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, 20102011

Continued

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

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

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

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

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.

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).

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 the 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).x

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.

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

Pepco, DPL, and ACE meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 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.

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

Portions of the Pepco Holdings, Inc. definitive proxy statement for the 20112012 Annual Meeting of ShareholdersStockholders to be filed with the Securities and Exchange Commission on or about Marchwithin 120 days after December 31, 2011 are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

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.

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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 and by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding the intents, beliefs, estimates and current expectations of one or more Reporting Companies 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 Company’s 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 their subsidiaries’ control and may cause actual results to differ materially from those contained in forward-looking statements:

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

Any forward-looking statements speak only as to the date of this Form 10-K for each Reporting Company 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, nor can the impact of any such factor be assessed 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

Overview

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, to a lesser extent, the distribution and supply of natural gas (Power Delivery):gas:

Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI also provides energy efficiency and renewable energy services primarily to government and institutional customers. Pepco Energy Services is in the process of winding down its competitive electricity and natural gas retail supply business and preparing for the retirement of its two oil firedoil-fired generating facilities.

In addition, through Potomac Capital Investment Corporation (PCI), PHI holds investments in eightseveral cross-border energy leaseslease investments as described below under the heading “Other Business Operations.” PCI is no longer engaged in new investment activity.

The following chart shows, in simplified form, the corporate structure of PHI and its principal subsidiaries:

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

Pepco Holdings’ management has identified its operating segments at December 31, 20102011 as (i) Power Delivery, consisting of the operations of Pepco, DPL and ACE, engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas, (ii) Pepco Energy Services and (iii) Other Non-Regulated, consisting primarily of the operations of PCI. For financial information relating to PHI’s segments, see Note (5), “Segment Information,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.PHI.

Discontinued Operations

In April 2010, the Board of Directors approved a plan for the disposition of PHI’s competitive wholesale power generation, marketing and supply business, which had been conducted through subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv(Conectiv Energy). On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.64 billion. The disposition of Conectiv Energy’s remaining assets and businesses not included in the Calpine sale, including its load service supply contracts, energy hedging portfolio and certain tolling agreements, has been substantially completed. The operations of Conectiv Energy, which previously comprised a separate segment for financial reporting purposes, are being accounted for as a discontinued operation. For further information on the former Conectiv Energy segment and the disposition of its assets, operations and obligations, see Note (20), “Discontinued Operations,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.PHI.

Investor Information

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

Each of PHI, Pepco, DPL and ACE files reports with the Securities and Exchange Commission (SEC) under the Securities Exchange ActAct. Copies of 1934, as amended. Thethe 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 of the companiesReporting Company are made available free of charge on PHI’s internetInternet Web site as soon as reasonably practicable after such documents are electronically filed with or furnished to the Securities and Exchange Commission (SEC). TheseSEC. Copies of these reports may be found athttp://www.pepcoholdings.com/www.pepcoholdings.com/investors. The information contained on the web sites listed above is not a part of this Form 10-K, and any web site references are not intended to be made through active hyperlinks.

Business Strategy

PHI’s business strategy is to become a top-performing, regulated power delivery company focused on:

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To further its business strategy, PHI may examine transactions involving its existing businesses, including entering into joint ventures, disposing of businesses or making acquisitions. PHI also may refine components of its business strategy as it deems necessary or appropriate in response to business factors and conditions, including regulatory requirements.

Description of Business

Power Delivery

PHI’s primary business is Power Delivery. The Power Delivery business in 2011, 2010 and 2009, and 2008, respectively, produced 79%, 73%, and 67%, and 68%respectively, of PHI’s consolidated operating revenues and 81%78%, 78%81%, and 101%78%, respectively, of PHI’s consolidated operating income. None of PHI’s three utilities owns any electric generation facilities.

TheEach utility comprising Power Delivery business consists of the operations of Pepco, DPL and ACE, each of which is a regulated electric utility in the jurisdictions that compriseencompass its electricity distribution service territory.territory and is regulated by FERC for its electricity transmission facilities. DPL also is a regulated natural gas utility serving portions of Delaware. In the aggregate, the Power Delivery business distributes electricity to more than 1.8 million customers in the mid-Atlantic region and delivers natural gas to approximately 123,000124,000 customers in Delaware. None of PHI’s three utilities owns any electric generation facilities.

Distribution and Default Supply of Electricity

Pepco, DPL and ACE each 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, or across, the utility’s service territory. Distribution facilities carry electricity from the transmission facilities to the end-use customers located in the utility’s service territory.

Each companyutility is responsible for the distribution of electricity in its service territory, for which it is paid tariff rates established by the applicable local public service commissions. Each companyutility also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive retail supplier. The regulatory term for this default supply service is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. In this Form 10-K, these supply services are referred to generally as Default Electricity Supply.

Transmission of Electricity and Relationship with PJM

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 the mid-Atlantic portion of the United States and parts of the Midwest. Pepco, DPL and ACE each is a member of the PJM Regional Transmission Organization (PJM RTO), the regional transmission organization designated by the Federal Energy Regulatory Commission (FERC) to coordinate the movement of wholesale electricity within a region consisting of all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

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PJM, Interconnection, LLC (PJM), the FERC-approved independent grid operator, manages the transmission grid and the wholesale electricity market in the PJM RTO region. Any entity that wishes to have wholesale electricity delivered at any point within the PJM RTO region must obtain transmission services from PJM. In accordance with FERC-approved rules, Pepco, DPL, ACE and the other transmission-owning utilities in the region make their transmission facilities available to the PJM RTO, and PJM directs and controls the operation of these transmission facilities. For transmission services, transmission owners are paid rates proposed by the transmission owner and approved by FERC. 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 the PJM RTO region. The PJM Board of Managers reviews and approves each PJM regional transmission expansion plan, including whether to include new construction of transmission facilities proposed by PJM RTO members in the plan and, if so, the target in-service date for those facilities.

Regulation

The operations of PHI’s utility subsidiaries, including the rates they are permitted to charge customers for the distribution and transmission 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 follows:

Seasonality

The operating results of the Power Delivery segment 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 long standing practice by which the stateapplicable public service commissions set distribution rates based on a fixed charge per kilowatt-hour of electricity used by the customer. 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 thea result of the implementation of a bill stabilization adjustment mechanism (BSA)BSA for retail customers of Pepco and DPL in Maryland in June 2007 and for customers of Pepco in the District of Columbia in November 2009, distribution revenues 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. Distribution revenues are not decoupled for the distribution of electricity and natural gas by DPL in Delaware or 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.

Regulated Utility Subsidiaries

The following is a more detailed description of the business of each of PHI’s three regulated utility subsidiaries:

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Pepco

Pepco is engaged in the transmission, distribution and default supply of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.2 million. As of December 31, 2010,2011, Pepco distributed electricity to 787,000788,000 customers (of which 256,000257,000 were located in the District of Columbia and 531,000 were located in Maryland), as compared to 778,000787,000 customers as of December 31, 2010 (of which 256,000 were located in the District of Columbia and 531,000 were located in Maryland). As of December 31, 2009, Pepco distributed electricity to 778,000 customers (of which 252,000 were located in the District of Columbia and 526,000 were located in Maryland).

In 2011, Pepco distributed a total of 26,895,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 30% of the total megawatt hours were delivered to residential customers, 50% to commercial customers, and 20% to United States and District of Columbia government customers. In 2010, Pepco distributed a total of 27,665,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 30% of the total megawatt hours were delivereddistributed to residential customers, 49% to commercial customers, and 21% to United States and District of Columbia government customers. In 2009, Pepco distributed a total of 26,549,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 29% of the total megawatt hours were distributed to residential customers, 50% to commercial customers, and 21% to United States and District of Columbia government customers.

Pepco has been providing SOS in Maryland since July 2004. Pursuant to orders issued by the MPSC,Maryland Public Service Commission (MPSC), Pepco is obligated to provide SOS (i) to residential and small commercial customers until further action of the Maryland General Assembly and (ii) to medium-sized commercial customers through MayNovember 2012. Pepco purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with competitive bid procedures approved and supervised by the MPSC. Pepco also is obligated to provide Standard Offer Service, known as Hourly Priced Service (HPS), for large Maryland customers. Power to supply HPS customers is acquired in next-day and other short-term PJM RTO markets. Pepco is entitled to recover from its SOS customers the cost of acquiring the SOS supply, plus an administrative charge that is intended to allow Pepco to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of Maryland SOS customers in each customer class and the electricity used by such customers. Pepco is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Maryland service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

Pepco has been providing SOS in the District of Columbia since February 2005. Pursuant to orders issued by the DCPSC,District of Columbia Public Service Commission (DCPSC), Pepco is obligated to provide SOS to residential and small, medium-sized and large commercial customers indefinitely. Pepco purchases the electricity required to satisfy its SOS obligations from wholesale suppliers under contracts entered into in accordance with a competitive bid procedure approved and supervised by the DCPSC. Pepco is entitled to recover from its SOS customers the costs of acquiring the SOS supply, plus an administrative charge that is intended to allow Pepco to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of District of Columbia SOS customers in each customer class and the amount of electricity used by such customers. Pepco is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its District of Columbia service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

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For the year ended December 31, 2010, 46%2011, 43% of Pepco’s Maryland distribution sales (measured by megawatt hours) were to SOS customers, as compared to 46% and 49% in 2010 and 2009, respectively, and 29%27% of its District of Columbia distribution sales (measured by megawatt hours) were to SOS customers in 2010,2011, as compared to 29% and 31% in 2009.2010 and 2009, respectively.

DPL

DPL is engaged in the transmission, distribution and default supply of electricity in Delaware and portions of 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.

Distribution and Supply of Electricity

DPL’s electricity distribution service territory consists 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 has a population of approximately 1.31.4 million. As of December 31, 2010,2011, DPL delivered electricity to 501,000 customers (of which 301,000 were located in Delaware and 200,000 were located in Maryland), as compared to 500,000 customers as of December 31, 2010 (of which 301,000 were located in Delaware and 199,000 were located in Maryland), as compared to 498,000 customers as. As of December 31, 2009, DPL delivered electricity to 498,000 customers (of which 299,000 were located in Delaware and 199,000 were located in Maryland).

