Pepco 10-K 2014 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

Commission File Number	Exact Name of Registrant as Specified in its Charter, State or Other Jurisdiction of Incorporation, Address of Principal Executive Offices, Zip Code and Telephone Number (Including Area Code)	I.R.S. Employer Identification Number
001-31403	PEPCO HOLDINGS, INC. (Pepco Holdings or PHI), a Delaware corporation 701 Ninth Street, N.W. Washington, D.C. 20068 Telephone: (202)872-2000	52-2297449
001-01072	POTOMAC ELECTRIC POWER COMPANY (Pepco), a District of Columbia and Virginia corporation 701 Ninth Street, N.W. Washington, D.C. 20068 Telephone: (202)872-2000	53-0127880
001-01405	DELMARVA POWER & LIGHT COMPANY (DPL), a Delaware and Virginia corporation 500 North Wakefield Drive, 2nd Floor Newark, DE 19702 Telephone: (202)872-2000	51-0084283
001-03559	ATLANTIC CITY ELECTRIC COMPANY (ACE), a New Jersey corporation 500 North Wakefield Drive, 2nd Floor Newark, DE 19702 Telephone: (202)872-2000	21-0398280

Securities registered pursuant to Section 12(b) of the Act:

Registrant	Title of Each Class	Name of Each Exchange on Which Registered
Pepco Holdings	Common Stock, $.01 par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Registrant	Title of Each Class
Pepco	Common Stock, $.01 par value
DPL	Common Stock, $2.25 par value
ACE	Common Stock, $3.00 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Pepco Holdings	Yes  x	No  ¨	Pepco	Yes  ¨	No  x
DPL	Yes  ¨	No  x	ACE	Yes  ¨	No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Pepco Holdings	Yes  ¨	No  x	Pepco	Yes  ¨	No  x
DPL	Yes  ¨	No  x	ACE	Yes  ¨	No  x

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

Pepco Holdings	Yes  x	No  ¨	Pepco	Yes  x	No  ¨
DPL	Yes  x	No  ¨	ACE	Yes  x	No  ¨

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

Pepco Holdings	Yes  x	No  ¨	Pepco	Yes  x	No  ¨
DPL	Yes  x	No  ¨	ACE	Yes  x	No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K (applicable to Pepco Holdings only).    ¨

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

	Large Accelerated Filer	Accelerated Filer	Non- Accelerated Filer	Smaller Reporting Company
Pepco Holdings	x	¨	¨	¨
Pepco	¨	¨	x	¨
DPL	¨	¨	x	¨
ACE	¨	¨	x	¨

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

Pepco Holdings	Yes  ¨	No  x	Pepco	Yes  ¨	No  x
DPL	Yes  ¨	No  x	ACE	Yes  ¨	No  x

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

Registrant	Aggregate Market Value of Voting and Non-Voting Common Equity Held by Non-Affiliates of the Registrant at June 30, 2014	Number of Shares of Common Stock of the Registrant Outstanding at February 13, 2015
Pepco Holdings	$6,893.8 million (a)	252,815,448 ($.01 par value)
Pepco	None (b)	100 ($.01 par value)
DPL	None (c)	1,000 ($2.25 par value)
ACE	None (c)	8,546,017 ($3.00 par value)

(a) Solely for purposes of calculating this aggregate market value, PHI has defined its affiliates to include (i) those persons who were, as of June 30, 2014, its executive officers, directors and beneficial owners of more than 10% of its common stock, and (ii) such other persons who were deemed, as of June 30, 2014, to be controlled by, or under common control with, PHI or any of the persons described in clause (i) above.

(b) All voting and non-voting common equity is owned by Pepco Holdings.

(c) All voting and non-voting common equity is owned by Conectiv, LLC, a wholly owned subsidiary of Pepco Holdings.

THIS COMBINED FORM 10-K IS SEPARATELY FILED BY PEPCO HOLDINGS, PEPCO, DPL AND ACE. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS.

DOCUMENTS INCORPORATED BY REFERENCE

Information required by Items 10, 11, 12 and 13 of Part III of this report will be incorporated by reference to Pepco Holdings’ definitive proxy statement with respect to its 2015 Annual Meeting of Stockholders, if such definitive proxy statement is filed with the Securities and Exchange Commission on or before April 30, 2015.

TABLE OF CONTENTS

			Page
Glossary of Terms			i
Forward-Looking Statements			1
PART I
Item 1.	-	Business	4
Item 1A.	-	Risk Factors	28
Item 1B.	-	Unresolved Staff Comments	43
Item 2.	-	Properties	43
Item 3.	-	Legal Proceedings	44
Item 4.	-	Mine Safety Disclosures	44
PART II
Item 5.	-	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	45
Item 6.	-	Selected Financial Data	48
Item 7.	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	-	Quantitative and Qualitative Disclosures About Market Risk	134
Item 8.	-	Financial Statements and Supplementary Data	136
Item 9.	-	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	345
Item 9A.	-	Controls and Procedures	346
Item 9B.	-	Other Information	347
PART III
Item 10.	-	Directors, Executive Officers and Corporate Governance	348
Item 11.	-	Executive Compensation	348
Item 12.	-	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	348
Item 13.	-	Certain Relationships and Related Transactions, and Director Independence	349
Item 14.	-	Principal Accountant Fees and Services	349
PART IV
Item 15.	-	Exhibits and Financial Statement Schedules	350
Schedule I	-	Condensed Financial Information of Parent Company	352
Schedule II	-	Valuation and Qualifying Accounts	357
Signatures			377
Index to Exhibits Filed Herewith			380
Index to Exhibits Furnished Herewith			381
Exhibit 12	-	Statements Re: Computation of Ratios
Exhibit 21	-	Subsidiaries of the Registrant
Exhibit 23	-	Consents of Independent Registered Public Accounting Firm
Exhibits 31.1 - 31.8	-	Rule 13a-14a/15d-14(a) Certifications
Exhibits 32.1 - 32.4	-	Section 1350 Certifications

GLOSSARY OF TERMS

The following is a glossary of terms, abbreviations and acronyms that are used in the Reporting Companies’ SEC reports. The terms, abbreviations and acronyms used have the meanings set forth below, unless the context requires otherwise.

Term	Definition
2012 LTIP	Pepco Holdings, Inc. 2012 Long-Term Incentive Plan
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
AFUDC	Allowance for funds used during construction
AMI	Advanced metering infrastructure, a system that collects, measures and analyzes energy usuage data from advanced digital electric and gas meters known as smart meters
AOCL	Accumulated Other Comprehensive Loss
ASC	Accounting Standards Codification
BGE	Baltimore Gas and Electric Company
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
Bondable Transition Property	Principal and interest payments on the Transition Bonds and related taxes, expenses and fees
BSA	Bill Stabilization Adjustment
CAA	Federal Clean Air Act
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Conectiv	Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE
Conectiv Energy	PHI’s former competitive wholesale power generation, marketing and supply business, the disposition of which was completed in 2010
Consent	An amendment of and consent entered into by PHI, Pepco, DPL and ACE with respect to the credit agreement, which, among other things, permits the consummation of the Merger
Contract EDCs	Pepco, DPL and BGE, the Maryland utilities required by the MPSC to enter into a contract for new generation
CRMC	PHI’s Corporate Risk Management Committee
CTA	Consolidated tax adjustment
DCPSC	District of Columbia Public Service Commission
DC PLUG	District of Columbia Power Line Undergrounding
DDOE	District of Columbia Department of the Environment
Default Electricity Supply	The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or BGS
Default Electricity Supply Revenue	Revenue primarily from Default Electricity Supply
DEDA	Delaware Economic Development Authority
DEMEC	Delaware Municipal Electric Corporation, Inc.
DOE	U.S. Department of Energy
DOJ	U.S. Department of Justice
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
DRC	New Jersey Division of Rate Counsel
DRP	Direct Stock Purchase and Dividend Reinvestment Plan
DSEU	Delaware Sustainable Energy Utility
EBITDA	Earnings before interest, taxes, depreciation, and amortization
EDC	Electricity Distribution Company
EmPower Maryland	A Maryland demand-side management program for Pepco and DPL
EPA	U.S. Environmental Protection Agency
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board

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Term	Definition
FERC	Federal Energy Regulatory Commission
FLRP	Forward Looking Rate Plan
FPA	Federal Power Act
FTC	U.S. Federal Trade Commission
GAAP	Accounting principles generally accepted in the United States of America
GCR	Gas Cost Rate
GWh	Gigawatt hour
HPS	Hourly Priced Service
HSR Act	The Hart-Scott-Rodino Antitrust Improvements Act of 1976
Improvement Financing Act	The Electric Company Infrastructure Improvement Financing Act of 2014 enacted by the Council of the District of Columbia on May 3, 2014
IMU	Interface management unit
IRS	Internal Revenue Service
ISRA	Industrial Site Recovery Act
LIBOR	London Interbank Offered Rate
LTIP	Pepco Holdings, Inc. Long-Term Incentive Plan
MAPP	Mid-Atlantic Power Pathway
Mcf	Thousand Cubic Feet
MDC	MDC Industries, Inc.
Merger	Merger of Merger Sub with and into PHI, with PHI surviving as a wholly owned subsidiary of Exelon
Merger Agreement	Agreement and Plan of Merger, dated April 29, 2014 among Exelon, Merger Sub and PHI, as amended and restated on July 18, 2014
MFVRD	Modified fixed variable rate design
MMBtu	One Million British Thermal Units
MPSC	Maryland Public Service Commission
MW	Megawatt
MWh	Megawatt hour
NAV	Net Asset Value
NERC	North American Electric Reliability Corporation
New Jersey Societal Benefit Charge	A surcharge related to the New Jersey Societal Benefit Program
New Jersey Societal Benefit Program	A New Jersey public interest program for low income customers
NJ SOCA Law	The New Jersey law under which the SOCAs were established
NJBPU	New Jersey Board of Public Utilities
NOLC	Net operating loss carryforward
NOV	Notice of violation
NPCC	Northeast Power Coordinating Council
NPDES	National Pollutant Discharge Elimination System
NRG	NRG Energy, Inc. (successor to GenOn MD Ash Management, LLC)
NUGs	Non-utility generators
NYMEX	New York Mercantile Exchange
OPC	Office of People’s Counsel
OPEB	Other postretirement benefit
PCI	Potomac Capital Investment Corporation and its subsidiaries
Pepco	Potomac Electric Power Company
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI	Pepco Holdings, Inc.
PHI OPEB Plan	Pepco Holdings, Inc. Welfare Plan for Retirees

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Term	Definition
PHI Retirement Plan	PHI’s non-contributory, defined benefit pension plan
PJM	PJM Interconnection, LLC
PJM RTO	PJM regional transmission organization
Power Delivery	The transmission, distribution and default supply of electricity and, to a lesser extent, the distribution and supply of natural gas, conducted through Pepco, DPL and ACE, PHI’s regulated public utility subsidiaries
PPA	Power purchase agreement
Preferred Stock	Originally issued shares of PHI non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share
PRP	Potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005
RECs	Renewable energy credits
Regulated T&D Electric Revenue	Revenue from the transmission and the distribution of electricity to PHI’s customers within its service territories at regulated rates
Regulatory Asset Recovery Charge	Costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s obligation to serve the public
Regulatory Termination	Termination of the Merger Agreement under certain circumstances due to, generally speaking, the failure to obtain regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals
Reporting Company	PHI, Pepco, DPL or ACE
Revenue Decoupling Adjustment	An adjustment equal to the amount by which revenue from distribution sales differs from the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer
RF	ReliabilityFirst
RI/FS	Remedial investigation and feasibility study
ROE	Return on equity
RPS	Renewable Energy Portfolio Standards
Sarbanes-Oxley Act	Sarbanes-Oxley Act of 2002
SEC	Securities and Exchange Commission
SEP	Supplemental Environmental Project
SOCAs	Standard Offer Capacity Agreements required to be entered into by ACE pursuant to a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey
SOS	Standard Offer Service, how Default Electricity Supply is referred to in Delaware, the District of Columbia and Maryland
SPCC	Spill Prevention, Control, and Countermeasure plans, required pursuant to federal regulations requiring plans for facilities using oil-containing equipment in proximity to surface waters
SRECs	Solar renewable energy credits
T&D	Transmission and distribution
TEFA	Transitional Energy Facility Assessment, a New Jersey tax surcharge providing a gradual transition from the previous franchise and gross receipts tax eliminated in 1997, to its new total liability under the corporation business tax and the sales-and-use tax (this surcharge was eliminated in 2013)
TMDL	Total Maxium Daily Load
Transition Bond Charge	Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
Transition Bonds	Transition Bonds issued by ACE Funding

iii

Term	Definition
Triennial Plan	A three-year plan related to the construction in the District of Columbia of selected underground feeders as part of the DC PLUG initiative and the recovery of Pepco’s investment through a volumetric surcharge
VDEQ	Virginia Department of Environmental Quality
VIE	Variable interest entity
VRDBs	Variable Rate Demand Bonds
VSCC	Virginia State Corporation Commission
WACC	Weighted average cost of capital

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FORWARD-LOOKING STATEMENTS

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

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

• Certain risks and uncertainties associated with the proposed merger (the Merger) of an indirect, wholly owned subsidiary of Exelon Corporation, a Pennsylvania corporation (Exelon) with and into Pepco Holdings, including, without limitation:

• The inability of Pepco Holdings or Exelon to obtain regulatory approvals required for the Merger;

• Delays caused by required regulatory approvals, which may delay the Merger or cause the companies to abandon the Merger;

• The inability of Pepco Holdings or Exelon to satisfy conditions to the closing of the Merger;

• Unexpected costs, liabilities or delays that may arise from the Merger, including as a result of stockholder litigation;

• Negative impacts on the businesses of Pepco Holdings and its utility subsidiaries as a result of uncertainty surrounding the Merger; and

• Future regulatory or legislative actions impacting the industries in which Pepco Holdings and its subsidiaries operate, which actions could adversely affect Pepco Holdings and its utility subsidiaries.

• Changes in governmental policies and regulatory actions affecting the energy industry or one or more of the Reporting Companies specifically, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of transmission and distribution facilities and the recovery of purchased power expenses;

• The outcome of pending and future rate cases and other regulatory proceedings, including (i) challenges to the base return on equity (ROE) and the application of the formula rate process previously established by the Federal Energy Regulatory Commission (FERC) for transmission services provided by Pepco, DPL and ACE; (ii) challenges to DPL’s 2012, 2013 and 2014 annual FERC formula rate updates; and (iii) other possible disallowances related to recovery of costs (including capital costs and advanced metering infrastructure (AMI) costs) and expenses or delays in the recovery of such costs;

1

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

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

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

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

• Weather conditions affecting usage and emergency restoration costs;

• Population growth rates and changes in demographic patterns;

• Changes in customer energy demand due to, among other things, conservation measures and the use of renewable energy and other energy-efficient products, as well as the impact of net metering and other issues associated with the deployment of distributed generation and other new technologies;

• General economic conditions, including the impact on energy use caused by an economic downturn or recession, or by changes in the level of commercial activity in a particular region or service territory, or affecting a particular business or industry located therein;

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

• Changes in tax rates or policies;

• Changes in rates of inflation;

• Changes in accounting standards or practices;

• Unanticipated changes in operating expenses and capital expenditures;

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

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

• Pace of entry into new markets;

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

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

These forward-looking statements are also qualified by, and should be read together with, the risk factors included in Part I, Item 1A. “Risk Factors” and other statements in this Annual Report on Form 10-K, and investors should refer to such risk factors and other statements in evaluating the forward-looking statements contained in this Annual Report on Form 10-K.

2

Any forward-looking statements speak only as to the date this Annual Report on Form 10-K for each Reporting Company was filed with the Securities and Exchange Commission (SEC) and none of the Reporting Companies undertakes an obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for a Reporting Company to predict all such factors. Furthermore, it may not be possible to assess the impact of any such factor on such Reporting Company’s or its subsidiaries’ business (viewed independently or together with the business or businesses of some or all of the other Reporting Companies or their subsidiaries), or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. The foregoing factors should not be construed as exhaustive.

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Part I

Item 1. BUSINESS

Overview

Pepco Holdings is a holding company that was incorporated in Delaware in 2001. Through its regulated public utility subsidiaries, PHI is engaged primarily in the transmission, distribution and default supply of electricity, and, to a lesser extent, the distribution and supply of natural gas. The principal executive offices of PHI are located at 701 Ninth Street, N.W., Washington, D.C. 20068.

PHI’s public utility subsidiaries are:

Name of Utility	State and Year of Incorporation	Business	Service Territories	Address of Principal Executive Offices
Potomac Electric Power Company	District of Columbia (1896) Virginia (1949)	Transmission, distribution and default supply of electricity	District of Columbia Major portions of Montgomery and Prince George’s Counties, Maryland	701 Ninth Street, N.W., Washington, D.C. 20068
Delmarva Power & Light Company	Delaware (1909) Virginia (1979)	Transmission, distribution and default supply of electricity Distribution and supply of natural gas	Portions of Delaware and Maryland (electricity) Portions of New Castle County, Delaware (natural gas)	500 North Wakefield Drive, Newark, Delaware 19702
Atlantic City Electric Company	New Jersey (1924)	Transmission, distribution and default supply of electricity	Portions of Southern New Jersey	500 North Wakefield Drive, Newark, Delaware 19702

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The service territories of each of Pepco Holdings’ utilities are depicted in the map below:

PHI’s three utility subsidiaries comprise a single operating segment for accounting purposes, which is referred to herein as “Power Delivery.”

In addition to its regulated utility operations, Pepco Holdings, through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), is engaged in an energy savings performance contracting business, an underground transmission and distribution construction business and a thermal business.

The operations of Pepco Energy Services collectively comprise a separate, second operating segment for accounting purposes. During 2013, Pepco Energy Services completed the wind-down of its retail electricity and natural gas supply businesses, and, as a result, these businesses have been accounted for as discontinued operations, as described below under “Discontinued Operations.”

Through its wholly owned subsidiary, Potomac Capital Investment Corporation (PCI), PHI previously held a portfolio of cross-border energy lease investments. During 2013, Pepco Holdings completed the termination of its interests in its cross-border energy lease investments, and as a result, these investments have been accounted for as discontinued operations, as described below under “Discontinued Operations.”

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The following table shows PHI’s consolidated operating revenue and net income from continuing operations derived from the Power Delivery and Pepco Energy Services segments over the three preceding fiscal years.

	2014			2013		2012
	(millions of dollars)
Operating Revenue
Power Delivery	$	4,607		$	4,472	$	4,378
Pepco Energy Services		278			203		256
Net Income (Loss) from Continuing Operations
Power Delivery	$	320		$	289	$	235
Pepco Energy Services		(39	)		3		(8	)

For additional financial information with respect to PHI’s segments, see Note (5), “Segment Information,” to the consolidated financial statements of PHI.

PHI Service Company, a wholly owned subsidiary 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 service agreements 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 agreements.

Agreement and Plan of Merger with Exelon Corporation

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated July 18, 2014 (the Merger Agreement), with Exelon and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the Merger, with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014 and January 26, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for a purchase price of $18 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

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Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from FERC, the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement).

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. On December 22, 2014, the applicable waiting period under the HSR Act expired, and the HSR Act no longer precludes completion of the Merger. Although the Department of Justice (DOJ) allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised PHI that it has concluded its investigation. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015. On February 13, 2015, Pepco Holdings, DPL, Exelon, certain of Exelon’s affiliates, the Staff of the DPSC and certain other parties, filed a settlement agreement with the DPSC with respect to the Merger. This settlement agreement is subject to approval by the DPSC.

The Merger Agreement may be terminated by each of PHI and Exelon under certain circumstances, including if the Merger is not consummated by July 29, 2015 (subject to extension by PHI or Exelon to October 29, 2015, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Merger Agreement also provides for certain termination rights for both PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

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Business Strategy

PHI’s business objective is to be a top-performing, regulated power delivery company that delivers safe and reliable electric and natural gas service to its customers and through its regulatory proceedings, earns a just and reasonable rate of return on, and receives timely recovery of, its utility investments.

In seeking to achieve this objective, Pepco Holdings’ business strategy is guided by its core values of safety, integrity, and diversity and its mission of environmental stewardship, and is focused on the following initiatives:

• investing in its utilities’ transmission and distribution infrastructure;

• building a smarter grid and implementing other technological enhancements designed to:

• automate power delivery system functions and improve the reliability of the power distribution system;

• enable its utilities to restore power more quickly and efficiently;

• offer customers detailed information about, and options to help customers better manage, their energy usage;

• enhance the customer experience and PHI’s communications with customers; and

• through Pepco Energy Services, providing comprehensive energy management solutions and developing, installing and operating renewable energy solutions.

In furtherance of its business strategy, PHI entered into the Merger Agreement with Exelon Corporation. For a discussion of the Merger Agreement, see “– Agreement and Plan of Merger with Exelon Corporation.” Further, PHI may dispose of existing businesses consistent with the terms of the Merger Agreement. PHI also may from time to time refine components of its business strategy as it deems necessary or appropriate in response to business factors and other conditions consistent with the terms of the Merger Agreement and subject to regulatory requirements.

Overview of the Power Delivery Business

Distribution and Default Supply of Electricity

Each of PHI’s utility subsidiaries owns and operates a network of wires, substations and other equipment that are classified as transmission facilities, distribution facilities or common facilities (which are used for both transmission and distribution). Transmission facilities carry wholesale electricity into, out of and across the utilities’ service territories. Distribution facilities carry electricity from the transmission facilities to the customers located in the utilities’ service territories.

Each utility subsidiary is responsible for the distribution of electricity to customers within its service territory or territories and for which it is paid tariff rates established by the applicable public service commissions. While the transmission and distribution of electricity is regulated, the law of each of these service territories allows for competition in the supply of electricity, which enables distribution customers to contract to purchase their electricity from a supplier approved by the applicable public service commission. PHI’s utility subsidiaries supply electricity at regulated rates to customers who do not elect to purchase their electricity from a competitive supplier. These “default” supply services are referred to generally in this Form 10-K as Default Electricity Supply. The regulatory term for Default Electricity Supply is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. The results of operations of PHI’s utility subsidiaries are only minimally impacted when customers choose to obtain their electricity through competitive suppliers because the utilities earn their approved rates of return by providing distribution service, and not by supplying the electricity.

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Transmission of Electricity and Relationship With PJM

Each of PHI’s utility subsidiaries provides transmission services within the jurisdictions that encompass its electricity distribution service territory. In the aggregate, PHI owns approximately 4,600 circuit miles of interconnected transmission lines with voltages ranging from 115 kilovolts (kV) to 500 kV. Under the Open Access Transmission Tariff adopted by FERC, each owner of transmission services is required to provide transmission customers with non-discriminatory access to its transmission facilities at tariff rates approved by FERC.

The transmission facilities owned by Pepco, DPL and ACE are interconnected with the transmission facilities of contiguous utilities and are part of an interstate power transmission grid over which electricity is transmitted throughout a region encompassing the mid-Atlantic portion of the United States and parts of the Midwest. PJM is the FERC-approved independent operator of this transmission grid and manages the wholesale electricity market within its region. Pepco, DPL and ACE each are members of the PJM Regional Transmission Organization (PJM RTO), the regional transmission organization designated by FERC to coordinate the movement of wholesale electricity in PJM’s region.

In accordance with FERC-approved rules, Pepco, DPL, ACE and the other transmission-owning utilities in the PJM region make their transmission facilities available to PJM, and PJM directs and controls the operation of these transmission facilities. Each transmission owner is compensated at transmission rates approved by FERC for the use of its transmission facilities. PJM provides billing and settlement services, collects transmission service revenue from transmission service customers and distributes the revenue to the transmission owners.

PJM also directs the regional transmission planning process within its region. The Board of Managers of PJM reviews and approves all transmission expansion plans within the PJM region, including the construction of new transmission facilities by PJM members. Changes in the current policies for building new transmission lines ordered by FERC and implemented by PJM could result in additional competition to build transmission lines in the PJM region, including in the service territories of PHI’s utility subsidiaries, and could allow PHI’s utility subsidiaries the opportunity to construct transmission facilities in other service territories.

For a discussion of the regulation of transmission rates, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulatory and Other Matters – Rate Proceedings – Transmission” and for a discussion of recently completed and pending FERC transmission rate proceedings, see Note (7), “Regulatory Matters – Rate Proceedings – Federal Energy Regulatory Commission,” to the consolidated financial statements of PHI.

Distribution and Supply of Natural Gas

DPL owns pipelines and other equipment for the distribution and supply of natural gas. DPL uses its natural gas distribution facilities to deliver natural gas to retail customers in its service territory and provides transportation-only services to customers that purchase natural gas from another supplier. Intrastate transportation customers pay DPL distribution service rates approved by the DPSC. Rates for the interstate transportation and sale of wholesale natural gas are regulated by FERC. DPL purchases natural gas supplies for resale to its retail service customers from marketers and producers through a combination of long-term agreements and next-day distribution arrangements.

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PHI’s Utility Subsidiaries

Potomac Electric Power Company

Pepco’s electric distribution service territory consists of the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. The service territory covers approximately 640 square miles and, as of December 31, 2014, had a population of approximately 2.3 million. This region includes the following key industries that contribute to the regional economic base:

• Federal and municipal government services;

• Professional, scientific, educational and technical services;

• Leisure, hospitality and transportation services; and

• Healthcare and social services.

The following table shows the number of Pepco distribution customers in each of its service territories as of the end of each of the preceding three years.

	2014		2013		2012
	(in thousands)
District of Columbia		271		264		260
Maryland		544		537		533
Total		815		801		793

Pepco distributed a total of 25,751,000, 25,801,000 and 26,006,000 megawatt (MW) hours (MWh) of electricity in 2014, 2013 and 2012, respectively. The following table shows the allocation by percentage among customer types of the total MWh of electricity delivered by Pepco in each of its service territories during each of the preceding three fiscal years:

	2014			2013			2012
District of Columbia:
Residential		8	%		8	%		8	%
Commercial, industrial and other		35	%		35	%		35	%
Total		43	%		43	%		43	%
Maryland:
Residential		22	%		22	%		22	%
Commercial, industrial and other		35	%		35	%		35	%
Total		57	%		57	%		57	%

Pepco has been designated as the default electricity supplier in its District of Columbia and Maryland service territories by the DCPSC and the MPSC, respectively. Pepco purchases the electricity required to satisfy its SOS obligations from wholesale suppliers primarily under contracts entered into in accordance with competitive bid procedures approved and supervised by each of the DCPSC and the MPSC. For commercial customers in the District of Columbia and large commercial customers in Maryland that do not purchase their electricity from a competitive supplier, Pepco is obligated to provide Hourly Priced Service (HPS), a form of SOS service for which Pepco purchases the electricity in the next-day and other short-term PJM RTO markets.

Under orders issued by the DCPSC, Pepco is obligated to provide SOS to residential and small, medium-sized and large commercial customers in the District of Columbia indefinitely. Under orders issued by the MPSC, Pepco is obligated to provide SOS to residential and small commercial customers and to medium-sized commercial customers in Maryland through November 2015. As contracts expire, they are rebid

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annually by Pepco through the MPSC-approved request for proposal process. Pepco is paid tariff rates for the transmission and distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territory, whether the customer receives SOS or HPS, or purchases electricity from a competitive supplier, and is entitled to recover from its SOS and HPS customers the costs of acquiring the electricity, plus an administrative charge that is intended to allow it to recover its administrative costs, plus a modest margin, which varies depending on the customer class.

The following table shows for Pepco customers in the District of Columbia and Maryland the percentage of distribution sales (measured by MWh) over the past three fiscal years to SOS customers.

	2014			2013			2012
District of Columbia		27	%		25	%		25	%
Maryland		41	%		41	%		40	%

In the District of Columbia, under various acts of Congress, pursuant to Pepco’s corporate charter, and subject to the supervision of the DCPSC, Pepco has the non-exclusive authority to install and maintain overhead and underground transmission and distribution lines and other related facilities for the furnishing of electricity. Pepco’s right to occupy public space for utility purposes is by permit from the District of Columbia and the federal government. Pepco is the only public utility that distributes electricity for sale to the public in the District of Columbia.

In Maryland, Pepco operates pursuant to state-wide franchises granted by Maryland’s General Assembly that are unlimited in duration. These franchises were granted to Pepco or to predecessor companies acquired by Pepco, and confer, among other things, the ability to construct electric transmission and distribution lines. Pursuant to statute, public service companies in Maryland may exercise a franchise to the extent authorized by the MPSC. The service territories for Pepco, as well as for other electric utilities in the state, were precisely delineated in 1966 by the MPSC and have been modified in minor ways over the years.

Delmarva Power & Light Company

DPL is engaged in the transmission, distribution and default supply of electricity in portions of Delaware and Maryland. In northern Delaware, DPL also supplies and delivers natural gas to retail customers and provides transportation-only services to retail customers that purchase natural gas from another supplier.

In Maryland, DPL operates pursuant to state-wide franchises that are substantially similar in nature to those described above with respect to Pepco’s Maryland operations. DPL’s exclusive and continuing authority to distribute electricity and natural gas in its non-municipal service territories in Delaware is derived from legislation, through which the DPSC has established exclusive service territories. With respect to municipalities that it serves, DPL provides service under various franchises granted to DPL and predecessor companies, which franchises are generally either unlimited as to time or renew automatically.

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Distribution and Supply of Electricity

DPL’s electric distribution service territory consists of portions of the state of Delaware, and Caroline, Cecil, Dorchester, Harford, Kent, Queen Anne’s, Somerset, Talbot, Wicomico and Worcester counties in Maryland. This territory covers approximately 5,000 square miles and, as of December 31, 2014, had a population of approximately 1.4 million. This region is economically diverse and includes the following key industries that contribute to the regional economic base:

• Commercial activities in the region include banking, government, educational and health services, transportation and tourism.

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

The following table shows the number of DPL electricity distribution customers in each of its service territories as of the end of each of the preceding three fiscal years.

	2014		2013		2012
	(in thousands)
Delaware		308		305		303
Maryland		202		201		200
Total		510		506		503

DPL distributed a total of 12,413,000, 12,465,000 and 12,641,000 MWh of electricity in 2014, 2013 and 2012, respectively. The following table shows the allocation by percentage among customer types of the total MWh of electricity delivered by DPL in each of its service territories during each of the preceding three fiscal years:

	2014			2013			2012
Delaware:
Residential		24	%		24	%		24	%
Commercial and industrial		41	%		42	%		43	%
Total		65	%		66	%		67	%
Maryland:
Residential		18	%		17	%		16	%
Commercial and industrial		17	%		17	%		17	%
Total		35	%		34	%		33	%

DPL has been designated as the default electricity supplier in its Delaware and Maryland service territories by the DPSC and the MPSC, respectively. DPL purchases the electricity required to satisfy its SOS obligations from wholesale suppliers primarily under contracts entered into in accordance with competitive bid procedures approved and supervised by each of the DPSC and the MPSC. DPL also has an obligation to provide HPS for its largest customers in Delaware and its large customers in Maryland. DPL acquires power to supply its HPS customers in the next-day and other short-term PJM RTO markets.

Under orders issued by the DPSC, DPL is obligated to provide SOS to residential, small commercial and industrial customers in Delaware through May 2018, and to medium, large and general service commercial customers in Delaware through May 2016. Under orders issued by the MPSC, DPL is obligated to provide SOS to residential and small commercial customers in Maryland until further action of the Maryland General Assembly, and to medium-sized commercial customers in Maryland through November 2015. As contracts expire, they are rebid annually by DPL through the MPSC-approved request for proposal process. In Delaware and Maryland, DPL is paid tariff rates for the transmission and distribution of electricity over its transmission and distribution facilities to all electricity customers in its

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service territories, whether the customer receives SOS or HPS, or purchases electricity from a competitive supplier. In Delaware, DPL is also entitled to recover from its SOS and HPS customers the associated costs of acquiring the electricity (including transmission, capacity and ancillary services costs and costs to satisfy renewable energy requirements), plus an amount referred to as a Reasonable Allowance for Retail Margin. In Maryland, DPL is entitled to recover from its SOS and HPS customers the costs of acquiring the electricity, plus an administrative charge that is intended to allow it to recover its administrative costs, plus a modest margin, which varies depending on the customer class.

The following table shows for DPL customers in Delaware and Maryland the percentage of distribution sales (measured in MWh) over the past three fiscal years to SOS customers.

	2014			2013			2012
Delaware		44	%		44	%		47	%
Maryland		51	%		51	%		53	%

Distribution and Supply of Natural Gas

DPL provides regulated natural gas supply and distribution service to customers in a service territory consisting of a major portion of New Castle County in Delaware. This service territory covers approximately 275 square miles and, as of December 31, 2014, had a population of approximately 500,000.

Large volume commercial, institutional, and industrial natural gas customers may purchase natural gas from DPL. Alternatively, a customer receiving a “transportation-only” service from DPL will purchase natural gas from a competitive supplier and have the natural gas delivered through DPL’s distribution facilities. The following table provides certain information regarding DPL’s natural gas distribution business for each of the last three fiscal years.

	2014			2013			2012
	(in thousands, except percentages)
Number of natural gas customers		128			126			125
Thousand cubic feet (Mcf) of natural gas delivered		21,031			19,796			16,815
Percentage of natural gas supplied and delivered by DPL		69	%		64	%		60	%

The following table shows on a percentage basis the allocation among customer types of the Mcf of natural gas delivered by DPL in Delaware in each of the preceding three fiscal years.

	2014			2013			2012
Residential		41	%		40	%		38	%
Commercial and industrial		29	%		25	%		22	%
Transportation and other		30	%		35	%		40	%

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Atlantic City Electric Company

Electricity Distribution and Supply

ACE’s electric distribution service territory consists of Gloucester, Camden, Burlington, Ocean, Atlantic, Cape May, Cumberland and Salem counties in southern New Jersey. The service territory covers approximately 2,700 square miles and had, as of December 31, 2014, a population of approximately 1.1 million. This region is economically diverse and includes the following key industries that contribute to the regional economic base:

• Commercial activities in the region include professional services, government, educational and health services, casinos and tourism.

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

The following table provides certain information regarding ACE’s electric distribution business for each of the last three fiscal years.

	2014		2013		2012
	(in thousands)
Number of electric distribution customers		546		545		545
MWh of electricity delivered		9,051		9,231		9,495

The following table shows the allocation by percentage among customer types of the total MWh of electricity delivered by ACE during each of the preceding three fiscal years.

	2014			2013			2012
Residential		45	%		46	%		46	%
Commercial and industrial		55	%		54	%		54	%

ACE has been designated as the default electricity supplier in its service territory by the NJBPU. In New Jersey, each of the state’s electric distribution companies, including ACE, jointly obtains the electricity to meet such companies’ collective BGS obligations from competitive suppliers selected through auctions authorized by the NJBPU for the supply of New Jersey’s total BGS requirements. Each winning bidder is required to supply its committed portion of the BGS customer load with full requirements service, consisting of power supply and transmission service. ACE provides two types of BGS:

• fixed price BGS, which is provided to smaller commercial and residential customers at seasonally-adjusted fixed prices (which as of December 31, 2014, had a peak load of approximately 1,511 MW and represented approximately 97% of ACE’s total BGS load); and

• commercial and industrial energy price BGS, which is provided to large customers at hourly PJM RTO real-time market prices for a term of 12 months (which as of December 31, 2014, had a peak load of approximately 54 MW and represented approximately 3% of ACE’s total BGS load).

ACE is paid tariff supply rates established by the NJBPU that compensate it for the cost of obtaining the BGS supply. These rates are set such that ACE does not make any profit or incur any loss with respect to the supply component of its BGS obligations. ACE is also paid tariff rates for the transmission and distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territory, whether the customer receives BGS or purchases electricity from a competitive supplier.

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For the year ended December 31, 2014, 49% of ACE’s total distribution sales (measured in MWh) were to BGS customers, as compared to 48% and 51% in 2013 and 2012, respectively.

ACE operates under non-exclusive franchises that have been granted by the NJBPU and under certain non-exclusive consents from municipalities in which ACE provides service. While most of the municipal consents were granted in perpetuity, two of the municipal consents require renewal on a periodic basis in accordance with their terms, and are subject to the ultimate review and approval of the NJBPU. All of the franchises and consents are currently in full force and effect.

Atlantic City Electric Transition Funding LLC

In 2001, ACE established Atlantic City Electric Transition Funding LLC (ACE Funding) 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 were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable transition bond charge (Transition Bond Charge) from ACE customers pursuant to bondable stranded costs rate orders issued by the 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). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges (representing revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) collected from ACE’s customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding.

Smart Grid Initiatives

PHI’s utility subsidiaries are engaged in transforming the power grid that they own and operate into a “smart grid,” a network of automated digital devices capable of collecting and communicating large amounts of real-time data. PHI believes that the smart grid benefits its customers by:

• improving service reliability of the energy distribution system;

• automating specific distribution system functions;

• enabling its utilities to restore energy to customers more quickly and efficiently;

• facilitating more efficient use of energy to meet the challenges of rising energy costs and governmental energy reduction goals;

• permitting its utilities to obtain and communicate to their customers timely and accurate information regarding energy usage and outages; and

• enhancing communications with its customers and the overall customer experience.

A central component of the smart grid is AMI, a system that collects, measures and analyzes energy usage data from advanced digital meters, known as “smart meters.” Also critical to the operation of the smart grid is distribution automation technology, which is comprised of automated devices that have internal intelligence and can be controlled remotely to better manage power flow and restore service quickly and more safely. Both the AMI system and distribution automation are enabled by advanced technology that communicates with devices installed on the energy delivery system and transmits energy usage data to the host utility. The implementation of the AMI system and distribution automation involves an integration of technologies provided by multiple vendors.

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Both Pepco and DPL have completed the installation and activation of AMI smart meters and related technologies in each of their jurisdictions. ACE has yet to receive approval from the NJBPU to proceed with the installation of AMI smart meters.

The DCPSC, the MPSC and the DPSC have approved the creation by Pepco and DPL of regulatory assets to defer certain costs associated with the implementation of the AMI system between rate cases and to defer carrying costs associated with the deferred costs. Thus, these costs will be recovered in the future through base rates; however, for AMI-related costs incurred by Pepco in Maryland with respect to test years after 2011, pursuant to an MPSC order, the recovery of such costs will be allowed when Pepco demonstrates that the AMI system is cost-effective. The MPSC’s July 2013 order in Pepco’s November 2012 electric distribution base rate application excluded the cost of AMI smart meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system. As a result, costs for AMI smart meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI-related costs incurred in conjunction with the deployment of the AMI system that are deferred and on which carrying costs are deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates.

In 2010, two of PHI’s utility subsidiaries were granted cash awards in the aggregate amount of $168 million by the U.S. Department of Energy to support their smart grid initiatives.

• Pepco was awarded $149 million for AMI, direct load control, distribution automation and communications infrastructure, of which $148 million has been received through December 31, 2014.

• ACE was awarded $19 million for direct load control, distribution automation and communications infrastructure, all of which has been received through December 31, 2014.

Substantially all of the awards received have been recorded as reductions in AMI-related costs (including those costs capitalized as property, plant and equipment and those costs deferred as regulatory assets).

Utility Capital Expenditures

PHI’s utility subsidiaries allocate a substantial portion of their total capital expenditures to improving the reliability of their electrical transmission and distribution systems and replacing aging infrastructure throughout their service territories. These activities include:

• identifying and upgrading under-performing feeder lines;

• adding new facilities to support load;

• installing distribution automation systems on both the overhead and underground network systems; and

• rejuvenating and replacing underground residential cables.

In addition, PHI’s utility subsidiaries allocate capital expenditures to increasing transmission and distribution system capacity, providing resiliency against major storm events, providing operating and system flexibility and installing and upgrading facilities for new and existing customers. For a discussion of PHI’s consolidated capital expenditure plan for 2015 through 2019, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Capital Requirements – Capital Expenditures.”

District of Columbia Power Line Undergrounding Initiative

On May 3, 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone

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power lines, which lines and surrounding conduit would be owned and maintained by Pepco. A more detailed discussion of the Improvement Financing Act is provided in Note (7), “Regulatory Matters – District of Columbia Power Line Undergrounding Initiative,” to the consolidated financial statements of PHI.

NERC Reliability Standards

NERC has established, and FERC has approved, reliability standards with regard to the bulk power system that impose certain operating, planning and cyber security requirements on Pepco, DPL and ACE. There are eight NERC regional oversight entities, including ReliabilityFirst(RF), of which Pepco, DPL, ACE and Pepco Energy Services are members. These oversight entities are charged with the day-to-day implementation and enforcement of NERC’s reliability standards, which impose certain operating, planning and cybersecurity requirements on the bulk power systems of each utility. RF performs compliance audits on entities registered with NERC based on reliability standards and criteria established by NERC. NERC and RF also conduct compliance investigations in response to a system disturbance, complaint, or possible violation of a reliability standard identified by other means. Each of PHI’s utility subsidiaries are subject to routine audits and monitoring for compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets designated as “critical assets” (including cybersecurity assets) subject to NERC’s cybersecurity standards. NERC is empowered to impose financial penalties, fines and other sanctions for non-compliance with certain rules and regulations.

Energy Efficiency Initiatives

Dynamic Pricing

Dynamic pricing provides customers with incentives to reward them for decreasing their energy use during peak energy demand periods, when energy demand and consequently, the cost of supplying electricity, are higher. PHI’s dynamic pricing rate structures, implemented in tandem with PHI’s smart grid, provide customers with billing credits when they reduce their power usage in response to their utility’s request. Dynamic pricing programs include variable peak pricing and critical peak rebate programs.

Dynamic pricing has been approved by the respective public service commissions and is in place for Pepco customers in Maryland and DPL customers in Maryland and Delaware. As of December 31, 2014, approximately 468,000 Pepco customers in Maryland, 5,000 DPL customers in Maryland and 252,000 DPL customers in Delaware have participated in dynamic pricing programs.

In February 2014, the DCPSC rejected Pepco’s proposal for dynamic pricing in the District of Columbia, but expressed interest in exploring dynamic pricing rate structures in future proceedings. Dynamic pricing has not been approved by the NJBPU for ACE’s customers in New Jersey.

Utility Energy Efficiency Programs

Each of Pepco, DPL and ACE has implemented the Energy Wise Rewards™ program, which allows participating customers to reduce energy usage and costs by authorizing the utility to cycle their air conditioner compressors off and on during high energy demand periods. Customers participating in this program are eligible to receive a credit on their bill. Pepco and DPL have also implemented a portfolio of energy efficiency programs designed to reduce energy consumption in Maryland, including appliance rebate and recycling, home energy check-ups, rebates on the purchase of energy efficiency equipment and services and discounts on energy efficient light bulbs and lighting fixtures. The MPSC has approved a customer surcharge through 2015 to recover Pepco’s and DPL’s costs associated with these energy efficiency programs.

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Pepco Energy Services

Pepco Energy Services is engaged in the following:

• Energy savings performance contracting business: designing, constructing and operating energy efficiency projects and distributed generation equipment, including combined heat and power plants, principally for federal, state and local government customers;

• Underground transmission and distribution business: providing underground transmission and distribution construction and maintenance services for electric utilities in North America; and

• Thermal business: providing steam and chilled water under long-term contracts through systems owned and operated by Pepco Energy Services, primarily to hotel casinos in Atlantic City, New Jersey.

The energy savings performance contracting business is highly competitive, and Pepco Energy Services competes with other energy services companies primarily with respect to contracts with federal, state and local governments and independent agencies. Many of these energy services companies are subsidiaries of larger building controls and equipment providers or utility holding companies. Competitive offerings include a wide range of electrical and thermal system upgrades, improved controls, and generation equipment such as combined heat and power units. Among the factors as to which companies in this business compete are the amount and duration of the guarantees provided in energy savings performance contracts and the quality and value of service provided to customers. In connection with many of Pepco Energy Services’ energy savings performance contracts, Pepco Energy Services provides performance guarantees, including guarantees of a certain level of energy savings. This business is affected by new entrants into the market, the financial strength of customers, governmental directives regarding energy efficiency, energy prices, and general economic conditions. Pepco Energy Services’ backlog of construction contracts in this business decreased to $41 million at December 31, 2014 from $91 million at December 31, 2013. Pepco Energy Services estimates that it will complete the construction contracts in its 2014 backlog during 2015.

Most of Pepco Energy Services’ energy savings performance contracts with federal, state and local governments, as well as those with independent agencies, such as housing and water authorities, contain provisions authorizing the governmental authority or independent agency to terminate the contract at any time. Those provisions include explicit mechanisms which, if exercised, would require the other party to pay Pepco Energy Services for work performed through the date of termination and for additional costs incurred as a result of the termination.

Through its wholly owned subsidiary, W.A. Chester, L.L.C., and its subsidiaries, Pepco Energy Services constructs and maintains underground transmission and distribution projects for electric utilities in North America. W.A. Chester is one of the two largest North American contractors that specializes in the installation and maintenance of pipe-type cable systems, a technology that W.A. Chester believes currently accounts for the majority of existing underground transmission circuit miles in North America. W.A. Chester’s primary competitor in the pipe-type cable system market is UTEC Constructors Corporation, and there are several other contractors that do not specialize in this cable system but rather undertake installation projects on a more limited basis. W.A. Chester also competes in the market for the installation and maintenance of solid dielectric cable, which is a relatively newer technology compared to pipe-type cable systems. The solid dielectric cable installation and maintenance market is highly competitive and composed of numerous different competitors, and the barriers to entry in this market are relatively low. The principal factors for competition in both of these markets are price, experience, customer service and ability to handle a wide range of utility applications. W.A. Chester believes its competitive strengths in both of these markets are the breadth of its experience in working with both technologies in various utility applications (including new installations, modifications, upgrades and maintenance of existing systems), its in-depth knowledge of the U.S. and Canadian utility industries and utility customers’ needs, and its ability to manage successfully all phases of these projects for the

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customer. W.A. Chester’s backlog of construction contracts increased to $104 million at December 31, 2014 from $84 million at December 31, 2013. W.A. Chester estimates that it will complete $67 million of the construction contracts in its backlog in 2015 and $37 million in 2016.

Revenues associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City are derived from long-term contracts with a few major customers in the Atlantic City hotel and casino industry. The carrying amount of Pepco Energy Services’ long-lived assets in Atlantic City at December 31, 2014 totaled $2 million, after impairment losses aggregating $81 million that were recorded during the third and fourth quarters of 2014. In September 2014, two significant customers of these thermal operations declared Chapter 11 bankruptcy. One of the customers closed operations in September 2014 and is seeking a buyer for its facility. The second customer announced that it would remain open in 2015 but that it could close operations later this year if it is unable to lower its operating costs. At September 30, 2014, PHI performed impairment tests on asset groups comprising substantially all of the long-lived assets associated with its thermal operations in Atlantic City and recorded an impairment loss of $53 million ($32 million after-tax) with respect to the most significant asset group (with a carrying amount, before the impairment loss, of $70 million at September 30, 2014). In light of recent developments regarding future business prospects with the two significant customers that declared bankruptcy in September 2014 (including their rejection of Pepco Energy Services’ long-term thermal contracts during February 2015, as part of these customers’ bankruptcy proceedings) and the fact that two other significant customers of the thermal operations declared Chapter 11 bankruptcy in January 2015, Pepco Energy Services again performed impairment tests on asset groups comprising substantially all of the long-lived assets associated with its thermal operations in Atlantic City at December 31, 2014. As a result, Pepco Energy Services recorded an additional impairment charge of $28 million ($16 million after-tax) in the fourth quarter of 2014 that was associated with the most significant asset group and another asset group. Future developments with respect to these and other customers in Atlantic City may require Pepco Energy Services to perform additional impairment analyses of the thermal operations and certain related assets. If these assets are determined to be further impaired, Pepco Energy Services would reduce the carrying value of these assets by the amount of the impairment and record a corresponding non-cash charge to earnings. Moreover, the contract rejections referred to above are expected to reduce Pepco Energy Services’ future earnings and cash flow associated with its thermal operations in Atlantic City.

PHI guarantees the obligations of Pepco Energy Services under certain contracts in its energy savings performance contracting business and underground transmission and distribution construction business. At December 31, 2014, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $336 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects. These guarantees totaled $185 million at December 31, 2014.

During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services is demolishing the Benning Road generation facility and realizing the scrap metal salvage value of the facility. The demolition of the facility commenced in the fourth quarter of 2013 and is expected to be completed in the first quarter of 2015. Pepco Energy Services is recognizing the salvage proceeds associated with the scrap metals at the facility as realized. At December 31, 2014, Pepco Energy Services owned five renewable energy generating facilities, with an aggregate generating capacity of 17,400 KW. See Part I, Item 2. “Properties – Generating Facilities” for more information about these facilities.

Discontinued Operations

Through its wholly owned subsidiary PCI, PHI maintained a portfolio of cross-border energy lease investments. During the third quarter of 2013, PHI completed the termination of its interests in its cross-border energy lease investments. These activities, which previously comprised substantially all of the operations of the Other Non-Regulated segment, have been accounted for as discontinued operations. The remaining operations of the Other Non-Regulated segment, which no longer meet the definition of a separate segment for financial reporting purposes, are included in Corporate and Other. Substantially all of the information in the notes to the consolidated financial statements of PHI with respect to the cross-border energy lease investments has been consolidated in Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments.”

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In 2013, Pepco Energy Services completed a previously announced wind-down of its retail electric and retail natural gas supply businesses. These operations are being accounted for 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 the notes to the consolidated financial statements of PHI with respect to Pepco Energy Services’ retail electric and retail natural gas supply businesses has been consolidated in Note (20), “Discontinued Operations – Retail Electric and Natural Gas Supply Businesses of Pepco Energy Services.”

Seasonality

Power Delivery

The operating results of Power Delivery historically have been directly related to the volume of electricity delivered to its customers, producing higher revenues and net income during periods when customers consumed higher amounts of electricity (usually during periods of extreme temperatures) and lower revenues and net income during periods when customers consumed lower amounts of electricity (usually during periods of mild temperatures). This has been due in part to the longstanding practice of tying the distribution charges paid by customers to kilowatt-hours of electricity used. Because most of the costs associated with the distribution of electricity do not vary with the volume of electricity delivered, this pricing mechanism also contributed to seasonal variations in net income.

As a result of the implementation of a bill stabilization adjustment (BSA) for retail customers of Pepco and DPL in Maryland and for customers of Pepco in the District of Columbia, distribution revenues from utility customers in these jurisdictions have been decoupled from the amount of electricity delivered. Under the BSA, utility customers pay an approved distribution charge for their electric service which does not vary by electricity usage. This change has had the effect of aligning annual distribution revenues more closely with annual distribution costs. In addition, the change has had the effect of eliminating changes in customer electricity usage, whether due to weather conditions or for any other reason, as a factor having an impact on annual distribution revenue and net income in those jurisdictions. The BSA also eliminates what otherwise might be a disincentive for the utility to aggressively develop and promote efficiency programs. A comparable revenue decoupling mechanism proposed for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC although there was little activity in this matter in 2014. Distribution revenues are not decoupled for the distribution of electricity by ACE in New Jersey, and thus are subject to variability due to changes in customer consumption.

In contrast to electricity distribution costs, the cost of the electricity supplied, which is the largest component of a customer’s bill, does vary directly in relation to the volume of electricity used by a customer. Accordingly, whether or not a BSA is in effect for the jurisdiction, the revenues of Pepco, DPL and ACE from the supply of electricity and natural gas vary based on consumption and on this basis are seasonal. Because the revenues received by each of the utility subsidiaries for the default supply of electricity and natural gas closely approximate the supply costs, the impact on net income is immaterial, and therefore is not seasonal.

Pepco Energy Services

The energy services business of Pepco Energy Services is not seasonal, except with respect to its thermal operations. The thermal operations of Pepco Energy Services provide steam and chilled water to customers year-round. Steam usage peaks during months with colder temperatures and chilled water usage peaks during months with warmer temperatures. The rates charged customers adjust quarterly for the cost of natural gas used to produce steam and electricity used to produce chilled water. Pepco Energy Services’ revenues and gross profit from its thermal operations will fluctuate based on the volumes of steam and chilled water delivered to customers.

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Regulation

The operations of PHI’s utility subsidiaries, including the rates and tariffs they are permitted to charge customers for the transmission and distribution of electricity, and, in the case of DPL, the distribution and transportation of natural gas, are subject to regulation by governmental agencies in the jurisdictions in which the subsidiaries provide utility service as described above in “– PHI’s Utility Subsidiaries.” Rates and tariffs are established by these regulatory commissions.

As further described in Note (1), “Organization,” to the consolidated financial statements of PHI, on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described in Note (7), “Regulatory Matters – Rate Proceedings,” to the consolidated financial statements of PHI.

In addition to the other regulatory matters described elsewhere in this section and in Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI, provided below are summary descriptions of certain regulatory matters involving PHI’s utility subsidiaries.

Mitigation of Regulatory Lag

An important factor in the ability of PHI’s utility subsidiaries to earn their authorized ROE is the willingness of applicable public service commissions to adequately address the shortfall in revenues in a utility’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Pepco, DPL and ACE are currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than their revenue growth.

In an effort to minimize the effects of regulatory lag, prior to the initial execution of the Merger Agreement in April 2014, PHI’s utility subsidiaries had been filing electric distribution base rate cases every nine to twelve months in each of their jurisdictions, pursuing alternative ratemaking mechanisms, evaluating potential reductions in planned capital expenditures, and discussing with the regulatory community and other stakeholders the changing regulatory model economics that are causing regulatory lag.

As further described in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation,” PHI has entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings. Accordingly, with the exception of ongoing rate cases (see Note (7), “Regulatory Matters – Rate Proceedings,” to the consolidated financial statements of PHI), PHI’s efforts to mitigate regulatory lag have been delayed pending the closing of the Merger or the termination of the Merger Agreement.

MAPP Settlement Agreement

For information about the Mid-Atlantic Power Pathway (MAPP) settlement agreement, please refer to Note (7), “Regulatory Matters – MAPP Settlement Agreement,” to the consolidated financial statements of PHI.

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MPSC New Generation Contract Requirement

For information about the MPSC new generation contract requirement, please refer to Note (7), “Regulatory Matters – MPSC New Generation Contract Requirement,” to the consolidated financial statements of PHI.

ACE Standard Offer Capacity Agreements

For information about the ACE Standard Offer Capacity Agreements, please refer to Note (7), “Regulatory Matters – ACE Standard Offer Capacity Agreements,” to the consolidated financial statements of PHI.

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, greenhouse gas emissions, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. PHI’s subsidiaries may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. PHI’s subsidiaries may also be responsible for ongoing environmental remediation costs associated with facilities or operations that have been sold to third parties as further described in Note (16), “Commitments and Contingencies – Environmental Matters – Conectiv Energy Wholesale Power Generation Sites,” to the consolidated financial statements of PHI.

PHI’s subsidiaries’ currently projected capital expenditures for the replacement of existing or installation of new environmental control facilities that are necessary for compliance with environmental laws, rules or agency orders are approximately $13.0 million in 2015, $9.3 million in 2016, $4.3 million in 2017 and $2.4 million in 2018. The projections for these capital expenditures could change depending on the outcome of the matters addressed below or as a result of the imposition of additional environmental requirements or new or different interpretations of existing environmental laws, rules and agency orders. In view of the sale of PHI’s competitive wholesale power generation business in 2010 and the deactivation in 2012 of two generating facilities located in the District of Columbia owned by Pepco Energy Services, PHI is no longer significantly affected by air quality and other environmental regulations applicable to electricity generating facilities.

Air Quality Regulation

The generating facilities owned by Pepco Energy Services were subject to federal, state and local laws and regulations, including the Federal Clean Air Act (CAA), which limit emissions of air pollutants, require permits for operation of facilities and impose recordkeeping and reporting requirements. Following the June 2012 deactivation of Pepco Energy Services’ Buzzard Point and Benning Road oil-fired generating facilities, both of which were considered major sources under the CAA, Pepco Energy Services received authorization in 2013 from the District Department of the Environment (DDOE) to exclude these major sources from the CAA Title V operating permits. DDOE also agreed to transfer the CAA Title V operating permit covering the remaining minor sources (e.g., Pepco-operated emergency generators) to Pepco. Pepco has filed minor source permit applications with DDOE for these minor sources.

Greenhouse Gas Emissions Reporting

In October 2009, the U.S. Environmental Protection Agency (EPA) adopted regulations requiring sources that emit designated greenhouse gases – specifically, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and other fluorinated gases (e.g., nitrogen trifluoride and

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hydrofluorinated ethers) – in excess of specified thresholds to file annual reports with EPA disclosing the amount of such emissions. Under these regulations:

• By April 1 of each year, DPL is required to report with respect to its gas distribution operations CO₂ emissions that would result assuming the complete combustion or oxidation of the annual volume of natural gas it distributed to its customers during the previous calendar year. In addition, DPL is required to report fugitive CO₂ and methane emissions for its gas distribution operations for the previous calendar year. DPL’s liquefied natural gas storage facility does not meet the reporting threshold (25,000 metric tons) for fugitive emissions.

• By April 1 of each year, Pepco, DPL and ACE are required to report sulfur hexafluoride emissions from electrical equipment for the previous calendar year.

Water Quality Regulation

Clean Water Act

Provisions of the federal Water Pollution Control Act, also known as the Clean Water Act, establish the basic legal structure for regulating the discharge of pollutants from point sources (generally confined, discrete conveyances such as pipes) to surface waters of the United States. Among other things, the Clean Water Act requires that any person wishing to discharge pollutants from a point source obtain a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA or by a state agency under a federally authorized state program.

Pepco holds a NPDES permit issued by EPA with a June 19, 2009 effective date, which authorizes discharges from the Benning Road facility, including the now deactivated Pepco Energy Services generating facility located at that site. The 2009 permit imposed compliance monitoring and storm water best management practices to satisfy the District of Columbia’s Total Maximum Daily Load (TMDL) standards for polychlorinated biphenyls, oil and grease, metals and other substances. As part of the implementation of the TMDL requirements, the permit also imposed numerical limits on certain substances in storm water discharges to the Anacostia River. Quarterly monitoring results since the issuance of the permit have shown consistent exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead. As required by the permit, Pepco initiated a study to identify the potential sources of these regulated substances at the site and to determine appropriate best management practices for minimizing the presence of the substances in storm water discharges from the facility. The initial study report was completed in May 2012. Pepco has completed the implementation of the first two phases of the best management practices recommended in the study report (consisting principally of installing metal absorbing filters to capture contaminants from storm water flows, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures have been effective in reducing metal concentrations in stormwater discharges; however, additional measures will be required to be implemented by Pepco to reduce the concentrations to levels required by the permit.

The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road facility has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. Pepco has prepared a plan to implement the third phase of the best management practices recommended in the study report with the objective of achieving full compliance with the permit limits by the end of 2015. The plan was submitted to EPA on December 30, 2014, and Pepco has begun implementing those best practices in accordance with the plan. Pepco anticipates that EPA may request that Pepco enter into an administrative compliance agreement with respect to the implementation of these additional control measures, and may seek administrative penalties for past noncompliance with the permit limits for metals in storm water. Whether such penalties will be imposed and, if so, the amount of any such penalties, is not known or estimable at this time. At present, Pepco expects that compliance with the permit limits can be achieved through a

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combination of enhanced storm drain inlet controls (filters and metal absorbing booms), enhanced site housekeeping, and enhanced inspection and maintenance of storm water controls. If these measures are not adequate to achieve compliance with the permit limits, however, it is possible that a capital project to install a storm water treatment system may be required. The need for any such capital expenditures will not be known until Pepco has implemented the third phase of the best management practices.

EPA Oil Pollution Prevention Regulations

Facilities that, because of their location, store or use oil and could reasonably be expected to discharge oil into water bodies or adjacent shorelines in quantities that may be harmful to the environment are subject to EPA’s oil pollution prevention regulations. These regulations require entities to prepare and implement Spill Prevention, Control, and Countermeasure (SPCC) plans and specify site-specific measures to prevent and respond to an oil discharge. The SPCC regulations generally require the use of containment and/or diversionary structures to prevent the discharge of oil in the event of a leak or release of oil at the facility. As an alternative to the containment/diversionary structure requirement, owners of certain oil-filled operational equipment, such as electric system transformers, may comply with EPA’s regulations by implementing an inspection and monitoring program, developing an oil spill contingency plan, and providing a written commitment of resources to control and remove any discharge of oil. Pepco, DPL and ACE are complying with the SPCC regulations by employing containment/diversionary structures and by means of inspection and monitoring measures, in each case where such measures have been determined to be appropriate. Total costs of complying with these regulations in 2014 for Pepco, DPL and ACE collectively were approximately $7.4 million. PHI projects total expenditures of approximately $29.0 million over the next five years for its subsidiaries to comply with these regulations, as shown in the capital expenditure projection set forth in “Environmental Matters” above, all of which are to install additional containment facilities and to replace certain oil-filled breakers with gas-filled breakers to eliminate the possibility of an oil release from such equipment. Compliance costs for Pepco Energy Services have not been material, and PHI does not expect that they will become material in the foreseeable future.

EPA Coal Combustion Residuals Regulations

In December 2014, EPA issued new regulations regarding coal combustion residuals, commonly known as coal ash, from coal-fired power plants. These regulations govern risks associated with coal ash disposal and establish recordkeeping and reporting requirements. The regulations also support the responsible recycling of coal ash by distinguishing safe and beneficial uses from disposal.

The regulations do not apply to inactive ash landfills that cease receiving coal ash prior to the effective date of the regulations, which will be six months after they are published in theFederal Register. Accordingly, the new regulations will not apply to PHI’s Edge Moor landfill, which was retained in the sale of the Conectiv Energy wholesale power generation business to Calpine Corporation in 2010. PHI also does not expect that these regulations will necessitate any changes to Pepco’s technical closure plan for the right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, because the technical closure plan is designed to comply with the more stringent Maryland landfill closure requirements.

Hazardous Substance Regulation

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) authorizes EPA, and comparable state laws authorize state environmental authorities, to issue orders and bring enforcement actions to compel responsible parties to investigate and take remedial actions at any site that is determined to present an actual or potential threat to human health or the environment because of an actual or threatened release of one or more hazardous substances. Parties that generated or transported hazardous substances to such sites, as well as the owners and operators of such sites, may be deemed liable under CERCLA or comparable state laws. Each of Pepco, DPL and ACE has been named

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by EPA or a state environmental agency as a potentially responsible party in pending proceedings involving certain contaminated sites. For additional information on these matters, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Capital Requirements – Environmental Remediation Obligations,” and Note (16), “Commitments and Contingencies – Environmental Matters,” to the consolidated financial statements of PHI.

Employees

At December 31, 2014, PHI had the following employees:

			In Collective Bargaining Agreements
	Non- union		International Brotherhood of Electrical Workers		International Union of Operating Engineers		Other		Total
Pepco		385		1,116		—		—		1,501
DPL		233		650		—		—		883
ACE		184		361		—		—		545
Pepco Energy Services		140		209		37		31		417
PHI Service Company and Other		1,432		347		—		—		1,779
Total PHI Employees		2,374		2,683		37		31		5,125

PHI’s utility subsidiaries are parties to five collective bargaining agreements with four local unions. Collective bargaining agreements are generally renegotiated every three to five years. All of these collective bargaining agreements were renegotiated in 2014 and were extended through various dates ranging from October 2018 through June 2020.

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Executive Officers of PHI

The names of the executive officers of PHI, their ages and the positions they held as of February 26, 2015, are set forth in the following table. The business experience of each executive officer during at least the past five years is set forth adjacent to his or her name under the heading “Office and Length of Service” in the following table and in the applicable footnote.

Name	Age	Office and Length of Service
Joseph M. Rigby	58	Chairman of the Board 5/09- Present, President3/08- Present, and Chief Executive Officer3/09- Present (1)
David M. Velazquez	55	Executive Vice President 3/09- Present (2)
Kevin C. Fitzgerald	52	Executive Vice President and General Counsel 9/12- Present (3)
Frederick J. Boyle	57	Senior Vice President and Chief Financial Officer 4/12- Present (4)
Kenneth J. Parker	52	Senior Vice President, Government Affairs and Corporate Citizenship 9/12- Present (5)
Thomas H. Graham	54	Vice President 8/13- Present (6)
Ronald K. Clark	59	Vice President and Controller 8/05- Present
Laura L. Monica	58	Vice President 8/11- Present (7)
Hallie M. Reese	51	Vice President, PHI Service Company 5/05- Present
John U. Huffman	55	President6/06- Present, and Chief Executive Officer,Pepco Energy Services, Inc. 3/09 - Present (8)

(1) Mr. Rigby was Chief Operating Officer of PHI from September 2007 until February 28, 2009 and Executive Vice President of PHI from September 2007 until March 2008, Senior Vice President of PHI from August 2002 until September 2007 and Chief Financial Officer of PHI from May 2004 until September 2007. Mr. Rigby was President and Chief Executive Officer of Pepco, DPL and ACE from September 1, 2007 to February 28, 2009. Mr. Rigby has been Chairman of Pepco, DPL and ACE since March 1, 2009. Since October 10, 2014, Mr. Rigby has served as a director of Dominion Midstream GP, LLC, the general partner of Dominion Midstream Partners, LP (NYSE: DM), a publicly-traded limited partnership. On April 29, 2014, PHI entered into that certain Employment Extension Agreement with Mr. Rigby, which extended the term of his employment as PHI’s President and Chief Executive Officer for a period beginning on January 1, 2015 and ending on the first to occur of (1) April 29, 2016, (2) the closing date of the Merger or (3) the date that is six months after the Merger Agreement is terminated.

(2) Mr. Velazquez served as President of Conectiv Energy Holding Company, formerly an affiliate of PHI, from June 2006 to February 28, 2009, Chief Executive Officer of Conectiv Energy Holding Company from January 2007 to February 28, 2009 and Chief Operating Officer of Conectiv Energy Holding Company from June 2006 to December 2006.

(3) Mr. Fitzgerald joined PHI in September 2012 as Executive Vice President and General Counsel. From 1997 to 2012, he was a partner with the law firm of Troutman Sanders, LLP in Washington, D.C. Mr. Fitzgerald was Managing Partner of that firm’s Washington, D.C. office from 1999 until 2010 and Executive Partner for Client Development Strategic Planning from 2010 to September 2012.

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(4) Mr. Boyle joined PHI in April 2012 as Senior Vice President and Chief Financial Officer. Prior to such time, he served as Senior Vice President and Chief Financial Officer of DPL Inc. and its wholly owned utility subsidiary, The Dayton Power and Light Company, from December 2010 until its acquisition in 2011. He served as Senior Vice President, Chief Financial Officer and Treasurer of both companies from May 2009 to December 2010, Senior Vice President, Chief Financial Officer, Treasurer and Controller of both companies from December 2008 to May 2009, Vice President, Finance, Chief Accounting Officer and Controller of both companies from June 2008 to November 2008, Vice President, Chief Accounting Officer and Controller of both companies from July 2007 to June 2008, and Vice President and Chief Accounting Officer of both companies from June 2006 to July 2007.

(5) Mr. Parker became Senior Vice President, Government Affairs and Corporate Citizenship in September 2012. From June 2009 to September 2012, he served as Vice President of Public Policy of PHI. From March 2005 to June 2009, he served as the ACE Region President.

(6) Mr. Graham became Vice President, People Strategy and Human Resources, in August 2013. From March 2005 to August 2013, he served as the Pepco Region President.

(7) Ms. Monica joined PHI in August 2011 as Vice President, Corporate Communications. From October 2006 to October 2010, Ms. Monica was Senior Vice President, Corporate Communications at American Water Works Company, Inc. (NYSE: AWK), and from September 1991 to October 2006, Ms. Monica was President of High Point Communications, a strategic communications firm. Ms. Monica rejoined High Point Communications as President from October 2010 to August 2011.

(8) Mr. Huffman has been employed by Pepco Energy Services since June 2003. He was Chief Operating Officer from April 2006 to February 28, 2009, Senior Vice President from February 2005 to March 2006 and Vice President from June 2003 to February 2005.

Each PHI executive officer is elected annually and serves until his or her respective successor has been elected and qualified or his or her earlier resignation or removal.

Investor Information

Each Reporting Company maintains an Internet web site, at the Internet address listed below:

Reporting Company	Internet Address
PHI	http://www.pepcoholdings.com
Pepco	http://www.pepco.com
DPL	http://www.delmarva.com
ACE	http://www.atlanticcityelectric.com

Each Reporting Company files reports with the SEC under the Exchange Act. Copies of the Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports, of each Reporting Company are routinely made available free of charge on PHI’s Internet Web site (http://www.pepcoholdings.com/investors) as soon as reasonably practicable after such documents are electronically filed with or furnished to the SEC. PHI recognizes its website as a key channel of distribution to reach public investors and as a means of disclosing material non-public information to comply with each Reporting Company’s disclosure obligations under SEC Regulation FD. The information contained on the web sites listed above shall not be deemed incorporated into, or to be part of, this Annual Report on Form 10-K, and any web site references included herein are not intended to be made through active hyperlinks.

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Item 1A. RISK FACTORS

The businesses of each Reporting Company are subject to numerous risks and uncertainties, including the events or conditions identified below. The occurrence of one or more of these events or conditions could have an adverse effect on the business of any one or more of the Reporting Companies, including, depending on the circumstances, its financial condition, results of operations and cash flow. Unless otherwise noted, each risk factor set forth below applies to each Reporting Company.

PHI’s utility subsidiaries are subject to comprehensive regulation which significantly affects their operations. PHI’s utility subsidiaries may be subject to fines, penalties and other sanctions for the inability to meet these requirements.

The regulated utilities that comprise Power Delivery are subject to extensive regulation by various federal, state and local regulatory agencies. Each of Pepco, DPL and ACE is regulated by the state agencies for each service territory in which it operates, with respect to, among other things, the manner in which utility service is provided to customers, as well as rates it can charge customers for the distribution and supply of electricity (and, additionally for DPL, the distribution and supply of natural gas). NERC has also established, and FERC has approved, reliability standards with regard to the bulk power system that impose certain operating, planning and cyber security requirements on Pepco, DPL, ACE and Pepco Energy Services. Further, FERC regulates the electricity transmission facilities of Pepco, DPL and ACE.

Approval of these regulators is required in connection with changes in rates and other aspects of the utilities’ operations. These regulatory authorities, and NERC with respect to electric reliability, are empowered to impose financial penalties, fines and other sanctions including setting rates at a level that may be inadequate to permit recovery of costs against the utilities for non-compliance with certain rules and regulations. In this regard, in December 2011, the MPSC sanctioned Pepco related to its reliability in connection with major storm events that occurred in July and August 2010. These sanctions included imposing a fine on Pepco and requiring Pepco to file a work plan detailing, among other things, its reliability improvement objectives and progress in meeting those objectives, while raising the possibility of additional fines or cost recovery disallowances for failing to meet those objectives.

NERC’s eight regional oversight entities, including RF, of which Pepco, DPL, ACE and Pepco Energy Services are members, and the Northeast Power Coordinating Council (NPCC), of which Pepco Energy Services is a member, are charged with the day-to-day implementation and enforcement of NERC’s standards. RF and NPCC perform compliance audits on entities registered with NERC based on reliability standards and criteria established by NERC. NERC, RF and NPCC also conduct compliance investigations in response to a system disturbance, complaint, or possible violation of a reliability standard identified by other means. Pepco, DPL, ACE and Pepco Energy Services are subject to routine audits and monitoring with respect to compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets (including cyber security assets) subject to NERC cyber security standards that are designated as “critical assets.” From time to time, Pepco, DPL and ACE have entered into settlement agreements with RF resolving alleged violations and resulting in fines. There can be no assurance that additional settlements resolving issues related to RF or NPCC requirements will not occur in the future. The imposition of additional sanctions and civil fines by these enforcement entities could have a material adverse effect on a Reporting Company’s results of operations, cash flow and financial condition.

PHI’s utility subsidiaries, as well as Pepco Energy Services, are also required to have numerous permits, approvals and certificates from governmental agencies that regulate their businesses. Although PHI believes that each of its subsidiaries has, and each of Pepco, DPL and ACE believes it has, obtained or sought renewal of the material permits, approvals and certificates necessary for its existing operations and that its business is conducted in accordance with applicable laws, PHI is unable to predict the impact that future regulatory activities may have on its business. Changes in or reinterpretations of existing laws or regulations, or the imposition of new laws or regulations, may require any one or more of PHI’s subsidiaries to incur additional expenses or significant capital expenditures or to change the way it conducts its operations.

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PHI’s profitability is largely dependent on its ability to recover costs of providing utility services to its customers and to earn an adequate return on its capital investments. The failure of PHI’s utility subsidiaries to obtain timely recognition of costs in rates may have a negative effect on PHI’s results of operations and financial condition.

The regulatory authorities that regulate PHI’s utility subsidiaries establish utility rates and tariffs intended to provide each utility the opportunity to obtain revenues sufficient to recover its prudently incurred costs, together with a reasonable return on investor supplied capital. These regulatory authorities also determine how Pepco, DPL and ACE recover from their customers purchased power and natural gas and other operating costs, including transmission and other costs. The utilities cannot change their rates without approval by the applicable regulatory authority. There can be no assurance that the regulatory authorities will consider all costs to have been prudently incurred, nor can there be any assurance that the regulatory process by which rates are determined will always result in rates that achieve full and timely recovery of costs or a just and reasonable rate of return on investments. In addition, if the costs incurred by any of the utilities in operating its business exceed the amounts on which its approved rates are based, the financial results of that utility, and correspondingly PHI, may be adversely affected.

For example, PHI’s utility subsidiaries are exposed to “regulatory lag,” which refers to a shortfall in revenues in a utility’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. All of PHI’s utilities are currently experiencing significant regulatory lag because their investments in rate base and operating expenses are increasing more rapidly than their revenue growth. PHI anticipates that this trend will continue for the foreseeable future.

