and state taxes (net of the $74 million tax payment described above) and approximately $144 million of interest on the remaining leases. These amounts have been estimated without 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. After consideration of these benefits, PHI would be obligated to pay between $170 million and $200 million in additional federal and state taxes and between $50 million and $60 million of interest on the additional federal and state taxes as of March 31, 2013. In addition, the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due.

See Note (20), “Subsequent Event,” for further information on PHI’s cross-border energy lease investments.

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District of Columbia Tax Legislation

In 2011, the Council of the District of Columbia approved the Budget Support Act which requires that corporate taxpayers in the District of Columbia calculate taxable income allocable or apportioned to the District of Columbia by reference to the income and apportionment factors applicable to commonly controlled entities organized within the United States that are engaged in a unitary business. In the aggregate, this new tax reporting method reduced pre-tax earnings for the year ended December 31, 2011 by $7 million ($5 million after-tax) as further discussed in Note (8), “Leasing Activities,” and Note (12), “Income Taxes.” During 2012, the District of Columbia Office of Tax and Revenue adopted regulations to implement this reporting method. PHI has analyzed these regulations and determined that the regulations did not impact PHI’s results of operations for the year ended December 31, 2012.

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 December 31, 2012, 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)	$	90	$	—	$	—	$	—	$	90
Guarantees associated with disposal of Conectiv Energy assets (b)		13		—		—		—		13
Guaranteed lease residual values (c)		2		5		6		4		17
Total	$	105	$	5	$	6	$	4	$	120

(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 $54 million, $9 million of which is a guaranty by PHI, $15 million by Pepco, $18 million by DPL and $12 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.

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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 December 31, 2012, the remaining notional amount of Pepco Energy Services’ energy savings guarantees on both completed projects and projects under construction totaled $446 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 December 31, 2012, 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 December 31, 2012, 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 year ended December 31, 2012 as compared to the year ended December 31, 2011.

Dividends

On January 24, 2013, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable March 28, 2013, to stockholders of record on March 11, 2013.

Contractual Obligations

As of December 31, 2012, Pepco Holdings’ contractual obligations under non-derivative fuel and purchase power contracts were $355 million in 2013, $707 million in 2014 to 2015, $653 million in 2016 to 2017, and $1,911 million in 2018 and thereafter.

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(17) 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.

	Treasury Lock			Other			Accumulated Other Comprehensive Loss
	(millions of dollars)
Balance, December 31, 2009	$	(22	)	$	(17	)	$	(39	)
Current year change		11			—			11
Balance, December 31, 2010		(11	)		(17	)		(28	)
Current year change		1			(7	)		(6	)
Balance, December 31, 2011		(10	)		(24	)		(34	)
Current year change		—			(8	)		(8	)
Balance, December 31, 2012	$	(10	)	$	(32	)	$	(42	)

The income tax expense (benefit) for each component of Pepco Holdings’ other comprehensive income is as follows.

For the Year Ended:	Treasury Lock		Other			Accumulated Other Comprehensive Loss
	(millions of dollars)
December 31, 2010	$	7	$	—		$	7
December 31, 2011	$	—	$	(4	)	$	(4	)
December 31, 2012	$	—	$	(6	)	$	(6	)

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(18) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. The totals of the four quarterly basic and diluted earnings per common share amounts may not equal the basic and diluted earnings per common share for the year due to changes in the number of shares of common stock outstanding during the year.