In 2010,2011, DPL distributed a total of 12,853,00012,688,000 megawatt hours of electricity to its customers, of which 66% was distributed within its Delaware territory and 34% within Maryland. Of this amount, 41% of the total megawatt hours were distributed to residential customers, 42% to commercial customers and 17% to industrial customers. In 2010, DPL distributed a total of 12,853,000 megawatt hours of electricity, of which 66% was distributed within its Delaware territory and 34% within Maryland. Of this amount, 42% of the total megawatt hours were distributed to residential customers, 41% to commercial customers and 17% to industrial customers. In 2009, DPL distributed a total of 12,494,000 megawatt hours of electricity, of which 67% was distributed within its Delaware territory and 33% within Maryland. Of this amount, 39% of the total megawatt hours were distributed to residential customers, 41% to commercial customers and 20% to industrial customers.

DPL has been providing SOS in Delaware since May 2006. Pursuant to orders issued by the DPSC,Delaware Public Service Commission (DPSC), DPL is obligated to provide SOS to residential, small commercial and industrial customers through May 2014, and to medium, large and general service commercial customers through May 2012. DPL purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with competitive bid procedures approved and supervised by the DPSC. DPL also has an obligation to provide SOS, known as HPS, for the largest Delaware customers. Power to supply the HPS customers is acquired in next-day and other short-term PJM RTO markets. DPL’s rates for supplying SOS and HPS reflect the associated capacity, energy (including satisfaction of renewable energy requirements), transmission and ancillary services costs and an amount referred to as a Reasonable Allowance for Retail Margin (RARM).Margin. Components of the RARMReasonable Allowance for Retail Margin include a fixed annual margin of approximately $2.75 million, plus estimated incremental expenses, a cash working capital allowance, and recovery, with a return over five years ending 2011, of the capitalized costs of the billing system used for billing HPS customers. DPL is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Delaware service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

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DPL has been providing SOS in Maryland since June 2004. Pursuant to orders issued by the MPSC, DPL is obligated to provide SOS to residential and small commercial customers until further action of the Maryland General Assembly, and to medium-sized commercial customers through May 2014. DPL purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with a competitive bid procedure approved and supervised by the MPSC. DPL also is obligated to provide SOS, known as HPS for large Maryland customers. Power to supply the HPS customers is acquired in next-day and other short-term PJM RTO markets. DPL is entitled to recover from its SOS customers the costs of acquiring the SOS supply, plus an administrative charge that is intended to allow DPL to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of Maryland SOS customers in each customer class and the electricity used by such customers. DPL is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Maryland service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

For the year ended December 31, 2010, 53%2011, 51% of DPL’s Delaware distribution sales (measured by megawatt hours) were to SOS customers, as compared to 53% and 51% in 2010 and 2009, respectively, and 63%58% of its Maryland distribution sales (measured by megawatt hours) were to SOS customers for the years ended December 31,in 2011, as compared to 63% in 2010 and 2009.

Supply and Distribution 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 has a population of approximately 500,000. Large volume commercial, institutional, and industrial natural gas customers may purchase natural gas either from DPL or from other suppliers. DPL uses its natural gas distribution facilities to deliver natural gas to customers that choose to purchase natural gas from another supplier. Intrastate transportation customers pay DPL distribution service rates approved by the DPSC. 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. For the year ended December 31, 2010,2011, DPL supplied 65%64% of the natural gas that it delivered, compared to 65% in 2010 and 68% in 2009.

In eachAs of the years ended December 31, 2010 and 2009,2011, DPL delivered natural gas to 124,000 customers as compared to 123,000 customers.customers as of December 31, 2010 and 2009. In 2010,2011, DPL delivered 19,000,000 Mcf (thousand cubic feet) of natural gas to customers in its Delaware service territory, of which 41%40% were sales to residential customers, 23% to commercial customers, 1% to industrial customers and 36% to customers receiving a transportation-only service. In 2010, DPL delivered 19,000,000 Mcf of natural gas, of which 41% were sales to residential customers, 23% were sales to commercial customers, 1% were sales to industrial customers and 35% were sales to customers receiving a transportation-only service. In 2009, DPL delivered 19,000,000 Mcf of natural gas, of which 42% were sales to residential customers, 25% were sales to commercial customers, 1% were sales to industrial customers and 32% were sales to customers receiving a transportation-only service.

ACE

ACE is primarily engaged in the transmission, distribution and default supply of electricity in a service territory consisting of Gloucester, Camden, Burlington, Ocean, Atlantic, Cape May, Cumberland and Salem counties in southern New Jersey. ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.1 million. As of December 31, 2010,2011, ACE distributed electricity to 548,000547,000 customers in its service territory, as compared to 548,000 and 547,000 customers as of December 31, 2009.2010 and 2009, respectively.

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In 2011, ACE distributed a total of 9,683,000 megawatt hours of electricity to its customers, of which 46% of the total was distributed to residential customers, 45% to commercial customers and 9% to industrial customers. In 2010, ACE distributed a total of 10,185,000 megawatt hours of electricity to its customers, of which 46% of the total was distributed to residential customers, 44% to commercial customers, and 10% to industrial customers. In 2009, ACE distributed a total of 9,659,000 megawatt hours of electricity to its customers, of which 45% was distributed to residential customers, 45% to commercial customers, and 10% to industrial customers.

Electric customers in New Jersey who do not choose another supplier receive BGS from their electric distribution company. New Jersey’s electric distribution companies, including ACE, jointly obtain the electricity to meet their BGS obligations from competitive suppliers selected through auctions authorized by the NJBPUNew Jersey Board of Public Utilities (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:

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 on the supply component of the BGS it supplies to customers. ACE is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territory regardless of whether the customer receives BGS or purchases electricity from another supplier.

For the year ended December 31, 2010, 65%2011, 56% of ACE’s total distribution sales (measured by megawatt hours) were to BGS customers, as compared to 65% and 73% in 2009.2010 and 2009, respectively.

ACE has contracts with three unaffiliated non-utility generators (NUGs) under which ACE is obligated to purchase capacity and the entire generation output of the facilities. One of the contracts expires in 2016 and the other two expire in 2024. In 2010,2011, ACE purchased 2.51.9 million megawatt hours of power from the NUGs. ACE sells this electricity into the wholesale market administered by PJM.

In 2001, ACE established Atlantic City Electric TransitionTransitional 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 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.

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Other Power Delivery Initiatives and Activities

Reliability Enhancement and Emergency Restoration Improvement Plans

DuringIn 2010, PepcoPHI announced Comprehensive Reliability Enhancement Planscomprehensive reliability enhancement plans for Maryland and the District of Columbia. Each six point plan advances work on existing programs and initiates new activities designed to increase the reliability of Pepco distribution services in Maryland and the District of Columbia. TheThese reliability enhancement plans include various initiatives such as enhanced vegetation management, the identification and upgrading of underperformingunder-performing feeder lines, the addition of new facilities to support load, growth,the installation of distribution automation systems on both the overhead and underground network system, the rejuvenation and replacement of underground residential cable replacementcables, improvements to substation supply lines and selective undergrounding of service lines. By focusingportions of existing above ground primary feeder lines, where appropriate to improve reliability and enhance customer satisfaction. During 2011, Pepco continued to execute on these six areas, Pepcoits plans to increase theimprove reliability of the distribution system bywhich it believes have contributed to its progress in reducing both the frequency and the duration of power outages. The incremental cost ofDuring 2011, Pepco invested $120 million in capital expenditures on these reliability enhancement activities. Since initiating the reliability enhancement plans, Pepco trimmed trees along nearly 3,500 miles of power lines, completed 48 expansion projects to meet growth in customer demand for electricity, upgraded more than 340 miles of aging underground lines, and added 125 automated switches that will reroute power more effectively during outages. PHI has extended its reliability enhancement efforts to DPL and ACE.

In 2011 PHI initiated an accelerated emergency restoration improvement program prior to the start of the 2011 summer storm season. As part of this program, Pepco:

These and other emergency restoration improvements overimplemented as a part of this program were tested during Hurricane Irene in August 2011. Although nearly 500,000 customers across all three utilities were without power at the next five years is estimated to be $100 millionpeak of the storm, nearly 98% of outages were restored within a little more than two days.

PHI’s capital expenditures for continuing reliability enhancement efforts are included in the Maryland service territory and $90 million in the Districttable of Columbia service territory. For a discussion of theprojected capital expenditures, associated with these plans, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital—Capital Resources and Liquidity -– Capital Expenditure - Reliability Enhancement Plans” of this Form 10-K.Expenditures.”

Blueprint for the Future

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

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One of the primary initiatives of Blueprint for the future programs include:

The status of some of the more significant aspects of these initiatives is as follows:

For a discussion of the capital expenditures associated with Blueprint for the Future, See Item 7,see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital—Capital Resources and Liquidity —– Capital Expenditure —Requirements – Blueprint for the Future” of this Form 10-K.Future.”

MAPP Project

In October 2007, the PJM Board of Managers approved PHI’s proposal to construct a new 230-mile, 500-kilovolt interstate transmission line referred to as the Mid-Atlantic Power Pathway (MAPP), as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM RTO system. Since that time, there have been various modifications to the proposal that have redefined the length and route of the MAPP project. PJM has approved the use of advanced direct current technology for segments of the project, including the portion of the line that will traverse under the Chesapeake Bay. The direct current portion of the line will be 640-kilovolts640 kilovolts and the remainder of the line will be 500-kilovolts.500 kilovolts. As currently approved by the PJM Board of Managers, MAPP is approximately 150-miles152 miles in length originating at the Possum Point substation in Virginia and ending at the Indian River substation in Delaware. The cost of the MAPP project for Pepco and DPL is currently estimated to be $1.2 billionbillion.