Prior to PHI’s initial execution of the Merger Agreement in April 2014, in an effort to minimize the effects of regulatory lag, PHI’s utility subsidiaries had been filing electric distribution base rate cases every nine to twelve months in each of their jurisdictions, pursuing alternative ratemaking mechanisms, evaluating potential reductions in planned capital expenditures, and discussing with the regulatory community and other stakeholders the changing regulatory model economics that are causing regulatory lag. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings. Any inability of PHI’s utility subsidiaries to mitigate regulatory lag could have a material adverse effect on PHI’s and each utility subsidiary’s business, results of operations, cash flow and financial condition.

The operating results of Power Delivery fluctuate on a seasonal basis and can be adversely affected by changes in weather.

The Power Delivery business historically has been seasonal and, as a result, weather has had a material impact on its operating performance. Demand for electricity is generally higher in the summer months associated with cooling and demand for electricity and natural gas is generally higher in the winter months associated with heating as compared to other times of the year. Accordingly, each of PHI, Pepco, DPL and ACE historically has generated less revenue and income when temperatures are warmer in the winter and cooler in the summer. In addition, severe weather conditions can produce storms that cause extensive damage to the transmission and distribution systems, as well as related facilities, that can require the utilities to incur additional operation and maintenance expense, as well as capital expenditures. These additional costs can be significant and the rates charged to customers may not always be timely or adequately adjusted to reflect these higher costs.

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In the District of Columbia and Maryland, Pepco and DPL are subject to a bill stabilization adjustment mechanism applicable to retail customers, which decouples distribution revenue for a given reporting period from the amount of power delivered during the period. The bill stabilization mechanism has the effect in those jurisdictions of reducing the impact of changes in the use of electricity by retail customers due to weather conditions or for other reasons on reported distribution revenue and income. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC. In those jurisdictions that have not adopted a bill stabilization adjustment or similar mechanism, operating results continue to be affected by weather conditions.

Facilities and related systems may not operate as planned or may require significant capital or operation and maintenance expenditures, which could decrease revenues or increase expenses.

Operation of the Pepco, DPL and ACE transmission and distribution facilities and related systems involves many risks, including: the breakdown or failure of equipment; accidents; labor disputes; theft of copper wire or pipe; failure of computer systems, software or hardware; and performance below expected levels. Older facilities, systems and equipment, even if maintained in accordance with sound engineering practices, may require significant capital expenditures for additions or upgrades to provide reliable operations or to comply with changing environmental requirements. Thefts of copper wire or pipe, which seek to capitalize on the current high market price of copper, increase the likelihood of poor system voltage control, electricity and streetlight outages, damage to equipment and property, and injury or death, as well as increasing the likelihood of damage to fuel lines, which can create an unsafe and potentially explosive condition. Natural disasters and weather, including tornadoes, hurricanes and snow and ice storms, also can disrupt transmission and distribution systems. Disruption of the operation of transmission or distribution facilities and related systems can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance.

Upgrades and improvements to computer systems and networks may require substantial amounts of management’s time and financial resources to complete, and may also result in system or network defects or operational errors due to employees’ inexperience of using a new or upgraded system. In January 2015, PHI’s utility subsidiaries implemented an integrated customer billing and information management system to replace separate existing legacy customer billing and information systems. There can be no assurance that this new system will not cause disruptions to the utility subsidiaries’ operations, which disruptions, if not anticipated and appropriately mitigated, could harm their business (individually or collectively) and have a material adverse effect on their results of operations, financial condition and cash flows.

In connection with the replacement of certain customers’ existing electric and natural gas meters with smart meters as part of the AMI system, Pepco and DPL were required to construct a wireless network across certain of their service territories and to implement and integrate new and existing information technology systems to collect and manage data made available by the smart meters and the AMI system. The implementation of the AMI system involves a combination of technologies provided by multiple vendors. If the AMI system results in lower than projected performance, PHI’s utility subsidiaries could experience higher than anticipated maintenance expenditures.

Energy companies are subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other sanctions.

Utility companies, including PHI’s utility subsidiaries, have a large consumer customer base and as a result have been the subject of public criticism focused on the reliability of their distribution services and the speed with which they are able to respond to outages caused by storm damage or other unanticipated events. Adverse publicity of this nature may render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view energy companies such as PHI and its subsidiaries in a favorable light, and may cause PHI and its subsidiaries to

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be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent regulatory requirements. Unfavorable regulatory outcomes can include the enactment of more stringent laws and regulations governing PHI’s operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material negative impact on PHI’s and each utility subsidiary’s business, results of operations, cash flow and financial condition.

Unfavorable regulatory developments and compliance with new or more rigorous regulatory requirements may subject PHI’s utility subsidiaries to higher operating costs.

PHI’s utility subsidiaries are subject to and will continue to be subject to changing regulatory requirements, including those related to reliability and customer service, in the various jurisdictions in which they operate. For example, in 2012, the MPSC adopted rules establishing reliability and customer service requirements. In April 2014, DPL filed a corrective action plan with the MPSC to address noncompliance in 2013 with certain of these reliability requirements. DPL expects to file an annual report in April 2015 indicating that it has not complied with certain of these requirements for 2014. In addition, in July 2011, the DCPSC adopted regulations that establish specific maximum outage frequency and outage duration levels beginning in 2013 and continuing through 2020 and thereafter and are intended to require Pepco to achieve a reliability level in the first quartile of all utilities in the nation by 2020. The reliability standards permit Pepco to petition the DCPSC to reevaluate these standards for the period from 2016 to 2020 to address feasibility and cost issues.

Each of Pepco and DPL may incur significant operating and maintenance and capital expenses to comply with these requirements. Furthermore, each of Pepco and DPL would be subject to civil penalties or other sanctions if it does not meet the required performance or reliability standards. Other jurisdictions in which PHI’s utility subsidiaries have operations have already adopted or may in the future adopt reliability and customer service quality standards, the violation of which could also result in the imposition of penalties, fines and other sanctions. Compliance, and any failure to comply, with current, proposed or future regulatory requirements may have a material adverse effect on PHI and each utility subsidiary’s business, results of operations, cash flow and financial condition.

The resolution of tax matters involving PHI’s former cross-border energy lease investments may have a material negative impact on PHI’s results of operations and financial condition. (PHI only).

Prior to July 2013, a wholly owned subsidiary of PHI had maintained a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States, which investments were terminated during the third quarter of 2013 prior to the expiration date of the leases. The aggregate financial impact to PHI of the completion of these early terminations resulted in a pre-tax loss, including transaction costs, of approximately $3 million ($2 million after-tax) for the year ended December 31, 2013.

These cross-border energy lease investments, each of which was with a tax-indifferent party, have been under examination by the IRS as part of normal PHI federal income tax audits. In connection with the audits of PHI’s federal income tax returns from 2001 to 2008, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to its cross-border energy lease investments. In addition, the IRS has sought to recharacterize the leases as loan transactions. In January 2012, PHI commenced litigation in the U.S. Court of Federal Claims regarding the disallowance of certain tax benefits claimed by PHI on its federal tax returns for 2001 and 2002.

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In January 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in an unrelated case that disallowed tax benefits associated with a lease-in, lease-out transaction. After analyzing this ruling, in the first quarter of 2013, PHI determined that its tax position with respect to the tax benefits associated with its cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes. Accordingly, PHI recorded non-cash charges of $383 million (after-tax) in the first half of 2013, consisting of a non-cash charge to reduce the carrying value of the cross-border energy lease investments and a non-cash charge to reflect the anticipated additional interest expense related to changes in estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed.

After consideration of certain tax benefits arising from matters unrelated to these lease investments, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal and state taxes and approximately $50 million of interest on the additional federal and state taxes. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made an advanced payment to the IRS of $242 million in the first quarter of 2013. While PHI presently believes that it is more likely than not that no penalty will be incurred, the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due. In order to mitigate the cost of continued litigation related to the cross-border energy lease investments, PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues for open tax years 2001 through 2011, including the cross-border energy lease issue. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2015. If a settlement of all tax issues or a standalone settlement on the cross-border energy leases is not reached, PHI may move forward with its litigation with the IRS. Further discovery in the case is stayed until March 19, 2015, pursuant to an order issued by the court on December 2, 2014.

Given the uncertainties associated with PHI’s litigation with the IRS, as well as with other efforts by PHI to address and resolve tax matters associated with its former cross-border energy leases in tax years not subject to this litigation, the aggregate financial impact, and timing of the resolution, of all of these matters cannot be determined presently; however, PHI presently believes that any such impact on PHI’s consolidated results of operations and financial condition could be material.

Power Delivery’s transmission facilities are interconnected with the facilities of other transmission facility owners. Failures of neighboring transmission systems could have a negative impact on Power Delivery’s operations.

The electricity transmission facilities of Pepco, DPL and ACE are interconnected with the transmission facilities of neighboring utilities and are part of the interstate power transmission grid. Pepco, DPL and ACE are members of the PJM RTO, a regional transmission organization that operates the portion of the interstate transmission grid that includes the PHI transmission facilities. Although PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities, there can be no assurance that service interruptions originating at other utilities will not cause interruptions in the Pepco, DPL or ACE service territories. Thus, due to the interconnected nature of the interstate power transmission grid, an outage in a neighboring utility could trigger a system outage in either Pepco, DPL or ACE. If Pepco, DPL or ACE were to suffer such a service interruption, it could have a negative impact on its and PHI’s business, results of operations, cash flow and financial condition.

Changes in technology, distributed generation and conservation measures may adversely affect Power Delivery.

Increased conservation and end-user generation made possible through current or future advances in technology, such as through fuel and solar (photovoltaic) cells, wind power and microturbines, could reduce demand for the transmission and distribution facilities of Power Delivery and adversely affect the results of operations of PHI and one or more of its utility subsidiaries. Alternative technologies that

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produce electricity, the development of which has expanded due to climate change and other environmental concerns, could ultimately provide alternative sources of electricity and permit current customers to adopt distributed generation systems which would allow them to generate electricity for their own use. As these and other technologies are created, developed and improved, the quantity and frequency of electricity usage by customers could decline, which could have a negative impact on the business, results of operations, cash flow and financial condition of PHI or its utility subsidiaries.

The cost of compliance with environmental laws is significant and implementation of new and existing environmental laws may increase operating costs.

The operations of PHI’s subsidiaries are subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, spill prevention, waste management, natural resource protection, site remediation, greenhouse gas emissions and health and safety. These laws and regulations may require significant capital and other expenditures to, among other things, meet emissions and effluent standards, conduct site remediation, complete environmental studies and perform environmental monitoring. If a company fails to comply with applicable environmental laws and regulations, even if caused by factors beyond its control, such failure could result in the assessment of civil or criminal penalties and liabilities and the need to expend significant sums to achieve compliance.

In addition, PHI’s subsidiaries are required to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if there is a failure to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.

Failure to retain and attract key skilled and properly motivated professional and technical employees could have an adverse effect on operations.

PHI and its subsidiaries operate in a highly regulated industry that requires the continued operation of sophisticated systems and technology. One of the challenges they face in implementing their business strategy is to attract, motivate and retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to retirements. Over the course of the next three years, PHI estimates that approximately one-third of this skilled workforce will reach retirement age. Competition for skilled employees in some areas is high and the inability to attract and retain these employees, especially as existing skilled workers retire in the near future, could adversely affect the business, operations and financial condition of PHI or the affected company.

PHI’s subsidiaries are subject to collective bargaining agreements that could impact their business and operations.

As of December 31, 2014, 54% of employees of PHI and its subsidiaries, collectively, were represented by various labor unions. PHI’s utility subsidiaries are parties to five collective bargaining agreements with four local unions that represent these employees. Collective bargaining agreements are generally renegotiated every three to five years, and the risk exists that there could be a work stoppage after expiration of an agreement until a new collective bargaining agreement has been reached. All of these collective bargaining agreements were renegotiated in 2014. Labor negotiations typically involve bargaining over wages, benefits and working conditions, including management rights. Although PHI believes that protracted work stoppages are unlikely, such an event could result in a disruption of the operations of the affected utility, which could, in turn, have a material adverse effect upon the business, results of operations, cash flow and financial condition of the affected utility and PHI.

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Pepco Energy Services’ thermal business in Atlantic City, New Jersey is exposed to customer concentration, and the loss of one or more of its significant customers would have a material adverse effect on Pepco Energy Services’ results of operations and cash flow. (PHI only)

Revenues associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City are derived from long-term contracts with a few major customers in the Atlantic City hotel and casino industry, some of which are experiencing significant financial difficulties and have closed or have contemplated closing operations. During 2014, PHI performed impairment tests on the most significant asset groups comprising these facilities and operations and recorded impairment losses of $81 million ($48 million after-tax) with respect to the two most significant asset groups. Two significant thermal business customers declared Chapter 11 bankruptcy in September 2014, and in February 2015, rejected Pepco Energy Services’ long-term thermal contracts as part of these customers’ bankruptcy proceedings. These contract rejections are expected to reduce Pepco Energy Services’ future earnings and cash flow associated with its thermal operations in Atlantic City and further reductions in future earnings and cash flows may occur if Pepco Energy Services’ thermal customers continue to experience financial difficulties.

Under its energy savings performance contracts, Pepco Energy Services is responsible for maintaining, repairing and replacing energy equipment, which obligations may require Pepco Energy Services to incur significant costs many years after an installation of a project is completed. (PHI only)

Pepco Energy Services owns energy equipment and is also responsible for operating and maintaining additional energy equipment that it does not own. In addition, it is generally Pepco Energy Services’ responsibility to repair or replace this energy equipment in the event of a failure. These equipment maintenance, repair and replacement obligations could be material and could adversely affect PHI’s results of operations, cash flow and financial condition.

Pepco Energy Services’ obligations in connection with its combined heat and power construction projects, energy savings construction projects and energy savings performance contracts may have a material adverse effect on PHI. (PHI only)

Pepco Energy Services has undertaken projects which include design, construction, startup and testing activities related to combined heat and power and energy savings construction projects, pursuant to guaranteed maximum price or fixed-price contracts. Pepco Energy Services will generally secure commitments from subcontractors and vendors to perform within contract pricing commitments, equipment-performance standards, jobsite safety requirements, and other key parameters. Under a number of these projects, the customer of Pepco Energy Services has required Pepco Energy Services to obtain surety bonds securing the performance of Pepco Energy Services, or its subcontractors or vendors. PHI has been required to guarantee the performance of Pepco Energy Services under the surety bonds and certain of these construction contracts. PHI also guarantees the obligations of Pepco Energy Services under certain of its energy savings performance contracts. At December 31, 2014, PHI’s guarantees of Pepco Energy Services’ obligations under its energy savings performance, combined heat and power, and construction contracts totaled $336 million, and PHI’s guarantees of Pepco Energy Services’ obligations under surety bonds for construction projects totaled $185 million.

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As a result, PHI may bear responsibility in the event of unexcused failures by Pepco Energy Services or its subcontractors or vendors to perform in accordance with the terms of these contracts, or if the customer does not realize the energy savings provided for in a performance contract. When such events occur, Pepco Energy Services and PHI may experience reputational harm and claims for money damages and other relief that may be sought in connection with such contracts, guarantees and surety bonds, which could, depending upon the nature of the claim and the amount of damages or other relief sought, have a material adverse effect upon Pepco Energy Services’ and PHI’s business, results of operations, cash flow and financial condition.

If PHI is not successful in mitigating the risks inherent in its business, its operations could be adversely affected.

PHI and its subsidiaries are faced with a number of different types of risk. PHI confronts legislative, regulatory policy, compliance and other risks, including:

• PHI’s inability to timely recover capital and operating costs, which may result in a shortfall in revenues;

• resource planning and other long-term planning risks, including resource acquisition risks, which may hinder PHI’s ability to maintain adequate resources;

• financial risks, including credit, interest rate and capital market risks, which could increase the cost of capital or make raising capital more difficult; and

• macroeconomic risks, and risks related to economic conditions and changes in demand for electricity and natural gas in the service territories of PHI’s utility subsidiaries (including changes due to or in connection with the loss of one or more commercial customers of a utility subsidiary), as well as with respect to Pepco Energy Services’ business, which could negatively impact the operations of the affected business.

PHI management seeks to mitigate the risks inherent in the implementation of PHI’s business strategy through its established risk mitigation process, which includes adherence to PHI’s business policies and other compliance policies, operation of formal risk management structures and groups, and overall business management. PHI management is responsible for identifying, assessing and managing risks, and developing risk-management strategies, while the Board of Directors and its various committees oversee the assessment, management and mitigation of risk. However, there can be no assurance these risk mitigation efforts will adequately address all such risks or that such efforts will be successful, and a failure to successfully identify, assess, manage or mitigate such risks may have a material adverse effect on the business, results of operations, cash flow or financial condition of one or more of the Reporting Companies.

PHI and its subsidiaries are exposed to contractual and credit risks associated with certain of their operations.

PHI and its subsidiaries are subject to a number of contractual and credit risks associated with certain of their operations. To mitigate contractual or credit risk, PHI or a subsidiary may give to or receive from the counterparty collateral or other types of performance assurance, which may be in the form of cash, letters of credit or parent guarantees, to protect against performance and credit risk. Even where collateral is provided, capital market disruptions, the lowered rating or insolvency of the issuer or guarantor, changes in the power supply other market prices and other events may prevent a party from being able to meet its obligations or may degrade the value of collateral, letters of credit and guarantees, and the collateral, guarantee or other performance assurance provided may prove insufficient to protect against all losses that a party may ultimately suffer. In the event of a bankruptcy of a counterparty to any contract to which PHI or any of its subsidiaries is a party, bankruptcy law, in some circumstances, could require the surrender of collateral or other guarantees held or payments received.

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Business operations could be adversely affected by terrorism and cyber attacks.

The threat of, or actual acts of, terrorism or cyber attacks may affect the operations of PHI and its subsidiaries in unpredictable ways and may cause changes in the insurance markets, force an increase in security measures and cause electrical disruptions or disruptions of fuel supplies and markets, including natural gas. Utility industry operations require the continued deployment and utilization of sophisticated information technology systems and network infrastructure. While PHI has implemented protective measures designed to mitigate its vulnerability to physical and cyber threats and attacks, such protective measures, and technology systems generally, are vulnerable to disability or failure due to cyber attack, acts of war or terrorism, and other causes. As a result, there can be no assurance that such protective measures will be completely effective in protecting PHI’s infrastructure or assets from a physical or cyber attack or the effects thereof. If any of Pepco’s, DPL’s or ACE’s infrastructure facilities, including their transmission or distribution facilities, were to be a direct target, or an indirect casualty, of an act of terrorism or a cyber attack, the operations of PHI, Pepco, DPL or ACE could be adversely affected. Furthermore, any threats or actions that negatively impact the physical security of the facilities of PHI or its subsidiaries, or the integrity or security of their computer networks and systems (and any programs or data stored thereon or therein), could adversely affect the ability of PHI or its subsidiaries to manage these facilities, networks, systems, programs and data efficiently or effectively, which in turn could have a material adverse effect on PHI’s or its subsidiaries’ results of operations and financial condition. In addition, any theft, loss or fraudulent use of customer, stockholder, employee or proprietary data as a result of a cyber attack or otherwise could subject PHI or its subsidiaries to significant litigation, liability and costs, as well as adversely impact PHI’s or its utility subsidiaries’ reputation with customers, stockholders and regulators, among others. Corresponding instability in the financial markets as a result of threats or acts of terrorism or threatened or actual cyber attacks also could adversely affect the ability of PHI or its subsidiaries to raise needed capital.

New accounting standards or changes to existing accounting standards could materially impact how a Reporting Company reports its results of operations, cash flow and financial condition.

Each Reporting Company’s financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The SEC, the Public Company Accounting Oversight Board, the Financial Accounting Standards Board (FASB) or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require the Reporting Companies to change their accounting policies. These changes are beyond the control of the Reporting Companies, can be difficult to predict and could materially impact how they report their results of operations, cash flow and financial condition. Each Reporting Company could be required to apply a new or revised standard retroactively, which could adversely affect its results of operations, cash flow and financial condition.

Undetected errors in internal controls and information reporting could result in the disallowance of cost recovery and noncompliant disclosure.

Each Reporting Company’s internal controls, accounting policies and practices and internal information systems are designed to enable the Reporting Company to capture and process transactions and information in a timely and accurate manner in compliance with GAAP, taxation requirements, federal securities laws and regulations and other laws and regulations (including pursuant to federal and state administrative grant programs) applicable to it. Such compliance permits each Reporting Company to, among other things, disclose and report financial and other information in connection with the recovery of its costs and with the reporting requirements for each Reporting Company under federal securities, tax and other laws and regulations.

Each Reporting Company has implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and relevant SEC rules, as well as other applicable regulations. Such internal controls and policies have been

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and continue to be closely monitored by each Reporting Company’s management and PHI’s Board of Directors to ensure continued compliance with these laws, rules and regulations. Management is also responsible for establishing and maintaining internal control over financial reporting and is required to assess annually the effectiveness of these controls. While PHI believes these controls, policies, practices and systems are adequate to verify data integrity, unanticipated and unauthorized actions of employees or temporary lapses in internal controls due to shortfalls in oversight or resource constraints could lead to undetected errors that could result in the disallowance of cost recovery and noncompliant disclosure and reporting. The consequences of these events could have a negative impact on the results of operations and financial condition of the affected Reporting Company. The inability of management to certify as to the effectiveness of these controls due to the identification of one or more material weaknesses in these controls could also increase financing costs or could also adversely affect the ability of a Reporting Company to access the capital markets.

Insurance coverage may not be sufficient to cover all casualty, property or other losses that PHI and its subsidiaries might incur.

PHI and its subsidiaries, including Pepco, DPL and ACE, as well as Pepco Energy Services, currently have insurance coverage for their facilities and operations in amounts and with deductibles that they consider appropriate. However, there is no assurance that such insurance coverage will be available in the future on commercially reasonable terms or at all. In addition, some risks and losses, such as weather related casualties, may not be insurable, and, where a risk has been insured, a risk or loss may be deemed to be excluded from coverage or coverage may otherwise be denied in whole or in part. PHI has also obtained insurance to provide coverage for a portion of the losses and damages that may result from a security breach of its or its utility subsidiaries’ information technology systems. In the case of loss or damage to property, plant, equipment, data or other assets, there is no assurance that the insurance proceeds received, if any, will be sufficient to cover the entire loss, including costs of replacement or repair.

PHI and its subsidiaries are dependent on obtaining access to the capital markets and bank financing to satisfy their capital and liquidity requirements. The inability to obtain required financing when needed would have an adverse effect on their respective businesses.

PHI and its subsidiaries, including Pepco, DPL and ACE, have significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. Each of the Reporting Companies relies primarily on cash flow from operations, access to the capital markets and medium- and long-term bank financing, to meet these long-term financing needs. The operating activities of PHI and its subsidiaries also require continued access to short-term sources of liquidity, including issuances by a Reporting Company of commercial paper and access to money markets and short-term bank financing, to provide for short-term liquidity needs that are not met by cash flows from their operations. Adverse business developments or market disruptions could increase the cost of financing or prevent PHI or any of its subsidiaries from accessing these sources of short-term and long-term capital. Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:

• a recession or an economic slowdown;

• the bankruptcy of one or more energy companies or financial institutions;

• a significant change in energy prices;

• a terrorist or cyber attack or threatened attacks;

• the outbreak of a pandemic or other similar event; or

• a significant electricity or natural gas transmission disruption.

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Any reductions in or other actions with respect to the credit ratings of PHI or any of its subsidiaries could increase its financing costs and the cost of maintaining certain contractual relationships.

Nationally recognized rating agencies currently rate each Reporting Company and debt securities issued by Pepco, DPL and ACE. Ratings are not recommendations to buy or sell securities. PHI or its subsidiaries may, in the future, incur new indebtedness with interest rates that may be affected by changes in or other actions associated with these credit ratings. Each of the rating agencies reviews its ratings periodically, and previous ratings may not be maintained in the future. Rating agencies may also place a Reporting Company under review for potential downgrade in certain circumstances or if any of them seek to take certain actions that it believes would otherwise be in its best interests. A downgrade of these debt ratings or other negative action, such as a review for a potential downgrade, could affect the market price of existing indebtedness and the ability to raise additional debt without incurring increases in the cost of capital. In addition, a downgrade of these ratings, or other negative action, could make it more difficult to raise capital to refinance any maturing debt obligations, to support business growth and to maintain or improve the current financial strength of PHI’s business and operations.

The agreements that govern PHI’s primary credit facility contain a consolidated indebtedness covenant that may limit discretion of each borrower to incur indebtedness or reduce its equity.

Under the terms of PHI’s primary credit facility, of which each Reporting Company is a borrower, the consolidated indebtedness of a borrower cannot exceed 65% of its consolidated capitalization. If a borrower’s equity were to decline or its debt were to increase to a level that caused its debt to exceed this limit, lenders under the credit facility would be entitled to refuse any further extension of credit and to declare all of the outstanding debt under the credit facility immediately due and payable. To avoid such a default, a waiver or renegotiation of this covenant would be required, which would likely increase funding costs and could result in additional covenants that would restrict each Reporting Company’s operational and financing flexibility.

Each borrower’s ability to comply with this covenant is subject to various risks and uncertainties, including events beyond the borrower’s control. For example, events that could cause a reduction in PHI’s equity include, without limitation, potential IRS taxes, interest and penalties associated with PHI’s former cross-border energy lease investments or a significant write-down of PHI’s goodwill. Even if each borrower is able to comply with this covenant, the limitations on its operational and financial flexibility could harm its and PHI’s business by, among other things, limiting the borrower’s ability to incur indebtedness or reduce equity in connection with financings or other corporate opportunities that it may believe would be in its best interests or the interests of PHI’s stockholders to complete.

PHI’s cash flow, ability to pay dividends and ability to satisfy debt obligations depend on the performance of its regulated and competitive operating subsidiaries, access to the capital markets and other sources of liquidity. PHI’s unsecured obligations are effectively subordinated to the liabilities of its subsidiaries. (PHI only)

PHI is a holding company that conducts its operations entirely through its regulated and competitive subsidiaries, and all of PHI’s consolidated operating assets are held by its subsidiaries. Accordingly, PHI’s cash flow, its ability to satisfy its obligations to creditors and its ability to pay dividends on its common stock are dependent upon the earnings of its subsidiaries, each Reporting Company’s access to the capital markets and all sources of cash flow and liquidity that may be available to PHI. PHI’s subsidiaries are separate legal entities and have no obligation to pay any amounts due on any debt or equity securities issued by PHI or to make any funds available for such payment. The ability of PHI’s subsidiaries to pay dividends and make other payments to PHI may be restricted by, among other things, applicable corporate, tax and other laws and regulations and agreements made by PHI and its subsidiaries, including under the terms of indebtedness, and PHI’s financial objective of maintaining a common equity ratio at its utility subsidiaries of between 49% and 50%. Because the claims of the creditors of PHI’s

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subsidiaries are superior to PHI’s entitlement to dividends, the unsecured debt and obligations of PHI are effectively subordinated to all existing and future liabilities of its subsidiaries, including trade creditors. In addition, claims of creditors, including trade creditors, of PHI’s subsidiaries will generally have priority with respect to the assets and earnings of such subsidiaries over the claims of PHI’s creditors.

PHI has a significant goodwill balance related to its Power Delivery business. A determination that goodwill is impaired could result in a significant non-cash charge to earnings.

PHI had a goodwill balance at December 31, 2014, of approximately $1.4 billion, primarily attributable to Pepco’s acquisition of Conectiv in 2002. An impairment charge must be recorded under GAAP to the extent that the implied fair value of goodwill is less than the carrying value of goodwill, as shown on the consolidated balance sheet. PHI is required to test goodwill for impairment at least annually and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors that may result in an interim impairment test include, but are not limited to: an adverse change in business conditions; a protracted decline in stock price causing market capitalization to fall significantly below book value; an adverse regulatory action; impairment of long-lived assets in the reporting unit; or a change in identified reporting units. If PHI were to determine that its goodwill is impaired, PHI would be required to reduce its goodwill balance by the amount of the impairment and record a corresponding non-cash charge to earnings. Depending on the amount of the impairment, an impairment determination could have a material adverse effect on PHI’s financial condition, results of operations and cash flow.

The funding of future defined benefit pension plan and post-retirement benefit plan obligations is based on assumptions regarding the valuation of future benefit obligations and the projected performance of plan assets. If market performance decreases plan assets or changes in assumptions regarding the valuation of benefit obligations increase plan liabilities, any of the Reporting Companies may be required to make significant cash contributions to fund these plans.

PHI holds assets in trust to meet its obligations under PHI’s defined benefit pension plan and its post-retirement benefit plan. The amounts that PHI is required to contribute (including the amounts for which Pepco, DPL and ACE are responsible) to fund the trusts are determined based on assumptions made as to the valuation of future benefit obligations, and the projected investment performance of the plan assets. Accordingly, the performance of the capital markets will affect the value of plan assets. A decline in the market value of plan assets as well as a decline in the rate of return on plan assets may increase the plan funding requirements to meet the future benefit obligations. In addition, changes in interest rates affect the valuation of the liabilities of the plans. As interest rates decrease, the present value of the liabilities increase, potentially requiring additional funding. Demographic changes, such as a change in the expected timing of retirements or changes in life expectancy assumptions, also may increase the funding requirements of the plans. A need for significant additional funding of the plans could have a material adverse effect on the cash flows of any of the Reporting Companies. Future increases in pension plan and other post-retirement benefit plan costs, to the extent they are not recoverable in the base rates of PHI’s utility subsidiaries, could have a material adverse effect on the results of operations, cash flow and financial condition of any of the Reporting Companies.

Provisions of the Delaware General Corporation Law and in PHI’s constituent documents may discourage an acquisition of PHI. (PHI only)

PHI is governed by the provisions of Section 203 of the Delaware General Corporation Law, which prohibit a public Delaware corporation from engaging in a business combination with an interested stockholder (as defined in Section 203) for a period commencing three years from the date in which the person became an interested stockholder, unless:

• the board of directors approved the transaction which resulted in the stockholder becoming an interested stockholder;

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• upon consummation of the transaction which resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation (excluding shares owned by officers, directors, or certain employee stock purchase plans); or

• at or subsequent to the time the transaction is approved by the board of directors, there is an affirmative vote of at least 66 2/3% of the outstanding voting stock not owned by the interested stockholder approving the transaction.

Section 203 could prohibit or delay mergers or other takeover attempts against PHI, and accordingly, may discourage or prevent attempts to acquire or control PHI through a tender offer, proxy contest or otherwise. Section 203 does not apply to the Merger.

In addition, and notwithstanding the proposed Merger with Exelon, PHI’s restated certificate of incorporation and amended and restated bylaws contain provisions that may discourage, delay or prevent a third party from acquiring PHI, even if doing so would be beneficial to its stockholders. For example, under PHI’s restated certificate of incorporation, only its board of directors may call special meetings of stockholders. Further, stockholder actions may only be taken at a duly called annual or special meeting of stockholders and not by written consent. Moreover, directors of PHI may be removed by stockholders only for cause and only by the effective vote of at least a majority of the outstanding shares of capital stock of PHI entitled to vote generally in the election of directors (voting together as a single class) at a meeting of stockholders called for that purpose. In addition, under PHI’s amended and restated bylaws, stockholders must comply with advance notice requirements for nominating candidates for election to PHI’s board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings, and this provision may be amended or repealed by stockholders only upon the affirmative vote of the holders of two-thirds of the outstanding shares of PHI capital stock entitled to vote generally in the election of directors, voting together as a single class.

Issuances of additional series of PHI preferred stock could adversely affect holders of PHI’s common stock. (PHI only)

PHI’s board of directors is authorized to issue shares of PHI preferred stock in series without any action on the part of PHI stockholders. PHI’s board of directors also has the power, without stockholder approval, to set the terms of any such series of preferred stock, including with respect to dividend rights, redemption rights and sinking fund provisions, conversion rights, voting rights, and other preferential rights, limitations and restrictions. As of January 26, 2015, there were 14,400 shares of PHI Preferred Stock issued and outstanding. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation,” for information regarding the outstanding Preferred Stock.

If PHI issues preferred stock in the future that has a preference over PHI’s common stock with respect to the payment of dividends or upon its liquidation, dissolution or winding up, or if preferred stock is issued with voting rights that dilute the voting power of the common stock, the rights of holders of PHI’s common stock or the market price of such common stock could be adversely affected. Furthermore, issuances of preferred stock can be used to discourage, delay or prevent a third party from acquiring PHI where the acquisition might be perceived as being beneficial to stockholders.

Because Pepco, DPL and ACE are direct or indirect wholly owned subsidiaries of PHI and have directors and executive officers who are also officers of PHI, PHI can effectively exercise control over their dividend policies and significant business and financial transactions. (Pepco, DPL and ACE only)

All of the members of each of Pepco’s, DPL’s and ACE’s board of directors, as well as many of their respective executive officers, are officers of PHI, and Pepco, DPL and ACE are direct or indirect wholly owned subsidiaries of PHI. Among other decisions, each of Pepco’s, DPL’s and ACE’s board of directors is responsible for decisions regarding payment of dividends, financing and capital raising activities and

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acquisition and disposition of assets. Within the limitations of applicable law, and subject to the financial covenants under each company’s respective outstanding debt instruments, each of Pepco’s, DPL’s and ACE’s board of directors will base its decisions concerning the amount and timing of dividends, and other business decisions, on its capital structure, which is based in part on earnings and cash flow, and also may take into account the business plans and financial requirements of PHI and its other subsidiaries.

PHI and Exelon may be unable to obtain the required governmental, regulatory and other approvals required to complete the Merger, or such approvals may require the combined company to comply with material restrictions or conditions.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including, as of February 26, 2015, the receipt of regulatory approvals required to consummate the Merger from the DCPSC, the MPSC and the DPSC, and other customary closing conditions. The regulatory and other approvals required to consummate the Merger may not be obtained at all, may not be obtained on the proposed terms and schedules as contemplated by the parties, and/or may impose terms, conditions, obligations or commitments that constitute a “burdensome condition” (as defined in the Merger Agreement). In the event that the regulatory approvals include any such burdensome conditions, or if any of the conditions to closing are not satisfied prior to the termination date specified in the Merger Agreement, Exelon will not be obligated to consummate the Merger.

In the event that the Merger Agreement is terminated prior to the completion of the Merger, PHI could incur significant transaction costs that could materially impact its financial performance and results.

PHI will incur significant transaction costs, including legal, accounting, financial advisory, filing, printing and other costs, relating to the Merger. If (i) the Merger Agreement is terminated under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), or (ii) if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, PHI will be required to pay Exelon a termination fee of $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). The occurrence of either of these events could have a material adverse effect on PHI’s financial results.

PHI and its subsidiaries will be subject to business uncertainties and contractual restrictions while the Merger is pending that could adversely affect PHI’s financial results.

Uncertainty about the effect of the Merger on employees or vendors and others may have an adverse effect on PHI. Although PHI intends to take steps designed to reduce any adverse effects, these uncertainties may impair PHI’s and its subsidiaries’ ability to attract, retain and motivate key personnel until the Merger is completed, and could cause vendors and others that deal with PHI to seek to change existing business relationships. Employee retention and recruitment may be particularly challenging prior to the completion of the Merger, as current employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite PHI’s retention and recruiting efforts, key employees depart or fail to accept employment with PHI or its subsidiaries due to the uncertainty and difficulty of integration or a desire not to remain with the combined company, PHI’s business operations and financial results could be adversely affected.

PHI expects that matters relating to the Merger and integration-related issues will place a significant burden on management, employees and internal resources, which could otherwise have been devoted to other business opportunities. The diversion of management time on Merger-related issues could affect PHI’s financial results. In addition, the Merger Agreement restricts PHI and its subsidiaries, without Exelon’s consent, from taking specified actions until the Merger occurs or the Merger Agreement is terminated, including, without limitation: (i) making certain acquisitions and dispositions of assets or

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property; (ii) exceeding certain capital spending limits; (iii) incurring indebtedness; (iv) issuing equity or equity equivalents; and (v) increasing the dividend rates on its stock. These restrictions may prevent PHI from pursuing otherwise attractive business opportunities and making other changes to its business prior to consummation of the Merger or termination of the Merger Agreement.

Pending or potential future litigation against PHI and its directors challenging the proposed Merger may prevent the Merger from being completed within the anticipated timeframe.

PHI and its directors have been named as defendants in a purported consolidated state class action lawsuit and a substantially similar purported federal class action lawsuit filed on behalf of public stockholders challenging the proposed Merger and seeking, among other things, to enjoin the defendants from consummating the Merger on the agreed-upon terms. If a plaintiff in these lawsuits or any other litigation that may be filed in the future is successful in obtaining an injunction prohibiting the parties from completing the Merger on the terms contemplated by the Merger Agreement, the injunction may prevent the completion of the Merger in the expected timeframe or altogether.

While PHI believes that these lawsuits are without merit, to avoid the risk of litigation delaying or adversely affecting the Merger and to minimize the expense of defending such litigation, on September 12, 2014, PHI entered into a memorandum of understanding with the plaintiffs to document the agreement in principle for the settlement of the state court lawsuit. There can be no assurance that the parties will ultimately enter into a stipulation of settlement or that the state court will approve the settlement even if the parties were to enter into such stipulation. In such event, the proposed settlement as contemplated by the memorandum of understanding may be terminated, which would create additional uncertainty relating to the consummation of the Merger.

Failure to complete the Merger could negatively impact the market price of PHI’s common stock.

Failure to complete the Merger may negatively impact the future trading price of PHI’s common stock. If the Merger is not completed, the market price of PHI’s common stock may decline to the extent that the current market price of PHI’s stock reflects a market assumption that the Merger will be completed.

Additionally, if the Merger is not completed, PHI will have incurred significant costs, as well as the diversion of the time and attention of management. A failure to complete the Merger may also result in negative publicity, litigation against PHI or its directors and officers, and a negative impression of PHI in the investment community. The occurrence of any of these events individually or in combination could have a material adverse effect on PHI’s financial condition, results of operations and its stock price.

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Item 1B. UNRESOLVED STAFF COMMENTS

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

Item 2. PROPERTIES

Transmission and Distribution Systems

On a combined basis, the electric transmission and distribution systems owned by Pepco, DPL and ACE at December 31, 2014, consisted of approximately 4,000 transmission circuit miles of overhead lines, 600 transmission circuit miles of underground cables, 18,200 distribution circuit miles of overhead lines, and 15,900 distribution circuit miles of underground cables, primarily in their respective service territories. DPL and ACE own and operate distribution system control centers in New Castle, Delaware and Mays Landing, New Jersey, respectively. Pepco also operates a distribution system control center in Bethesda, Maryland. The computer equipment and systems contained in Pepco’s control center are financed through a sale and leaseback transaction.

DPL owns a liquefied natural gas facility located in Wilmington, Delaware, with a storage capacity of approximately 3 million gallons and an emergency sendout capability of 25,000 Mcf per day. DPL owns 10 natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 224,744 Mcf per day. DPL also owns approximately 104 pipeline miles of natural gas transmission mains, 1,874 pipeline miles of natural gas distribution mains, and 1,322 pipeline miles of natural gas service lines. In addition, DPL has a 10% undivided interest in approximately 7 miles of natural gas transmission mains, which are used by DPL for its natural gas operations and by the 90% owner for distribution of natural gas to its electric generating facilities.

Substantially all of the transmission and distribution property, plant and equipment owned by each of Pepco, DPL and ACE is subject to the liens of the respective mortgages under which the companies issue First Mortgage Bonds. See Note (10), “Debt” to the consolidated financial statements of PHI.

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Generating Facilities

The following table identifies the electric generating facilities owned by PHI’s subsidiaries at December 31, 2014.

Electric Generating Facilities	Location	Owner	Generating Capacity (kilowatts)
Landfill Gas-Fired Units
Fauquier Landfill Project	Fauquier County, VA	Pepco Energy Services		2,000
Eastern Landfill Project	Baltimore County, MD	Pepco Energy Services		3,000
Bethlehem Landfill Project	Northampton, PA	Pepco Energy Services		5,000
				10,000
Solar Photovoltaic
Atlantic City Convention Center	Atlantic City, NJ	Pepco Energy Services		2,000
Combined Heat and Power Generating
Mid Town Plant	Atlantic City, NJ	Pepco Energy Services		5,400
Total Electric Generating Capacity				17,400

The preceding table sets forth the net summer electric generating capacity of each electric generating facility owned. Although the generating capacity may be higher during the winter months, the facilities are used to meet summer peak loads that are generally higher than winter peak loads. Accordingly, the summer generating capacity more accurately reflects the operational capability of the facilities.

Item 3. LEGAL PROCEEDINGS

Pepco Holdings

Other than litigation incidental to PHI and its subsidiaries’ business, PHI is not a party to, and PHI and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (16), “Commitments and Contingencies,” to the consolidated financial statements of PHI.

Pepco

Other than litigation incidental to its business, Pepco is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (12), “Commitments and Contingencies,” to the financial statements of Pepco.

DPL

Other than litigation incidental to its business, DPL is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (14), “Commitments and Contingencies,” to the financial statements of DPL.

ACE

Other than litigation incidental to its business, ACE is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (13), “Commitments and Contingencies,” to the consolidated financial statements of ACE.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

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Part II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The New York Stock Exchange is the principal market on which Pepco Holdings common stock is traded. The following table presents the dividends declared per share on the Pepco Holdings common stock and the high and low sales prices for the common stock based on composite trading as reported by the New York Stock Exchange during each quarter in the last two years.

	Dividends Per Share		Price Range
			High		Low
2014:
First Quarter	$	0.27	$	20.93	$	18.53
Second Quarter		0.27		27.90		20.09
Third Quarter		0.27		27.92		26.76
Fourth Quarter		0.27		27.65		26.35
	$	1.08
2013:
First Quarter	$	0.27	$	21.43	$	18.82
Second Quarter		0.27		22.72		19.35
Third Quarter		0.27		20.90		18.04
Fourth Quarter		0.27		19.62		18.19
	$	1.08

At February 13, 2015, there were 43,769 holders of record of Pepco Holdings common stock.

Dividends

On January 22, 2015, the PHI Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2015, to shareholders of record on March 10, 2015.

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Capital Requirements – Dividends,” and Note (12), “Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock – Dividend Restrictions,” of the consolidated financial statements of PHI for information regarding restrictions on the ability of PHI and its subsidiaries to pay dividends.

PHI Subsidiaries

One of PHI’s financial objectives is to maintain an equity ratio of 49%-50% in each of its operating utilities. Each quarter, PHI may contribute equity to its utility subsidiaries or the utility subsidiaries may make a dividend payment to PHI in order to maintain an equity ratio of 49%-50% in each of the utility subsidiaries. During 2014, PHI made capital contributions of $80 million and $130 million to Pepco and DPL, respectively, and in 2013, PHI made capital contributions of $175 million and $75 million to Pepco and ACE, respectively.

All of Pepco’s common stock is held by Pepco Holdings, and all of DPL’s and ACE’s common stock is held by Conectiv, LLC (Conectiv), which in turn is wholly owned by Pepco Holdings. The table below presents the aggregate amount of common stock dividends paid by Pepco to PHI, and by DPL and ACE to Conectiv, during each quarter in the last two years. Dividends received by PHI in 2014 and 2013 from Pepco were used to support the payment of its common stock dividend. Dividends paid by ACE and DPL in 2014 and 2013 were used by Conectiv to pay down its short-term debt owed to PHI.

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	Pepco		DPL		ACE
2014:
First Quarter	$	—	$	20,000,000	$	26,000,000
Second Quarter		46,000,000		—		—
Third Quarter		—		—		—
Fourth Quarter		40,000,000		80,000,000		—
	$	86,000,000	$	100,000,000	$	26,000,000
2013:
First Quarter	$	—	$	—	$	—
Second Quarter		15,000,000		20,000,000		—
Third Quarter		31,000,000		10,000,000		25,000,000
Fourth Quarter		—		—		35,000,000
	$	46,000,000	$	30,000,000	$	60,000,000

Recent Sales of Unregistered Equity Securities

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

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Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Pepco Holdings

The following table includes shares of common stock accepted by Pepco Holdings during the quarter ended December 31, 2014 from certain employees in accordance with the provisions of the Pepco Holdings 2012 Long-Term Incentive Plan (2012 LTIP) to satisfy the employees’ minimum statutory tax withholding obligations related to awards of restricted stock under the 2012 LTIP that were granted in December 2014. Pepco Holdings does not currently have any publicly announced plans or programs to repurchase its common stock.

Period	Total Number of Shares Accepted (a)		Average Price Per Share
October 1 – October 31, 2014		—		—
November 1 – November 30, 2014		—		—
December 1 – December 31, 2014		29,065	$	27.01	(b)
Total		29,065	$	27.01

(a) Includes shares of Pepco Holdings’ common stock accepted from certain employees under the 2012 LTIP to satisfy the employees’ minimum statutory tax withholding obligations related to awards of restricted stock, which shares of common stock were then held in treasury.

(b) Represents the average of the high and low trading prices of a share of common stock on the New York Stock Exchange (NYSE) on the date of grant of the shares of restricted stock.

Pepco

None.

DPL

None.

ACE

None.

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Item 6. SELECTED FINANCIAL DATA

The following table sets forth selected historical consolidated data for PHI as of and for each of the years ended December 31, 2014, 2013, 2012, 2011 and 2010, derived from PHI’s audited consolidated financial statements.

PEPCO HOLDINGS CONSOLIDATED FINANCIAL HIGHLIGHTS

	2014			2013			2012		2011		2010
	(in millions, except per share data)
Consolidated Operating Results
Total Operating Revenue	$	4,878		$	4,666		$	4,625	$	4,964	$	5,407
Net Income from Continuing Operations		242	(a)		110	(b)		218		222		91	(c)
Net Income (Loss)		242			(212	)		285		257		32
Common Stock Information
Basic Earnings Per Share of Common Stock from Continuing Operations	$	0.96		$	0.45		$	0.95	$	0.98	$	0.41
Basic Earnings (Loss) Per Share of Common Stock		0.96			(0.86	)		1.25		1.14		0.14
Weighted Average Shares Outstanding—Basic		251			246			229		226		224
Cash Dividends Per Share of Common Stock		1.08			1.08			1.08		1.08		1.08
Year-End Stock Price		26.93			19.13			19.61		20.30		18.25
Net Book Value Per Common Share		17.10			17.23			19.19		18.92		18.65
Other Information
Total Assets	$	15,667		$	14,848		$	15,794	$	15,001	$	14,654
Capitalization
Short-Term Debt	$	729		$	565		$	965	$	732	$	534
Long-Term Debt		4,441			4,053			3,648		3,794		3,629
Current Portion of Long-Term Debt and Project Funding		431			446			569		112		75
Transition Bonds issued by ACE Funding		171			214			256		295		332
Capital Lease Obligations Due Within One Year		10			9			8		8		8
Capital Lease Obligations		50			60			70		78		86
Long-Term Project Funding		8			10			12		13		15
Series A Preferred Stock		129			—			—		—		—
Non-controlling Interest		—			—			—		—		6
Common Shareholders’ Equity		4,322			4,315			4,414		4,304		4,198
Total Capitalization	$	10,291		$	9,672		$	9,942	$	9,336	$	8,883

(a) Includes impairment losses of $81 million ($48 million after-tax) associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City and $25 million ($23 million after-tax) of incremental merger-related transaction costs.

(b) Includes a charge of $101 million to establish valuation allowances related to certain PCI deferred tax assets and a charge of $66 million to reflect the anticipated additional interest expense on estimated federal and state income tax obligations resulting from the change in assessment of the tax benefits associated with the cross-border energy lease investments.

(c) Includes a loss on extinguishment of debt of $189 million ($113 million after-tax).

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Registrants	Page No.
Pepco Holdings		50
Pepco		102
DPL		113
ACE		124

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PEPCO HOLDINGS

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

Pepco Holdings, Inc.

General Overview

PHI, a Delaware corporation incorporated in 2001, is a holding company that, through its regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity, and, to a lesser extent, the distribution and supply of natural gas (Power Delivery). Through Pepco Energy Services, PHI provides energy savings performance contracting services, underground transmission and distribution construction and maintenance services and steam and chilled water under long-term contracts. For additional discussion, see “Pepco Energy Services” below.

Each of Power Delivery and Pepco Energy Services constitutes a separate segment for financial reporting purposes. Through its subsidiary PCI, PHI maintained a portfolio of cross-border energy lease investments. PHI completed the termination of its interests in its cross-border energy lease investments during 2013. As a result, the cross-border energy lease investments, which comprised substantially all of the operations of the Other Non-Regulated segment, have been accounted for as discontinued operations. The remaining operations of the Other Non-Regulated segment, which no longer meet the definition of a separate segment for financial reporting purposes, have been included in Corporate and Other.

The following table sets forth the percentage contributions to consolidated operating revenue and operating income from continuing operations attributable to PHI segments for each of the preceding three years:

	2014			2013			2012
Percentage of Consolidated Operating Revenue
Power Delivery		94	%		96	%		95	%
Pepco Energy Services		6	%		4	%		6	%
Corporate and Other		—			—			(1	)%
Percentage of Consolidated Operating Income
Power Delivery		114	%		97	%		98	%
Pepco Energy Services		(13	)%		—			(3	)%
Corporate and Other		(1	)%		3	%		5	%
Percentage of Consolidated Operating Revenue—Power Delivery
Power Delivery Electric		96	%		96	%		96	%
Power Delivery Gas		4	%		4	%		4	%

Agreement and Plan of Merger with Exelon Corporation

PHI entered into the Merger Agreement, with Exelon and Merger Sub, providing for the Merger, with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

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PEPCO HOLDINGS

In connection with entering into the Merger Agreement, PHI entered into the Subscription Agreement with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of the Preferred Stock, for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014 and January 26, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for a purchase price of $18 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from FERC, the FCC, the DPSC, the DCPSC, the MPSC, the NJBPU and the VSCC; (iii) the expiration or termination of the applicable waiting period under the HSR Act; and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement).

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. On December 22, 2014, the applicable waiting period under the HSR Act expired, and the HSR Act no longer precludes completion of the Merger. Although the DOJ allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised PHI that it has concluded its investigation. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015. On February 13, 2015, Pepco Holdings, DPL, Exelon, certain of Exelon’s affiliates, the Staff of the DPSC and certain other parties, filed a settlement agreement with the DPSC with respect to the Merger. This settlement agreement is subject to approval by the DPSC.

The Merger Agreement may be terminated by each of PHI and Exelon under certain circumstances, including if the Merger is not consummated by July 29, 2015 (subject to extension by PHI or Exelon to October 29, 2015, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Merger Agreement also provides for certain termination rights for both PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, in the event of a Regulatory Termination, PHI will be able to redeem any issued and outstanding Preferred Stock at par value. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

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PEPCO HOLDINGS

Power Delivery

Power Delivery Electric consists primarily of the transmission, distribution and default supply of electricity, and Power Delivery Gas consists of the delivery and supply of natural gas.

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

• Commercial activities in the region include federal and municipal government services, professional, scientific and technical services, educational and health services, banking, casinos, tourism and transportation.

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

Each utility comprising Power Delivery is a regulated public utility in the jurisdictions that comprise its service territory. Each utility is responsible for the distribution of electricity and, in the case of DPL, natural gas in its service territory, for which it is paid tariff rates established by the applicable local public service commission in each jurisdiction. Each utility also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is SOS in Delaware, the District of Columbia and Maryland, and BGS in New Jersey. These supply service obligations are referred to generally as Default Electricity Supply.

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

The profitability of Power Delivery depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge. Operating results also can be affected by economic conditions generally, the level of commercial activity affecting a region, industry or business sector within a service territory, energy prices, the impact of energy efficiency measures on customer usage of electricity and weather.

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

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

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PHI’s utility subsidiaries allocate a substantial portion of their total capital expenditures to improving the reliability of their electrical transmission and distribution systems and replacing aging infrastructure throughout their service territories. These activities include:

• identifying and upgrading under-performing feeder lines;

• adding new facilities to support load;

• installing distribution automation systems on both the overhead and underground network systems; and

• rejuvenating and replacing underground residential cables.

PHI’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures within “– Capital Resources and Liquidity – Capital Requirements – Capital Expenditures.”

Power Delivery Initiatives and Activities

District of Columbia Power Line Undergrounding Initiative

For information about the District of Columbia Power Line Undergrounding Initiative, please refer to Note (7), “Regulatory Matters – District of Columbia Power Line Undergrounding Initiative,” to the consolidated financial statements of PHI.

MPSC New Generation Contract Requirement

For information about the MPSC New Generation Contract Requirement, please refer to Note (7), “Regulatory Matters – MPSC New Generation Contract Requirement,” to the consolidated financial statements of PHI.

Smart Grid Initiatives

PHI’s utility subsidiaries are engaged in transforming the power grid that they own and operate into a “smart grid,” a network of automated digital devices capable of collecting and communicating large amounts of real-time data.

A central component of the smart grid is AMI, a system that collects, measures and analyzes energy usage data from advanced digital meters, known as “smart meters.” Also critical to the operation of the smart grid is distribution automation technology, which is comprised of automated devices that have internal intelligence and can be controlled remotely to better manage power flow and restore service quickly and more safely. Both the AMI system and distribution automation are enabled by advanced technology that communicates with devices installed on the energy delivery system and transmits energy usage data to the host utility. The implementation of the AMI system and distribution automation involves an integration of technologies provided by multiple vendors.

As of December 31, 2014, Pepco and DPL have completed the installation and activation of smart meters in the District of Columbia, Maryland and Delaware service territories. The DCPSC, the MPSC and the DPSC approved the creation by PHI’s utility subsidiaries of regulatory assets to defer AMI costs between rate cases and to defer carrying charges on the deferred costs. Thus, these costs will be recovered in the future through base rates; however, for AMI costs incurred by Pepco in Maryland with respect to test years after 2011, pursuant to an MPSC order, the recovery of such costs will be allowed when Pepco demonstrates that the AMI system is cost-effective. The MPSC’s July 2013 order in Pepco’s November 2012 electric distribution base rate application excluded the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system. As a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred.

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PEPCO HOLDINGS

In 2010, two of PHI’s utility subsidiaries were granted cash awards in the aggregate amount of $168 million by the U.S. Department of Energy to support their smart grid initiatives.

• Pepco was awarded $149 million for AMI, direct load control, distribution automation and communications infrastructure, of which $148 million has been received through December 31, 2014.

• ACE was awarded $19 million for direct load control, distribution automation and communications infrastructure, all of which has been received through December 31, 2014.

Mitigation of Regulatory Lag

An important factor in the ability of PHI’s utility subsidiaries to earn their authorized ROE is the willingness of applicable public service commissions to adequately address the shortfall in revenues in a utility’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Pepco, DPL and ACE are currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than their revenue growth.

In an effort to minimize the effects of regulatory lag, prior to the initial execution of the Merger Agreement in April 2014, PHI’s utility subsidiaries had been filing electric distribution base rate cases every nine to twelve months in each of their jurisdictions, pursuing alternative ratemaking mechanisms, evaluating potential reductions in planned capital expenditures, and discussing with the regulatory community and other stakeholders the changing regulatory model economics that are causing regulatory lag.

As further described in “– Agreement and Plan of Merger with Exelon Corporation,” PHI has entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings. Accordingly, with the exception of ongoing rate cases (see Note (7), “Regulatory Matters – Rate Proceedings,” to the consolidated financial statements of PHI), PHI’s efforts to mitigate regulatory lag have been delayed pending the closing of the Merger or the termination of the Merger Agreement.

MAPP Settlement Agreement

For information about the MAPP settlement agreement, please refer to Note (7), “Regulatory Matters – MAPP Settlement Agreement,” to the consolidated financial statements of PHI.

Transmission ROE Challenges

For information about the challenges to the utility subsidiaries’ base ROE and the application of the formula rate process, each associated with the transmission services they provide, please refer to Note (7), “Regulatory Matters – Transmission ROE Challenges,” to the consolidated financial statements of PHI.

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PEPCO HOLDINGS

Pepco Energy Services

Pepco Energy Services is focused on growing its energy savings business and its underground transmission and distribution construction business while managing its thermal assets in Atlantic City. The energy savings business focuses on developing, building and operating energy savings performance contracting solutions primarily for federal, state and local government customers. After a significant slowdown in 2012, the energy savings market has improved, however the market has not returned to the level of activity prior to 2012. The market is expected to continue to improve as the long-term fundamentals of the energy savings business remain strong. Pepco Energy Services’ underground transmission and distribution construction business focuses on providing construction and maintenance services for electric power utilities in North America.

PHI guarantees the obligations of Pepco Energy Services under certain contracts in its energy savings performance contracting business and underground transmission and distribution construction business. At December 31, 2014, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $336 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects. These guarantees totaled $185 million at December 31, 2014.

During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services is demolishing the Benning Road generation facility and realizing the scrap metal salvage value of the facility. The demolition of the facility commenced in the fourth quarter of 2013 and is expected to be completed in the first quarter of 2015. Pepco Energy Services is recognizing the salvage proceeds associated with the scrap metals at the facility as realized.

Revenues associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City are derived from long-term contracts with a few major customers in the Atlantic City hotel and casino industry. The carrying amount of Pepco Energy Services’ long-lived assets in Atlantic City at December 31, 2014 totaled $2 million, after impairment losses aggregating $81 million that were recorded during the third and fourth quarters of 2014. In September 2014, two significant customers of these thermal operations declared Chapter 11 bankruptcy. One of the customers closed operations in September 2014 and is seeking a buyer for its facility. The second customer announced that it would remain open in 2015 but that it could close operations later this year if it is unable to lower its operating costs. At September 30, 2014, PHI performed impairment tests on asset groups comprising substantially all of the long-lived assets associated with its thermal operations in Atlantic City and recorded an impairment loss of $53 million ($32 million after-tax) with respect to the most significant asset group (with a carrying amount, before the impairment loss, of $70 million at September 30, 2014). In light of recent developments regarding future business prospects with the two significant customers that declared bankruptcy in September 2014 (including their rejection of Pepco Energy Services’ long-term thermal contracts during February 2015, as part of these customers’ bankruptcy proceedings) and the fact that two other significant customers of the thermal operations declared Chapter 11 bankruptcy in January 2015, Pepco Energy Services again performed impairment tests on asset groups comprising substantially all of the long-lived assets associated with its thermal operations in Atlantic City at December 31, 2014. As a result, Pepco Energy Services recorded an additional impairment charge of $28 million ($16 million after-tax) in the fourth quarter of 2014 that was associated with the most significant asset group and another asset group. Future developments with respect to these and other customers in Atlantic City may require Pepco Energy Services to perform additional impairment analyses of the thermal operations and certain related assets. If these assets are determined to be further impaired, Pepco Energy Services would reduce the carrying value of these assets by the amount of the impairment and record a corresponding non-cash charge to earnings. Moreover, the contract rejections referred to above are expected to reduce Pepco Energy Services’ future earnings and cash flow associated with its thermal operations in Atlantic City.

Corporate and Other

Corporate and other includes the remaining operations of the former Other Non-Regulated segment, certain parent company transactions (including interest expense on parent company debt and incremental external merger-related costs) and inter-company eliminations.

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Between 1990 and 1999, PCI entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets, which comprise substantially all of the remaining operations of the former Other Non-Regulated segment. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. After evaluating events that took place during the first quarter of 2013, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of all relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances.

Discontinued Operations

In this Management’s Discussion and Analysis of Financial Condition and Results of Operations, all references to PHI’s segments and continuing operations exclude the following discontinued operations.

Cross-Border Energy Lease Investments

Through its subsidiary PCI, PHI held a portfolio of cross-border energy lease investments. During 2013, PHI completed the termination of its interest in its cross-border energy lease investments and, as a result, these investments are being accounted for as discontinued operations.

As discussed in Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI, PHI is involved in ongoing litigation with the IRS concerning certain benefits associated with previously held investments in cross-border energy leases. 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 determined in the first quarter of 2013 that its tax position with respect to the benefits associated with its cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes, and PHI recorded non-cash after-tax charges of $323 million (after-tax) in the first quarter of 2013 and $6 million (after-tax) in the second quarter 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 (Accounting Standards Codification (ASC) 840). This pre-tax charge was originally recorded in the consolidated statements of income (loss) as a reduction in operating revenue and is now reflected in loss from discontinued operations, net of income taxes.

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

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Retail Electric and Natural Gas Supply Businesses of 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 not a part of the Pepco Energy Services segment for financial reporting purposes.

Earnings Overview

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

	2014			2013			Change
	(millions of dollars)
Power Delivery	$	320		$	289		$	31
Pepco Energy Services		(39	)		3			(42	)
Corporate and Other		(39	)		(182	)		143
Net Income from Continuing Operations		242			110			132
Discontinued Operations		—			(322	)		322
Total PHI Net Income (Loss)	$	242		$	(212	)	$	454

Net income from continuing operations for the year ended December 31, 2014 was $242 million, or $0.96 per share, compared to $110 million, or $0.45 per share, for the year ended December 31, 2013.

Net income from continuing operations for the year ended December 31, 2014 included the items set forth below, which are presented net of related federal and state income taxes and are in millions of dollars:

•	Asset impairment losses in Pepco Energy Services ($81 million pre-tax)	$	48
•	Incremental merger-related transaction costs in Corporate and Other ($25 million pre-tax)	$	23

Excluding the items listed above for the year ended December 31, 2014, net income from continuing operations would have been $313 million, or $1.24 per share.

Net income from continuing operations for the year ended December 31, 2013 included the charges set forth below in Corporate and Other, which are presented, where applicable, net of related federal and state income taxes and are in millions of dollars:

•	Charge to establish valuation allowances related to certain PCI deferred tax assets	$	101
•	Charge to reflect the anticipated additional interest expense on estimated federal and state income tax obligations allocated to Corporate and Other (as if it were a separate taxpayer) resulting from the change in assessment of the tax benefits associated with the cross-border energy lease investments ($102 million pre-tax)	$	66

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Excluding the items listed above for the year ended December 31, 2013, net income from continuing operations would have been $277 million, or $1.13 per share.

PHI discloses net income from continuing operations and related per share data excluding certain items because management believes that these items are not representative of PHI’s ongoing business operations. Management uses this information, and believes that such information is useful to investors, in evaluating PHI’s period-over-period performance. The inclusion of this disclosure is intended to complement, and should not be considered as an alternative to, PHI’s reported net income from continuing operations and related per share data in accordance with GAAP.

Net loss from discontinued operations was $322 million, or $1.31 per share, for the year ended December 31, 2013.

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $31 million increase in earnings was primarily due to the following:

• An increase of $50 million from electric distribution base rate increases (Pepco in the District of Columbia and Maryland, DPL in Maryland and Delaware and ACE in New Jersey).

• An increase of $14 million from other distribution revenue, primarily due to Pepco customer growth.

• An increase of $10 million from network service transmission revenues primarily due to increased rates, partially offset by the amortization of MAPP abandonment costs and the establishment of a reserve related to the FERC ROE complaint.

• An increase of $5 million related to gains recorded in 2014 associated with condemnation awards for certain Pepco transmission properties.

• A decrease of $22 million due to higher depreciation and amortization expense primarily resulting from increases in plant investment and regulatory assets, partially offset by lower depreciation rates.

• A decrease of $9 million associated with higher interest benefits recorded in 2013 related to uncertain and effectively settled tax positions.

• A decrease of $9 million due to higher other operation and maintenance expense primarily related to higher system maintenance expenses, recovery of energy efficiency and conservation costs in 2013 (in accordance with an MPSC order) and billing system training costs, partially offset by lower pension and other postretirement benefit (OPEB) costs and the allowed recovery in 2014 of certain previously expensed rate case costs in accordance with a District of Columbia rate order.

• A decrease of $7 million due to incremental merger-related integration costs.

Pepco Energy Services’ $42 million decrease in earnings was primarily due to asset impairment losses recorded in 2014 associated with its combined heat and power thermal generating facilities and operations in Atlantic City, partially offset by tax benefits received from deductions for energy efficiency construction projects, and higher construction activity.

Corporate and Other’s $143 million decrease in net loss was primarily due to the following:

• An after-tax charge of $101 million in 2013 to establish valuation allowances against certain PCI deferred tax assets.

• An after-tax charge of $66 million in 2013 to reflect the anticipated additional interest expense allocated to Corporate and Other related to changes in PHI’s consolidated estimated federal and state income tax obligations resulting from the change in assessment regarding the tax benefits related to the cross-border energy lease investments.

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• After-tax charges of $23 million in 2014 due to incremental merger-related transaction costs.

Discussion of Discontinued Operations:

There were no discontinued operations for the year ended December 31, 2014. Net loss from discontinued operations for the year ended December 31, 2013 was $322 million, primarily as a result of the following:

• An aggregate after-tax charge of $313 million recorded in 2013 to reduce the carrying value of PCI’s cross-border energy lease investments ($373 million pre-tax).

• An after-tax charge of $16 million recorded in 2013 to reflect the anticipated additional interest expense on estimated federal and state income tax obligations allocated to PCI (as if it were a separate taxpayer) resulting from the change in assessment of the tax benefits associated with the cross-border energy lease investments ($25 million pre-tax).

• A loss of $2 million as a result of the early termination of certain cross-border energy leases in 2013.

• Net income of $5 million in 2013 from the discontinued Pepco Energy Services retail electric and natural gas supply businesses.

Consolidated Results of Operations

The following results of operations discussion compares the year ended December 31, 2014 to the year ended December 31, 2013. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

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

	2014			2013			Change
Power Delivery	$	4,607		$	4,472		$	135
Pepco Energy Services		278			203			75
Corporate and Other		(7	)		(9	)		2
Total Operating Revenue	$	4,878		$	4,666		$	212

Power Delivery

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

	2014		2013		Change
Regulated T&D Electric Revenue	$	2,277	$	2,146	$	131
Default Electricity Supply Revenue		2,076		2,075		1
Other Electric Revenue		60		60		—
Total Electric Operating Revenue		4,413		4,281		132
Regulated Gas Revenue		176		165		11
Other Gas Revenue		18		26		(8	)
Total Gas Operating Revenue		194		191		3
Total Power Delivery Operating Revenue	$	4,607	$	4,472	$	135

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Regulated Transmission and Distribution (T&D) Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from non-bypassable Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM in consideration for approved regional transmission expansion plan expenditures.

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

Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates.

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

Regulated T&D Electric

	2014		2013		Change
Regulated T&D Electric Revenue
Residential	$	824	$	781	$	43
Commercial and industrial		1,013		970		43
Transmission and other		440		395		45
Total Regulated T&D Electric Revenue	$	2,277	$	2,146	$	131
	2014		2013		Change
Regulated T&D Electric Sales (Gigawatt hour (GWh))
Residential		17,129		17,168		(39	)
Commercial and industrial		29,831		30,070		(239	)
Transmission and other		255		259		(4	)
Total Regulated T&D Electric Sales		47,215		47,497		(282	)
	2014		2013		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,669		1,650		19
Commercial and industrial		200		200		—
Transmission and other		2		2		—
Total Regulated T&D Electric Customers		1,871		1,852		19

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Regulated T&D Electric Revenue increased by $131 million primarily due to:

• An increase of $81 million due to electric distribution base rate increases (Pepco in the District of Columbia effective March 2014, and in Maryland effective July 2013; DPL in Maryland effective September 2013, and in Delaware effective October 2013; ACE effective July 2013 and September 2014).

• An increase of $20 million in transmission revenue resulting from higher rates effective June 1, 2014 and June 1, 2013 related to increases in transmission plant investment and operating expenses, partially offset by the establishment of a reserve related to the FERC ROE complaint.

• An increase of $19 million due to an EmPower Maryland (a Maryland demand-side management program for Pepco and DPL) rate increase effective February 2014 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

• An increase of $16 million due to customer growth in 2014 primarily in the residential classes.

• An increase of $12 million in transmission revenue related to the recovery of MAPP abandonment costs, as approved by FERC (which is substantially offset in Depreciation and Amortization).

• An increase of $5 million primarily due to a rate increase in the New Jersey Societal Benefit Charge (a surcharge related to the New Jersey Societal Benefit Program, which is a public interest program for low income customers) effective January 2014 (which is offset in Depreciation and Amortization and Deferred Electric Service Costs).

• An increase of $5 million in transmission revenue related to the resale by DPL of renewable energy in Delaware (which is substantially offset in Purchased Energy and Depreciation and Amortization).

• An increase of $4 million in capacity revenue as a result of expanding Maryland demand side management programs (which is partially offset in Depreciation and Amortization).

The aggregate amount of these increases was partially offset by:

• A decrease of $12 million in distribution revenue due to lower pass-through revenue (which is substantially offset by a corresponding decrease in Other Taxes) primarily the result of a rate decrease effective July 2014 in utility taxes collected by Pepco on behalf of Montgomery County, Maryland.

• A decrease of $10 million in distribution revenue due to lower pass-through revenue primarily the result of the expiration of the New Jersey Transitional Energy Facility Assessment (TEFA) tax surcharge effective December 2013 (which is offset in Other Taxes).

• A decrease of $5 million due to lower ACE non-weather related average commercial and residential customer usage.

• A decrease of $4 million due to lower ACE sales primarily as a result of milder weather during the 2014 spring and summer months.

• A decrease of $2 million primarily due to a rate decrease effective May 2013 associated with the Renewable Portfolio Surcharge in Delaware (which is substantially offset in Fuel and Purchased Energy and Depreciation and Amortization).

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Default Electricity Supply

	2014		2013		Change
Default Electricity Supply Revenue
Residential	$	1,312	$	1,376	$	(64	)
Commercial and industrial		553		542		11
Other		211		157		54
Total Default Electricity Supply Revenue	$	2,076	$	2,075	$	1

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

	2014		2013		Change
Default Electricity Supply Sales (GWh)
Residential		13,851		13,743		108
Commercial and industrial		5,420		5,079		341
Other		44		55		(11	)
Total Default Electricity Supply Sales		19,315		18,877		438
	2014		2013		Change
Default Electricity Supply Customers (in thousands)
Residential		1,397		1,352		45
Commercial and industrial		129		125		4
Other		—		—		—
Total Default Electricity Supply Customers		1,526		1,477		49

Default Electricity Supply Revenue increased by $1 million primarily due to:

• A net increase of $68 million due to higher sales primarily as a result of customer migration from competitive suppliers in Pepco and ACE, partially offset by lower sales in DPL as a result of customer migration to competitive suppliers.

• An increase of $50 million in wholesale energy and capacity resale revenues primarily due to higher market prices for the resale of electricity and capacity purchased from NUGs.

• An increase of $5 million in revenue from PJM for transmission enhancement credits as a result of a higher total cost of transmission projects in 2014.

The aggregate amount of these increases was partially offset by:

• A decrease of $97 million as a result of lower Default Electricity Supply rates.

• A net decrease of $24 million due to lower Pepco and ACE non-weather related average customer usage, partially offset by higher usage at DPL.

The variances described above with respect to Default Electricity Supply Revenue include the effects of an increase of $3 million in ACE’s BGS unbilled revenue resulting primarily from higher rates and customer migration from competitive suppliers in the unbilled revenue period for December 31, 2014 as compared to the corresponding period for December 31, 2013. Such an increase in ACE’s BGS unbilled revenue has the effect of directly increasing the profitability of ACE’s Default Electricity Supply business ($2 million increase in net income) as these unbilled revenues are not included in the deferral calculation until they are billed to customers under the BGS terms approved by the NJBPU.

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Regulated Gas

	2014		2013		Change
Regulated Gas Revenue
Residential	$	106	$	103	$	3
Commercial and industrial		59		52		7
Transportation and other		11		10		1
Total Regulated Gas Revenue	$	176	$	165	$	11
	2014		2013		Change
Regulated Gas Sales (million cubic feet)
Residential		8,550		7,861		689
Commercial and industrial		6,063		4,945		1,118
Transportation and other		6,418		6,990		(572	)
Total Regulated Gas Sales		21,031		19,796		1,235
	2014		2013		Change
Regulated Gas Customers (in thousands)
Residential		118		117		1
Commercial and industrial		10		9		1
Transportation and other		—		—		—
Total Regulated Gas Customers		128		126		2

Regulated Gas Revenue increased by $11 million primarily due to:

• An increase of $9 million due to higher sales primarily as a result of colder weather during the winter months of 2014, as compared to 2013.

• An increase of $6 million due to higher non-weather related average customer usage.

• An increase of $4 million due to a distribution rate increase effective July 2013.

• An increase of $2 million due to customer growth primarily in the residential customer class.

The aggregate amount of these increases was partially offset by a decrease of $10 million due to a Gas Cost Rate (GCR) decrease effective November 2013.

Other Gas Revenue

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

Pepco Energy Services

Pepco Energy Services’ operating revenue increased by $75 million primarily due to:

• An increase of $46 million primarily in energy savings construction activities.

• An increase of $26 million in underground transmission and distribution construction activities.

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• An increase of $3 million associated with the thermal business in Atlantic City primarily due to colder temperatures in the first half of 2014.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2014		2013			Change
Power Delivery	$	2,074	$	2,070		$	4
Pepco Energy Services		212		148			64
Corporate and Other		1		(2	)		3
Total	$	2,287	$	2,216		$	71

Power Delivery

Power Delivery’s Fuel and Purchased Energy expense consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense increased by $4 million primarily due to:

• An increase of $33 million primarily due to customer migration from competitive suppliers.

• An increase of $20 million in deferred electricity expense primarily due to higher revenue associated with Pepco and DPL Default Electricity Supply sales, which resulted in a higher rate of recovery of Default Electricity Supply costs.

• An increase of $16 million in the cost of gas purchases for on-system sales as a result of higher average gas prices.

• An increase of $3 million in the costs associated with purchasing Renewable Energy Credits in Delaware (which is offset by a corresponding increase in Regulated T&D Revenue).

• An increase of $2 million due to higher electricity sales primarily as a result of colder weather during the 2014 winter months, as compared to 2013.

The aggregate amount of these increases was partially offset by:

• A net decrease of $50 million due to lower average electricity costs under Pepco and DPL Default Electricity Supply contracts, and due to lower ACE costs under BGS contracts.

• A decrease of $8 million in the cost of gas purchases for off-system sales as a result of lower volumes.

• A decrease of $7 million in deferred gas expense as a result of a lower rate of recovery of natural gas supply costs.

• A decrease of $6 million from the settlement of financial hedges entered into as part of DPL’s hedge program for the purchase of regulated natural gas.