	2012
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions, except per share amounts)
Total Operating Revenue (a)	$	1,136		$	1,070		$	1,402		$	1,067		$	4,675
Total Operating Expenses (a)(b)		1,010			934			1,150	(c)		954			4,048
Operating Income		126			136			252			113			627
Other Expenses		(57	)		(55	)		(60	)		(58	)		(230	)
Income From Continuing Operations Before Income Tax Expense		69			81			192			55			397
Income Tax Expense Related to Continuing Operations		9			28			88	(d)		13			138
Net Income From Continuing Operations		60			53			104			42			259
Income from Discontinued Operations, net of taxes		8			9			8			1			26
Net Income	$	68		$	62		$	112	(c)	$	43		$	285
Basic Earnings Per Share of Common Stock
Earnings Per Share of Common Stock from Continuing Operations		0.27			0.23			0.46			0.18			1.13
Earnings Per Share of Common Stock from Discontinued Operations		0.03			0.04			0.03			—			0.12
Basic Earnings Per Share of Common Stock		0.30			0.27			0.49			0.18			1.25
Diluted Earnings Per Share of Common Stock
Earnings Per Share of Common Stock from Continuing Operations		0.27			0.23			0.45			0.18			1.12
Earnings Per Share of Common Stock from Discontinued Operations		0.03			0.04			0.04			—			0.12
Diluted Earnings Per Share of Common Stock		0.30			0.27			0.49			0.18			1.24
Cash Dividends Per Share of Common Stock		0.27			0.27			0.27			0.27			1.08

(a) Includes $9 million of intra-company revenues (and associated costs) previously eliminated in consolidation which will continue to be recognized from third parties subsequent to the completion of the wind-down of the Pepco Energy Services’ retail electric and natural gas supply businesses.

(b) Includes impairment losses of $12 million pre-tax ($7 million after-tax) at Pepco Energy Services associated primarily with investments in landfill gas-fired electric generation facilities, and the combustion turbines at Buzzard Point.

(c) Includes $39 million pre-tax ($9 million after-tax) gain from the early termination of cross-border energy leases.

(d) Includes a $16 million charge related to the recognition of the tax consequences associated with the early termination of cross-border energy leases.

	2011
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions, except per share amounts)
Total Operating Revenue (a)	$	1,334		$	1,185		$	1,431		$	1,062		$	5,012
Total Operating Expenses (a)		1,195			985	(b)		1,239			959			4,378
Operating Income		139			200			192			103			634
Other Expenses		(53	)		(53	)		(60	)		(62	)		(228	)
Income From Continuing Operations Before Income Tax Expense		86			147			132			41			406
Income Tax Expense Related to Continuing Operations		30			53	(c)		54			11			148
Net Income From Continuing Operations		56			94	(b)		78			30			258
Income (Loss) From Discontinued Operations, net of taxes		8			—			2			(11	)		(1	)
Net Income	$	64		$	94		$	80		$	19		$	257
Basic and Diluted Earnings Per Share of Common Stock
Earnings Per Share of Common Stock from Continuing Operations		0.25			0.41			0.35			0.13			1.14
Earnings (Loss) Per Share of Common Stock from Discontinued Operations		0.03			0.01			—			(0.05	)		—
Basic and Diluted Earnings Per Share of Common Stock		0.28			0.42			0.35			0.08			1.14
Cash Dividends Per Share of Common Stock		0.27			0.27			0.27			0.27			1.08

(a) Includes $15 million of intra-company revenues (and associated costs) previously eliminated in consolidation which will continue to be recognized from third parties subsequent to the completion of the wind-down of the Pepco Energy Services’ retail electric and natural gas supply businesses.

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

(c) Includes tax benefits of $14 million in the second quarter primarily associated with an interest benefit related to federal tax liabilities and a $22 million charge related to the recognition of the tax consequences associated with the early termination of cross-border energy leases.