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In connection with the MAPP project, FERC has authorized for each of Pepco and DPL a 150 basis point adder to its return on equity, resulting in a FERC-approved rate of return on the planned in serviceMAPP project of 12.8%, along with full recovery of construction work-in-progress and prudently incurred abandoned plant costs.

On August 18, 2011, PJM notified PHI that the scheduled in-service date isfor MAPP has been delayed from June 1, 2015.

PHI understands that PJM currently is2015 to the 2019 to 2021 time period, after taking into account changes in the process of reassessing reliability requirements of the PJM RTO system in the context of the preparation of its 2011 Regional Transmission Expansion Plan, which is scheduled to be completed in June 2011. This reassessment is expected to take into accountdemand response, generation retirements and additions, and a revised load forecast for the PJM region that is significantly lower than the load that was forecastforecasted in prior PJM studies. This reassessment could resultA more recent load forecast continues to support this trend. PJM has retained the MAPP project in a further deferralits 2011 Regional Transmission Expansion Plan. In light of the required operationaldelayed in-service date for MAPP, substantially all of the anticipated capital expenditures associated with MAPP have been delayed until at least 2016 based on current projections.

The exact revised in-service date of all or a portionMAPP will be evaluated as part of PJM’s 2012 Regional Transmission Expansion Plan review process. Until PJM’s evaluation is concluded, PJM has directed PHI to limit further development efforts with respect to the MAPP transmission line.

The construction ofproject and to proceed with only those development efforts reasonably necessary to allow the MAPP requires various permitsproject to be quickly restarted if and approvals, includingwhen deemed necessary. Based on PJM’s direction, PHI intends to continue to complete the approval ofright-of-way acquisition for the MPSC. The MPSC has issued a procedural schedule to consider a request for a Certificate of Public Convenienceproposed route, and Necessity filed by Pepcosome environmental and DPL, which contemplates decision by January 31, 2012.other preparatory activities.

For a discussion of the capital expenditures associated with the MAPP project,Project, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital—Capital Resources and Liquidity —– Capital Expenditure —Requirements – MAPP Project” of this Form 10-K.Project.”

Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

Most of Pepco Energy Services’ contracts with federal, state and local governments, as well as 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 contain explicit mechanisms that, if exercised, would require the other party to pay Pepco Energy Services alsofor work performed through the date of termination and for additional costs incurred as a result of the termination.

From time to time, PHI is required to guarantee the obligations of Pepco Energy Services under certain of its construction contracts. At December 31, 2011, PHI’s guarantees of Pepco Energy Services’ projects totaled $65 million.

Pepco Energy Services has historically been engaged in the business of providing retail energy supply services, consisting of the sale of electricity, including electricity from renewable resources, primarily to commercial, industrial and government customers located primarily in the mid-Atlantic and northeastern regions of the U.S.,United States, as well as Texas and Illinois, and the sale of natural gas to customers located primarily in the mid-Atlantic region. In December 2009, PHI announced that it would wind downwind-down the retail energy supply business. Pepco Energy Services is implementing this wind downwind-down by not entering into any new supply contracts, while continuing to perform under its existing supply contracts through their expiration dates. As of December 31, 2010,2011, Pepco Energy Services’ estimated retail electricity backlog was approximately 9.73.9 million megawatts for distribution through 2014, a decrease of approximately 10.45.8 million megawatts and 16.2 million megawatts when compared to December 31, 2009.2010 and 2009, respectively. For additional information on the Pepco Energy Services wind-down, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Pepco Energy Services.”

Pepco Energy Services’ retail natural gas sales volumes and revenues are seasonally dependent. Colder weather from November through March of each year generally translates into increased sales volumes, which, when coupled with higher natural gas prices during these months, allows Pepco Energy Services to recognize generally higher revenues as compared to other months of the year. Retail electricity sales volumes are also seasonally dependent, with sales in the summer and winter months being generally higher than other months of the year, which, when coupled with higher electricity prices during these periods, allows Pepco Energy Services to recognize generally higher revenues as compared to other periods during the year. However, as Pepco Energy Services is in the process of winding down its retail energy supply business, this Form 10-K.effect of seasonality will likely decrease as such wind-down is completed. The energy services business is not seasonal.

Pepco Energy Services owns and operates two oil-fired generating facilities. The facilities are located in Washington, D.C. and have a combined generating capacity of approximately 790 megawatts. See Item 2, “Properties” of this Form 10-K. Pepco Energy Services sells the output of these facilities into the wholesale market administered by PJM. In February 2007, Pepco Energy Services provided notice to PJM of its intention to deactivate these facilities. Pepco Energy Services currently plans to deactivate both facilities inby the end of May 2012. PJM has informed Pepco

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Energy Services that these facilities arewill not expected to be needed for reliability after that time, but that its evaluationMay 2012; therefore decommissioning plans are currently underway and on schedule. It is dependent on the completion of transmission and distribution upgrades. Pepco Energy Services’ timing fornot expected that deactivation of thethese facilities in whole or in part, may be delayed based on reliability considerations, economic conditions and the operating condition of the facilities. Deactivation will not have a material impact on PHI’s financial condition, results of operations or cash flows.

Pepco Energy Services also owns three landfill gas-fired electricity facilities that have a total generating capacity rating of ten megawatts, the output of which is sold into the wholesale market administered by PJM andPJM. Pepco Energy Services also owns a solar photovoltaic facility that has a generating capacity rating of two megawatts, the output of which is sold to its host facility.

Pepco Energy Services’ continuing lines of business will not be significantly affected by the wind downwind-down of the retail energy supply business.

PJM Capacity Markets

A source of revenue forHistorically, Pepco Energy Services has beenearned revenue from the sale of capacity associated with its generating facilities. The wholesale market for capacity in the PJM RTO region is administered by PJM, which is responsible for ensuring that within its transmission control area there is sufficient generating capacity available to meet the load requirements plus a reserve margin. In accordance with PJM requirements, retail sellers ofmargin and locates and prices electricity in the PJM market are required to maintain capacity from generating facilities within the control area, or capacity for generating facilities outside the control area that have firm transmission rights into the control area that correspond to their load service obligations. This capacity can be obtained through the ownership of generation facilities, entry into bilateral contracts or the purchase of capacity credits in the auctions administered by PJM. Both generating facilities owned by Pepco Energy Services are located in the transmission control area administered by PJM.

Beginning on June 1, 2007, PJM replaced its former capacity market rules with a forward capacity auction procedure known as the Reliability Pricing Model (RPM), which provides for differentiation in capacity prices between “locational deliverability areas.” Under RPM, PJM holdsholding annual auctions covering capacity to be supplied over consecutive 12-month periods. Pepco Energy Services ishas been exposed to deficiency charges payable to PJM ifwhen their generation units failfailed to meet certain reliability levels. Some deficiency charges may be reduced by purchasing capacity from PJM or third parties.

Since Pepco Energy Services intends to deactivate its two oil-fired generating facilities by May 2012, Pepco Energy Services has not included the facilities’ capacity in any auctions for periods after May 2012.

Competition

In providingPepco Energy Services’ energy management services business is highly competitive. Pepco Energy Services competes with numerous other providers. Competitionenergy 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 construction or utility holding companies (as is the case with Pepco Energy Services). Among the factors as to which the energy services business competes are the amount and duration of the guarantees provided in energy savings performance contracts and the quality and value of service provided to customers. The energy services business is impacted by new entrants into the market, for energy management services is based primarily on overall value to customers.prices, and general economic conditions.

Other Business Operations

Between 1994 and 2002, PCI, a subsidiary of PHI, entered into eight cross-border energy lease investments involving public utility assets (primarily consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks) located outside of the United States. Each of these investments is structured as a sale and leaseback transaction commonly referred to as a sale-in, lease-out, or SILO, transaction. During the second quarter of 2011, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the eight lease investments and a small portion of the leases comprising a second lease investment. The early termination of the leases were negotiated at the request of the lessees and were completed in June 2011. As of December 31, 2010,2011, PHI’s equity investment in its cross-border energy leases was approximately $1.4$1.3 billion. For additional information concerning these cross-border energy lease investments, see Note (8), “Leasing Activities,” and Note (17), “Commitments and Contingencies,” to the consolidated financial statements of PHI.

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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 distribution and transmission 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 follows:

Rates and tariffs are established by these regulatory commissions. PHI’s utility subsidiaries have filed rate cases which are pending in each of its jurisdictions as further described in Note (7), “Regulatory Matters – Regulatory Proceedings – Rate Proceedings,” to the consolidated financial statements of PHI.

The rates and tariffs established by these regulatory commissions are intended to balance the interests of the utilities’ customers and those of its investors by reflecting costs incurred during the period in which the rates are in effect, and giving each utility the opportunity to generate revenues sufficient to recover its costs, including a reasonable rate of return on investor supplied capital during such period. In establishing a utility’s rates, an important factor in the ability of each of Pepco, DPL and ACE to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in the utility’s rate structure in order to minimize the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Each of Pepco, DPL and ACE is currently experiencing significant regulatory lag because their investment in the rate base and operating expenses is outpacing revenue growth.

Higher operating and construction costs, including labor, material, depreciation, taxes and financing costs, as well as costs associated with enhanced distribution system reliability and environmental compliance, are expected at each of PHI’s utility subsidiaries for several years into the future. At the same time, low usage growth and customer growth is expected to limit the growth in revenues. This mismatch between high expense growth and low revenue growth exacerbates regulatory lag for each of PHI’s utility subsidiaries, making it more difficult for each utility to earn equity returns that are allowed by regulators without higher rates or other regulatory relief. See “Risk Factors – The failure of PHI set forthto obtain timely recognition of costs in Part II, Item 8its rates may have a negative effect on PHI’s results of operations and financial condition.”