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Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy expense and Other Services Cost of Sales increased by $64 million primarily due to:

• An increase of $39 million primarily associated with increased energy savings construction activity.

• An increase of $25 million associated with increased underground transmission and distribution construction activities.

Other Operation and Maintenance

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

	2014			2013			Change
Power Delivery	$	904		$	871		$	33
Pepco Energy Services		52			42			10
Corporate and Other		(32	)		(62	)		30
Total	$	924		$	851		$	73

Power Delivery

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

• An increase of $14 million in internal and external merger-related integration costs.

• An increase of $8 million primarily due to higher tree trimming and maintenance costs.

• An increase of $7 million primarily due to new customer system support costs.

• An increase of $6 million in bad debt expense, of which $1 million is deferred and recoverable.

• An increase of $5 million in emergency restoration costs.

• An increase of $3 million due to the write-off of unrecoverable regulatory assets previously established in connection with the sale of certain ACE generation assets.

The aggregate amount of these increases was partially offset by:

• A decrease of $7 million in regulatory expenses.

• A decrease of $3 million resulting from the 2013 write-off of disallowed MAPP and associated transmission project costs.

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Pepco Energy Services

Other Operation and Maintenance expense for Pepco Energy Services increased by $10 million primarily due to:

• An increase of $4 million in bad debt expense for accounts receivable.

• An increase of $3 million in employee compensation primarily associated with its energy savings business.

• An increase of $2 million in repairs and maintenance costs associated with its thermal business in Atlantic City.

• An increase of $1 million associated with the demolition of the Benning Road generation facility.

Corporate and Other

Other Operation and Maintenance expense for Corporate and Other increased by $30 million primarily due to internal and external merger-related transaction costs.

Depreciation and Amortization

Depreciation and Amortization expense increased by $76 million to $549 million in 2014 from $473 million in 2013 primarily due to:

• An increase of $20 million due to utility plant additions.

• An increase of $13 million in amortization of regulatory assets primarily associated with the EmPower Maryland surcharge rate increase effective February 2014 (which is offset by an increase in Regulated T&D Electric Revenue).

• An increase of $12 million in amortization of MAPP abandonment costs (which is offset in Regulated T&D Electric Revenue).

• An increase of $12 million in amortization due to the expiration in August 2013 of the excess depreciation reserve regulatory liability of ACE.

• An increase of $10 million in amortization of regulatory assets primarily related to recoverable AMI costs, major storm costs and rate case costs.

• An increase of $5 million in amortization of solar renewable energy credits (which is offset by an increase in Regulated T&D Electric Revenue).

Other Taxes

Other Taxes decreased by $15 million to $413 million in 2014 from $428 million in 2013. The decrease was primarily due to:

• A decrease of $10 million in TEFA tax collections due to the expiration of the assessment effective December 2013 (which is offset by a corresponding decrease in Regulated T&D Electric Revenue).

• A decrease of $10 million in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).

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The aggregate amount of these decreases was partially offset by an increase of $7 million in property taxes in Maryland.

Deferred Electric Service Costs

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

Deferred Electric Service Costs decreased by $6 million to an expense of $20 million in 2014 as compared to an expense of $26 million in 2013 primarily due to a decrease in deferred electricity expense as a result of lower Default Electricity Supply revenue rates.

Impairment Losses

Impairment losses increased by $77 million to $81 million in 2014 from $4 million in 2013. The increase was primarily due to 2014 impairment losses of $81 million ($48 million after-tax) at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City, partially offset by a 2013 impairment loss of $4 million ($3 million after-tax) associated with a landfill gas-fired electric generation facility.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $15 million to a net expense of $224 million in 2014 from a net expense of $239 million in 2013 primarily due to:

• An increase of $9 million in Other Income associated with gains recorded in 2014 associated with condemnation awards for certain Pepco transmission properties.

• A decrease of $5 million in interest expense primarily associated with lower short-term debt and lower long-term debt interest expense.

Income Tax Expense

PHI’s income tax expense decreased by $181 million to $138 million in 2014 from $319 million in 2013.

PHI’s consolidated effective income tax rates for the years ended December 31, 2014 and 2013 were 36.3% and 74.4%, respectively. The decrease in the effective tax rate resulted from certain tax benefits associated with Pepco Energy Services recorded in the third quarter of 2014, changes in estimates and interest related to uncertain and effectively settled tax positions and deferred tax valuation allowances established in the first quarter of 2013, partially offset by the effect of certain incremental merger-related costs (as further described in Note (1), “Organization,” to the consolidated financial statements of PHI), incurred in 2014 that are not tax deductible.

During 2014, PHI recorded a tax benefit of $5 million related to certain energy efficiency tax deductions related to Pepco Energy Services’ energy savings performance contracting services.

During 2013, PHI recorded a $56 million charge for a change in estimates and interest related to uncertain and effectively settled tax positions, primarily representing the anticipated additional interest expense on estimated federal and state income tax obligations that was allocated to PHI’s continuing operations resulting from a change in assessment of tax benefits associated with the formercross-border energy lease investments of PCI in the first quarter of 2013.

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Also, in the first quarter of 2013, PHI established valuation allowances of $101 million related to deferred tax assets. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to other taxpayers’ cross-border lease and other structured transactions (as discussed in Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”), (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases, and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represented a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI would be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of all relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances.

Discontinued Operations

PHI’s loss from discontinued operations, net of income taxes, is comprised of the following:

	2014		2013			Change
Cross-border energy lease investments	$	—	$	(327	)	$	327
Pepco Energy Services’ retail electric and natural gas supply businesses		—		5			(5	)
Loss from discontinued operations, net of income taxes	$	—	$	(322	)	$	322

During 2014, there was no activity in PHI’s discontinued operations.

In 2013, the loss from discontinued operations, net of income taxes, for PHI’s cross-border energy lease investments of $327 million was primarily related to a change in assessment regarding the tax benefits related to the cross-border energy lease investments consisting of a $373 million non-cash pre-tax charge ($313 million after-tax) to reduce the carrying value of the investments and a $16 million non-cash after-tax charge to reflect the anticipated additional interest expense related to the change in PCI’s estimated federal and state income tax obligations as if it were a separate taxpayer. In addition, PHI recorded a loss of $3 million ($2 million after-tax) in 2013 for the termination of PHI’s interests in its remaining cross-border energy lease investments, representing the excess of the carrying value of the terminated leases over the net cash proceeds received.

In 2013, the income from discontinued operations, net of income taxes, at Pepco Energy Services of $5 million was due to the completion of the wind-down of the retail electric and natural gas supply businesses in 2013.

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

Continuing Operations

Operating Revenue

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

	2013			2012			Change
Power Delivery	$	4,472		$	4,378		$	94
Pepco Energy Services		203			256			(53	)
Corporate and Other		(9	)		(9	)		—
Total Operating Revenue	$	4,666		$	4,625		$	41

Power Delivery

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

	2013		2012		Change
Regulated T&D Electric Revenue	$	2,146	$	2,006	$	140
Default Electricity Supply Revenue		2,075		2,124		(49	)
Other Electric Revenue		60		65		(5	)
Total Electric Operating Revenue		4,281		4,195		86
Regulated Gas Revenue		165		151		14
Other Gas Revenue		26		32		(6	)
Total Gas Operating Revenue		191		183		8
Total Power Delivery Operating Revenue	$	4,472	$	4,378	$	94

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

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

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

Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates.

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

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Regulated T&D Electric

	2013		2012		Change
Regulated T&D Electric Revenue
Residential	$	781	$	722	$	59
Commercial and industrial		970		923		47
Transmission and other		395		361		34
Total Regulated T&D Electric Revenue	$	2,146	$	2,006	$	140
	2013		2012		Change
Regulated T&D Electric Sales (GWh)
Residential		17,168		17,150		18
Commercial and industrial		30,070		30,734		(664	)
Transmission and other		259		258		1
Total Regulated T&D Electric Sales		47,497		48,142		(645	)
	2013		2012		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,650		1,641		9
Commercial and industrial		200		198		2
Transmission and other		2		2		—
Total Regulated T&D Electric Customers		1,852		1,841		11

Regulated T&D Electric Revenue increased by $140 million primarily due to:

• An increase of $107 million due to distribution rate increases (Pepco in the District of Columbia effective October 2012, and in Maryland effective July 2013 and July 2012; DPL in Maryland effective July 2012 and September 2013, and in Delaware effective October 2013 and July 2012; ACE effective November 2012 and July 2013).

• An increase of $14 million in transmission revenue related to the recovery of MAPP abandonment costs, as approved by FERC (which is offset in Depreciation and Amortization).

• An increase of $14 million in transmission revenue rates effective June 1, 2012 and June 1, 2013 related to increases in transmission plant investment and operating expenses.

• An increase of $7 million in transmission revenue related to the resale by DPL of renewable energy in Delaware (which is substantially offset in Purchased Energy and Depreciation and Amortization).

• An increase of $6 million primarily due to a rate increase in the New Jersey Societal Benefit Charge effective July 2012 (which is offset in Deferred Electric Service Costs).

• An increase of $6 million in transmission revenue primarily attributable to higher capacity as a result of expanding Maryland demand side management programs (which is partially offset in Depreciation and Amortization).

• An increase of $5 million primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset in Fuel and Purchased Energy and Depreciation and Amortization).

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• An increase of $3 million due to Pepco and DPL customer growth in 2013, primarily in the residential class.

The aggregate amount of these increases was partially offset by:

• A decrease of $13 million due to lower non-weather related average residential and commercial customer usage.

• A decrease of $6 million in transmission revenue associated with the change in FERC formula rate true-ups.

• A decrease of $4 million in distribution revenue due to lower pass-through revenue (which is substantially offset by a corresponding decrease in Other Taxes) primarily the result of a decrease in utility taxes collected by Pepco on behalf of Montgomery County, Maryland.

• A decrease of $1 million in transmission revenue primarily attributable to a peak-load rate decrease effective January 2013.

Default Electricity Supply

	2013		2012		Change
Default Electricity Supply Revenue
Residential	$	1,376	$	1,467	$	(91	)
Commercial and industrial		542		542		—
Other		157		115		42
Total Default Electricity Supply Revenue	$	2,075	$	2,124	$	(49	)

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

	2013		2012		Change
Default Electricity Supply Sales (GWh)
Residential		13,743		14,245		(502	)
Commercial and industrial		5,079		5,508		(429	)
Other		55		55		—
Total Default Electricity Supply Sales		18,877		19,808		(931	)
	2013		2012		Change
Default Electricity Supply Customers (in thousands)
Residential		1,352		1,366		(14	)
Commercial and industrial		125		128		(3	)
Other		—		1		(1	)
Total Default Electricity Supply Customers		1,477		1,495		(18	)

Default Electricity Supply Revenue decreased by $49 million primarily due to:

• A decrease of $76 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

• A decrease of $22 million due to lower ACE and DPL non-weather related average customer usage.

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The aggregate amount of these decreases was partially offset by:

• An increase of $36 million in wholesale energy and capacity resale revenues primarily due to higher market prices for the resale of electricity and capacity purchased from NUGs.

• An increase of $6 million due to higher Pepco and DPL revenue from transmission enhancement credits.

• An increase of $4 million due to higher sales primarily as a result of colder weather during the 2013 fall months, as compared to 2012.

• A net increase of $2 million as a result of higher Pepco Default Electricity Supply rates, partially offset by lower DPL and ACE rates.

Regulated Gas

	2013		2012		Change
Regulated Gas Revenue
Residential	$	103	$	94	$	9
Commercial and industrial		52		47		5
Transportation and other		10		10		—
Total Regulated Gas Revenue	$	165	$	151	$	14
	2013		2012		Change
Regulated Gas Sales (million cubic feet)
Residential		7,861		6,428		1,433
Commercial and industrial		4,945		3,636		1,309
Transportation and other		6,990		6,751		239
Total Regulated Gas Sales		19,796		16,815		2,981
	2013		2012		Change
Regulated Gas Customers (in thousands)
Residential		117		115		2
Commercial and industrial		9		10		(1	)
Transportation and other		—		—		—
Total Regulated Gas Customers		126		125		1

Regulated Gas Revenue increased by $14 million primarily due to:

• An increase of $22 million due to higher sales primarily as a result of colder weather during the winter months of 2013 as compared to 2012.

• An increase of $7 million due to higher non-weather related average commercial customer usage.

• An increase of $4 million due to a revenue adjustment recorded in June 2012 for a reduction in the estimate of gas sold but not yet billed to customers (which is partially offset by an increase in Purchased Energy).

• An increase of $2 million due to a distribution rate increase effective July 2013.

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The aggregate amount of these increases was partially offset by a decrease of $22 million due to a GCR decrease effective November 2012.

Other Gas Revenue

Other Gas Revenue decreased by $6 million primarily due to lower average prices and lower volumes for off-system sales to electric generators and gas marketers.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased by $53 million primarily due to:

• A decrease of $36 million primarily in energy savings construction activities.

• A decrease of $18 million associated with the retirement of the two remaining oil-fired generation facilities in the second quarter of 2012.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2013			2012			Change
Power Delivery	$	2,070		$	2,109		$	(39	)
Pepco Energy Services		148			186			(38	)
Corporate and Other		(2	)		(2	)		—
Total	$	2,216		$	2,293		$	(77	)

Power Delivery

Power Delivery’s Fuel and Purchased Energy expense consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $39 million primarily due to:

• A decrease of $85 million primarily due to customer migration to competitive suppliers.

• A decrease of $20 million in deferred electricity expense primarily due to higher DPL Default Electricity Supply cost of service rates, which resulted in a lower rate of recovery of Default Electricity Supply costs.

• A decrease of $13 million from the settlement of financial hedges entered into as part of DPL’s hedge program for the purchase of regulated natural gas.

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

The aggregate amount of these decreases was partially offset by:

• A net increase of $45 million due to higher average electricity costs under Pepco and DPL Default Electricity Supply contracts, partially offset by lower ACE costs.

• An increase of $13 million in deferred electricity expense primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset in Regulated T&D Electric Revenue and Depreciation and Amortization).

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• An increase of $11 million in the cost of gas purchases for on-system sales as a result of higher average gas prices.

• An increase of $6 million due to higher electricity sales primarily as a result of colder weather during the 2013 fall months, as compared to 2012.

• An increase of $4 million in the costs associated with purchasing Renewable Energy Credits in Delaware (which is offset by a corresponding increase in Regulated T&D Electric Revenue).

• An increase of $4 million in the cost of gas purchases for on-system sales as a result of an adjustment recorded in June 2012 for a reduction in the estimate of gas sold but not yet billed to customers (which is offset by an increase in Regulated Gas Revenue).

• An increase of $2 million in the costs associated with purchases under wind power purchase agreements in Delaware (which is offset by a corresponding increase in Regulated T&D Electric Revenue).

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased by $38 million primarily due to:

• A decrease of $30 million primarily due to lower energy savings construction activity.

• A decrease of $7 million due to lower purchases of capacity and lower fuel usage, both attributable to the retirement of the remaining oil-fired generation facilities in the second quarter of 2012.

Other Operation and Maintenance

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

	2013			2012			Change
Power Delivery	$	871		$	901		$	(30	)
Pepco Energy Services		42			58			(16	)
Corporate and Other		(62	)		(61	)		(1	)
Total	$	851		$	898		$	(47	)

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Power Delivery

Other Operation and Maintenance expense for Power Delivery decreased by $30 million primarily due to:

• A decrease of $16 million in storm restoration costs.

• A decrease of $15 million associated with lower maintenance costs.

• A decrease of $9 million in customer service costs.

• A decrease of $1 million primarily due to 2012 total incremental storm restoration costs for major storm events as described in the following table:

	2013		2012			Change
Regulatory asset established for future recovery of January 2011 winter storm costs	$	—	$	(9	)	$	9
Costs associated with derecho storm (June 2012)		—		38			(38	)
Regulatory assets established for future recovery of derecho storm costs		—		(34	)		34
Costs associated with Hurricane Sandy (October 2012)		—		28			(28	)
Regulatory assets established for future recovery of Hurricane Sandy costs		—		(22	)		22
Total incremental major storm restoration costs	$	—	$	1		$	(1	)

• In January 2011, Pepco incurred incremental storm restoration costs of $10 million associated with a severe winter storm, all of which were expensed in 2011. In July 2012, the MPSC issued an order allowing for the deferral and recovery of $9 million of such costs over a five-year period.

• During 2012, Pepco, DPL and ACE incurred incremental storm restoration costs of $38 million associated with the June 2012 derecho which resulted in widespread damage to the electric distribution system in each of their service territories. PHI’s utility subsidiaries deferred $34 million of these costs as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland and New Jersey. The MPSC approved the recovery of these costs in Maryland for both Pepco and DPL in its July 2013 and August 2013 rate orders, respectively, over a five-year period. ACE’s stipulation of settlement approved by the NJBPU in June 2013 provides for recovery of these costs in New Jersey over a three-year period. The remaining costs of $4 million relate to repair work completed in Delaware and the District of Columbia which are not deferrable in those jurisdictions.

• In the fourth quarter of 2012, Pepco, DPL and ACE incurred incremental storm restoration costs of $28 million associated with Hurricane Sandy which resulted in widespread damage to the electric distribution system in each of their service territories. PHI’s utility subsidiaries deferred $22 million of these costs as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland and New Jersey. The MPSC approved the recovery of these costs in Maryland for both Pepco and DPL in its July 2013 and August 2013 rate orders, respectively, over a five-year period. ACE’s stipulation of settlement approved by the NJBPU in June 2013 provides for recovery of these costs in New Jersey over a three-year period. The remaining costs of $6 million relate to repair work completed in Delaware and the District of Columbia which are not deferrable in those jurisdictions.

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The aggregate amount of these decreases was partially offset by:

• An increase of $6 million resulting from a 2012 deferred cost adjustment associated with DPL Default Electricity Supply. The deferred cost adjustments were primarily due to the under-recognition of allowed returns on net uncollectible expense and regulatory taxes.

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

• An increase of $3 million in environmental remediation costs.

Pepco Energy Services

Other Operation and Maintenance expense for Pepco Energy Services decreased by $16 million primarily due to:

• A decrease of $5 million in personnel costs in its energy savings business primarily due to a reduction in the number of employees in the second half of 2012.

• A decrease of $4 million in contractual costs associated with the retirement of the two remaining oil-fired generation facilities in the second quarter of 2012.

• A decrease of $3 million in bid and proposal costs in its energy savings business.

• A decrease of $1 million associated with an accrual for an energy savings guarantee shortfall in 2012.

• A decrease of $1 million in operating, repairs and maintenance expenses at its combined heat and power thermal operations in Atlantic City.

Depreciation and Amortization

Depreciation and Amortization expense increased by $19 million to $473 million in 2013 from $454 million in 2012 primarily due to:

• An increase of $14 million in amortization of regulatory assets primarily related to recoverable AMI costs, major storm costs and rate case costs.

• An increase of $14 million in amortization of MAPP abandonment costs (which is offset in T&D Electric Revenue).

• An increase of $6 million in amortization due to the expiration in August 2013 of the excess depreciation reserve regulatory liability of ACE.

The aggregate amount of these increases was partially offset by:

• A decrease of $8 million due to the deactivation of Pepco Energy Services’ oil-fired generating facilities in the second quarter of 2012 and a reduction in the Benning Road asset retirement obligation in 2013 resulting from the decision to pursue the demolition of the Benning Road oil-fired generating facility.

• A decrease of $7 million in the Delaware Renewable Energy Portfolio Standards deferral (which is substantially offset by a corresponding increase in Fuel and Purchased Energy).

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Power Delivery depreciation reflected no change from 2012 due to an increase from higher plant investment offset by lower depreciation rates in Pepco and DPL, approved by the MPSC effective July 20, 2012.

Other Taxes

Other Taxes decreased by $4 million to $428 million in 2013 from $432 million in 2012. The decrease was primarily due to lower sales that resulted in a decrease in utility taxes that are collected and passed through by Power Delivery (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).

Deferred Electric Service Costs

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

Deferred Electric Service Costs increased by $31 million to an expense of $26 million in 2013 as compared to an expense reduction of $5 million in 2012 primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply and New Jersey Societal Benefit Program revenue rates and lower electricity supply costs.

Impairment Losses

Impairment losses decreased by $8 million to $4 million in 2013 from $12 million in 2012. The decrease was primarily due to 2012 impairment losses of $12 million ($7 million after-tax) at Pepco Energy Services associated with the combustion turbines at Buzzard Point and certain landfill gas-fired electric generation facilities, partially offset by a 2013 impairment loss of $4 million ($3 million after-tax) associated with a landfill gas-fired electric generation facility.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $19 million to a net expense of $239 million in 2013 from a net expense of $220 million in 2012. The increase reflects a $16 million increase in interest expense primarily associated with higher long-term debt and $3 million associated with lower income related to the allowance for funds used during construction (AFUDC) that is applied to capital projects.

Income Tax Expense

PHI’s income tax expense increased by $216 million to $319 million in 2013 from $103 million in 2012.

PHI’s consolidated effective income tax rates for the years ended December 31, 2013 and 2012 were 74.4% and 32.1%, respectively.

The increase in the effective tax rate for the year ended December 31, 2013 occurred as a result of recording $56 million of changes in estimates and interest related to uncertain and effectively settled tax positions in the first quarter of 2013. In addition, the increase in the effective tax rate resulted from the establishment of valuation allowances of $101 million in the first quarter of 2013 against certain deferred tax assets in PCI, which is now included in Corporate and Other. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax

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assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to both Consolidated Edison’s cross-border lease transaction (as discussed in Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI) and another taxpayer’s structured transactions, (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases, and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represented a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI would be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of the relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances.

The effective income tax rate for the year ended December 31, 2012 includes income tax benefits of $8 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.

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.

Discontinued Operations

PHI’s (loss) income from discontinued operations, net of income taxes, is comprised of the following:

	2013			2012		Change
Cross-border energy lease investments	$	(327	)	$	41	$	(368	)
Pepco Energy Services’ retail electric and natural gas supply businesses		5			26		(21	)
(Loss) income from discontinued operations, net of income taxes	$	(322	)	$	67	$	(389	)

For the years ended December 31, 2013 and 2012, (loss) income from discontinued operations, net of income taxes, was a loss of $322 million and income of $67 million, respectively. The decrease of $389 million is comprised of a decrease of $368 million related to PHI’s cross-border lease investments and a decrease of $21 million related to the retail electric and natural gas supply businesses at Pepco Energy Services.

The decrease in (loss) income from discontinued operations, net of income taxes, for PHI’s cross-border energy lease investments is primarily due to after-tax non-cash charges of $323 million recorded in the first quarter of 2013 and $6 million in the second quarter of 2013, each related to a change in assessment regarding the tax benefits related to the cross-border energy lease investments and consisting of a $373 million pre-tax non-cash charge ($313 million after-tax) to reduce the carrying value of the investments and a $16 million after-tax non-cash charge to reflect the anticipated additional interest expense related to the change in PCI’s estimated federal and state income tax obligations as if it were a separate taxpayer. The (loss) income from discontinued operations, net of income taxes, was reduced further by lower cross-border energy lease investment earnings as a result of terminating the cross-border lease investments in 2013, the loss recorded on the early termination of the remaining cross-border energy lease investments during 2013, and gains recorded on the early termination of certain leases within the cross-border energy lease portfolio in the third quarter of 2012.

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The decrease in (loss) income from discontinued operations, net of income taxes, at Pepco Energy Services is due to a reduction in sales volume associated with the wind-down of the retail electric and natural gas supply businesses, a reduction in mark-to-market gains, and costs incurred to accelerate the wind-down of the retail electric supply business.

Capital Resources and Liquidity

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

Working Capital

At December 31, 2014, PHI’s current assets on a consolidated basis totaled $1.1 billion and its consolidated current liabilities totaled $2.1 billion, resulting in a working capital deficit of $981 million. PHI expects the working capital deficit at December 31, 2014 to be funded during 2015 in part through cash flows from operations, from the issuance of long-term debt and the sale of preferred stock. At December 31, 2013, PHI’s current assets on a consolidated basis totaled $1.4 billion and its consolidated current liabilities totaled $2.3 billion, for a working capital deficit of $915 million. The increase of $66 million in the working capital deficit from December 31, 2013 to December 31, 2014 was primarily due to an increase in short-term debt, an increase in other current liabilities and a decrease in accounts receivable, partially offset by lower net current income tax liabilities associated with the implementation of a new accounting standard, which required certain non-current deferred income tax assets to be netted against current income tax liabilities.

At December 31, 2014, PHI’s consolidated cash and cash equivalents totaled $14 million, which consisted of cash and uncollected funds but excluded current Restricted cash equivalents (cash that is available to be used only for designated purposes) that totaled $25 million. At December 31, 2013, PHI’s consolidated cash and cash equivalents totaled $23 million, which consisted of cash and uncollected funds but excluded current Restricted cash equivalents that totaled $13 million.

Detail of PHI’s short-term debt balance and current portion of long-term debt and project funding balance is as follows:

	As of December 31, 2014
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PCI		PHI Consolidated
	(millions of dollars)
Variable Rate Demand Bonds	$	—	$	—	$	105	$	—	$	—	$	—	$	—	$	105
Commercial Paper		287		104		106		127		—		—		—		624
Total Short-Term Debt	$	287	$	104	$	211	$	127	$	—	$	—	$	—	$	729
Current Portion of Long-Term Debt and Project Funding	$	250	$	12	$	100	$	15	$	44	$	10	$	—	$	431

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	As of December 31, 2013
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PCI		PHI Consolidated
	(millions of dollars)
Variable Rate Demand Bonds	$	—	$	—	$	105	$	18	$	—	$	—	$	—	$	123
Commercial Paper		24		151		147		120		—		—		—		442
Total Short-Term Debt	$	24	$	151	$	252	$	138	$	—	$	—	$	—	$	565
Current Portion of Long-Term Debt and Project Funding	$	—	$	175	$	100	$	107	$	41	$	12	$	11	$	446

Commercial Paper

PHI, Pepco, DPL and ACE maintain commercial paper programs to address short-term liquidity needs. As of December 31, 2014, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $350 million, respectively, subject to available borrowing capacity under the unsecured syndicated credit facility described below.

The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2014 was 0.57%, 0.28%, 0.26% and 0.27%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2014 was six, six, five and five days, respectively.

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. The termination date of this credit facility is currently August 1, 2018.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

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

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Credit Facility Amendment

On May 20, 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.

ACE Term Loan Agreement

On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE borrowed $100 million at a rate of interest equal to the prevailing Eurodollar rate, which was determined by reference to the London Interbank Offered Rate with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. On August 21, 2014, ACE repaid the term loan in full.

Sale of Receivables

During 2014, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project pursuant to a Task Order entered into under a General Services Administration area-wide agreement. The purchase price received by Pepco was $12 million. The energy savings project, which is being performed by Pepco Energy Services, was completed in 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project, the buyer will be entitled to receive the contract payments under the Task Order payable by the customer over approximately 9 years. At December 31, 2014, Pepco included the $12 million received in the Current portion of long-term debt and project funding.

On October 24, 2013, Pepco Energy Services, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a Task Order. The purchase price received by Pepco Energy Services was $7 million. Pursuant to the purchase agreement, following acceptance of the energy savings project, the buyer will be entitled to receive the contract payments under the Task Order payable by the customer over approximately 23 years. At December 31, 2014, Pepco Energy Services included the $7 million received in the Current portion of long-term debt and project funding.

Cash and Credit Facility Available as of December 31, 2014

	Consolidated PHI		PHI Parent		Utility Subsidiaries
	(millions of dollars)
Credit Facility (Total Capacity)	$	1,500	$	750	$	750
Less: Letters of Credit issued		1		1		—
Commercial Paper outstanding		624		287		337
Remaining Credit Facility Available		875		462		413
Cash Invested in Money Market Funds (a)		—		—		—
Total Cash and Credit Facility Available	$	875	$	462	$	413

(a) Cash and cash equivalents reported on the PHI consolidated balance sheet totaling $14 million did not include cash invested in money market funds.

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PHI’s Cross-Border Energy Lease Investments

PHI has an ongoing dispute with the IRS regarding the appropriateness of certain significant income tax benefits claimed by PHI related to its cross-border energy lease investments beginning with its 2001 federal income tax return. In the first quarter of 2013, PHI estimated that, in the event the IRS were to be fully successful in its challenge to PHI’s tax position on the cross-border energy leases, PHI would have been obligated to pay $192 million in additional federal taxes and $50 million of interest on the additional federal taxes, totaling $242 million as of March 31, 2013. The estimate of additional federal taxes due includes PHI’s estimate of the expected resolution of other uncertain and effectively settled tax positions unrelated to the leases, the carrying back or carrying forward of any existing net operating losses, and the application of certain amounts 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 a $242 million advanced payment to the IRS for the estimated additional taxes and related interest in the first quarter of 2013. This advanced payment was funded from then currently available sources of liquidity and short-term borrowings. During 2013, PHI terminated all of its interests in its cross-border energy 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. A portion of the net cash proceeds from the terminated leases was used to repay borrowings utilized to fund the advanced payment discussed above.

Pension and Other Postretirement Benefit Plans

PHI sponsors a non-contributory, defined benefit pension plan (the PHI Retirement Plan) that covers substantially all employees of Pepco, DPL and ACE and certain employees of other PHI subsidiaries. PHI also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the target liability as defined under the Pension Protection Act of 2006, as modified by subsequent legislation.

Under the Pension Protection Act, if a plan incurs a funding shortfall in the preceding plan year, there can be minimum quarterly contributions required in the current and following plan years. In 2015, PHI expects to make no discretionary tax-deductible contributions to the PHI Retirement Plan. During 2014, PHI, Pepco, DPL and ACE did not make any discretionary tax-deductible contributions to the PHI Retirement Plan. During 2013, PHI, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan of $80 million, $10 million and $30 million, respectively. PHI satisfied the minimum required contribution rules under the Pension Protection Act in 2014, 2013 and 2012. For additional discussion of PHI’s Pension and Other Postretirement Benefits, see Note (9), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI.

PHI 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 health care coverage; however, they will be able to purchase coverage at full cost through PHI.

In 2014 and 2013, Pepco contributed $1 million and $6 million, respectively, DPL contributed zero and $3 million, respectively, and ACE contributed $3 million and $6 million, respectively, to the other postretirement benefit plan. In 2014 and 2013, contributions of zero and $7 million, respectively, were made by other PHI subsidiaries.

Based on the results of the 2014 actuarial valuation, PHI’s net periodic pension and OPEB costs were approximately $58 million in 2014 versus $94 million in 2013. The current estimate of benefit cost for 2015 is $97 million. The increase in costs is primarily due to the adoption of new mortality tables, which generally lengthen the estimated time over which benefits would be paid, and a decrease in the discount

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rate. For additional discussion, see Note (9), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and OPEB costs. Approximately 36% of net periodic pension and OPEB costs, excluding the nonqualified retirement plan costs, were capitalized in 2014. PHI estimates that its net periodic pension and OPEB expense will be approximately $66 million in 2015, as compared to $34 million in 2014 and $57 million in 2013.

Other Postretirement Benefit Plan Amendments

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree health care and retiree life insurance benefits, and were effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its accumulated postretirement benefit obligation as of July 1, 2013. The remeasurement resulted in a $193 million reduction of the accumulated postretirement benefit obligation, which included recording a prior service credit of $124 million, which will be amortized over approximately ten years, and a $69 million reduction from a change in the discount rate from 4.10% as of December 31, 2012 to 4.95% as of July 1, 2013.

Cash Flow Activity

PHI’s cash flows during 2014, 2013 and 2012 are summarized below:

	Cash Source (Use)
	2014			2013			2012
	(millions of dollars)
Operating Activities	$	854		$	497		$	592
Investing Activities		(1,226	)		(411	)		(969	)
Financing Activities		363			(88	)		293
Net decrease in cash and cash equivalents	$	(9	)	$	(2	)	$	(84	)

Operating Activities

Cash flows from operating activities during 2014, 2013 and 2012 are summarized below:

	Cash Source (Use)
	2014			2013			2012
	(millions of dollars)
Net income from continuing operations	$	242		$	110		$	218
Non-cash adjustments to net income		625			465			451
Pension contributions		—			(120	)		(200	)
Advanced payment made to taxing authority		—			(242	)		—
Changes in cash collateral related to derivative activities		(9	)		31			88
Changes in other assets and liabilities		(4	)		206			60
Changes in net current assets held for disposition or sale		—			47			(25	)
Net cash from operating activities	$	854		$	497		$	592

Net cash from operating activities increased $357 million for the year ended December 31, 2014, compared to the same period in 2013. The increase was primarily due to an increase in net income of $132 million, a decrease in pension contributions of $120 million and a $242 million advanced payment to the IRS for estimated additional taxes and related interest made in 2013, partially offset by a $47 million reduction in net current assets held for disposition or sale associated with the termination of all cross-border energy lease investments and the wind-down of Pepco Energy Services’ retail electric and natural gas supply businesses.

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Net cash from operating activities decreased $95 million for the year ended December 31, 2013, compared to the same period in 2012. The decrease was primarily due to a decrease in net income of $108 million and a $242 million advanced payment to the IRS for estimated additional taxes and related interest, partially offset by an $80 million decrease in pension contributions and a $72 million reduction in net current assets held for disposition or sale associated with the termination of all cross-border energy lease investments and the wind-down of Pepco Energy Services’ retail electric and natural gas supply businesses.

Investing Activities

Cash flows used by investing activities during 2014, 2013 and 2012 are summarized below:

	Cash (Use) Source
	2014			2013			2012
	(millions of dollars)
Investment in property, plant and equipment	$	(1,223	)	$	(1,310	)	$	(1,216	)
DOE capital reimbursement awards received		4			22			40
Proceeds from sales of land		9			—			—
Changes in restricted cash equivalents		(12	)		1			(1	)
Net other investing activities		(4	)		3			6
Proceeds from discontinued operations, early termination of finance leases held in trust		—			873			202
Net cash used by investing activities	$	(1,226	)	$	(411	)	$	(969	)

Net cash used by investing activities increased $815 million for the year ended December 31, 2014, compared to the same period in 2013. The increase was primarily due to $873 million of proceeds from discontinued operations related to the termination of all cross-border energy lease investments received in 2013.

Net cash used by investing activities decreased $558 million for the year ended December 31, 2013, compared to the same period in 2012. The decrease was primarily due to proceeds from the termination of all cross-border energy lease investments.

Financing Activities

Cash flows from financing activities during 2014, 2013 and 2012 are summarized below:

	Cash (Use) Source
	2014			2013			2012
	(millions of dollars)
Dividends paid on common stock	$	(272	)	$	(270	)	$	(248	)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan (DRP) and employee-related compensation (a)		34			50			51
Issuances of common stock		—			324			—
Issuance of Series A preferred stock		126			—			—
Issuances of long-term debt		766			800			450
Reacquisitions of long-term debt		(334	)		(558	)		(176	)
Issuances (repayments) of short-term debt, net		164			(200	)		33
Issuances of term loans		—			250			200
Repayments of term loans		(100	)		(450	)		—
Cost of issuances		(10	)		(23	)		(9	)
Net other financing activities		(11	)		(11	)		(8	)
Net cash from (used by) financing activities	$	363		$	(88	)	$	293

(a) Prior to October 1, 2013, the DRP was named the Shareholder Dividend Reinvestment Plan.

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Net cash from financing activities increased $451 million for the year ended December 31, 2014, compared to the same period in 2013. The increase was primarily due to a net increase of $190 million in long-term debt, a net decrease of $100 million in term loans, an increase of $364 million of short-term debt issuances, and an issuance of preferred stock of $126 million, partially offset by issuances of common stock of $324 million in 2013 primarily due to the settlement of an equity forward transaction. For additional information about the equity forward transaction, please refer to Note (12), “Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock,” to the consolidated financial statements of PHI.

Net cash from financing activities decreased $381 million for the year ended December 31, 2013, compared to the same period in 2012. The decrease was primarily due to a net decrease of $400 million in term loans and an increase of $233 million in short-term debt repayments, partially offset by issuances of common stock of $324 million primarily due to the settlement in 2013 of the equity forward transaction.

Common Stock Dividends

Common stock dividend payments were $272 million in 2014, $270 million in 2013, and $248 million in 2012. The increase in common stock dividends paid in 2014 and 2013 was the result of additional shares outstanding, primarily shares issued upon settlement of the equity forward transaction in February 2013 and under the DRP.

Changes in Outstanding Common Stock

PHI issued approximately 1 million shares of common stock in each of 2014, 2013 and 2012 under PHI’s long-term incentive plans.

Under the DRP, PHI issued 1.1 million shares of common stock in 2014, 1.6 million shares of common stock in 2013, and 1.7 million shares of common stock in 2012.

In February 2013, PHI issued 17.9 million shares of common stock pursuant to the settlement of the equity forward transaction.

Changes in Outstanding Long-Term Debt

Cash flows from issuances and reacquisitions of long-term debt in 2014, 2013 and 2012 are summarized in the tables below:

	2014		2013		2012
Issuances	(millions of dollars)
Pepco
3.05% First mortgage bonds due 2022	$	—	$	—	$	200
4.15% First mortgage bonds due 2043		—		250		—
4.95% First mortgage bonds due 2043		—		150		—
3.60% First mortgage bonds due 2024		400		—		—
Project Funding Debt		12		—		—
		412		400		200
DPL
4.00% First mortgage bonds due 2042		—		—		250
3.50% First mortgage bonds due 2023		204		300		—
		204		300		250
ACE
Variable rate term loan due 2014		—		100		—
3.375% First mortgage bonds due 2024		150		—		—
		150		100		—
	$	766	$	800	$	450

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	2014		2013		2012
Reacquisitions	(millions of dollars)
Pepco
5.375% Tax-exempt bonds due 2024 (a)	$	—	$	—	$	38
4.95% First mortgage bonds due 2013		—		200		—
4.65% First mortgage bonds due 2014		175		—		—
		175		200		38
DPL
0.75% Tax-exempt bonds due 2026 (a)		—		—		35
1.80% Tax-exempt bonds due 2025 (b)		—		—		15
2.30% Tax-exempt bonds due 2028 (b)		—		—		16
5.20% Tax-exempt bonds due 2019 (a)		—		—		31
6.40% First mortgage bonds due 2013 (a)		—		250		—
5.00% Unsecured notes due 2014		100		—		—
		100		250		97
ACE
Securitization bonds due 2012-2014		41		39		37
5.60% First mortgage bonds due 2025 (a)		—		—		4
6.625% First mortgage bonds due 2013		—		69		—
7.63% First mortgage bonds due 2014		7		—		—
		48		108		41
PCI
6.59%-6.69% Recourse Debt		11		—		—
		11		—		—
	$	334	$	558	$	176

(a) These bonds were secured by an outstanding series of collateral first mortgage bonds issued by the utility, which had maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that were identical to the terms of the tax-exempt bonds. The collateral first mortgage bonds were automatically redeemed simultaneously with the redemption of the tax-exempt bonds.

(b) Repurchased by DPL in June 2012 pursuant to a mandatory purchase obligation and then retired.

First Mortgage Bond Issuances

During 2014, Pepco issued $400 million of 3.60% first mortgage bonds due March 15, 2024. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of Pepco’s properties, except for such property excluded from the lien of the Mortgage and Deed of Trust. Pepco used a portion of the net proceeds of the offering to repay in full at maturity $175 million in aggregate principal amount of its 4.65% senior notes due April 15, 2014, plus accrued and unpaid interest.

During 2014, DPL issued $200 million of its 3.50% first mortgage bonds due November 15, 2023. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of DPL’s properties, except for such property excluded from the lien of the Mortgage and Deed of Trust. Net proceeds from the issuance of the bonds, which included a premium of $4 million, were used to repay DPL’s outstanding commercial paper and for general corporate purposes.

During 2014, ACE issued $150 million of its 3.375% first mortgage bonds due September 1, 2024. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of ACE’s properties, except for such property excluded from the lien of the Mortgage and Deed of Trust. ACE used $7.2 million of the net proceeds from the issuance of the bonds to repay in full at maturity $7.0 million in aggregate principal amount of ACE’s 7.63% secured medium term notes due August 29, 2014, plus accrued and unpaid interest thereon. ACE used the remainder of the net proceeds to repay its outstanding commercial paper, including commercial paper that ACE issued to prepay in full its $100 million term loan, and for general corporate purposes.

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During 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043 and $150 million of 4.95% first mortgage bonds due November 15, 2043. Net proceeds from the issuance of the 4.15% bonds were used to repay Pepco’s outstanding commercial paper and for general corporate purposes. The net proceeds from the 4.95% bonds were used to repay outstanding commercial paper, including commercial paper issued to repay in full at maturity $200 million of Pepco 4.95% senior notes due November 15, 2013, plus accrued but unpaid interest thereon. The senior notes were secured by a like principal amount of Pepco first mortgage bonds, which under Pepco’s Mortgage and Deed of Trust were deemed to be satisfied with the repayment of the senior notes.

During 2013, DPL issued $300 million of 3.50% first mortgage bonds due November 15, 2023. The net proceeds from the issuance of the bonds were used to repay at maturity $250 million of DPL’s 6.40% first mortgage bonds due December 1, 2013, plus accrued but unpaid interest thereon, to repay outstanding commercial paper and for general corporate purposes.

During 2012, Pepco issued $200 million of 3.05% first mortgage bonds due April 1, 2022. Net proceeds from the issuance of the bonds 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% tax-exempt 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 bonds 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 the Delaware Economic Development Authority (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.

Tax Exempt Auction Rate and First Mortgage Bond Redemptions

During 2014, Pepco retired, at maturity, $175 million of its 4.65% senior notes. The senior notes were secured by a like principal amount of its 4.65% first mortgage bonds due April 15, 2014, which under Pepco’s mortgage and deed of trust were deemed to be satisfied when the senior notes were repaid.

During 2014, DPL retired, at maturity, $100 million of its 5.00% unsecured notes.

During 2014, ACE retired, at maturity, $7 million of its 7.63% medium term notes due August 29, 2014. The notes were secured by a like principal amount of first mortgage bonds due August 29, 2014, which under ACE’s mortgage and deed of trust were deemed to be satisfied when the notes were repaid.

During 2014, PCI retired, at maturity, $11 million of bank loans.

During 2013, Pepco retired, at maturity, $200 million of its 4.95% senior notes, which were secured by a like principal amount of Pepco’s first mortgage bonds as previously discussed above.

During 2013, DPL retired, at maturity, $250 million of its 6.40% first mortgage bonds.

During 2013, ACE retired, at maturity, $69 million of its 6.625% non-callable first mortgage bonds. ACE also funded the redemption, prior to maturity, of $4 million of outstanding weekly rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.

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During 2012, all of the $38.3 million of the outstanding 5.375% tax-exempt 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 $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.

Changes in Short-Term Debt

As of December 31, 2014, PHI had a total of $624 million of commercial paper outstanding as compared to $442 million and $637 million of commercial paper outstanding at December 31, 2013 and 2012, respectively.

Capital Requirements

Capital Expenditures

Pepco Holdings’ capital expenditures for the year ended December 31, 2014 totaled $1,223 million, a decrease of $87 million from $1,310 million in 2013. Capital expenditures in 2014 were $567 million for Pepco, $352 million for DPL, $225 million for ACE, $3 million for Pepco Energy Services and $76 million for Corporate and Other. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. Corporate and Other capital expenditures primarily consisted of hardware and software expenditures that will be allocated to Power Delivery when the assets are placed in service.

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The table below shows the projected capital expenditures for Power Delivery, Pepco Energy Services and Corporate and Other for the five-year period 2015 through 2019. PHI expects to fund these expenditures through internally generated cash and external financing.

	For the Year Ended December 31,
	2015		2016		2017		2018		2019		Total
	(millions of dollars)
Power Delivery
Distribution	$	739	$	858	$	853	$	832	$	771	$	4,053
Transmission		423		390		417		405		323		1,958
Gas Delivery		32		32		35		36		38		173
Other		97		102		91		73		60		423
Total for Power Delivery		1,291		1,382		1,396		1,346		1,192		6,607
Pepco Energy Services		6		6		5		2		2		21
Corporate and Other		6		6		6		6		6		30
Total PHI	$	1,303	$	1,394	$	1,407	$	1,354	$	1,200	$	6,658

Transmission and Distribution

The projected capital expenditures listed in the table for distribution, transmission and gas delivery are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. For a more detailed discussion of these efforts, see “General Overview – Power Delivery.” The projected capital expenditures related to the DC PLUG initiative are included as part of distribution expenditures in the table above.

DOE Capital Reimbursement Awards

In 2009, the U.S. Department of Energy (DOE) announced awards under the American Recovery and Reinvestment Act of 2009 of:

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

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

Of the total $168 million in DOE awards, $130 million was offset against smart grid-related capital expenditures of Pepco and ACE. The remaining $38 million is being used to offset incremental expenditures associated with direct load control and other Pepco and ACE programs, which have been deferred as regulatory assets. During 2014, Pepco and ACE received award payments of $3 million and $1 million, respectively. The cumulative award payments received by Pepco and ACE as of December 31, 2014, were $148 million and $19 million, respectively.

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

Dividends

Pepco Holdings’ annual dividend rate on its common stock is determined by the Board of Directors on a quarterly basis and takes into consideration, among other factors, current and possible future developments that may affect PHI’s income and cash flows. In 2014, PHI’s Board of Directors declared quarterly dividends of 27 cents per share of common stock payable on March 31, 2014, June 30, 2014, September 30, 2014 and December 31, 2014.

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On January 22, 2015, the Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2015, to shareholders of record on March 10, 2015.

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 each 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 when such dividends can be paid, 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 existing and future mortgage bonds and other long-term debt issued by the subsidiaries, and any preferred stock that may be issued by the subsidiaries in the future, (iii) any other restrictions imposed in connection with the incurrence of liabilities; and (iv) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. None of Pepco, DPL or ACE currently have shares of preferred stock outstanding. 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 $584 million and $595 million of retained earnings free of restrictions at December 31, 2014 and 2013, respectively. These amounts represent the total retained earnings balances at those dates.

Contractual Obligations and Commercial Commitments

Summary information about Pepco Holdings’ consolidated contractual obligations and commercial commitments at December 31, 2014, is as follows:

	Contractual Maturity
Contractual Obligations	Total		Less than 1 Year		2-3 Years		4-5 Years		After 5 Years
	(millions of dollars)
Variable rate demand bonds	$	105	$	105	$	—	$	—	$	—
Commercial paper		624		624		—		—		—
Long-term debt (a)		5,032		410		471		315		3,836
Long-term project funding		10		2		2		3		3
Interest payments on debt		3,578		252		459		405		2,462
Capital leases, including interest		76		15		30		31		—
Operating leases		525		45		83		68		329
Non-derivative power purchase contracts (b)		2,440		276		509		478		1,177
Total (c)	$	12,390	$	1,729	$	1,554	$	1,300	$	7,807

(a) Includes Transition Bonds issued by ACE Funding.

(b) Excludes contracts for the purchase of electricity to satisfy Default Electricity Supply load service obligations which have neither a fixed commitment amount nor a minimum purchase amount. In addition, costs are recoverable from customers.

(c) Excludes $625 million of net current and non-current liabilities related to uncertain tax positions due to uncertainty in the timing of the associated cash payments.

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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.

PHI guarantees the obligations of Pepco Energy Services under certain contracts in its energy savings performance contracting business and underground transmission and distribution construction business. At December 31, 2014, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $336 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects. These guarantees totaled $185 million at December 31, 2014.

In addition, PHI guarantees certain obligations of Pepco, DPL and ACE under surety bonds obtained by these subsidiaries, for construction projects and self-insured workers compensation matters. These guarantees totaled $53 million at December 31, 2014.

For additional discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (16), “Commitments and Contingencies – Third Party Guarantees, Indemnifications, and Off-Balance Sheet Arrangements,” to the consolidated financial statements of PHI.

Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI’s subsidiaries, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of PHI or the subsidiary are downgraded. In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade. Based on contractual provisions in effect at December 31, 2014, a downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries to below “investment grade” would increase the collateral obligation of PHI and its subsidiaries by up to $37 million. This amount is attributable primarily to energy services contracts and accounts payable to independent system operators and distribution companies. PHI believes that it and its subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.

Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the applicable arrangements. Pursuant to these margining rights, the affected PHI subsidiary may receive, or be required to post, collateral due to energy price movements. PHI believes that it and its subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.

Environmental Remediation Obligations

PHI’s accrued liabilities for environmental remediation obligations as of December 31, 2014 totaled approximately $28 million, of which approximately $4 million is expected to be incurred in 2015, for potential environmental cleanup and related costs at sites owned or formerly owned by an operating subsidiary where an operating subsidiary is a potentially responsible party or is alleged to be a third-party contributor. For further information concerning the remediation obligations associated with these sites, see Note (16), “Commitments and Contingencies – Environmental Matters,” to the consolidated financial statements of PHI. The most significant environmental remediation obligations as of December 31, 2014, are for the following items:

• Environmental investigation and remediation costs payable by Pepco with respect to the Benning Road site.

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• Amounts payable by Pepco in connection with a January 2011 mineral oil release at Pepco’s Potomac River substation in Alexandria, Virginia.

• Estimated costs for implementation of a closure plan and cap on a Pepco right-of-way that traverses the NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG) fly ash disposal site in Brandywine, Prince George’s County, Maryland. PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under a 2000 agreement covering the sale of this site, the terms of which specify that the buyer of Pepco’s generation assets assumed environmental liability for hazardous substances, including ash, which remain on or have been removed from the land on which the acquired generating stations are situated.

• Estimated costs for implementation of a closure plan for the Edge Moor landfill.

• Costs associated with investigation and resolution of potential impacts from a September 2013 mineral oil release from a Pepco underground feeder to Watts Branch.

• Amounts payable by DPL in accordance with a 2001 consent agreement reached 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 that resulted from an oil release at the Indian River power plant, which DPL sold in June 2001.

• Potential compliance remediation costs under New Jersey’s Industrial Site Recovery Act payable by PHI associated with the retained environmental exposure from the sale of the Conectiv Energy wholesale power generation business.

• Amounts payable by DPL in connection with the Wilmington Coal Gas South site located in Wilmington, Delaware, to remediate residual material from the historical operation of a manufactured gas plant.

Sources of Capital

PHI’s sources to meet its long-term funding needs, such as capital expenditures, dividends, and new investments, and its short-term funding needs, such as working capital and the temporary funding of long-term funding needs, include internally generated funds, issuances by PHI, Pepco, DPL and ACE under their commercial paper programs, securities issuances, medium- and short-term loans, and bank financing under new or existing facilities. PHI’s ability to generate funds from its operations and to access capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of PHI’s potential funding sources.

Cash Flow from Operations

Cash flow generated by regulated utility subsidiaries in Power Delivery is the primary source of PHI’s cash flow from operations. Additional cash flows are generated by the business of Pepco Energy Services and from the occasional sale of non-core assets.

Short-Term Funding Sources

Pepco Holdings 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 term loans and 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. For additional discussion of PHI’s short-term debt, see Note (10), “Debt,” to the consolidated financial statements of PHI.

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Long-Term Funding Sources

The sources of long-term funding for PHI and its subsidiaries are the issuance of debt and equity securities and borrowing under long-term credit agreements. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures and new investments, and to repay or refinance existing indebtedness.

Regulatory Restrictions on Financing Activities

The issuance of debt securities by PHI’s principal subsidiaries requires the approval of either FERC or one or more state public utility commissions. Neither FERC approval nor state public utility commission approval is required as a condition to the issuance of securities by PHI.

State Financing Authority

Pepco’s long-term financing activities (including the issuance of securities and the incurrence of long-term debt) are subject to authorization by the DCPSC and MPSC. DPL’s long-term financing activities are subject to authorization by the MPSC and the DPSC. ACE’s long-term and short-term (consisting of debt instruments with a maturity of one year or less) financing activities are subject to authorization by the NJBPU. Each utility, through periodic filings with the state public service commission(s) having jurisdiction over its financing activities, has maintained standing authority sufficient to cover its projected financing needs over a multi-year period.

FERC Financing Authority

Under the Federal Power Act (FPA), FERC has jurisdiction over the issuance of long-term and short-term securities of public utilities, but only if the issuance is not regulated by the state public utility commission in which the public utility is organized and operating. Under these provisions, FERC has jurisdiction over the issuance of short-term debt by Pepco and DPL. Pepco and DPL have obtained FERC authority for the issuance of short-term debt. Because Pepco Energy Services also qualifies as a public utility under the FPA and is not regulated by a state utility commission, FERC also has jurisdiction over the issuance of securities by Pepco Energy Services. Pepco Energy Services has obtained the requisite FERC financing authority in its market-based rate orders.

Money Pool

Pepco Holdings operates a system money pool under a blanket authorization adopted by FERC. The money pool is an unsecured cash management mechanism used by Pepco Holdings to manage the short-term investment and borrowing requirements of its subsidiaries that participate in the money pool. Pepco Holdings may invest in but not borrow from the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by Pepco Holdings. Eligible subsidiaries with cash requirements may borrow from the money pool. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on Pepco Holdings’ short-term borrowing rate. Pepco Holdings deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require Pepco Holdings to borrow funds for deposit from external sources.

Regulatory and Other Matters

Rate Proceedings

Distribution

The rates that each of Pepco, DPL and ACE is permitted to charge for the retail distribution of electricity and natural gas to its various classes of customers are based on the principle that the utility is entitled to generate an amount of revenue sufficient to recover the cost of providing the service, including a reasonable rate of return on its invested capital. These “base rates” are intended to cover all of each utility’s reasonable and prudent expenses of constructing, operating and maintaining its distribution facilities (other than costs covered by specific cost-recovery surcharges).

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A change in base rates in a jurisdiction requires the approval of the public service commission. In the rate application submitted to the public service commission, the utility specifies an increase in its “revenue requirement,” which is the additional revenue that the utility is seeking authorization to earn. The “revenue requirement” consists of (i) the allowable expenses incurred by the utility, including operation and maintenance expenses, taxes and depreciation, and (ii) the utility’s cost of capital. The compensation of the utility for its cost of capital takes the form of an overall “rate of return” allowed by the public service commission on the utility’s distribution “rate base” to compensate the utility’s investors for their debt and equity investments in the company. The rate base is the aggregate value of the investment in property used by the utility in providing electricity and natural gas distribution services and generally consists of plant in service net of accumulated depreciation and accumulated deferred taxes, plus cash working capital, material and operating supplies and, depending on the jurisdiction, construction work in progress. Over time, the rate base is increased by utility property additions and reduced by depreciation and property retirements and write-offs.

In addition to its base rates, some of the costs of providing distribution service are recovered through the operation of surcharges. Examples of costs recovered by PHI’s utility subsidiaries through surcharges, which vary depending on the jurisdiction, include: a surcharge to reimburse the utility for the cost of purchasing electricity from NUGs (New Jersey); surcharges to reimburse the utility for costs of public interest programs for low income customers and for demand-side management programs (New Jersey, Maryland, Delaware and the District of Columbia); a surcharge to pay the Transitional Bond Charge (New Jersey); surcharges to reimburse the utility for certain environmental costs (Delaware and Maryland); and surcharges related to the BSA (Maryland and the District of Columbia). Each utility subsidiary regularly reviews its distribution rates in each jurisdiction of its service territory, and files applications to adjust its rates as necessary in an effort to ensure that its revenues are sufficient to cover its operating expenses and its cost of capital. The timing of future rate filings and the change in the distribution rate requested will depend on a number of factors, including changes in revenues and expenses and the incurrence or the planned incurrence of capital expenditures.

As further described in the “– General Overview – Agreement and Plan of Merger with Exelon Corporation,” PHI has entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings. In addition, the regulatory commissions may seek to suspend or delay one or more of the ongoing proceedings as a result of the Merger Agreement.

In general, a request for new distribution rates is made on the basis of “test year” balances for rate base allowable operating expenses and a requested rate of return. The test year amounts used in the filing may be historical or partially projected. The public service commission may, however, select a different test period than that proposed by the applicable utility. Although the approved tariff rates are intended to be forward-looking, and therefore provide for the recovery of some future changes in rate base and operating costs, they typically do not reflect all of the changes in costs for the period in which the new rates are in effect. See “– General Overview – Power Delivery Initiatives and Activities – Mitigation of Regulatory Lag.”

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The following table shows, for each of the PHI utility subsidiaries, the authorized return on equity as determined in the most recently concluded base rate proceeding and the effective date of the authorized return:

	Authorized Return on Equity	Rate Effective Date
Pepco:
District of Columbia (electricity)	9.40%	April 2014
Maryland (electricity)	9.62%	July 2014
DPL:
Delaware (electricity)	9.70%	May 2014 (a)
Maryland (electricity)	9.81% (b)	September 2013
Delaware (natural gas)	9.75% (c)	November 2013
ACE:
New Jersey (electricity)	9.75%	September 2014

(a) Beginning in September 2014, DPL provided credits or refunds to any customer whose rates were increased in October 2013 in excess of the increase approved by the DPSC in April 2014.

(b) ROE has not been determined by any proceeding and is specified only for the purposes of calculating the AFUDC and regulatory asset carrying costs.

(c) ROE has not been determined by any proceeding and is specified only for reporting purposes and for calculating the AFUDC, construction work in progress, regulatory asset carrying costs and other accounting metrics.

Transmission

The rates Pepco, DPL and ACE are permitted to charge for the transmission of electricity are regulated by FERC and are based on each utility’s transmission rate base, transmission operating expenses and an overall rate of return that is approved by FERC. For each utility subsidiary, FERC has approved a formula for the calculation of the utility transmission rate, which is referred to as a “formula rate.” The formula rates include both fixed and variable elements. Certain of the fixed elements, such as the return on equity and depreciation rates, can be changed only in a FERC transmission rate proceeding. The variable elements of the formula, including the utility’s rate base and operating expenses, are updated annually, effective June 1 of each year, with data from the utility’s most recent annual FERC Form 1 filing. See Note (7), “Regulatory Matters – Rate Proceedings – Federal Energy Regulatory Commission,” to the consolidated financial statements of PHI, regarding certain challenges to DPL’s 2011, 2012 and 2013 annual formula rate updates.

In addition to its formula rate, each utility’s return on equity is supplemented by incentive rates, sometimes referred to as “adders,” and other incentives, which are authorized by FERC to promote capital investment in transmission infrastructure. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In addition, ROE adders are in effect for each of Pepco, DPL and ACE relating to specific transmission upgrades and improvements. As members of PJM, the transmission rates of Pepco, DPL and ACE are set out in PJM’s Open Access Transmission Tariff. See Note (7), “Regulatory Matters – Rate Proceedings – Federal Energy Regulatory Commission,” to the consolidated financial statements of PHI, regarding certain challenges to Pepco’s, DPL’s and ACE’s base ROE.

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For a discussion of pending state public utility commission and FERC transmission rate and other rate proceedings, see Note (7), “Regulatory Matters – Rate Proceedings,” to the consolidated financial statements of PHI.

Legal Proceedings and Regulatory Matters

For a discussion of legal proceedings, see Note (16), “Commitments and Contingencies,” to the consolidated financial statements of PHI, and for a discussion of regulatory matters, see Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI.

Critical Accounting Policies

General

PHI has identified the following critical accounting policies that result in having to make certain estimates that, as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and estimates involved, could result in material changes in its financial condition or results of operations under different conditions or using different assumptions. PHI has discussed the development, selection and disclosure of each of these policies with the Audit Committee of the Board of Directors.

Goodwill Impairment Evaluation

Substantially all of PHI’s goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to the Power Delivery reporting unit for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350). PHI has identified Power Delivery as a single reporting unit because its components have similar economic characteristics, similar products and services, similar distribution methods and support processes, and operate in a similar regulatory environment.

PHI 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 (that is, a greater than 50% chance) reduce the estimated 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: an adverse change in business conditions; a protracted decline in stock price causing market capitalization to fall significantly below book value; an adverse regulatory action; impairment of long-lived assets in the reporting unit; or a change in identified reporting units.

In evaluating goodwill for impairment, PHI first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. For reporting units in which PHI concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and PHI is not required to perform the two-step goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, including the price per share offered by potential acquirers of PHI during 2014, overall financial performance, lack of significant changes in any key inputs to the prior year impairment test, including the discount rate and forecasted cash flows, and other relevant events and factors affecting the reporting unit.

For reporting units in which PHI concludes that it is more likely than not that the fair value is less than its carrying value, PHI performs the first step of the goodwill impairment test. The first step of the goodwill impairment test compares the estimated fair value of the reporting unit with its carrying amount, including goodwill. PHI uses its best judgment to make reasonable projections of future cash flows and selection of a discount rate for the associated risk with those cash flows when estimating the reporting unit’s fair value. These judgments are inherently uncertain, and actual results could vary from those used in PHI’s estimates. The impact of such variations could significantly alter the results of a goodwill impairment test, which could materially impact the estimated fair value of Power Delivery and potentially the amount of any impairment recorded in the financial statements.

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PHI’s November 1, 2014 annual impairment test indicated that its goodwill was not impaired. See Note (6), “Goodwill,” to the consolidated financial statements of PHI.

In order to estimate the fair value of the Power Delivery reporting unit, PHI prepares an analysis of traditional valuation techniques: an income approach and a market approach. The income approach estimates fair value based on a discounted future cash flow analysis 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 reporting unit. PHI determines the estimated WACC by considering appropriate market-based information for the cost of equity and cost of debt as of the measurement date. The market approach estimates fair value based on a multiple of earnings before interest, taxes, depreciation and amortization (EBITDA) that PHI believes is consistent with EBITDA multiples for comparable utilities. PHI has consistently used this valuation technique to estimate the fair value of Power Delivery.

The estimation of fair value is dependent on a number of factors 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 impact the results of impairment testing. Assumptions used were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures, and current market-based information. A hypothetical 10 percent decrease in estimated fair value of the Power Delivery reporting unit at November 1, 2014 would not have resulted in the Power Delivery reporting unit failing the first step of the impairment test, as defined in the guidance, as the estimated fair value of the reporting unit would have been above its carrying value. 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, change in forecasted revenues, higher operating and maintenance capital expenditure requirements, a significant increase in the weighted average cost of capital, and other factors.

PHI believes that the estimates involved in its goodwill impairment evaluation process represent “Critical Accounting Estimates” because they are subjective and susceptible to change from period to period as PHI makes assumptions and judgments, and the impact of a change in such assumptions and estimates could be material to financial results.

Long-Lived Assets Impairment Evaluation

PHI believes that the estimates involved in its long-lived asset impairment evaluation process represent “Critical Accounting Estimates” because (i) they are highly susceptible to change from period to period because PHI is required to make assumptions and judgments about when events indicate the carrying value may not be recoverable and how to estimate undiscounted and discounted future cash flows and fair values, which are inherently uncertain, (ii) actual results could vary from those used in PHI’s estimates and the impact of such variations could be material, and (iii) the impact that recognizing an impairment would have on PHI’s assets as well as the net loss related to an impairment charge could be material. The primary assets subject to a long-lived asset impairment evaluation are property, plant, and equipment.

The FASB guidance on the accounting for the impairment or disposal of long-lived assets (ASC 360), requires that certain long-lived assets must be tested for recoverability whenever events or circumstances indicate that the carrying amount may not be recoverable, such as (i) a significant decrease in the market price of a long-lived asset or asset group, (ii) a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition, (iii) a significant adverse change in legal factors or in the business climate, including an adverse action or assessment by a regulator, (iv) an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset or asset group, (v) a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates

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continuing losses associated with the use of a long-lived asset or asset group, and (vi) a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

An impairment loss may only be recognized if the carrying amount of an asset is not recoverable and the carrying amount exceeds its estimated fair value. The asset is deemed not to be recoverable when its carrying amount exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. PHI uses reasonable estimates in making these evaluations of an asset’s future cash flows and considers various factors, including forward price curves for energy, related fuel costs, legislative initiatives, operating costs, and historical cash flows.

For the year ended December 31, 2014, PHI recorded impairment charges associated with certain long-lived assets at Pepco Energy Services. See Note (8), “Property, Plant and Equipment,” to the consolidated financial statements of PHI.

Pension and Other Postretirement Benefit Plans

PHI believes that the estimates involved in reporting the costs of providing pension and OPEB benefits represent Critical Accounting Estimates because (i) they are based on an actuarial calculation that includes a number of assumptions which are subjective in nature, (ii) they are dependent on numerous factors resulting from actual plan experience and assumptions of future experience, and (iii) changes in assumptions could impact PHI’s expected future cash funding requirements for the benefit plans and would have an impact on the benefit obligations, which affect the reported amount of net periodic pension and OPEB cost on the consolidated income statement.

Assumptions about the future, including the discount rate applied to benefit obligations, the expected long-term rate of return on plan assets, the anticipated rate of increase in health care costs, average remaining service period and life expectancy, and participant compensation have a significant impact on net periodic pension and OPEB costs.

The discount rate for determining the pension benefit obligation was 4.20% and 5.05% as of December 31, 2014 and 2013, respectively. The discount rate for determining the postretirement benefit obligation was 4.15% and 5.00% as of December 31, 2014 and 2013, respectively. 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 and postretirement benefit plan assets used to determine net periodic pension and OPEB cost was 7.00% and 7.25%, respectively, for 2014 and 7.00% for 2013. 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 measurement date of net periodic cost, 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 the related asset class. The pension and postretirement benefit plan assets consist of equity, fixed income, real estate and private equity investments.

The average remaining service periods for participating employees of the benefit plans was approximately 11 years for both 2014 and 2013. PHI utilizes plan census data to estimate these average remaining service periods. PHI uses the IRS prescribed mortality tables to estimate the average life expectancy. The IRS prescribed tables for 2014 and 2013 were used to determine net periodic pension and OPEB cost for the same respective years. The IRS prescribed mortality tables for 2013 were used for determining the benefit obligations as of December 31, 2013. In 2014, the Society of Actuaries issued new mortality tables which PHI applied in determining its benefit obligations as of December 31, 2014.

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The following table reflects the effect on the projected benefit obligation for the pension plans and the accumulated benefit obligation for the OPEB plan, as well as the net periodic cost, if there were changes in these critical actuarial assumptions while holding all other actuarial assumptions constant:

(in millions, except percentages)	Change in Assumptions			Impact on Benefit Obligation		Projected Increase in 2014 Net Periodic Cost
Pension Plans
Discount rate		(0.25	)%	$	78	$	6
Expected return		(0.25	)%		—		5
Postretirement Benefit Plan
Discount rate		(0.25	)%		18		1
Expected return		(0.25	)%		—		1
Health care cost trend rate		1.00	%		18		2

The impact of changes in assumptions and the difference between actual and expected or estimated results on pension and postretirement benefit obligations is generally recognized over the average remaining service period of the employees who benefit under the plans rather than immediate recognition in the statement of income.

For additional discussion, see Note (9), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI.

Accounting for Regulated Activities

FASB guidance on the accounting for regulated operations (ASC 980), applies to Power Delivery and can result in the deferral of costs or revenue that would otherwise be recognized by non-regulated entities. PHI defers the recognition of costs and records regulatory assets when it is probable that those costs will be recovered in future customer rates. PHI defers the recognition of revenues and records regulatory liabilities when it is probable that it will refund payments received from customers in the future or that it will incur future costs related to the payments currently received from customers. PHI believes that the judgments involved in accounting for its regulated operations represent “Critical Accounting Estimates” because (i) PHI must interpret laws and regulatory commission orders to assess the probability of the recovery of costs in customer rates or the return of revenues to customers when determining whether those costs or revenues should be deferred, (ii) decisions made by regulatory commissions or legislative changes at a later date could vary from earlier interpretations made by PHI and the impact of such variations could be material, and (iii) the elimination of a regulatory asset because deferred costs are no longer probable of recovery in future customer rates could have a material negative impact on PHI’s assets and earnings.

PHI’s most significant judgment is whether to defer costs or revenues when there is not a current regulatory order specific to the item being considered for deferral. In those cases, PHI considers relevant historical precedents of the regulatory commissions, the results of recent rate orders, and any new information from its more current interactions with the regulatory commissions on that item. PHI regularly evaluates whether it should defer costs or revenues and reviews whether adjustments to its previous conclusions regarding its regulatory assets and liabilities are necessary based on the current regulatory and legislative environment as well as recent rate orders.

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

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Unbilled Revenue

Unbilled revenue represents an estimate of revenue earned from services rendered by PHI’s utility operations that have not yet been billed. PHI’s utility operations calculate unbilled revenue using an output-based methodology. The calculation is based on the supply of electricity or natural gas distributed to customers but not yet billed, adjusted for estimated line losses (estimates of electricity and gas expected to be lost in the process of a utility’s transmission and distribution to customers).

PHI estimates involved in its unbilled revenue process represent “Critical Accounting Estimates” because PHI is required to make assumptions and judgments about factors to the unbilled revenue calculation. Specifically, the determination of estimated line losses is inherently uncertain. Estimated line losses is defined as the estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers. A change in estimated line losses can change the output available for sale which is a factor in the unbilled revenue calculation. Certain factors can influence the estimated line losses such as weather and a change in customer mix. These factors may vary between companies due to geography and density of service territory, and the impact of changes in these factors could be material. PHI seeks to reduce the risk of an inaccurate estimate of unbilled revenue through corroboration of the estimate with historical information and other output-based observable metrics.

Accounting for Income Taxes

PHI exercises significant judgment about the outcome of income tax matters in its application of the FASB guidance on accounting for income taxes (ASC 740) and believes it represents a “Critical Accounting Estimate” because: (i) it records a current tax liability for estimated current tax expense on its federal and state tax returns; (ii) it records deferred tax assets for temporary differences between the financial statement and tax return determination of pre-tax income and the carrying amount of assets and liabilities that are more likely than not going to result in tax deductions in future years; (iii) it determines whether a valuation allowance is needed against deferred tax assets if it is more likely than not that some portion of the future tax deductions will not be realized; (iv) it records deferred tax liabilities for temporary differences between the financial statement and tax return determination of pre-tax income and the carrying amount of assets and liabilities if it is more likely than not that they are expected to result in tax payments in future years; (v) the measurement of deferred tax assets and deferred tax liabilities requires it to estimate future effective tax rates and future taxable income on its federal and state tax returns; (vi) it must consider the effect of newly enacted tax law on its estimated effective tax rate and in measuring deferred tax balances; and (vii) it asserts that tax positions in its tax returns or expected to be taken in its tax returns are more likely than not to be sustained assuming that the tax positions will be examined by taxing authorities with full knowledge of all relevant information prior to recording the related tax benefit in the financial statements.

Assumptions, judgment and the use of estimates are required in determining if the more-likely-than-not measurement threshold (that is, the cumulative result for a greater than 50% chance of being realized) has been met when developing the provision for current and deferred income taxes and the associated current and deferred tax assets and liabilities. PHI’s assumptions, judgments and estimates take into account current tax laws and regulations, interpretation of current tax laws and regulations, the impact of newly enacted tax laws and regulations, developments in case law, settlements of tax positions, and the possible outcomes of current and future investigations conducted by tax authorities. PHI has established reserves for income taxes to address potential exposures involving tax positions that could be challenged by tax authorities. Although PHI believes that these assumptions, judgments and estimates are reasonable, changes in tax laws and regulations or its interpretation of tax laws and regulations as well as the resolutions of the current and any future investigations or legal proceedings could significantly impact the financial results from applying the accounting for income taxes in the consolidated financial statements. PHI reviews its application of the more-likely-than-not measurement threshold quarterly.

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PHI also evaluates quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and prudent and feasible tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets and the amount of any associated valuation allowance. The forecast of future taxable income is dependent on a number of factors that can change over time, including growth assumptions, business conditions, returns on rate base, operating and capital expenditures, cost of capital, tax laws and regulations, the legal structure of entities and other factors, which could materially impact the realizability of deferred tax assets and the associated financial results in the consolidated financial statements.

New Accounting Standards and Pronouncements

For information concerning new accounting standards and pronouncements that have recently been adopted, or will be required to be adopted in the future, by PHI and its subsidiaries , see Note (3), “Newly Adopted Accounting Standards,” and Note (4), “Recently Issued Accounting Standards, Not Yet Adopted,” to the consolidated financial statements of PHI.

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

Potomac Electric Power Company

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

General Overview

Pepco is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply. Pepco’s service territory covers approximately 640 square miles and, as of December 31, 2014, had a population of approximately 2.3 million. As of December 31, 2014, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to District of Columbia customers.

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

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

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

Agreement and Plan of Merger with Exelon Corporation

PHI has entered into the Merger Agreement with Exelon and Merger Sub, providing for the Merger, with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. For additional information regarding the Merger, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation.”

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Utility Capital Expenditures

Pepco allocates a substantial portion of its total capital expenditures to improving the reliability of its electrical transmission and distribution systems and replacing aging infrastructure throughout its service territories. These activities include one or more of the following:

• identifying and upgrading under-performing feeder lines;

• adding new facilities to support load;

• installing distribution automation systems on both the overhead and underground network systems; and

• rejuvenating and replacing underground residential cables.

Pepco’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures within “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Requirements – Capital Expenditures.”

Smart Grid

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

District of Columbia Power Line Undergrounding Initiative

For information about the District of Columbia Power Line Undergrounding Initiative, please refer to Note (6), “Regulatory Matters – District of Columbia Power Line Undergrounding Initiative,” to the financial statements of Pepco.

Mitigation of Regulatory Lag

An important factor in the ability of Pepco to earn its authorized ROE is the willingness of the DCPSC and the MPSC to adequately address the shortfall in revenues in Pepco’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Pepco is currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than revenue growth. For a more detailed discussion of regulatory lag, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Power Delivery Initiatives and Activities – Mitigation of Regulatory Lag.”

In an effort to minimize the effects of regulatory lag, prior to the initial execution of the Merger Agreement in April 2014, Pepco had been filing electric distribution base rate cases every nine to twelve months in each of its jurisdictions, pursuing alternative ratemaking mechanisms, evaluating potential reductions in planned capital expenditures, and discussing with the regulatory community and other stakeholders the changing regulatory model economics that are causing regulatory lag.