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(19) DISCONTINUED OPERATIONS

Retail Electric and Natural Gas Supply Businesses of Pepco Energy Services

On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, in the second quarter of 2013, Pepco Energy Services completed the wind-down of its retail electric supply business by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013. As a result, PHI has reported the results of operations of Pepco Energy Services’ retail electric and natural gas supply businesses as discontinued operations in all periods presented in the accompanying consolidated statements of income. Further, the assets and liabilities of Pepco Energy Services’ retail electric and natural gas supply businesses are reported as held for disposition as of each date presented in the accompanying consolidated balance sheets. In addition, Note (1), “Organization,” Note (5), “Segment Information,” Note (12), “Income Taxes,” Note (14), “Derivative Instruments and Hedging Activities,” Note (15), “Fair Value Disclosures,” Note (17), “Accumulated Other Comprehensive Loss,” Note (18), “Quarterly Financial Information (Unaudited),” and Note (19), “Discontinued Operations” have been updated to reflect the classification of the retail electric and natural gas supply businesses of Pepco Energy Services as discontinued operations.

Operating Results

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

	For the Year Ended December 31,
	2012		2011		2010
	(millions of dollars)
Operating revenue	$	415	$	954	$	1,597
Income from operations of discontinued operations	$	44	$	3	$	33
Income Tax expense		18		1		13
Income From Discontinued Operations, Net of Income Taxes	$	26	$	2	$	20

Balance Sheet Information

As of December 31, 2012 and 2011, the retail electric and natural gas supply businesses of Pepco Energy Services had net accounts receivable of $33 million and $94 million, respectively, inventory assets of $3 million and $7 million, respectively, gross derivative assets of $1 million and $24 million, respectively, other current assets of $1 million and $2 million, respectively, accrued liabilities of $20 million and $61 million, respectively, gross derivative liabilities of $21 million and $107 million, respectively, exclusive of the collateral pledged by Pepco Energy Services against the derivative liabilities, and other current liabilities of $1 million and $2 million, respectively. As of December 31, 2012, the derivative assets were considered level 1 within the fair value hierarchy, and $11 million and $10 million of the derivative liabilities were considered levels 1 and 2, respectively, within the fair value hierarchy. As of December 31, 2011, $22 million and $2 million of the derivative assets were considered levels 1 and 2, respectively, within the fair value hierarchy, and $50 million, $55 million, and $2 million of the derivative liabilities were considered levels 1, 2, and 3, respectively, within the fair value hierarchy.

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Derivative Instruments and Hedging Activities

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

The retail electric and natural gas supply businesses 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 and electricity 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 electric and natural gas supply businesses 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 table below identifies the balance sheet location and fair values of the retail electric and natural gas supply businesses’ derivative instruments as of December 31, 2012 and 2011:

	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)
Assets held for disposition (current assets)	$	—		$	1		$	1		$	—	$	1
Total Derivative assets		—			1			1			—		1
Liabilities associated with assets held for disposition (current liabilities)		(10	)		(9	)		(19	)		16		(3	)
Liabilities associated with assets held for disposition (non-current liabilities)		(1	)		(1	)		(2	)		2		—
Total Derivative liabilities		(11	)		(10	)		(21	)		18		(3	)
Net Derivative (liability) asset	$	(11	)	$	(9	)	$	(20	)	$	18	$	(2	)

(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.

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	As of December 31, 2011
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)
Assets held for disposition (current assets)	$	17		$	6		$	23		$	(18	)	$	5
Assets held for disposition (non-current assets)		—			1			1			(1	)		—
Total Derivative assets		17			7			24			(19	)		5
Liabilities associated with assets held for disposition (current liabilities)		(55	)		(34	)		(89	)		75			(14	)
Liabilities associated with assets held for disposition (non-current liabilities)		(11	)		(7	)		(18	)		15			(3	)
Total Derivative liabilities		(66	)		(41	)		(107	)		90			(17	)
Net Derivative (liability) asset	$	(49	)	$	(34	)	$	(83	)	$	71		$	(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 electric and natural gas supply businesses of Pepco Energy Services offset the fair value amounts recognized for derivative instruments and the fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2012		December 31, 2011
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	18	$	71

(a) Includes cash deposits on commodity brokerage accounts.

As of December 31, 2012 and 2011, all cash collateral pledged by the retail electric and natural gas supply businesses 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 electric and natural gas supply businesses of Pepco Energy Services had elected to no longer apply cash flow hedge accounting to energy derivatives. Amounts included in AOCL for these cash flow hedges as of December 31, 2012 and 2011 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.