Pepco, DPL and ACE anticipate that they will continue to face regulatory lag. In their most recent rate cases, Pepco (in the District of Columbia and Maryland) and DPL (in Delaware and Maryland) each has proposed mechanisms that would track reliability and other expenses and permit the utility between rate cases to make adjustments in its rates for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. In New Jersey, the NJBPU has approved certain rate recovery mechanisms

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in connection with ACE’s Infrastructure Investment Program (IIP), which ACE has proposed to extend and expand. There can be no assurance that these proposals or any other attempts by Pepco, DPL and ACE to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms or any base rate cases will fully ameliorate the effects of regulatory lag. Until such time as these proposed mechanisms are approved, if necessary to address the problem of regulatory lag, the utilities plan to file rate cases at least annually in an effort to align more closely their revenue and related cash flow levels with other operation and maintenance spending and capital investments. In future rate cases, Pepco, DPL and ACE, as applicable, would also continue to seek cost recovery and tracking mechanisms from applicable regulatory commissions to reduce the effects of regulatory lag.

Maryland Reliability Investigation

In August 2010, following major storm events that occurred in July and August 2010, an investigation was initiated in Maryland into the reliability of Pepco’s distribution system and the quality of distribution service Pepco provided to its customers. As a result of that investigation, the MPSC imposed sanctions on Pepco in December 2011, including a fine of $1 million, which Pepco has paid. In accordance with the order, Pepco has filed a detailed work plan for the next five years, which provided a comprehensive description of Pepco’s reliability enhancement plan, its emergency response improvement project, and other communication and service restoration improvements. Pepco is also required to file quarterly updates and a year-end status report with the MPSC providing, among other things, detailed information about its reliability and emergency response improvement objectives, progress and spending (and explanations for any inability to meet such objectives), together with an analysis of trends concerning the measured duration and frequency of customer interruptions. In the required reports, Pepco will be required to demonstrate that its reliability enhancement plan costs were prudently spent and produced a significant improvement in reliability, and if it is unable to do so, the MPSC may deny Pepco reimbursement for future reliability enhancement investments or impose additional fines. In addition to the sanctions, the MPSC stated its intent to review the recovery of reliability costs in Pepco’s pending rate case and to disallow incremental costs it determines to be the result of imprudent management. Pepco believes its reliability costs have been prudently incurred. Furthermore, Pepco expects its reliability enhancement plan to enable Pepco to meet the MPSC’s requirements. For more information about the MPSC’s ruling in this Form 10-K.proceeding, see Note (7), “Regulatory Matters – Regulatory Proceedings,” to the consolidated financial statements of PHI.

District of Columbia and Maryland Reliability and Customer Service Rulemakings

In December 2011, the MPSC approved proposed rules establishing reliability and customer service regulations, compliance with which is anticipated to be mandated as early as the second quarter of 2012. 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. Pepco and DPL each expect to incur significant operation and maintenance spending and capital investments to comply with these requirements. Pepco believes that the DCPSC’s standards are achievable in the short term, but continues to believe that the standards may not be realistically achievable at an acceptable cost over the longer term. 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.

Maryland New Generation RFP Issuance Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland’s regulated electric distribution companies (EDCs) should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland. In September 2011, the MPSC issued a notice in which it stated that it had not made a final determination at this time whether new generation in Maryland is needed, but directed each of the four Maryland EDCs, including Pepco and DPL, to issue a request for proposal (RFP) for new generation resources by October 7, 2011. On that date, Pepco and DPL issued the RFP and sought additional information from the MPSC on

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several aspects of the process established in the notice, including whether the MPSC will consider a utility-owned generation option. Hearings were held on January 31, 2012, to obtain further input on whether the EDCs should be ordered to proceed with the RFP. Pepco and DPL have filed a request for rehearing of the notice. The MPSC has stated its intent to select generators and execute long-term contracts between the generators and selected EDCs in April 2012. PHI opposes the requirement to enter into such long-term contracts, which would be viewed as debt by the credit rating agencies and would have an adverse effect on PHI’s, Pepco’s and DPL’s credit metrics.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generators to receive payments from, or make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM. Each of the other EDCs in New Jersey has entered into SOCAs having the same terms with the same generation companies. The annual share of payments or receipts for ACE and the other EDCs is based upon each company’s annual proportion of the total New Jersey load attributable to all EDCs. The NJBPU has approved full recovery from distribution customers of payments made by ACE and the other EDCs, and distribution customers would be entitled to any payments received by ACE and the other EDCs.

ACE and the other EDCs entered the SOCAs under protest based on concerns about the potential cost to distribution customers and the negative credit rating agency implications and have filed lawsuits challenging the constitutionality of the New Jersey law. For more information about the New Jersey law and associated regulatory and legal proceedings, see Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements,” to the consolidated financial statements of PHI.

Delaware Renewable Energy Portfolio Standards

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. In July 2011, the Governor of the State of Delaware signed legislation that expands DPL’s RPS obligations beginning in 2012. Before this legislation, DPL was required to obtain RECs for energy delivered only to SOS customers in Delaware; the legislation expands that requirement to energy delivered to all of DPL’s distribution customers in Delaware. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its distribution customers by law.

The legislation also establishes that the energy output from fuel cells manufactured in Delaware capable of running on renewable fuels is an eligible resource for RECs under the Renewable Portfolio Standards Act. The legislation requires that the DPSC adopt a tariff under which DPL would be an agent that collects payments from its customers and disburses the amounts collected to a qualified fuel cell provider that deploys Delaware-manufactured fuel cells as part of a 30-megawatt generation facility. The legislation also provides for a reduction in DPL’s REC and solar REC requirements based upon the actual energy output of the 30-megawatt generation facility. In October 2011, the DPSC approved the tariff submitted by DPL in response to the legislation. For more information on the tariff, see Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – DPL Renewable Energy Transactions,” to the consolidated financial statements of PHI.

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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, ACE and Pepco Energy Services. There are eight NERC regional oversight entities, including ReliabilityFirstCorporation (RFC), of which Pepco, DPL, ACE and Pepco Energy Services are members, and Northeast Power Coordinating Council (NPCC), of which Pepco Energy Services is a member. These oversight entities are charged with the day-to-day implementation and enforcement of NERC’s reliability standards, which impose certain operating, planning and cyber security requirements on the bulk power systems of Pepco, DPL, ACE and Pepco Energy Services. RFC and NPCC perform compliance audits on entities registered with NERC based on reliability standards and criteria established by NERC. NERC, RFC and NPCC also conduct compliance investigations in response to a system disturbance, complaint, or possible violation of a reliability standard identified by other means. Each of PHI’s utility subsidiaries and Pepco Energy Services 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 cyber security assets) subject to NERC’s cyber security standards. NERC is empowered to impose financial penalties, fines and other sanctions for non-compliance with certain rules and regulations.

Employees

At December 31, 2010,2011, PHI had 5,014 employees, including 1,375 employed by Pepco, 905 employed by DPL, 553 employed by ACE and 1,662 employed by PHI Service Company. The remaining employees were employed by Pepco Energy Services. Approximately 2,592 employees (including 1,028 employed by Pepco, 699 employed by DPL, 390 employed by ACE, 331 employed by the PHI Service Company, and 144 employed by Pepco Energy Services)following number of employees:

PHI’s subsidiaries are covered byparties to five collective bargaining agreements with various locals offour local unions. All five collective bargaining agreements will expire within the International Brotherhood of Electrical Workers.next four years, including one agreement that will expire on June 1, 2012. Collective bargaining agreements are generally renegotiated every three to five years.

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 (17), “Commitments and Contingencies – Environmental Matters – Conectiv Energy Wholesale Power Generation Sites,” to the consolidated financial statements of PHI.

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PHI’s subsidiaries’ currently have no 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.orders are approximately $6 million in 2012 and $3 million in each of 2013, 2014 and 2015. This projection 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 the Conectiv Energy wholesale power generation business in 2010, PHI is no longer subject to environmental regulations prospectively applicable to electricity generating facilities, except insofar as such regulations affect the operation of the two generating facilities located in the District of Columbia owned by Pepco Energy Services. Moreover, PHI anticipates that these regulations will cease to apply to PHI electricity generating facilities altogether after May 2012, assuming the two generating facilities are deactivated by Pepco Energy Services as planned.

Air Quality Regulation

The generating facilities owned by Pepco Energy Services are 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.

Sulfur Dioxide and Nitrogen Oxide Emissions

The acid rain provisions of the CAAClean Air Act regulate total sulfurSulfur dioxide (SO₂) emissions from affected generating units and allocate “allowances” to each affected unit that permit the unit to emit a specified amount of SO₂. The generating facilities of Pepco Energy Services that require SO₂ allowances use allocated allowances or allowances acquired, as necessary, in the open market to satisfy the applicable regulatory requirements.

In 2005, the U.S. Environmental Protection Agency (EPA) issued the Clean Air Interstate Rule (CAIR), which imposes further reductions of SO₂ and limits nitrogen oxide (NOx) emissions from electric generating units in 28 eastern states and the District of Columbia. CAIR uses an allowance system to cap state-wide emissions (and emissions within the District of Columbia) of SO₂ (using acid rain allowances) and NOx allowances, as described below, in two stages. NOx reductions were required beginning in 2009 and SO₂ reductions were required beginning in 2010. States and the District of Columbia may implement CAIR by adopting EPA’s trading program or through adopting regulations that at a minimum achieve the level of reductions that would otherwise be achieved through implementation of EPA’s trading program. Pepco Energy Services Buzzard Point generating units and its landfill gas generating units produce fewer megawatts than CAIR’s applicability threshold and therefore are not subject to CAIR.

Each state covered by CAIR and the District of Columbia may determine independently which emission sources to control and which control measures to adopt. CAIR includes model rules for multi-state cap and trade programs for power plants that states may choose to adopt to meet the required emissions reductions. In the District of Columbia, the Pepco Energy Services’ Benning Road units are permitted to satisfy the CAIR requirements through the use of allocated allowances or allowances acquired in the open market, through the installation of pollution control devices or through fuel modifications.

The Benning Road units use NOx annual, NOx ozone season and SO₂ allowances allocated or acquired, as necessary, in the open market to comply with CAIR.