As further described in PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation,” PHI has entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, Pepco may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings. Accordingly, with the exception of ongoing rate cases (see Note (6), “Regulatory Matters – Rate Proceedings,” to the financial statements of Pepco), Pepco’s efforts to mitigate regulatory lag have been delayed pending the closing of the Merger or the termination of the Merger Agreement.

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MAPP Settlement Agreement

For information about the MAPP settlement agreement, please refer to Note (6), “Regulatory Matters – MAPP Settlement Agreement,” to the financial statements of Pepco.

Transmission ROE Challenges

For information about the challenges to Pepco’s base ROE and the application of the formula rate process, each associated with the transmission services it provides, please refer to Note (6), “Regulatory Matters – FERC Transmission ROE Challenges,” to the financial statements of Pepco.

Earnings Overview

Net Income For the Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

Pepco’s net income for the year ended December 31, 2014 was $171 million compared to $150 million for the year ended December 31, 2013. The $21 million increase in earnings was primarily due to the following:

• An increase of $17 million from electric distribution base rate increases in the District of Columbia and in Maryland.

• An increase of $8 million due to customer growth in 2014, primarily in the residential customer class.

• An increase of $5 million in other income related to gains recorded in 2014 associated with condemnation awards for certain transmission properties.

• An increase of $1 million due to higher transmission revenue attributable to a change in FERC formula rates.

• A decrease of $8 million due to higher depreciation and amortization expense associated with regulatory assets and increases in plant investment.

• A decrease of $2 million due to higher tax benefits recorded in 2013 related to uncertain and effectively settled tax positions.

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Results of Operations

The following results of operations discussion compares the year ended December 31, 2014 to the year ended December 31, 2013. All amounts in the tables (except sales and customers) are in millions of dollars.

A condensed summary of Pepco’s statement of income for the year ended December 31, 2014 compared to the year ended December 31, 2013, is set forth in the table below:

	2014			2013			Change
Operating revenue	$	2,101		$	2,026		$	75
Purchased energy		771			750			21
Other operation and maintenance		390			391			(1	)
Depreciation and amortization		229			196			33
Other taxes		363			368			(5	)
Total operating expenses		1,753			1,705			48
Operating income		348			321			27
Other income (expenses)		(85	)		(92	)		7
Income before income tax expense		263			229			34
Income tax expense		92			79			13
Net income	$	171		$	150		$	21

Operating Revenue

	2014		2013		Change
Regulated T&D Electric Revenue	$	1,269	$	1,215	$	54
Default Electricity Supply Revenue		798		778		20
Other Electric Revenue		34		33		1
Total Operating Revenue	$	2,101	$	2,026	$	75

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to Pepco’s customers within its service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that Pepco receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.

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

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Regulated T&D Electric

	2014		2013		Change
Regulated T&D Electric Revenue
Residential	$	375	$	359	$	16
Commercial and industrial		705		678		27
Transmission and other		189		178		11
Total Regulated T&D Electric Revenue	$	1,269	$	1,215	$	54
	2014		2013		Change
Regulated T&D Electric Sales (GWh)
Residential		7,854		7,832		22
Commercial and industrial		17,737		17,806		(69	)
Transmission and other		160		163		(3	)
Total Regulated T&D Electric Sales		25,751		25,801		(50	)
	2014		2013		Change
Regulated T&D Electric Customers (in thousands)
Residential		740		727		13
Commercial and industrial		75		74		1
Transmission and other		—		—		—
Total Regulated T&D Electric Customers		815		801		14

Regulated T&D Electric Revenue increased by $54 million primarily due to:

• An increase of $27 million due to electric distribution base rate increases in the District of Columbia effective March 2014 and in Maryland effective July 2013.

• An increase of $15 million due to an EmPower Maryland rate increase effective February 2014 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

• An increase of $13 million due to customer growth in 2014 primarily in the residential class.

• An increase of $7 million in transmission revenue related to the recovery of MAPP abandonment costs, as approved by FERC (which is offset in Depreciation and Amortization).

• An increase of $4 million in capacity revenue as a result of expanding Maryland demand side management programs (which is partially offset in Depreciation and Amortization).

• An increase of $1 million in transmission revenue rates effective June 1, 2014 and June 1, 2013 related to increases in transmission plant investment and operating expenses, partially offset by the establishment of a reserve related to the FERC ROE complaint.

The aggregate amount of these increases was partially offset by a decrease of $12 million in distribution revenue due to lower pass-through revenue (which is substantially offset by a corresponding decrease in Other Taxes), primarily the result of a rate decrease effective July 2014 in utility taxes collected by Pepco on behalf of Montgomery County, Maryland.

Default Electricity Supply

	2014		2013		Change
Default Electricity Supply Revenue
Residential	$	527	$	539	$	(12	)
Commercial and industrial		251		222		29
Other		20		17		3
Total Default Electricity Supply Revenue	$	798	$	778	$	20

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	2014		2013		Change
Default Electricity Supply Sales (GWh)
Residential		6,027		5,944		83
Commercial and industrial		2,993		2,700		293
Other		6		14		(8	)
Total Default Electricity Supply Sales		9,026		8,658		368
	2014		2013		Change
Default Electricity Supply Customers (in thousands)
Residential		591		569		22
Commercial and industrial		45		44		1
Other		—		—		—
Total Default Electricity Supply Customers		636		613		23

Default Electricity Supply Revenue increased by $20 million primarily due to:

• An increase of $42 million due to higher sales primarily as a result of customer migration from competitive suppliers.

• An increase of $8 million due to higher sales primarily as a result of colder weather during the 2014 winter months, as compared to 2013.

• An increase of $3 million in revenue from PJM for transmission enhancement credits as a result of a higher total cost of transmission projects in 2014.

The aggregate of these increases was partially offset by:

• A decrease of $18 million in average customer usage.

• A decrease of $15 million as a result of lower Default Electricity Supply rates.

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

	2014			2013
Sales to District of Columbia customers		27	%		25	%
Sales to Maryland customers		41	%		41	%

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by Pepco to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy increased by $21 million to $771 million in 2014 from $750 million in 2013 primarily due to:

• An increase of $21 million primarily due to customer migration from competitive suppliers.

• An increase of $7 million due to higher electricity sales primarily as a result of warmer weather during the 2014 summer months, as compared to 2013.

• An increase of $5 million in deferred electricity expense primarily due to higher revenue associated with Default Electricity Supply sales, which resulted in a higher rate of recovery of Default Electricity Supply costs.

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The aggregate of these increases was partially offset by a decrease of $12 million due to lower average electricity costs under Default Electricity Supply contracts.

Other Operation and Maintenance

Other Operation and Maintenance expense decreased by $1 million to $390 million in 2014 from $391 million in 2013 primarily due to:

• A decrease of $5 million in regulatory expenses.

• A decrease of $3 million associated with higher environmental remediation costs in 2013.

• A decrease of $2 million primarily resulting from lower pension costs.

The aggregate amount of these decreases was partially offset by:

• An increase of $6 million in incremental merger-related integration costs.

• An increase of $3 million primarily due to new customer system support costs.

Depreciation and Amortization

Depreciation and Amortization expense increased by $33 million to $229 million in 2014 from $196 million in 2013 primarily due to:

• An increase of $11 million in amortization of regulatory assets primarily associated with the EmPower Maryland surcharge rate increase effective February 2014 (which is offset in Regulated T&D Electric Revenue).

• An increase of $11 million due to utility plant additions.

• An increase of $7 million in amortization of MAPP abandonment costs (which is offset in T&D Electric Revenue).

• An increase of $3 million in amortization of regulatory assets primarily related to recoverable major storm costs and rate case costs.

Other Taxes

Other Taxes decreased by $5 million to $363 million in 2014 from $368 million in 2013. The decrease was primarily due to a decrease of $10 million in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue) partially offset by higher property taxes of $6 million in Maryland.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $7 million to a net expense of $85 million in 2014 from a net expense of $92 million in 2013. The decrease was primarily due to a $9 million gain recorded in 2014 associated with condemnation awards for certain transmission properties.

Income Tax Expense

Pepco’s income tax expense increased by $13 million to $92 million in 2014 from $79 million in 2013. Pepco’s effective income tax rates for the years ended December 31, 2014 and 2013 were 35.0% and 34.5%, respectively. The increase in the effective tax rate primarily resulted from a decrease in interest benefits related to uncertain and effectively settled tax positions and a reduction in asset removal costs.

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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 Pepco is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly owned subsidiary PCI, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in Pepco recording a $5 million (after-tax) interest benefit in the first quarter of 2013.

Capital Requirements

Sources of Capital

Pepco has a range of capital sources available, in addition to internally generated funds, to meet its long-term and short-term funding needs. The sources of long-term funding include the issuance of mortgage bonds and other debt securities and bank financings, as well as the ability to issue preferred stock. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures, and to repay or refinance existing indebtedness. Pepco traditionally has used a number of sources to fulfill short-term funding needs, including commercial paper, short-term notes, bank lines of credit and borrowings under the PHI money pool. 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. Pepco’s ability to generate funds from its operations and to access the capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of Pepco’s potential funding sources.

Debt Securities

Pepco has a Mortgage and Deed of Trust (the Mortgage) under which it issues First Mortgage Bonds. First Mortgage Bonds issued under the Mortgage are secured by a lien on substantially all of Pepco’s property, plant and equipment, except for such property excluded from the lien of the Mortgage. The principal amount of First Mortgage Bonds that Pepco may issue under the Mortgage is limited by the principal amount of retired First Mortgage Bonds and 60% of the lesser of the cost or fair value of new property additions that have not been used as the basis for the issuance of additional First Mortgage Bonds. Pepco also has an indenture under which it issues senior notes secured by First Mortgage Bonds and an indenture under which it can issue unsecured debt securities, including medium-term notes. To fund the construction of pollution control facilities, Pepco also has from time to time raised capital through tax-exempt bonds issued by a municipality or public agency, the proceeds of which are loaned to Pepco by the municipality or agency.

Information concerning the principal amount and terms of Pepco’s outstanding debt securities, as of December 31, 2014, is set forth in Note (9), “Debt,” to the financial statements of Pepco.

Bank Financing

As further discussed in Note (9), “Debt,” to the financial statements of Pepco, Pepco is a borrower under a $1.5 billion unsecured syndicated credit facility, along with PHI, DPL and ACE, which expires in August 2018. This credit facility provides for Pepco’s liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting its commercial paper program. Pepco’s credit limit under the facility is the lesser of $250 million and the maximum amount of short-term debt Pepco is permitted to have outstanding by its regulatory authorities. The short-term borrowing limit established by FERC for Pepco is $500 million.

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Commercial Paper Program

Pepco maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2014, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

Pepco had $104 million of commercial paper outstanding at December 31, 2014. The weighted average interest rate for commercial paper issued by Pepco during 2014 was 0.28% and the weighted average maturity of all commercial paper issued by Pepco during 2014 was six days.

Money Pool

Pepco participates in the money pool operated by PHI under authorization received from FERC. The money pool is an unsecured cash management mechanism used by PHI and eligible subsidiaries to manage their short-term investment and borrowing requirements. PHI may invest in, but not borrow from, the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by PHI. Eligible subsidiaries with cash requirements may borrow from the money pool. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on PHI’s short-term borrowing rate. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Preferred Stock

Under its Articles of Incorporation, Pepco is authorized to issue and have outstanding up to 6 million shares of preferred stock in one or more series, with each series having such rights, preferences and limitations, including dividend and voting rights and redemption provisions, as the Board of Directors may establish. As of December 31, 2014 and 2013, there were no shares of Pepco preferred stock outstanding.

Regulatory Restrictions on Financing Activities

Pepco’s long-term financing activities (including the issuance of securities and the incurrence of debt) are subject to authorization by the DCPSC and MPSC. Through its periodic filings with the respective utility commissions, Pepco generally maintains standing authority sufficient to cover its projected financing needs over a multi-year period. Under the FPA, FERC has jurisdiction over the issuance of long-term and short-term securities of public utilities, but only if the issuance is not regulated by the state public utility commission in which the public utility is organized and operating. Pepco has obtained FERC authorization for the issuance of short-term debt under these provisions.

Capital Expenditures

Pepco’s capital expenditures for the year ended December 31, 2014 were $567 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to Pepco when the assets are placed in service.

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Pepco’s projected capital expenditures for the five-year period from 2015 through 2019 are summarized below. Pepco expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year Ended December 31,
	2015		2016		2017		2018		2019		Total
	(millions of dollars)
Pepco
Distribution	$	495	$	559	$	531	$	529	$	473	$	2,587
Transmission		122		99		148		127		153		649
Other		50		49		37		31		28		195
Total Pepco	$	667	$	707	$	716	$	687	$	654	$	3,431

Pepco has several construction projects within its service territory where performance has been subcontracted to Pepco Energy Services. Pepco guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for these projects. These guarantees totaled $39 million at December 31, 2014.

District of Columbia Power Line Undergrounding Initiative

On May 3, 2014, the Council of the District of Columbia enacted the Improvement Financing Act, which provides enabling legislation for the DC PLUG initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco. A more detailed discussion of the Improvement Financing Act is provided in Note (6), “Regulatory Matters – District of Columbia Power Line Undergrounding Initiative,” to the financial statements of Pepco.

Transmission and Distribution

The projected capital expenditures listed in the table above for distribution and transmission are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. The projected capital expenditures related to the DC PLUG initiative are included as part of distribution expenditures in the table above.

DOE Capital Reimbursement Awards

During 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure. Pepco was awarded $149 million, with $105 million to be used in the Maryland service territory and $44 million to be used in the District of Columbia service territory.

During 2010, Pepco and the DOE signed agreements formalizing Pepco’s $149 million share of the $168 million award. Of the $149 million, $118 million was offset against smart grid-related capital expenditures of Pepco. The remaining $31 million is being used to offset incremental expenditures associated with direct load control and other programs, which have been deferred as regulatory assets. During 2014, Pepco received award payments of $3 million. The cumulative award payments received by Pepco as of December 31, 2014, were $148 million.

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

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Pension and Other Postretirement Benefit Plans

Pepco participates in pension and OPEB plans sponsored by PHI for its employees. Pepco made no contributions the PHI Retirement Plan during 2014 and 2013. In 2014 and 2013, Pepco contributed $1 million and $6 million, respectively, to the other postretirement benefit plan.

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DPL

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

Delmarva Power & Light Company

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

General Overview

DPL is engaged in the transmission and distribution of electricity in portions of Delaware and Maryland. DPL also provides Default Electricity Supply. DPL’s electricity distribution service territory covers approximately 5,000 square miles and, as of December 31, 2014, had a population of approximately 1.4 million. As of December 31, 2014, approximately 65% of delivered electricity sales were to Delaware customers and approximately 35% were to Maryland customers. In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers who purchase natural gas from other suppliers. DPL’s natural gas distribution service territory covers approximately 275 square miles and, as of December 31, 2014, had a population of approximately 0.5 million.

DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a BSA for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A modified fixed variable rate design, which would provide for a charge not tied to a customer’s volumetric consumption of electricity or natural gas, has been proposed for DPL electricity and natural gas customers in Delaware. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

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

DPL is a wholly owned subsidiary of Conectiv which is wholly owned by PHI. Because each of PHI and Conectiv is a public utility holding company subject to PUHCA 2005, the relationship between each of PHI, Conectiv, PHI Service Company and DPL, as well as certain activities of DPL, are subject to FERC’s regulatory oversight under PUHCA 2005.

Agreement and Plan of Merger with Exelon Corporation

PHI has entered into the Merger Agreement with Exelon and Merger Sub, providing for the Merger, with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. For additional information regarding the Merger, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation.”

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Utility Capital Expenditures

DPL allocates a substantial portion of its total capital expenditures to improving the reliability of its electrical transmission and distribution systems and replacing aging infrastructure throughout its service territories. These activities include one or more of the following:

• Identifying and upgrading under-performing feeders;

• Adding new facilities to support load;

• Installing distribution automation systems on both the overhead and underground network systems; and

• Rejuvenating and replacing underground residential cables.

DPL’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures within “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Requirements – Capital Expenditures.”

Smart Grid

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

Mitigation of Regulatory Lag

An important factor in the ability of DPL to earn its authorized ROE is the willingness of the DPSC and the MPSC to adequately address the shortfall in revenues in DPL’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” DPL is currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than revenue growth. For a more detailed discussion of regulatory lag, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Power Delivery Initiatives and Activities – Mitigation of Regulatory Lag.”

In an effort to minimize the effects of regulatory lag, prior to the initial execution of the Merger Agreement in April 2014, DPL had been filing electric distribution base rate cases every nine to twelve months in each of its jurisdictions, pursuing alternative ratemaking mechanisms, evaluating potential reductions in planned capital expenditures, and discussing with the regulatory community and other stakeholders the changing regulatory model economics that are causing regulatory lag.

As further described in PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation,” PHI has entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, DPL may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings. Accordingly, with the exception of ongoing rate cases (see Note (7), “Regulatory Matters – Rate Proceedings,” to the financial statements of DPL), DPL’s efforts to mitigate regulatory lag have been delayed pending the closing of the Merger or the termination of the Merger Agreement.

MAPP Settlement Agreement

For information about the MAPP settlement agreement, please refer to Note (7), “Regulatory Matters – MAPP Settlement Agreement,” to the financial statements of DPL.

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Transmission ROE Challenges

For information about the challenges to DPL’s base ROE and the application of the formula rate process, each associated with the transmission services it provides, please refer to Note (7), “Regulatory Matters – Transmission ROE Challenges,” to the financial statements of DPL.

Earnings Overview

Net Income For the Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

DPL’s net income for the year ended December 31, 2014 was $104 million compared to $89 million for the year ended December 31, 2013. The $15 million increase in earnings was primarily due to the following:

• An increase of $16 million from electric distribution base rate increases in Maryland and Delaware.

• An increase of $7 million due to higher transmission revenue attributable to a change in FERC formula rates.

• An increase of $3 million due to customer growth.

• An increase of $2 million from a gas distribution base rate increase.

• An increase of $2 million primarily due to lower long-term debt interest expense.

• A decrease of $10 million due to higher operation and maintenance expense primarily associated with higher tree trimming, emergency restoration, and incremental merger-related costs in 2014.

• A decrease of $6 million due to higher depreciation and amortization expense associated primarily with regulatory assets and increases in plant investment.

Results of Operations

The following results of operations discussion compares the year ended December 31, 2014 to the year ended December 31, 2013. All amounts in the tables (except sales and customers) are in millions of dollars.

A condensed summary of DPL’s statement of income for the year ended December 31, 2014 compared to the year ended December 31, 2013, is set forth in the table below:

	2014			2013			Change
Operating revenue	$	1,293		$	1,244		$	49
Purchased energy		546			552			(6	)
Gas purchased		104			109			(5	)
Other operation and maintenance		269			251			18
Depreciation and amortization		125			107			18
Other taxes		42			40			2
Total operating expenses		1,086			1,059			27
Operating income		207			185			22
Other income (expenses)		(38	)		(40	)		2
Income before income tax expense		169			145			24
Income tax expense		65			56			9
Net income	$	104		$	89		$	15

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Electric Operating Revenue

	2014		2013		Change
Regulated T&D Electric Revenue	$	559	$	502	$	57
Default Electricity Supply Revenue		527		538		(11	)
Other Electric Revenue		13		13		—
Total Electric Operating Revenue	$	1,099	$	1,053	$	46

The table above shows the amount of Electric Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to DPL’s customers within its service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that DPL receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.

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

Regulated T&D Electric

	2014		2013		Change
Regulated T&D Electric Revenue
Residential	$	251	$	232	$	19
Commercial and industrial		156		144		12
Transmission and other		152		126		26
Total Regulated T&D Electric Revenue	$	559	$	502	$	57
	2014		2013		Change
Regulated T&D Electric Sales (GWh)
Residential		5,188		5,122		66
Commercial and industrial		7,178		7,295		(117	)
Transmission and other		47		48		(1	)
Total Regulated T&D Electric Sales		12,413		12,465		(52	)
	2014		2013		Change
Regulated T&D Electric Customers (in thousands)
Residential		449		445		4
Commercial and industrial		60		60		—
Transmission and other		1		1		—
Total Regulated T&D Electric Customers		510		506		4

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Regulated T&D Electric Revenue increased by $57 million primarily due to:

• An increase of $26 million due to electric distribution base rate increases in Maryland effective September 2013 and in Delaware effective October 2013.

• An increase of $13 million in transmission revenue resulting from higher rates effective June 1, 2014 and June 1, 2013 related to increases in transmission plant investment and operating expenses, partially offset by the establishment of a reserve related to the FERC ROE complaint.

• An increase of $5 million in transmission revenue related to the recovery of MAPP abandonment costs, as approved by FERC (which is offset in Depreciation and Amortization).

• An increase of $5 million in transmission revenue related to the resale by DPL of renewable energy in Delaware (which is substantially offset in Purchased Energy and Depreciation and Amortization).

• An increase of $4 million due to an EmPower Maryland rate increase effective February 2014 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

• An increase of $3 million due to customer growth in 2014 primarily in the residential and commercial customer classes.

The aggregate amount of these increases was partially offset by a decrease of $2 million primarily due to a rate decrease effective May 2013 associated with the Renewable Portfolio Surcharge in Delaware (which is substantially offset in Fuel and Purchased Energy and Depreciation and Amortization).

Default Electricity Supply

	2014		2013		Change
Default Electricity Supply Revenue
Residential	$	402	$	412	$	(10	)
Commercial and industrial		112		114		(2	)
Other		13		12		1
Total Default Electricity Supply Revenue	$	527	$	538	$	(11	)
	2014		2013		Change
Default Electricity Supply Sales (GWh)
Residential		4,420		4,464		(44	)
Commercial and industrial		1,371		1,342		29
Other		26		27		(1	)
Total Default Electricity Supply Sales		5,817		5,833		(16	)
	2014		2013		Change
Default Electricity Supply Customers (in thousands)
Residential		392		390		2
Commercial and industrial		40		38		2
Other		—		—		—
Total Default Electricity Supply Customers		432		428		4

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Default Supply Revenue decreased by $11 million primarily due to:

• A decrease of $10 million as a result of lower Default Electricity Supply rates.

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

The aggregate amount of these decreases was partially offset by:

• An increase of $2 million in revenue from PJM for transmission enhancement credits as a result of a higher total cost of transmission projects in 2014.

• An increase of $1 million due to higher non-weather related average customer usage.

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

	2014			2013
Sales to Delaware customers		44	%		44	%
Sales to Maryland customers		51	%		51	%

Natural Gas Operating Revenue

	2014		2013		Change
Regulated Gas Revenue	$	176	$	165	$	11
Other Gas Revenue		18		26		(8	)
Total Natural Gas Operating Revenue	$	194	$	191	$	3

The table above shows the amounts of Natural Gas Operating Revenue from sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other Gas Revenue consists of off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Regulated Gas

	2014		2013		Change
Regulated Gas Revenue
Residential	$	106	$	103	$	3
Commercial and industrial		59		52		7
Transportation and other		11		10		1
Total Regulated Gas Revenue	$	176	$	165	$	11
	2014		2013		Change
Regulated Gas Sales (million cubic feet)
Residential		8,550		7,861		689
Commercial and industrial		6,063		4,945		1,118
Transportation and other		6,418		6,990		(572	)
Total Regulated Gas Sales		21,031		19,796		1,235

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	2014		2013		Change
Regulated Gas Customers (in thousands)
Residential		118		117		1
Commercial and industrial		10		9		1
Transportation and other		—		—		—
Total Regulated Gas Customers		128		126		2

Regulated Gas Revenue increased by $11 million primarily due to:

• An increase of $9 million due to higher sales primarily as a result of colder weather during the winter months of 2014, as compared to 2013.

• An increase of $6 million due to higher non-weather related average customer usage.

• An increase of $4 million due to a distribution rate increase effective July 2013.

• An increase of $2 million due to customer growth primarily in the residential customer class.

The aggregate amount of these increases was partially offset by a decrease of $10 million due to GCR decreases effective November 2014 and November 2013.

Other Gas Revenue

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

Operating Expenses

Purchased Energy consists of the cost of electricity purchased by DPL to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $6 million to $546 million in 2014 from $552 million in 2013 primarily due to:

• A decrease of $23 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $1 million primarily due to customer migration to competitive suppliers.

The aggregate amount of these decreases was partially offset by:

• An increase of $15 million due to deferred electricity expense primarily due to higher Default Electricity Supply rates, which resulted in higher rate of recovery of Default Electricity Supply costs.

• An increase of $3 million due to Renewable Energy Credits in Delaware (which is offset by a corresponding increase in Regulated T&D Electric Revenue).

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Gas Purchased

Gas Purchased expense consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Total Gas Purchased expense decreased by $5 million to $104 million in 2014 from $109 million in 2013 primarily due to the following:

• A decrease of $8 million in the cost of gas purchases for off-system sales as a result of lower volumes.

• A decrease of $7 million in deferred gas expense as a result of a lower rate of recovery of natural gas supply costs.

• A decrease of $6 million from the settlement of financial hedges entered into as part of DPL’s hedge program for the purchase of regulated natural gas.

The aggregate amount of these decreases was partially offset by an increase of $16 million in the cost of gas purchases for on-system sales as a result of higher average gas prices.

Other Operation and Maintenance

Other Operation and Maintenance expense increased by $18 million to $269 million in 2014 from $251 million in 2013 primarily due to:

• An increase of $6 million in tree trimming costs.

• An increase of $4 million in emergency restoration costs.

• An increase of $4 million in incremental merger-related integration costs.

• An increase of $3 million in bad debt expenses.

• An increase of $2 million primarily due to new customer system support costs.

The aggregate amount of these increases was partially offset by a decrease of $2 million resulting from the 2013 write-offs of disallowed MAPP and associated transmission project costs.

Depreciation and Amortization

Depreciation and Amortization expense increased by $18 million to $125 million in 2014 from $107 million in 2013 primarily due to:

• An increase of $9 million due to utility plant additions.

• An increase of $5 million in amortization of MAPP abandonment costs (which is offset by a corresponding increase in Regulated T&D Electric Revenue).

• An increase of $3 million in amortization of regulatory assets primarily related to recoverable AMI costs, major storm costs and rate case costs.

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Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $2 million to a net expense of $38 million in 2014 from a net expense of $40 million in 2013. The decrease was primarily due to lower long-term debt interest expense.

Income Tax Expense

DPL’s income tax expense increased by $9 million to $65 million in 2014 from $56 million in 2013. DPL’s effective income tax rates for the years ended December 31, 2014 and 2013 were 38.5% and 38.6%, respectively.

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 DPL is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly owned subsidiary PCI, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in DPL recording a $1 million (after-tax) interest benefit in the first quarter of 2013.

Capital Requirements

Sources of Capital

DPL has a range of capital sources available, in addition to internally generated funds, to meet its long-term and short-term funding needs. The sources of long-term funding include the issuance of mortgage bonds and other debt securities and bank financings, as well as the ability to issue preferred stock. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures, and to repay or refinance existing indebtedness. DPL traditionally has used a number of sources to fulfill short-term funding needs, including commercial paper, medium- and short-term notes, bank lines of credit, and borrowings under the PHI money pool. 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. DPL’s ability to generate funds from its operations and to access the capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of DPL’s potential funding sources.

Debt Securities

DPL has a Mortgage and Deed of Trust (the Mortgage) under which it issues First Mortgage Bonds. First Mortgage Bonds issued under the Mortgage are secured by a lien on substantially all of DPL’s property, plant and equipment, except for such property excluded from the lien of the Mortgage. The principal amount of First Mortgage Bonds that DPL may issue under the Mortgage is limited by the principal amount of retired First Mortgage Bonds and 60% of the lesser of the cost or fair value of new property additions that have not been used as the basis for the issuance of additional First Mortgage Bonds. DPL also has an indenture under which it issues unsecured senior notes, medium-term notes and Variable Rate Demand Bonds (VRDBs). To fund the construction of pollution control facilities, DPL also has from time to time raised capital through tax-exempt bonds, including tax-exempt VRDBs, issued by a public agency, the proceeds of which are loaned to DPL by the agency.

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Information concerning the principal amount and terms of DPL’s outstanding First Mortgage Bonds, senior notes, medium-term notes and tax-exempt bonds issued for the benefit of DPL, as of December 31, 2014, is set forth in Note (10), “Debt,” to the financial statements of DPL.

Bank Financing

As further discussed in Note (10), “Debt,” to the financial statements of DPL, DPL is a borrower under a $1.5 billion unsecured syndicated credit facility, along with PHI, Pepco and ACE, which expires in August 2018. This credit facility provides for DPL’s liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting its commercial paper program. DPL’s credit limit under the facility is the lesser of $250 million and the maximum amount of short-term debt DPL is permitted to have outstanding by its regulatory authorities. The short-term borrowing limit established by FERC for DPL is $500 million.

Commercial Paper Program

DPL maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2014, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

DPL had $106 million of commercial paper outstanding at December 31, 2014. The weighted average interest rate for commercial paper issued by DPL during 2014 was 0.26% and the weighted average maturity of all commercial paper issued by DPL during 2014 was five days.

Money Pool

DPL participates in the money pool operated by PHI under authorization received from FERC. The money pool is an unsecured cash management mechanism used by PHI and eligible subsidiaries to manage their short-term investment and borrowing requirements. PHI may invest in, but not borrow from, the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by PHI. Eligible subsidiaries with cash requirements may borrow from the money pool. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on PHI’s short-term borrowing rate. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Regulatory Restrictions on Financing Activities

DPL’s long-term financing activities (including the issuance of securities and the incurrence of debt) is subject to authorization by the DPSC and the MPSC. Through its periodic filings with the respective utility commissions, DPL generally maintains standing authority sufficient to cover its projected financing needs over a multi-year period. Under the FPA, FERC has jurisdiction over the issuance of long-term and short-term securities of public utilities, but only if the issuance is not regulated by the state public utility commission in which the public utility is organized and operating. DPL has obtained FERC authorization for the issuance of short-term debt under these provisions.

Capital Expenditures

DPL’s capital expenditures for the year ended December 31, 2014 were $352 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to DPL when the assets are placed in service.

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DPL

DPL’s projected capital expenditures for the five-year period from 2015 through 2019 are summarized below. DPL expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year Ended December 31,
	2015		2016		2017		2018		2019		Total
	(millions of dollars)
DPL
Distribution	$	171	$	164	$	181	$	172	$	167	$	855
Transmission		124		127		114		144		75		584
Gas Delivery		32		32		35		36		38		173
Other		32		28		29		24		21		134
Total DPL	$	359	$	351	$	359	$	376	$	301	$	1,746

Transmission and Distribution

The projected capital expenditures listed in the table above for distribution, transmission and gas delivery are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for reliability enhancement efforts.

Pension and Other Postretirement Benefit Plans

DPL participates in pension and OPEB plans sponsored by PHI for its employees. DPL contributed zero and $10 million to the PHI Retirement Plan during 2014 and 2013, respectively. In 2014 and 2013, DPL contributed zero and $3 million, respectively, to the other postretirement benefit plan.

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ACE

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

Atlantic City Electric Company

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

General Overview

ACE is engaged in the transmission and distribution of electricity in portions of southern New Jersey. ACE also provides Default Electricity Supply. Default Electricity Supply is known as BGS in New Jersey. ACE’s service territory covers approximately 2,700 square miles and, as of December 31, 2014, had a population of approximately 1.1 million.

ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by PHI. Because each of PHI and Conectiv is a public utility holding company subject to PUHCA 2005, the relationship between each of PHI, Conectiv, PHI Service Company and ACE, as well as certain activities of ACE, are subject to FERC’s regulatory oversight under PUHCA 2005.

Agreement and Plan of Merger with Exelon Corporation

PHI has entered into the Merger Agreement with Exelon and Merger Sub, providing for the Merger, with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. For additional information regarding the Merger, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation.”

Utility Capital Expenditures

ACE allocates a substantial portion of its total capital expenditures to improving the reliability of its electrical transmission and distribution systems and replacing aging infrastructure throughout its service territory. These activities include one or more of the following:

• Identifying and upgrading under-performing feeders;

• Adding new facilities to support load;

• Installing distribution automation systems on both the overhead and underground network systems; and

• Rejuvenating and replacing underground residential cables.

ACE’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures within “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Requirements – Capital Expenditures.”

Mitigation of Regulatory Lag

An important factor in the ability of ACE to earn its authorized ROE is the willingness of the NJBPU to adequately address the shortfall in revenues in ACE’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” ACE is currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than revenue growth. For a more detailed discussion of regulatory lag, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Power Delivery Initiatives and Activities – Mitigation of Regulatory Lag.”

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In an effort to minimize the effects of regulatory lag, prior to the initial execution of the Merger Agreement in April 2014, ACE had been filing electric distribution base rate cases every nine to twelve months, pursuing alternative ratemaking mechanisms, evaluating potential reductions in planned capital expenditures, and discussing with the regulatory community and other stakeholders the changing regulatory model economics that are causing regulatory lag.

As further described in PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation,” PHI has entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, ACE may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings. Accordingly, ACE’s efforts to mitigate regulatory lag have been delayed pending the closing of the Merger or the termination of the Merger Agreement.

Transmission ROE Challenges

For information about the challenges to ACE’s base ROE and the application of the formula rate process, each associated with the transmission services it provides, please refer to Note (6), “Regulatory Matters – FERC Transmission ROE Challenges,” to the consolidated financial statements of ACE.

Earnings Overview

Net Income For the Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

ACE’s consolidated net income for the year ended December 31, 2014 was $45 million compared to $50 million for the year ended December 31, 2013. The $5 million decrease in earnings was primarily due to the following:

• A decrease of $9 million due to higher amortization expense of regulatory assets.

• A decrease of $7 million due to higher tax benefits recorded in 2013 related to uncertain and effectively settled tax positions.

• A decrease of $6 million due to higher operation and maintenance expense primarily associated with higher tree trimming and incremental merger-related costs.

• A decrease of $5 million primarily due to lower sales from milder spring and summer weather, and from lower non-weather related average customer usage.

• An increase of $17 million from electric distribution base rate increases in New Jersey.

• An increase of $3 million due to higher transmission revenue attributable to a change in FERC formula rates.

• An increase of $3 million due to lower long-term debt interest expense.

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ACE

Results of Operations

The following results of operations discussion compares the year ended December 31, 2014 to the year ended December 31, 2013. All amounts in the tables (except sales and customers) are in millions of dollars.

A condensed summary of ACE’s consolidated statement of income for the year ended December 31, 2014 compared to the year ended December 31, 2013, is set forth in the table below:

	2014			2013			Change
Operating revenue	$	1,213		$	1,202		$	11
Purchased energy		653			660			(7	)
Other operation and maintenance		246			230			16
Depreciation and amortization		157			136			21
Other taxes		2			14			(12	)
Deferred electric service costs		20			26			(6	)
Total operating expenses		1,078			1,066			12
Operating income		135			136			(1	)
Other income (expenses)		(62	)		(67	)		5
Income before income tax expense		73			69			4
Income tax expense		28			19			9
Consolidated Net Income	$	45		$	50		$	(5	)

Operating Revenue

	2014		2013		Change
Regulated T&D Electric Revenue	$	449	$	429	$	20
Default Electricity Supply Revenue		751		759		(8	)
Other Electric Revenue		13		14		(1	)
Total Operating Revenue	$	1,213	$	1,202	$	11

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to ACE’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, and revenue in the form of transmission enhancement credits.

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

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ACE

Regulated T&D Electric

	2014		2013		Change
Regulated T&D Electric Revenue
Residential	$	198	$	190	$	8
Commercial and industrial		152		148		4
Transmission and other		99		91		8
Total Regulated T&D Electric Revenue	$	449	$	429	$	20
	2014		2013		Change
Regulated T&D Electric Sales (GWh)
Residential		4,087		4,214		(127	)
Commercial and industrial		4,916		4,969		(53	)
Transmission and other		48		48		—
Total Regulated T&D Electric Sales		9,051		9,231		(180	)
	2014		2013		Change
Regulated T&D Electric Customers (in thousands)
Residential		480		478		2
Commercial and industrial		65		66		(1	)
Transmission and other		1		1		—
Total Regulated T&D Electric Customers		546		545		1

Regulated T&D Electric Revenue increased by $20 million primarily due to:

• An increase of $28 million due to electric distribution rate increases effective July 2013 and September 2014.

• An increase of $6 million in transmission revenue resulting from higher rates effective June 1, 2014 and June 1, 2013 related to increases in transmission plant investment and operating expenses, partially offset by the establishment of a reserve related to the FERC ROE complaint.

• An increase of $5 million primarily due to a rate increase in the New Jersey Societal Benefit Charge effective January 2014 (which is offset in Depreciation and Amortization and Deferred Electric Service Costs).

The aggregate amount of these increases was partially offset by:

• A decrease of $10 million in distribution revenue due to lower pass-through revenue primarily the result of the expiration of the New Jersey TEFA tax surcharge effective December 2013 (which is offset in Other Taxes).

• A decrease of $5 million due to lower non-weather related average residential and commercial customer usage.

• A decrease of $4 million due to lower sales primarily as a result of milder weather during the 2014 spring and summer months, as compared to 2013.

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ACE

Default Electricity Supply

	2014		2013		Change
Default Electricity Supply Revenue
Residential	$	383	$	425	$	(42	)
Commercial and industrial		190		206		(16	)
Other		178		128		50
Total Default Electricity Supply Revenue	$	751	$	759	$	(8	)

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

	2014		2013		Change
Default Electricity Supply Sales (GWh)
Residential		3,404		3,335		69
Commercial and industrial		1,056		1,037		19
Other		12		14		(2	)
Total Default Electricity Supply Sales		4,472		4,386		86
	2014		2013		Change
Default Electricity Supply Customers (in thousands)
Residential		414		393		21
Commercial and industrial		44		43		1
Other		—		—		—
Total Default Electricity Supply Customers		458		436		22

Default Electricity Supply Revenue decreased by $8 million primarily due to:

• A decrease of $72 million as a result of lower Default Electricity Supply rates.

• A decrease of $9 million due to lower sales primarily as a result of milder weather during the 2014 spring and summer months, as compared to 2013.

• A decrease of $7 million due to lower non-weather related average commercial customer usage.

The aggregate amount of these decreases was partially offset by:

• An increase of $50 million in wholesale energy and capacity resale revenues primarily due to higher market prices for the resale of electricity and capacity purchased from NUGs.

• An increase of $30 million due to higher sales primarily as a result of customer migration from competitive suppliers.

The variances described above with respect to Default Electricity Supply Revenue include the effects of an increase of $3 million in ACE’s BGS unbilled revenue resulting primarily from higher rates and customer migration from competitive suppliers in the unbilled revenue period for the year ended 2014 as compared to the corresponding period for the year ended 2013. Such an increase in ACE’s BGS unbilled revenue has the effect of directly increasing the profitability of ACE’s Default Electricity Supply business ($2 million increase in net income) as these unbilled revenues are not included in the deferral calculation until they are billed to customers under the BGS terms approved by the NJBPU.

For the year ended December 31, 2014 and 2013, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 49% and 48%, respectively.

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ACE

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by ACE to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $7 million to $653 million in 2014 from $660 million in 2013 primarily due to:

• A decrease of $15 million due to lower average electricity costs under BGS contracts.

• A decrease of $5 million due to lower electricity sales, primarily as a result of milder weather during the 2014 summer months, as compared to 2013.

The aggregate amount of these increases was partially offset by an increase of $13 million primarily due to customer migration from competitive suppliers.

Other Operation and Maintenance

Other Operation and Maintenance expense increased by $16 million to $246 million in 2014 from $230 million in 2013 primarily due to:

• An increase of $3 million in incremental merger-related integration costs.

• An increase of $3 million in tree trimming costs.

• An increase of $3 million due to the write-off of unrecoverable regulatory assets previously established in connection with the sale of certain generation assets.

• An increase of $2 million in bad debt expense, of which $1 million is deferred and recoverable.

• An increase of $2 million primarily due to new customer system support costs.

• An increase of $2 million resulting from higher other benefit expenses partially offset by lower pension costs.

Depreciation and Amortization

Depreciation and Amortization expense increased by $21 million to $157 million in 2014 from $136 million in 2013 primarily due to:

• An increase of $12 million in amortization due to the expiration of the excess depreciation reserve regulatory liability in August 2013.

• An increase of $5 million in amortization of solar renewable energy credits (which is offset by an increase in Regulated T&D Electric Revenue).

• An increase of $4 million in amortization of major storm costs.

Other Taxes

Other Taxes decreased by $12 million to $2 million in 2014 from $14 million in 2013. The decrease was primarily due to the expiration of the TEFA effective December 2013 (which is offset by a corresponding decrease in Regulated T&D Electric Revenue).

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ACE

Deferred Electric Service Costs

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

Deferred Electric Service Costs decreased by $6 million to an expense of $20 million in 2014 as compared to an expense of $26 million in 2013, primarily due to a decrease in deferred electricity expense as a result of lower Default Electricity Supply revenue rates.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $5 million to a net expense of $62 million in 2014 from a net expense of $67 million in 2013. The decrease was primarily due to lower long-term debt interest expense.

Income Tax Expense

ACE’s consolidated income tax expense increased by $9 million to $28 million in 2014 from $19 million in 2013. ACE’s consolidated effective income tax rates for the years ended December 31, 2014 and 2013 were 38.4% and 27.5%, respectively. The change in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions. In the first quarter of 2013, ACE recorded an interest benefit of $6 million as discussed further below.

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 ACE is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in ACE recording a $6 million (after-tax) interest benefit in the first quarter of 2013.

Capital Requirements

Sources of Capital

ACE has a range of capital sources available, in addition to internally generated funds, to meet its long-term and short-term funding needs. The sources of long-term funding include the issuance of mortgage bonds and other debt securities and bank financings, as well as preferred stock. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures, and to repay or refinance existing indebtedness. ACE traditionally has used a number of sources to fulfill medium- and short-term funding needs, including commercial paper, medium- and short-term notes, bank lines of credit, and under certain circumstances, borrowings under the PHI money pool. 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. ACE’s ability to generate funds from its operations and to access the capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of ACE’s potential funding sources.

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ACE

Debt Securities

ACE has a Mortgage and Deed of Trust (the Mortgage) under which it issues First Mortgage Bonds. First Mortgage Bonds issued under the Mortgage are secured by a lien on substantially all of ACE’s property, plant and equipment, except for such property excluded from the lien of the Mortgage. The principal amount of First Mortgage Bonds that ACE may issue under the Mortgage is limited by the principal amount of retired First Mortgage Bonds and 65% of the lesser of the cost or fair value of new property additions that have not been used as the basis for the issuance of additional First Mortgage Bonds. ACE also has an indenture under which it issues senior notes secured by First Mortgage Bonds and an indenture under which it can issue unsecured debt securities, including VRDBs. To fund the construction of pollution control facilities, ACE also has from time to time raised capital through tax-exempt bonds, including tax-exempt VRDBs, issued by a municipality, the proceeds of which are loaned to ACE by the municipality.

Information concerning the principal amount and terms of ACE’s outstanding First Mortgage Bonds, senior notes and tax-exempt bonds issued for the benefit of ACE, as of December 31, 2014, is set forth in Note (9), “Debt,” to the consolidated financial statements of ACE.

Bank Financing

As further discussed in Note (9), “Debt,” to the consolidated financial statements of ACE, ACE is a borrower under a $1.5 billion unsecured syndicated credit facility, along with PHI, Pepco and DPL, which expires in August 2018. This credit facility provides for ACE’s liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting its commercial paper program. ACE’s credit limit under the facility is the lesser of $250 million and the maximum amount of short-term debt ACE is permitted to have outstanding by its regulatory authorities. The short-term borrowing limit established by the NJBPU for ACE is $350 million.

Commercial Paper Program

ACE maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2014, the maximum capacity available under the program was $250 million, subject to available borrowing capacity under the credit facility.

ACE had $127 million of commercial paper outstanding at December 31, 2014. The weighted average interest rate for commercial paper issued by ACE during 2014 was 0.27% and the weighted average maturity of all commercial paper issued by ACE during 2014 was five days.

Money Pool

ACE participates in the money pool operated by PHI under authorization received from the NJBPU. The money pool is an unsecured cash management mechanism used by PHI and eligible subsidiaries to manage their short-term investment and borrowing requirements. PHI may invest in, but not borrow from, the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by PHI. Eligible subsidiaries with cash requirements may borrow from the money pool. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on PHI’s short-term borrowing rate. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require PHI to borrow funds for deposit from external sources. By regulatory order, the NJBPU has restricted ACE’s participation in the PHI money pool. ACE may not invest in the money pool, but may borrow from it if the interest rates are lower than the interest rates at which ACE could borrow funds externally.

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ACE

Preferred Stock

Under its Certificate of Incorporation, ACE is authorized to issue and have outstanding up to (i) 799,979 shares of Cumulative Preferred Stock, (ii) 2 million shares of No Par Preferred Stock and (iii) 3 million shares of Preference Stock, each such type of preferred stock having such terms and conditions as are set forth in or authorized by the Certificate of Incorporation. As of December 31, 2014 and 2013, ACE had no shares of preferred stock outstanding.

Regulatory Restrictions on Financing Activities

ACE’s long-term and short-term (consisting of debt instruments with a maturity of one year or less) financing activities are subject to authorization by the NJBPU. Through its periodic filings with the NJBPU, ACE generally maintains standing authority sufficient to cover its projected financing needs over a multi-year period. ACE’s long-term and short-term financing activities do not require FERC approval.

State corporate laws impose limitations on the funds that can be used to pay dividends. In addition, ACE must obtain the 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%. As of December 31, 2014, ACE complied with this requirement without the need to seek approval of the NJBPU.

Capital Expenditures

ACE’s capital expenditures for the year ended December 31, 2014 were $225 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to ACE when the assets are placed in service.

ACE’s projected capital expenditures for the five-year period from 2015 through 2019 are summarized below. ACE expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year Ended December 31,
	2015		2016		2017		2018		2019		Total
	(millions of dollars)
ACE
Distribution	$	73	$	135	$	141	$	131	$	131	$	611
Transmission		177		164		155		134		95		725
Other		15		25		25		18		11		94
Total ACE	$	265	$	324	$	321	$	283	$	237	$	1,430

Transmission and Distribution

The projected capital expenditures listed in the table for distribution and transmission are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including continued capital expenditures for reliability enhancement efforts.

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ACE

DOE Capital Reimbursement Awards

During 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure, of which $19 million was for ACE’s service territory.

During 2010, ACE and the DOE signed agreements formalizing ACE’s $19 million share of the $168 million award. Of the $19 million, $12 million was offset against smart grid-related capital expenditures of ACE. The remaining $7 million is being used to offset incremental expenditures associated with direct load control and other programs, which have been deferred as regulatory assets. During 2014, ACE received award payments of $1 million. As of December 31, 2014, ACE has received all of its share of the DOE award payments.

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

Pension and Other Postretirement Benefit Plans

ACE participates in pension and OPEB plans sponsored by PHI for its employees. ACE contributed zero and $30 million, respectively, to the PHI Retirement Plan during 2014 and 2013. In 2014 and 2013, ACE contributed $3 million and $6 million, respectively, to the other postretirement benefit plan.

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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk management policies for PHI and its subsidiaries are determined by PHI’s Corporate Risk Management Committee (CRMC), the members of which are PHI’s Chief Risk Officer, Executive Vice President (Power Delivery), Chief Financial Officer, General Counsel, Chief Information Officer and other senior executives. The CRMC monitors interest rate fluctuation, commodity price fluctuation, and credit risk exposure, and sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements. For information about PHI’s derivative activities, other than the information otherwise disclosed herein, refer to Note (2), “Significant Accounting Policies – Accounting For Derivatives,” and Note (14), “Derivative Instruments and Hedging Activities,” of the consolidated financial statements of PHI.

Pepco Holdings, Inc.

Interest Rate Risk

Pepco Holdings’ and its subsidiaries’ variable or floating rate debt is subject to the risk of fluctuating interest rates in the normal course of business. Pepco Holdings manages interest rate risk through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term and variable rate debt was less than $1 million as of December 31, 2014.

Potomac Electric Power Company

Interest Rate Risk

Pepco’s debt is subject to the risk of fluctuating interest rates in the normal course of business. Pepco manages interest rate risk through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt and variable rate debt was less than $1 million as of December 31, 2014.

Delmarva Power & Light Company

Commodity Price Risk

DPL uses derivative instruments (for example, forward contracts, futures, swaps, and exchange-traded and over-the-counter options) primarily to reduce natural gas commodity price volatility. DPL also manages commodity risk with capacity contracts that do not meet the definition of derivatives. The primary goal of these activities is to reduce the exposure of its regulated retail natural gas customers to natural gas price spikes. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses on the natural gas hedging activity, are fully recoverable through the GCR clause included in DPL’s natural gas tariff rates approved by the DPSC and are deferred until recovered. At December 31, 2014 and 2013, after the effects of cash collateral and netting of derivative assets and liabilities available to be offset under master netting arrangements, DPL had no net derivative assets or liabilities.

Interest Rate Risk

DPL’s debt is subject to the risk of fluctuating interest rates in the normal course of business. DPL manages interest rate risk through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt and variable rate debt was less than $1 million as of December 31, 2014.

134

Atlantic City Electric Company

Interest Rate Risk

ACE’s debt is subject to the risk of fluctuating interest rates in the normal course of business. ACE manages interest rate risk through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt and variable rate debt was less than $1 million as of December 31, 2014.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Listed below is a table that sets forth, for each registrant, the page number where the information is contained herein.

	Registrants
Item	Pepco Holdings		Pepco *		DPL *		ACE
Management’s Report on Internal Control Over Financial Reporting		137		228		269		310
Report of Independent Registered Public Accounting Firm		138		229		270		311
Consolidated Statements of Income (Loss)		140		230		271		312
Consolidated Statements of Comprehensive Income (Loss)		141		N/A		N/A		N/A
Consolidated Balance Sheets		142		231		272		313
Consolidated Statements of Cash Flows		144		233		274		315
Consolidated Statements of Equity		145		234		275		316
Notes to Consolidated Financial Statements		146		235		276		317

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

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Management’s Report on Internal Control Over Financial Reporting

The management of Pepco Holdings, Inc. (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, 2014 based on criteria established in theInternal Control – Integrated Framework (2013) 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, 2014.

PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the consolidated financial statements of Pepco Holdings included in this 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, 2014 and December 31, 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, based on criteria established in theInternal Control—Integrated Framework (2013) 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 26, 2015

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

For the Year Ended December 31,	2014			2013			2012
	(millions of dollars, except per share data)
Operating Revenue	$	4,878		$	4,666		$	4,625
Operating Expenses
Fuel and purchased energy		2,080			2,070			2,123
Other services cost of sales		207			146			170
Other operation and maintenance		924			851			898
Depreciation and amortization		549			473			454
Other taxes		413			428			432
Deferred electric service costs		20			26			(5	)
Impairment losses		81			4			12
Total Operating Expenses		4,274			3,998			4,084
Operating Income		604			668			541
Other Income (Expenses)
Interest and dividend income		—			—			1
Interest expense		(268	)		(273	)		(256	)
Gain from equity investments		—			2			1
Impairment losses		—			—			(1	)
Other income		44			32			35
Total Other Expenses		(224	)		(239	)		(220	)
Income from Continuing Operations Before Income Tax Expense		380			429			321
Income Tax Expense Related to Continuing Operations		138			319			103
Net Income from Continuing Operations		242			110			218
(Loss) Income from Discontinued Operations, net of Income Taxes		—			(322	)		67
Net Income (Loss)	$	242		$	(212	)	$	285
Basic Share Information
Weighted average shares outstanding—Basic (millions)		251			246			229
Earnings per share of common stock from Continuing Operations—Basic	$	0.96		$	0.45		$	0.95
(Loss) earnings per share of common stock from Discontinued Operations—Basic		—			(1.31	)		0.30
Earnings (loss) per share—Basic	$	0.96		$	(0.86	)	$	1.25
Diluted Share Information
Weighted average shares outstanding—Diluted (millions)		252			246			230
Earnings per share of common stock from Continuing Operations—Diluted	$	0.96		$	0.45		$	0.95
(Loss) earnings per share of common stock from Discontinued Operations—Diluted		—			(1.31	)		0.29
Earnings (loss) per share—Diluted	$	0.96		$	(0.86	)	$	1.24

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

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Year Ended December 31,	2014			2013			2012
	(millions of dollars)
Net Income (Loss)	$	242		$	(212	)	$	285
Other Comprehensive Income (Loss) from Continuing Operations
Losses on treasury rate locks reclassified into income		1			1			—
Pension and other postretirement benefit plans		(20	)		13			(14	)
Other comprehensive (loss) income, before income taxes		(19	)		14			(14	)
Income tax (benefit) expense related to other comprehensive income		(7	)		6			(6	)
Other comprehensive (loss) income from continuing operations, net of income taxes		(12	)		8			(8	)
Other Comprehensive Income from Discontinued Operations, Net of Income Taxes		—			6			23
Comprehensive Income (Loss)	$	230		$	(198	)	$	300

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, 2014			December 31, 2013
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	14		$	23
Restricted cash equivalents		25			13
Accounts receivable, less allowance for uncollectible accounts of $40 million and $38 million, respectively		782			835
Inventories		141			148
Deferred income tax assets, net		50			51
Income taxes and related accrued interest receivable		9			274
Prepaid expenses and other		63			54
Total Current Assets		1,084			1,398
OTHER ASSETS
Goodwill		1,407			1,407
Regulatory assets		2,409			2,087
Income taxes and related accrued interest receivable		81			75
Restricted cash equivalents		14			14
Other		166			163
Total Other Assets		4,077			3,746
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		15,465			14,567
Accumulated depreciation		(4,959	)		(4,863	)
Net Property, Plant and Equipment		10,506			9,704
TOTAL ASSETS	$	15,667		$	14,848

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, 2014			December 31, 2013
	(millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	729		$	565
Current portion of long-term debt and project funding		431			446
Accounts payable		174			215
Accrued liabilities		313			301
Capital lease obligations due within one year		10			9
Taxes accrued		41			56
Interest accrued		47			47
Liabilities and accrued interest related to uncertain tax positions		6			397
Other		314			277
				��
Total Current Liabilities		2,065			2,313
DEFERRED CREDITS
Regulatory liabilities		343			399
Deferred income tax liabilities, net		3,266			2,928
Investment tax credits		16			17
Pension benefit obligation		396			116
Other postretirement benefit obligations		265			206
Liabilities and accrued interest related to uncertain tax positions		2			28
Other		193			189
Total Deferred Credits		4,481			3,883
OTHER LONG-TERM LIABILITIES
Long-term debt		4,441			4,053
Transition bonds issued by ACE Funding		171			214
Long-term project funding		8			10
Capital lease obligations		50			60
Total Other Long-Term Liabilities		4,670			4,337
COMMITMENTS AND CONTINGENCIES (NOTE 16)
PREFERRED STOCK
Series A preferred stock, $.01 par value, 18,000 shares authorized, 12,600 and zero shares outstanding, respectively		129			—
EQUITY
Common stock, $.01 par value—400,000,000 shares authorized, 252,728,684 and 250,324,898 shares outstanding, respectively		3			3
Premium on stock and other capital contributions		3,800			3,751
Accumulated other comprehensive loss		(46	)		(34	)
Retained earnings		565			595
Total Equity		4,322			4,315
TOTAL LIABILITIES AND EQUITY	$	15,667		$	14,848

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,	2014			2013			2012
	(millions of dollars)
OPERATING ACTIVITIES
Net income (loss)	$	242		$	(212	)	$	285
Loss (income) from discontinued operations, net of income taxes		—			322			(67	)
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		549			473			454
Deferred income taxes		302			458			312
Gains on sales of land		(9	)		—			—
Losses on treasury rate locks reclassified into income		1			1			—
Impairment losses		81			4			12
Other		3			(13	)		(15	)
Changes in:
Accounts receivable		48			(46	)		(2	)
Inventories		7			5			(28	)
Prepaid expenses		(8	)		17			(12	)
Regulatory assets and liabilities, net		(216	)		(121	)		(174	)
Accounts payable and accrued liabilities		(22	)		1			43
Pension contributions		—			(120	)		(200	)
Pension benefit obligation, excluding contributions		48			65			65
Cash collateral related to derivative activities		(9	)		31			88
Income tax-related prepayments, receivables and payables		(173	)		(182	)		(160	)
Advanced payment made to taxing authority		—			(242	)		—
Other assets and liabilities		10			9			16
Net current assets held for disposition or sale		—			47			(25	)
Net Cash From Operating Activities		854			497			592
INVESTING ACTIVITIES
Investment in property, plant and equipment		(1,223	)		(1,310	)		(1,216	)
Department of Energy capital reimbursement awards received		4			22			40
Proceeds from sales of land		9			—			—
Changes in restricted cash equivalents		(12	)		1			(1	)
Net other investing activities		(4	)		3			6
Proceeds from discontinued operations, early termination of finance leases held in trust		—			873			202
Net Cash Used By Investing Activities		(1,226	)		(411	)		(969	)
FINANCING ACTIVITIES
Dividends paid on common stock		(272	)		(270	)		(248	)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan (DRP) and employee-related compensation		34			50			51
Issuances of common stock		—			324			—
Issuances of Series A preferred stock		126			—			—
Issuances of long-term debt		766			800			450
Reacquisitions of long-term debt		(334	)		(558	)		(176	)
Issuances (repayments) of short-term debt, net		164			(200	)		33
Issuances of term loans		—			250			200
Repayments of term loans		(100	)		(450	)		—
Cost of issuances		(10	)		(23	)		(9	)
Net other financing activities		(11	)		(11	)		(8	)
Net Cash From (Used By) Financing Activities		363			(88	)		293
Net Decrease In Cash and Cash Equivalents		(9	)		(2	)		(84	)
Cash and Cash Equivalents at Beginning of Year		23			25			109
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	14		$	23		$	25
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $8 million, $7 million and $8 million, respectively)	$	257		$	260		$	253
Cash (received) paid for income taxes		(2	)		228			—
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

	Common Stock					Premium		Accumulated Other Comprehensive			Retained
(millions of dollars, except shares)	Shares			Par Value		on Stock		(Loss) Income			Earnings			Total
Balance as of 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
DRP original shares		1,661,177			—		32		—			—			32
Net activity related to stock-based awards		—			—		7		—			—			7
Balance as of December 31, 2012		230,015,427			2		3,383		(48	)		1,077			4,414
Net Loss		—			—		—		—			(212	)		(212	)
Other comprehensive income		—			—		—		14			—			14
Dividends on common stock ($1.08 per share)		—			—		—		—			(270	)		(270	)
Issuance of common stock:
Original issue shares, net		18,734,128			1		331		—			—			332
DRP original shares		1,575,343			—		30		—			—			30
Net activity related to stock-based awards		—			—		7		—			—			7
Balance as of December 31, 2013		250,324,898			3		3,751		(34	)		595			4,315
Net Income		—			—		—		—			242			242
Other comprehensive loss		—			—		—		(12	)		—			(12	)
Dividends on common stock ($1.08 per share)		—			—		—		—			(272	)		(272	)
Issuance of common stock:
Original issue shares, net		1,310,276					14		—			—			14
DRP original shares		1,122,575			—		28		—			—			28
Net activity related to stock-based awards		(29,065	)		—		7		—			—			7
Balance as of December 31, 2014		252,728,684		$	3	$	3,800	$	(46	)	$	565		$	4,322

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, underground transmission and distribution construction and maintenance services, and steam and chilled water under long-term contracts.

PHI Service Company, a wholly owned 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 service agreements 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 agreements.

Agreement and Plan of Merger with Exelon Corporation

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect, wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, as further described in Note (13), “Preferred Stock,” PHI entered into a Subscription Agreement with Exelon dated April 29, 2014 (the Subscription Agreement), pursuant to which PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million on April 30, 2014. Exelon also committed, pursuant to the

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Subscription Agreement, to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014 and January 26, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for a purchase price of $18 million.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (7), “Regulatory Matters – Merger Approval Proceedings.”

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. On December 22, 2014, the applicable waiting period under the HSR Act expired, and the HSR Act no longer precludes completion of the Merger. Although the Department of Justice (DOJ) allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised PHI that it has concluded its investigation. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015. On February 13, 2015, Pepco Holdings, DPL, Exelon, certain of Exelon’s affiliates, the Staff of the DPSC and certain other parties, filed a settlement agreement with the DPSC with respect to the Merger. This settlement agreement is subject to approval by the DPSC.

The Merger Agreement may be terminated by each of PHI and Exelon under certain circumstances, including if the Merger is not consummated by July 29, 2015 (subject to extension by PHI or Exelon to October 29, 2015, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Merger Agreement also provides for certain termination rights for both PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain such regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

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Power Delivery

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

Each utility is responsible for the distribution of electricity, and in the case of DPL, the distribution and supply of natural gas, in its service territory, for which it is paid tariff rates established by the applicable local public service commissions. Each utility also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Offer Service (SOS) 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:

• Energy savings performance contracting business: designing, constructing and operating energy efficiency projects and distributed generation equipment, including combined heat and power plants, principally for federal, state and local government customers;

• Underground transmission and distribution business: providing underground transmission and distribution construction and maintenance services for electric utilities in North America; and

• Thermal business: providing steam and chilled water under long-term contracts through systems owned and operated by Pepco Energy Services, primarily to hotels and casinos in Atlantic City, New Jersey.

During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services is demolishing the Benning Road generation facility and realizing the scrap metal salvage value of the facility. The demolition of the facility commenced in the fourth quarter of 2013 and is expected to be completed in the first quarter of 2015. Pepco Energy Services is recognizing the salvage proceeds associated with the scrap metals at the facility as realized.

Corporate and Other

Between 1990 and 1999, Potomac Capital Investment Corporation (PCI), a wholly owned subsidiary of PHI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the Internal Revenue Service (IRS) with respect to other taxpayers’ cross-border lease and other structured transactions (see “Discontinued Operations – Cross-Border Energy Lease Investments” below), (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases, and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represented a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI would be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013.

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Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of all relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances.

Discontinued Operations

Cross-Border Energy Lease Investments

Through its subsidiary PCI, PHI held a portfolio of cross-border energy lease investments. During 2013, PHI completed the termination of its interest in its cross-border energy lease investments and, as a result, these investments have been accounted for as 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.

(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 (VIEs) 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. See Note (17), “Variable Interest Entities,” for additional information.

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.

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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 loss contingency liabilities for general litigation and auto and other liability claims, accrual of interest related to income taxes, the recognition of lease income and income tax benefits for investments in finance leases held in trust associated with PHI’s former cross-border energy lease investments (see Note (20), “Discontinued Operations – 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.

Revenue Recognition

Regulated Revenue

Power Delivery recognizes revenue upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered but not yet billed. PHI’s unbilled revenue was $172 million and $177 million as of December 31, 2014 and 2013, 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 natural 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 natural 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 natural 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.

Pepco Energy Services Revenue

Revenue for Pepco Energy Services’ energy savings performance construction business and certain construction contracts in its underground transmission and distribution business is recognized using the percentage-of-completion method which recognizes revenue as work is completed and costs are incurred on its contracts. Under this method, Pepco Energy Services recognizes these contractual revenues based on the percentage of incurred costs relative to the estimated costs to complete a contract. Revenues from its operation and maintenance activities and measurement and verification activities in its energy savings business and certain construction contracts in its underground transmission and distribution business are recognized when earned.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in PHI’s gross revenues were $321 million, $346 million and $356 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Accounting for Derivatives

PHI and its subsidiaries may use derivative instruments primarily to manage risk associated with commodity prices and interest rates. Risk management policies are determined by PHI’s Corporate Risk

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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.

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

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.

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 in the consolidated statements of income (loss).

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 (loss) 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.

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 may also be used to determine fair value. For some custom and complex instruments, internal models use market-based information when external broker quotes are not available. For certain long-dated instruments, broker or exchange data are extrapolated, or capacity prices are forecasted, for future periods where information is limited. Models are also used to estimate volumes for certain transactions.

PHI may enter into master netting arrangements to mitigate credit risk related to its derivatives. Under FASB guidance on offsetting of balance sheet accounts (ASC 210-20), amounts recognized for derivative assets and liabilities and the fair value amounts recognized for any related collateral positions executed with the same counterparty under such master netting agreements are offset.

See Note (14), “Derivative Instruments and Hedging Activities,” for more information about the types of derivatives employed by PHI, the components of any unrealized and realized gains and losses and Note (15), “Fair Value Disclosures,” for the methodologies used to value them.

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. 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, restricted stock and restricted stock unit awards, which are deductible only upon exercise and/or vesting.

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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 estimated the fair value of stock option awards on the date of grant using the Black-Scholes-Merton option pricing model. This model used assumptions related to expected term, expected volatility, expected dividend yield, and the risk-free interest rate. PHI used historical data to estimate award exercises and employee terminations within the valuation model; groups of employees that have similar historical exercise behavior were 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 2002 in connection with the establishment of PHI as a public utility 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 (11), “Income 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 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.

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Accounts Receivable and Allowance for Uncollectible Accounts

PHI’s Accounts receivable balances primarily consist of customer accounts receivable arising from the sale of goods and services to customers within PHI’s service territories, other accounts receivable, and accrued unbilled revenue. 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 (loss). 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. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although PHI 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

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.

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. PHI 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 (that is, a greater than 50% chance) reduce the estimated 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 significantly below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its most recent annual impairment test as of November 1, 2014, 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 DCPSC and the 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.

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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 and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. 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.

Leasing Activities

Pepco Holdings’ lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (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 was an equity participant, was accounted for using the financing method. In accordance with the financing method, investments in leased property were recorded as a receivable from the lessee to be recovered through the collection of future rentals. Income was recognized over the life of the lease at a constant rate of return on the positive net investment. Each quarter, PHI reviewed the carrying value of each lease, which included 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, were 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 occurred.

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.

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Arrangements Containing a Lease

PPAs are deemed to 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.

The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. 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, 2014, 2013 and 2012.

	Transmission and Distribution									Generation
	2014			2013			2012			2014			2013			2012
Pepco		2.3	%		2.2	%		2.5	%		—			—			—
DPL		2.6	%		2.6	%		2.7	%		—			—			—
ACE		2.6	%		2.8	%		3.0	%		—			—			—
Pepco Energy Services		—			—			—			1.2	%		0.4	%		6.4	%(a)

(a) Percentage reflects 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 (DOE) under the American Recovery and Reinvestment Act of 2009. Pepco was awarded $149 million from DOE 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 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 from DOE 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 award proceeds as a reduction in the carrying value of the assets acquired rather than grant income over the service period.

Long-Lived Asset Impairment Evaluation

PHI 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 its estimated 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 estimated fair value including costs to sell.

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Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), PHI’s utility subsidiaries may 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 (loss).

Pepco Holdings recorded AFUDC for borrowed funds of $7 million, $7 million and $7 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Pepco Holdings recorded amounts for the equity component of AFUDC of $13 million, $11 million and $14 million for the years ended December 31, 2014, 2013 and 2012, 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, 2014 and 2013, $250 million and $275 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying consolidated balance sheets.

Pension and Postretirement Benefit Plans

PHI sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other PHI subsidiaries (the PHI Retirement Plan). PHI also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. Most employees hired after January 1, 2005 will not have retiree health care coverage.

Net periodic benefit cost is included in Other operation and maintenance expense, net of the portion of the net periodic benefit cost 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.

PHI 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 (9), “Pension and Other Postretirement Benefits,” for additional information.

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Reclassifications

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

(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Liabilities (ASC 405)

In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, PHI is required to measure such obligations as the sum of the amount it agreed to pay on the basis of its arrangement among co-obligors and any additional amount it expects to pay on behalf of its co-obligors. Adoption of this guidance during the first quarter of 2014 did not have a material impact on PHI’s consolidated financial statements.

Income Taxes (ASC 740)

In July 2013, the FASB issued new guidance requiring netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of the uncertain tax position. The prospective adoption of this guidance at March 31, 2014 resulted in PHI netting liabilities related to uncertain tax positions with deferred tax assets for net operating loss and other carryforwards (included in Deferred income tax liabilities, net) and income taxes receivable (including income tax deposits) related to effectively settled uncertain tax positions.

(4)RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements are effective for PHI beginning January 1, 2017, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2017. Early adoption is not permitted. PHI is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select.

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Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon closes.

(5)SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at December 31, 2014 as Power Delivery and Pepco Energy Services. 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. During 2013, PHI completed the termination of its interests in its cross-border energy lease investments that had been maintained by PHI through its wholly- owned subsidiary, PCI. As a result, the cross-border energy lease investments, which comprised substantially all of the operations of the former Other Non-Regulated segment, have been accounted for as discontinued operations. The remaining operations of the former Other Non-Regulated segment, which no longer meet the definition of a separate segment for financial reporting purposes, have been included in Corporate and Other. Segment financial information for continuing operations at and for the years ended December 31, 2014, 2013 and 2012, is as follows:

	Year Ended December 31, 2014
	Power Delivery		Pepco Energy Services			Corporate and Other (a)			PHI Consolidated
	(millions of dollars)
Operating Revenue	$	4,607	$	278		$	(7	)	$	4,878
Operating Expenses (b)		3,916		354	(c)		4			4,274
Operating Income (Loss)		691		(76	)		(11	)		604
Interest Expense		226		1			41			268
Other Income		40		2			2			44
Income Tax Expense (Benefit)		185		(36	)		(11	)		138
Net Income (Loss) from Continuing Operations		320		(39	)		(39	)		242
Total Assets		13,719		244			1,704			15,667
Construction Expenditures	$	1,144	$	3		$	76		$	1,223

(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 Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(7) million for Operating Revenue, $(7) million for Operating Expenses and $(4) million for Interest Expense.

(b) Includes depreciation and amortization expense of $549 million, consisting of $511 million for Power Delivery, $7 million for Pepco Energy Services and $31 million for Corporate and Other.

(c) Includes impairment losses of $81 million ($48 million after-tax) associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City.

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	Year Ended December 31, 2013
	Power Delivery		Pepco Energy Services			Corporate and Other (a)			PHI Consolidated
	(millions of dollars)
Operating Revenue	$	4,472	$	203		$	(9	)	$	4,666
Operating Expenses (b)		3,828		201	(c)		(31	)		3,998
Operating Income		644		2			22			668
Interest Expense		228		1			44			273
Other Income		28		3			3			34
Income Tax Expense (d)		155		1			163	(e)		319
Net Income (Loss) from Continuing Operations		289		3			(182	)		110
Total Assets		13,027		335			1,486			14,848
Construction Expenditures	$	1,194	$	4		$	112		$	1,310

(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 Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(10) million for Operating Revenue, $(9) million for Operating Expenses and $(5) million for Interest Expense.

(b) Includes depreciation and amortization expense of $473 million, consisting of $439 million for Power Delivery, $6 million for Pepco Energy Services and $28 million for Corporate and Other.

(c) Includes impairment losses of $4 million ($3 million after-tax) associated with Pepco Energy Services’ landfill gas-fired electric generation facility.

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

(e) Includes non-cash charges of $101 million representing the establishment of valuation allowances against certain deferred tax assets of PCI included in Corporate and Other.

	Year Ended December 31, 2012
	Power Delivery		Pepco Energy Services			Corporate and Other (a)			PHI Consolidated
	(millions of dollars)
Operating Revenue	$	4,378	$	256	(b)	$	(9	)	$	4,625
Operating Expenses (c)		3,847		271	(b)(d)		(34	)		4,084
Operating Income (Loss)		531		(15	)		25			541
Interest Income		1		1			(1	)		1
Interest Expense		219		2			35			256
Impairment Losses		—		—			(1	)		(1	)
Other Income		32		1			3			36
Income Tax Expense (Benefit)		110		(7	)		—			103
Net Income (Loss) from Continuing Operations		235		(8	)		(9	)		218
Total Assets (excluding Assets Held for Disposition)		12,149		342			2,028			14,519
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 Corporate and Other 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 and $(18) million for Interest Expense.

(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 and $24 million for Corporate and Other.

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

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(6)GOODWILL

Substantially all of PHI’s goodwill balance as of December 31, 2014 and 2013 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 performs an annual impairment assessment as of November 1 each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill relates is less than its carrying value. In evaluating goodwill for impairment, PHI first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. For reporting units in which PHI concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and PHI is not required to perform the two-step goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, including the price per share offered by potential acquirers of PHI during 2014, overall financial performance, lack of significant changes in any key inputs to the prior year impairment test, including the discount rate and forecasted cash flows, and other relevant events and factors affecting the reporting unit.

For reporting units in which PHI concludes that it is more likely than not that the fair value is less than its carrying value, PHI performs the first step of the goodwill impairment test, which compares the fair value of the reporting unit to its carrying value. If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and PHI is not required to perform additional testing. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, then PHI must perform the second step of the goodwill impairment test to determine the implied fair value of the reporting unit’s goodwill. If PHI determines during this second step that the carrying value of a reporting unit’s goodwill exceeds its implied fair value, PHI records an impairment loss equal to the difference.

For the annual impairment assessment in 2014, PHI qualitatively determined for each of its reporting units that it was more likely than not that fair value exceeded carrying value. As a result, PHI did not perform the two-step goodwill impairment test on those reporting units.

As of December 31, 2014 and 2013, PHI’s goodwill balance was $1,407 million, which is net of accumulated impairment losses of $18 million.

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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, 2014 and 2013 are as follows:

	2014		2013
	(millions of dollars)
Regulatory Assets
Pension and other postretirement benefit costs	$	946	$	667
Securitized stranded costs		278		350
Recoverable income taxes		274		225
Demand-side management costs		264		125
Smart Grid costs		261		251
Deferred energy supply costs		73		136
Incremental storm restoration costs		51		72
Deferred debt extinguishment costs		42		47
MAPP abandonment costs		33		68
Recoverable workers’ compensation and long-term disability costs		30		26
Deferred losses on gas derivatives		4		—
Other		153		120
Total Regulatory Assets	$	2,409	$	2,087
Regulatory Liabilities
Asset removal costs	$	250	$	275
Deferred income taxes due to customers		44		45
Deferred energy supply costs		3		46
Deferred gains on gas derivatives		—		1
Other		46		32
Total Regulatory Liabilities	$	343	$	399

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

Pension and OPEB Costs: Represents unrecognized net actuarial losses and prior service cost (credit) 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 (9), “Pension and Other Postretirement Benefits,” for more information about the components of the unrecognized pension and OPEB costs. PHI does not earn a return on these regulatory assets.