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The cash flow hedge activity during the years ended December 31, 2012, 2011 and 2010 is provided in the tables below:

	For the Year Ended December 31,
	2012		2011		2010
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss	$	—	$	—	$	(100	)
Amount of net pre-tax loss reclassified into income:
Income from Discontinued Operations, Net of Income Taxes (a)		39		81		135
Total net pre-tax loss reclassified into Income from Discontinued Operations, Net of Income Taxes		39		81		135
Net pre-tax gain on commodity derivatives included in Accumulated Other Comprehensive Loss	$	39	$	81	$	35

(a) Included in the above table is a loss of $1 million for the years ended December 31, 2012 and 2011, respectively, which was reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

As of December 31, 2012 and 2011, the retail electric and natural gas supply businesses of Pepco Energy Services had the following types and quantities of outstanding energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

	Quantities
Commodity	December 31, 2012		December 31, 2011
Forecasted Purchases Hedges
Electricity (Megawatt hours (MWh))		—		614,560
Forecasted Sales Hedges
Electricity (MWh)		—		614,560

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 December 31, 2012, $11 million of the losses in AOCL were associated with derivatives that the retail electric and natural gas supply businesses of Pepco Energy Services had previously designated as cash flow hedges. The tables below provide details regarding effective cash flow hedges included in the retail electric and natural gas supply businesses of Pepco Energy Services’ balance sheets as of December 31, 2012 and 2011. Although the retail electric and natural gas supply businesses of Pepco Energy Services elected to no longer apply cash flow hedge accounting to derivatives prior to December 31, 2011, 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 December 31, 2012
	Accumulated Other Comprehensive  Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Energy commodity (a)	$	6	$	5		17 months
Total	$	6	$	5

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

Contracts	As of December 31, 2011
	Accumulated Other Comprehensive  Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Energy commodity (a)	$	29	$	23		29 months
Total	$	29	$	23

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

Other Derivative Activity

The retail electric and natural gas supply businesses 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 years ended December 31, 2012, 2011, and 2010, the amount of the derivative gain (loss) for the retail electric and natural gas supply businesses of Pepco Energy Services recognized in Income from Discontinued Operations, Net of Income Taxes is provided in the table below:

	For the Year Ended December 31,
	2012			2011			2010
	(millions of dollars)
Reclassification of mark-to-market to realized on settlement of contracts	$	27		$	—		$	2
Unrealized mark-to-market loss		(3	)		(30	)		(3	)
Total net gain (loss)	$	24		$	(30	)	$	(1	)

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As of December 31, 2012 and 2011, the retail electric and natural gas supply businesses 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:

	December 31, 2012				December 31, 2011
Commodity	Quantity		Net Position		Quantity		Net Position
Financial transmission rights (MWh)		181,008		Long		267,480		Long
Electric capacity (MW-Days)		—		—		12,920		Long
Electricity (MWh)		261,240		Long		788,280		Long
Natural gas (MMBtu)		2,867,500		Long		24,550,257		Long

Conectiv Energy

In April 2010, the Board of Directors approved a plan for the disposition of PHI’s competitive wholesale power generation, marketing and supply business, which had been conducted through Conectiv Energy. On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine. The disposition of Conectiv Energy’s remaining assets and businesses, consisting of its load service supply contracts, energy hedging portfolio, certain tolling agreements and other assets not included in the Calpine sale, has been completed.

Conectiv Energy’s loss from discontinued operations, net of income taxes, for the years ended December 31, 2012, 2011 and 2010, was zero, $3 million and $107 million, respectively. Conectiv Energy’s other comprehensive income from discontinued operations, net of income taxes, for the years ended December 31, 2012, 2011 and 2010, was zero, zero and $103 million, respectively.