In July 2010,2011, EPA proposedadopted new regulations to replace CAIR, towhich address transport of air pollution across state boundaries. EPA’s proposed TransportThe Cross-State Air Pollution Rule will impose(CSAPR) imposes stricter limits on SO₂ and NO_xNOx (annual and ozone season) than CAIR, effective as early as 2012. The proposed Transport Rule will affect Benning generating facility because it has a stationary fossil-fuel fired boiler that was in operation after November 15, 1990 and is used in combination with a generator with nameplate capacity greater than 25 MW producing electricity for sale to the grid.

EPA will propose a Federal Implementation Plan forCAIR; however, the District of Columbia was in the group of jurisdictions excluded from the SO₂, NOx, and each state covered by the ruleseasonal NOx under CSAPR. As a result, CSAPR’s Cap and Trade program, which was originally planned to address the lower limits. Alternatively,go into effect on January 1, 2012, is not applicable to Pepco Energy Services.

On December 30, 2011, the District of Columbia DepartmentCircuit Court of Appeals ruled to stay the Environment (DDOE) could develop its own State Implementation Plan (SIP). DDOE’s strategy for addressing the requirements is unknown at this time.

Although implementation of CAIR increases costs forCSAPR, and ordered EPA to continue enforcing CAIR. Consequently, Pepco Energy Services must continue to operate these Benning Road units, PHI currently does not anticipate thatmeet its CAIR orobligations until after the proposed Transport Rule will have a material adverse impact on its resultscourt resolves petitions for review of operations, financial condition or cash flows, even assuming the units are not deactivated by May 2012 as planned. Pepco Energy Services’ Buzzard Point generating units and its landfill gas generating units produce fewer megawatts than the CAIR applicability threshold and therefore would not be affected by the proposed Transport Rule.CSAPR.

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Federal Regional Haze Rule

The federal Regional Haze Rule was adopted by EPA to address a type of visibility impairment known as regional haze created by the emission of specified pollutants by certain types of large stationary sources. The regulation requires installation of best available retrofit technology (BART) to boilers that (i) emit 250 tons or more per year of a visibility-impairing air pollutant, (ii) were placed in service between 1962 and 1977, and (iii) may reasonably be anticipated to cause or contribute to visibility impairment in any federally protected park or wilderness area. Pepco Energy Services’ Benning Road generating units are subject to this regulation for particulate matter less than ten microns in diameter (PM₁₀) and for SO₂ and NOx to the extent not addressed by CAIR. Under Pepco Energy Services is evaluatingServices’ current operating permit issued by the manner of addressing BART, including ceasing operation ofDDOE, the Benning Road generating units consistent with its previously announced planwill not be required to deactivate those units by May 2012.

On January 4, 2011,implement any remedial actions if the facilities are shut down on or before December 17, 2012, which is Pepco Energy Services received from the DDOE the draft of a Title V permit, which reflects Pepco’s agreement to deactivate the Benning Road units by the end of calendar year 2012 and DDOE’s agreement to delay the implementation BART until after the agreed upon retirement date. PHI expects the Title V permit to be finalized before the end of the second quarter 2011.Services’ current plan.

Pepco Energy Services’ Buzzard Pointother generating units, and its landfill gas generating unitsincluding those at Buzzard Point, are not subject to the Regional Haze Rule.

Hazardous Air Pollutant Emissions

In December 2011, EPA finalized a March 2005 rulemaking, EPA removed coal- and oil-fired electric generating units fromrule to reduce the listemission of source categories requiring Maximum Achievable Control Technology for hazardous air pollutants such as mercury and nickel under CAA Section 112. In a decision issued in February 2008, the U.S. Court of Appeals for the District of Columbia Circuit determined that this action by EPA was unlawful. To date, EPA has not proposed new regulations to address hazardous air pollutant emissions from existing electric generating units in response to the court’s decision.

In January 2010, Pepco Energy Services received from EPA an Information Collection Request (ICR) under Section 114 of the Clean Air Act, requesting that it provide information regarding Benning Road units 15 and 16 that will allow EPA to assess the emissions of hazardoustoxic air pollutants from those units.generating facilities. The information requested includes historical data with respect to both units,Mercury and Air Toxics Standards will reduce emissions of heavy metals, including mercury, arsenic, chromium and nickel, as well as dataemissions of acid gases, including hydrochloric and hydrofluoric acid. Because existing generating sources generally have up to four years from the Standards’ effective date to comply with the Mercury and Air Toxics Standards, this rule is not expected to impact the Benning Road or Buzzard Point generating facilities, which are expected to be obtainedretired by stack testing during the operation of Benning Road unit 16. Pepco Energy Services provided timely responses to the ICR. In September 2010, Pepco Energy Services received a variance from EPA such that stack testing at Benning is not required.May 2012.

Green HouseGreenhouse Gas Emissions Reporting

In October 2009, EPA has adopted regulations requiring sources that emit designated greenhouse gases –gases– specifically, carbon dioxide, (CO₂), methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and other fluorinated gases (e.g., nitrogen trifluoride and hydrofluorinated ethers) – in excess of specified thresholds to file annual reports with EPA disclosing the amount of such emissions. Under these regulations:

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Water Quality Regulation

Clean Water Act

Provisions of the federal Water Pollution Control Act, also known as the Clean Water Act, (CWA), establish the basic legal structure for regulating the discharge of pollutants from point sources to surface waters of the United States. Among other things, the CWAClean Water Act requires that any person wishing to discharge pollutants from a point source (generally a confined, discrete conveyance such as a pipe) obtain a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA or by a state agency under a federally authorized state program. The Benning Road generating facility has a NPDES permit authorizing pollutant discharges, which is subject to periodic renewal.

Pepco and a subsidiary of Pepco Energy Services discharge water from the Benning Road electric generating plant and service center located in the District of Columbia under a NPDES permit issued by EPA in July 2009. The permit imposes compliance monitoring and storm water best management practices (BMPs) to satisfy the District of Columbia’s Total Maximum Daily Load standards for polychlorinated biphenyls (PCBs), oil and grease, metals and other substances. As required by the permit, Pepco has initiated studies to identify the source of the regulated substances to determine appropriate BMPsbest management practices for minimizing the presence of the substances in storm water. The initial study reports are scheduled for completion in March 2012 and will be submitted to EPA as required. The capital expenditures, if any, that may be needed to implement BMPsbest management practices to satisfy these new permit conditions will not be known until thesethe results of the studies are completed.

NPDES General Permit for Pesticide Discharge

PHI operates and maintains approximately 3,600 miles of transmission right of way and approximately 30,000 miles of distribution right of way and uses a combination of mechanical and chemical controls (pesticides/herbicides) to manage vegetation in its rights-of-way through a process known as “Integrated Vegetation Management.” PHI’s application of pesticides and herbicides for vegetation management traditionally has been governedreviewed by the requirements of the Federal Insecticide, Fungicide and Rodenticide Act.

In response to a 2009 decision by the Sixth Circuit Court of Appeals in National Cotton Council,et al, v. EPA, which invalidated a 2006 EPA rulemaking exempting pesticide application from NPDES permit requirements, EPA, in June 2010, proposed a draft NPDES general permit for point source discharges from the application of pesticides to waters of the United States. Under the Court’s order, pesticide discharges are required to be permitted under either an EPA- or state- issued NPDES permit no later than April 9, 2011. State water pollution regulators and agriculture officials asked the EPA to seek a six month stay of the court’s order to provide sufficient time for EPA to finalize its general permit and for states to use the final EPA general permit as a guide for developing state NPDES general permits.

When permitting authorities make such permits available, PHI utility companies will apply for NPDES permits for pesticide application as part of vegetation management activities.EPA.

New Jersey Flood Hazard Area Control Act

In November 2007, the New Jersey Department of Environmental Protection adopted amendments to the agency’s regulations under the Flood Hazard Area Control Act the (FHACA) to minimize damage to life and property from flooding caused by development in flood plains. The amended regulations impose a new regulatory program to mitigate flooding and related environmental impacts from a broad range of construction and development activities, including electric utility transmission and distribution construction, which were previously unregulated under the FHACA. These regulations impose restrictions on construction of new electric transmission and distribution facilities and increase the time and personnel resources required to obtain permits and conduct maintenance activities. In November 2008,While ACE filed an appeal ofcontinues to evaluate the financial impact related to compliance with the amended regulations, based on current information, PHI and ACE do not believe these regulations with the Appellate Divisionwill have a material adverse effect on their respective financial conditions or results of the Superior Court of New Jersey. The grounds for ACE’s appeal include the lack of administrative record justification for the FHACA regulations and conflict between the FHACA regulations and other state and federal regulations and standards for maintenance of electric power transmission and distribution facilities. The matter was argued before the Appellate Division on January 3, 2011, and the decision of the court is pending.operations.

EPA Oil Pollution Prevention Regulations

Business Strategy

In 2002, EPA amendedPHI’s business strategy is to become a top-performing, regulated power delivery company focused on:

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To further its oil pollution prevention regulationsbusiness strategy, PHI may examine transactions involving its existing businesses, including entering into joint ventures, disposing of businesses or making acquisitions. PHI also may refine components of its business strategy as it deems necessary or appropriate in response to require facilities that, becausebusiness factors and conditions, including regulatory requirements.

Description of their location, could reasonably be expected to discharge oil in quantities that may be harmful to the environment, to amend existing Spill Prevention, Control, and Countermeasure (SPCC) Plans and implement secondary containment as necessary. After giving effect to additional amendments and delays in the effective date, PHI facilities subject to the regulations must comply with these regulatory requirements by November 10, 2011. PHI anticipates that compliance with the SPCC regulations will require physical modification of certain facilities through the construction of containment structures or replacement of oil-filled equipment with non-oil-filled equipment at a total anticipated cost to ACE, DPL and Pepco of approximately $1 million, $2 million and $2 million, respectively. PHI does not expect the compliance costs for Pepco Energy Services to be material.Business

Hazardous Substance RegulationPower Delivery

The Comprehensive Environmental Response, Compensation,PHI’s primary business is Power Delivery. Power Delivery in 2011, 2010 and Liability Act2009, produced 79%, 73%, and 67%, respectively, of 1980 (CERCLA) authorizes EPA,PHI’s consolidated operating revenues and comparable state laws authorize state environmental authorities,78%, 81%, and 78%, respectively, of PHI’s consolidated operating income.