Securitized Stranded Costs: Certain contract termination payments under a contract between ACE and an unaffiliated non-utility generator (NUG) and costs associated with the regulated operations of ACE’s 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 Atlantic City Electric Transition Funding LLC (ACE Funding) (Transition Bonds) to securitize the recoverability of these stranded costs. These bonds mature between 2015 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. PHI earns a return on these regulatory assets.

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 record 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.

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Demand-Side Management Costs:Represents costs associated with customer energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. PHI earns a return on these regulatory assets.

Smart Grid Costs:Represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout Pepco’s and DPL’s service territories that are recoverable from customers. AMI has not been approved by the NJBPU for ACE in New Jersey. PHI generally is deferring carrying charges on these regulatory assets.

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 being or are expected to be recovered from customers. PHI generally earns a return on these regulatory assets. 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.

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), that are recoverable from customers in the Maryland and New Jersey jurisdictions. Pepco’s and DPL’s costs related to Hurricane Sandy, the June 2012 derecho, Hurricane Irene and Pepco’s costs related to the 2011 severe winter storm are being amortized and recovered from customers, each over a five-year period. ACE’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a three-year period. PHI does not earn a return on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment of Pepco, DPL and ACE that are amortized to interest expense and recovered from customers. PHI generally earns a return on these regulatory assets.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated by PJM Interconnection, LLC (PJM) on August 24, 2012. For additional information, see “MAPP Settlement Agreement” discussion below. These regulatory assets are being amortized and recovered in transmission rates through May 2016. PHI generally does not earn a return on these regulatory assets.

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. PHI does not earn a return on these regulatory assets.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable from customers through the Gas Cost Rate (GCR) approved by the DPSC. PHI does not earn a return on these regulatory assets.

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

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.

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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.

Deferred Gains on Gas Derivatives: Represents gains associated with hedges of natural gas purchases that will be refunded to customers through the GCR approved by the DPSC.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

The following table shows, for each of PHI’s utility subsidiaries, the distribution base rate cases completed in 2014. Additional information concerning each of these cases is provided in the discussion below.

Jurisdiction/Company	Approved Revenue Requirement Increase		Approved Return on Equity			Completion Date	Rate Effective Date
	(millions of dollars)
DC – Pepco	$	23.4		9.40	%	March 26, 2014	April 16, 2014
DE – DPL (Electric)	$	15.1		9.70	%	August 5, 2014	May 1, 2014
MD – Pepco	$	8.8		9.62	%	July 2, 2014	July 4, 2014
NJ – ACE	$	19.0		9.75	%	August 20, 2014	September 1, 2014

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below.

Bill Stabilization Adjustment

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 has been approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia.

• A proposed modified fixed variable rate design (MFVRD) for DPL electric and natural gas service in Delaware was filed in 2009 for consideration by the DPSC and while there was little to no activity associated with this filing in 2014 or to date in 2015, the proceeding remains open.

• 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 proposed in Delaware contemplates 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.

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Delaware

Electric Distribution Base Rates

On March 22, 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The application sought approval of an annual rate increase of approximately $42 million (adjusted by DPL to approximately $39 million on September 20, 2013), based on a requested return on equity (ROE) of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. On August 5, 2014, the DPSC issued a final order in this proceeding providing for an annual increase in DPL’s electric distribution base rates of approximately $15.1 million, based on an ROE of 9.70%. The new rates became effective on May 1, 2014.

On September 4, 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 5, 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and recovery of credit facility expenses. The Division of the Public Advocate filed a cross-appeal on September 8, 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” the parties have agreed to suspend the appeal and to withdraw the appeal with prejudice upon the closing of the Merger.

Under the Merger Agreement, DPL is not permitted to initiate or file any new electric distribution base rate cases in Delaware without Exelon’s consent.

Forward Looking Rate Plan

On October 2, 2013, DPL filed a multi-year rate plan, referred to as the Forward Looking Rate Plan (FLRP). As proposed, the FLRP would provide for annual electric distribution base rate increases over a four-year period in the aggregate amount of approximately $56 million. The FLRP as proposed provides the opportunity to achieve estimated earned ROEs of 7.41% and 8.80% in years one and two, respectively, and 9.75% in both years three and four of the plan.

In addition, DPL proposed that as part of the FLRP, in order to provide a higher minimum required standard of reliability for DPL’s customers than that to which DPL is currently subject, the standards by which DPL’s reliability is measured would be made more stringent in each year of the FLRP. DPL has also offered to refund an aggregate of $500,000 to customers in each year of the FLRP that it fails to meet the proposed stricter minimum reliability standards.

On October 22, 2013, the DPSC opened a docket for the purpose of reviewing the details of the FLRP, but stated that it would not address the FLRP until the electric distribution base rate case discussed above was concluded. A schedule for the FLRP docket has not yet been established.

Under the Merger Agreement, DPL is permitted to pursue this matter; however, under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” DPL has agreed to withdraw the FLRP without prejudice to refile it in a subsequent base rate case.

Gas Distribution Base Rates

A settlement approved in October 2013 by the DPSC in a proceeding filed by DPL in December 2012 to increase its natural gas distribution base rates provides in part for a phase-in of the recovery of the deferred costs associated with DPL’s deployment of the interface management unit (IMU). The IMU is part of DPL’s AMI and allows for the remote reading of gas meters. Filing for recovery of such costs will occur in two phases, subject to compliance with specific metrics, with recovery over a 15-year period. For the first phase, 50% of the IMU-related portion of DPL’s AMI costs were put into rates on July 11, 2014.

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The remainder of these costs will be put into rates in the second phase when the specific metrics allowing for recovery are met.

Under the Merger Agreement, DPL is not permitted to initiate or file any new gas distribution base rate cases without Exelon’s consent.

Gas Cost Rates

DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. On August 29, 2014, DPL made its 2014 GCR filing in which it proposed a GCR decrease of approximately 7.4%. On September 30, 2014, the DPSC issued an order authorizing DPL to place the new rates into effect on November 1, 2014, subject to refund and pending final DPSC approval.

Under the Merger Agreement, DPL is permitted and intends to continue to file its required annual GCR cases in Delaware.

District of Columbia

On March 8, 2013, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by approximately $52.1 million (adjusted by Pepco to approximately $44.8 million on December 3, 2013), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. On March 26, 2014, the DCPSC issued an order approving an increase in base rates of approximately $23.4 million, based on an ROE of 9.40%. The new rates became effective on April 16, 2014.

Under the Merger Agreement, Pepco is not permitted to initiate or file any new electric distribution base rate cases in the District of Columbia without Exelon’s consent.

Maryland

Pepco Electric Distribution Base Rates

Under the Merger Agreement, Pepco is permitted, and intends to continue, to pursue the conclusion of the following matters. However, Pepco is not permitted to initiate or file any new electric distribution base rate cases in Maryland without Exelon’s consent.

2011 Base Rate Proceeding

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 adjusted by Pepco to approximately $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorized Pepco to recover the actual cost of AMI meters installed during the 2011 test year, stating that cost recovery for AMI deployment will be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new rates became effective on July 20, 2012. The Maryland Office of People’s Counsel (OPC) has sought rehearing on the portion of the order allowing Pepco to recover the costs of AMI meters installed during the test year; that motion remains pending.

2012 Base Rate Proceeding

On November 30, 2012, 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 $60.8 million, based on a requested ROE of 10.25%.

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On July 12, 2013, the MPSC issued an order related to Pepco’s November 30, 2012 application approving an annual rate increase of approximately $27.9 million, based on an ROE of 9.36%. The order excludes the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; as a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates. However, the MPSC’s July 2012 order in Pepco’s previous electric distribution base rate case, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect, and the Maryland OPC’s motion for rehearing in that case remains pending.

The July 12, 2013 order also approved a Grid Resiliency Charge, which went into effect on January 1, 2014, for recovery of costs totaling approximately $24.0 million associated with Pepco’s proposed plan to accelerate investments related to certain priority feeders, provided that, before implementing the surcharge, Pepco (i) provides additional information to the MPSC related to performance objectives, milestones and costs, and (ii) makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for each following year. The MPSC rejected certain other cost recovery mechanisms, including Pepco’s proposed reliability performance-based mechanism. The new rates were effective on July 12, 2013.

On July 26, 2013, Pepco filed a notice of appeal of the July 12, 2013 order in the Circuit Court for Baltimore City. Other parties also filed notices of appeal, which were consolidated with Pepco’s appeal. In its appeal, Pepco asserted that the MPSC erred in failing to grant Pepco an adequate ROE, denying a number of other cost recovery mechanisms and limiting Pepco’s test year data to no more than four months of forecasted data in future rate cases. The other parties primarily asserted that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco, in approving the Grid Resiliency Charge, and in refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. On November 14, 2014, the Circuit Court issued an order reversing the MPSC’s decision on Pepco’s ROE and directing the MPSC to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE. On all other issues appealed, the Circuit Court affirmed the MPSC’s July 12, 2013 order. Pepco will not appeal this decision, but other parties have filed notices of appeal of the Circuit Court’s decision to the Court of Special Appeals.

Phase II Proceeding to 2012 Base Rate Proceeding

On August 26, 2014, the MPSC issued an order establishing a Phase II proceeding pertaining to the base rate case filed in November 2012 to address an issue regarding Pepco’s net operating loss carryforward (NOLC). The issue in this Phase II proceeding is the same as for the Phase II proceeding described below. Pepco filed a motion to dismiss this Phase II proceeding, asserting that the MPSC no longer has jurisdiction over the 2012 base rate case due to appeals having been filed by numerous parties. On September 11, 2014, the MPSC issued an order staying this Phase II proceeding until further notice.

2013 Base Rate Proceeding

On December 4, 2013, 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 $43.3 million (adjusted by Pepco to approximately $37.4 million on April 15, 2014), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. On July 2, 2014, the MPSC issued an order approving an annual rate increase of approximately $8.75 million, based on an ROE of 9.62%. The new rates became effective on July 4, 2014. On July 31, 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order dated November 13, 2014. On December 11, 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. This petition remains pending.

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Phase II Proceeding to 2013 Base Rate Proceeding

On August 26, 2014, the MPSC issued an order establishing a Phase II proceeding pertaining to the base rate case filed in December 2013 to address an issue regarding Pepco’s NOLC. Specifically, the MPSC considered the tax implications of Pepco’s NOLC, which had impacted certain of Pepco’s rate adjustments in the 2013 base rate proceeding. On November 13, 2014, the MPSC issued its order in this Phase II proceeding upholding Pepco’s treatment of the NOLC.

New Jersey

Electric Distribution Base Rates

On March 14, 2014, ACE submitted an application with the NJBPU to increase its electric distribution base rates by approximately $61.7 million (excluding sales and use taxes), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with ACE’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. On August 20, 2014, the NJBPU approved a Stipulation of Settlement entered into by ACE, NJBPU staff and the Division of Rate Counsel (DRC). The approved stipulation of settlement provides for an annual increase in ACE’s electric distribution base rates by the net amount of approximately $19.0 million (excluding sales and use taxes), based on a specified ROE of 9.75%. The new electric distribution base rates became effective for service rendered by ACE on and after September 1, 2014. The annual pre-tax earnings impact of the rate increase is approximately $19.0 million.

Under the Merger Agreement, ACE is not permitted to initiate or file any new electric distribution base rate cases in New Jersey without Exelon’s consent.

Update and Reconciliation of Certain Under-Recovered Balances

On March 3, 2014, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The net impact of adjusting the charges as proposed would have been an overall annual rate decrease of approximately $24.5 million (revised to a decrease of approximately $41.1 million on April 16, 2014, based upon an update for actual data through March 2014). In May 2014, the NJBPU approved a stipulation of settlement entered into by the parties in this proceeding providing for an overall annual rate decrease of $41.1 million. The rate decrease was placed into effect provisionally on June 1, 2014, subject to a review by the NJBPU of the final underlying costs for reasonableness and prudence. On January 21, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect on June 1, 2014. The rate decrease will have no effect on ACE’s operating income.

This proceeding is not expected to be affected by the Merger Agreement.

Service Extension Contributions Refund Order

On July 19, 2013, in compliance with a 2012 Superior Court of New Jersey Appellate Division (Appellate Division) court decision, the NJBPU released an order requiring utilities to issue refunds to persons or entities that paid non-refundable contributions for utility service extensions to certain areas described as “Areas Not Designated for Growth.” The order is limited to eligible contributions paid between March 20, 2005 and December 20, 2009. ACE is processing the refund requests that meet the eligibility criteria

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established in the order as they are received. Although ACE estimates that it received approximately $11 million of contributions between March 20, 2005 and December 20, 2009, it is currently unable to reasonably estimate the amount that it may be required to refund using the eligibility criteria established by the order. Since the July 2013 order was released, ACE has received less than $1 million in refund claims, the validity of which is being investigated by ACE prior to making any such refunds. At this time, ACE does not expect that any such amount refunded will have a material effect on its consolidated financial condition, results of operations or cash flows, as any amounts that may be refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation and cost of service. On September 30, 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision and, on December 1, 2014, published a rule proposal for comment. The changes proposed by the NJBPU remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs.

Under the Merger Agreement, ACE is permitted to pursue the conclusion of this matter and intends to continue to do so.

Generic Consolidated Tax Adjustment Proceeding

In January 2013, the NJBPU initiated a generic proceeding to examine whether a consolidated tax adjustment (CTA) should continue to be used, and if so, how it should be calculated in determining a utility’s cost of service. Under the NJBPU’s current policy, when a New Jersey utility is included in a consolidated group income tax return, an allocated amount of any reduction in the consolidated group’s taxes as a result of losses by affiliates is used to reduce the utility’s rate base, upon which the utility earns a return. This policy has negatively impacted ACE’s electric distribution base rate case outcomes and ACE’s position is that the CTA should be eliminated. In an order dated October 22, 2014, the NJBPU determined that it is appropriate for affected consolidated groups to continue to include a CTA in New Jersey base rate filings, but that the CTA calculation will be modified to limit the look-back period for the calculation to five years, exclude transmission assets from the calculation and allocate 25 percent of the final CTA amount as a reduction to the distribution revenue requirement. With this revised methodology, ACE anticipates that the negative effects of the CTA in future base rate cases will be significantly reduced.

On November 5, 2014, the DRC filed an appeal of the NJBPU’s CTA order in the Appellate Division. This appeal remains pending.

Under the Merger Agreement, ACE is permitted to pursue the conclusion of this matter and intends to continue to do so.

Federal Energy Regulatory Commission

Transmission Annual Formula Rate Update Challenges

In October 2013, FERC issued a ruling on challenges filed by the Delaware Municipal Electric Corporation, Inc. (DEMEC) to DPL’s 2011 and 2012 annual formula rate updates for transmission service. In 2006, FERC approved a formula rate for DPL that is incorporated into the PJM tariff. The formula rate establishes the treatment of costs and revenues and the resulting rates for DPL. Pursuant to the protocols approved by FERC and after a period of discovery, interested parties have an opportunity to file challenges regarding the application of the formula rate. The October 2013 FERC order set various issues in this proceeding for hearing, including challenges regarding formula rate inputs, deferred income items, prepayments of estimated income taxes, rate base reductions, various administrative and general expenses and the inclusion in rate base of construction work in progress related to the MAPP project abandoned by PJM. Settlement discussions began in this matter in November 2013 before an administrative law judge at FERC.

In December 2013, DEMEC filed a formal challenge to the DPL 2013 annual formula rate update for transmission service, including a request to consolidate the 2013 challenge with the two prior challenges.

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The issues in the challenges for 2011, 2012 and 2013 are similar. On April 8, 2014, FERC issued an order setting the 2013 challenge issues for hearing and on April 15, 2014, those issues were consolidated with the 2011 and 2012 challenges. A settlement agreement was filed with FERC on August 25, 2014. On January 9, 2015, FERC issued an order approving the settlement, thereby resolving all of the issues set for hearing in the proceeding. Pursuant to the settlement, DPL will provide a one-time reduction of $225,000 to DPL’s 2015 annual formula rate update and will provide a one-time payment of $258,500 to DEMEC. In addition, the settlement resolves certain ratemaking and accounting treatments prospectively and provides that certain items will not be challenged in the future.

Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as DEMEC, filed a joint complaint at FERC against Pepco, DPL and ACE, as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. PHI, Pepco, DPL and ACE believe the allegations in this complaint are without merit and are vigorously contesting it. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set February 27, 2013 as the refund effective date, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, on November 24, 2014, the settlement judge issued an order terminating the settlement discussions. The matter is now before a hearing judge and a procedural schedule will be established for both the February 2013 complaint and a second complaint (discussed below) that has been consolidated with the February 2013 complaint.

On June 19, 2014, FERC issued an order in a proceeding in which the PHI utilities were not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology announced by FERC for the period over which each of their transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves in the second quarter of 2014 related to this matter. To the extent that the final ROE determined by FERC is lower than the ROE used to record the estimated reserves, each ten basis point reduction in the ROE would result in a reduction of PHI’s operating income of $1.5 million.

A second complaint against Pepco, DPL and ACE challenging the base ROE was filed at FERC on December 8, 2014 by the same parties. Employing the new ROE methodology referenced above, the complainants contend that the resulting base ROE should be 8.8%, and request consolidation of this complaint with the February 2013 complaint. Consistent with the prior challenge, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology described above, and recorded estimated reserves in the fourth quarter of 2014 using a refund effective date of December 8, 2014.

Under the Merger Agreement, PHI is permitted to pursue the conclusion of these FERC matters and intends to continue to do so.

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MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, 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, and each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.

In response to a complaint filed by a group of generating companies in the PJM region, on September 30, 2013, the U.S. District Court for the District of Maryland issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, on October 1, 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

On October 24, 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. The Federal district court order and its associated ruling could impact the state circuit court appeal, to which the Contract EDCs are parties, although such impact, if any, cannot be determined at this time. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal district court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the lower Federal court ruling. On November 26, 2014, both the winning bidder and the MPSC petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision.

The Maryland Court of Special Appeals has stayed the appeal of the Baltimore City Circuit Court decision until July 23, 2015.

On June 2, 2014, the winning bidder filed the contracts at FERC requesting that they be accepted pursuant to Section 205 of the Federal Power Act (FPA). On August 5, 2014, FERC issued an order rejecting the filings made by the winning bidder, finding that the contracts cannot be accepted as valid contracts, given the decisions reached in the Federal court proceedings discussed above.

Assuming the contracts, as currently written, were to become effective by the expected commercial operation date of June 1, 2015, PHI continues to believe that Pepco and DPL may be required to record their proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because Pepco and DPL would recover any payments under the contracts from SOS customers. PHI, Pepco and DPL have concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

Under the Merger Agreement, PHI is permitted to pursue the conclusion of this matter and intends to continue to do so.

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. ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violate certain of the requirements under the New Jersey law under which the SOCAs were established (the NJ SOCA Law). On October 22, 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice subject to the parties exercising their appellate rights in the Federal courts.

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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 NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. On October 11, 2013, the Federal district court issued a ruling that the NJ SOCA Law is preempted by the FPA and violates the Supremacy Clause, and is therefore null and void. On October 25, 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit in September 2014. On November 26, 2014 and December 10, 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision.

One of the three SOCAs was terminated effective July 1, 2013 because of an event of default of the generation company that was a party to the SOCA. The remaining two SOCAs were terminated effective November 19, 2013, as a result of a termination notice delivered by ACE after the Federal district court’s October 25, 2013 decision.

Despite the terminated status of the SOCAs, on June 2, 2014, one of the generation companies that was a party to a SOCA filed the SOCA at FERC seeking to have the SOCA accepted under Section 205 of the FPA. The EDCs intervened in the proceeding and requested that the generation company’s filing be rejected on the grounds that the SOCA never came into effect. On August 5, 2014, FERC issued an order rejecting the filings made by the generation company, finding that the contracts cannot be accepted as valid contracts, given the decisions reached in the Federal court proceedings discussed above.

In light of the October 25, 2013 Federal district court order, ACE derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) in the fourth quarter of 2013.

District of Columbia Power Line Undergrounding Initiative

On May 3, 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco.

The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a surcharge on the electric bills of Pepco District of Columbia customers that Pepco will remit to the District of Columbia; and (iii) the remaining amount is to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

On June 17, 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. On August 1, 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District to recover the costs associated with the bond issuance.

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On November 12, 2014, the DCPSC issued an order approving the Triennial Plan and Pepco’s volumetric surcharge, and on November 24, 2014, the DCPSC issued the financing order. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act. In December 2014, a party to the proceeding sought reconsideration from the DCPSC of both decisions. Final decisions denying both requests for reconsideration were issued on January 22, 2015 and February 2, 2015, respectively.

On December 4, 2014, a party filed a petition for review with the District of Columbia Court of Appeals disputing the DCPSC’s denial of its motion to intervene. The procedural schedule for the petition has not yet been set.

Under the Merger Agreement, Pepco is permitted to pursue the DC PLUG initiative and intends to continue to do so.

MAPP Settlement Agreement

In February 2014, FERC issued an order approving the settlement agreement submitted by Pepco and DPL in connection with Pepco’s and DPL’s proceeding seeking recovery of approximately $88 million in abandonment costs related to the MAPP project. PHI had been directed by PJM to construct the MAPP project, a 152-mile high-voltage interstate transmission line, and in August 2012 was directed by PJM to cancel it. The abandonment costs sought for recovery were subsequently reduced to $82 million as a result of write-offs of certain disallowed costs in 2013 and transfers of materials to inventories for use on other projects. Under the terms of the FERC-approved settlement agreement, Pepco and DPL will receive $80.5 million of transmission revenues over a three-year period, which began on June 1, 2013, and will retain title to all real property and property rights acquired in connection with the MAPP project, which had an estimated fair value of $8 million. The FERC-approved settlement agreement resolves all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project, and the terms of the settlement agreement are not subject to modification through any other FERC proceeding. As of December 31, 2014, PHI had recorded a regulatory asset related to the MAPP abandonment costs of approximately $33 million, net of amortization, and land of $8 million. PHI expects to recognize pre-tax income related to the MAPP abandonment costs of $1 million in 2015.

Merger Approval Proceedings

Delaware

On June 18, 2014, Exelon, PHI and DPL, and certain of their respective affiliates, filed an application with the DPSC seeking approval of the Merger. Delaware law requires the DPSC to approve the Merger when it determines that the transaction is in accordance with law, for a proper purpose, and is consistent with the public interest. The DPSC must further find that the successor will continue to provide safe and reliable service, will not terminate or impair existing collective bargaining agreements and will engage in good faith bargaining with organized labor. On February 13, 2015, Exelon, DPL, the DPSC staff, the Division of the Public Advocate and certain other parties filed a settlement agreement with the DPSC. The settling parties also requested that the scheduled hearings be suspended. The settlement requests that hearings regarding DPSC approval of the settlement be held in April 2015 and that the decision of the DPSC be issued thereafter in April 2015.

District of Columbia

On June 18, 2014, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application with the DCPSC seeking approval of the Merger. To approve the Merger, the DCPSC must find that the Merger is in the public interest. In an order issued August 22, 2014, the DCPSC stated that to make the determination of whether the transaction is in the public interest, it will analyze the transaction in the

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context of seven factors to determine whether the transaction balances the interests of shareholders and investors with ratepayers and the community, whether the benefits to shareholders do or do not come at the expense of the ratepayers, and whether the transaction produces a direct and tangible benefit to ratepayers. The seven factors identified by the DCPSC are the effects of the transaction on: (i) ratepayers, shareholders, the financial health of the utility standing alone and as merged, and the local economy; (ii) utility management and administrative operations; (iii) the public safety and the safety and reliability of services; (iv) risks associated with all of the affiliated non-jurisdictional business operations, including nuclear operations, of the applicants; (v) the DCPSC’s ability to regulate the utility effectively following the Merger; (vi) competition in the local retail and wholesale markets that impacts the District and District ratepayers; and (vii) conservation of natural resources and preservation of environmental quality. District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger. The DCPSC has scheduled evidentiary hearings for March 30, 2015 to April 8, 2015.

Maryland

On August 19, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. In making this determination, the MPSC is required to consider the following 12 criteria: (i) the potential impact of the merger on rates and charges paid by customers and on the services and conditions of operation of the utility; (ii) the potential impact of the merger on continuing investment needs for the maintenance of utility services, plant and related infrastructure; (iii) the proposed capital structure that will result from the merger, including allocation of earnings from the utility; (iv) the potential effects on employment by the utility; (v) the projected allocation between the utility’s shareholders and ratepayers of any savings that are expected; (vi) issues of reliability, quality of service and quality of customer service; (vii) the potential impact of the merger on community investment; (viii) affiliate and cross-subsidization issues; (ix) the use or pledge of utility assets for the benefit of an affiliate; (x) jurisdictional and choice-of-law issues; (xi) whether it is necessary to revise the MPSC’s ring-fencing and affiliate code of conduct regulations in light of the merger; and (xii) any other issues the MPSC considers relevant to the assessment of the merger. The MPSC is required to issue an order within 180 days of the August 19, 2014 filing date. However, the MPSC can grant a 45-day extension for good cause. If no order is issued by the statutory deadline, then the Merger would be deemed to be approved. On September 22, 2014, the MPSC issued an order setting the procedural schedule for this matter. Pursuant to that schedule, evidentiary hearings were held beginning on January 26, 2015, and all briefs are scheduled to be filed in March 2015. The deadline for the MPSC’s decision is April 8, 2015.

New Jersey

On June 18, 2014, Exelon, PHI and ACE, and certain of their respective affiliates, filed a petition with the NJBPU seeking approval of the Merger. To approve the Merger, the NJBPU must find the Merger is in the public interest, and consider the impact of the Merger on (i) competition, (ii) rates of ratepayers affected by the Merger, (iii) ACE’s employees, and (iv) the provision of safe and reliable service at just and reasonable rates. On July 23, 2014, the NJBPU voted to retain this matter, rather than assigning it to an administrative law judge. On January 14, 2015, PHI, ACE, Exelon, certain of Exelon’s affiliates, the Staff of the NJBPU, and the Independent Energy Producers of New Jersey filed a stipulation of settlement (the Stipulation) with the NJBPU in this proceeding. On February 11, 2015, the NJBPU approved the Stipulation and the Merger.

Virginia

On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will

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not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

Hart-Scott-Rodino Act

The HSR Act, which is the U.S. federal pre-merger notification statute, and its related rules and regulations provide that acquisition transactions that meet the HSR Act’s coverage thresholds may not be completed until a Notification and Report Form has been furnished to the DOJ and the Federal Trade Commission (FTC), and that the waiting period required by the HSR Act has been terminated or has expired. Pursuant to the HSR Act requirements, Pepco Holdings and Exelon filed the required Notification and Report Forms with the DOJ and the FTC on August 6, 2014. Following informal discussions with the DOJ, effective as of September 5, 2014, Exelon withdrew its Notification and Report Form and refiled it on September 9, 2014, which restarted the waiting period required by the HSR Act. On October 9, 2014, each of Pepco Holdings and Exelon received a request for additional information and documentary material from the DOJ, which had the effect of extending the DOJ review period until 30 days after each of Pepco Holdings and Exelon certified that it has substantially complied with the request. On November 21, 2014, each of Pepco Holdings and Exelon certified that it had substantially complied with the request. Accordingly, the HSR Act waiting period expired on December 22, 2014, and the HSR Act no longer precludes completion of the Merger. Although the DOJ allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised Pepco Holdings or Exelon that it has concluded its investigation.

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(8) 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, 2014
Generation	$	104	$	100	$	4
Distribution		9,527		3,021		6,506
Transmission		3,252		934		2,318
Gas		511		153		358
Construction work in progress		688		—		688
Non-operating and other property		1,383		751		632
Total	$	15,465	$	4,959	$	10,506
At December 31, 2013
Generation	$	105	$	99	$	6
Distribution		8,896		2,961		5,935
Transmission		2,991		908		2,083
Gas		481		142		339
Construction work in progress		677		—		677
Non-operating and other property		1,417		753		664
Total	$	14,567	$	4,863	$	9,704

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, 2014 and 2013, PHI’s subsidiaries had a net book value ownership interest of $15 million and $12 million, respectively, 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 (loss). PHI is responsible for providing its share of the financing for the above jointly owned facilities.

Capital Leases

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 (loss). This lease is treated as an operating lease for rate-making purposes.

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Capital lease assets recorded within Property, Plant and Equipment at December 31, 2014 and 2013 are comprised of the following:

	Original Cost		Accumulated Amortization		Net Book Value
	(millions of dollars)
At December 31, 2014
Transmission	$	76	$	46	$	30
Distribution		76		46		30
Total	$	152	$	92	$	60
At December 31, 2013
Transmission	$	76	$	41	$	35
Distribution		76		42		34
General		3		3		—
Total	$	155	$	86	$	69

The approximate annual commitments under all capital leases are $15 million in each of the years 2015 through 2018 and $16 million in 2019.

Deactivation of Pepco Energy Services’ Generating Facilities

During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services is demolishing the Benning Road generation facility and realizing the scrap metal salvage value of the facility. The demolition of the facility commenced in the fourth quarter of 2013 and is expected to be completed in the first quarter of 2015. Pepco Energy Services is recognizing the salvage proceeds associated with the scrap metals at the facility as realized.

Long-Lived Asset Impairment

During 2014, PHI recorded impairment losses of $81 million ($48 million after-tax) at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City, which reduced the carrying amount of its long-lived assets in Atlantic City from $83 million to $2 million at December 31, 2014. PHI performed long-lived asset impairment tests on asset groups comprising substantially all of the long-lived assets in Atlantic City as a result of significant adverse changes in the financial condition of its customers and the business climate in Atlantic City. The assets were written down to their estimated fair values because the future estimated undiscounted cash flows from the asset groups were significantly lower than their carrying value. PHI estimated the fair values of the asset groups from a market participant’s perspective by calculating the present value of estimated future cash flows over the useful lives of the assets using an appropriate discount rate. Both the estimated future cash flows and the discount rate were based on primarily unobservable, Level 3 inputs. The estimated future cash flows were probability weighted based on several potential outcomes regarding forecasted revenues and expenses associated with each asset group. Forecasted revenues and expenses were, in part, based on estimated future commodity prices from an external valuation specialist. In addition, PHI forecasted customer usage volumes and the associated operations and maintenance expenses and capital expenditures. A 10 percent change in the estimated cash flows would not have a significant impact on the estimated fair value of the assets. PHI also selected a discount rate that would reflect a market return on the estimated cash flows. PHI considered a range of discount rates between 10 percent and 16 percent. A one percent change in the discount rate assumptions would not have a significant impact on the estimated fair value of the assets.

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During 2013, PHI recorded impairment losses of $4 million ($3 million after-tax) at Pepco Energy Services associated primarily with its investments in landfill gas-fired electric generation facilities. PHI performed a long-lived asset impairment test on the landfill generation facilities of Pepco Energy Services as a result of a sustained decline in energy prices and recent production levels. The asset value of the facilities was written down to the 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 had asset retirement obligations of zero and $2 million as of December 31, 2014 and 2013, respectively, on its consolidated balance sheets.

During 2013, Pepco Energy Services determined to pursue the demolition of the Benning Road generation facility. As a result of this determination, Pepco Energy Services reduced its asset retirement obligation related to the facility by $2 million.

The sale of the wholesale power generation business of Conectiv Energy Holding Company and its subsidiaries (collectively, Conectiv Energy) to Calpine Corporation (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 for 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.

(9)PENSION AND OTHER POSTRETIREMENT BENEFITS

The following table shows changes in the benefit obligation and plan assets for the years ended December 31, 2014 and 2013:

	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
	(millions of dollars)
Change in Benefit Obligation
Benefit obligation as of January 1	$	2,238		$	2,494		$	574		$	775
Service cost		44			53			7			8
Interest cost		109			100			26			29
Amendments		—			3			—			(124	)
Actuarial loss (gain)		401			(277	)		59			(71	)
Benefits paid		(154	)		(135	)		(34	)		(43	)
Benefit obligation as of December 31	$	2,638		$	2,238		$	632		$	574
Change in Plan Assets
Fair value of plan assets as of January 1	$	2,116		$	2,039		$	368		$	321
Actual return on plan assets		268			86			21			56
Company and participant contributions		6			126			12			34
Benefits paid		(154	)		(135	)		(34	)		(43	)
Fair value of plan assets as of December 31	$	2,236		$	2,116		$	367		$	368
Funded Status at end of year (plan assets less plan obligations)	$	(402	)	$	(122	)	$	(265	)	$	(206	)

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At December 31, 2014 and 2013, the PHI Retirement Plan’s accumulated benefit obligation was approximately $2.4 billion and $2.1 billion, respectively. The accumulated benefit obligation differs from the pension benefit obligation presented in the table above in that the accumulated benefit obligation includes no assumption about future compensation levels.

The following table provides the amounts recorded in PHI’s consolidated balance sheets as of December 31, 2014 and 2013:

	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
	(millions of dollars)
Regulatory asset	$	871		$	664		$	75		$	3
Current liabilities		(6	)		(6	)		—			—
Pension benefit obligation		(396	)		(116	)		—			—
Other postretirement benefit obligations		—			—			(265	)		(206	)
Deferred income taxes liabilities		(193	)		(217	)		77			82
Accumulated other comprehensive loss, net of tax		37			25			—			—
Net amount recorded	$	313		$	350		$	(113	)	$	(121	)

Amounts included in AOCL (pre-tax) and Regulatory assets at December 31, 2014 and 2013, consist of:

	Pension Benefits				Other Postretirement Benefits
	2014		2013		2014			2013
	(millions of dollars)
Unrecognized net actuarial loss	$	925	$	694	$	176		$	117
Unamortized prior service cost (credit)		8		10		(101	)		(114	)
Total	$	933	$	704	$	75		$	3
Accumulated other comprehensive loss ($37 million and $25 million, net of tax, at December 31, 2014 and 2013, respectively)	$	62	$	40	$	—		$	—
Regulatory assets		871		664		75			3
Total	$	933	$	704	$	75		$	3

Under FASB guidance on regulated operations, a portion of actuarial gains and losses and prior service costs (credits) are included in Regulatory assets (liabilities) in the consolidated balance sheets to reflect expected regulatory recovery of such amounts, which otherwise would be recorded to AOCL. The table below provides the changes in plan assets and benefit obligations recognized in AOCL and Regulatory assets for the years ended December 31, 2014, 2013 and 2012:

	Pension Benefits									Other Postretirement Benefits
	2014			2013			2012			2014			2013			2012
	(millions of dollars)
Amounts amortized during the year:
Amortization of prior service (cost) credit	$	(2	)	$	(2	)	$	(1	)	$	13		$	11		$	4
Amortization of net actuarial (loss)		(45	)		(67	)		(64	)		(3	)		(12	)		(14	)
Amounts arising during the year:
Current year prior service cost (credit)		—			3			—			—			(124	)		—
Current year actuarial loss (gain)		276			(218	)		220			62			(109	)		4
Total recognized in AOCL and Regulatory assets for the year ended December 31	$	229		$	(284	)	$	155		$	72		$	(234	)	$	(6	)

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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 $63 million and $2 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 $11 million and $13 million, respectively.

The table below provides the components of net periodic benefit costs recognized for the years ended December 31, 2014, 2013 and 2012:

	Pension Benefits									Other Postretirement Benefits
	2014			2013			2012			2014			2013			2012
	(millions of dollars)
Service cost	$	44		$	53		$	35		$	7		$	8		$	7
Interest cost		109			100			107			26			29			35
Expected return on plan assets		(141	)		(145	)		(132	)		(24	)		(20	)		(18	)
Amortization of prior service cost (credit)		2			2			1			(13	)		(11	)		(4	)
Amortization of net actuarial loss		45			67			64			3			12			14
Termination benefits		—			—			—			—			—			1
Net periodic benefit cost	$	59		$	77		$	75		$	(1	)	$	18		$	35

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, 2014, 2013 and 2012:

	2014		2013		2012
	(millions of dollars)
Pepco	$	22	$	34	$	39
DPL		7		18		23
ACE		13		17		24
Other subsidiaries		16		26		24
Total	$	58	$	95	$	110

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

	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
Discount rate		4.20	%		5.05	%		4.15	%		5.00	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%
Health care cost trend rate assumed for current year – pre 65		—			—			6.67	%		7.00	%
Health care cost trend rate assumed for current year – post 65		—			—			5.50	%		5.60	%
Rate to which the cost trend rate is assumed to decline for all eligible retirees (the ultimate trend rate)		—			—			5.00	%		5.00	%
Year that the cost trend rate reaches the ultimate trend rate		—			—			2020			2020

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	$	1	$	(1	)
Increase (decrease) in postretirement benefit obligation	$	18	$	(20	)

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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
	2014			2013			2012			2014			2013			2012
Discount rate		5.05	%		4.15	%		5.00	%		5.00	%		4.10%/4.95	% (a)		4.90	%
Expected long-term return on plan assets		7.00	%		7.00	%		7.25	%		7.25	%		7.00	%		7.25	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%
Health care cost trend rate		—			—			—			7.00	%		7.50	%		8.00	%

(a) The discount rate was updated for remeasurement to 4.95% on July 1, 2013.

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.

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. PHI periodically reviews its asset mix and rebalances assets to the target allocation.

The average remaining service periods for participating employees of the benefit plans was approximately 11 years for both 2014 and 2013. PHI utilizes plan census data to estimate these average remaining service periods. PHI uses the IRS prescribed mortality tables to estimate the average life expectancy. The IRS prescribed tables for 2014 and 2013 were used to determine net periodic pension and OPEB cost for the same respective years. The IRS prescribed mortality tables for 2013 were used for determining the benefit obligations as of December 31, 2013. In 2014, the Society of Actuaries issued new mortality tables which PHI applied in determining its benefit obligations as of December 31, 2014.

Benefit Plan Modifications

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree health care and the retiree life insurance benefits, and were effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its accumulated postretirement benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $193 million reduction of the accumulated postretirement benefit obligation, which included recording a prior service credit of $124 million, which will be amortized over approximately ten years, and a $69 million reduction from a change in the discount rate from 4.10% as of December 31, 2012 to 4.95% as of July 1, 2013. The remeasurement resulted in a $19 million reduction in net periodic benefit cost for other postretirement benefits during 2014, when compared to 2013. Approximately 36% of net periodic other postretirement benefit costs were capitalized in 2014.

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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, and

• 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.

PHI follows an asset-liability management strategy for PHI Retirement Plan assets in order to reduce the effects of future volatility of the fair value of its pension plan assets relative to its pension plan liabilities. For example, in 2014, this strategy uses a 68% target allocation to fixed income investments, primarily in high quality, longer-maturity fixed income securities. The PHI Retirement Plan asset allocations at December 31, 2014 and 2013, by asset category, were as follows:

Asset Category	Plan Assets at December 31,						Target Plan Asset Allocation
	2014			2013			2014			2013
Equity		28	%		31	%		27	%		28	%
Fixed Income		65	%		62	%		68	%		66	%
Other (real estate, private equity)		7	%		7	%		5	%		6	%
Total		100	%		100	%		100	%		100	%

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PHI’s other postretirement benefit plan asset allocations at December 31, 2014 and 2013, by asset category, were as follows:

Asset Category	Plan Assets at December 31,						Target Plan Asset Allocation
	2014			2013			2014			2013
Equity		64	%		63	%		60	%		60	%
Fixed Income		34	%		31	%		35	%		35	%
Cash		2	%		6	%		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.

Fair Value of Plan Assets

As defined in the FASB guidance on fair value measurement (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.

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There were no significant transfers between level 1 and level 2 during the years ended December 31, 2014 and 2013.

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, 2014 and 2013:

	Fair Value Measurements at December 31, 2014
	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Asset Category	(millions of dollars)
Pension Plan Assets:
Equity
Domestic (a)	$	376	$	128	$	213	$	35
International (b)		255		254		—		1
Fixed Income (c)		1,459		—		1,448		11
Other
Private Equity		47		—		—		47
Real Estate		54		—		—		54
Cash Equivalents (d)		45		45		—		—
Pension Plan Assets Subtotal		2,236		427		1,661		148
Other Postretirement Plan Assets:
Equity (e)		235		208		27		—
Fixed Income (f)		126		126		—		—
Cash Equivalents		6		6		—		—
Postretirement Plan Assets Subtotal		367		340		27		—
Total Pension and Other Postretirement Plan Assets	$	2,603	$	767	$	1,688	$	148

(a) Domestic equity assets predominantly include domestic common stock and commingled funds.

(b) International equity assets predominantly include foreign common and preferred stock and warrants.

(c) Fixed income assets predominantly include corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds.

(d) Cash equivalents predominantly include cash investments in short-term investment funds.

(e) Equity assets include domestic and international commingled funds.

(f) Fixed income assets include fixed income commingled funds.

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	Fair Value Measurements at December 31, 2013
	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Asset Category	(millions of dollars)
Pension Plan Assets:
Equity
Domestic (a)	$	389	$	142	(g)	$	213	$	34
International (b)		260		258	(g)		1		1
Fixed Income (c)		1,309		—			1,298		11
Other
Private Equity		53		—			—		53
Real Estate		61		—			—		61
Cash Equivalents (d)		44		44			—		—
Pension Plan Assets Subtotal		2,116		444			1,512		160
Other Postretirement Plan Assets:
Equity (e)		233		204			29		—
Fixed Income (f)		113		113			—		—
Cash Equivalents		22		22			—		—
Postretirement Plan Assets Subtotal		368		339			29		—
Total Pension and Other Postretirement Plan Assets	$	2,484	$	783		$	1,541	$	160

(a) Domestic equity assets predominantly include domestic common stock and commingled funds.

(b) International equity assets predominantly include foreign common and preferred stock and warrants.

(c) Fixed income assets predominantly include corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds.

(d) Cash equivalents predominantly include cash investments in short-term investment funds.

(e) Equity assets include domestic and international commingled funds.

(f) Fixed income assets include fixed income commingled funds.

(g) Certain equity assets totaling $43 million have been reclassified from domestic equity to international equity to conform to the currect period presentation.

There were no significant concentrations of risk in pension and OPEB plan assets at December 31, 2014 and 2013.

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.

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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, 2014 and 2013 totaled $11 million and $12 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, 2014 and 2013 are shown below:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Equity			Fixed Income		Private Equity			Real Estate			Total Level 3
	(millions of dollars)
Balance as of January 1, 2014	$	35		$	11	$	53		$	61		$	160
Transfer in (out) of Level 3		—			—		—			—			—
Purchases		—			—		3			1			4
Sales		(3	)		—		—			(5	)		(8	)
Settlements		—			—		(6	)		(9	)		(15	)
Unrealized gain (loss)		2			—		(12	)		2			(8	)
Realized gain		2			—		9			4			15
Balance as of December 31, 2014	$	36		$	11	$	47		$	54		$	148

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	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Equity			Fixed Income			Private Equity			Real Estate			Total Level 3
	(millions of dollars)
Balance as of January 1, 2013	$	31		$	13		$	56		$	74		$	174
Transfer in (out) of Level 3		—			(3	)		—			—			(3	)
Purchases		—			—			2			2			4
Sales		(5	)		(1	)		—			(13	)		(19	)
Settlements		—			2			(4	)		(10	)		(12	)
Unrealized gain (loss)		7			—			(7	)		7			7
Realized gain		2			—			6			1			9
Balance as of December 31, 2013	$	35		$	11		$	53		$	61		$	160

Cash Flows

Contributions—PHI Retirement Plan

PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the target liability as defined under the Pension Protection Act of 2006, as modified by subsequent legislation. During 2014, PHI, Pepco, DPL and ACE did not make any discretionary tax-deductible contributions to the PHI Retirement Plan as its assets met or exceeded the funding target level for 2014. During 2013, PHI, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $80 million, $10 million and $30 million, respectively, which brought the PHI Retirement Plan assets to the funding target level for 2013 under the Pension Protection Act.

Contributions—Other Postretirement Benefit Plan

In 2014 and 2013, Pepco contributed $1 million and $6 million, respectively, DPL contributed zero and $3 million, respectively, and ACE contributed $3 million and $6 million, respectively, to the other postretirement benefit plan. In 2014 and 2013, contributions of zero and $7 million, respectively, were made by other PHI subsidiaries.

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
	(millions of dollars)
2015	$	134	$	38
2016		140		38
2017		142		39
2018		148		39
2019		153		39
2020 through 2023		826		193

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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 $13 million, $12 million and $12 million for the years ended December 31, 2014, 2013 and 2012, respectively.

(10) DEBT

Long-Term Debt

The components of long-term debt are shown in the table below:

		At December 31,
Interest Rate	Maturity	2014		2013
		(millions of dollars)
First Mortgage Bonds
Pepco:
4.65% (a)(b)	2014	$	—	$	175
3.05%	2022		200		200
6.20% (c)(d)	2022		110		110
3.60%	2024		400		—
5.75% (a)(b)	2034		100		100
5.40% (a)(b)	2035		175		175
6.50% (a)(c)	2037		500		500
7.90%	2038		250		250
4.15%	2043		250		250
4.95%	2043		150		150
ACE:
7.63% (e)	2014		—		7
7.68% (e)	2015 - 2016		17		17
7.75%	2018		250		250
6.80% (b)(f)	2021		39		39
4.35%	2021		200		200
3.375%	2024		150		—
4.875% (c)(f)	2029		23		23
5.80% (b)(g)	2034		120		120
5.80% (b)(g)	2036		105		105
DPL:
5.22% (h)	2016		100		100
3.50%	2023		500		300
4.00%	2042		250		250
Total First Mortgage Bonds			3,889		3,321
Unsecured Tax-Exempt Bonds
DPL:
5.40%	2031		78		78
Total Unsecured Tax-Exempt Bonds			78		78

NOTE: Schedule is continued on next page.

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		At December 31,
Interest Rate	Maturity	2014			2013
		(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
ACE Variable Rate Term Loan	2014		—			100
Recourse Debt
PCI:
6.59% - 6.69%	2014		—			11
Notes (secured)
Pepco Energy Services:
6.70% - 7.46%	2015-2018		4			14
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
5.00%	2015		100			100
Total Notes (unsecured)			806			906
Total Long-Term Debt			4,817			4,470
Net unamortized discount			(10	)		(14	)
Current portion of long-term debt			(366	)		(403	)
Total Net Long-Term Debt		$	4,441		$	4,053

(a) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of senior notes issued by Pepco.

(b) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).

(c) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that the issuer may not permit such release of collateral unless the issuer substitutes comparable obligations for such collateral.

(d) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco.

(e) Represents a series of Collateral First Mortgage Bonds securing a series of medium-term notes issued by ACE.

(f) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE.

(g) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE.

(h) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL.

The outstanding first mortgage bonds issued by each of Pepco, DPL and ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of the issuing company’s property, plant and equipment, except for certain property excluded from the lien of the respective mortgage.

PHI’s long-term debt is subject to certain covenants. As of December 31, 2014, PHI and its subsidiaries were in compliance with all such covenants.

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The table above does not separately identify $885 million, $100 million and $242 million in aggregate principal amount of senior notes, medium term notes and other debt securities (issuer notes) issued by each of Pepco, DPL and ACE, respectively, and $110 million and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of Pepco and ACE, respectively. These issuer notes are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of each respective issuer. In addition, these tax-exempt bonds are secured by a like amount of Collateral First Mortgage Bonds issued by the utility subsidiary for whose benefit the tax-exempt bonds were issued. The principal terms of each such series of issuer notes, or the issuer’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of the issuer’s obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes and/or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.

Bond Issuances

During 2014, Pepco issued $400 million of 3.60% first mortgage bonds due March 15, 2024. Pepco used a portion of the net proceeds of the offering to repay in full at maturity $175 million in aggregate principal amount of its 4.65% senior notes due April 15, 2014, plus accrued and unpaid interest.

During 2014, DPL issued $200 million of its 3.50% first mortgage bonds due November 15, 2023. Net proceeds from the issuance of the bonds, which included a premium of $4 million, were used to repay DPL’s outstanding commercial paper and for general corporate purposes.

During 2014, ACE issued $150 million of its 3.375% first mortgage bonds due September 1, 2024. ACE used $7.2 million of the net proceeds from the issuance of the bonds to repay in full at maturity $7.0 million in aggregate principal amount of ACE’s 7.63% secured medium term notes due August 29, 2014, plus accrued and unpaid interest thereon. ACE used the remainder of the net proceeds to repay its outstanding commercial paper, including commercial paper that ACE issued to prepay in full its $100 million term loan, and for general corporate purposes.

Debt Retirements

During 2014, Pepco retired, at maturity, $175 million of its 4.65% senior notes. The senior notes were secured by a like principal amount of its 4.65% first mortgage bonds due April 15, 2014, which under Pepco’s mortgage and deed of trust were deemed to be satisfied when the senior notes were repaid.

During 2014, DPL retired, at maturity, $100 million of its 5.00% unsecured notes.

During 2014, ACE retired, at maturity, $7 million of its 7.63% medium term notes due August 29, 2014. The notes were secured by a like principal amount of first mortgage bonds due August 29, 2014, which under ACE’s mortgage and deed of trust were deemed to be satisfied when the notes were repaid.

During 2014, PCI retired, at maturity, $11 million of bank loans.

189

PEPCO HOLDINGS

Transition Bonds Issued by ACE Funding

The components of transition bonds are shown in the table below:

		At December 31,
Interest Rate	Maturity	2014			2013
		(millions of dollars)
4.46%	2016	$	—		$	8
4.91%	2017		17			46
5.05%	2020		51			54
5.55%	2023		147			147
Total Transition Bonds			215			255
Current portion of long-term debt			(44	)		(41	)
Total Net Long-Term Transition Bonds		$	171		$	214

For a description of the Transition Bonds, see Note (17), “Variable Interest Entities – ACE Funding.”

Maturities of PHI’s long-term debt and Transition Bonds outstanding at December 31, 2014 are $410 million in 2015, $340 million in 2016, $131 million in 2017, $285 million in 2018, $30 million in 2019 and $3,836 million thereafter.

Long-Term Project Funding

As of December 31, 2014 and 2013, Pepco Energy Services had total outstanding long-term project funding (including current maturities) of $10 million and $12 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, 2014 are $2 million in 2015, $1 million in each of the years 2016, 2017 and 2018, $2 million in 2019 and $3 million thereafter.

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. The components of PHI’s short-term debt at December 31, 2014 and 2013 are as follows:

	2014		2013
	(millions of dollars)
Commercial paper	$	624	$	442
Variable rate demand bonds		105		123
Total	$	729	$	565

Commercial Paper

PHI, Pepco, DPL and ACE maintain ongoing commercial paper programs to address short-term liquidity needs. As of December 31, 2014, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $350 million, respectively, subject to available borrowing capacity under the credit facility.

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PEPCO HOLDINGS

PHI, Pepco, DPL and ACE had $287 million, $104 million, $106 million and $127 million, respectively, of commercial paper outstanding at December 31, 2014. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2014 was 0.57%, 0.28%, 0.26% and 0.27%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2014 was six, six, five and five days, respectively.

PHI, Pepco, DPL and ACE had $24 million, $151 million, $147 million and $120 million, respectively, of commercial paper outstanding at December 31, 2013. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2013 was 0.70%, 0.34%, 0.29% and 0.31%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2013 was five, five, three and four days, respectively.

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, 2014, $105 million of VRDBs issued on behalf of DPL were outstanding (of which $72 million were secured by Collateral First Mortgage Bonds issued by DPL). During 2014, ACE retired, at maturity, its last remaining VRDBs in the amount of $18 million.

The VRDBs outstanding at December 31, 2014 mature as follows: 2015 to 2017 ($26 million), 2024 ($33 million) and 2028 to 2029 ($46 million). The weighted average interest rate for VRDBs outstanding on December 31, 2014 was 0.19% during 2014 and 0.24% during 2013.

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. The termination date of this credit facility is currently August 1, 2018.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one-month London Interbank Offered Rate (LIBOR) plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

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PEPCO HOLDINGS

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility as of December 31, 2014.

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.

As of December 31, 2014 and 2013, 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 $875 million and $1,063 million, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of $413 million and $332 million at December 31, 2014 and 2013, respectively.

Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.

Other Financing Activities

Sale of Receivables

During 2014, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project pursuant to a Task Order entered into under a General Services Administration area-wide agreement. The purchase price received by Pepco was $12 million. The energy savings project, which is being performed by Pepco Energy Services, was completed in 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project, the buyer will be entitled to receive the contract payments under the Task Order payable by the customer over approximately 9 years. At December 31, 2014, Pepco included the $12 million received in the Current portion of long-term debt and project funding.

On October 24, 2013, Pepco Energy Services, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a Task Order. The purchase price received by Pepco Energy Services was $7 million. Pursuant to the purchase agreement, following acceptance of the energy savings project, the buyer will be entitled to receive the contract payments under the Task Order payable by the customer over approximately 23 years. At December 31, 2014, Pepco Energy Services included the $7 million received in the Current portion of long-term debt and project funding.

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PEPCO HOLDINGS

ACE Term Loan Agreement

On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE borrowed $100 million at a rate of interest equal to the prevailing Eurodollar rate, which was determined by reference to the LIBOR with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. On August 21, 2014, ACE repaid the term loan in full.

(11) 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 2002 in connection with the establishment of PHI as a public utility 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.

Provision for Consolidated Income Taxes – Continuing Operations

	For the Year Ended December 31,
	2014			2013			2012
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(137	)	$	(128	)	$	(166	)
State and local		(26	)		(9	)		(40	)
Total Current Tax (Benefit) Expense		(163	)		(137	)		(206	)
Deferred Tax Expense (Benefit)
Federal		261			393			254
State and local		41			65			58
Investment tax credit amortization		(1	)		(2	)		(3	)
Total Deferred Tax Expense		301			456			309
Total Consolidated Income Tax Expense Related to Continuing Operations	$	138		$	319		$	103

Reconciliation of Consolidated Income Tax Expense – Continuing Operations

	For the Year Ended December 31,
	2014					2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	133		35.0	%	$	150		35.0	%	$	112		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		23		6.1	%		27		6.3	%		19		6.0	%
Asset removal costs		(12	)	(3.2	)%		(14	)	(3.3	)%		(11	)	(3.4	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		—		—			56		13.1	%		(8	)	(2.6	)%
Establishment of valuation allowances related to deferred tax assets		—		—			101		23.5	%		—		—
Merger related costs		7		1.8	%		—		—			—		—
Other, net		(13	)	(3.4	)%		(1	)	(0.2	)%		(9	)	(2.9	)%
Consolidated Income Tax Expense Related to Continuing Operations	$	138		36.3	%	$	319		74.4	%	$	103		32.1	%

193

PEPCO HOLDINGS

During 2014, PHI recorded a tax benefit of $5 million related to certain energy efficiency tax deductions associated with Pepco Energy Services’ energy savings performance contracting services.

In connection with entering into the Merger Agreement (as further described in Note (1), “Organization”), PHI incurred certain merger-related costs in 2014 which are not tax deductible.

During 2013, PHI recorded a $56 million charge for a change in estimates and interest related to uncertain and effectively settled tax positions, primarily representing the anticipated additional interest expense on estimated federal and state income tax obligations that was allocated to PHI’s continuing operations resulting from a change in assessment of tax benefits associated with the former cross-border energy lease investments of PCI in the first quarter of 2013.

Also, in 2013, PHI established valuation allowances of $101 million related to deferred tax assets. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to other taxpayers’ cross-border lease and other structured transactions (as discussed in Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”), (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases, and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represented a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI would be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of all relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances.

PHI’s consolidated effective income tax rate for the year ended December 31, 2012 includes income tax benefits totaling $8 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.

194

PEPCO HOLDINGS

Components of Consolidated Deferred Tax Liabilities (Assets)

	At December 31,
	2014			2013
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	2,962		$	2,628
Deferred electric service and electric restructuring liabilities		67			91
Cross-border energy lease investments		—			(6	)
Federal and state net operating losses		(400	)		(350	)
Valuation allowances on state net operating losses		61			21
Pension and other postretirement benefits		116			135
Deferred taxes on amounts to be collected through future rates		94			75
Other (a)		325			285
Total Deferred Tax Liabilities, net		3,225			2,879
Deferred tax assets included in Current Assets		50			51
Deferred tax liabilities included in Other Current Liabilities		(9	)		(2	)
Total Consolidated Deferred Tax Liabilities, net non-current	$	3,266		$	2,928

(a) PCI established valuation allowances against certain of these other deferred taxes totaling $101 million in the first quarter of 2013. Management determined during the fourth quarter of 2013 to abandon the further pursuit of the related deferred tax assets and, accordingly, these assets were charged off against the valuation allowances.

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 2034.

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.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2014			2013			2012
	(millions of dollars)
Balance as of January 1,	$	831		$	200		$	357
Tax positions related to current year:
Additions		4			3			1
Reductions		(2	)		—			—
Tax positions related to prior years:
Additions		27			646	(a)		79
Reductions		(10	)		(12	)		(235	)(b)
Settlements		—			(6	)		(2	)
Balance as of December 31,	$	850		$	831		$	200

(a) These additions of unrecognized tax benefits in 2013 primarily relate to the former cross-border energy lease investments of PCI.

(b) These reductions of unrecognized tax benefits in 2012 primarily relate to a resolution reached with the IRS for determining deductible mixed service costs for additions to property, plant and equipment.

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PEPCO HOLDINGS

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, 2014 included $12 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, 2014, 2013 and 2012, PHI recognized less than $1 million of pre-tax interest expense, $125 million of pre-tax interest expense ($75 million after-tax), and $23 million of pre-tax interest income ($14 million after-tax), respectively, as a component of income tax expense related to continuing and discontinued operations. As of December 31, 2014, 2013 and 2012, PHI had accrued interest receivable of $2 million, $2 million and $10 million, respectively, related to effectively settled and uncertain tax positions.

Possible Changes to Unrecognized Tax Benefits

It is reasonably possible that the amount of unrecognized tax benefits with respect to PHI’s uncertain tax positions will significantly increase or decrease within the next 12 months. In order to mitigate the cost of continued litigation of tax matters related to the former cross-border energy lease investments, PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues for open tax years 2001 through 2011. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2015, which could significantly impact the balances of unrecognized tax benefits and the related interest accruals. At this time, it is estimated that there will be a $700 million to $800 million decrease in unrecognized tax benefits within the next 12 months. See Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” 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.

Final IRS Regulations on Repair of Tangible Property

In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on PHI’s consolidated financial statements.

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PEPCO HOLDINGS

Other Taxes

Other taxes for continuing operations are shown below. The annual amounts include $407 million, $422 million and $426 million for the years ended December 31, 2014, 2013 and 2012, respectively, related to Power Delivery, which are recoverable through rates.

	2014		2013		2012
	(millions of dollars)
Gross Receipts/Delivery	$	123	$	133	$	135
Property		84		77		75
County Fuel and Energy		143		153		160
Environmental, Use and Other		63		65		62
Total	$	413	$	428	$	432

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

Stock-Based Compensation

Pepco Holdings maintains the 2012 Long-Term Incentive Plan (2012 LTIP), the successor plan to the Long-Term Incentive Plan (LTIP), the objective 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 (loss) for the years ended December 31, 2014, 2013 and 2012 was $18 million, $12 million and $11 million, respectively, all of which was associated with restricted stock, restricted stock unit and unrestricted stock awards.

No material amount of stock compensation expense was capitalized for the years ended December 31, 2014, 2013 and 2012.

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 and restricted stock units, and time-based restricted stock and restricted stock units. A summary of each of these programs is as follows:

• 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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PEPCO HOLDINGS

• PHI granted a total of 21,138 and 37,735 restricted stock units in 2014 and 2013, respectively, to its non-employee directors under the 2012 LTIP. These restricted stock units vest over a service period which 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. These awards represent the equity portion of the annual retainer paid to non-employee directors for their service as a director of PHI.

Activity for the year

The 2014 activity for restricted stock, performance-based restricted stock, time-based restricted stock units and performance-based restricted stock unit awards, is summarized in the table below. For performance-based restricted stock and restricted stock unit awards, the table reflects awards projected, for purposes of computing the weighted average grant date fair value, to achieve 100% of targeted performance criteria for each outstanding award cycle.

				Weighted
	Number			Average Grant
	of Shares			Date Fair Value
Balance as of January 1, 2014 (a)
Restricted stock		—		$	—
Performance-based restricted stock		—			—
Time-based restricted stock units		583,554			19.34
Performance-based restricted stock units		1,069,830			19.06
Total		1,653,384
Granted during 2014
Restricted stock		183,486			26.80
Performance-based restricted stock		70,276			27.01
Time-based restricted stock units		222,350			19.77
Performance-based restricted stock units		448,107			18.53
Total		924,219
Vested during 2014
Restricted stock		(129,321	)		26.80
Time-based restricted stock units		(336,946	)		19.25
Performance-based restricted stock units		(349,020	)		21.07
Total		(815,287	)
Forfeited during 2014
Performance-based restricted stock units		(340,936	)		19.54
Total		(340,936	)
Balance as of December 31, 2014 (b)
Restricted stock		54,165			26.80
Performance-based restricted stock		70,276			27.01
Time-based restricted stock units		468,958			19.61
Performance-based restricted stock units		827,981			17.73
Total		1,421,380

(a) The balance as of January 1, 2014 does not include 59,523 time-based restricted stock units and 31,403 performance-based restricted stock units that were vested but had not yet settled.

(b) The balance as of December 31, 2014 does not include 36,110 shares of restricted stock, 94,685 time-based restricted stock units and 59,797 performance-based restricted stock units that were vested but had not yet settled.

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PEPCO HOLDINGS

Grants included in the table above reflect 2014 grants of restricted stock, performance-based restricted stock, time-based restricted stock units and performance-based restricted stock unit awards. PHI recognizes compensation expense related to restricted stock, performance-based restricted stock, time-based restricted stock units and performance-based 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 per share of those awards granted during each of the years ended December 31, 2014, 2013 and 2012:

	2014		2013		2012
Weighted average grant-date fair value of each restricted stock award granted during the year	$	26.80	$	—	$	—
Weighted average grant-date fair value of each performance-based restricted stock award granted during the year	$	27.01	$	—	$	—
Weighted average grant-date fair value of each unrestricted stock award granted during the year	$	—	$	—	$	18.85
Weighted average grant-date fair value of each time-based restricted stock unit award granted during the year	$	19.77	$	19.70	$	19.69
Weighted average grant-date fair value of each performance-based restricted stock unit award granted during the year	$	18.53	$	17.03	$	21.13

As of December 31, 2014, there was approximately $12 million of future compensation cost (net of estimated forfeitures) related to 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.

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 or the 2012 LTIP since 2002. As of December 31, 2012, all outstanding stock options under predecessor plans have been exercised or expired. Total intrinsic value and tax benefits recognized for stock options exercised in 2012 were immaterial.

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, 2014, 2013 and 2012 was not material.

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Compensation expense recognized in respect of dividends and the increase in fair value was $1 million for the year ended December 31, 2014 and not material for each of the years ended December 31, 2013 and 2012. The deferred compensation balances under this program were approximately $2 million at December 31, 2014 and 2013.

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, 2014. 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. As further described in Note (10), “Debt,” PHI, Pepco, DPL and ACE have restrictions on total indebtedness in relation to total capitalization under the credit facility.

PHI had approximately $565 million and $595 million of retained earnings free of restrictions at December 31, 2014 and 2013, respectively. These amounts represent the total retained earnings balances at those dates. The amount of restricted net assets for PHI’s consolidated subsidiaries at December 31, 2014 is $2,547 million.

For the years ended December 31, 2014, 2013 and 2012, dividends paid by PHI’s subsidiaries were as follows:

Subsidiary	2014		2013		2012
	(millions of dollars)
Pepco (paid to PHI)	$	86	$	46	$	35
DPL (paid to Conectiv)		100		30		—
ACE (paid to Conectiv)		26		60		35
Total	$	212	$	136	$	70

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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,
	2014		2013			2012
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	242	$	110		$	218
Net (loss) income from discontinued operations		—		(322	)		67
Net income (loss)	$	242	$	(212	)	$	285
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		251		246			229
Adjustment to shares outstanding		—		—			—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		251		246			229
Net effect of potentially dilutive shares (a)		1		—			1
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		252		246			230
Basic earnings per share of common stock from continuing operations	$	0.96	$	0.45		$	0.95
Basic (loss) earnings per share of common stock from discontinued operations		—		(1.31	)		0.30
Basic earnings (loss) per share	$	0.96	$	(0.86	)	$	1.25
Diluted earnings per share of common stock from continuing operations	$	0.96	$	0.45		$	0.95
Diluted (loss) earnings per share of common stock from discontinued operations		—		(1.31	)		0.29
Diluted earnings (loss) per share	$	0.96	$	(0.86	)	$	1.24

(a) There were no options to purchase shares of common stock that were excluded from the calculation of diluted earnings per share for the years ended December 31, 2014, 2013 and 2012.

Equity Forward Transaction

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

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Direct Stock Purchase and Dividend Reinvestment Plan

PHI maintains a Direct Stock Purchase and Dividend Reinvestment Plan (DRP) through which participants may reinvest cash dividends. In addition, participants can make purchases of shares of PHI common stock through the investment of not less than $25 per purchase nor more than $300,000 each calendar year. Shares of common stock purchased through the DRP may be new shares, treasury shares held by PHI, or, at the election of PHI, shares purchased in the open market. Approximately 1 million, 2 million and 2 million new shares were issued and sold under the DRP in 2014, 2013 and 2012, respectively.

Pepco Holdings Common Stock Reserved and Unissued

The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2014:

Name of Plan	Number of Shares
DRP		4,982,016
Pepco Holdings Long-Term Incentive Plan (a)		6,946,614
Pepco Holdings 2012 Long-Term Incentive Plan		7,746,773
Pepco Holdings Non-Management Directors Compensation Plan (b)		457,211
Pepco Holdings Retirement Savings Plan		4,003,652
Total		24,136,266

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

(b) This plan expired by its terms on December 31, 2014.

(13)PREFERRED STOCK

In connection with entering into the Merger Agreement (as further described in Note (1), “Organization”), PHI entered into a Subscription Agreement with Exelon, dated April 29, 2014, pursuant to which PHI issued to Exelon 9,000 originally issued shares of Preferred Stock for a purchase price of $90 million on April 30, 2014. In connection with these agreements, Exelon also committed to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following April 29, 2014, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014 and January 26, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for a purchase price of $18 million. If the Merger closes or terminates for any reason, no additional shares of Preferred Stock will be issued pursuant to the Subscription Agreement. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

If the Merger Agreement is terminated under certain circumstances due to the failure to obtain regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value. If the Merger Agreement is terminated for any other reason, PHI will be required to redeem all issued and outstanding Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

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PHI has excluded the Preferred Stock from equity at December 31, 2014 since the Preferred Stock contains conditions for redemption that are not solely within the control of PHI. Management determined that the Preferred Stock contains embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding Preferred Stock could be called and redeemed at a nominal par value upon a Regulatory Termination. The embedded call and redemption features on the shares of the Preferred Stock in the event of a Regulatory Termination are separately accounted for as derivatives. The estimated fair value of the derivatives related to the Preferred Stock was $3 million and has been included in current assets (Prepaid expenses and other) with a corresponding increase in Preferred Stock on the consolidated balance sheet at December 31, 2014, representing an increase in the fair value of the Preferred Stock as of such date. These Preferred Stock derivatives were valued using quantitative and qualitative factors at both the issuance date and December 31, 2014, including management’s assessment of the likelihood of a Regulatory Termination. There was no material change in the fair value of these derivatives during the fourth quarter of 2014. The fair value of these derivatives will be determined quarterly, and any increases or decreases in such fair value in future periods would be recorded as income or loss.

(14)DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Derivative Instruments

DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC. In addition, included in derivative assets are PHI Preferred Stock derivatives which are further described in Note (13), “Preferred Stock.”

ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would have received payments from or made 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. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because these generators cleared the 2015-2016 PJM capacity auction in May 2012. The fair value of the derivatives embedded in these SOCAs were deferred as regulatory assets or regulatory liabilities because the NJBPU allowed full recovery from ACE’s distribution customers for any payments made by ACE, and ACE’s distribution customers would be entitled to payments received by ACE.

As further discussed in Note (7), “Regulatory Matters,” in light of a Federal district court order, which ruled that the SOCAs are void, invalid and unenforceable, and ACE’s subsequent termination of the SOCAs in the fourth quarter of 2013, ACE derecognized the derivative assets and derivative liabilities related to the SOCAs.

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The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2014 and 2013:

	As of December 31, 2014
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative assets (current assets)	$	—	$	3		$	3		$	—	$	3
Derivative liabilities (current liabilities)		—		(4	)		(4	)		4		—
Net Derivative (liability) asset	$	—	$	(1	)	$	(1	)	$	4	$	3

	As of December 31, 2013
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments		Gross Derivative Instruments		Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative assets (current assets)	$	—	$	1	$	1	$	(1	)	$	—

All derivative assets and liabilities available to be offset under master netting arrangements were netted as of December 31, 2014 and 2013. The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2014		December 31, 2013
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	4	$	—
Cash collateral received from counterparties with the obligation to return	$	—	$	(1	)

(a) Includes cash deposits on commodity brokerage accounts.

As of December 31, 2014 and 2013, all PHI cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

PHI also may use 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 AOCL and is being recognized in interest expense over the life of the debt issued as interest payments are made.

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The tables below provide details regarding terminated cash flow hedges included in PHI’s consolidated balance sheets as of December 31, 2014 and 2013. The data in the following tables indicate the cumulative net loss after-tax related to terminated 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, 2014				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Interest rate	$	9	$	1	212 months

Contracts	As of December 31, 2013				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Interest rate	$	9	$	1		224 months

Other Derivative Activity

PHI, 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 addition, in accordance with FASB guidance on regulated operations, regulatory liabilities or regulatory assets of the same amount 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 ACE SOCA derivatives. During 2012, ACE had recognized derivative assets and derivative liabilities in connection with the SOCAs referred to in Note (7), “Regulatory Matters.” In 2013, the Federal district court issued an order as described in Note (7), “Regulatory Matters” which caused ACE to derecognize the derivative assets and derivatives liabilities related to the SOCAs in the fourth quarter of 2013. The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the consolidated statements of income (loss) (through Fuel and purchased energy expense) and that were also deferred as Regulatory liabilities and Regulatory assets for the years ended December 31, 2014, 2013 and 2012:

	For the Year Ended December 31,
	2014			2013			2012
	(millions of dollars)
Net unrealized (loss) gain arising during the period	$	(3	)	$	4		$	(6	)
Net realized gain (loss) recognized during the period		2			(4	)		(16	)

As of December 31, 2014 and 2013, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were:

	December 31, 2014			December 31, 2013
Commodity	Quantity		Net Position	Quantity		Net Position
DPL – Natural gas (one Million British Thermal Units (MMBtu))		3,892,500	Long		3,977,500	Long

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In addition, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock as further described in Note (13), “Preferred Stock.”

(15)FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

PHI applies FASB guidance on fair value measurement (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, 2014 and 2013. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2014
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
Preferred stock	$	3	$	—	$	—	$	3
Restricted cash equivalents
Treasury fund		38		38		—		—
Executive deferred compensation plan assets
Money market funds and short-term investments		35		14		21		—
Life insurance contracts		46		—		27		19
Total	$	122	$	52	$	48	$	22
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	4	$	4	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		30		—		30		—
Total	$	34	$	4	$	30	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

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

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

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	Fair Value Measurements at December 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (b)
Natural gas (c)	$	1	$	1	$	—	$	—
Restricted cash and cash equivalents
Treasury fund		34		34		—		—
Executive deferred compensation plan assets
Money market funds and short-term investments		35		15		20		—
Life insurance contracts		46		—		27		19
Total	$	116	$	50	$	47	$	19
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	30	$	—	$	30	$	—
Total	$	30	$	—	$	30	$	—

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

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

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

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 and liabilities categorized as level 2 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, 2014. 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 (which are included with life insurance contracts in the tables above) 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.

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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 classified as level 3 include embedded call and redemption features on the Preferred Stock as further discussed in Note (13), “Preferred Stock.”

Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by 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, 2014 and 2013 are shown below:

	Year Ended December 31, 2014					Year Ended December 31, 2013
	Preferred Stock		Life Insurance Contracts			Natural Gas			Life Insurance Contracts			Capacity
	(millions of dollars)
Balance as of January 1	$	—	$	19		$	(4	)	$	18		$	(3	)
Total gains (losses) (realized and unrealized):
Included in income		—		3			—			4			—
Included in accumulated other comprehensive loss		—		—			—			—			—
Included in regulatory liabilities		—		—			—			—			3
Purchases		—		—			—			—			—
Issuances		3		(3	)		—			(3	)		—
Settlements		—		—			4			—			—
Transfers in (out) of level 3		—		—			—			—			—
Balance as of December 31	$	3	$	19		$	—		$	19		$	—

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

	Year Ended December 31,
	2014		2013
	(millions of dollars)
Total net gains included in income for the period	$	3	$	4
Change in unrealized gains relating to assets still held at reporting date	$	3	$	4

Other Financial Instruments

The estimated fair values of PHI’s Long-term 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, 2014 and 2013 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

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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 on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and PHI reviews the methodologies and results.

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

	Fair Value Measurements at December 31, 2014
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)	$	5,583	$	—	$	5,136	$	447
Transition Bonds (b)		235		—		235		—
Long-term project funding		28		—		—		28
Total	$	5,846	$	—	$	5,371	$	475

(a) The carrying amount for Long-term debt was $4,807 million as of December 31, 2014.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014.

	Fair Value Measurements at December 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	4,850	$	—	$	4,289	$	561
Transition Bonds (b)		284		—		284		—
Long-term project funding		12		—		—		12
Total	$	5,146	$	—	$	4,573	$	573

(a) The carrying amount for Long-term debt was $4,456 million as of December 31, 2013.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $255 million as of December 31, 2013.