(20) SUBSEQUENT EVENT

In the last several years, IRS challenges related to SILO transactions, such as PHI’s cross-border energy lease investments, and lease-in, lease-out (LILO) transactions have been the subject of litigation, including litigation commenced by PHI in the U.S. Court of Federal Claims in January 2012 related to certain tax benefits claimed by PHI on its federal tax returns for 2001 and 2002.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion inConsolidated 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 LILO transaction. PHI had viewed the initial trial court ruling on this matter, in which the U.S. Court of Federal Claims issued a decision in favor of the taxpayer in October 2009, as a favorable development in PHI’s dispute with the IRS.

Under the FASB guidance for income taxes (ASC 740), 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 FASB guidance for leases (ASC 840) requires a company 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 from these investments, a recalculation of the carrying value of its net investment is required.

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 described above, 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 expects to record a non-cash charge of between $355 million and $380 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 PHI’s estimated federal and state income tax obligations for the period over which the tax benefits ultimately may be disallowed. While the IRS could require PHI to pay a penalty of up to 20 percent of the amount of additional taxes due,

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PHI believes that it is more likely than not that no such penalty will be incurred, and therefore no amount for any potential penalty will be included in the charge expected to be recorded in the first quarter of 2013.

PHI currently estimates 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 be obligated to pay between $170 million and $200 million in additional federal and state taxes and between $50 million and $60 million of interest on the additional federal and state taxes as of March 31, 2013. These amounts have been estimated taking into consideration certain tax benefits arising from matters unrelated to the leases that would offset the amount of taxes and interest due, including PHI’s estimate of the expected resolution of other uncertain and effectively settled tax positions, the carrying back or carrying forward of any existing net operating losses, and the application of certain amounts on deposit with the IRS. Without consideration of these benefits, PHI estimates that it would have been obligated to pay approximately $600 million in additional federal and state taxes and approximately $150 million of interest on the additional federal and state taxes as of March 31, 2013.

In the first quarter of 2013, PHI anticipates that it will make a deposit with the IRS for the additional taxes and related interest of approximately $220 million to $260 million in order to mitigate PHI’s ongoing interest costs. This deposit is expected to be funded from currently available sources of liquidity and short-term borrowings. PHI also is evaluating the liquidation of all or a portion of its remaining cross-border energy lease investments and the liquidation proceeds could be used to repay any borrowings utilized to fund the deposit discussed above. PHI estimates that a partial or complete liquidation could be accomplished within one year. The aggregate financial impact of a partial or complete liquidation of the cross-border leases is not determinable at this time, but could result in material gains or losses. PHI continues to weigh its options with respect to its litigation with the IRS.

Update to Subsequent Event (unaudited)

As a result of the court’s ruling in theConsolidated Edison case, PHI 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 after-tax non-cash charges totaling $383 million in the first half of 2013, consisting of the following components:

• A non-cash pre-tax charge of $373 million ($313 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 was 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 was 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.

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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 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 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 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 paid in advance to the IRS. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made an advanced payment to the IRS of $242 million in the first quarter of 2013. This advanced payment was funded from currently available sources of liquidity and short-term borrowings.

In March 2013, PHI began to pursue the early termination of all of its remaining cross-border energy lease investments with its lessees. During the second and third quarters of 2013, PHI terminated early its interest in all of the remaining lease investments. PHI received aggregate net cash proceeds of $873 million (net of aggregate termination payments of $2.0 billion used to retire the non-recourse debt associated with the terminated leases) and recorded an aggregate pre-tax loss, including transaction costs, of approximately $3 million ($2 million after-tax), representing the excess of the carrying value of the terminated leases over the net cash proceeds received for the year ending December 31, 2013. A portion of the proceeds from lease terminations was used to repay the short-term borrowings utilized to fund the advanced payment.

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 was effectively stayed until October 30, 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.

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Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents List

1. Financial Statements (See Exhibit 99.3)

Pepco Holdings, Inc.