Each utility comprising Power Delivery is regulated in the jurisdictions that encompass its electricity distribution service territory and is regulated by FERC for its electricity transmission facilities. DPL also is a regulated natural gas utility serving portions of Delaware. In the aggregate, Power Delivery distributes electricity to issue ordersmore than 1.8 million customers in the mid-Atlantic region and bring enforcement actionsdelivers natural gas to compel responsible parties to investigateapproximately 124,000 customers in Delaware. None of PHI’s three utilities owns any electric generation facilities.

Distribution and take remedial actions at any site that is determined to present an actual or potential threat to human health or the environment becauseDefault Supply 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. Electricity

Pepco, DPL and ACE each 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, or across, the utility’s service territory. Distribution facilities carry electricity from the transmission facilities to the end-use customers located in the utility’s service territory.

Each utility is responsible for the distribution of electricity 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 retail supplier. The regulatory term for this default supply service is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. In this Form 10-K, these supply services are referred to generally as Default Electricity Supply.

Transmission of Electricity and Relationship with PJM

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 the mid-Atlantic portion of the United States and parts of the Midwest. Pepco, DPL and ACE each is a member of the PJM Regional Transmission Organization (PJM RTO), the regional transmission organization designated by the Federal Energy Regulatory Commission (FERC) to coordinate the movement of wholesale electricity within a region consisting of all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

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PJM, the FERC-approved independent grid operator, manages the transmission grid and the wholesale electricity market in the PJM RTO region. Any entity that wishes to have wholesale electricity delivered at any point within the PJM RTO region must obtain transmission services from PJM. In accordance with FERC-approved rules, Pepco, DPL, ACE and the other transmission-owning utilities in the region make their transmission facilities available to the PJM RTO, and PJM directs and controls the operation of these transmission facilities. For transmission services, transmission owners are paid rates proposed by the transmission owner and approved by FERC. 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 the PJM RTO region. The PJM Board of Managers reviews and approves each PJM regional transmission expansion plan, including whether to include new construction of transmission facilities proposed by PJM RTO members in the plan and, if so, the target in-service date for those facilities.

Seasonality

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 nameddue in part to the long standing practice by EPAwhich the applicable public service commissions set distribution rates based on a fixed charge per kilowatt-hour of electricity used by the customer. 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 BSA for retail customers of Pepco and DPL in Maryland in June 2007 and for customers of Pepco in the District of Columbia in November 2009, distribution revenues 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 a state environmental agencyfor any other reason, as a potentially responsible partyfactor having an impact on annual distribution revenue and net income in pending proceedings involving certain contaminated sites. Seethose jurisdictions. The BSA also eliminates what otherwise might be a disincentive for the utility to aggressively develop and promote efficiency programs. Distribution revenues are not decoupled for the distribution of electricity and natural gas by DPL in Delaware or 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.

Regulated Utility Subsidiaries

The following is a more detailed description of the business of each of PHI’s three regulated utility subsidiaries:

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Pepco

Pepco is engaged in the transmission, distribution and default supply of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.2 million. As of December 31, 2011, Pepco distributed electricity to 788,000 customers (of which 257,000 were located in the District of Columbia and 531,000 were located in Maryland), as compared to 787,000 customers as of December 31, 2010 (of which 256,000 were located in the District of Columbia and 531,000 were located in Maryland). As of December 31, 2009, Pepco distributed electricity to 778,000 customers (of which 252,000 were located in the District of Columbia and 526,000 were located in Maryland).

In 2011, Pepco distributed a total of 26,895,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 30% of the total megawatt hours were delivered to residential customers, 50% to commercial customers, and 20% to United States and District of Columbia government customers. In 2010, Pepco distributed a total of 27,665,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 30% of the total megawatt hours were distributed to residential customers, 49% to commercial customers, and 21% to United States and District of Columbia government customers. In 2009, Pepco distributed a total of 26,549,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 29% of the total megawatt hours were distributed to residential customers, 50% to commercial customers, and 21% to United States and District of Columbia government customers.

Pepco has been providing SOS in Maryland since July 2004. Pursuant to orders issued by the Maryland Public Service Commission (MPSC), Pepco is obligated to provide SOS (i) Item to residential and small commercial customers until further action of the Maryland General Assembly and (ii) to medium-sized commercial customers through November 2012. Pepco purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with competitive bid procedures approved and supervised by the MPSC. Pepco also is obligated to provide Standard Offer Service, known as Hourly Priced Service (HPS), for large Maryland customers. Power to supply HPS customers is acquired in next-day and other short-term PJM RTO markets. Pepco is entitled to recover from its SOS customers the cost of acquiring the SOS supply, plus an administrative charge that is intended to allow Pepco to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of Maryland SOS customers in each customer class and the electricity used by such customers. Pepco is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Maryland service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

Pepco has been providing SOS in the District of Columbia since February 2005. Pursuant to orders issued by the District of Columbia Public Service Commission (DCPSC), Pepco is obligated to provide SOS to residential and small, medium-sized and large commercial customers indefinitely. Pepco purchases the electricity required to satisfy its SOS obligations from wholesale suppliers under contracts entered into in accordance with a competitive bid procedure approved and supervised by the DCPSC. Pepco is entitled to recover from its SOS customers the costs of acquiring the SOS supply, plus an administrative charge that is intended to allow Pepco to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of District of Columbia SOS customers in each customer class and the amount of electricity used by such customers. Pepco is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its District of Columbia service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

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For the year ended December 31, 2011, 43% of Pepco’s Maryland distribution sales (measured by megawatt hours) were to SOS customers, as compared to 46% and 49% in 2010 and 2009, respectively, and 27% of its District of Columbia distribution sales (measured by megawatt hours) were to SOS customers in 2011, as compared to 29% and 31% in 2010 and 2009, respectively.

DPL

DPL is engaged in the transmission, distribution and default supply of electricity in Delaware and portions of 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.

Distribution and Supply of Electricity

DPL’s electricity distribution service territory consists 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 has a population of approximately 1.4 million. As of December 31, 2011, DPL delivered electricity to 501,000 customers (of which 301,000 were located in Delaware and 200,000 were located in Maryland), as compared to 500,000 customers as of December 31, 2010 (of which 301,000 were located in Delaware and 199,000 were located in Maryland). As of December 31, 2009, DPL delivered electricity to 498,000 customers (of which 299,000 were located in Delaware and 199,000 were located in Maryland).

In 2011, DPL distributed a total of 12,688,000 megawatt hours of electricity to its customers, of which 66% was distributed within its Delaware territory and 34% within Maryland. Of this amount, 41% of the total megawatt hours were distributed to residential customers, 42% to commercial customers and 17% to industrial customers. In 2010, DPL distributed a total of 12,853,000 megawatt hours of electricity, of which 66% was distributed within its Delaware territory and 34% within Maryland. Of this amount, 42% of the total megawatt hours were distributed to residential customers, 41% to commercial customers and 17% to industrial customers. In 2009, DPL distributed a total of 12,494,000 megawatt hours of electricity, of which 67% was distributed within its Delaware territory and 33% within Maryland. Of this amount, 39% of the total megawatt hours were distributed to residential customers, 41% to commercial customers and 20% to industrial customers.

DPL has been providing SOS in Delaware since May 2006. Pursuant to orders issued by the Delaware Public Service Commission (DPSC), DPL is obligated to provide SOS to residential, small commercial and industrial customers through May 2014, and to medium, large and general service commercial customers through May 2012. DPL purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with competitive bid procedures approved and supervised by the DPSC. DPL also has an obligation to provide SOS, known as HPS, for the largest Delaware customers. Power to supply the HPS customers is acquired in next-day and other short-term PJM RTO markets. DPL’s rates for supplying SOS and HPS reflect the associated capacity, energy (including satisfaction of renewable energy requirements), transmission and ancillary services costs and an amount referred to as a Reasonable Allowance for Retail Margin. Components of the Reasonable Allowance for Retail Margin include a fixed annual margin of approximately $2.75 million, plus estimated incremental expenses, a cash working capital allowance, and recovery, with a return over five years ending 2011, of the capitalized costs of the billing system used for billing HPS customers. DPL is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Delaware service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

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DPL has been providing SOS in Maryland since June 2004. Pursuant to orders issued by the MPSC, DPL is obligated to provide SOS to residential and small commercial customers until further action of the Maryland General Assembly, and to medium-sized commercial customers through May 2014. DPL purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with a competitive bid procedure approved and supervised by the MPSC. DPL also is obligated to provide HPS for large Maryland customers. Power to supply the HPS customers is acquired in next-day and other short-term PJM RTO markets. DPL is entitled to recover from its SOS customers the costs of acquiring the SOS supply, plus an administrative charge that is intended to allow DPL to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of Maryland SOS customers in each customer class and the electricity used by such customers. DPL is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Maryland service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

For the year ended December 31, 2011, 51% of DPL’s Delaware distribution sales (measured by megawatt hours) were to SOS customers, as compared to 53% and 51% in 2010 and 2009, respectively, and 58% of its Maryland distribution sales (measured by megawatt hours) were to SOS customers in 2011, as compared to 63% in 2010 and 2009.

Supply and Distribution 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 has a population of approximately 500,000. Large volume commercial, institutional, and industrial natural gas customers may purchase natural gas either from DPL or from other suppliers. DPL uses its natural gas distribution facilities to deliver natural gas to customers that choose to purchase natural gas from another supplier. Intrastate transportation customers pay DPL distribution service rates approved by the DPSC. 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. For the year ended December 31, 2011, DPL supplied 64% of the natural gas that it delivered, compared to 65% in 2010 and 68% in 2009.