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

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(16) COMMITMENTS AND CONTINGENCIES

General Litigation and Other Matters

From time to time, PHI and its subsidiaries are named as defendants in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. PHI and each of its subsidiaries are self-insured against such claims up to a certain self-insured retention amount and maintain insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, PHI’s contracts with its vendors generally require the vendors to name PHI and/or its subsidiaries as additional insureds for the amounts at least equal to PHI’s self-insured retention. Further, PHI’s contracts with its vendors require the vendors to indemnify PHI for various acts and activities that may give rise to claims against PHI. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on PHI’s or its subsidiaries’ financial condition, results of operations or cash flows. At December 31, 2014, PHI had recorded estimated loss contingency liabilities for general litigation totaling approximately $33 million (including amounts related to the matters specifically described below), and the portion of these estimated loss contingency liabilities in excess of the self-insured retention amount was substantially offset by estimated insurance receivables.

Pepco Substation Injury Claim

In May 2013, a worker employed by a subcontractor to erect a scaffold at a Pepco substation came into contact with an energized transformer and suffered serious injuries. In August 2013, the individual filed suit against Pepco in the Circuit Court for Montgomery County, Maryland, seeking damages for past and future medical expenses, past and future lost wages, pain and suffering and the cost of a life care plan. On October 22, 2014, an award of approximately $21.7 million was entered in favor of the plaintiff in this matter. Pepco has recorded this liability as of December 31, 2014, which is included in the liability for general litigation referred to above. Pepco’s insurer and the contractor’s insurer have acknowledged insurance coverage for the incident, including coverage of Pepco’s self-insured retention amount. Pepco has concluded as of December 31, 2014, that realization of its insurance claims associated with this matter is probable and, accordingly, has recorded an estimated insurance receivable of the same amount as the related liability.

ACE Asbestos Claim

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 December 31, 2014, ACE has concluded that a loss is probable with respect to this matter and has recorded an estimated loss contingency liability, which is included in the liability for general litigation referred to above as of December 31, 2014. However, due to the inherent uncertainty of litigation, ACE is unable to estimate a maximum amount of possible loss because the damages sought are indeterminate and 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.

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ACE Electrical Contact Injury Claims

In October 2010, a farm combine came into and remained in contact with a primary electric line in ACE’s service territory in New Jersey. As a result, two individuals operating the combine received fatal electrical contact injuries. While attempting to rescue those two individuals, another individual sustained third-degree burns to his torso and upper extremities. In September 2012, the individual who received third-degree burns filed suit in New Jersey Superior Court, Salem County. In October 2012, additional suits were filed in the same court by or on behalf of the estates of the deceased individuals. Plaintiffs in each of the cases sought indeterminate damages and alleged that ACE was negligent in the design, construction, erection, operation and maintenance of its poles, power lines, and equipment, and that ACE failed to warn and protect the public from the foreseeable dangers of farm equipment contacting electric lines. The litigation involved a number of other defendants and the filing of numerous cross-claims. On September 23, 2014, ACE entered into a confidential settlement with each of the plaintiffs regarding this matter. On November 5, 2014, ACE received reimbursement from its insurers for the amounts of this settlement above its $2 million self-insured retention amount.

Pepco Energy Services Billing Claims

During 2012, Pepco Energy Services received letters on behalf of two school districts in Maryland, which claim that they had paid invoices in connection with electricity supply contracts that included certain allegedly unauthorized charges, totaling approximately $7 million, for which they were entitled to reimbursement. The school districts also claim additional compounded interest totaling approximately $9 million. Although no litigation involving Pepco Energy Services related to these claims has commenced, in August and September 2013, Pepco Energy Services received correspondence from the Superintendent of each of the school districts advising of the intention to render a decision regarding an unresolved dispute between the school district and Pepco Energy Services. Pepco Energy Services filed timely answers to the Superintendents challenging their authority to render decisions on the claims and also disputing the merits of the allegations regarding unauthorized charges as well as the claims of entitlement to compounded interest.

With respect to the claim of one of the school districts, in July 2014 its Superintendent determined that Pepco Energy Services should reimburse the allegedly unauthorized charges related to that district, totaling approximately $3 million, but rejected the school district’s claim for interest (representing $4 million of the $9 million of total compounded interest originally claimed by both school districts). Throughout these proceedings, the Superintendent acknowledged the availability of administrative and judicial review of the merits of any decision. Pepco Energy Services appealed the Superintendent’s determination to the district’s Board of Education. On November 19, 2014, that district’s Board of Education voted to sustain the Superintendent’s ruling and Pepco Energy Services has filed a timely notice of appeal of that ruling with the Maryland State Board of Education. The Board of Education sought to enter judgment against Pepco Energy Services in a Maryland circuit court. On December 17, 2014, Pepco Energy Services filed petitions in the U.S. District Court for the District of Maryland seeking declaratory judgment and to vacate the Board of Education’s award, thereby challenging both the action of the Board of Education to enter judgment against Pepco Energy Services without further review and the determination of the Board of Education on the merits. The Superintendent of the other school district has not yet acted on the matter. Both Superintendents and the district Board of Education from whose determination an administrative appeal has been taken have acknowledged the availability of administrative and judicial review of the merits of any decision. As of December 31, 2014, Pepco Energy Services has concluded that a loss is reasonably possible with respect to these claims, but the amount of loss, if any, is not reasonably estimable.

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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, 2014 are summarized as follows:

			Legacy Generation
	Transmission and Distribution		Regulated		Non-Regulated		Total
	(millions of dollars)
Balance as of January 1	$	19	$	6	$	5	$	30
Accruals		—		—		—		—
Payments		2		—		—		2
Balance as of December 31		17		6		5		28
Less amounts in Other Current Liabilities		3		1		—		4
Amounts in Other Deferred Credits	$	14	$	5	$	5	$	24

Conectiv Energy Wholesale Power Generation Sites

In July 2010, PHI sold the wholesale power generation business of Conectiv Energy 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 PHI’s estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million. The amount accrued by PHI for the ISRA-required remediation activities at the nine generating facility sites is included in the table above in the column entitled “Legacy Generation – Non-Regulated.”

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

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Franklin Slag Pile Site

In November 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA’s feasibility study for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

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

Peck Iron and Metal Site

EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and 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 in November 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 this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

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Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including Pepco, DPL and ACE, 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 Pepco, DPL and ACE) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the Federal 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 Federal district court’s order addresses only the liability of the test case defendant. Plaintiffs have appealed the district court’s order to the U.S. Court of Appeals for the Fourth Circuit. PHI has concluded that a loss is reasonably possible with respect to this matter, but is unable to estimate an amount or range of reasonably possible losses to which it may be exposed. PHI does not believe that any of its three utility subsidiaries had extensive business transactions, if any, with the Ward Transformer site.

Benning Road Site

Contamination of Lower Anacostia River

In September 2010, PHI received a letter from EPA identifying the Benning Road location, consisting of a generation facility formerly operated by Pepco Energy Services, and a transmission and distribution service center facility operated by Pepco, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The generation facility was deactivated in June 2012 and the plant structures are currently in the process of being demolished, but the service center remains in operation. The principal contaminants of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of the Environment (DDOE), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 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 Pepco and Pepco Energy Services 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 final phase of remedial investigation field work, consisting of the installation of monitoring wells and groundwater sampling and analysis, began in May 2014. In addition, as part of the remaining remedial investigation field work and in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the cooling towers previously dismantled and removed from the site of the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and Pepco has submitted a plan to DDOE for the removal of contaminated soil in conjunction with the demolition and removal of the concrete basins. The remedial investigation field sampling was completed in December 2014. Pepco and Pepco Energy Services will prepare RI/FS reports for review and approval by DDOE after solicitation and consideration of public comment. The next status report to the court is due on May 25, 2015.

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.”

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NPDES Permit Limit Exceedances

Pepco holds a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA with a June 19, 2009 effective date, which authorizes discharges from the Benning Road facility, including the now deactivated Pepco Energy Services generating facility located at that site. The 2009 permit imposed compliance monitoring and storm water best management practices to satisfy the District of Columbia’s Total Maximum Daily Load (TMDL) standards for polychlorinated biphenyls, oil and grease, metals and other substances. As part of the implementation of the TMDL requirements, the permit also imposed numerical limits on certain substances in storm water discharges to the Anacostia River. Quarterly monitoring results since the issuance of the permit have shown consistent exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead. As required by the permit, Pepco initiated a study to identify the potential sources of these substances at the site and to determine appropriate best management practices for minimizing the presence of the substances in storm water discharges from the facility. The initial study report was completed in May 2012. Pepco has completed the implementation of the first two phases of the best management practices recommended in the study report (consisting principally of installing metal absorbing filters to capture contaminants from storm water flows, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures have been effective in reducing metal concentrations in stormwater discharges; however, additional measures will be required to be implemented by Pepco to reduce the concentrations to levels required by the permit.

The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road facility has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. Pepco has prepared a plan to implement the third phase of the best management practices recommended in the study report with the objective of achieving full compliance with the permit limits by the end of 2015. The plan was submitted to EPA on December 30, 2014, and Pepco has begun implementing those best practices in accordance with the plan. Pepco anticipates that EPA may request that Pepco enter into an administrative compliance agreement with respect to the implementation of these additional control measures, and may seek administrative penalties for past noncompliance with the permit limits for metals in storm water. Whether such penalties will be imposed and, if so, the amount of any such penalties, is not known or estimable at this time. At present, Pepco expects that compliance with the permit limits can be achieved through a combination of enhanced storm drain inlet controls (filters and metal absorbing booms), enhanced site housekeeping, and enhanced inspection and maintenance of storm water controls. If these measures are not adequate to achieve compliance with the permit limits, however, it is possible that a capital project to install a storm water treatment system may be required. The need for any such capital expenditures will not be known until Pepco has implemented the third phase of the best management practices.

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.

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In March 2014, Pepco and DDOE entered into a consent decree to resolve a threatened DDOE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with Living Classrooms Foundation, Inc., a non-profit educational organization, to provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. The design for the trash collection system is currently under review by DDOE, and Pepco expects that this system will be constructed and placed into operation by the end of 2015, which will satisfy Pepco’s obligations under the consent decree. The next status hearing in this matter has been set for September 18, 2015.

The consent decree does not resolve potential claims under federal law for natural resource damages resulting from the oil release. Pepco has engaged in separate discussions with DDOE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. The federal trustees are still evaluating the claim and the terms of a possible settlement. At this time, it is uncertain whether or when the settlement discussions may resume or if the trustees will continue to pursue the natural resource damages claim. Based on discussions to date, PHI and Pepco do not believe that the resolution of the federal natural resource damages claim will have a material adverse effect on their respective financial condition, results of operations or cash flows.

As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an above-ground 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 on a pilot basis to demonstrate its effectiveness in meeting both secondary containment requirements and water quality standards related to the discharge of storm water from the facility. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system. Pepco also is evaluating other technical and regulatory options for managing storm water from the secondary containment system as alternatives to the proposed treatment system discharge currently under discussion with EPA and DDOE.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Metal Bank Site

In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco and DPL on behalf of itself and other federal and state trustees to request that Pepco and DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. Pepco and DPL executed a tolling agreement, which has been extended to March 15, 2015, and will continue settlement discussions with the NOAA, the trustees and other PRPs.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

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Brandywine Fly Ash Disposal Site

In February 2013, Pepco received a letter from the Maryland Department of the Environment (MDE) requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

PHI and Pepco have determined that a loss associated with this matter for PHI and Pepco is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Virginia Department of Environmental Quality Notice of Violation

On February 2, 2015, the Virginia Department of Environmental Quality (VDEQ) issued a notice of violation (NOV) to DPL in connection with alleged violations of state water control laws and regulations associated with recent construction activities undertaken to replace certain transmission facilities. The NOV informs DPL of information on which VDEQ may rely to institute an administrative or judicial enforcement action, requests a meeting, and states that DPL may be asked to enter into a consent order to formalize a plan and schedule of corrective action and settle any outstanding issues regarding the matter including the assessment of civil charges. Whether any such charges will be assessed is not known or estimable at this time. PHI and DPL do not believe that the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

PHI’s Cross-Border Energy Lease Investments

As discussed in Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments,” PHI held a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States. Each of these investments was comprised of multiple leases and was 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 for the purpose of commencing litigation associated with this matter and subsequently filed refund claims in July 2011 for the disallowed tax deductions relating to the leases for these years. In January 2011, as part of this settlement, PHI paid $74 million of additional tax for 2001 and 2002, penalties of $1 million, and $28 million in interest associated with the disallowed deductions. Since the July 2011 refund claims were not approved by the IRS within the statutory six-month period, in January 2012 PHI filed complaints in the U.S. Court of Federal Claims seeking recovery of the tax payment, interest and penalties. The 2003-2005 and 2006-2011 income tax return audits continue to be in process with the IRS Office of Appeals and the IRS Exam Division, respectively, and are not presently a part of the U.S. Court of Federal Claims litigation.

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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. While PHI believes that its tax position with regard to its cross-border energy lease investments is appropriate, after analyzing the recent U.S. Court of Appeals ruling, PHI determined in the first quarter of 2013 that its tax position with respect to the tax benefits associated with the cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes. Accordingly, PHI recorded a non-cash after-tax charge of $377 million in the first quarter of 2013 (as discussed in Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”), consisting of a charge to reduce the carrying value of the cross-border energy lease investments and a charge to reflect the anticipated additional interest expense related to changes in PHI’s estimated federal and state income tax obligations for the period over which the tax benefits ultimately may be disallowed. PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. During the first quarter of 2013, management believed that its conclusions regarding these business assumptions were no longer supportable, and the tax effects of this change in conclusion were included in the charge. While the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due, PHI believes that it is more likely than not that no such penalty will be incurred, and therefore no amount for any potential penalty has been recorded.

In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these lease investments and recharacterize these lease investments as loans, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal taxes (net of the $74 million tax payment described above) and approximately $50 million of interest on the additional federal taxes. These amounts, totaling $242 million, were estimated after consideration of certain tax benefits arising from matters unrelated to the leases that would offset the taxes and interest due, including PHI’s best estimate of the expected resolution of other uncertain and effectively settled tax positions, the carrying back and carrying forward of any existing net operating losses, and the application of certain amounts 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. A portion of the proceeds from lease terminations (discussed in Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”) was used to repay the short-term borrowings utilized to fund the advanced payment.

In order to mitigate the cost of continued litigation related to the cross-border energy lease investments, PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues for open tax years 2001 through 2011, including the cross-border energy lease issue. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2015. If a settlement of all tax issues or a standalone settlement on the leases is not reached, PHI may move forward with its litigation with the IRS. Further discovery in the case is stayed until March 19, 2015, pursuant to an order issued by the court on December 2, 2014.

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

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

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As of December 31, 2014, 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
	(millions of dollars)
Guarantees associated with disposal of Conectiv Energy assets (a)	$	13	$	—	$	—	$	—	$	13
Guaranteed lease residual values (b)		3		5		7		5		20
Total	$	16	$	5	$	7	$	5	$	33

(a) 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.

(b) 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 $52 million, $10 million of which is a guarantee by PHI, $13 million by Pepco, $16 million by DPL and $13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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

Energy Savings Performance Contracts

Pepco Energy Services has a diverse portfolio of energy savings performance contracts that are associated with the installation of energy savings equipment 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, 2014, the remaining notional amount of Pepco Energy Services’ energy savings guarantees over the life of the multi-year performance contracts on: (i) completed projects was $356 million with the longest guarantee having a remaining term of 23 years; and, (ii) projects under construction was $61 million with the longest guarantee having a term of 13 years after completion of construction. 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, 2014, 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 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, 2014, Pepco Energy Services had an accrued liability of $1 million for an energy savings contract under which construction was completed in 2012. There was no significant change in the type of contracts issued during the year ended December 31, 2014 as compared to the year ended December 31, 2013.

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Dividends

On January 22, 2015, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2015, to stockholders of record on March 10, 2015.

Contractual Obligations

Power Purchase Contracts

As of December 31, 2014, Pepco Holdings’ contractual obligations under non-derivative power purchase contracts were $276 million in 2015, $509 million in 2016 to 2017, and $478 million in 2018 to 2019 and $1,177 million thereafter.

Lease Commitments

Rental expense for operating leases was $59 million, $54 million and $52 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Total future minimum operating lease payments for Pepco Holdings as of December 31, 2014 are $45 million in 2015, $43 million in 2016, $40 million in 2017, $40 million in 2018, $28 million in 2019 and $329 million thereafter.

(17)VARIABLE INTEREST ENTITIES

PHI is required to consolidate a VIE in accordance with FASB ASC 810 if PHI or a subsidiary is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. PHI performs a qualitative analysis to determine whether a variable interest provides a controlling financial interest in any of the VIEs in which PHI or its subsidiaries have an interest. Set forth below are the relationships with respect to which PHI conducted a VIE analysis as of December 31, 2014:

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, 2014, PHI, through its DPL subsidiary, is a party to three land-based wind PPAs in the aggregate amount of 128 MWs, one solar PPA with a 10 MW facility, and a PPA with the Delaware Sustainable Energy Utility (DSEU) to purchase solar renewable energy credits (SRECs). 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 SRECs from the solar facility and DSEU, up to certain amounts (as set forth below) at rates that are primarily fixed under the respective agreements. PHI and DPL have concluded that while VIEs exist under these contracts, consolidation is not required under the FASB guidance on the consolidation of VIEs as DPL is not the primary beneficiary. DPL has not provided financial or other support under these arrangements that it was not previously contractually required to provide during the periods presented, nor does DPL have any intention to provide such additional support.

Because DPL has no equity or debt interest in these renewable energy transactions, the maximum exposure to loss relates primarily to any above-market costs incurred for power, RECs or SRECs. Due to unpredictability in the amount of MWs ultimately purchased under the agreements for purchased renewable energy, RECs and SRECs, PHI and DPL are unable to quantify the maximum exposure to loss. The power purchase, REC and SREC costs are recoverable from DPL’s customers through regulated rates.

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Wind PPAs

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. DPL’s aggregate purchases under the three wind PPAs totaled $31 million, $30 million and $27 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Solar PPAs

The term of the PPA with the solar facility is through 2030 and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. The DSEU may enter into 20-year contracts with solar facilities to purchase SRECs for resale to DPL. Under the DSEU PPA, DPL is obligated to purchase SRECs in amounts not to exceed 19 MWs at annually determined auction rates. DPL’s purchases under these solar PPAs totaled $6 million, $3 million and $2 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Fuel Cell Facilities

On October 18, 2011, the 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 acts solely as an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each MW hour of energy produced by the fuel cell facilities through 2033. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. At December 31, 2014 and 2013, 30 MWs and 15 MWs of capacity were available from fuel cell facilities placed in service under the tariff, respectively. DPL billed $36 million, $23 million and $4 million to distribution customers for the years ended December 31, 2014, 2013 and 2012, respectively.

ACE Power Purchase Agreements

PHI, through its ACE subsidiary, is a party to three PPAs with unaffiliated NUGs totaling 459 MWs. One of the agreements ends in 2016 and the other two end in 2024. PHI and ACE have no equity or debt invested in these entities. In performing its VIE analysis, PHI has been 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 has applied the scope exemption from the consolidation guidance.

Because ACE has no equity or debt invested in the NUGs, the maximum exposure to loss relates primarily to any above-market costs incurred for power. Due to unpredictability in the pricing for purchased energy under the PPAs, PHI and ACE are unable to quantify the maximum exposure to loss. The power purchase costs are recoverable from ACE’s customers through regulated rates. Purchase activities with the NUGs, including excess power purchases not covered by the PPAs, for the years ended December 31, 2014, 2013 and 2012, were approximately $233 million, $221 million and $206 million, respectively, of which approximately $208 million, $206 million and $201 million, respectively, consisted of power purchases under the PPAs.

ACE Funding

In 2001, ACE established ACE Funding solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable Transition Bond Charge (representing revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) from ACE customers pursuant to bondable stranded costs rate orders issued by the 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). The assets of ACE Funding,

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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 Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding, and PHI and ACE consolidate ACE Funding in their consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

(18) ACCUMULATED OTHER COMPREHENSIVE LOSS

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

	Year Ended December 31,
	2014			2013			2012
	(millions of dollars)
Balance as of January 1	$	(34	)	$	(48	)	$	(63	)
Treasury Lock
Balance as of January 1		(9	)		(10	)		(10	)
Amount of pre-tax loss reclassified to Interest expense		1			1			—
Income tax expense		1			—			—
Balance as of December 31		(9	)		(9	)		(10	)
Pension and Other Postretirement Benefits
Balance as of January 1		(25	)		(32	)		(24	)
Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense		5			5			5
Amount of net prior service cost and actuarial (loss) gain arising during the year		(25	)		8			(19	)
Income tax (benefit) expense		(8	)		6			(6	)
Balance as of December 31		(37	)		(25	)		(32	)
Commodity Derivatives
Balance as of January 1		—			(6	)		(29	)
Amount of net pre-tax loss reclassified to (Loss) income from discontinued operations before income tax		—			10			39
Income tax expense		—			4			16
Balance as of December 31		—			—			(6	)
Balance as of December 31	$	(46	)	$	(34	)	$	(48	)

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(19) 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.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars, except per share amounts)
Total Operating Revenue (a)	$	1,330		$	1,117		$	1,313		$	1,118		$	4,878
Total Operating Expenses (b)		1,157			966			1,147			1,004	(c)		4,274
Operating Income		173			151			166			114			604
Other Expenses		(52	)		(53	)		(53	)		(66	)		(224	)
Income from Continuing Operations Before Income Tax Expense		121			98			113			48			380
Income Tax Expense Related to Continuing Operations		46			45			34			13			138
Net Income	$	75		$	53		$	79		$	35		$	242
Basic and Diluted Earnings Per Share of Common Stock:
Earnings Per Share of Common Stock	$	0.30		$	0.21		$	0.31		$	0.14		$	0.96
Cash Dividends Per Share of Common Stock	$	0.27		$	0.27		$	0.27		$	0.27		$	1.08

(a) During the fourth quarter of 2014, ACE reversed unbilled revenue of $3 million ($2 million after-tax) to correct an error that had overstated operating revenue in the third quarter of 2014.

(b) Includes pre-tax impairment losses of $53 million ($32 million after-tax) and $28 million ($16 million after-tax) in the third and fourth quarters of 2014, respectively, at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City.

(c) Includes a charge of $3 million ($2 million after-tax) to correct a prior period error related to the recoverability of certain regulatory assets at ACE.

	2013
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars, except per share amounts)
Total Operating Revenue	$	1,180		$	1,051		$	1,344		$	1,091		$	4,666
Total Operating Expenses		1,047			906			1,109			936	(a)		3,998
Operating Income		133			145			235			155			668
Other Expenses		(59	)		(62	)		(60	)		(58	)		(239	)
Income From Continuing Operations Before Income Tax Expense		74			83			175			97			429
Income Tax Expense Related to Continuing Operations		185	(b)		30			65			39	(c)		319
Net (Loss) Income From Continuing Operations		(111	)		53			110			58			110
(Loss) Income from Discontinued Operations, net of taxes		(319	)		(11	)		8			—			(322	)
Net (Loss) Income	$	(430	)	$	42		$	118		$	58		$	(212	)
Basic and Diluted Earnings Per Share of Common Stock:
(Loss) Earnings Per Share of Common Stock from Continuing Operations	$	(0.47	)	$	0.21		$	0.44		$	0.23		$	0.45
(Loss) Earnings Per Share of Common Stock from Discontinued Operations	$	(1.35	)	$	(0.04	)	$	0.04		$	—		$	(1.31	)
(Loss) Earnings Per Share of Common Stock	$	(1.82	)	$	0.17		$	0.48		$	0.23		$	(0.86	)
Cash Dividends Per Share of Common Stock	$	0.27		$	0.27		$	0.27		$	0.27		$	1.08

(a) Includes a pre-tax impairment loss of $4 million ($3 million after-tax) at Pepco Energy Services associated with a landfill gas-fired electric generation facility.

(b) Includes an income tax charge of $56 million (after-tax) primarily associated with interest on uncertain and effectively settled tax positions and an income tax charge of $101 million associated with the establishment of valuation allowances against certain deferred tax assets of PCI.

(c) Includes an income tax charge of $4 million (after-tax) to correct a prior period error related to Pepco’s deferred income taxes.

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(20) DISCONTINUED OPERATIONS

PHI’s (loss) income from discontinued operations, net of income taxes, is comprised of the following:

	For the Year Ended December 31,
	2014		2013			2012
	(millions of dollars)
Cross-border energy lease investments	$	—	$	(327	)	$	41
Pepco Energy Services’ retail electric and natural gas supply businesses		—		5			26
(Loss) income from discontinued operations, net of income taxes	$	—	$	(322	)	$	67

Cross-Border Energy Lease Investments

Between 1994 and 2002, PCI entered into cross-border energy lease investments consisting of hydroelectric generation facilities, coal-fired electric generation facilities and natural gas distribution networks located outside of the United States. Each of these lease investments was structured as a sale and leaseback transaction commonly referred to as a sale-in, lease-out, or SILO, transaction. During the second and third quarters of 2013, PHI terminated early all of its interests in the remaining lease investments. PHI received aggregate net cash proceeds from these early terminations 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. As a result, PHI has reported the results of operations of the cross-border energy lease investments as discontinued operations in all periods presented in the accompanying consolidated statements of income (loss).

Operating Results

The operating results for the cross-border energy lease investments are as follows:

	For the Year Ended December 31,
	2014		2013			2012
	(millions of dollars)
Operating revenue from PHI’s cross-border energy lease investments	$	—	$	7		$	50
Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments		—		(373	)		—
Total operating revenue	$	—	$	(366	)	$	50
(Loss) income from operations of discontinued operations, net of income taxes (a)	$	—	$	(325	)	$	32
Net (losses) gains associated with the early termination of the cross-border energy lease investments, net of income taxes (b)		—		(2	)		9
(Loss) income from discontinued operations, net of income taxes	$	—	$	(327	)	$	41

(a) Includes income tax (benefit) expense of approximately zero, $(44) million and $5 million for the years ended December 31, 2014, 2013 and 2012, respectively.

(b) Includes income tax (benefit) expense of approximately zero, $(1) million and $30 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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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 determined in the first quarter of 2013 that its tax position with respect to the benefits associated with its cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes, and PCI recorded after-tax non-cash charges of $323 million in the first quarter of 2013 and $6 million in the second quarter 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 originally recorded in the consolidated statements of income (loss) as a reduction in operating revenue and is now reflected in income (loss) from discontinued operations, net of income taxes.

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

PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. In view of the change in PHI’s tax position with respect to the tax benefits associated with the cross-border energy lease investments and PHI’s resulting decision to pursue the early termination of these investments, management concluded in the first quarter of 2013 that these business assumptions were no longer supportable and the tax effects of this conclusion were reflected in the after-tax charge of $313 million described above.

PHI 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.

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

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 (loss).

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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,
	2014		2013		2012
	(millions of dollars)
Operating revenue	$	—	$	84	$	415
Income from operations of discontinued operations, net of income taxes	$	—	$	4	$	26
Net gains associated with accelerated disposition of retail electric and natural gas contracts, net of income taxes				1		—
Income from discontinued operations, net of income taxes (a)	$	—	$	5	$	26

(a) Includes income tax expense of approximately zero, $3 million and $18 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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. There were no outstanding forward contracts or derivative positions for Pepco Energy Services as of December 31, 2014 and December 31, 2013.

Derivatives Designated as Hedging Instruments

At December 31, 2012, the cumulative net pre-tax loss related to effective cash flow hedges of the retail electric and natural gas supply businesses of Pepco Energy Services included in AOCL was $10 million ($6 million after-tax). With the assumption by a third party, on April 1, 2013, of all the rights and obligations of the derivative contracts associated with the retail natural gas supply business, PHI determined that the hedged forecasted purchases of supply for retail natural gas customers were probable not to occur. Accordingly, during the first quarter of 2013, PHI recognized $4 million of pre-tax unrealized derivative losses ($2 million after-tax) that were previously included in AOCL as cash flow hedges. The remaining pre-tax loss of $6 million included in AOCL was reclassified into income on completion of the wind-down of the retail electric business in the second quarter of 2013.

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 (loss) from discontinued operations, net of income taxes.

For the years ended December 31, 2014, 2013, and 2012, the amount of the derivative gain (loss) for the retail electric and natural gas supply businesses of Pepco Energy Services recognized in Income (loss) from discontinued operations, net of income taxes is provided in the table below:

	For the Year Ended December 31,
	2014		2013		2012
	(millions of dollars)
Reclassification of mark-to-market to realized on settlement of contracts	$	—	$	10	$	27
Unrealized mark-to-market loss		—		—		(3	)
Total net gain	$	—	$	10	$	24

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As of December 31, 2014 and 2013, the retail electric and natural gas supply businesses of Pepco Energy Services had no outstanding commodity forward contracts or derivative positions.

As of December 31, 2014, Pepco Energy Services had posted net cash collateral of $2 million and letters of credit of zero. As of December 31, 2013, Pepco Energy Services had posted net cash collateral of $3 million and letters of credit of less than $1 million.

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Management’s Report on Internal Control Over Financial Reporting

The management of Potomac Electric Power Company (Pepco) 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 assessed Pepco’s internal control over financial reporting as of December 31, 2014 based on criteria established in theInternal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of Pepco concluded that Pepco’s internal control over financial reporting was effective as of December 31, 2014.

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Report of Independent Registered Public Accounting Firm

To the Shareholder and Board of Directors

of Potomac Electric Power Company

In our opinion, the financial statements of Potomac Electric Power Company (a wholly owned subsidiary of Pepco Holdings, Inc.) listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Potomac Electric Power Company at December 31, 2014 and December 31, 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule of Potomac Electric Power Company listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Washington, D.C.

February 26, 2015

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

For the Year Ended December 31,	2014			2013			2012
	(millions of dollars)
Operating Revenue	$	2,101		$	2,026		$	1,948
Operating Expenses
Purchased energy		771			750			726
Other operation and maintenance		390			391			403
Depreciation and amortization		229			196			190
Other taxes		363			368			372
Total Operating Expenses		1,753			1,705			1,691
Operating Income		348			321			257
Other Income (Expenses)
Interest expense		(115	)		(110	)		(101	)
Other income		30			18			18
Total Other Expenses		(85	)		(92	)		(83	)
Income Before Income Tax Expense		263			229			174
Income Tax Expense		92			79			48
Net Income	$	171		$	150		$	126

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

ASSETS	December 31, 2014			December 31, 2013
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	6		$	9
Restricted cash equivalents		5			3
Accounts receivable, less allowance for uncollectible accounts of $16 million and $16 million, respectively		315			345
Inventories		62			67
Deferred income tax assets, net		14			48
Income taxes and related accrued interest receivable		94			113
Prepaid expenses and other		21			18
Total Current Assets		517			603
OTHER ASSETS
Regulatory assets		697			563
Prepaid pension expense		316			332
Investment in trust		34			33
Income taxes and related accrued interest receivable		30			36
Other		71			66
Total Other Assets		1,148			1,030
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		7,764			7,310
Accumulated depreciation		(2,816	)		(2,772	)
Net Property, Plant and Equipment		4,948			4,538
TOTAL ASSETS	$	6,613		$	6,171

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

LIABILITIES AND EQUITY	December 31, 2014		December 31, 2013
	(millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	104	$	151
Current portion of long-term debt and project funding		12		175
Accounts payable		94		132
Accrued liabilities		91		90
Accounts payable due to associated companies		30		32
Capital lease obligations due within one year		10		9
Taxes accrued		32		34
Interest accrued		19		20
Liabilities and accrued interest related to uncertain tax positions		—		37
Customer deposits		44		46
Other		102		75
Total Current Liabilities		538		801
DEFERRED CREDITS
Regulatory liabilities		104		113
Deferred income tax liabilities, net		1,584		1,412
Investment tax credits		2		3
Other postretirement benefit obligations		57		61
Liabilities and accrued interest related to uncertain tax positions		—		10
Other		67		65
Total Deferred Credits		1,814		1,664
OTHER LONG-TERM LIABILITIES
Long-term debt		2,124		1,724
Capital lease obligations		50		60
Total Other Long-Term Liabilities		2,174		1,784
COMMITMENTS AND CONTINGENCIES (NOTE 12)
EQUITY
Common stock, $.01 par value, 200,000,000 shares authorized, 100 shares outstanding		—		—
Premium on stock and other capital contributions		1,010		930
Retained earnings		1,077		992
Total Equity		2,087		1,922
TOTAL LIABILITIES AND EQUITY	$	6,613	$	6,171

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

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

For the Year Ended December 31,	2014			2013			2012
	(millions of dollars)
OPERATING ACTIVITIES
Net Income	$	171		$	150		$	126
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		229			196			190
Deferred income taxes		174			120			160
Gains on sales of land		(9	)		—			—
Investment tax credit amortization		—			(1	)		(1	)
Changes in:
Accounts receivable		27			(39	)		22
Inventories		5			2			(19	)
Prepaid expenses		(2	)		(1	)		6
Regulatory assets and liabilities, net		(163	)		(99	)		(110	)
Prepaid pension expense, excluding contributions		16			21			21
Accounts payable and accrued liabilities		(34	)		26			(10	)
Pension contributions		—			—			(85	)
Income tax-related prepayments, receivables and payables		(25	)		(36	)		(69	)
Interest accrued		—			2			—
Other assets and liabilities		(3	)		(11	)		(8	)
Net Cash From Operating Activities		386			330			223
			��
INVESTING ACTIVITIES
Investment in property, plant and equipment		(567	)		(576	)		(592	)
Department of Energy capital reimbursement awards received		3			20			38
Proceeds from sales of land		9			—			—
Changes in restricted cash equivalents		(3	)		(3	)		—
Net other investing activities		(2	)		(5	)		4
Net Cash Used By Investing Activities		(560	)		(564	)		(550	)
FINANCING ACTIVITIES
Dividends paid to Parent		(86	)		(46	)		(35	)
Capital contributions from Parent		80			175			50
Issuances of long-term debt		412			400			200
Reacquisitions of long-term debt		(175	)		(200	)		(38	)
(Repayments) issuances of short-term debt, net		(47	)		(80	)		157
Cost of issuances		(7	)		(7	)		(4	)
Net other financing activities		(6	)		(8	)		(6	)
Net Cash From Financing Activities		171			234			324
Net Decrease in Cash and Cash Equivalents		(3	)		—			(3	)
Cash and Cash Equivalents at Beginning of Year		9			9			12
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	6		$	9		$	9
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $5 million, $5 million and $4 million, respectively)	$	111		$	102		$	97
Cash received for income taxes (includes payments from PHI for Federal income taxes)		(58	)		(28	)		(40	)
Non-cash activities:
Reclassification of property, plant and equipment to regulatory assets		—			—			50
Reclassification of asset removal costs regulatory liability to accumulated depreciation		—			—			19

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

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF EQUITY

	Common Stock				Premium on Stock		Retained Earnings
(millions of dollars, except shares)	Shares		Par Value							Total
Balance as of December 31, 2011		100	$	—	$	705	$	797		$	1,502
Net Income		—		—		—		126			126
Capital contribution from Parent		—		—		50		—			50
Dividends on common stock		—		—		—		(35	)		(35	)
Balance as of December 31, 2012		100		—		755		888			1,643
Net Income		—		—		—		150			150
Capital contribution from Parent		—		—		175		—			175
Dividends on common stock		—		—		—		(46	)		(46	)
Balance as of December 31, 2013		100		—		930		992			1,922
Net Income		—		—		—		171			171
Capital contribution from Parent		—		—		80		—			80
Dividends on common stock		—		—		—		(86	)		(86	)
Balance as of December 31, 2014		100	$	—	$	1,010	$	1,077		$	2,087

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

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NOTES TO FINANCIAL STATEMENTS

POTOMAC ELECTRIC POWER COMPANY

(1) ORGANIZATION

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

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014 and January 26, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for a purchase price of $18 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each

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party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (6), “Regulatory Matters – Merger Approval Proceedings.”

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. On December 22, 2014, the applicable waiting period under the HSR Act expired, and the HSR Act no longer precludes completion of the Merger. Although the Department of Justice (DOJ) allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised PHI that it has concluded its investigation. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015. On February 13, 2015, Pepco Holdings, Delmarva Power & Light Company (DPL), Exelon, certain of Exelon’s affiliates, the Staff of the DPSC and certain other parties, filed a settlement agreement with the DPSC with respect to the Merger. This settlement agreement is subject to approval by the DPSC.

The Merger Agreement may be terminated by each of PHI and Exelon under certain circumstances, including if the Merger is not consummated by July 29, 2015 (subject to extension by PHI or Exelon to October 29, 2015, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Merger Agreement also provides for certain termination rights for both PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain regulatory approvals with the respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), Exelon will pay PHI a reverse termination fee equal to the purchase price paid up to the date of termination by Exelon to purchase the Preferred Stock, through PHI’s redemption of the Preferred Stock for nominal consideration. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

(2) SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

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Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, 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 loss contingency liabilities for general litigation and auto and other liability claims and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. Pepco records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

Pepco recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for services rendered, but not yet billed. Pepco’s unbilled revenue was $77 million and $80 million as of December 31, 2014 and 2013, respectively, and these amounts are included in Accounts receivable. Pepco calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity 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 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 actual results differ from projected results, the impact could be material.

Taxes related to the consumption of electricity by its customers, such as fuel, energy, or other similar taxes, are components of Pepco’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by Pepco are recorded in Other taxes.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $304 million, $318 million and $324 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Long-Lived Assets Impairment Evaluation

Pepco evaluates certain long-lived assets to be held and used (for example, 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 its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.

Income Taxes

Pepco, as a direct subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco based upon the taxable income or loss amounts, determined on a separate return basis.

The financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on Pepco’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.

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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. The portion of Pepco’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the balance sheets. See Note (6), “Regulatory Matters,” for additional information.

Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

Pepco recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.

Investment tax credits are being 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. Additionally, deposits in PHI’s money pool, which Pepco and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Restricted Cash Equivalents

The Restricted cash equivalents included in Current 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 conforms to the classification of the related liabilities.

Accounts Receivable and Allowance for Uncollectible Accounts

Pepco’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. 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).

Pepco maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the statements of income. Pepco 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. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although Pepco believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, Pepco 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

Included in Inventories are transmission and distribution materials and supplies. Pepco 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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Regulatory Assets and Regulatory Liabilities

Pepco is regulated by the MPSC and the DCPSC. The transmission of electricity by Pepco is regulated by FERC.

Based on the regulatory framework in which it has operated, Pepco has historically applied, and in connection with its transmission and distribution business continues to apply, the Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980). The guidance 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 and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. 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, 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. Effective November 2009, the DCPSC approved a BSA for retail customers. For customers to whom the BSA applies, Pepco recognizes 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 recognizes 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 is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer (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.

Investment in Trust

Represents assets held in a trust for the benefit of participants in the Pepco Owned Life Insurance plan.

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 that 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 additional information regarding the treatment of asset removal obligations, see the “Asset Removal Costs” section included in this Note.

The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2014, 2013 and 2012 for Pepco’s property were approximately 2.3%, 2.2% and 2.5%, respectively.

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Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities may 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 statements of income.

Pepco recorded AFUDC for borrowed funds of $5 million, $5 million and $4 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Pepco recorded amounts for the equity component of AFUDC of $10 million, $9 million and $8 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Leasing Activities

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

Operating Leases

An operating lease in which Pepco 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, Pepco’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 Pepco 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.

Amortization of Debt Issuance and Reacquisition Costs

Pepco defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as Regulatory assets and are amortized generally over the life of the new issue.

Asset Removal Costs

In accordance with FASB guidance, asset removal costs are recorded as regulatory liabilities. At December 31, 2014 and 2013, $84 million and $102 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets.

Pension and Postretirement Benefit Plans

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

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The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).

Dividend Restrictions

All of Pepco’s shares of outstanding common stock are held by PHI, its parent company. In addition to its future financial performance, the ability of Pepco to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by Pepco and any other restrictions imposed in connection with the incurrence of liabilities. Pepco has no shares of preferred stock outstanding. Pepco had approximately $1,077 million and $992 million of retained earnings available for payment of common stock dividends at December 31, 2014 and 2013, respectively. These amounts represent the total retained earnings balances at those dates.

Reclassifications

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

(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Liabilities (ASC 405)

In February 2013, FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, Pepco is required to measure such obligations as the sum of the amount it agreed to pay on the basis of its arrangement among co-obligors and any additional amount it expects to pay on behalf of its co-obligors. Adoption of this guidance during the first quarter of 2014 did not have a material impact on Pepco’s financial statements.

Income Taxes (ASC 740)

In July 2013, the FASB issued new guidance requiring netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of the uncertain tax position. The prospective adoption of this guidance at March 31, 2014 resulted in Pepco netting liabilities related to uncertain tax positions with deferred tax assets for net operating loss and other carryforwards (included in Deferred income tax liabilities, net) and income taxes receivable (including income tax deposits) related to effectively settled uncertain tax positions.

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements are effective for Pepco beginning January 1, 2017, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2017. Early adoption is not permitted. Pepco is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select.

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

(5) SEGMENT INFORMATION

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

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(6)REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco’s regulatory asset and liability balances at December 31, 2014 and 2013 are as follows:

	2014		2013
	(millions of dollars)
Regulatory Assets
Demand-side management costs	$	197	$	98
Smart Grid costs		175		168
Recoverable income taxes		148		107
Recoverable workers’ compensation and long-term disability costs		30		26
Incremental storm restoration costs		29		37
Deferred debt extinguishment costs		22		25
MAPP abandonment costs		19		37
Deferred energy supply costs		3		6
Other		74		59
Total Regulatory Assets	$	697	$	563
Regulatory Liabilities
Asset removal costs	$	84	$	102
Other		20		11
Total Regulatory Liabilities	$	104	$	113

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

Demand-Side Management Costs: Represents costs associated with customer energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. Pepco earns a return on these regulatory assets.

Smart Grid Costs:Represents advanced metering infrastructure (AMI) costs associated with the installation of smart meters and the early retirement of legacy meters throughout Pepco’s service territory that are recoverable from customers. Pepco generally is deferring carrying charges on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from Pepco’s customers for tax benefits applicable to utility operations that were previously recognized in income tax expense before the company was ordered to record 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.

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. Pepco does not earn a return on these regulatory assets.

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, that are recoverable from customers in the Maryland jurisdiction. Pepco’s costs related to Hurricane Sandy, the June 2012 derecho, Hurricane Irene and the 2011 severe winter storm are being amortized and recovered from customers, each over a five-year period. Pepco does not earn a return on these regulatory assets.

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Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment that are amortized to interest expense and recovered from customers. Pepco generally earns a return on these regulatory assets.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated on August 24, 2012. For additional information, see “MAPP Settlement Agreement” discussion below. These regulatory assets are being amortized and recovered in transmission rates through May 2016. Pepco generally does not earn a return on these regulatory assets.

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 and are being or are expected to be recovered from customers. Pepco does not earn a return on these regulatory assets.

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

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

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of the pending filings indicated below.

Bill Stabilization Adjustment

Pepco proposed in each of its respective jurisdictions the adoption of a BSA mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. The BSA proposal has been approved and implemented for Pepco electric service in Maryland and in the District of Columbia.

Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission.

District of Columbia

On March 8, 2013, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by approximately $52.1 million (adjusted by Pepco to approximately $44.8 million on December 3, 2013), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. On March 26, 2014, the DCPSC issued an order approving an increase in base rates of approximately $23.4 million, based on an ROE of 9.40%. The new rates became effective on April 16, 2014.

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Maryland

Electric Distribution Base Rates

2011 Base Rate Proceeding

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 adjusted by Pepco to approximately $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorized Pepco to recover the actual cost of AMI meters installed during the 2011 test year, stating that cost recovery for AMI deployment will be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new rates became effective on July 20, 2012. The Maryland Office of People’s Counsel (OPC) has sought rehearing on the portion of the order allowing Pepco to recover the costs of AMI meters installed during the test year; that motion remains pending.

2012 Base Rate Proceeding

On November 30, 2012, 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 $60.8 million, based on a requested ROE of 10.25%.

On July 12, 2013, the MPSC issued an order related to Pepco’s November 30, 2012 application approving an annual rate increase of approximately $27.9 million, based on an ROE of 9.36%. The order excludes the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; as a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates. However, the MPSC’s July 2012 order in Pepco’s previous electric distribution base rate case, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect, and the Maryland OPC’s motion for rehearing in that case remains pending.

The July 12, 2013 order also approved a Grid Resiliency Charge, which went into effect on January 1, 2014, for recovery of costs totaling approximately $24.0 million associated with Pepco’s proposed plan to accelerate investments related to certain priority feeders, provided that, before implementing the surcharge, Pepco (i) provides additional information to the MPSC related to performance objectives, milestones and costs, and (ii) makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for each following year. The MPSC rejected certain other cost recovery mechanisms, including Pepco’s proposed reliability performance-based mechanism. The new rates were effective on July 12, 2013.

On July 26, 2013, Pepco filed a notice of appeal of the July 12, 2013 order in the Circuit Court for Baltimore City. Other parties also filed notices of appeal, which were consolidated with Pepco’s appeal. In its appeal, Pepco asserted that the MPSC erred in failing to grant Pepco an adequate ROE, denying a number of other cost recovery mechanisms and limiting Pepco’s test year data to no more than four months of forecasted data in future rate cases. The other parties primarily asserted that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco, in approving the Grid Resiliency Charge, and in refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. On November 14, 2014, the Circuit Court issued an order reversing the

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MPSC’s decision on Pepco’s ROE and directing the MPSC to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE. On all other issues appealed, the Circuit Court affirmed the MPSC’s July 12, 2013 order. Pepco will not appeal this decision, but other parties have filed notices of appeal of the Circuit Court’s decision to the Court of Special Appeals.

Phase II Proceeding to 2012 Base Rate Proceeding

On August 26, 2014, the MPSC issued an order establishing a Phase II proceeding pertaining to the base rate case filed in November 2012 to address an issue regarding Pepco’s net operating loss carryforward (NOLC). The issue in this Phase II proceeding is the same as for the Phase II proceeding described below. Pepco filed a motion to dismiss this Phase II proceeding, asserting that the MPSC no longer has jurisdiction over the 2012 base rate case due to appeals having been filed by numerous parties. On September 11, 2014, the MPSC issued an order staying this Phase II proceeding until further notice.

2013 Base Rate Proceeding

On December 4, 2013, 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 $43.3 million (adjusted by Pepco to approximately $37.4 million on April 15, 2014), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. On July 2, 2014, the MPSC issued an order approving an annual rate increase of approximately $8.75 million, based on an ROE of 9.62%. The new rates became effective on July 4, 2014. On July 31, 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order dated November 13, 2014. On December 11, 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. This petition remains pending.

Phase II Proceeding to 2013 Base Rate Proceeding

On August 26, 2014, the MPSC issued an order establishing a Phase II proceeding pertaining to the base rate case filed in December 2013 to address an issue regarding Pepco’s NOLC. Specifically, the MPSC considered the tax implications of Pepco’s NOLC, which had impacted certain of Pepco’s rate adjustments in the 2013 base rate proceeding. On November 13, 2014, the MPSC issued its order in this Phase II proceeding upholding Pepco’s treatment of the NOLC.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against Pepco, and its affiliates Delmarva Power & Light Company (DPL) and ACE, as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. Pepco believes the allegations in this complaint are without merit and is vigorously contesting it. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set February 27, 2013 as the refund effective date, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, on November 24, 2014, the settlement judge issued an order terminating the settlement discussions. The matter is now before a hearing judge and a procedural schedule will be established for both the February 2013 complaint and a second complaint (discussed below) that has been consolidated with the February 2013 complaint.

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On June 19, 2014, FERC issued an order in a proceeding in which Pepco was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, Pepco applied an estimated ROE based on the two-step methodology announced by FERC for the period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves in the second quarter of 2014 related to this matter. To the extent that the final ROE determined by FERC is lower than the ROE used to record the estimated reserves, each ten basis point reduction in the ROE would result in a reduction of Pepco’s operating income of $0.6 million.

A second complaint against Pepco, DPL and ACE challenging the base ROE was filed at FERC on December 8, 2014 by the same parties. Employing the new ROE methodology referenced above, the complainants contend that the resulting base ROE should be 8.8%, and request consolidation of this complaint with the February 2013 complaint. Consistent with the prior challenge, Pepco applied an estimated ROE based on the two-step methodology described above, and recorded estimated reserves in the fourth quarter of 2014 using a refund effective date of December 8, 2014.

Under the Merger Agreement, ACE is permitted to pursue the conclusion of these FERC matters and intends to continue to do so.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative Standard Offer Service (SOS) loads. Under the terms of the order, 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, and each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.

In response to a complaint filed by a group of generating companies in the PJM Interconnection, LLC (PJM) region, on September 30, 2013, the U.S. District Court for the District of Maryland issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, on October 1, 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

On October 24, 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. The Federal district court order and its associated ruling could impact the state circuit court appeal, to which the Contract EDCs are parties, although such impact, if any, cannot be determined at this time. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal district court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the lower Federal court ruling. On November 26, 2014, both the winning bidder and the MPSC petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision.

The Maryland Court of Special Appeals has stayed the appeal of the Baltimore City Circuit Court decision until July 23, 2015.

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On June 2, 2014, the winning bidder filed the contracts at FERC requesting that they be accepted pursuant to Section 205 of the Federal Power Act (FPA). On August 5, 2014, FERC issued an order rejecting the filings made by the winning bidder, finding that the contracts cannot be accepted as valid contracts, given the decisions reached in the Federal court proceedings discussed above.

Assuming the contracts, as currently written, were to become effective by the expected commercial operation date of June 1, 2015, Pepco continues to believe that it may be required to record its proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because Pepco would recover any payments under the contracts from SOS customers. Pepco has concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

Under the Merger Agreement, Pepco is permitted to pursue the conclusion of this matter and intends to continue to do so.

District of Columbia Power Line Undergrounding Initiative

On May 3, 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco.

The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a surcharge on the electric bills of Pepco District of Columbia customers that Pepco will remit to the District of Columbia; and (iii) the remaining amount is to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

On June 17, 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. On August 1, 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District to recover the costs associated with the bond issuance.

On November 12, 2014, the DCPSC issued an order approving the Triennial Plan and Pepco’s volumetric surcharge, and on November 24, 2014, the DCPSC issued the financing order. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act. In December 2014, a party to the proceeding sought reconsideration from the DCPSC of both decisions. Final decisions denying both requests for reconsideration were issued on January 22, 2015 and February 2, 2015, respectively.

On December 4, 2014, a party filed a petition for review with the District of Columbia Court of Appeals disputing the DCPSC’s denial of its motion to intervene. The procedural schedule for the petition has not yet been set.

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Under the Merger Agreement, Pepco is permitted to pursue the DC PLUG initiative and intends to continue to do so.

MAPP Settlement Agreement

In February 2014, FERC issued an order approving the settlement agreement submitted by Pepco connection with Pepco’s proceeding seeking recovery of approximately $88 million in abandonment costs related to the MAPP project. Pepco had been directed by PJM to construct the MAPP project, a 152-mile high-voltage interstate transmission line, and in August 2012 was directed by PJM to cancel it. The abandonment costs sought for recovery were subsequently reduced to $45 million as a result of write-offs of certain disallowed costs in 2013 and transfers of materials to inventories for use on other projects. Under the terms of the FERC-approved settlement agreement, Pepco will receive approximately $43.9 million of transmission revenues over a three-year period, which began on June 1, 2013, and will retain title to all real property and property rights acquired in connection with the MAPP project, which had an estimated fair value of $2 million. The FERC-approved settlement agreement resolves all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project, and the terms of the settlement agreement are not subject to modification through any other FERC proceeding. As of December 31, 2014, Pepco had a regulatory asset related to the MAPP abandonment costs of approximately $19 million, net of amortization, and land of $2 million. Pepco does not expect to recognize any further pre-tax income related to the MAPP abandonment costs.

Merger Approval Proceedings

District of Columbia

On June 18, 2014, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application with the DCPSC seeking approval of the Merger. To approve the Merger, the DCPSC must find that the Merger is in the public interest. In an order issued August 22, 2014, the DCPSC stated that to make the determination of whether the transaction is in the public interest, it will analyze the transaction in the context of seven factors to determine whether the transaction balances the interests of shareholders and investors with ratepayers and the community, whether the benefits to shareholders do or do not come at the expense of the ratepayers, and whether the transaction produces a direct and tangible benefit to ratepayers. The seven factors identified by the DCPSC are the effects of the transaction on: (i) ratepayers, shareholders, the financial health of the utility standing alone and as merged, and the local economy; (ii) utility management and administrative operations; (iii) the public safety and the safety and reliability of services; (iv) risks associated with all of the affiliated non-jurisdictional business operations, including nuclear operations, of the applicants; (v) the DCPSC’s ability to regulate the utility effectively following the Merger; (vi) competition in the local retail and wholesale markets that impacts the District and District ratepayers; and (vii) conservation of natural resources and preservation of environmental quality. District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger. The DCPSC has scheduled evidentiary hearings for March 30, 2015 to April 8, 2015.

Maryland

On August 19, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. In making this determination, the MPSC is required to consider the following 12 criteria: (i) the potential impact of the merger on rates and charges paid by customers and on the services and conditions of operation of the utility; (ii) the potential impact of the merger on continuing investment needs for the maintenance of utility services, plant and related infrastructure; (iii) the proposed capital structure that will result from the merger, including allocation of earnings from the utility; (iv) the potential effects on employment by the utility; (v) the projected allocation between the utility’s shareholders and ratepayers of any savings that are expected; (vi) issues of

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reliability, quality of service and quality of customer service; (vii) the potential impact of the merger on community investment; (viii) affiliate and cross-subsidization issues; (ix) the use or pledge of utility assets for the benefit of an affiliate; (x) jurisdictional and choice-of-law issues; (xi) whether it is necessary to revise the MPSC’s ring-fencing and affiliate code of conduct regulations in light of the merger; and (xii) any other issues the MPSC considers relevant to the assessment of the merger. The MPSC is required to issue an order within 180 days of the August 19, 2014 filing date. However, the MPSC can grant a 45-day extension for good cause. If no order is issued by the statutory deadline, then the Merger would be deemed to be approved. On September 22, 2014, the MPSC issued an order setting the procedural schedule for this matter. Pursuant to that schedule, evidentiary hearings were held beginning on January 26, 2015, and all briefs are scheduled to be filed in March 2015. The deadline for the MPSC’s decision is April 8, 2015.

Virginia

On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

(7)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, 2014
Distribution	$	5,668	$	2,082	$	3,586
Transmission		1,306		463		843
Construction work in progress		312		—		312
Non-operating and other property		478		271		207
Total	$	7,764	$	2,816	$	4,948
At December 31, 2013
Distribution	$	5,287	$	2,027	$	3,260
Transmission		1,223		444		779
Construction work in progress		312		—		312
Non-operating and other property		488		301		187
Total	$	7,310	$	2,772	$	4,538

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

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Capital Leases

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. 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 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, 2014 and 2013 are comprised of the following:

	Original Cost		Accumulated Amortization		Net Book Value
At December 31, 2014	(millions of dollars)
Transmission	$	76	$	46	$	30
Distribution		76		46		30
Total	$	152	$	92	$	60
At December 31, 2013
Transmission	$	76	$	41	$	35
Distribution		76		42		34
Other		3		3		—
Total	$	155	$	86	$	69

The approximate annual commitments under all capital leases are $15 million in each of the years 2015 through 2018, and $16 million thereafter.

(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in PHI’s single-employer plans, the PHI Retirement Plan and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the PHI OPEB Plan), as participation in multiemployer plans. For 2014, 2013 and 2012, Pepco was responsible for $22 million, $34 million and $39 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. Pepco made a discretionary, tax-deductible contribution of zero, zero and $85 million to the PHI Retirement Plan for the years ended December 31, 2014, 2013 and 2012, respectively. In addition, Pepco made contributions of $1 million, $6 million and $5 million, respectively, to the PHI OPEB Plan for the years ended December 31, 2014, 2013 and 2012. At December 31, 2014 and 2013, Pepco’s Prepaid pension expense of $316 million and $332 million, respectively, and Other postretirement benefit obligations of $57 million and $61 million, respectively, effectively represent assets and benefit obligations resulting from Pepco’s participation in the Pepco Holdings benefit plans.

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Other Postretirement Benefit Plan Amendments

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree medical plan and the retiree life insurance benefits, and became effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its projected benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $7 million reduction in Pepco’s net periodic benefit cost for other postretirement benefits in 2014, when compared to 2013. Approximately 40% of net periodic other postretirement benefit costs were capitalized in 2014.

(9) DEBT

Long-Term Debt

The components of long-term debt are shown in the table below:

Type of Debt	Interest Rate			Maturity		2014			2013
						(millions of dollars)
First Mortgage Bonds
		4.65	%(a)(b)		2014	$	—		$	175
		3.05	%		2022		200			200
		6.20	%(c)(d)		2022		110			110
		3.60	%		2024		400			—
		5.75	%(a)(b)		2034		100			100
		5.40	%(a)(b)		2035		175			175
		6.50	%(a)(c)		2037		500			500
		7.90	%		2038		250			250
		4.15	%		2043		250			250
		4.95	%		2043		150			150
Total long-term debt							2,135			1,910
Net unamortized discount							(11	)		(11	)
Current portion of long-term debt							—			(175	)
Total net long-term debt						$	2,124		$	1,724

(a) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of senior notes issued by Pepco.

(b) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).

(c) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that Pepco may not permit such release of collateral unless Pepco substitutes comparable obligations for such collateral.

(d) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco.

The outstanding first mortgage bonds are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of Pepco’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.

Maturities of Pepco’s long-term debt outstanding at December 31, 2014, are zero in 2015 through 2019 and $2,135 million thereafter.

Pepco’s long-term debt is subject to certain covenants. As of December 31, 2014, Pepco is in compliance with all such covenants.

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The table above does not separately identify $885 million in aggregate principal amount of senior notes issued by Pepco and $110 million in aggregate principal amount of tax-exempt bonds issued for the benefit of Pepco. These senior notes are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of Pepco. In addition, these tax-exempt bonds are secured by a like amount of Collateral First Mortgage Bonds issued by Pepco. The principal terms of each such series of senior notes, or Pepco’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such senior notes, or the satisfaction of Pepco’s obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding senior notes and/or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.

Bond Issuance

During 2014, Pepco issued $400 million of 3.60% first mortgage bonds due March 15, 2024. Pepco used a portion of the net proceeds of the offering to repay in full at maturity $175 million in aggregate principal amount of its 4.65% senior notes due April 15, 2014, plus accrued and unpaid interest.

Bond Retirement

During 2014, Pepco retired, at maturity, $175 million of its 4.65% senior notes. The senior notes were secured by a like principal amount of its 4.65% first mortgage bonds due April 15, 2014, which under the mortgage and deed of trust were deemed to be satisfied when the senior notes were repaid.

Short-Term Debt

Pepco has 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.

Pepco’s short-term debt at December 31, 2014 and 2013 consisted of the following:

	2014		2013
	(millions of dollars)
Commercial paper	$	104	$	151

Commercial Paper

Pepco maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2014, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

Pepco had $104 million and $151 million of commercial paper outstanding at December 31, 2014 and 2013, respectively. The weighted average interest rates for commercial paper issued by Pepco during 2014 and 2013 were 0.28% and 0.34%, respectively. The weighted average maturity of all commercial paper issued by Pepco during each of 2014 and 2013 was six days and five days, respectively.

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. The termination date of this credit facility is currently August 1, 2018.

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The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility as of December 31, 2014.

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.

As of December 31, 2014 and 2013, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $413 million and $332 million, respectively. Pepco’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by DPL and ACE and the portion of the total capacity being used by PHI.

Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.

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Other Financing Activities

Sale of Receivables

During 2014, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a Task Order entered into under a General Services Administration area-wide agreement. The purchase price received by Pepco was $12 million. The energy savings project, which is being performed by Pepco Energy Services, was completed in 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project, the buyer will be entitled to receive the contract payments under the Task Order payable by the customer over approximately 9 years. At December 31, 2014, Pepco included the $12 million received in the Current portion of long-term debt and project funding.

(10) INCOME TAXES

Pepco, as a direct subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission 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 income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.

Provision for Income Taxes

	For the Year Ended December 31,
	2014			2013			2012
	(millions of dollars)
Current Tax Benefit
Federal	$	(79	)	$	(39	)	$	(84	)
State and local		(3	)		(1	)		(27	)
Total Current Tax Benefit		(82	)		(40	)		(111	)
Deferred Tax Expense (Benefit)
Federal		150			96			127
State and local		24			24			33
Investment tax credit amortization		—			(1	)		(1	)
Total Deferred Tax Expense		174			119			159
Total Income Tax Expense	$	92		$	79		$	48

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Reconciliation of Income Tax Expense

	For the Year Ended December 31,
	2014					2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	92		35.0	%	$	80		35.0	%	$	61		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		15		5.7	%		13		5.7	%		10		5.7	%
Asset removal costs		(12	)	(4.6	)%		(14	)	(6.1	)%		(11	)	(6.3	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(1	)	(0.4	)%		(3	)	(1.3	)%		(11	)	(6.3	)%
Other, net		(2	)	(0.7	)%		3		1.2	%		(1	)	(0.5	)%
Income Tax Expense	$	92		35.0	%	$	79		34.5	%	$	48		27.6	%

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 Pepco is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in Pepco recording a $5 million (after-tax) interest benefit in the first quarter of 2013, which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions.

During 2012, Pepco recorded income tax benefits of $10 million (after-tax) related to uncertain and effectively settled tax positions primarily due to the effective settlement with the Internal Revenue Service (IRS) 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. The effective income tax rate also reflects an increase in deductible asset removal costs for Pepco in 2012 related to a higher level of asset retirements.

Components of Deferred Income Tax Liabilities (Assets)

	At December 31,
	2014			2013
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	1,423		$	1,240
Pension and other postretirement benefits		103			105
Deferred taxes on amounts to be collected through future rates		59			43
Federal and state net operating losses		(186	)		(169	)
Other		180			145
Total Deferred Tax Liabilities, net		1,579			1,364
Deferred tax assets included in Current Assets		14			48
Deferred tax liabilities included in Other Current Liabilities		(9	)		—
Total Deferred Tax Liabilities, net non-current	$	1,584		$	1,412

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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 Pepco’s 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. No valuation allowance for deferred tax assets was required or recorded at December 31, 2014 and 2013. Federal and state net operating losses generally expire over 20 years from 2029 to 2034.

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 property continue to be amortized to income over the useful lives of the related property.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2014			2013			2012
	(millions of dollars)
Balance as of January 1	$	101		$	91		$	173
Tax positions related to current year:
Additions		1			1			—
Reductions		(2	)		—			—
Tax positions related to prior years:
Additions		1			12			60
Reductions		(4	)		(3	)		(142	)(a)
Settlements		—			—			—
Balance as of December 31	$	97		$	101		$	91

(a) These reductions of unrecognized tax benefits in 2012 primarily relate to a resolution reached with the IRS for determining deductible mixed service costs for additions to property, plant and equipment.

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. At December 31, 2014, Pepco had less than $1 million of unrecognized tax benefits that, if recognized, would lower the effective tax rate.

Interest and Penalties

Pepco recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2014, 2013 and 2012, Pepco recognized $2 million of pre-tax interest income ($1 million after-tax), $5 million of pre-tax interest income ($3 million after-tax), and $18 million of pre-tax interest income ($11 million after-tax), respectively, as a component of income tax expense. As of December 31, 2014, 2013 and 2012, Pepco had accrued interest receivable of $9 million, $9 million and $5 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 Pepco’s uncertain tax positions will significantly increase or decrease within the next 12 months. PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues of Pepco for open tax years 2001 through 2011. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2015, which could significantly impact the balances of unrecognized tax benefits and the related interest accruals of Pepco. At this time, it is estimated that there will be a $65 million to $85 million decrease in unrecognized tax benefits within the next 12 months.

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Tax Years Open to Examination

Pepco, as a direct subsidiary of PHI, is included on PHI’s consolidated Federal income tax return. Pepco’s federal income tax liabilities for all years through 2002 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where Pepco files state income tax returns (District of Columbia and Maryland) are the same as for the Federal returns. As a result of the final determination of these years, Pepco filed amended state returns requesting $20 million in refunds which are subject to review by the various states. To date, Pepco has received $4 million in refunds and legislation has been enacted in the District of Columbia (subject to a 30-day Congressional review period before becoming law) which will allow for the recovery of the remaining $16 million in refunds.

Final IRS Regulations on Repair of Tangible Property

In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on Pepco’s financial statements.

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2014		2013		2012
	(millions of dollars)
Gross Receipts/Delivery	$	107	$	108	$	106
Property		51		45		46
County Fuel and Energy		143		153		160
Environmental, Use and Other		62		62		60
Total	$	363	$	368	$	372

(11)FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

Pepco applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Pepco utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, Pepco utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

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The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2014
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
Restricted cash equivalents
Treasury fund	$	5	$	5	$	—	$	—
Executive deferred compensation plan assets
Money market funds and short-term investments		34		13		21		—
Life insurance contracts		41		—		23		18
Total	$	80	$	18	$	44	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	7	$	—	$	7	$	—
Total	$	7	$	—	$	7	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

	Fair Value Measurements at December 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Restricted cash equivalents
Treasury fund	$	3	$	3	$	—	$	—
Executive deferred compensation plan assets
Money market funds and short-term investments		33		13		20		—
Life insurance contracts		41		—		23		18
Total	$	77	$	16	$	43	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	7	$	—	$	7	$	—
Total	$	7	$	—	$	7	$	—

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

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Pepco classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

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

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

Executive deferred compensation plan assets and liabilities categorized as level 2 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, 2014. 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 (which are included in life insurance contracts in the tables above) is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

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

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Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2014 and 2013 are shown below.

	Year Ended December 31, 2014			Year Ended December 31, 2013
	Life Insurance Contracts			Life Insurance Contracts
	(millions of dollars)
Balance as of January 1	$	18		$	18
Total gains (losses) (realized and unrealized):
Included in income		3			4
Included in accumulated other comprehensive loss		—			—
Purchases		—			—
Issuances		(3	)		(3	)
Settlements		—			(1	)
Transfers in (out) of level 3		—			—
Balance as of December 31	$	18		$	18

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

	Year Ended December 31,
	2014		2013
	(millions of dollars)
Total gains included in income for the period	$	3	$	4
Change in unrealized gains relating to assets still held at reporting date	$	3	$	4

Other Financial Instruments

The estimated fair values of Pepco’s Long-term debt instruments that are measured at amortized cost in Pepco’s financial statements and the associated level of the estimates within the fair value hierarchy as of December 31, 2014 and 2013 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and Pepco reviews the methodologies and results.

The Project funding represents debt instruments issued by Pepco related to its construction contracts. Project funding is categorized as level 3 because PHI concluded that the amortized cost carrying amounts for these instruments approximate fair value, which does not represent a quoted price in an active market.

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	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,624	$	—	$	2,624	$	—
Project funding		12		—		—		12
Total	$	2,636	$	—	$	2,624	$	12

(a) The carrying amount for Long-term debt was $2,124 million as of December 31, 2014.

	Fair Value Measurements at December 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,127	$	—	$	2,127	$	—

(a) The carrying amount for Long-term debt was $1,899 million as of December 31, 2013.

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

(12) COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, Pepco is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. Pepco is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, Pepco’s contracts with its vendors generally require the vendors to name Pepco as an additional insured for the amount at least equal to Pepco’s self-insured retention. Further, Pepco’s contracts with its vendors require the vendors to indemnify Pepco for various acts and activities that may give rise to claims against Pepco. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on Pepco’s financial condition, results of operations or cash flows. At December 31, 2014, Pepco had recorded estimated loss contingency liabilities for general litigation totaling approximately $25 million (including amounts related to the matter specifically described below), and the portion of these estimated loss contingency liabilities in excess of the self-insured retention amount was substantially offset by estimated insurance receivables.

Pepco Substation Injury Claim

In May 2013, a worker employed by a subcontractor to erect a scaffold at a Pepco substation came into contact with an energized transformer and suffered serious injuries. In August 2013, the individual filed suit against Pepco in the Circuit Court for Montgomery County, Maryland, seeking damages for past and future medical expenses, past and future lost wages, pain and suffering and the cost of a life care plan. On

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October 22, 2014, an award of approximately $21.7 million was entered in favor of the plaintiff in this matter. Pepco has recorded this liability as of December 31, 2014, which is included in the liability for general litigation referred to above. Pepco’s insurer and the contractor’s insurer have acknowledged insurance coverage for the incident, including coverage of Pepco’s self-insured retention amount. Pepco has concluded as of December 31, 2014, that realization of its insurance claims associated with this matter is probable and, accordingly, has recorded an estimated insurance receivable of the same amount as the related liability.

Environmental Matters

Pepco is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of Pepco, environmental clean-up costs incurred by Pepco generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of Pepco described below at December 31, 2014 are summarized as follows:

	Transmission and Distribution		Legacy Generation - Regulated		Total
	(millions of dollars)
Balance as of January 1	$	18	$	3	$	21
Accruals		—		—		—
Payments		2		—		2
Balance as of December 31		16		3		19
Less amounts in Other Current Liabilities		2		—		2
Amounts in Other Deferred Credits	$	14	$	3	$	17

Peck Iron and Metal Site

The U.S. Environmental Protection Agency (EPA) informed Pepco in a May 2009 letter that Pepco may be a potentially responsible party (PRP) under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and 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 in November 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 this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

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Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including 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 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 Federal 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 Federal district court’s order addresses only the liability of the test case defendant. Plaintiffs have appealed the district court’s order to the U.S. Court of Appeals for the Fourth Circuit. Pepco has concluded that a loss is reasonably possible with respect to this matter, but is unable to estimate an amount or range of reasonably possible losses to which it may be exposed. Pepco does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

Benning Road Site

Contamination of Lower Anacosita River

In September 2010, PHI received a letter from EPA identifying the Benning Road location, consisting of a generation facility formerly operated by Pepco’s affiliate, Pepco Energy Services, Inc. (Pepco Energy Services), and a transmission and distribution service center facility operated by Pepco, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The generation facility was deactivated in June 2012 and the plant structures are currently in the process of being demolished, but the service center remains in operation. The principal contaminants of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of the Environment (DDOE), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 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 Pepco and Pepco Energy Services 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 final phase of remedial investigation field work, consisting of the installation of monitoring wells and groundwater sampling and analysis, began in May 2014. In addition, as part of the remaining remedial investigation field work and in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the cooling towers previously dismantled and removed from the site of the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and Pepco has submitted a plan to DDOE for the removal of contaminated soil in conjunction with the demolition and removal of the concrete basins. The remedial investigation field sampling was completed in December 2014. Pepco and Pepco Energy Services will prepare RI/FS reports for review and approval by DDOE after solicitation and consideration of public comment. The next status report to the court is due on May 25, 2015.

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

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NPDES Permit Limit Exceedances

Pepco holds a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA with a June 19, 2009 effective date, which authorizes discharges from the Benning Road facility, including the now deactivated Pepco Energy Services generating facility located at that site. The 2009 permit imposed compliance monitoring and storm water best management practices to satisfy the District of Columbia’s Total Maximum Daily Load (TMDL) standards for polychlorinated biphenyls, oil and grease, metals and other substances. As part of the implementation of the TMDL requirements, the permit also imposed numerical limits on certain substances in storm water discharges to the Anacostia River. Quarterly monitoring results since the issuance of the permit have shown consistent exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead. As required by the permit, Pepco initiated a study to identify the potential sources of these substances at the site and to determine appropriate best management practices for minimizing the presence of the substances in storm water discharges from the facility. The initial study report was completed in May 2012. Pepco has completed the implementation of the first two phases of the best management practices recommended in the study report (consisting principally of installing metal absorbing filters to capture contaminants from storm water flows, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures have been effective in reducing metal concentrations in stormwater discharges; however, additional measures will be required to be implemented by Pepco to reduce the concentrations to levels required by the permit.

The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road facility has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. Pepco has prepared a plan to implement the third phase of the best management practices recommended in the study report with the objective of achieving full compliance with the permit limits by the end of 2015. The plan was submitted to EPA on December 30, 2014, and Pepco has begun implementing those best practices in accordance with the plan. Pepco anticipates that EPA may request that Pepco enter into an administrative compliance agreement with respect to the implementation of these additional control measures, and may seek administrative penalties for past noncompliance with the permit limits for metals in storm water. Whether such penalties will be imposed and, if so, the amount of any such penalties, is not known or estimable at this time. At present, Pepco expects that compliance with the permit limits can be achieved through a combination of enhanced storm drain inlet controls (filters and metal absorbing booms), enhanced site housekeeping, and enhanced inspection and maintenance of storm water controls. If these measures are not adequate to achieve compliance with the permit limits, however, it is possible that a capital project to install a storm water treatment system may be required. The need for any such capital expenditures will not be known until Pepco has implemented the third phase of the best management practices.

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.

In March 2014, Pepco and DDOE entered into a consent decree to resolve a threatened DDOE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with

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Living Classrooms Foundation, Inc., a non-profit educational organization, to provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. The design for the trash collection system is currently under review by DDOE, and Pepco expects that this system will be constructed and placed into operation by the end of 2015, which will satisfy Pepco’s obligations under the consent decree. The next status hearing in this matter has been set for September 18, 2015.

The consent decree does not resolve potential claims under federal law for natural resource damages resulting from the oil release. Pepco has engaged in separate discussions with DDOE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. The federal trustees are still evaluating the claim and the terms of a possible settlement. At this time, it is uncertain whether or when the settlement discussions may resume or if the trustees will continue to pursue the natural resource damages claim. Based on discussions to date, Pepco does not believe that the resolution of the federal natural resource damages claim will have a material adverse effect on its financial condition, results of operations or cash flows.