Consolidated Statements of Income for each of the years ended December 31, 2012, 2011 and 2010

Consolidated Statements of Comprehensive Income for each of the years ended December 31, 2012, 2011 and 2010

Consolidated Balance Sheets as of December 31, 2012 and 2011

Consolidated Statements of Cash Flows for each of the years ended December 31, 2012, 2011 and 2010

Consolidated Statements of Equity for each of the years ended December 31, 2012, 2011 and 2010

Notes to Consolidated Financial Statements

2. Financial Statement Schedules

The financial statement schedules specified by Regulation S-X, other than those listed below, are omitted because either they are not applicable or the required information is presented in the financial statements set forth in Exhibit 99.3.

Schedule I, Condensed Financial Information of Parent Company

Schedule II, Valuation and Qualifying Accounts

(b) There are no changes being made to Item 15(b) from the 2012 Form 10-K.

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Schedule I, Condensed Financial Information of Parent Company is submitted below.

PEPCO HOLDINGS, INC. (Parent Company)

STATEMENTS OF INCOME

	For the Year Ended December 31,
	2012			2011			2010
	(millions of dollars, except share data)
OPERATING REVENUE	$	—		$	—		$	—
OPERATING EXPENSES
Other operation and maintenance		1			1			5
Total operating expenses		1			1			5
OPERATING LOSS		(1	)		(1	)		(5	)
OTHER INCOME (EXPENSES)
Interest expense		(33	)		(29	)		(72	)
Loss on extinguishment of debt		—			—			(189	)
Income from equity investments		278			279			267
Impairment losses		—			(5	)		—
Total other income		245			245			6
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		244			244			1
INCOME TAX BENEFIT RELATED TO CONTINUING OPERATIONS		(15	)		(14	)		(118	)
NET INCOME FROM CONTINUING OPERATIONS		259			258			119
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES		26			(1	)		(87	)
NET INCOME	$	285		$	257		$	32
COMPREHENSIVE INCOME	$	300		$	300		$	167
EARNINGS PER SHARE
Basic earnings per share of common stock from Continuing Operations	$	1.13		$	1.14		$	0.53
Basic earnings (loss) per share of common stock from Discontinued Operations		0.12			—			(0.39	)
Basic earnings per share of common stock	$	1.25		$	1.14		$	0.14
Diluted earnings per share of common stock from Continuing Operations	$	1.12		$	1.14		$	0.53
Diluted earnings (loss) per share of common stock from Discontinued Operations		0.12			—			(0.39	)
Diluted earnings per share of common stock	$	1.24		$	1.14		$	0.14

The accompanying Notes are an integral part of these financial statements.

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PEPCO HOLDINGS, INC. (Parent Company)

BALANCE SHEETS

	As of December 31,
	2012			2011
	(millions of dollars, except share data)
ASSETS
Current Assets
Cash and cash equivalents	$	262		$	257
Prepayments of income taxes		12			51
Accounts receivable and other		7			7
		281			315
Investments and Other Assets
Goodwill		1,398			1,398
Notes receivable from subsidiary companies		—			154
Investment in consolidated companies		3,869			3,665
Other		55			24
		5,322			5,241
Total Assets	$	5,603		$	5,556
LIABILITIES AND EQUITY
Current Liabilities
Short-term debt	$	464		$	465
Interest and taxes accrued		11			11
Accounts payable due to associated companies		2			25
Net liabilities associated with investment in consolidated companies held for disposition		4			43
		481			544
Deferred Credits
Liabilities and accrued interest related to uncertain tax positions		3			3
Long-Term Debt		705			705
Commitments and Contingencies (Note 4)
Equity
Common stock, $.01 par value—authorized 400,000,000 shares, 230,015,427 and 227,500,190 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,383			3,325
Accumulated other comprehensive loss		(48	)		(63	)
Retained earnings		1,077			1,040
Total equity		4,414			4,304
Total Liabilities and Equity	$	5,603		$	5,556

The accompanying Notes are an integral part of these financial statements.