As of December 31, 2011, DPL delivered natural gas to 124,000 customers as compared to 123,000 customers as of December 31, 2010 and 2009. In 2011, DPL delivered 19,000,000 Mcf (thousand cubic feet) of natural gas to customers in its Delaware service territory, of which 40% were sales to residential customers, 23% to commercial customers, 1% to industrial customers and 36% to customers receiving a transportation-only service. In 2010, DPL delivered 19,000,000 Mcf of natural gas, of which 41% were sales to residential customers, 23% were sales to commercial customers, 1% were sales to industrial customers and 35% were sales to customers receiving a transportation-only service. In 2009, DPL delivered 19,000,000 Mcf of natural gas, of which 42% were sales to residential customers, 25% were sales to commercial customers, 1% were sales to industrial customers and 32% were sales to customers receiving a transportation-only service.

ACE

ACE is primarily engaged in the transmission, distribution and default supply of electricity in a service territory consisting of Gloucester, Camden, Burlington, Ocean, Atlantic, Cape May, Cumberland and Salem counties in southern New Jersey. ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.1 million. As of December 31, 2011, ACE distributed electricity to 547,000 customers in its service territory, as compared to 548,000 and 547,000 customers as of December 31, 2010 and 2009, respectively.

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In 2011, ACE distributed a total of 9,683,000 megawatt hours of electricity to its customers, of which 46% of the total was distributed to residential customers, 45% to commercial customers and 9% to industrial customers. In 2010, ACE distributed a total of 10,185,000 megawatt hours of electricity to its customers, of which 46% of the total was distributed to residential customers, 44% to commercial customers, and 10% to industrial customers. In 2009, ACE distributed a total of 9,659,000 megawatt hours of electricity to its customers, of which 45% was distributed to residential customers, 45% to commercial customers, and 10% to industrial customers.

Electric customers in New Jersey who do not choose another supplier receive BGS from their electric distribution company. New Jersey’s electric distribution companies, including ACE, jointly obtain the electricity to meet their BGS obligations from competitive suppliers selected through auctions authorized by the New Jersey Board of Public Utilities (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:

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 on the supply component of the BGS it supplies to customers. ACE is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territory regardless of whether the customer receives BGS or purchases electricity from another supplier.

For the year ended December 31, 2011, 56% of ACE’s total distribution sales (measured by megawatt hours) were to BGS customers, as compared to 65% and 73% in 2010 and 2009, respectively.

ACE has contracts with three unaffiliated non-utility generators (NUGs) under which ACE is obligated to purchase capacity and the entire generation output of the facilities. One of the contracts expires in 2016 and the other two expire in 2024. In 2011, ACE purchased 1.9 million megawatt hours of power from the NUGs. ACE sells this electricity into the wholesale market administered by PJM.

In 2001, ACE established Atlantic City Electric Transitional 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 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.

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Other Power Delivery Initiatives and Activities

Reliability Enhancement and Emergency Restoration Improvement Plans

In 2010, PHI announced comprehensive reliability enhancement plans for Pepco in Maryland and the District of Columbia. These reliability enhancement plans include various initiatives such as enhanced vegetation management, the identification and upgrading of under-performing feeder lines, the addition of new facilities to support load, the installation of distribution automation systems on both the overhead and underground network system, the rejuvenation and replacement of underground residential cables, improvements to substation supply lines and selective undergrounding of portions of existing above ground primary feeder lines, where appropriate to improve reliability and enhance customer satisfaction. During 2011, Pepco continued to execute on its plans to improve reliability which it believes have contributed to its progress in reducing both the frequency and duration of power outages. During 2011, Pepco invested $120 million in capital expenditures on these reliability enhancement activities. Since initiating the reliability enhancement plans, Pepco trimmed trees along nearly 3,500 miles of power lines, completed 48 expansion projects to meet growth in customer demand for electricity, upgraded more than 340 miles of aging underground lines, and added 125 automated switches that will reroute power more effectively during outages. PHI has extended its reliability enhancement efforts to DPL and ACE.

In 2011 PHI initiated an accelerated emergency restoration improvement program prior to the start of the 2011 summer storm season. As part of this program, Pepco:

These and other emergency restoration improvements implemented as a part of this program were tested during Hurricane Irene in August 2011. Although nearly 500,000 customers across all three utilities were without power at the peak of the storm, nearly 98% of outages were restored within a little more than two days.

PHI’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital—Capital Resources and Liquidity – Capital Requirements – Environmental Remediation Obligations,Expenditures.” and (ii) Note (17), “Commitments and Contingencies – Legal Proceedings – Environmental Litigation,” to

Blueprint for the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.

The businesses of PHI, Pepco, DPL and ACE 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 companies, including, depending on the circumstances, its financial condition, results of operations and cash flows. Unless otherwise noted, each risk factor set forth below applies to each of PHI, Pepco, DPL and ACE.

PHI and its subsidiaries are subject to substantial governmental regulation, and unfavorable regulatory treatment could have a negative effect.Future

The regulated utilities that comprise the Power Delivery businesses are subject to regulation by various federal, state and local regulatory agencies that significantly affects their operations. Each of Pepco, DPL and ACE is regulated by the public service commission for each service territory in which it operates, with respect to, among other things, the rates it can charge retail customers for the distribution and supply of electricity (and, additionally for DPL, the distribution and supply of natural gas). In addition, the rates that the companies can charge for electricity transmission are regulated by FERC, and DPL’s natural gas transportation is regulated by FERC. The companies cannot change these rates without approval by the applicable regulatory authority. While the approved rates are intended to permit the companies to recover their costs of service and earn a reasonable rate of return on invested capital, the profitability of the companies is affected by the rates they are able to charge. In addition, if the costs incurred by any of the companies in operating its facilities exceed the allowed amounts for costs included in the approved rates, the financial results of that company, and correspondingly PHI, will be adversely affected.

PHI’s utility subsidiaries is participating in a PHI initiative referred to as well as Pepco Energy Services, are required“Blueprint for the Future,” which is designed to have numerous permits, approvalsmeet the challenges of rising energy costs, respond to concerns about the environment, improve reliability and certificates from governmental agencies that regulateaddress government energy reduction goals. The initiative includes the implementation of various programs to help customers better manage their businesses. PHI believes that eachenergy use, reduce the total cost of its subsidiaries has,energy and each of Pepco, DPL and ACE believes it has, obtained or sought renewal ofprovide other benefits. These programs also enhance the material permits, approvals and certificates necessary for its existing operations and that its business is conducted in accordance with applicable laws. None of the companies, however, are able 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 moreability of PHI’s subsidiariesutilities to incur additional expenses or significant capital expenditures or to change the way it conducts its operations.

The operating results of the Power Delivery businessbetter manage and the retail energy supply business of Pepco Energy Services fluctuate on a seasonal basis and can be adversely affected by changes in weather.

The Power Delivery business historically has been seasonal and 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 electricityoperate their electrical and natural gas is generally higher in the winter months associated with heating as compared to other timesdistribution systems.

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One of the year. Accordingly, eachprimary initiatives of PHI, Pepco, DPL and ACE historically has generated less revenue and income when temperatures are warmer than normal inBlueprint for the winter and cooler than normal inFuture is the summer. The recent adoptioninstallation of smart meters (also known as Advanced Metering Infrastructure (AMI)) for retail customers of Pepco and DPL in Maryland and for Pepco retail customers in the District of Columbia of a bill stabilization adjustment mechanism which decouples distribution revenue for a given reporting period from the amount of power delivered during the period, has had the effect of eliminating in those jurisdictions, changes in the use of electricity by such retail customers due to weather conditions or for other reasons as a factor having an impact on reported distribution revenue and income.

The adoption of bill stabilization adjustment or similar mechanisms for DPL electricityelectric and natural gas customers, in Delaware and ACE electricity customers in New Jersey are under consideration by the state public service commissions. In those jurisdictions that have not adopted a bill stabilization adjustment or similar mechanism, operating results continue to be affected by weather conditions.

The retail energy supply business of Pepco Energy Services generally produces higher gross margins when temperatures are colder than normal in winter or warmer than normal in summer, and less gross margin when weather conditions are milder than normal. The Energy Services business of Pepco Energy Services, which includes providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power energy plants for customers, is not seasonal.

Facilities may not operate as planned or may require significant maintenance expenditures, which could decrease revenues or increase expenses.

Operation of the Pepco, DPL and ACE transmission and distribution facilities and Pepco Energy Services’ generating facilities (scheduled for deactivation in May 2012) involves many risks, including the breakdown or failure of equipment, accidents, labor disputes and performance below expected levels. Older facilities and equipment, even if maintained in accordance with sound engineering practices, may require significant capital expenditures for additions or upgrades to provide reliable operations or to comply with changing environmental requirements. Natural disasters and weather, including tornadoes, hurricanes and snow and ice storms, also can disrupt transmission and distribution systems. Disruption of the operation of transmission or distribution facilities or the operation of generation facilities below expected output levels, can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance, including deficiency charges imposed by PJM on generating facilities at a rate of up to two times the capacity payment that the generating facility receives. Furthermore, the transmission and generating facilities of the PHI companies are subject to reliability standards imposed by the North American Electric Reliability Corporation. Failureapproval of applicable state regulators. These smart meters allow the utilities, among other capabilities, to complyremotely read meters, significantly reduce the number of customer bills that are based on usage estimates, improve outage management and detection, and provide customers with the standards may result in substantial monetary penalties.

Energy companies are subject to adverse publicity which makes them vulnerable to negative regulatory and litigation outcomes.

Utility companies, including PHI’s utility subsidiaries, have been the subject of public criticism focused on the reliability ofmore detailed information about their distribution services and the speed with which they are able to respond to outages caused by storm damage. Adverse publicity of this nature may render legislatures, regulatory authorities and other government officials less likely to view energy companies such as PHI and its subsidiaries in a favorable light, and may cause PHI and its subsidiaries to be susceptible to less favorable legislative and regulatory outcomes.