As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an above-ground 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 on a pilot basis to demonstrate its effectiveness in meeting both secondary containment requirements and water quality standards related to the discharge of storm water from the facility. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system. Pepco also is evaluating other technical and regulatory options for managing storm water from the secondary containment system as alternatives to the proposed treatment system discharge currently under discussion with EPA and DDOE.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Metal Bank Site

In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco on behalf of itself and other federal and state trustees to request that Pepco execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. Pepco executed a tolling agreement, which has been extended to March 15, 2015, and will continue settlement discussions with the NOAA, the trustees and other PRPs.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Brandywine Fly Ash Disposal Site

In February 2013, Pepco received a letter from the Maryland Department of the Environment (MDE) requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

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Pepco has determined that a loss associated with this matter is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. Pepco believes that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Contractual Obligations

Power Purchase Contracts

As of December 31, 2014, Pepco had no contractual obligations under non-derivative power purchase contracts.

Lease Commitments

Rental expense for operating leases was $8 million, $7 million and $6 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Total future minimum operating lease payments for Pepco as of December 31, 2014 are $7 million in 2015, $6 million in 2016, $5 million in 2017, $4 million in 2018, $3 million in 2019 and $22 million thereafter.

(13) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including Pepco. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to Pepco for the years ended December 31, 2014, 2013 and 2012 were approximately $220 million, $209 million and $211 million, respectively.

Pepco Energy Services performs utility maintenance services and high voltage underground transmission cabling, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by Pepco Energy Services for the years ended December 31, 2014, 2013 and 2012 were approximately $30 million, $20 million and $16 million, respectively.

As of December 31, 2014 and 2013, Pepco had the following balances on its balance sheets due to related parties:

	2014			2013
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(27	)	$	(25	)
Pepco Energy Services (b)		(2	)		(7	)
Other		(1	)		—
Total	$	(30	)	$	(32	)

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

(b) Pepco bills customers on behalf of Pepco Energy Services where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco. Prior to the wind-down of Pepco Energy Services’ retail electric and natural gas businesses, Pepco billed customers on behalf of Pepco Energy Services where customers had selected Pepco Energy Services as their alternative energy supplier.

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(14)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. Therefore, comparisons by quarter within a year are not meaningful.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	535		$	508		$	587		$	471		$	2,101
Total Operating Expenses		469			414			462			408			1,753
Operating Income		66			94			125			63			348
Other Expenses		(18	)		(20	)		(20	)		(27	)		(85	)
Income Before Income Tax Expense		48			74			105			36			263
Income Tax Expense		16			28			38			10			92
Net Income	$	32		$	46		$	67		$	26		$	171
	2013
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	477		$	469		$	605		$	475		$	2,026
Total Operating Expenses		430			389			476			410			1,705
Operating Income		47			80			129			65			321
Other Expenses		(22	)		(23	)		(23	)		(24	)		(92	)
Income Before Income Tax Expense		25			57			106			41			229
Income Tax Expense		2	(a)		20			40			17	(b)		79
Net Income	$	23		$	37		$	66		$	24		$	150

(a) Includes tax benefits of $5 million (after-tax) allocated to Pepco associated with interest on uncertain and effectively settled tax positions resulting from a change in assessment of tax benefits associated with the cross-border energy leases of a PHI affiliate.

(b) Includes an income tax charge of $4 million (after-tax) to correct a prior period error related to Pepco’s deferred income taxes.

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Management’s Report on Internal Control Over Financial Reporting

The management of Delmarva Power & Light Company (DPL) 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 DPL assessed DPL’s internal control over financial reporting as of December 31, 2014 based on criteria established in theInternal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of DPL concluded that DPL’s internal control over financial reporting was effective as of December 31, 2014.

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Report of Independent Registered Public Accounting Firm

To the Shareholder and Board

of Directors of Delmarva Power & Light Company

In our opinion, the financial statements of Delmarva Power & Light Company (a wholly owned subsidiary of Pepco Holdings, Inc.) listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Delmarva Power & Light Company at December 31, 2014 and December 31, 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule of Delmarva Power & Light Company listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Washington, D.C.

February 26, 2015

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF INCOME

For the Year Ended December 31,	2014			2013			2012
	(millions of dollars)
Operating Revenue
Electric	$	1,099		$	1,053		$	1,050
Natural gas		194			191			183
Total Operating Revenue		1,293			1,244			1,233
Operating Expenses
Purchased energy		546			552			568
Gas purchased		104			109			113
Other operation and maintenance		269			251			260
Depreciation and amortization		125			107			102
Other taxes		42			40			36
Total Operating Expenses		1,086			1,059			1,079
Operating Income		207			185			154
Other Income (Expenses)
Interest expense		(48	)		(50	)		(47	)
Other income		10			10			10
Total Other Expenses		(38	)		(40	)		(37	)
Income Before Income Tax Expense		169			145			117
Income Tax Expense		65			56			44
Net Income	$	104		$	89		$	73

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

ASSETS	December 31, 2014			December 31, 2013
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	4		$	2
Restricted cash equivalents		5			—
Accounts receivable, less allowance for uncollectible accounts of $11 million and $12 million, respectively		193			208
Inventories		55			51
Deferred income tax assets, net		16			59
Income taxes and related accrued interest receivable		34			32
Prepaid expenses and other		12			9
Total Current Assets		319			361
OTHER ASSETS
Goodwill		8			8
Regulatory assets		356			311
Prepaid pension expense		220			228
Income taxes and related accrued interest receivable		4			4
Other		12			12
Total Other Assets		600			563
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		3,946			3,673
Accumulated depreciation		(1,021	)		(1,016	)
Net Property, Plant and Equipment		2,925			2,657
TOTAL ASSETS	$	3,844		$	3,581

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

LIABILITIES AND EQUITY	December 31, 2014		December 31, 2013
	(millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	211	$	252
Current portion of long-term debt		100		100
Accounts payable		39		46
Accrued liabilities		74		71
Accounts payable due to associated companies		17		22
Taxes accrued		3		4
Interest accrued		7		6
Customer deposits		24		25
Other		42		35
Total Current Liabilities		517		561
DEFERRED CREDITS
Regulatory liabilities		225		229
Deferred income tax liabilities, net		893		816
Investment tax credits		4		5
Other postretirement benefit obligations		21		23
Other		35		36
Total Deferred Credits		1,178		1,109
OTHER LONG-TERM LIABILITIES
Long-term debt		971		867
COMMITMENTS AND CONTINGENCIES (NOTE 14)
EQUITY
Common stock, $2.25 par value, 1,000 shares authorized, 1,000 shares outstanding		—		—
Premium on stock and other capital contributions		537		407
Retained earnings		641		637
Total Equity		1,178		1,044
TOTAL LIABILITIES AND EQUITY	$	3,844	$	3,581

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

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

For the Year Ended December 31,	2014			2013			2012
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	104		$	89		$	73
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		125			107			102
Deferred income taxes		111			65			55
Investment tax credit amortization		(1	)		(1	)		(1	)
Changes in:
Accounts receivable		15			(7	)		(15	)
Inventories		(4	)		2			(9	)
Regulatory assets and liabilities, net		(66	)		(42	)		(29	)
Accounts payable and accrued liabilities		(15	)		(1	)		26
Pension contributions		—			(10	)		(85	)
Prepaid pension expense, excluding contributions		8			14			15
Income tax-related prepayments, receivables and payables		(3	)		(1	)		8
Other assets and liabilities		(6	)		(1	)		(9	)
Net Cash From Operating Activities		268			214			131
INVESTING ACTIVITIES
Investment in property, plant and equipment		(352	)		(357	)		(320	)
Net other investing activities		(6	)		2			—
Net Cash Used By Investing Activities		(358	)		(355	)		(320	)
FINANCING ACTIVITIES
Dividends paid to Parent		(100	)		(30	)		—
Capital contributions from Parent		130			—			60
Issuances of long-term debt		204			300			250
Reacquisitions of long-term debt		(100	)		(250	)		(97	)
(Repayments) issuances of short-term debt, net		(41	)		115			(15	)
Cost of issuances		(2	)		(3	)		(3	)
Net other financing activities		1			5			(5	)
Net Cash From Financing Activities		92			137			190
Net Increase (Decrease) In Cash and Cash Equivalents		2			(4	)		1
Cash and Cash Equivalents at Beginning of Year		2			6			5
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	4		$	2		$	6
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $1 million, $2 million and $2 million, respectively)	$	45		$	47		$	44
Cash received for income taxes (includes payments from PHI for Federal income taxes)		(43	)		(8	)		(24	)
Non-cash activities:
Reclassification of property, plant and equipment to regulatory assets		—			—			38
Reclassification of asset removal costs regulatory liability to accumulated depreciation		—			—			42

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

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF EQUITY

	Common Stock				Premium on Stock		Retained Earnings			Total
(millions of dollars, except shares)	Shares		Par Value
Balance as of December 31, 2011		1,000	$	—	$	347	$	505		$	852
Net Income		—		—		—		73			73
Capital contribution from Parent		—		—		60		—			60
Balance as of December 31, 2012		1,000		—		407		578			985
Net Income		—		—		—		89			89
Dividends on common stock		—		—		—		(30	)		(30	)
Balance as of December 31, 2013		1,000		—		407		637			1,044
Net Income		—		—		—		104			104
Capital contribution from Parent		—		—		130		—			130
Dividends on common stock		—		—		—		(100	)		(100	)
Balance as of December 31, 2014		1,000	$	—	$	537	$	641		$	1,178

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

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NOTES TO FINANCIAL STATEMENTS

DELMARVA POWER & LIGHT COMPANY

(1) ORGANIZATION

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

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014 and January 26, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for a purchase price of $18 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission, the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each

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party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (7), “Regulatory Matters – Merger Approval Proceedings.”

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. On December 22, 2014, the applicable waiting period under the HSR Act expired, and the HSR Act no longer precludes completion of the Merger. Although the Department of Justice (DOJ) allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised PHI that it has concluded its investigation. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015. On February 13, 2015, Pepco Holdings, DPL, Exelon, certain of Exelon’s affiliates, the Staff of the DPSC and certain other parties, filed a settlement agreement with the DPSC with respect to the Merger. This settlement agreement is subject to approval by the DPSC.

The Merger Agreement may be terminated by each of PHI and Exelon under certain circumstances, including if the Merger is not consummated by July 29, 2015 (subject to extension by PHI or Exelon to October 29, 2015, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Merger Agreement also provides for certain termination rights for both PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), Exelon will pay PHI a reverse termination fee equal to the purchase price paid up to the date of termination by Exelon to purchase the Preferred Stock, through PHI’s redemption of the Preferred Stock for nominal consideration. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

(2) SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

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Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment evaluations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, 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 loss contingency liabilities for general litigation and auto and other liability claims, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

DPL recognizes revenues upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered, but not yet billed. DPL’s unbilled revenue was $63 million and $61 million as of December 31, 2014 and 2013, respectively, and these amounts are included in Accounts receivable. DPL calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural 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 natural 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. Revenues from non-regulated electricity and natural gas sales are included in Electric revenues and Natural gas revenues, respectively.

Taxes related to the consumption of electricity and natural gas by its customers, such as fuel, energy, or other similar taxes, are components of DPL’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by DPL are recorded in Other taxes.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $16 million, $17 million and $15 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Accounting for Derivatives

DPL uses derivative instruments primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to natural gas price fluctuations under a hedging program approved by the DPSC. Derivatives are recorded in the balance sheets as Derivative assets or Derivative liabilities and measured at fair value. DPL enters physical natural gas contracts as part of the hedging program that qualify as normal purchases or normal sales, which are not required to be recorded in the financial statements until settled. DPL’s capacity contracts are not classified as derivatives. Changes in the fair value of derivatives that are not designated as cash flow hedges are reflected in income.

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 fully recoverable through the fuel adjustment clause approved by the DPSC, and are deferred under Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980) until recovered.

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Long-Lived Asset Impairment Evaluation

DPL evaluates certain long-lived assets to be held and used (for example, 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 its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the assets’ carrying value exceeds its estimated fair value including costs to sell.

Income Taxes

DPL, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL based upon the taxable income or loss amounts, determined on a separate return basis.

The financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on DPL’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.

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. The portion of DPL’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the balance sheets. See Note (7), “Regulatory Matters,” for additional information.

Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

DPL recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.

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

Consolidation of Variable Interest Entities

DPL assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with ASC 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (17), “Variable Interest Entities, “ for additional information.

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. Additionally, deposits in PHI’s money pool, which DPL and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

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Accounts Receivable and Allowance for Uncollectible Accounts

DPL’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. 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).

DPL maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the statements of income. DPL 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. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although DPL believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, DPL 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

Included in Inventories are transmission and distribution materials and supplies and natural gas. DPL 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.

The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Gas purchased 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. DPL tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of DPL below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting unit; an adverse change in business conditions; an adverse regulatory action; or an impairment of DPL’s long-lived assets. DPL performed its most recent annual impairment test as of November 1, 2014, and its goodwill was not impaired as described in Note (6), “Goodwill.”

Regulatory Assets and Regulatory Liabilities

Certain aspects of DPL’s business are subject to regulation by the DPSC and the MPSC. The transmission of electricity by DPL is regulated by FERC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC.

Based on the regulatory framework in which it has operated, DPL has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance 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 and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. 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, the regulatory asset would be eliminated through a charge to earnings.

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Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. For customers to whom the BSA applies, DPL recognizes 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, DPL recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer (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.

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 that 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 additional information regarding the treatment of asset retirement obligations, see the “Asset Removal Costs” section included in this Note.

The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2014, 2013 and 2012 for DPL’s property were approximately 2.6%, 2.6% and 2.7%, respectively.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities may 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 statements of income.

DPL recorded AFUDC for borrowed funds of $1 million, $2 million and $2 million for the years ended December 31, 2014, 2013 and 2012, respectively.

DPL recorded amounts for the equity component of AFUDC of $2 million, $2 million and $3 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Leasing Activities

DPL’s lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.

Operating Leases

An operating lease in which DPL 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, DPL’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.

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Arrangements Containing a Lease

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

Amortization of Debt Issuance and Reacquisition Costs

DPL defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as Regulatory assets and are amortized generally over the life of the original issue.

Asset Removal Costs

In accordance with FASB guidance, asset removal costs are recorded as regulatory liabilities. At December 31, 2014 and 2013, $166 million and $173 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets.

Pension and Postretirement Benefit Plans

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

The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).

Dividend Restrictions

All of DPL’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of DPL to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by DPL and any other restrictions imposed in connection with the incurrence of liabilities. DPL has no shares of preferred stock outstanding. DPL had approximately $641 million and $637 million of retained earnings available for payment of common stock dividends at December 31, 2014 and 2013, respectively. These amounts represent the total retained earnings balances at those dates.

Reclassifications

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

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(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Liabilities (ASC 405)

In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, DPL is required to measure such obligations as the sum of the amount it agreed to pay on the basis of its arrangement among co-obligors and any additional amount it expects to pay on behalf of its co-obligors. Adoption of this guidance during the first quarter of 2014 did not have a material impact on DPL’s financial statements.

Income Taxes (ASC 740)

In July 2013, the FASB issued new guidance requiring netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of the uncertain tax position. The prospective adoption of this guidance at March 31, 2014 resulted in DPL netting liabilities related to uncertain tax positions with deferred tax assets for net operating loss and other carryforwards (included in Deferred income tax liabilities, net) and income taxes receivable (including income tax deposits) related to effectively settled uncertain tax positions.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements are effective for DPL beginning January 1, 2017, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2017. Early adoption is not permitted. DPL is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select.

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

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The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

(5) SEGMENT INFORMATION

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

(6) GOODWILL

All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.

DPL performs an annual impairment assessment as of November 1 of each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of the DPL reporting unit to which goodwill relates is less than its carrying value. In evaluating goodwill for impairment, DPL first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If DPL concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and DPL is not required to perform the two-step goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, overall financial performance, changes in any key inputs to the prior year impairment test, including the discount rate, and other relevant events and factors affecting the reporting unit.

If DPL concludes that it is more likely than not that the fair value is less than its carrying value, DPL performs the first step of the goodwill impairment test, which compares DPL’s fair value to its carrying value. If DPL’s fair value exceeds the carrying value of DPL’s net assets, goodwill is not considered impaired and DPL is not required to perform additional testing. If the carrying value of DPL’s net assets exceeds DPL’s fair value, then DPL must perform the second step of the goodwill impairment test to determine the implied fair value of DPL’s goodwill. If DPL determines during this second step that the carrying value of DPL’s goodwill exceeds its implied fair value, DPL records an impairment loss equal to the difference.

For the annual impairment assessment in 2014, DPL qualitatively determined that it was more likely than not that fair value exceeded carrying value. As a result, DPL did not perform the two-step goodwill impairment test on that reporting unit.

As of December 31, 2014 and 2013, DPL’s goodwill balance was $8 million. There are no accumulated impairment losses.

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(7)REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of DPL’s regulatory asset and liability balances at December 31, 2014 and 2013 are as follows:

	2014		2013
	(millions of dollars)
Regulatory Assets
Smart Grid costs	$	86	$	83
Recoverable income taxes		84		76
Demand-side management costs		67		27
COPCO acquisition adjustment		18		22
MAPP abandonment costs		14		31
Deferred debt extinguishment costs		12		13
Deferred energy supply costs		12		13
Incremental storm restoration costs		7		9
Deferred losses on gas derivatives		4		—
Other		52		37
Total Regulatory Assets	$	356	$	311
Regulatory Liabilities
Asset removal costs	$	166	$	173
Deferred income taxes due to customers		37		37
Deferred energy supply costs		—		3
Deferred gains on gas derivatives		—		1
Other		22		15
Total Regulatory Liabilities	$	225	$	229

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

Smart Grid Costs:Represents advanced metering infrastructure (AMI) costs associated with the installation of smart meters and the early retirement of legacy meters throughout DPL’s service territory that are recoverable from customers. DPL generally is deferring carrying charges on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from DPL’s customers for tax benefits applicable to utility operations that were previously recognized in income tax expense before the company was ordered to record 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.

Demand-Side Management Costs:Represents recoverable costs associated with customer energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. DPL earns a return on these regulatory assets.

COPCO Acquisition Adjustment:On July 19, 2007, the MPSC issued an order which provided for the recovery of a portion of DPL’s goodwill. As a result of this order, $41 million in DPL goodwill was transferred to a regulatory asset. This item is being amortized from August 2007 through August 2018. DPL earns a return of 12.95% on these regulatory assets.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated on August 24, 2012.

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For additional information, see “MAPP Settlement Agreement” discussion below. These regulatory assets are being amortized and recovered in transmission rates through May 2016. DPL generally does not earn a return on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment that are amortized to interest expense and recovered from customers. DPL generally earns a return on these regulatory assets.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by DPL that are being or are expected to be recovered from customers. DPL earns a return on these regulatory assets in Delaware. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by DPL to customers.

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, and Hurricane Irene, that are recoverable from customers in the Maryland jurisdiction. DPL’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a five-year period. DPL generally earns a return on these regulatory assets.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable from customers through the Gas Cost Rate (GCR) approved by the DPSC. DPL does not earn a return on these regulatory assets.

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

Asset Removal Costs: The depreciation rates for DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, DPL has recorded regulatory liabilities for its 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 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.

Deferred Gains on Gas Derivatives:Represents gains associated with hedges of natural gas purchases that will be refunded to customers through the GCR approved by the DPSC.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of the pending filings indicated below.

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Bill Stabilization Adjustment

DPL has proposed in each of its 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 has been approved and implemented for DPL electric service in Maryland.

• A proposed modified fixed variable rate design (MFVRD) for DPL electric and natural gas service in Delaware was filed in 2009 for consideration by the DPSC and while there was little to no activity associated with this filing in 2014, or to date in 2015, the proceeding remains open.

Under a 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 proposed in Delaware contemplates 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.

Delaware

Electric Distribution Base Rates

On March 22, 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The application sought approval of an annual rate increase of approximately $42 million (adjusted by DPL to approximately $39 million on September 20, 2013), based on a requested return on equity (ROE) of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. On August 5, 2014, the DPSC issued a final order in this proceeding providing for an annual increase in DPL’s electric distribution base rates of approximately $15.1 million, based on an ROE of 9.70%. The new rates became effective on May 1, 2014.

On September 4, 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 5, 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and recovery of credit facility expenses. The Division of the Public Advocate filed a cross-appeal on September 8, 2014, pertaining to the treatment of prepaid pension expense and other postretirement benefit obligations in base rates. Under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” the parties have agreed to suspend the appeal and to withdraw the appeal with prejudice upon the closing of the Merger.

Forward Looking Rate Plan

On October 2, 2013, DPL filed a multi-year rate plan, referred to as the Forward Looking Rate Plan (FLRP). As proposed, the FLRP would provide for annual electric distribution base rate increases over a four-year period in the aggregate amount of approximately $56 million. The FLRP as proposed provides the opportunity to achieve estimated earned ROEs of 7.41% and 8.80% in years one and two, respectively, and 9.75% in both years three and four of the plan.

In addition, DPL proposed that as part of the FLRP, in order to provide a higher minimum required standard of reliability for DPL’s customers than that to which DPL is currently subject, the standards by which DPL’s reliability is measured would be made more stringent in each year of the FLRP. DPL has also offered to refund an aggregate of $500,000 to customers in each year of the FLRP that it fails to meet the proposed stricter minimum reliability standards.

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On October 22, 2013, the DPSC opened a docket for the purpose of reviewing the details of the FLRP, but stated that it would not address the FLRP until the electric distribution base rate case discussed above was concluded. A schedule for the FLRP docket has not yet been established.

Under the Merger Agreement, DPL is permitted to pursue this matter; however, under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” DPL has agreed to withdraw the FLRP without prejudice to refile it in a subsequent base rate case.

Gas Distribution Base Rates

A settlement approved in October 2013 by the DPSC in a proceeding filed by DPL in December 2012 to increase its natural gas distribution base rates provides in part for a phase-in of the recovery of the deferred costs associated with DPL’s deployment of the interface management unit (IMU). The IMU is part of DPL’s AMI and allows for the remote reading of gas meters. Filing for recovery of such costs will occur in two phases, subject to compliance with specific metrics, with recovery over a 15-year period. For the first phase, 50% of the IMU-related portion of DPL’s AMI costs were put into rates on July 11, 2014. The remainder of these costs will be put into rates in the second phase when the specific metrics allowing for recovery are met.

Gas Cost Rates

DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. On August 29, 2014, DPL made its 2014 GCR filing in which it proposed a GCR decrease of approximately 7.4%. On September 30, 2014, the DPSC issued an order authorizing DPL to place the new rates into effect on November 1, 2014, subject to refund and pending final DPSC approval.

Under the Merger Agreement, DPL is permitted and intends to continue to file its required annual GCR cases in Delaware.

Federal Energy Regulatory Commission

Transmission Annual Formula Rate Update Challenges

In October 2013, FERC issued a ruling on challenges filed by the Delaware Municipal Electric Corporation, Inc. (DEMEC) to DPL’s 2011 and 2012 annual formula rate updates for transmission service. In 2006, FERC approved a formula rate for DPL that is incorporated into the PJM Interconnection, LLC (PJM) tariff. The formula rate establishes the treatment of costs and revenues and the resulting rates for DPL. Pursuant to the protocols approved by FERC and after a period of discovery, interested parties have an opportunity to file challenges regarding the application of the formula rate. The October 2013 FERC order set various issues in this proceeding for hearing, including challenges regarding formula rate inputs, deferred income items, prepayments of estimated income taxes, rate base reductions, various administrative and general expenses and the inclusion in rate base of construction work in progress related to the MAPP project abandoned by PJM. Settlement discussions began in this matter in November 2013 before an administrative law judge at FERC.

In December 2013, DEMEC filed a formal challenge to the DPL 2013 annual formula rate update for transmission service, including a request to consolidate the 2013 challenge with the two prior challenges. The issues in the challenges for 2011, 2012 and 2013 are similar. On April 8, 2014, FERC issued an order setting the 2013 challenge issues for hearing and on April 15, 2014, those issues were consolidated with

288

DPL

the 2011 and 2012 challenges. A settlement agreement was filed with FERC on August 25, 2014. On January 9, 2015, FERC issued an order approving the settlement, thereby resolving all of the issues set for hearing in the proceeding. Pursuant to the settlement, DPL will provide a one-time reduction of $225,000 to DPL’s 2015 annual formula rate update and will provide a one-time payment of $258,500 to DEMEC. In addition, the settlement resolves certain ratemaking and accounting treatments prospectively and provides that certain items will not be challenged in the future.

Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as DEMEC, filed a joint complaint at FERC against DPL and its affiliates Potomac Electric Power Company (Pepco) and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for DPL and its utility affiliates is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. DPL believes the allegations in this complaint are without merit and is vigorously contesting it. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set February 27, 2013 as the refund effective date, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, on November 24, 2014, the settlement judge issued an order terminating the settlement discussions. The matter is now before a hearing judge and a procedural schedule will be established for both the February 2013 complaint and a second complaint (discussed below) that has been consolidated with the February 2013 complaint.

On June 19, 2014, FERC issued an order in a proceeding in which DPL was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, DPL applied an estimated ROE based on the two-step methodology announced by FERC for the period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves in the second quarter of 2014 related to this matter. To the extent that the final ROE determined by FERC is lower than the ROE used to record the estimated reserves, each ten basis point reduction in the ROE would result in a reduction of DPL’s operating income of $0.5 million.

A second complaint against Pepco, DPL and ACE challenging the base ROE was filed at FERC on December 8, 2014 by the same parties. Employing the new ROE methodology referenced above, the complainants contend that the resulting base ROE should be 8.8%, and request consolidation of this complaint with the February 2013 complaint. Consistent with the prior challenge, DPL applied an estimated ROE based on the two-step methodology described above, and recorded estimated reserves in the fourth quarter of 2014 using a refund effective date of December 8, 2014.

Under the Merger Agreement, DPL is permitted to pursue the conclusion of these FERC matters and intends to continue to do so.

289

DPL

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, 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, and each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.

In response to a complaint filed by a group of generating companies in the PJM region, on September 30, 2013, the U.S. District Court for the District of Maryland issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, on October 1, 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

On October 24, 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. The Federal district court order and its associated ruling could impact the state circuit court appeal, to which the Contract EDCs are parties, although such impact, if any, cannot be determined at this time. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal district court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the lower Federal court ruling. On November 26, 2014, both the winning bidder and the MPSC petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision.

The Maryland Court of Special Appeals has stayed the appeal of the Baltimore City Circuit Court decision until July 23, 2015.

On June 2, 2014, the winning bidder filed the contracts at FERC requesting that they be accepted pursuant to Section 205 of the Federal Power Act (FPA). On August 5, 2014, FERC issued an order rejecting the filings made by the winning bidder, finding that the contracts cannot be accepted as valid contracts, given the decisions reached in the Federal court proceedings discussed above.

Assuming the contracts, as currently written, were to become effective by the expected commercial operation date of June 1, 2015, DPL continues to believe that it may be required to record its proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because DPL would recover any payments under the contracts from SOS customers. DPL has concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

Under the Merger Agreement, DPL is permitted to pursue the conclusion of this matter and intends to continue to do so.

MAPP Settlement Agreement

In February 2014, FERC issued an order approving the settlement agreement submitted by DPL in connection with DPL’s proceeding seeking recovery of approximately $38 million in abandonment costs related to the MAPP project. DPL had been directed by PJM to construct the MAPP project, a 152-mile high-voltage interstate transmission line, and in August 2012 was directed by PJM to cancel it. The abandonment costs sought for recovery were subsequently reduced to $37 million as a result of write-offs of certain disallowed costs in 2013. Under the terms of the FERC-approved settlement agreement, DPL will receive $36.6 million of transmission revenues over a three-year period, which began on June 1,

290

DPL

2013, and will retain title to all real property and property rights acquired in connection with the MAPP project, which had an estimated fair value of $6 million. The FERC-approved settlement agreement resolves all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project, and the terms of the settlement agreement are not subject to modification through any other FERC proceeding. As of December 31, 2014, DPL had a regulatory asset related to the MAPP abandonment costs of approximately $14 million, net of amortization, and land of $6 million. DPL expects to recognize pre-tax income related to the MAPP abandonment costs of $1 million in 2015.

Merger Approval Proceedings

Delaware

On June 18, 2014, Exelon, PHI and DPL, and certain of their respective affiliates, filed an application with the DPSC seeking approval of the Merger. Delaware law requires the DPSC to approve the Merger when it determines that the transaction is in accordance with law, for a proper purpose, and is consistent with the public interest. The DPSC must further find that the successor will continue to provide safe and reliable service, will not terminate or impair existing collective bargaining agreements and will engage in good faith bargaining with organized labor.

On February 13, 2015, Exelon, DPL, the DPSC staff, the Division of the Public Advocate and certain other parties filed a settlement agreement with the DPSC. The settling parties also requested that the scheduled hearings be suspended. The settlement requests that hearings regarding DPSC approval of the settlement be held in April 2015 and that the decision of the DPSC be issued thereafter in April 2015.

Maryland

On August 19, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. In making this determination, the MPSC is required to consider the following 12 criteria: (i) the potential impact of the merger on rates and charges paid by customers and on the services and conditions of operation of the utility; (ii) the potential impact of the merger on continuing investment needs for the maintenance of utility services, plant and related infrastructure; (iii) the proposed capital structure that will result from the merger, including allocation of earnings from the utility; (iv) the potential effects on employment by the utility; (v) the projected allocation between the utility’s shareholders and ratepayers of any savings that are expected; (vi) issues of reliability, quality of service and quality of customer service; (vii) the potential impact of the merger on community investment; (viii) affiliate and cross-subsidization issues; (ix) the use or pledge of utility assets for the benefit of an affiliate; (x) jurisdictional and choice-of-law issues; (xi) whether it is necessary to revise the MPSC’s ring-fencing and affiliate code of conduct regulations in light of the merger; and (xii) any other issues the MPSC considers relevant to the assessment of the merger. The MPSC is required to issue an order within 180 days of the August 19, 2014 filing date. However, the MPSC can grant a 45-day extension for good cause. If no order is issued by the statutory deadline, then the Merger would be deemed to be approved. On September 22, 2014, the MPSC issued an order setting the procedural schedule for this matter. Pursuant to that schedule, evidentiary hearings were held beginning on January 26, 2015, and all briefs are scheduled to be filed in March 2015. The deadline for the MPSC’s decision is April 8, 2015.

Virginia

On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2015, the VSCC issued an order approving the Merger.

291

DPL

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

(8) 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, 2014
Distribution	$	1,928	$	489	$	1,439
Transmission		1,107		248		859
Gas		511		153		358
Construction work in progress		125		—		125
Non-operating and other property		275		131		144
Total	$	3,946	$	1,021	$	2,925
At December 31, 2013
Distribution	$	1,788	$	492	$	1,296
Transmission		982		243		739
Gas		481		142		339
Construction work in progress		158		—		158
Non-operating and other property		264		139		125
Total	$	3,673	$	1,016	$	2,657

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

(9) PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in PHI’s single-employer plans, the PHI Retirement Plan and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the PHI OPEB Plan), as participation in multiemployer plans. For 2014, 2013 and 2012, DPL was responsible for $7 million, $18 million and $23 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan of zero, $10 million and $85 million for the years ended December 31, 2014, 2013 and 2012, respectively. In addition, DPL made contributions of zero, $3 million and $7 million, respectively, to the PHI OPEB Plan for the years ended December 31, 2014, 2013 and 2012. At December 31, 2014 and 2013, DPL’s Prepaid pension expense of $220 million and $228 million, respectively, and Other postretirement benefit obligations of $21 million and $23 million, respectively, effectively represent assets and benefit obligations resulting from DPL’s participation in the PHI benefit plans.

292

DPL

Other Postretirement Benefit Plan Amendments

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree medical plan and the retiree life insurance benefits, and became effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its projected benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $4 million reduction in DPL’s net periodic benefit cost for other postretirement benefits in 2014, when compared to 2013.

(10) DEBT

Long-Term Debt

The components of long-term debt are shown in the table below:

Type of Debt	Interest Rate	Maturity	2014			2013
			(millions of dollars)
First Mortgage Bonds
	5.22%(a)	2016	$	100		$	100
	3.50%	2023		500			300
	4.00%	2042		250			250
				850			650
Unsecured Tax-Exempt Bonds
	5.40%	2031		78			78
				78			78
Medium-Term Notes (unsecured)
	7.56%-7.58%	2017		14			14
	6.81%	2018		4			4
	7.61%	2019		12			12
	7.72%	2027		10			10
				40			40
Notes (unsecured)
	5.00%	2014		—			100
	5.00%	2015		100			100
				100			200
Total long-term debt				1,068			968
Net unamortized premium(discount)				3			(1	)
Current portion of long-term debt				(100	)		(100	)
Total net long-term debt			$	971		$	867

(a) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL.

The outstanding first mortgage bonds issued by DPL are issued under a Mortgage and Deed of Trust and are secured by a first lien on substantially all of DPL’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.

Maturities of DPL’s long-term debt outstanding at December 31, 2014 are $100 million in each of the years 2015 and 2016, $14 million in 2017, $4 million in 2018, $12 million in 2019 and $838 million thereafter.

DPL’s long-term debt is subject to certain covenants. As of December 31, 2014, DPL is in compliance with all such covenants.

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DPL

The table above does not separately identify $100 million in aggregate principal amount of debt securities issued by DPL. These debt securities are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of DPL. The principal terms of each such series of debt securities are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such debt securities, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding debt securities together effectively represent a single financial obligation and are not identified in the table above separately.

Bond Issuance

During 2014, DPL issued $200 million of its 3.50% first mortgage bonds due November 15, 2023. Net proceeds from the issuance of the bonds, which included a premium of $4 million, were used to repay DPL’s outstanding commercial paper and for general corporate purposes.

Note Retirement

During 2014, DPL retired, at maturity, $100 million of its 5.00% unsecured notes.

Short-Term Debt

DPL has 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. The components of DPL’s short-term debt at December 31, 2014 and 2013 are as follows:

	2014		2013
	(millions of dollars)
Commercial paper	$	106	$	147
Variable rate demand bonds		105		105
Total	$	211	$	252

Commercial Paper

DPL maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2014, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

DPL had $106 million and $147 million of commercial paper outstanding at December 31, 2014 and 2013, respectively. The weighted average interest rates for commercial paper issued by DPL during 2014 and 2013 were 0.26% and 0.29%, respectively. The weighted average maturity of all commercial paper issued by DPL during 2014 and 2013 was five days and three days, respectively.

Variable Rate Demand Bonds

Variable Rate Demand Bonds (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. DPL expects that any bonds submitted for purchase will continue to be remarketed successfully due to the creditworthiness of the company and because the remarketing agent 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, DPL views VRDBs as a source of long-term financing. The VRDBs outstanding in 2014 mature as follows: 2017 ($26 million), 2024 ($33 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDBs was 0.19% during 2014 and 0.26% during 2013. As of December 31, 2014, $105 million in VRDBs issued on behalf of DPL were outstanding (of which $72 million were secured by Collateral First Mortgage Bonds issued by DPL).

294

DPL

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. The termination date of this credit facility is currently August 1, 2018.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one-month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility as of December 31, 2014.

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.

As of December 31, 2014 and 2013, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $413 million and $332 million, respectively. DPL’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and ACE and the portion of the total capacity being used by PHI.

295

DPL

Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.

(11) INCOME TAXES

DPL, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission 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 income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.

Provision for Income Taxes

	For the Year Ended December 31,
	2014			2013			2012
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(45	)	$	(8	)	$	(9	)
State and local		—			—			(1	)
Total Current Tax Benefit		(45	)		(8	)		(10	)
Deferred Tax Expense (Benefit)
Federal		99			53			44
State and local		12			12			11
Investment tax credit amortization		(1	)		(1	)		(1	)
Total Deferred Tax Expense		110			64			54
Total Income Tax Expense	$	65		$	56		$	44

Reconciliation of Income Tax Expense

	For the Year Ended December 31,
	2014					2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	59		35.0	%	$	51		35.0	%	$	41		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		9		5.3	%		8		5.5	%		6		5.1	%
Other, net		(3	)	(1.8	)%		(3	)	(1.9	)%		(3	)	(2.5	)%
Income Tax Expense	$	65		38.5	%	$	56		38.6	%	$	44		37.6	%

296

DPL

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 DPL is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in DPL recording a $1 million (after-tax) interest benefit in the first quarter of 2013, which is included above in Other, net.

Components of Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2014			2013
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	797		$	712
Deferred taxes on amounts to be collected through future rates		19			16
Federal and state net operating losses		(115	)		(125	)
Pension and other postretirement benefits		80			80
Electric restructuring liabilities		(4	)		(5	)
Other		101			80
Total Deferred Tax Liabilities, net		878			758
Deferred tax assets included in Current Assets		16			59
Deferred tax liabilities included in Other Current Liabilities		(1	)		(1	)
Total Deferred Tax Liabilities, net non-current	$	893		$	816

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 DPL’s 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. No valuation allowance for deferred tax assets was required or recorded at December 31, 2014 and 2013. Federal and state net operating losses generally expire over 20 years from 2029 to 2034.

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 DPL’s property continue to be amortized to income over the useful lives of the related property.

297

DPL

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2014			2013		2012
	(millions of dollars)
Balance as of January 1	$	9		$	9	$	35
Tax positions related to current year:
Additions		1			—		—
Reductions		—			—		—
Tax positions related to prior years:
Additions		13			—		—
Reductions		(1	)		—		(26	)(a)
Settlements		—			—		—
Balance as of December 31	$	22		$	9	$	9

(a) These reductions of unrecognized tax benefits in 2012 primarily relate to a resolution reached with the Internal Revenue Service (IRS) for determining deductible mixed service costs for additions to property, plant and equipment.

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. At December 31, 2014, DPL had $1 million of unrecognized tax benefits that, if recognized, would lower the effective tax rate.

Interest and Penalties

DPL recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For each of the years ended December 31, 2014, 2013 and 2012, DPL recognized less than $1 million of pre-tax interest income as a component of income tax expense. As of December 31, 2014, 2013 and 2012, DPL had accrued interest receivable of $2 million, $2 million and $1 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 DPL’s uncertain tax positions will significantly increase or decrease within the next 12 months. PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues of DPL for open tax years 2001 through 2011. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2015, which could significantly impact the balances of unrecognized tax benefits and the related interest accruals of DPL. At this time, it is estimated that there will be a $14 million to $18 million decrease in unrecognized tax benefits within the next 12 months.

Tax Years Open to Examination

DPL, as an indirect subsidiary of PHI, is included on PHI’s consolidated Federal tax return. DPL’s federal income tax liabilities for all years through 2002 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where DPL files state income tax returns (Maryland and Delaware) are the same as for the Federal returns.

298

DPL

Final IRS Regulations on Repair of Tangible Property

In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on DPL’s financial statements.

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2014		2013		2012
	(millions of dollars)
Gross Receipts/Delivery	$	16	$	15	$	14
Property		24		24		21
Environmental, Use and Other		2		1		1
Total	$	42	$	40	$	36

(12)DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce natural gas commodity price volatility and limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC.

299

DPL

The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2014 and 2013:

	As of December 31, 2014
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative liabilities (current liabilities)	$	—	$	(4	)	$	(4	)	$	4	$	—

	As of December 31, 2013
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments		Gross Derivative Instruments		Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative assets (current assets)	$	—	$	1	$	1	$	(1	)	$	—

All derivative assets and liabilities available to be offset under master netting arrangements were netted as of December 31, 2014 and 2013. The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2014		December 31, 2013
	(millions of dollars)
Cash collateral pledged to counterparities with the right reclaim (a)	$	4	$	—
Cash collateral received from counterparties with the obligation to return	$	—	$	(1	)

(a) Includes cash deposits on commodity brokerage accounts.

As of December 31, 2014 and 2013, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

Other Derivative Activity

DPL has certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheets with the gain or loss for changes in the fair value recorded in income. In addition, in accordance with FASB guidance on regulated operations, regulatory liabilities or regulatory assets of the same amount are recorded on the balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the statements of income (through Purchased energy and Gas purchased expense) and that were also deferred as Regulatory liabilities and Regulatory assets, respectively, for the years ended December 31, 2014, 2013 and 2012:

	For the Year Ended December 31,
	2014			2013			2012
	(millions of dollars)
Net unrealized (loss) gain arising during the period	$	(3	)	$	1		$	(3	)
Net realized gain (loss) recognized during the period		2			(4	)		(16	)

300

DPL

As of December 31, 2014 and 2013, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	December 31, 2014				December 31, 2013
Commodity	Quantity		Net Position		Quantity		Net Position
Natural Gas (One Million British Thermal Units (MMBtu))		3,892,500		Long		3,977,500		Long

(13) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

DPL applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). DPL utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, DPL utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

301

DPL

The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2014
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
Restricted cash equivalents
Treasury funds	$	5	$	5	$	—	$	—
Executive deferred compensation plan assets
Money market funds		1		1		—		—
Life insurance contracts		1		—		—		1
Total	$	7	$	6	$	—	$	1
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	4	$	4	$	—	$	—
Executive deferred compensation plan assets
Life insurance contracts		1		—		1		—
Total	$	5	$	4	$	1	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

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

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

	Fair Value Measurements at December 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (b)
Natural gas (c)	$	1	$	1	$	—	$	—
Executive deferred compensation plan assets
Money market funds		1		1		—		—
Life insurance contracts		1		—		—		1
Total	$	3	$	2	$	—	$	1
LIABILITIES
Executive deferred compensation plan assets
Life insurance contracts	$	1	$	—	$	1	$	—
Total	$	1	$	—	$	1	$	—

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

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

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

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DPL

DPL classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

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

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

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

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

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

Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2014 and 2013 are shown below:

	Year Ended December 31, 2014		Year Ended December 31, 2013
	Life Insurance Contracts		Natural Gas			Life Insurance Contracts
	(millions of dollars)
Balance as of January 1	$	1	$	(4	)	$	1
Total gains (losses) (realized and unrealized):
Included in income		—		—			—
Included in accumulated other comprehensive loss		—		—			—
Included in regulatory liabilities		—		—			—
Purchases		—		—			—
Issuances		—		—			—
Settlements		—		4			—
Transfers in (out) of Level 3		—		—			—
Balance as of December 31	$	1	$	—		$	1

303

DPL

Other Financial Instruments

The estimated fair values of DPL’s Long-term debt instruments that are measured at amortized cost in DPL’s financial statements and the associated level of the estimates within the fair value hierarchy as of December 31, 2014 and 2013 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and DPL reviews the methodologies and results.

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

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,123	$	—	$	1,016	$	107

(a) The carrying amount for Long-term debt was $1,071 million as of December 31, 2014.

	Fair Value Measurements at December 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	960	$	—	$	850	$	110

(a) The carrying amount for Long-term debt was $967 million as of December 31, 2013.

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

304

DPL

(14) COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, DPL is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. DPL is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, DPL’s contracts with its vendors generally require the vendors to name DPL as an additional insured for the amount at least equal to DPL’s self-insured retention. Further, DPL’s contracts with its vendors require the vendors to indemnify DPL for various acts and activities that may give rise to claims against DPL. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on DPL’s financial condition, results of operations or cash flows. At December 31, 2014, DPL had recorded estimated loss contingency liabilities for general litigation totaling approximately $2 million.

Environmental Matters

DPL is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from DPL’s customers, environmental clean-up costs incurred by DPL generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of DPL described below at December 31, 2014 are summarized as follows:

	Transmission and Distribution		Legacy Generation - Regulated		Total
	(millions of dollars)
Balance as of January 1	$	1	$	2	$	3
Accruals		—		—		—
Payments		—		—		—
Balance as of December 31		1		2		3
Less amounts in Other Current Liabilities		1		1		2
Amounts in Other Deferred Credits	$	—	$	1	$	1

Ward Transformer Site

In April 2009, a group of potentially responsible parties (PRPs) with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including DPL, based on 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 DPL) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the Federal 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 Federal district court’s order addresses only the liability of the test case defendant. Plaintiffs have appealed the district court’s order to the U.S. Court of Appeals for the Fourth Circuit. DPL has concluded that a loss is reasonably possible with respect

305

DPL

to this matter, but is unable to estimate an amount or range of reasonably possible losses to which it may be exposed. DPL does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

Indian River Oil Release

In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. The amount of remediation costs accrued for this matter is included in the table above in the column entitled “Legacy Generation – Regulated.”

Metal Bank Site

In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted DPL on behalf of itself and other federal and state trustees to request that DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. DPL executed a tolling agreement, which has been extended to March 15, 2015, and will continue settlement discussions with the NOAA, the trustees and other PRPs.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Virginia Department of Environmental Quality Notice of Violation

On February 2, 2015, the Virginia Department of Environmental Quality (VDEQ) issued a notice of violation (NOV) to DPL in connection with alleged violations of state water control laws and regulations associated with recent construction activities undertaken to replace certain transmission facilities. The NOV informs DPL of information on which VDEQ may rely to institute an administrative or judicial enforcement action, requests a meeting, and states that DPL may be asked to enter into a consent order to formalize a plan and schedule of corrective action and settle any outstanding issues regarding the matter including the assessment of civil charges. Whether any such charges will be assessed is not known or estimable at this time. DPL does not believe that the remediation costs to resolve this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

Contractual Obligations

Power Purchase Contracts

As of December 31, 2014, DPL’s contractual obligations under non-derivative power purchase contracts were $64 million in 2015, $129 million in 2016 to 2017, $128 million in 2018 to 2019 and $291 million thereafter.

Lease Commitments

DPL leases an 11.9% interest in the Merrill Creek Reservoir. The lease is an operating lease and payments over the remaining lease term, which ends in 2032, are $79 million in the aggregate. DPL also has long-term leases for certain other facilities and equipment. Total future minimum operating lease payments for DPL, including the Merrill Creek Reservoir lease, as of December 31, 2014, are $13 million in 2015, $12 million in 2016, $11 million in 2017, $14 million in 2018, $5 million in 2019 and $114 million thereafter.

Rental expense for operating leases, including the Merrill Creek Reservoir lease, was $14 million, $13 million and $12 million for the years ended December 31, 2014, 2013 and 2012, respectively.

306

DPL

(15) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the years ended December 31, 2014, 2013 and 2012 were $163 million, $154 million and $153 million, respectively.

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

	For the Year Ended December 31,
	2014		2013		2012
	(millions of dollars)
Intercompany lease transactions (a)	$	5	$	4	$	4

(a) Included in Electric revenue.

As of December 31, 2014 and 2013, DPL had the following balances on its balance sheets due to related parties:

	2014			2013
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(18	)	$	(22	)
Other		1			—
Total	$	(17	)	$	(22	)

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

(16) 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. Therefore, comparisons by quarter within a year are not meaningful.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	397		$	279		$	309		$	308		$	1,293
Total Operating Expenses		326			239			264			257			1,086
Operating Income		71			40			45			51			207
Other Expenses		(9	)		(8	)		(9	)		(12	)		(38	)
Income Before Income Tax Expense		62			32			36			39			169
Income Tax Expense		25			13			13			14			65
Net Income	$	37		$	19		$	23		$	25		$	104

307

DPL

	2013
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	370		$	266		$	296		$	312		$	1,244
Total Operating Expenses		317			235			249			258			1,059
Operating Income		53			31			47			54			185
Other Expenses		(11	)		(10	)		(10	)		(9	)		(40	)
Income Before Income Tax Expense		42			21			37			45			145
Income Tax Expense		16			9			14			17			56
Net Income	$	26		$	12		$	23		$	28		$	89

(17)VARIABLE INTEREST ENTITIES

DPL is required to consolidate a VIE in accordance with FASB ASC 810 if DPL is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. DPL performed a qualitative analysis to determine whether a variable interest provided a controlling financial interest in any of the VIE’s in which DPL has an interest at December 31, 2014, as described below.

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, 2014, DPL is a party to three land-based wind PPAs in the aggregate amount of 128 MWs, one solar PPA with a 10 MW facility, and a PPA with the Delaware Sustainable Energy Utility (DSEU) to purchase solar renewable energy credits (SRECs). 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 SRECs from the solar facility and DSEU, up to certain amounts (as set forth below) at rates that are primarily fixed under the respective agreements. DPL has concluded that while VIEs exist under these contracts, consolidation is not required under the FASB guidance on the consolidation of VIEs as DPL is not the primary beneficiary. DPL has not provided financial or other support under these arrangements that it was not previously contractually required to provide during the periods presented, nor does DPL have any intention to provide such additional support.

Because DPL has no equity or debt interest in these renewable energy transactions, the maximum exposure to loss relates primarily to any above-market costs incurred for power, RECs or SRECs. Due to unpredictability in the amount of MWs ultimately purchased under the agreements for purchased renewable energy, RECs and SRECs, DPL is unable to quantify the maximum exposure to loss. The power purchase, REC and SREC costs are recoverable from DPL’s customers through regulated rates.

Wind PPAs

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. DPL’s aggregate purchases under the three wind PPAs totaled $31million, $30 million and $27 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Solar PPAs

The term of the PPA with the solar facility is through 2030 and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. The DSEU may enter into 20-year contracts with solar facilities to purchase SRECs for resale to DPL. Under the DSEU PPA, DPL is obligated to purchase SRECs in amounts not to exceed 19 MWs at annually determined auction rates. DPL’s purchases under these solar PPAs totaled $6 million, $3 million and $2 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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DPL

Fuel Cell Facilities

On October 18, 2011, the 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 acts solely as an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each MW hour of energy produced by the fuel cell facilities through 2033. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. At December 31, 2014 and 2013, 30 MWs and 15 MWs of capacity were available from fuel cell facilities placed in service under the tariff, respectively. DPL billed $36 million, $23 million and $4 million to distribution customers for the years ended December 31, 2014, 2013 and 2012, respectively.

309

ACE

Management’s Report on Internal Control Over Financial Reporting

The management of Atlantic City Electric Company (ACE) 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 ACE assessed ACE’s internal control over financial reporting as of December 31, 2014 based on criteria established in theInternal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of ACE concluded that ACE’s internal control over financial reporting was effective as of December 31, 2014.

310

ACE

Report of Independent Registered Public Accounting Firm

To the Shareholder and Board of Directors of

Atlantic City Electric Company

In our opinion, the consolidated financial statements of Atlantic City Electric Company (a wholly owned subsidiary of Pepco Holdings, Inc.) listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Atlantic City Electric Company and its subsidiary at December 31, 2014 and December 31, 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule of Atlantic City Electric Company listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Washington, D.C.

February 26, 2015

311

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Year Ended December 31,	2014			2013			2012
	(millions of dollars)
Operating Revenue	$	1,213		$	1,202		$	1,198
Operating Expenses
Purchased energy		653			660			703
Other operation and maintenance		246			230			239
Depreciation and amortization		157			136			124
Other taxes		2			14			18
Deferred electric service costs		20			26			(5	)
Total Operating Expenses		1,078			1,066			1,079
Operating Income		135			136			119
Other Income (Expenses)
Interest expense		(63	)		(68	)		(70	)
Other income		1			1			4
Total Other Expenses		(62	)		(67	)		(66	)
Income Before Income Tax Expense		73			69			53
Income Tax Expense		28			19			18
Net Income	$	45		$	50		$	35

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

ASSETS	December 31, 2014			December 31, 2013
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	2		$	3
Restricted cash equivalents		10			10
Accounts receivable, less allowance for uncollectible accounts of $9 million and $10 million, respectively		167			186
Inventories		23			28
Income taxes and related accrued interest receivable		151			147
Prepaid expenses and other		13			16
Total Current Assets		366			390
OTHER ASSETS
Regulatory assets		427			569
Prepaid pension expense		96			106
Income taxes and related accrued interest receivable		34			34
Restricted cash equivalents		14			14
Other		12			12
Total Other Assets		583			735
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		3,073			2,901
Accumulated depreciation		(760	)		(751	)
Net Property, Plant and Equipment		2,313			2,150
TOTAL ASSETS	$	3,262		$	3,275

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY	December 31, 2014		December 31, 2013
	(millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	127	$	138
Current portion of long-term debt		59		148
Accounts payable		20		21
Accrued liabilities		103		105
Accounts payable due to associated companies		15		15
Taxes accrued		1		12
Interest accrued		13		13
Customer deposits		21		22
Other		22		23
Total Current Liabilities		381		497
DEFERRED CREDITS
Regulatory liabilities		14		57
Deferred income tax liabilities, net		865		833
Investment tax credits		5		5
Other postretirement benefit obligations		36		35
Other		16		14
Total Deferred Credits		936		944
OTHER LONG-TERM LIABILITIES
Long-term debt		888		753
Transition bonds issued by ACE Funding		171		214
Total Other Long-Term Liabilities		1,059		967
COMMITMENTS AND CONTINGENCIES (NOTE 13)
EQUITY
Common stock, $3.00 par value, 25,000,000 shares authorized, 8,546,017 shares outstanding		26		26
Premium on stock and other capital contributions		651		651
Retained earnings		209		190
Total Equity		886		867
TOTAL LIABILITIES AND EQUITY	$	3,262	$	3,275

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Year Ended December 31,	2014			2013			2012
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	45		$	50		$	35
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		157			136			124
Deferred income taxes		37			53			62
Investment tax credit amortization		—			(1	)		(1	)
Changes in:
Accounts receivable		18			7			(7	)
Inventories		5			2			(5	)
Regulatory assets and liabilities, net		13			19			(33	)
Accounts payable and accrued liabilities		(13	)		(1	)		15
Pension contributions		—			(30	)		(30	)
Income tax-related prepayments, receivables and payables		(16	)		(6	)		(43	)
Other assets and liabilities		13			12			19
Net Cash From Operating Activities		259			241			136
INVESTING ACTIVITIES
Investment in property, plant and equipment		(225	)		(261	)		(256	)
Department of Energy capital reimbursement awards received		1			2			2
Net other investing activities		—			3			(1	)
Net Cash Used By Investing Activities		(224	)		(256	)		(255	)
FINANCING ACTIVITIES
Dividends paid to Parent		(26	)		(60	)		(35	)
Capital contributions from Parent		—			75			—
Issuances of long-term debt		150			100			—
Reacquisitions of long-term debt		(48	)		(108	)		(41	)
(Repayments) issuances of short-term debt, net		(11	)		6			110
Repayment of term loan		(100	)		—			—
Net other financing activities		(1	)		(1	)		—
Net Cash (Used By) From Financing Activities		(36	)		12			34
Net Decrease In Cash and Cash Equivalents		(1	)		(3	)		(85	)
Cash and Cash Equivalents at Beginning of Year		3			6			91
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	2		$	3		$	6
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $1 million, less than $1 million and $2 million, respectively)	$	61		$	67		$	68
Cash (received) paid for income taxes (includes payments to (from) PHI for Federal income taxes)		(3	)		(21	)		1

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

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CONSOLIDATED STATEMENTS OF EQUITY

(millions of dollars, except shares)	Common Stock				Premium on Stock		Retained Earnings			Total
	Shares		Par Value
Balance as of December 31, 2011		8,546,017	$	26	$	576	$	200		$	802
Net Income		—		—		—		35			35
Dividends on common stock		—		—		—		(35	)		(35	)
Balance as of December 31, 2012		8,546,017		26		576		200			802
Net Income		—		—		—		50			50
Dividends on common stock		—		—		—		(60	)		(60	)
Capital contribution from Parent		—		—		75		—			75
Balance as of December 31, 2013		8,546,017		26		651		190			867
Net Income		—		—		—		45			45
Dividends on common stock		—		—		—		(26	)		(26	)
Balance as of December 31, 2014		8,546,017	$	26	$	651	$	209		$	886

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1)ORGANIZATION

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

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014 and January 26, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for a purchase price of $18 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission, the Maryland Public Service Commission, the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period

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between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (6), “Regulatory Matters – Merger Approval Proceedings.”

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. On December 22, 2014, the applicable waiting period under the HSR Act expired, and the HSR Act no longer precludes completion of the Merger. Although the Department of Justice (DOJ) allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised PHI that it has concluded its investigation. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015. On February 13, 2015, Pepco Holdings, Delmarva Power & Light Company (DPL), Exelon, certain of Exelon’s affiliates, the Staff of the DPSC and certain other parties, filed a settlement agreement with the DPSC with respect to the Merger. This settlement agreement is subject to approval by the DPSC.

The Merger Agreement may be terminated by each of PHI and Exelon under certain circumstances, including if the Merger is not consummated by July 29, 2015 (subject to extension by PHI or Exelon to October 29, 2015, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Merger Agreement also provides for certain termination rights for both PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), Exelon will pay PHI a reverse termination fee equal to the purchase price paid up to the date of termination by Exelon to purchase the Preferred Stock, through PHI’s redemption of the Preferred Stock for nominal consideration. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

(2) SIGNIFICANT ACCOUNTING POLICIES

Consolidation Policy

The accompanying consolidated financial statements include the accounts of ACE and its wholly owned subsidiary Atlantic City Electric Transition Funding, LLC (ACE Funding). All intercompany balances and transactions between subsidiaries have been eliminated. ACE uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies where 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 ACE’s percentage interest in the facility.

Use of Estimates

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

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

Revenue Recognition

ACE recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for electricity delivered but not yet billed. ACE’s unbilled revenue was $32 million and $36 million as of December 31, 2014 and 2013, respectively, and these amounts are included in Accounts receivable. ACE calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity 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 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 by its customers are a component of ACE’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by ACE are recorded in Other taxes.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $1 million, $11 million and $15 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Long-Lived Asset Impairment Evaluation

ACE evaluates certain long-lived assets to be held and used (for example, 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 its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.

Income Taxes

ACE, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE based upon the taxable income or loss amounts, determined on a separate return basis.

The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on ACE’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.

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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. The portion of ACE’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the consolidated balance sheets. See Note (6), “Regulatory Matters,” for additional information.

Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

ACE recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.

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

Consolidation of Variable Interest Entities

ACE assesses its contractual arrangements with variable interest entities (VIEs) 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. See Note (16), “Variable Interest Entities,” for additional information.

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. Additionally, deposits in PHI’s money pool, which ACE and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Restricted Cash Equivalents

The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in 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

ACE’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territories, other accounts receivable, and accrued unbilled revenue. 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).

ACE 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. ACE 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. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although ACE believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, ACE 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.

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Inventories

Included in inventories are transmission and distribution materials and supplies. ACE 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.

Regulatory Assets and Regulatory Liabilities

Certain aspects of ACE’s business are subject to regulation by the NJBPU. The transmission of electricity by ACE is regulated by FERC.

Based on the regulatory framework in which it has operated, ACE has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance 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 and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. 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, the regulatory asset would be eliminated through a charge to earnings.

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 that 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.

The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2014, 2013 and 2012 for ACE’s property were approximately 2.6%, 2.8% and 3.0%, respectively.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities may 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.

ACE recorded AFUDC for borrowed funds of $1 million for the year ended December 31, 2014, less than $1 million for the year ended December 31, 2013 and $2 million for the year ended December 31, 2012.

ACE recorded amounts for the equity component of AFUDC of $1 million for the year ended December 31, 2014, less than $1 million for the year ended December 31, 2013 and $3 million for the year ended December 31, 2012.

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Leasing Activities

ACE’s lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.

Operating Leases

An operating lease in which ACE 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, ACE’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.

Arrangements Containing a Lease

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

Amortization of Debt Issuance and Reacquisition Costs

ACE defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the original issue.

Pension and Postretirement Benefit Plans

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

The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).

Dividend Restrictions

All of ACE’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of ACE to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and the regulatory requirement that ACE 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 existing and future preferred stock, mortgage bonds and other long-term debt issued by ACE and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of the charter of ACE which impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Currently, the restriction in the ACE charter does not limit its ability to pay common stock dividends. ACE had approximately $209 million and $190 million of retained earnings available for payment of common stock dividends at December 31, 2014 and 2013, respectively. These amounts represent the total retained earnings balances at those dates.

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Reclassifications

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

Revisions of Prior Period Financial Statements

Operating and Financing Cash Flows

The consolidated statements of cash flows for the years ended December 31, 2013 and 2012 have been revised to correctly present changes in book overdraft balances as operating activities (included in Changes in accounts payable and accrued liabilities) rather than financing activities (included previously in Net other financing activities). For the year ended December 31, 2013, the effect of the revision was to decrease Net cash from operating activities by $5 million from $246 million to $241 million, and increase Net cash from financing activities by $5 million from $7 million to $12 million. For the year ended December 31, 2012, the effect of the revision was to increase Net cash from operating activities by $3 million from $133 million to $136 million, and decrease Net cash from financing activities by $3 million from $37 million to $34 million. The revision was not considered to be material, individually or in the aggregate, to previously issued financial statements.

(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Liabilities (ASC 405)

In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, ACE is required to measure such obligations as the sum of the amount it agreed to pay on the basis of its arrangement among co-obligors and any additional amount it expects to pay on behalf of its co-obligors. Adoption of this guidance during the first quarter of 2014 did not have a material impact on ACE’s consolidated financial statements.

Income Taxes (ASC 740)

In July 2013, the FASB issued new guidance requiring netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of the uncertain tax position. The prospective adoption of this guidance at March 31, 2014 resulted in ACE netting liabilities related to uncertain tax positions with deferred tax assets for net operating loss and other carryforwards (included in Deferred income tax liabilities, net) and income taxes receivable (including income tax deposits) related to effectively settled uncertain tax positions.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

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The new requirements are effective for ACE beginning January 1, 2017, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2017. Early adoption is not permitted. ACE is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select.

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

(5) SEGMENT INFORMATION

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

(6) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of ACE’s regulatory asset and liability balances at December 31, 2014 and 2013 are as follows:

	2014		2013
	(millions of dollars)
Regulatory Assets
Securitized stranded costs	$	278	$	350
Deferred energy supply costs		58		117
Recoverable income taxes		42		42
Incremental storm restoration costs		15		26
Other		34		34
Total Regulatory Assets	$	427	$	569
Regulatory Liabilities
Federal and state tax benefits, related to securitized stranded costs	$	8	$	13
Deferred energy supply costs		—		38
Other		6		6
Total Regulatory Liabilities	$	14	$	57

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

Securitized Stranded Costs: Certain contract termination payments under a contract between ACE and an unaffiliated non-utility generator (NUG) and costs associated with the regulated operations of ACE’s 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 (the Transition Bonds). These Transition Bonds mature between 2015 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. ACE earns a return on these regulatory assets.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of energy supply costs incurred by ACE that are being or are expected to be recovered from customers. ACE earns a return on these regulatory assets. The regulatory liability represents primarily deferred costs associated with a net over-recovery of energy supply costs incurred that will be refunded by ACE to customers.

Recoverable Income Taxes: Represents amounts recoverable from ACE’s customers for tax benefits applicable to utility operations previously recognized in income tax expense before the company was ordered to record 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, and Hurricane Irene, that are recoverable from customers. ACE’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a three-year period. ACE does not earn a return on these regulatory assets.

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

Federal and State Tax Benefits, Related to Securitized Stranded Costs:Securitized stranded costs include a portion attributable to the future tax benefit expected to be realized when the higher tax basis of the generating facilities divested by ACE is deducted for New Jersey state income tax purposes, as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE’s customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service (IRS) issues its final regulations with respect to normalization of these federal excess deferred taxes.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of the pending filings indicated below.

Bill Stabilization Adjustment

In 2009, ACE proposed in New Jersey the adoption of a bill stabilization adjustment (BSA) mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. The BSA proposal was not approved and there is no BSA proposal currently pending. Under a BSA, customer distribution rates would be 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.

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Electric Distribution Base Rates

On March 14, 2014, ACE submitted an application with the NJBPU to increase its electric distribution base rates by approximately $61.7 million (excluding sales and use taxes), based on a requested return on equity (ROE) of 10.25%. The requested rate increase sought to recover expenses associated with ACE’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. On August 20, 2014, the NJBPU approved a Stipulation of Settlement entered into by ACE, NJBPU staff and the Division of Rate Counsel (DRC). The approved stipulation of settlement provides for an annual increase in ACE’s electric distribution base rates by the net amount of approximately $19.0 million (excluding sales and use taxes), based on a specified ROE of 9.75%. The new electric distribution base rates became effective for service rendered by ACE on and after September 1, 2014. The annual pre-tax earnings impact of the rate increase is approximately $19.0 million.

Update and Reconciliation of Certain Under-Recovered Balances

On March 3, 2014, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The net impact of adjusting the charges as proposed would have been an overall annual rate decrease of approximately $24.5 million (revised to a decrease of approximately $41.1 million on April 16, 2014, based upon an update for actual data through March 2014). In May 2014, the NJBPU approved a stipulation of settlement entered into by the parties in this proceeding providing for an overall annual rate decrease of $41.1 million. The rate decrease was placed into effect provisionally on June 1, 2014, subject to a review by the NJBPU of the final underlying costs for reasonableness and prudence. On January 21, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect on June 1, 2014. The rate decrease will have no effect on ACE’s operating income.

This proceeding is not expected to be affected by the Merger Agreement.

Service Extension Contributions Refund Order

On July 19, 2013, in compliance with a 2012 Superior Court of New Jersey Appellate Division (Appellate Division) court decision, the NJBPU released an order requiring utilities to issue refunds to persons or entities that paid non-refundable contributions for utility service extensions to certain areas described as “Areas Not Designated for Growth.” The order is limited to eligible contributions paid between March 20, 2005 and December 20, 2009. ACE is processing the refund requests that meet the eligibility criteria established in the order as they are received. Although ACE estimates that it received approximately $11 million of contributions between March 20, 2005 and December 20, 2009, it is currently unable to reasonably estimate the amount that it may be required to refund using the eligibility criteria established by the order. Since the July 2013 order was released, ACE has received less than $1 million in refund claims, the validity of which is being investigated by ACE prior to making any such refunds. At this time, ACE does not expect that any such amount refunded will have a material effect on its consolidated financial condition, results of operations or cash flows, as any amounts that may be refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation and cost of service. On September 30, 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision and on December 1, 2014, published a rule proposal for comment. The changes proposed by the NJBPU remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs.

Under the Merger Agreement, ACE is permitted to pursue the conclusion of this matter and intends to continue to do so.

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Generic Consolidated Tax Adjustment Proceeding

In January 2013, the NJBPU initiated a generic proceeding to examine whether a consolidated tax adjustment (CTA) should continue to be used, and if so, how it should be calculated in determining a utility’s cost of service. Under the NJBPU’s current policy, when a New Jersey utility is included in a consolidated group income tax return, an allocated amount of any reduction in the consolidated group’s taxes as a result of losses by affiliates is used to reduce the utility’s rate base, upon which the utility earns a return. This policy has negatively impacted ACE’s electric distribution base rate case outcomes and ACE’s position is that the CTA should be eliminated. In an order dated October 22, 2014, the NJBPU determined that it is appropriate for affected consolidated groups to continue to include a CTA in New Jersey base rate filings, but that the CTA calculation will be modified to limit the look-back period for the calculation to five years, exclude transmission assets from the calculation and allocate 25 percent of the final CTA amount as a reduction to the distribution revenue requirement. With this revised methodology, ACE anticipates that the negative effects of the CTA in future base rate cases will be significantly reduced.

On November 5, 2014, the DRC filed an appeal of the NJBPU’s CTA order in the Appellate Division. This appeal remains pending.

Under the Merger Agreement, ACE is permitted to pursue the conclusion of this matter and intends to continue to do so.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as DEMEC, filed a joint complaint at FERC against ACE and its affiliates Potomac Electric Power Company (Pepco) and Delmarva Power & Light Company (DPL), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. PHI, Pepco, DPL and ACE believe the allegations in this complaint are without merit and are vigorously contesting it. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set February 27, 2013 as the refund effective date, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, on November 24, 2014, the settlement judge issued an order terminating the settlement discussions. The matter is now before a hearing judge and a procedural schedule will be established for both the February 2013 complaint and a second complaint (discussed below) that has been consolidated with the February 2013 complaint.

On June 19, 2014, FERC issued an order in a proceeding in which ACE was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, ACE applied an estimated ROE based on the two-step methodology announced by FERC for the period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves in the second quarter of 2014 related to this matter. To the extent that the final ROE determined by FERC is lower than the ROE used to record the estimated reserves, each ten basis point reduction in the ROE would result in a reduction of ACE’s operating income of $0.4 million.

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A second complaint against Pepco, DPL and ACE challenging the base ROE was filed at FERC on December 8, 2014 by the same parties. Employing the new ROE methodology referenced above, the complainants contend that the resulting base ROE should be 8.8%, and request consolidation of this complaint with the February 2013 complaint. Consistent with the prior challenge, ACE applied an estimated ROE based on the two-step methodology described above, and recorded estimated reserves in the fourth quarter of 2014 using a refund effective date of December 8, 2014.

Under the Merger Agreement, ACE is permitted to pursue the conclusion of these FERC matters and intends to continue to do so.

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. ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violate certain of the requirements under the New Jersey law under which the SOCAs were established (the NJ SOCA Law). On October 22, 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice subject to the parties exercising their appellate rights in the Federal courts.

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 NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. On October 11, 2013, the Federal district court issued a ruling that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. On October 25, 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit in September 2014. On November 26, 2014 and December 10, 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision.

One of the three SOCAs was terminated effective July 1, 2013 because of an event of default of the generation company that was a party to the SOCA. The remaining two SOCAs were terminated effective November 19, 2013, as a result of a termination notice delivered by ACE after the Federal district court’s October 25, 2013 decision.

Despite the terminated status of the SOCAs, on June 2, 2014, one of the generation companies that was a party to a SOCA filed the SOCA at FERC seeking to have the SOCA accepted under Section 205 of the FPA. The EDCs intervened in the proceeding and requested that the generation company’s filing be rejected on the grounds that the SOCA never came into effect. On August 5, 2014, FERC issued an order rejecting the filings made by the generation company, finding that the contracts cannot be accepted as valid contracts, given the decisions reached in the Federal court proceedings discussed above.

In light of the October 25, 2013 Federal district court order, ACE derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) in the fourth quarter of 2013.

Merger Approval Proceedings

New Jersey

On June 18, 2014, Exelon, PHI and ACE, and certain of their respective affiliates, filed a petition with the NJBPU seeking approval of the Merger. To approve the Merger, the NJBPU must find the Merger is in the public interest, and consider the impact of the Merger on (i) competition, (ii) rates of ratepayers affected by the Merger, (iii) ACE’s employees, and (iv) the provision of safe and reliable service at just and reasonable rates. On July 23, 2014, the NJBPU voted to retain this matter, rather than assigning it to an administrative law judge. On January 14, 2015, PHI, ACE, Exelon, certain of Exelon’s affiliates, the Staff of the NJBPU, and the Independent Energy Producers of New Jersey filed a stipulation of settlement (the Stipulation) with the NJBPU in this proceeding. On February 11, 2015, the NJBPU approved the Stipulation and the Merger.

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Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

(7) 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, 2014
Generation	$	10	$	9	$	1
Distribution		1,931		450		1,481
Transmission		839		223		616
Construction work in progress		115		—		115
Non-operating and other property		178		78		100
Total	$	3,073	$	760	$	2,313
At December 31, 2013
Generation	$	10	$	9	$	1
Distribution		1,821		442		1,379
Transmission		786		221		565
Construction work in progress		110		—		110
Non-operating and other property		174		79		95
Total	$	2,901	$	751	$	2,150

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

Jointly Owned Plant

ACE’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At December 31, 2014 and 2013, ACE’s subsidiaries had a net book value ownership interest of $11 million and $8 million, respectively, in transmission and other facilities in which various parties also have ownership interests. ACE’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. ACE is responsible for providing its share of the financing for the above jointly owned facilities.

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(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in PHI’s single-employer plans, the PHI Retirement Plan and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the PHI OPEB Plan), as participation in multiemployer plans. For 2014, 2013 and 2012, ACE was responsible for $13 million, $17 million and $24 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. ACE made discretionary tax-deductible contributions of zero, $30 million and $30 million to the PHI Retirement Plan for the years ended December 31, 2014, 2013 and 2012, respectively. In addition, ACE made contributions of $3 million, $6 million and $7 million to the PHI OPEB Plan for the years ended December 31, 2014, 2013 and 2012, respectively. At December 31, 2014 and 2013, ACE’s Prepaid pension expense of $96 million and $106 million, and Other postretirement benefit obligations of $36 million and $35 million, respectively, effectively represent assets and benefit obligations resulting from ACE’s participation in these PHI benefit plans.

Other Postretirement Benefit Plan Amendments

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree medical plan and the retiree life insurance benefits, and became effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its projected benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $3 million reduction in ACE’s net periodic benefit cost for other postretirement benefits in 2014, when compared to 2013. Approximately 45% of net periodic other postretirement benefit costs were capitalized in 2014.

(9) DEBT

Long-Term Debt

The components of long-term debt are shown in the table below:

Type of Debt	Interest Rate			Maturity	2014			2013
					(millions of dollars)
First Mortgage Bonds
		7.63	% (a)	2014	$	—		$	7
		7.68	% (a)	2015-2016		17			17
		7.75	%	2018		250			250
		6.80	% (b)(c)	2021		39			39
		4.35	%	2021		200			200
		3.375	%	2024		150			—
		4.875	% (c)(d)	2029		23			23
		5.80	% (b)(e)	2034		120			120
		5.80	% (b)(e)	2036		105			105
						904			761
Variable Rate Term Loan						—			100
Total long-term debt						904			861
Net unamortized discount						(1	)		(1	)
Current portion of long-term debt						(15	)		(107	)
Total net long-term debt					$	888		$	753

(a) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of medium-term notes issued by ACE.

(b) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).

(c) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE.

(d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that ACE may not permit such release of collateral unless ACE substitutes comparable obligations for such collateral.

(e) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE.

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The outstanding first mortgage bonds issued by ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of ACE’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.

Maturities of ACE’s long-term debt outstanding at December 31, 2014 are $15 million in 2015, $2 million in 2016, zero in 2017, $250 million in 2018, zero in 2019 and $637 million thereafter.

ACE’s long-term debt is subject to certain covenants. As of December 31, 2014, ACE was in compliance with all such covenants.

The table above does not separately identify $242 million in aggregate principal amount of senior notes and medium term notes (issuer notes) issued by ACE and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of ACE. These issuer notes and tax-exempt bonds are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of ACE. The principal terms of each such series of issuer notes, or ACE’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of ACE obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.