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PEPCO HOLDINGS, INC. (Parent Company)

STATEMENTS OF CASH FLOWS

	For the Year Ended December 31,
	2012			2011			2010
	(millions of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	285		$	257		$	32
Loss from discontinued operations, net of income taxes		(26	)		1			87
Adjustments to reconcile net income to net cash from operating activities:
Distributions from related parties less than earnings		(93	)		(205	)		(130	)
Deferred income taxes		(31	)		(16	)		(5	)
Changes in:
Prepaid and other		(23	)		23			24
Accounts payable		6			2			1
Interest and taxes		39		��	42			(130	)
Other assets and liabilities		4			11			31
Net Cash From (Used By) Operating Activities		161			115			(90	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of Conectiv Energy wholesale power generation business		—			—			1,035
Net Cash From Investing Activities		—			—			1,035
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock		(248	)		(244	)		(241	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		51			47			47
Issuance of long-term debt		—			—			250
Capital distribution to subsidiaries, net		(110	)		(20	)		(31	)
Reacquisitions of long-term debt		—			—			(1,644	)
Decrease in notes receivable from associated companies		154			—			318
(Repayments) issuances of short-term debt, net		(1	)		235			(94	)
Costs of issuances		(2	)		(7	)		(4	)
Net Cash (Used By) From Financing Activities		(156	)		11			(1,399	)
Net increase (decrease) in cash and cash equivalents		5			126			(454	)
Cash and cash equivalents at beginning of year		257			131			585
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	262		$	257		$	131

The accompanying Notes are an integral part of these financial statements.

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NOTES TO FINANCIAL INFORMATION

(1)BASIS OF PRESENTATION

Pepco Holdings, Inc. (Pepco Holdings) is a holding company and conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Pepco Holdings included in Exhibit 99.3 of this Form 8-K.

Pepco Holdings owns 100% of the common stock of all its significant subsidiaries.

(2)RECLASSIFICATIONS AND ADJUSTMENTS

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

Revision to Prior Period Financial Statements

PCI Deferred Income Tax Liability Adjustment

Since 1999, PCI had not recorded a deferred tax liability related to a temporary difference between the financial reporting basis and the tax basis of an investment in a wholly owned partnership. In the second quarter of 2013, PHI re-evaluated this accounting treatment and found it to be in error, requiring an adjustment related to prior periods. PHI determined that the cumulative adjustment required, representing a charge to earnings of $32 million, related to a period prior to the year ended December 31, 2008 (the earliest period for which selected consolidated financial data were presented in the table entitled “Selected Financial Data” in Part II, Item 6 of PHI’s 2012 Annual Report on Form 10-K). Consistent with PHI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, the accompanying PHI parent company financial statements reflect the correction of this error as an adjustment to shareholders’ equity for the earliest period presented. The adjustment to correct the error did not affect PHI’s parent company statements of income and cash flows for each of the three years in the period ended December 31, 2012, and only affected the reported balances of investment in consolidated companies and retained earnings as reflected in PHI’s parent company balance sheets as of December 31, 2012 and 2011. The adjustment is not considered to be material to the reported balances of retained earnings and total equity reflected in PHI’s parent company financial statements included in PHI’s 2012 Annual Report on Form 10-K. The table below illustrates the effects of the revision on reported balances in PHI’s parent company financial statements.

	As Filed			Adjustment			As Revised
	(millions of dollars)
December 31, 2012
Investment in consolidated companies	$	3,901	(a)	$	(32	)	$	3,869
Total investments and other assets		5,354			(32	)		5,322
Retained earnings		1,109			(32	)		1,077
Total equity		4,446			(32	)		4,414
December 31, 2011
Investment in consolidated companies	$	3,697	(a)	$	(32	)	$	3,665
Total investments and other assets		5,273			(32	)		5,241
Retained earnings		1,072			(32	)		1,040
Total equity		4,336			(32	)		4,304
December 31, 2010
Investment in consolidated companies	$	3,086	(a)	$	(32	)	$	3,054
Total investments and other assets		5,012			(32	)		4,980
Retained earnings		1,059			(32	)		1,027
Total equity		4,230			(32	)		4,198

(a) The amount of investment in consolidated companies differs from the amount originally reported in PHI’s 2012 Form 10-K due to certain reclassifications.

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(3)DEBT

For information concerning Pepco Holdings’ long-term debt obligations, see Note (11), “Debt,” to the consolidated financial statements of Pepco Holdings.

(4)COMMITMENTS AND CONTINGENCIES

For information concerning Pepco Holdings’ material contingencies and guarantees, see Note (16), “Commitments and Contingencies” to the consolidated financial statements of Pepco Holdings.

(5)INVESTMENT IN CONSOLIDATED COMPANIES

Pepco Holdings’ majority owned subsidiaries are recorded using the equity method of accounting. A breakout of the balance in Investment in consolidated companies is as follows:

	2012		2011
	(millions of dollars)
Conectiv	$	1,473	$	1,300
Potomac Electric Power Company		1,643		1,502
Potomac Capital Investment Corporation		507		467
Pepco Energy Services, Inc.		242		393
PHI Service Company		4		3
Total investment in consolidated companies	$	3,869	$	3,665

(6)DISCONTINUED OPERATIONS

Discontinued Operations

In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business, which was comprised of the retail electric and natural gas supply businesses. Pepco Energy Services implemented the wind-down by not entering into any new retail electric or natural gas supply contracts while continuing to perform under its existing retail electric and natural gas supply contracts through their respective expiration dates. On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, Pepco Energy Services completed the wind-down of its retail electric supply business in the second quarter of 2013 by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013. The operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations for financial reporting purposes.

Conectiv Energy

In April 2010, the Board of Directors approved a plan for the disposition of PHI’s competitive wholesale power generation, marketing and supply business, which had been conducted through Conectiv Energy. On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine for $1.64 billion. The disposition of Conectiv Energy’s remaining assets and businesses, consisting of its load service supply contracts, energy hedging portfolio, certain tolling agreements and other assets not included in the Calpine sale, has been completed.

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(7) RELATED PARTY TRANSACTIONS

As of December 31, 2012 and 2011, PHI had the following balances on its balance sheets due (to) from related parties:

	2012			2011
	(millions of dollars)
(Payable to) Receivable from Related Party (current) (a)
Potomac Capital Investment Corporation	$	—		$	(37	)
Conectiv		—			29
Conectiv Communications, Inc.		(4	)		(4	)
Potomac Electric Power Company		—			(15	)
PHI Service Company		1			2
Other		1			—
Total	$	(2	)	$	(25	)
Receivable from Related Party (non-current) (b)
Potomac Capital Investment Corporation	$	—		$	154
Money Pool Balance with Pepco Holdings (included in cash and cash equivalents)	$	262		$	257

(a) Included in Accounts payable due to associated companies.

(b) Included in Notes receivable from subsidiary companies.

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Schedule II, Valuation and Qualifying Accounts, for each registrant is submitted below.

Pepco Holdings, Inc.

Col. A	Col. B		Col. C				Col. D			Col. E
			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts(a)		Deductions(b)			Balance at End of Period
	(millions of dollars)
Year Ended December 31, 2012
Allowance for uncollectible accounts – customer and other accounts receivable	$	43	$	35	$	8	$	(52	)	$	34
Year Ended December 31, 2011
Allowance for uncollectible accounts – customer and other accounts receivable	$	44	$	45	$	8	$	(54	)	$	43
Year Ended December 31, 2010
Allowance for uncollectible accounts – customer and other accounts receivable	$	37	$	52	$	6	$	(51	)	$	44

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

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