Bond Issuance

During 2014, ACE issued $150 million of its 3.375% first mortgage bonds due September 1, 2024. ACE used $7.2 million of the net proceeds from the issuance of the bonds to repay in full at maturity $7.0 million in aggregate principal amount of ACE’s 7.63% secured medium term notes due August 29, 2014, plus accrued and unpaid interest thereon. ACE used the remainder of the net proceeds to repay its outstanding commercial paper, including commercial paper that ACE issued to prepay in full its $100 million term loan, and for general corporate purposes.

Bond Retirement

During 2014, ACE retired, at maturity, $7 million of its 7.63% medium term notes due August 29, 2014. The notes were secured by a like principal amount of first mortgage bonds due August 29, 2014, which under ACE’s mortgage and deed of trust were deemed to be satisfied when the notes were repaid.

Term Loan Agreement

On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE borrowed $100 million at a rate of interest equal to the prevailing Eurodollar rate, which was determined by reference to the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. On August 21, 2014, ACE repaid the term loan in full.

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Transition Bonds Issued by ACE Funding

The components of transition bonds are shown in the table below:

Type of Debt	Interest Rate			Maturity	2014			2013
					(millions of dollars)
Transition Bonds
		4.46	%	2016	$	—		$	8
		4.91	%	2017		17			46
		5.05	%	2020		51			54
		5.55	%	2023		147			147
						215			255
Current portion of long-term debt						(44	)		(41	)
Total net long-term Transition Bonds					$	171		$	214

For a description of the Transition Bonds, see Note (16), “Variable Interest Entities – ACE Funding.” Maturities of ACE’s Transition Bonds outstanding at December 31, 2014 are $44 million in 2015, $46 million in 2016, $35 million in 2017, $31 million in 2018, $18 million in 2019 and $41 million thereafter.

Short-Term Debt

ACE has 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. The components of ACE’s short-term debt at December 31, 2014 and 2013 are as follows:

	2014		2013
	(millions of dollars)
Commercial paper	$	127	$	120
Variable rate demand bonds		—		18
Total	$	127	$	138

Commercial Paper

ACE maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2014, the maximum capacity available under the program was $350 million, subject to available borrowing capacity under the credit facility.

ACE had $127 million and $120 million of commercial paper outstanding at December 31, 2014 and 2013, respectively. The weighted average interest rates for commercial paper issued by ACE during 2014 and 2013 were 0.27% and 0.31%, respectively. The weighted average maturity of all commercial paper issued by ACE during 2014 and 2013 was five days and four days, respectively.

Variable Rate Demand Bonds

During 2014, ACE retired, at maturity, its last remaining Variable Rate Demand Bonds (VRDBs) in the amount of $18 million. The weighted average interest rate for VRDBs was 0.05% and 0.11% during 2014 and 2013, respectively.

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. The termination date of this credit facility is currently August 1, 2018.

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The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one-month 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 agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2014.

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.

As of December 31, 2014 and 2013, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $413 million and $332 million, respectively. ACE’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and DPL and the portion of the total capacity being used by PHI.

Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.

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ACE

(10)INCOME TAXES

ACE, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission 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 income tax liabilities (assets) are shown below.

Provision for Consolidated Income Taxes

	For the Year Ended December 31,
	2014			2013			2012
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(7	)	$	(23	)	$	(31	)
State and local		(2	)		(10	)		(12	)
Total Current Tax Benefit		(9	)		(33	)		(43	)
Deferred Tax Expense (Benefit)
Federal		30			28			46
State and local		7			25			16
Investment tax credit amortization		—			(1	)		(1	)
Total Deferred Tax Expense		37			52			61
Total Consolidated Income Tax Expense	$	28		$	19		$	18

Reconciliation of Consolidated Income Tax Expense

	For the Year Ended December 31,
	2014					2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	26		35.0	%	$	24		35.0	%	$	19		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		4		5.5	%		5		7.2	%		3		5.7	%
Change in estimates and interest related to uncertain and effectively settled tax positions		(1	)	(1.4	)		(9	)	(13.0	)%		(1	)	(1.9	)%
Plant basis adjustments		—		—			(2	)	(2.9	)%		(1	)	(1.9	)%
Investment tax credit amortization		—		—			(1	)	(1.4	)%		(1	)	(1.9	)%
Other, net		(1	)	(0.7	)%		2		2.6	%		(1	)	(1.0	)%
Consolidated Income Tax Expense	$	28		38.4	%	$	19		27.5	%	$	18		34.0	%

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 ACE is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in ACE recording a $6 million (after-tax) interest benefit in the first quarter of 2013, which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions.

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During 2012, ACE recorded a $1 million benefit associated with the effective settlement with the IRS with respect to the methodology used historically to calculate deductible mixed service costs.

Components of Consolidated Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2014			2013
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	691		$	627
Deferred taxes on amounts to be collected through future rates		16			16
Payment for termination of purchased power contracts with NUGs		38			43
Deferred electric service and electric restructuring liabilities		71			96
Pension and other postretirement benefits		25			29
Purchased energy		1			2
Federal and state net operating losses		(26	)		(49	)
Other		39			55
Total Deferred Tax Liabilities, net		855			819
Deferred tax assets included in Current Assets		10			15
Deferred tax liabilities included in Other Current Liabilities		—			(1	)
Total Consolidated Deferred Tax Liabilities, net non-current	$	865		$	833

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 ACE’s 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. No valuation allowance for deferred tax assets was required or recorded at December 31, 2014 and 2013. 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 ACE’s property continue to be amortized to income over the useful lives of the related property.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2014			2013			2012
	(millions of dollars)
Balance as of January 1	$	9		$	17		$	79
Tax positions related to current year:
Additions		1			2			1
Reductions		—			—			—
Tax positions related to prior years:
Additions		5			1			8
Reductions		(2	)		(5	)		(69	)(a)
Settlements		—			(6	)		(2	)
Balance as of December 31	$	13		$	9		$	17

(a) These reductions of unrecognized tax benefits in 2012 primarily relate to a resolution reached with the IRS for determining deductible mixed service costs for additions to property, plant and equipment.

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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. At December 31, 2014, ACE had no unrecognized tax benefits that, if recognized, would lower the effective tax rate.

Interest and Penalties

ACE recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2014, 2013 and 2012, ACE recognized $1 million of pre-tax interest income (less than $1 million after-tax), $12 million of pre-tax interest income ($7 million after-tax), and $2 million of pre-tax interest income ($1 million after-tax), respectively, as a component of income tax expense. As of December 31, 2014, 2013 and 2012, ACE had accrued interest receivable of $14 million, $14 million and $7 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 ACE’s uncertain tax positions will significantly increase or decrease within the next 12 months. PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues of ACE for open tax years 2001 through 2011. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2015, which could significantly impact the balances of unrecognized tax benefits and the related interest accruals of ACE. At this time, it is estimated that there will be a $6 million to $8 million decrease in unrecognized tax benefits within the next 12 months.

Tax Years Open to Examination

ACE, as an indirect subsidiary of PHI, is included on PHI’s consolidated Federal tax return. ACE’s federal income tax liabilities for all years through 2002 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where ACE files state income tax returns (New Jersey and Pennsylvania) are the same as for the Federal returns. As a result of the final determination of these years, ACE filed amended state returns receiving $1 million in refunds.

Final IRS Regulations on Repair of Tangible Property

In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on ACE’s consolidated financial statements.

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Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2014			2013		2012
	(millions of dollars)
Gross Receipts/Delivery	$	—		$	10	$	14
Property		3			3		3
Environmental, Use and Other		(1	)		1		1
Total	$	2		$	14	$	18

(11)DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would have received payments from or made 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. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because these generators cleared the 2015-2016 PJM capacity auction in May 2012. The fair value of the derivatives embedded in the SOCAs were deferred as Regulatory assets or Regulatory liabilities because the NJBPU allowed full recovery from ACE’s distribution customers for any payments made by ACE, and ACE’s distribution customers would be entitled to any payments received by ACE.

As further discussed in Note (6), “Regulatory Matters,” in light of a Federal district court order, which ruled that the SOCAs are void, invalid and unenforceable, and ACE’s subsequent termination of the SOCAs in the fourth quarter of 2013, ACE derecognized the derivative assets and derivative liabilities related to the SOCAs in the fourth quarter of 2013.

(12)FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

ACE applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ACE utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, ACE utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

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The following tables set forth by level within the fair value hierarchy ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2014
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
Restricted cash equivalents
Treasury fund	$	24	$	24	$	—	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

	Fair Value Measurements at December 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Restricted cash equivalents
Treasury fund	$	24	$	24	$	—	$	—

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

ACE classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

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

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

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.

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

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

Other Financial Instruments

The estimated fair values of ACE’s Long-term debt instruments that are measured at amortized cost in ACE’s consolidated financial statements and the associated level of the estimates within the fair value hierarchy as of December 31, 2014 and 2013 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. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt and Transition bonds issued by ACE Funding categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and ACE reviews the methodologies and results.

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

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,035	$	—	$	903	$	132
Transition Bonds (b)		235		—		235		—
Total	$	1,270	$	—	$	1,138	$	132

(a) The carrying amount for Long-term debt was $903 million as of December 31, 2014.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014.

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	Fair Value Measurements at December 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	959	$	—	$	744	$	215
Transition Bonds (b)		285		—		285		—
Total	$	1,244	$	—	$	1,029	$	215

(a) The carrying amount for Long-term debt was $860 million as of December 31, 2013.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $255 million as of December 31, 2013.

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

(13)COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, ACE is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. ACE is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, ACE’s contracts with its vendors generally require the vendors to name ACE as an additional insured for the amount at least equal to ACE’s self-insured retention. Further, ACE’s contracts with its vendors require the vendors to indemnify ACE for various acts and activities that may give rise to claims against ACE. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on ACE’s financial condition, results of operations or cash flows. At December 31, 2014, ACE had recorded estimated loss contingency liabilities for general litigation totaling approximately $6 million (including amounts related to the matters specifically described below), and the portion of these estimated loss contingency liabilities in excess of the self-insured retention amount was substantially offset by estimated insurance receivables.

Asbestos Claim

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 December 31, 2014, ACE has concluded that a loss is probable with respect to this matter and has recorded an estimated loss contingency liability, which is included in the liability for general litigation referred to above as of December 31, 2014. However, due to the inherent uncertainty of litigation, ACE is unable to estimate a maximum amount of possible loss because the damages sought are indeterminate and 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.

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Electrical Contact Injury Claims

In October 2010, a farm combine came into and remained in contact with a primary electric line in ACE’s service territory in New Jersey. As a result, two individuals operating the combine received fatal electrical contact injuries. While attempting to rescue those two individuals, another individual sustained third-degree burns to his torso and upper extremities. In September 2012, the individual who received third-degree burns filed suit in New Jersey Superior Court, Salem County. In October 2012, additional suits were filed in the same court by or on behalf of the estates of the deceased individuals. Plaintiffs in each of the cases sought indeterminate damages and alleged that ACE was negligent in the design, construction, erection, operation and maintenance of its poles, power lines, and equipment, and that ACE failed to warn and protect the public from the foreseeable dangers of farm equipment contacting electric lines. The litigation involved a number of other defendants and the filing of numerous cross-claims. On September 23, 2014, ACE entered into a confidential settlement with each of the plaintiffs regarding this matter. On November 5, 2014, ACE received reimbursement from its insurers for the amounts of this settlement above its $2 million self-insured retention amount.

Environmental Matters

ACE is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of ACE, environmental clean-up costs incurred by ACE generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of ACE described below at December 31, 2014 are summarized as follows:

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

Franklin Slag Pile Site

In November 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA’s feasibility study for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

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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.

Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including ACE, based on 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) 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 Federal 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 Federal district court’s order addresses only the liability of the test case defendant. Plaintiffs have appealed the district court’s order to the U.S. Court of Appeals for the Fourth Circuit. ACE has concluded that a loss is reasonably possible with respect to this matter, but is unable to estimate an amount or range of reasonably possible losses to which it may be exposed. ACE does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

Contractual Obligations

Power Purchase Contracts

As of December 31, 2014, ACE’s contractual obligations under non-derivative power purchase contracts were $210 million in 2015, $381 million in 2016 to 2017, $349 million in 2018 to 2019 and $886 million thereafter.

Lease Commitments

ACE leases certain types of property and equipment for use in its operations. Rental expense for operating leases was $12 million, $12 million and $11 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Total future minimum operating lease payments for ACE as of December 31, 2014 are $6 million in 2015, $6 million 2016, $5 million in 2017, $4 million in 2018, $4 million in 2019 and $30 million thereafter.

(14)RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the years ended December 31, 2014, 2013 and 2012 were $124 million, $115 million and $117 million, respectively.

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

	For the Year Ended December 31,
	2014			2013			2012
	(millions of dollars)
Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a)	$	(4	)	$	(4	)	$	(4	)
Intercompany use revenue (b)		2			3			3

(a) Included in Other operation and maintenance expense.

(b) Included in Operating revenue.

As of December 31, 2014 and 2013, ACE had the following balances on its consolidated balance sheets due to related parties:

	2014			2013
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(14	)	$	(15	)
Other		(1	)		—
Total	$	(15	)	$	(15	)

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

(15)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. Therefore, comparisons by quarter within a year are not meaningful.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue(a)	$	340		$	253		$	347		$	273		$	1,213
Total Operating Expenses		309			228			295			246	(b)		1,078
Operating Income		31			25			52			27			135
Other Expenses		(15	)		(15	)		(15	)		(17	)		(62	)
Income Before Income Tax Expense		16			10			37			10			73
Income Tax Expense		6			4			14			4			28
Net Income	$	10		$	6		$	23		$	6		$	45

(a) During the fourth quarter of 2014, ACE reversed unbilled revenue of $3 million ($2 million after-tax) to correct an error that had overstated operating revenue in the third quarter of 2014.

(b) Includes a charge of $3 million ($2 million after-tax) to correct a prior period error related to the recoverability of certain regulatory assets.

	2013
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	277		$	271		$	396		$	258		$	1,202
Total Operating Expenses		254			242			341			229			1,066
Operating Income		23			29			55			29			136
Other Expenses		(17	)		(18	)		(17	)		(15	)		(67	)
Income Before Income Tax (Benefit) Expense		6			11			38			14			69
Income Tax (Benefit) Expense		(3	)		4			13			5			19
Net Income	$	9		$	7		$	25		$	9		$	50

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(16)VARIABLE INTEREST ENTITIES

ACE is required to consolidate a VIE in accordance with FASB ASC 810 if ACE or a subsidiary is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. ACE performed a qualitative analysis to determine whether a variable interest provided a controlling financial interest in any of the VIE’s in which ACE has an interest at December 31, 2014, as described below.

Power Purchase Agreements

ACE is a party to three PPAs with unaffiliated NUGs totaling 459 megawatts. One of the agreements ends in 2016 and the other two end in 2024. ACE has no equity or debt invested in these entities. In performing its VIE analysis, ACE has been unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE has applied the scope exemption from the consolidation guidance.

Because ACE has no equity or debt invested in the NUGs, the maximum exposure to loss relates primarily to any above-market costs incurred for power. Due to unpredictability in the pricing for purchased energy under the PPAs, ACE is unable to quantify the maximum exposure to loss. The power purchase costs are recoverable from ACE’s customers through regulated rates. Purchase activities with the NUGs, including excess power purchases not covered by the PPAs, for the years ended December 31, 2014, 2013 and 2012, were approximately $233 million, $221 million and $206 million, respectively, of which approximately $208 million, $206 million and $201 million, respectively, consisted of power purchases under the PPAs.

ACE Funding

In 2001, ACE established ACE Funding solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable Transition Bond Charge (representing revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) from ACE customers pursuant to bondable stranded costs rate orders issued by the 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). 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 Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding, and PHI and ACE consolidate ACE Funding in their consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

344

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Pepco Holdings, Inc.

None.

Potomac Electric Power Company

None.

Delmarva Power & Light Company

None.

Atlantic City Electric Company

None.

345

Item 9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Each Reporting Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in such Reporting Company’s reports under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to management of such Reporting Company, including such Reporting Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), as appropriate, to allow timely decisions regarding required disclosure. This control system, no matter how well designed and operated, can provide only reasonable assurance that the objectives of the control system are met. Such Reporting Company’s disclosure controls and procedures were designed to provide reasonable assurance of achieving their stated objectives. Under the supervision, and with the participation of management, including the CEO and the CFO, each Reporting Company has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2014, and, based upon this evaluation, the CEO and the CFO of such Reporting Company have concluded that these disclosure controls and procedures are effective to provide reasonable assurance that material information relating to such Reporting Company and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

See “Management’s Report on Internal Control Over Financial Reporting” with respect to each Reporting Company.

Attestation Report of the Registered Public Accounting Firm

The “Report of Independent Registered Public Accounting Firm” with respect to the attestation report of PHI’s registered public accounting firm is hereby incorporated by reference in response to this Item 9A.

The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted on July 21, 2010, exempts any company that is not a “large accelerated filer” or an “accelerated filer” (as defined by SEC rules) from the requirement that such company obtain an external audit of the effectiveness of its internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act. As a result, each of Pepco, DPL and ACE is exempt from the requirement that it include in its Annual Report on Form 10-K an attestation report on internal control over financial reporting by an independent registered public accounting firm; however, management’s annual report on internal control over financial reporting, pursuant to Section 404(a) of the Sarbanes-Oxley Act, is still required with respect to each of them.

Reports of Changes in Internal Control Over Financial Reporting

Under the supervision and with the participation of management, including the CEO and CFO of each Reporting Company, each such Reporting Company has evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2014, and has concluded there was no change in such Reporting Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, such Reporting Company’s internal control over financial reporting.

346

Transition to Internal Control – Integrated Framework (2013)

In May 2013, theInternal Control – Integrated Framework (2013) (2013 Framework) was released by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The 2013 Framework updates and formalizes the principles embedded in the originalInternal Control-Integrated Framework (1992) (1992 Framework), incorporates business and operating environment changes over the past two decades, and improves the original 1992 Framework’s ease of use and application. As of December 15, 2014, each Reporting Company transitioned its assessment of internal controls over financial reporting to use the 2013 Framework. Each Reporting Company’s transition to the 2013 Framework did not have a significant impact on its underlying compliance with the applicable provisions of the Sarbanes-Oxley Act of 2002, including those related to internal control over financial reporting and disclosure controls and procedures.

Item 9B. OTHER INFORMATION

Pepco Holdings, Inc.

None.

Potomac Electric Power Company

None.

Delmarva Power & Light Company

None.

Atlantic City Electric Company

None.

347

Part III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Pepco Holdings, Inc.

Other than the section entitled “Executive Officers of PHI” contained in Part I, Item 1. “Business,” of this Form 10-K, information required by this Item 10 will be (i) incorporated by reference to Pepco Holdings’ definitive proxy statement with respect to its 2015 Annual Meeting of Stockholders or (ii) provided in an amendment to this Form 10-K, to be filed with the SEC on or before April 30, 2015.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.

Item 11. EXECUTIVE COMPENSATION

Pepco Holdings, Inc.

Other than as set forth below and on Exhibit 10.51 hereto, information required by this Item 11 will be (i) incorporated by reference to Pepco Holdings’ definitive proxy statement with respect to its 2015 Annual Meeting of Stockholders or (ii) provided in an amendment to this Form 10-K, to be filed with the SEC on or before April 30, 2015.

On February 26, 2015, the Board of Directors of Pepco Holdings approved an amendment to each of the Pepco Holdings, Inc. Amended and Restated Annual Executive Incentive Compensation Plan (the EICP) and the 2012 LTIP. The amendments to each of the EICP and the 2012 LTIP give effect to certain provisions in the Merger Agreement relating to (i) the determination and payment of award opportunities under the EICP outstanding as of the effective time of the Merger and (ii) the settlement of awards outstanding under the 2012 LTIP as of the effective time of the Merger. These amendments will be effective upon the date of the closing of the Merger. The amendments to the EICP and the 2012 LTIP are set forth in Exhibit 10.19.1 and Exhibit 10.21.2 hereto, respectively. A brief description of the terms of each of the 2012 LTIP and the EICP is provided in Exhibit 10.51 attached hereto and is incorporated by reference herein.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Pepco Holdings, Inc.

Information required by this Item 12 will be (i) incorporated by reference to Pepco Holdings’ definitive proxy statement with respect to its 2015 Annual Meeting of Stockholders or (ii) provided in an amendment to this Form 10-K, to be filed with the SEC on or before April 30, 2015.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.

348

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Pepco Holdings, Inc.

Information required by this Item 13 will be (i) incorporated by reference to Pepco Holdings’ definitive proxy statement with respect to its 2015 Annual Meeting of Stockholders or (ii) provided in an amendment to this Form 10-K, to be filed with the SEC on or before April 30, 2015.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Pepco Holdings, Pepco, DPL and ACE

Audit Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for professional services rendered for the audit of the annual financial statements of Pepco Holdings and its subsidiary reporting companies for the 2014 and 2013 fiscal years, reviews of the financial statements included in the 2014 and 2013 Forms 10-Q of Pepco Holdings and its subsidiary reporting companies, reviews of other public filings, comfort letters and other attest services were $5,812,671 and $6,462,474, respectively. The amount for 2013 includes $282,058 to reflect actual invoices received that were less than the estimated invoices included within the 2013 audit amount that was disclosed in Pepco Holdings’ proxy statement for the 2014 Annual Meeting of Stockholders.

Audit-Related Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for audit-related services rendered for the 2014 and 2013 fiscal years were $654,962 and $497,177, respectively. These fees generally consisted of amounts billed in connection with advice and recommendations related to financial and accounting systems implementation and for attest services performed in connection with public service commission rate case filings. In addition, the amount for the 2014 fiscal year included $330,826 for merger-related due diligence and audit services.

Tax Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for tax services rendered for the 2014 and 2013 fiscal years were $759,767 and $1,292,685, respectively. These services generally consisted of tax compliance, tax advice and tax planning. In addition, the amounts for the 2014 and 2013 fiscal years included $363,048 and $560,236 in fees for assistance with issues related to the evaluation of potential settlement scenarios with respect to the former cross-border energy lease investments.

All Other Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for services other than those covered under “Audit Fees,” “Audit-Related Fees” and “Tax Fees” were $7,200 for each of the 2014 and 2013 fiscal years. These fees for 2014 and 2013 represented the costs of an online accounting and financial reporting research tool.

All of the services described in “Audit Fees,” “Audit-Related Fees,” “Tax Fees” and “All Other Fees” were approved in advance by the Audit Committee, in accordance with the Audit Committee Policy on the Approval of Services Provided By the Independent Auditor, which has been filed as Exhibit 99 to this Form 10-K.

349

Part IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents List

1.Financial Statements

Pepco Holdings, Inc.

Consolidated Statements of Income (Loss) for each of the years ended December 31, 2014, 2013 and 2012

Consolidated Statements of Comprehensive Income (Loss) for each of the years ended December 31, 2014, 2013 and 2012

Consolidated Balance Sheets as of December 31, 2014 and 2013

Consolidated Statements of Cash Flows for each of the years ended December 31, 2014, 2013 and 2012

Consolidated Statements of Equity for each of the years ended December 31, 2014, 2013 and 2012

Notes to Consolidated Financial Statements

Potomac Electric Power Company

Statements of Income for each of the years ended December 31, 2014, 2013 and 2012

Balance Sheets as of December 31, 2014 and 2013

Statements of Cash Flows for each of the years ended December 31, 2014, 2013 and 2012

Statements of Equity for each of the years ended December 31, 2014, 2013 and 2012

Notes to Financial Statements

Delmarva Power & Light Company

Statements of Income for each of the years ended December 31, 2014, 2013 and 2012

Balance Sheets as of December 31, 2014 and 2013

Statements of Cash Flows for each of the years ended December 31, 2014, 2013 and 2012

Statements of Equity for each of the years ended December 31, 2014, 2013 and 2012

Notes to Financial Statements

Atlantic City Electric Company

Consolidated Statements of Income for each of the years ended December 31, 2014, 2013 and 2012

Consolidated Balance Sheets as of December 31, 2014 and 2013

Consolidated Statements of Cash Flows for each of the years ended December 31, 2014, 2013 and 2012

Consolidated Statements of Equity for each of the years ended December 31, 2014, 2013 and 2012

Notes to Consolidated Financial Statements

350

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 included in Part II, Item 8. “Financial Statements and Supplementary Data” of this Form10-K.

	Registrants
Item	Pepco Holdings		Pepco		DPL		ACE
Schedule I, Condensed Financial Information of Parent Company		352		N/A		N/A		N/A
Schedule II, Valuation and Qualifying Accounts		357		357		358		358

351

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

PEPCO HOLDINGS, INC. (Parent Company)

STATEMENTS OF INCOME (LOSS)

	For the Year Ended December 31,
	2014			2013			2012
	(millions of dollars, except share data)
Operating Revenue	$	—		$	—		$	—
Operating Expenses
Other operation and maintenance		31			1			1
Total operating expenses		31			1			1
Operating Loss		(31	)		(1	)		(1	)
Other Income (Expenses)
Interest expense		(43	)		(42	)		(33	)
Income from equity investments		291			204			237
Total other income		248			162			204
Income from Continuing Operations Before Income Tax		217			161			203
Income Tax (Benefit) Expense Related to Continuing Operations		(25	)		51			(15	)
Net Income from Continuing Operations		242			110			218
(Loss) Income from Discontinued Operations, net of Income Taxes		—			(322	)		67
Net Income (Loss)	$	242		$	(212	)	$	285
Comprehensive Income (Loss)	$	230		$	(198	)	$	300
Earnings Per Share
Basic earnings per share of common stock from Continuing Operations	$	0.96		$	0.45		$	0.95
Basic (loss) earnings per share of common stock from Discontinued Operations		—			(1.31	)		0.30
Basic earnings (loss) per share of common stock	$	0.96		$	(0.86	)	$	1.25
Diluted earnings per share of common stock from Continuing Operations	$	0.96		$	0.45		$	0.95
Diluted (loss) earnings per share of common stock from Discontinued Operations		—			(1.31	)		0.29
Diluted earnings (loss) per share of common stock	$	0.96		$	(0.86	)	$	1.24

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

352

PEPCO HOLDINGS, INC. (Parent Company)

BALANCE SHEETS

	As of December 31,
	2014			2013
	(millions of dollars, except share data)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	65		$	—
Prepayments of income taxes		152			151
Accounts receivable and other		9			28
Total Current Assets		226			179
INVESTMENTS AND OTHER ASSETS
Goodwill		1,398			1,398
Investment in consolidated companies		4,256			3,935
Other		84			37
Total Investments and Other Assets		5,738			5,370
TOTAL ASSETS	$	5,964		$	5,549
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	287		$	24
Current portion of long-term debt		250			—
Interest and taxes accrued		9			10
Accounts payable due to associated companies		13			1
Total Current Liabilities		559			35
DEFERRED CREDITS
Notes payable due to subsidiary companies		494			491
Liabilities and accrued interest related to uncertain tax positions		4			3
Total Deferred Credits		498			494
LONG-TERM DEBT		456			705
COMMITMENTS AND CONTINGENCIES (NOTE 4)
PREFERRED STOCK
Series A preferred stock, $.01 par value, 18,000 shares authorized, 12,600 and zero shares outstanding, respectively		129			—
EQUITY
Common stock, $.01 par value—400,000,000 shares authorized, 252,728,684 and 250,324,898 shares outstanding, respectively		3			3
Premium on stock and other capital contributions		3,800			3,751
Accumulated other comprehensive loss		(46	)		(34	)
Retained earnings		565			595
Total Equity		4,322			4,315
TOTAL LIABILITIES AND EQUITY	$	5,964		$	5,549

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

353

PEPCO HOLDINGS, INC. (Parent Company)

STATEMENTS OF CASH FLOWS

	For the Year Ended December 31,
	2014			2013			2012
	(millions of dollars)
OPERATING ACTIVITIES
Net income (loss)	$	242		$	(212	)	$	285
Loss (income) from discontinued operations, net of income taxes		—			322			(67	)
Adjustments to reconcile net income to net cash from operating activities:
Distributions from related parties less than earnings		(149	)		(127	)		(52	)
Deferred income taxes		(5	)		(7	)		(31	)
Other		18			—			—
Changes in:
Prepaid and other		13			2			(23	)
Accounts payable		1			6			6
Interest and taxes		—			(141	)		39
Other assets and liabilities		1			3			4
Net Cash From (Used By) Operating Activities		121			(154	)		161
FINANCING ACTIVITIES
Dividends paid on common stock		(272	)		(270	)		(248	)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation		34			50			51
Issuances of common stock		—			324			—
Issuances of Series A preferred stock		126			—			—
Capital contributions to subsidiaries, net		(210	)		(250	)		(110	)
Decrease in notes receivable from associated companies		—			—			154
Increase in notes payable due to associated companies		3			491			—
Issuances (repayments) of short-term debt, net		263			(240	)		(201	)
Issuance of term loan		—			250			200
Repayments of term loans		—			(450	)		—
Costs of issuances		—			(13	)		(2	)
Net Cash Used By Financing Activities		(56	)		(108	)		(156	)
Net Increase (Decrease) In Cash and Cash Equivalents		65			(262	)		5
Cash and Cash Equivalents at Beginning of Year		—			262			257
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	65		$	—		$	262

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

354

NOTES TO FINANCIAL INFORMATION

(1)BASIS OF PRESENTATION

Pepco Holdings, Inc. (Pepco Holdings or PHI) 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 Part II, Item 8 of this Form 10-K.

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

(2)RECLASSIFICATIONS

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

(3)DEBT

For information concerning Pepco Holdings’ long-term debt obligations, see Note (10), “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.

Pepco Holdings guarantees the obligations of Pepco Energy Services, Inc., its wholly owned subsidiary, under certain contracts in its energy savings performance contracting businesses and underground transmission and distribution construction business. At December 31, 2014, Pepco Holdings’ guarantees of Pepco Energy Services’ obligations under these contracts totaled $336 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects in these businesses. These guarantees totaled $185 million at December 31, 2014.

In addition, Pepco Holdings guarantees certain obligations of Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL), and Atlantic City Electric Company (ACE) under surety bonds obtained by these subsidiaries, for construction projects and self-insured workers compensation matters. These guarantees totaled $53 million at December 31, 2014.

Pepco Holdings, pursuant to an intercompany guarantee agreement with Potomac Capital Investment Corporation (PCI), guarantees certain intercompany obligations of PCI to its subsidiaries. This guarantee totaled $725 million at December 31, 2014.

(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:

	2014		2013
	(millions of dollars)
Conectiv, LLC (a)	$	1,984	$	1,730
Potomac Electric Power Company		2,087		1,922
Potomac Capital Investment Corporation		30		29
Pepco Energy Services, Inc.		153		250
PHI Service Company		2		4
Total investment in consolidated companies	$	4,256	$	3,935

(a) Conectiv, LLC is the parent company of Delmarva Power & Light Company and Atlantic City Electric Company.

355

(6)DISCONTINUED OPERATIONS

During 2013, PHI completed the termination of its interest in its cross-border energy lease investments and, as a result, these investments have been accounted for as 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. In 2013, Pepco Energy Services completed the wind-down and, accordingly, the operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations.

(7)RELATED PARTY TRANSACTIONS

As of December 31, 2014 and 2013, PHI had the following balances on its balance sheets due (to) from related parties:

	2014			2013
	(millions of dollars)
(Payable to) Receivable from Related Party (current) (a)
Conectiv Communications, Inc.	$	(4	)	$	(4	)
PHI Service Company		(10	)		3
Other		1			—
Total	$	(13	)	$	(1	)
Payable to Related Party (non-current) (b)
Potomac Capital Investment Corporation	$	(494	)	$	(491	)
Money Pool Balance (included in cash and cash equivalents)	$	65		$	—

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

(b) Included in Notes payable due to subsidiary companies.

(8)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 New Jersey Board of Public Utilities 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, 2014. 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. As further described in Note (10), “Debt,” to the consolidated financial statements of Pepco Holdings, PHI, Pepco, DPL and ACE have restrictions on total indebtedness in relation to total capitalization under the credit facility.

PHI had approximately $565 million and $595 million of retained earnings free of restrictions at December 31, 2014 and 2013, respectively. These amounts represent the total retained earnings balances at those dates. The amount of restricted net assets for PHI’s consolidated subsidiaries at December 31, 2014 is $2,547 million.

356

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, 2014 Allowance for uncollectible accounts—customer and other accounts receivable	$	38	$	46	$	9	$	(53	)	$	40
Year Ended December 31, 2013 Allowance for uncollectible accounts—customer and other accounts receivable	$	34	$	37	$	5	$	(38	)	$	38
Year Ended December 31, 2012 Allowance for uncollectible accounts—customer and other accounts receivable	$	43	$	35	$	8	$	(52	)	$	34

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

Potomac Electric Power Company

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, 2014 Allowance for uncollectible accounts—customer and other accounts receivable	$	16	$	17	$	2	$	(19	)	$	16
Year Ended December 31, 2013 Allowance for uncollectible accounts—customer and other accounts receivable	$	13	$	15	$	1	$	(13	)	$	16
Year Ended December 31, 2012 Allowance for uncollectible accounts—customer and other accounts receivable	$	18	$	13	$	2	$	(20	)	$	13

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

357

Delmarva Power & Light Company

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, 2014 Allowance for uncollectible accounts—customer and other accounts receivable	$	12	$	13	$	4	$	(18	)	$	11
Year Ended December 31, 2013 Allowance for uncollectible accounts—customer and other accounts receivable	$	9	$	11	$	1	$	(9	)	$	12
Year Ended December 31, 2012 Allowance for uncollectible accounts—customer and other accounts receivable	$	12	$	11	$	3	$	(17	)	$	9

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

Atlantic City Electric Company

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, 2014 Allowance for uncollectible accounts—customer and other accounts receivable	$	10	$	12	$	3	$	(16	)	$	9
Year Ended December 31, 2013 Allowance for uncollectible accounts—customer and other accounts receivable	$	11	$	11	$	3	$	(15	)	$	10
Year Ended December 31, 2012 Allowance for uncollectible accounts—customer and other accounts receivable	$	12	$	12	$	3	$	(16	)	$	11

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

358

3.EXHIBITS

The documents listed below are being filed or furnished on behalf of PHI, Pepco, DPL and/or ACE, as indicated. The warranties, representations and covenants contained in any of the agreements included or incorporated by reference herein or which appear as exhibits hereto should not be relied upon by buyers, sellers or holders of PHI’s or its subsidiaries’ securities and are not intended as warranties, representations or covenants to any individual or entity except as specifically set forth in such agreement.

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
2.1	PHI Pepco DPL ACE	Agreement and Plan of Merger, dated as of April 29, 2014, among PHI, Exelon Corporation and Purple Acquisition Corp.	Exh. 2.1 to PHI’s Form 8-K, 4/30/14.
2.2	PHI Pepco DPL ACE	Amended and Restated Agreement and Plan of Merger, dated as of July 18, 2014, among PHI, Exelon Corporation and Purple Acquisition Corp.	Exh. 2.1 to PHI’s Form 8-K, 7/21/14.
2.3	PHI	Subscription Agreement, dated as of April 29, 2014, between PHI and Exelon Corporation	Exh. 2.2 to PHI’s Form 8-K, 4/30/14.
3.1	PHI	Restated Certificate of Incorporation (filed in Delaware 6/2/05)	Exh. 3.1 to PHI’s Form 10-K, 3/13/06.
3.2	PHI	Certificate of Designation for Series A Non-Voting Non-Convertible Preferred Stock (filed in Delaware 4/30/14)	Exh. 3.1 to PHI’s Form 8-K, 4/30/14.
3.3	Pepco	Restated Articles of Incorporation and Articles of Restatement (as filed in the District of Columbia)	Exh. 3.1 to Pepco’s Form 10-Q, 5/5/06.
3.4	Pepco	Restated Articles of Incorporation and Articles of Restatement (as filed in Virginia)	Exh. 3.3 to PHI’s Form 10-Q, 11/4/11.
3.5	DPL	Articles of Restatement of Certificate and Articles of Incorporation (filed in Delaware and Virginia 02/22/07)	Exh. 3.3 to DPL’s Form 10-K, 3/1/07.
3.6	ACE	Restated Certificate of Incorporation (filed in New Jersey 8/09/02)	Exh. B.8.1 to PHI’s Amendment No. 1 to Form U5B, 2/13/03.
3.7	PHI	Bylaws	Exh. 3.6 to PHI’s Form 10-K, 3/1/13.
3.8	Pepco	Bylaws	Exh. 3.2 to Pepco’s Form 10-Q, 5/5/06.
3.9	DPL	Bylaws	Exh. 3.2.1 to DPL’s Form 10-Q, 5/9/05.
3.10	ACE	Bylaws	Exh. 3.2.2 to ACE’s Form 10-Q, 5/9/05.

359

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
4.1	PHI Pepco	Mortgage and Deed of Trust, dated July 1, 1936, of Pepco to The Bank of New York Mellon as successor trustee, securing First Mortgage Bonds of Pepco, and Supplemental Indenture dated July 1, 1936	Exh. B-4 to First Amendment, 6/19/36, to Pepco’s Registration Statement No. 2-2232.
		Supplemental Indentures, to the aforesaid Mortgage and Deed of Trust, dated as of
		December 10, 1939	Exh. B to Pepco’s Form 8-K, 1/3/40.
		July 15, 1942	Exh. B-1 to Amendment No. 2, 8/24/42, and B-3 to Post-Effective Amendment, 8/31/42, to Pepco’s Registration Statement No. 2-5032.
		October 15, 1947	Exh. A to Pepco’s Form 8-K, 12/8/47.
		December 31, 1948	Exh. A-2 to Pepco’s Form 10-K, 4/13/49.
		December 31, 1949	Exh. (a)-1 to Pepco’s Form 8-K, 2/8/50.
		February 15, 1951	Exh. (a) to Pepco’s Form 8-K, 3/9/51.
		February 16, 1953	Exh. (a)-1 to Pepco’s Form 8-K, 3/5/53.
		March 15, 1954 and March 15, 1955	Exh. 4-B to Pepco’s Registration Statement No. 2-11627, 5/2/55.
		March 15, 1956	Exh. C to Pepco’s Form 10-K, 4/4/56.
		April 1, 1957	Exh. 4-B to Pepco’s Registration Statement No. 2-13884, 2/5/58.
		May 1, 1958	Exh. 2-B to Pepco’s Registration Statement No. 2-14518, 11/10/58.
		May 1, 1959	Exh. 4-B to Amendment No. 1, 5/13/59, to Pepco’s Registration Statement No. 2-15027.
		May 2, 1960	Exh. 2-B to Pepco’s Registration Statement No. 2-17286, 11/9/60.
		April 3, 1961	Exh. A-1 to Pepco’s Form 10-K, 4/24/61.

360

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		May 1, 1962	Exh. 2-B to Pepco’s Registration Statement No. 2-21037, 1/25/63.
		May 1, 1963	Exh. 4-B to Pepco’s Registration Statement No. 2-21961, 12/19/63.
		April 23, 1964	Exh. 2-B to Pepco’s Registration Statement No. 2-22344, 4/24/64.
		May 3, 1965	Exh. 2-B to Pepco’s Registration Statement No. 2-24655, 3/16/66.
		June 1, 1966	Exh. 1 to Pepco’s Form 10-K, 4/11/67.
		April 28, 1967	Exh. 2-B to Post-Effective Amendment No. 1 to Pepco’s Registration Statement No. 2-26356, 5/3/67.
		July 3, 1967	Exh. 2-B to Pepco’s Registration Statement No. 2-28080, 1/25/68.
		May 1, 1968	Exh. 2-B to Pepco’s Registration Statement No. 2-31896, 2/28/69.
		June 16, 1969	Exh. 2-B to Pepco’s Registration Statement No. 2-36094, 1/27/70.
		May 15, 1970	Exh. 2-B to Pepco’s Registration Statement No. 2-38038, 7/27/70.
		September 1, 1971	Exh. 2-C to Pepco’s Registration Statement No. 2-45591, 9/1/72.
		June 17, 1981	Exh. 2 to Amendment No. 1 to Pepco’s Form 8-A, 6/18/81.
		November 1, 1985	Exh. 2B to Pepco’s Form 8-A, 11/1/85.
		September 16, 1987	Exh. 4-B to Pepco’s Registration Statement No. 33-18229, 10/30/87.
		May 1, 1989	Exh. 4-C to Pepco’s Registration Statement No. 33-29382, 6/16/89.
		May 21, 1991	Exh. 4 to Pepco’s Form 10-K, 3/27/92.

361

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		May 7, 1992	Exh. 4 to Pepco’s Form 10-K, 3/26/93.
		September 1, 1992	Exh. 4 to Pepco’s Form 10-K, 3/26/93.
		November 1, 1992	Exh. 4 to Pepco’s Form 10-K, 3/26/93.
		July 1, 1993	Exh. 4.4 to Pepco’s Registration Statement No. 33-49973, 8/11/93.
		February 10, 1994	Exh. 4 to Pepco’s Form 10-K, 3/25/94.
		February 11, 1994	Exh. 4 to Pepco’s Form 10-K, 3/25/94.
		October 2, 1997	Exh. 4 to Pepco’s Form 10-K, 3/26/98.
		November 17, 2003	Exhibit 4.1 to Pepco’s Form 10-K, 3/11/04.
		March 16, 2004	Exh. 4.3 to Pepco’s Form 8-K, 3/23/04.
		May 24, 2005	Exh. 4.2 to Pepco’s Form 8-K, 5/26/05.
		April 1, 2006	Exh. 4.1 to Pepco’s Form 8-K, 4/17/06.
		November 13, 2007	Exh. 4.2 to Pepco’s Form 8-K, 11/15/07.
		March 24, 2008	Exh. 4.1 to Pepco’s Form 8-K, 3/28/08.
		December 3, 2008	Exh. 4.2 to Pepco’s Form 8-K, 12/8/08.
		March 28, 2012	Exh. 4.2 to Pepco’s Form 8-K, 3/29/12.
		March 11, 2013	Exh. 4.2 to Pepco’s Form 8-K, 3/12/13.
		November 14, 2013	Exh. 4.2 to Pepco’s Form 8-K, 11/15/13.
		March 11, 2014	Exh. 4.2 to Pepco’s Form 8-K, 3/12/14.
4.2	PHI Pepco	Indenture, dated as of July 28, 1989, between Pepco and The Bank of New York Mellon, Trustee, with respect to Pepco’s Medium-Term Note Program	Exh. 4 to Pepco’s Form 8-K, 6/21/90.
4.3	PHI Pepco	Senior Note Indenture, dated November 17, 2003 between Pepco and The Bank of New York Mellon	Exh. 4.2 to Pepco’s Form 8-K, 11/21/03.

362

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		Supplemental Indenture, to the aforesaid Senior Note Indenture, dated March 3, 2008	Exh. 4.3 to Pepco’s Form 10-K, 3/2/09.
4.4	PHI DPL	Mortgage and Deed of Trust of Delaware Power & Light Company to The Bank of New York Mellon (ultimate successor to the New York Trust Company), as trustee, dated as of October 1, 1943 and copies of the First through Sixty-Eighth Supplemental Indentures thereto	Exh. 4-A to DPL’s Registration Statement No. 33-1763, 11/27/85.
		Sixty-Ninth Supplemental Indenture	Exh. 4-B to DPL’s Registration Statement No. 33-39756, 4/03/91.
		Seventieth through Seventy-Fourth Supplemental Indentures	Exhs. 4-B to DPL’s Registration Statement No. 33-24955, 10/13/88.
		Seventy-Fifth through Seventy-Seventh Supplemental Indentures	Exhs. 4-D, 4-E and 4-F to DPL’s Registration Statement No. 33-39756, 4/03/91.
		Seventy-Eighth and Seventy-Ninth Supplemental Indentures	Exhs. 4-E and 4-F to DPL’s Registration Statement No. 33-46892, 4/1/92.
		Eightieth Supplemental Indenture	Exh. 4 to DPL’s Registration Statement No. 33-49750, 7/17/92.
		Eighty-First Supplemental Indenture	Exh. 4-G to DPL’s Registration Statement No. 33-57652, 1/29/93.
		Eighty-Second Supplemental Indenture	Exh. 4-H to DPL’s Registration Statement No. 33-63582, 5/28/93.
		Eighty-Third Supplemental Indenture	Exh. 99 to DPL’s Registration Statement No. 33-50453, 10/1/93.
		Eighty-Fourth through Eighty-Eighth Supplemental Indentures	Exhs. 4-J, 4-K, 4-L, 4-M and 4-N to DPL’s Registration Statement No. 33-53855, 1/30/95.
		Eighty-Ninth and Ninetieth Supplemental Indentures	Exhs. 4-K and 4-L to DPL’s Registration Statement No. 333-00505, 1/29/96.
		Ninety-First Supplemental Indenture	Exh. 4.L to DPL’s Registration Statement No.333-24059, 3/27/97.
		Ninety-Second Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.

363

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		Ninety-Third Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		Ninety-Fourth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		Ninety-Fifth Supplemental Indenture	Exh. 4-K to DPL’s Post Effective Amendment No. 1 to Registration Statement No. 333-145691-02, 11/18/08.
		Ninety-Sixth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		Ninety-Seventh Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		Ninety-Eighth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		Ninety-Ninth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		One Hundredth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		One Hundred and First Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		One Hundred and Second Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		One Hundred and Third Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		One Hundred and Fourth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		One Hundred and Fifth Supplemental Indenture	Exh. 4.4 to DPL’s Form 8-K, 10/1/09.
		One Hundred and Sixth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/25/11.
		One Hundred and Seventh Supplemental Indenture	Exh. 4.2 to DPL’s Form 10-Q, 8/3/11.
		One Hundred and Eighth Supplemental Indenture	Exh. 4.2 to DPL’s Form 8-K, 6/3/11.
		One Hundred and Ninth Supplemental Indenture	Exh. 4.3 to DPL’s Form 10-Q, 8/7/12.
		One Hundred and Tenth Supplemental Indenture	Exh. 4.2 to DPL’s Form 8-K, 6/20/12.
		One Hundred and Eleventh Supplemental Indenture	Exh. 4.1 to DPL’s Form 10-Q, 8/6/13.
		One Hundred and Twelfth Supplemental Indenture	Exh. 4.2 to DPL’s Form 8-K, 11/8/13.
		One Hundred and Thirteenth Supplemental Indenture	Filed herewith.

364

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		One Hundred and Fourteenth Supplemental Indenture	Exh. 4.3 to DPL’s Form 8-K, 6/3/14.
4.5	PHI DPL	Indenture between DPL and The Bank of New York Mellon Trust Company, N.A. (ultimate successor to Manufacturers Hanover Trust Company), as trustee, dated as of November 1, 1988	Exh. No. 4-G to DPL’s Registration Statement No. 33-46892, 4/1/92.
4.6	PHI ACE	Mortgage and Deed of Trust, dated January 15, 1937, between ACE and The Bank of New York Mellon (formerly Irving Trust Company), as trustee	Exh. 2(a) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		Supplemental Indentures, to the aforesaid Mortgage and Deed of Trust, dated as of -
		June 1, 1949	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		July 1, 1950	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		November 1, 1950	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		March 1, 1952	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		January 1, 1953	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		March 1, 1954	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		March 1, 1955	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		January 1, 1957	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		April 1, 1958	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		April 1, 1959	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		March 1, 1961	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.

365

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		July 1, 1962	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		March 1, 1963	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		February 1, 1966	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		April 1, 1970	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		September 1, 1970	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		May 1, 1971	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		April 1, 1972	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		June 1, 1973	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		January 1, 1975	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		May 1, 1975	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		December 1, 1976	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		January 1, 1980	Exh. 4(e) to ACE’s Form 10-K, 3/25/81.
		May 1, 1981	Exh. 4(a) to ACE’s Form 10-Q, 8/10/81.
		November 1, 1983	Exh. 4(d) to ACE’s Form 10-K, 3/30/84.
		April 15, 1984	Exh. 4(a) to ACE’s Form 10-Q, 5/14/84.
		July 15, 1984	Exh. 4(a) to ACE’s Form 10-Q, 8/13/84.
		October 1, 1985	Exh. 4 to ACE’s Form 10-Q, 11/12/85.

366

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		May 1, 1986	Exh. 4 to ACE’s Form 10-Q, 5/12/86.
		July 15, 1987	Exh. 4(d) to ACE’s Form 10-K, 3/28/88.
		October 1, 1989	Exh. 4(a) to ACE’s Form 10-Q for quarter ended 9/30/89.
		March 1, 1991	Exh. 4(d)(1) to ACE’s Form 10-K, 3/28/91.
		May 1, 1992	Exh. 4(b) to ACE’s Registration Statement No. 33-49279, 1/6/93.
		January 1, 1993	Exh. 4.05(hh) to ACE’s Registration Statement No. 333-108861, 9/17/03.
		August 1, 1993	Exh. 4(a) to ACE’s Form 10-Q, 11/12/93.
		September 1, 1993	Exh. 4(b) to ACE’s Form 10-Q, 11/12/93.
		November 1, 1993	Exh. 4(c)(1) to ACE’s Form 10-K, 3/29/94.
		June 1, 1994	Exh. 4(a) to ACE’s Form 10-Q, 8/14/94.
		October 1, 1994	Exh. 4(a) to ACE’s Form 10-Q, 11/14/94.
		November 1, 1994	Exh. 4(c)(1) to ACE’s Form 10-K, 3/21/95.
		March 1, 1997	Exh. 4(b) to ACE’s Form 8-K, 3/24/97.
		April 1, 2004	Exh. 4.3 to ACE’s Form 8-K, 4/6/04.
		August 10, 2004	Exh. 4 to PHI’s Form 10-Q, 11/8/04.
		March 8, 2006	Exh. 4 to ACE’s Form8-K, 3/17/06.
		November 6, 2008	Exh. 4.2 to ACE’s Form 8-K, 11/10/08.
		March 29, 2011	Exh. 4.2 to ACE’s Form 8-K, 4/1/11.
		August 18, 2014	Exh. 4.2 to ACE’s Form 8-K, 8/19/14.
4.7	PHI ACE	Indenture, dated as of March 1, 1997 between ACE and The Bank of New York Mellon, as trustee	Exh. 4(e) to ACE’s Form 8-K, 3/24/97.

367

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
4.8	PHI ACE	Senior Note Indenture, dated as of April 1, 2004, with The Bank of New York Mellon, as trustee	Exh. 4.2 to ACE’s Form 8-K, 4/6/04.
4.9	PHI ACE	Indenture, dated as of December 19, 2002 between Atlantic City Electric Transition Funding LLC (ACE Funding) and The Bank of New York Mellon, as trustee	Exh. 4.1 to ACE Funding’s Form 8-K, 12/23/02.
4.10	PHI ACE	2002-1 Series Supplement, dated as of December 19, 2002 between ACE Funding and The Bank of New York Mellon, as trustee	Exh. 4.2 to ACE Funding’s Form 8-K, 12/23/02.
4.11	PHI ACE	2003-1 Series Supplement, dated as of December 23, 2003 between ACE Funding and The Bank of New York Mellon, as trustee	Exh. 4.2 to ACE Funding’s Form 8-K, 12/23/03.
4.12	PHI	Indenture, dated September 6, 2002, between PHI and The Bank of New York Mellon, as trustee	Exh. 4.03 to PHI’s Registration Statement No. 333-100478, 10/10/02.
4.13	PHI Pepco DPL ACE	Corporate Commercial Paper – Master Note	Exh. 4.13 to PHI’s Form 10-K, 2/24/12.
4.14	PHI	Certificate of Series A Non-Voting Non-Convertible Preferred Stock	Exh. 4.1 to PHI’s Form 8-K, 4/30/14.
10.1	ACE	Bondable Transition Property Sale Agreement, dated as of December 19, 2002, between ACE Funding and ACE	Exh. 10.1 to ACE Funding’s Form 8-K, 12/23/02.
10.2	ACE	Bondable Transition Property Servicing Agreement, dated as of December 19, 2002, between ACE Funding and ACE	Exh. 10.2 to ACE Funding’s Form 8-K, 12/23/02.
10.3	PHI	Purchase Agreement, dated as of April 20, 2010, by and among PHI, Conectiv, LLC, Conectiv Energy Holding Company, LLC and New Development Holdings, LLC	Exh. 2.1 to PHI’s Form 8-K, 7/8/10.
10.4	Pepco	Purchase Agreement, dated March 11, 2013, among Pepco and Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Scotia Capital (USA) Inc., as representatives of the several underwriters named therein	Exh. 1.1 to Pepco’s Form 8-K, 3/12/13.
10.5	Pepco	Purchase Agreement, dated November 14, 2013, among Pepco and Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Scotia Capital (USA) Inc., as representatives of the several underwriters named therein	Exh. 1.1 to Pepco’s Form 8-K, 11/15/13.

368

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.6	Pepco	Purchase Agreement, dated March 11, 2014, among Pepco and J.P. Morgan Securities LLC, RBS Securities Inc. and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein	Exh. 1.1 to Pepco’s Form 8-K, 3/12/14.
10.7	DPL	Purchase Agreement, dated November 7, 2013, among DPL and Citigroup Global Markets Inc., RBS Securities Inc., and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein	Exh. 1.1 to DPL’s Form 8-K, 11/8/13.
10.8	DPL	Purchase Agreement, dated June 2, 2014, among DPL, Morgan Stanley & Co. LLC and SunTrust Robinson Humphrey, Inc., as representatives of the several underwriters named therein	Exh. 1.1 to DPL’s Form 8-K, 6/3/14.
10.9	ACE	Purchase Agreement, dated August 18, 2014, among ACE, and each of Barclays Capital Inc. and KeyBanc Capital Markets Inc., as representatives of the several underwriters named therein	Exh. 1.1 to ACE’s Form 8-K, 8/19/14.
10.10	ACE	$100,000,000 Term Loan Agreement by and among ACE, KeyBank National Association, as Administrative Agent, SunTrust Bank, as Documentation Agent, and the Lenders Party Thereto, dated May 10, 2013	Exh. 10 to ACE’s Form 8-K, 5/10/13.
10.11	PHI	$250,000,000 Term Loan Agreement by and among PHI, JPMorgan Chase Bank, N.A., as Administrative Agent, The Bank of Nova Scotia, as Documentation Agent, and the Lenders Party Thereto, dated March 28, 2013	Exh. 10 to PHI’s Form 8-K, 3/28/13.
10.12	PHI Pepco DPL ACE	Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among PHI, Pepco, DPL and ACE, the lenders party thereto, Wells Fargo Bank, National Association, as agent, issuer and swingline lender, Bank of America, N.A., as syndication agent and issuer, The Royal Bank of Scotland plc and Citicorp USA, Inc., as co-documentation agents, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner and Smith Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global Markets Inc. and RBS Securities, Inc. as passive joint lead arrangers and joint book runners	Exh. 10.1 to PHI’s Form 10-Q, 8/3/11.

369

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.12.1	PHI Pepco DPL ACE	First Amendment, dated as of August 2, 2012, to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among PHI, Pepco, DPL and ACE, the various financial institutions party thereto, Wells Fargo Bank, National Association, as agent, issuer of letters of credit and swingline lender, Bank of America, N.A., as syndication agent and issuer of letters of credit, and The Royal Bank of Scotland plc and Citibank, N.A., as co-documentation agents	Exh. 10.25.1 to PHI’s Form 10-K, 3/1/13.
10.12.2	PHI Pepco DPL ACE	Amendment and Consent to Second Amended and Restated Credit Agreement, dated as of May 20, 2014, by and among PHI, Pepco, DPL, ACE, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association.	Exh. 10.1 to PHI’s Form 8-K, 5/20/14.
10.13	DPL	Reoffering Agreement, dated May 18, 2011, by and among DPL and Morgan Stanley & Co. Incorporated, as remarketing agent, and Morgan Stanley & Co. Incorporated, as underwriter	Exh. 1.1 to DPL’s Form 8-K, 6/3/11.
10.14	PHI Pepco DPL ACE	Form of Issuing and Paying Agency Agreement, dated August 28, 2014, between Bank of America, National Association, and each Reporting Company	Filed herewith.
10.15	PHI	Employment Agreement of Joseph M. Rigby, dated December 20, 2011 (including forms of Restricted Stock Unit Award Agreements contained therein)*	Exh. 10 to PHI’s Form 8-K, 12/27/11.
10.15.1	PHI	Amendment to the 2013 Performance-Based Restricted Stock Unit Award Agreement, effective as of October 25, 2013*	Exh. 10.2 to PHI’s Form 8-K, 10/25/13.
10.16	PHI	Employment Extension Agreement, by and between PHI and Joseph M. Rigby, effective April 29, 2014*	Exh. 10.1 to PHI’s Form 8-K, 5/2/14.
10.17	PHI	Letter Agreement between Pepco Holdings, Inc. and Frederick J. Boyle*	Exh. 10 to PHI’s Form 8-K, 3/26/12.
10.18	PHI	Employment Agreement, dated September 7, 2012, by and between PHI and Kevin C. Fitzgerald (including forms of Restricted Stock Unit Award Agreements contained therein)*	Exh. 10.1 to PHI’s Form 10-Q, 11/6/12.
10.19	PHI	Pepco Holdings, Inc. Amended and Restated Annual Executive Incentive Compensation Plan*	Exh. 10.30.1 to PHI’s Form 10-K, 2/24/12.

370

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.19.1	PHI	Amendment to Pepco Holdings, Inc. Amended and Restated Annual Executive Incentive Compensation Plan*	Filed herewith.
10.20	PHI	Pepco Holdings, Inc. Long-Term Incentive Plan (as amended and restated)*	Exh. 10.5 to PHI’s Form 10-K, 3/2/09.
10.20.1	PHI	Amendment to the Pepco Holdings, Inc. Long-Term Incentive Plan*	Exh. 10.2.1 to PHI’s Form 10-K, 2/24/12.
10.21	PHI	Pepco Holdings, Inc. 2012 Long-Term Incentive Plan*	Exh. 10.10 to PHI’s Form 10-K, 3/1/13.
10.21.1	PHI	Amendment to Pepco Holdings, Inc. 2012 Long-Term Incentive Plan, effective as of March 28, 2014*	Exh. 10.2.2 to PHI’s Form 10-Q, 5/7/14.
10.21.2	PHI	Second Amendment to Pepco Holdings, Inc. 2012 Long-Term Incentive Plan*	Filed herewith.
10.22	PHI	Form of Restricted Stock Unit Agreement (Director Award) under the PHI 2012 Long-Term Incentive Plan*	Exh. 10.4 to PHI’s Form 10-Q, 8/7/12.
10.23	PHI	Form of 2013 Restricted Stock Unit Agreement (Time-Vested) under the PHI 2012 Long-Term Incentive Plan*	Exh. 10.50 to PHI’s Form 10-K, 3/1/13.
10.24	PHI	Form of 2014 Restricted Stock Unit Agreement (Time-Vested) under the PHI 2012 Long-Term Incentive Plan*	Exh. 10.3 to PHI’s Form 10-Q, 5/7/14.
10.25	PHI	Form of 2013 Restricted Stock Unit Agreement (Time-Vested) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby*	Exh. 10.3 to PHI’s Form 10-Q, 5/2/13.
10.26	PHI	Form of 2014 Restricted Stock Unit Agreement (Time-Vested) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby*	Exh. 10.4 to PHI’s Form 10-Q, 5/7/14.
10.27	PHI	Form of 2013 Restricted Stock Unit Agreement (Time-Vested) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald*	Exh. 10.4 to PHI’s Form 10-Q, 5/2/13.
10.28	PHI	Form of 2014 Restricted Stock Unit Agreement (Time-Vested) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald*	Exh. 10.5 to PHI’s Form 10-Q, 5/7/14.
10.29	PHI	Form of 2013 Restricted Stock Unit Agreement (Performance-Based/162(m)) under the PHI 2012 Long-Term Incentive Plan*	Exh. 10.51 to PHI’s Form 10-K, 3/1/13.
10.30	PHI	Form of 2014 Restricted Stock Unit Agreement (Performance-Based/162(m)) under the PHI 2012 Long-Term Incentive Plan*	Exh. 10.6 to PHI’s Form 10-Q, 5/7/14.

371

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.31	PHI	Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby*	Exh. 10.8 to PHI’s Form 10-Q, 5/2/13.
10.32	PHI	Form of 2014 Restricted Stock Unit Agreement (Performance-Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby*	Exh. 10.7 to PHI’s Form 10-Q, 5/7/14.
10.33	PHI	Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald*	Exh. 10.9 to PHI’s Form 10-Q, 5/2/13.
10.34	PHI	Form of 2014 Restricted Stock Unit Agreement (Performance-Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald*	Exh. 10.8 to PHI’s Form 10-Q, 5/7/14.
10.35	PHI	Form of 2013 Restricted Stock Unit Agreement (Performance-Based/Non-162(m)) under the PHI 2012 Long-Term Incentive Plan*	Exh. 10.52 to PHI’s Form 10-K, 3/1/13.
10.36	PHI	Form of 2014 Restricted Stock Unit Agreement (Performance-Based/Non-162(m)) under the PHI 2012 Long-Term Incentive Plan*	Exh. 10.9 to PHI’s Form 10-Q, 5/7/14.
10.37	PHI	Form of Restricted Stock Award Agreement (Performance-Based/162(m)) under the 2012 Long-Term Incentive Plan*	Exh. 10.2 to PHI’s Form 10-Q, 10/31/14.
10.38	PHI	Pepco Holdings, Inc. Second Revised and Restated Executive and Director Deferred Compensation Plan*	Exh. 10.31.1 to PHI’s Form 10-K, 2/24/12.
10.39	PHI Pepco	Potomac Electric Power Company Director and Executive Deferred Compensation Plan*	Exh. 10.22 to PHI’s Form 10-K, 3/28/03.
10.40	PHI	Conectiv Deferred Compensation Plan*	Exh. 10.1 to PHI’s Form 10-Q, 8/6/04.
10.41	PHI	Form of 2014 Non-Management Director Compensation Election Agreement*	Exh. 10.42 to PHI’s Form 10-K, 2/28/14.
10.42	PHI	Form of 2015 Non-Management Director Compensation Election Agreement*	Filed herewith.
10.43	PHI	Form of 2014 Executive and Director Deferred Compensation Plan Executive Deferral Agreement*	Exh. 10.43 to PHI’s Form 10-K, 2/28/14.
10.44	PHI	Form of 2015 Executive and Director Deferred Compensation Plan Executive Deferral Agreement*	Filed herewith.
10.45	PHI	Non-Management Director Compensation Arrangements*	Exh. 10.13 to PHI’s Form 10-K, 3/1/13.

372

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.46	PHI Pepco	Change-in-Control Severance Plan for Certain Executive Employees*	Exh. 10.25 to PHI’s Form10-K, 3/2/09.
10.46.1	PHI Pepco	Amended and Restated Change in Control / Severance Plan for Certain Executive Employees*	Exh. 10 to PHI’s Form8-K, 7/31/13.
10.47	PHI	Pepco Holdings, Inc. Combined Executive Retirement Plan*	Exh. 10.28 to PHI’s Form10-K, 3/2/09.
10.47.1	PHI	Amendment to the Pepco Holdings, Inc. Combined Executive Retirement Plan*	Exh. 10.3 to PHI’s Form 10-Q, 8/3/11.
10.48	PHI	The Pepco Holdings, Inc. 2011 Supplemental Executive Retirement Plan*	Exh. 10.2 to PHI’s Form 10-Q, 8/3/11.
10.49	PHI DPL ACE	Conectiv Supplemental Executive Retirement Plan*	Exh. 10.10 to PHI’s Form 10-K, 3/2/09.
10.49.1	PHI DPL ACE	Amendment to the Conectiv Supplemental Executive Retirement Plan*	Exh. 10.4 to PHI’s Form 10-Q, 8/3/11.
10.50	PHI	PHI Named Executive Officer 2014 Compensation Determinations*	Exh. 10.51 to PHI’s Form 10-K, 2/28/14.
10.51	PHI	PHI Named Executive Officer 2015 Compensation Determinations and Other Compensation Information*	Filed herewith.
10.52	PHI	Restricted Stock Award Agreement, by and between PHI and Joseph M. Rigby, effective April 30, 2014 (Immediate Vesting) *	Exh. 10.2 to PHI’s Form 8-K, 5/2/14.
10.53	PHI	Restricted Stock Award Agreement, by and between PHI and Joseph M. Rigby, effective April 30, 2014*	Exh. 10.3 to PHI’s Form 8-K, 5/2/14.
10.54	PHI	Pepco Holdings, Inc. 2014 Management Employee Severance Plan*	Exh. 10.4 to PHI’s Form 8-K, 5/2/14.
10.55	Pepco	Asset Purchase and Sale Agreement for Generating Plants and Related Assets, dated as of June 7, 2000, by and between Pepco and Southern Energy, Inc.	Exh. 10 to Pepco’s Form 8-K, 6/13/00.
10.55.1	Pepco	Amendment No. 1 to the Asset Purchase and Sale Agreement for Generating Plants and Related Assets, dated September 18, 2000, by and between Pepco and Southern Energy, Inc.	Exh. 10.1 to Pepco’s Form 8-K, 12/9/00.
10.55.2	Pepco	Amendment No. 2 to the Asset Purchase and Sale Agreement for Generating Plants and Related Assets, dated December 19, 2000, by and between Pepco and Southern Energy, Inc.	Exh. 10.2 to Pepco’s Form 8-K, 12/9/00.

373

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
11	PHI	Statements Re: Computation of Earnings Per Common Share	**
12.1	PHI	Statements Re: Computation of Ratios	Filed herewith.
12.2	Pepco	Statements Re: Computation of Ratios	Filed herewith.
12.3	DPL	Statements Re: Computation of Ratios	Filed herewith.
12.4	ACE	Statements Re: Computation of Ratios	Filed herewith.
21	PHI	Subsidiaries of the Registrant	Filed herewith.
23.1	PHI	Consent of Independent Registered Public Accounting Firm	Filed herewith.
23.2	Pepco	Consent of Independent Registered Public Accounting Firm	Filed herewith.
23.3	DPL	Consent of Independent Registered Public Accounting Firm	Filed herewith.
23.4	ACE	Consent of Independent Registered Public Accounting Firm	Filed herewith.
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
99	PHI	Audit Committee Policy on the Approval of Services Provided By the Independent Auditor	Filed herewith.
101. INS	PHI Pepco DPL ACE	XBRL Instance Document	Filed herewith.
101. SCH	PHI Pepco DPL ACE	XBRL Taxonomy Extension Schema Document	Filed herewith.
101. CAL	PHI Pepco DPL ACE	XBRL Taxonomy Extension Calculation Linkbase Document	Filed herewith.

374

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
101. DEF	PHI Pepco DPL ACE	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith.
101. LAB	PHI Pepco DPL ACE	XBRL Taxonomy Extension Label Linkbase Document	Filed herewith.
101. PRE	PHI Pepco DPL ACE	XBRL Taxonomy Extension Presentation Linkbase Document	Filed herewith.

* Management contract or compensatory plan or arrangement.

** The information required by this Exhibit is set forth in Note (12), “Stock-Based Compensation, Dividend Restrictions and Calculations of Earnings Per Share of Common Stock,” of the consolidated financial statements of Pepco Holdings, Inc. included in Part II, Item 8 “Financial Statements and Supplementary Data” of this Form 10-K.

Regulation S-K Item 10(d) requires registrants to identify the physical location, by SEC file number reference, of all documents incorporated by reference that are not included in a registration statement and have been on file with the SEC for more than five years. The SEC file number references for PHI and each of its subsidiaries that are currently registrants, Conectiv and ACE Funding are provided below:

Pepco Holdings, Inc. (File Nos. 001-31403 and 030-00359)

Potomac Electric Power Company (File No. 001-01072)

Delmarva Power & Light Company (File No. 001-01405)

Atlantic City Electric Company (File No. 001-03559)

Conectiv (File No. 001-13895)

Atlantic City Electric Transition Funding LLC (File No. 333-59558)

Certain instruments defining the rights of the holders of long-term debt of PHI, Pepco, DPL and ACE (including medium-term notes, unsecured notes, senior notes and tax-exempt financing instruments) have not been filed as exhibits in accordance with Regulation S-K Item 601(b)(4)(iii) because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis. Each of PHI, Pepco, DPL or ACE agrees to furnish to the SEC upon request a copy of any such instruments omitted by it.

375

INDEX TO FURNISHED EXHIBITS

The documents listed below are being furnished herewith:

Exhibit No.	Registrant(s)	Description of Exhibit
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350

(b) Exhibits.

The list of exhibits filed or furnished with this Form 10-K are set forth on the exhibit index appearing at the end of thisForm 10-K

376

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PEPCO HOLDINGS, INC.     (Registrant)
February 26, 2015	By	/s/ JOSEPH M. RIGBY
		Joseph M. Rigby   Chairman of the Board, President and   Chief Executive Officer
	POTOMAC ELECTRIC POWER COMPANY (Pepco)     (Registrant)
February 26, 2015	By	/s/ DAVID M. VELAZQUEZ
		David M. Velazquez,   President and Chief   Executive Officer
	DELMARVA POWER & LIGHT COMPANY (DPL)     (Registrant)
February 26, 2015	By	/s/ DAVID M. VELAZQUEZ
		David M. Velazquez,   President and Chief   Executive Officer
	ATLANTIC CITY ELECTRIC COMPANY (ACE)     (Registrant)
February 26, 2015	By	/s/ DAVID M. VELAZQUEZ
		David M. Velazquez,   President and Chief   Executive Officer

377

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the above named registrants and in the capacities and on the dates indicated:

/s/ JOSEPH M. RIGBY     Joseph M. Rigby	Chairman of the Board, President and Chief Executive Officer of Pepco Holdings, Director of Pepco, DPL and ACE (Principal Executive Officer of Pepco Holdings)	February 26, 2015
/s/ DAVID M. VELAZQUEZ     David M. Velazquez	President and Chief Executive Officer of Pepco, DPL and ACE, Director of Pepco and DPL (Principal Executive Officer of Pepco, DPL and ACE)	February 26, 2015
/s/ FRED BOYLE     Frederick J. Boyle	Senior Vice President and Chief Financial Officer of Pepco Holdings, Pepco, and DPL, Chief Financial Officer of ACE and Director of Pepco (Principal Financial Officer of Pepco Holdings, Pepco, DPL and ACE)	February 26, 2015
/s/ RONALD K. CLARK     Ronald K. Clark	Vice President and Controller of Pepco Holdings, Pepco and DPL and Controller of ACE (Principal Accounting Officer of Pepco Holdings, Pepco, DPL and ACE)	February 26, 2015

378

Signature	Title	Date
/s/ PAUL M. BARBAS	Director, Pepco Holdings	February 26, 2015
Paul M. Barbas
/s/ J.B. DUNN	Director, Pepco Holdings	February 26, 2015
Jack B. Dunn, IV
/s/ H. RUSSELL FRISBY, JR.	Director, Pepco Holdings	February 26, 2015
H. Russell Frisby, Jr.
/s/ T. C. GOLDEN	Director, Pepco Holdings	February 26, 2015
Terence C. Golden
/s/ PATRICK T. HARKER	Director, Pepco Holdings	February 26, 2015
Patrick T. Harker
/s/ BARBARA J. KRUMSIEK	Director, Pepco Holdings	February 26, 2015
Barbara J. Krumsiek
/s/ LAWRENCE C. NUSSDORF	Director, Pepco Holdings	February 26, 2015
Lawrence C. Nussdorf
/s/ PATRICIA A. OELRICH	Director, Pepco Holdings	February 26, 2015
Patricia A. Oelrich
/s/ LESTER P. SILVERMAN	Director, Pepco Holdings	February 26, 2015
Lester P. Silverman
/s/ KEVIN C. FITZGERALD	Director, Pepco and DPL	February 26, 2015
Kevin C. Fitzgerald
/s/ CHARLES R. DICKERSON	Director, Pepco	February 26, 2015
Charles R. Dickerson
/s/ WILLIAM M. GAUSMAN	Director, Pepco	February 26, 2015
William M. Gausman
/s/ MICHAEL J. SULLIVAN	Director, Pepco	February 26, 2015
Michael J. Sullivan

379

INDEX TO EXHIBITS FILED HEREWITH

Exhibit No.	Registrant(s)	Description of Exhibit
4.4	PHI DPL	One Hundred and Thirteenth Supplemental Indenture
10.14	PHI Pepco DPL ACE	Form of Issuing and Paying Agency Agreement, dated August 28, 2014, between Bank of America, National Association, and each Reporting Company
10.19.1	PHI	Amendment to Pepco Holdings, Inc. Amended and Restated Annual Executive Incentive Compensation Plan*
10.21.2	PHI	Second Amendment to Pepco Holdings, Inc. 2012 Long-Term Incentive Plan*
10.42	PHI	Form of 2015 Non-Management Director Compensation Election Agreement*
10.44	PHI	Form of 2015 Executive and Director Deferred Compensation Plan Executive Deferral Agreement*
10.51	PHI	PHI Named Executive Officer 2015 Compensation Determinations and Other Compensation Information*
12.1	PHI	Statements Re: Computation of Ratios
12.2	Pepco	Statements Re: Computation of Ratios
12.3	DPL	Statements Re: Computation of Ratios
12.4	ACE	Statements Re: Computation of Ratios
21	PHI	Subsidiaries of the Registrant
23.1	PHI	Consent of Independent Registered Public Accounting Firm
23.2	Pepco	Consent of Independent Registered Public Accounting Firm
23.3	DPL	Consent of Independent Registered Public Accounting Firm
23.4	ACE	Consent of Independent Registered Public Accounting Firm
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
99	PHI	Audit Committee Policy on the Approval of Services Provided By the Independent Auditor
101. INS	PHI Pepco DPL ACE	XBRL Instance Document

380

101. SCH	PHI Pepco DPL ACE	XBRL Taxonomy Extension Schema Document
101. CAL	PHI Pepco DPL ACE	XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF	PHI Pepco DPL ACE	XBRL Taxonomy Extension Definition Linkbase Document
101. LAB	PHI Pepco DPL ACE	XBRL Taxonomy Extension Label Linkbase Document
101. PRE	PHI Pepco DPL ACE	XBRL Taxonomy Extension Presentation Linkbase Document

* Management contract or compensatory plan or arrangement.

INDEX TO EXHIBITS FURNISHED HEREWITH

32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350

381