PHI’s Blueprint for the Future program includes the replacement of customers’ existing electric and gas meters with an AMI system.consumption. In addition to the replacement of existing meters, the AMI system involves the construction of a wireless network across the service territories of PHI’s utility subsidiaries and the implementation and integration of new and existing information technology systems to collect and manage the data made available by the advanced meters. The implementation of the AMI system involves a combination of technologies provided by multiple vendors. IfMeter installation is substantially complete for DPL electric customers in Delaware, with meter activation expected to be completed in the first quarter of 2012. Meter installation is progressing for Pepco customers in both the District of Columbia and Maryland, with installation expected to be complete in the second and fourth quarters of 2012, respectively. The respective public service commissions have approved the creation of a regulatory asset to defer AMI system results in lower than projected performance, PHI’s utility subsidiaries could experience higher than anticipated maintenance expenditures.

The transmission facilitiescosts between rate cases, as well as the accrual of the Power Delivery business are interconnected with the facilities of other transmission facility owners whose actions 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 contiguous utilities and are part of an interstate power transmission grid. FERC has designated a number of regional transmission organizations to coordinate the operation of portions of the interstate transmission grid. Pepco, DPL and ACE are members of the PJM RTO. The PJM RTO and the other regional transmission organizations have established sophisticated systems that are designed to ensure the reliability of the operation of transmission facilities and prevent the operations of one utility from having an adverse impactreturn on the operations of the other utilities. However, the systems put in place by the PJM RTO and the other regional transmission organizations may not alwaysdeferred costs. Thus, these costs will be adequate to prevent problems at other utilities from causing service interruptionsrecovered through base rates in the transmission facilitiesfuture.

Approval of Pepco, DPL or ACE. If any of Pepco, DPL orAMI is still pending for electric customers in DPL’s Maryland service territory, and has been deferred for ACE were to suffer such a service interruption, it could have a negative impact on it and on PHI.in New Jersey.

The cost of compliance with environmental laws, including laws relating to emissions of greenhouse gases, is significant and implementation of new and existing environmental laws may increase operating costs.

The operations of PHI’s subsidiaries, including Pepco, DPL and ACE, 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 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 inOn December 20, 2011, 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.

There is growing concern at the federal and state levels regarding the implications of CO₂ and other greenhouse gas emissions on the global climate. The implementation of restrictions on the emission of CO₂ and other greenhouse gases or regulatory action by the U.S. Environmental Protection Agency prior to deactivation of Pepco Energy Services’ generating facilities (scheduled for May 2012) could require Pepco Energy Services to incur increased capital expenditures or operating costs to replace existing equipment, install additional pollution control equipment or purchase CO₂ allowances and offsets.

Alternatively, Pepco Energy Services could be required to discontinue or curtail the operations of one or more units prior to their planned deactivation date.

Until specific requirements are promulgated, the impact that any new environmental regulations, voluntary compliance guidelines, enforcement initiatives or legislation may have on the results of operations, financial position or liquidity of PHI and its subsidiaries is not determinable.

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

The ability of each of PHI and its subsidiaries, including Pepco, DPL and ACE,Delaware Public Service Commission approved DPL’s request to implement dynamic pricing for its business strategy is dependent on its ability to recruit, retainDelaware customers. Dynamic pricing will reward SOS customers for lowering their energy use during those times when energy demand and, motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect the business, operations and financial condition of PHI or the affected company.

The Energy Services business of Pepco Energy Services is highly competitive. (PHI only)

The Energy Services business of Pepco Energy Services is highly competitive. This competition generally has the effect of limiting margins and requiring a continual focus on controlling costs.

Pepco Energy Services relies on generation, transmission, storage, and distribution assets that it does not own or control to deliver electricity and natural gas to its customers and to obtain the fuel required to operate its generating facilities. (PHI only)

Pepco Energy Services is dependent on electric generating and transmission facilities, natural gas pipelines and natural gas storage facilities owned and operated by others to fulfill the remaining contractual obligations of its retail energy supply business. A disruption in the operation of these facilities would have an adverse effect on Pepco Energy Services.

The operation of Pepco Energy Services’ generating facilities depends on natural gas or diesel fuel supplied by others. If the fuel supply to these generating facilities were to be disrupted and storage or other sources of supply were not available, the ability of Pepco Energy Services to operate its plants would be adversely affected.

Changes in technology may adversely affect the Power Delivery business.

Increased conservation and end-user generation made possible through advances in technology could reduce demand for the transmission and distribution facilities of the Power Delivery business and adversely affect PHI and any one or more of its utility subsidiaries.

Pepco Energy Services’ risk management procedures may not be effective in preventing losses. (PHI only)

The retail energy supply and the electricity generation businesses of Pepco Energy Services are conducted in accordance with sophisticated risk management systems that are designed to quantify and control risk. However, actual results sometimes deviate from modeled expectations. Until the completion of the ongoing wind down of retail energy supply business and the deactivation of Pepco Energy Services’ two generating facilities (scheduled for May 2012), the ineffectiveness of Pepco Energy Service’s risk management procedures could have a material adverse effect on PHI’s results of operations.

The retail energy supply business of Pepco Energy Services can give rise to significant collateral requirements. (PHI only)

In conducting its retail energy supply business, Pepco Energy Services typically entered into electricity and natural gas sale contracts under which it committed to supply the electricity or natural gas requirements of its retail customers over a specified period at agreed upon prices. To acquire the required energy, Pepco Energy Services has entered into wholesale purchase contracts for electricity and natural gas. These contracts typically impose collateral requirements on each party designed to protect the other party against the risk of nonperformance between the date the contract was entered into and the date the energy is paid for. The collateral required to be posted can be of varying forms, including cash, letters of credit and guarantees. When energy market prices decrease relative to the supplier contract prices, Pepco Energy Service’s collateral obligations increase. While Pepco Energy Services no longer enters into new energy supply contracts, it has continuing supply obligations based on prior contracts and corresponding wholesale purchase contracts that extend through 2014. Particularly in periods of energy market price volatility, the collateral obligations associated with these wholesale purchase contracts can be substantial, although they can be expected to diminish as the Pepco Energy Services retail energy supply business is wound down. These collateral demands could negatively affect PHI’s liquidity by requiring PHI to draw on its capacity under its credit facilities or other financing sources.

The retail energy supply business of Pepco Energy Services has significant exposure to counterparty risk. (PHI only)

Pepco Energy Services has entered into transactions with numerous counterparties. These include both commercial transactions for the purchase and sale of electricity and natural gas, and derivative and other transactions, to manage the risk of commodity price fluctuations. Under these arrangements, Pepco Energy Services is exposed to the risk that the counterparty may fail to perform its obligation to make or take delivery under the contract, fail to make a required payment or fail to return collateral posted by Pepco Energy Services when no longer required. Under many of these contracts, Pepco Energy Services is entitled to receive collateral or other types of performance assurance from the counterparty, 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 can prevent the counterparty from meeting its collateral obligations or degrade the value of letters of credit and guarantees as a result of the lowered rating or insolvency of the issuer or guarantor. In the event of a bankruptcy of a counterparty, bankruptcy law, in some circumstances, could require Pepco Energy Services to surrender collateral held or payments received.

Mark-to-market accounting treatment for instruments Pepco Energy Service’s uses to hedgeconsequently, the cost of supply used to satisfy retail customer load obligations could cause earnings volatility. (PHI only)supplying electricity, are higher. Implementation for residential customers will be phased in commencing in 2012 through 2013. Implementation of dynamic pricing for commercial and industrial SOS customers in Delaware will be phased in commencing in 2013 through 2014.

Dynamic pricing has been approved in concept for Pepco Energy Services purchases energy commodity contractscustomers in Maryland, with phase-in for residential customers beginning in 2012. Pepco has dynamic pricing proposals pending in the formDistrict of electricity and natural gas futures, swaps, options and forward contracts to hedge commodity price risk in connectionColumbia jurisdiction with the purchase of natural gas and electricityproposed phase-in for deliveryresidential customers anticipated to customers. Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of forecasted transactions. Certain commodity contracts that do not qualify as cash flow hedges of forecasted transactions or do not meet the requirements for normal purchase and normal sale accounting are marked to market through current earnings. Any changebegin in the fair value of the transactions used to hedge price risk that receive mark-to-market accounting treatment will be reflected in PHI’s current earnings without any offsetting change in the fair value of its retail load obligations until the settlement date of these contracts in future periods. As a result, PHI’s earnings could be more volatile due to the mark-to-market accounting treatment for its commodity contracts.

Business operations could be adversely affected by terrorism.

The threat of, or actual acts of, terrorism may affect the operations of PHI and its subsidiaries in unpredictable ways and may cause changes in the insurance markets, force an increase in security measures and cause disruptions of fuel supplies and markets. If any of its infrastructure facilities, including its transmission or distribution facilities, were to be a direct target, or an indirect casualty, of an act of terrorism, the operations of PHI, Pepco, DPL or ACE could be adversely affected. Corresponding instability in the financial markets as a result of terrorism also could adversely affect the ability to raise needed capital.

Insurance coverage may not be sufficient to cover all casualty losses that the companies might incur.

PHI and its subsidiaries, including Pepco, DPL and ACE, 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. In addition, some risks, such as weather related casualties, may not be insurable. In the case of loss or damage to property, plant or equipment, there is no assurance that the insurance proceeds received, if any, will be sufficient to cover the entire cost of replacement or repair.

Revenues, profits and cash flows may be adversely affected by economic conditions.

Periods of slowed economic activity generally result in decreased demand for power, particularly by industrial and large commercial customers. As a consequence, recessions or other downturns in the economy may result in decreased revenues, profits and cash flows for the Power Delivery businesses of Pepco, DPL and ACE and the business of Pepco Energy Services.

The Internal Revenue Service (IRS) challenge to cross-border energy sale and lease-back transactions entered into by a PHI subsidiary could result in loss of prior and future tax benefits. (PHI only)

PCI maintains a portfolio of eight cross-border energy lease investments, which as of December 31, 2010, had an equity value of approximately $1.4 billion and from which PHI currently derives approximately $59 million per year in tax benefits in the form of interest and depreciation deductions in excess of rental income. PHI’s cross-border energy lease investments, each of which is with a tax-indifferent party, have been under examination by the IRS as part of the normal PHI federal income tax audits. In the final IRS revenue agent’s report issued in June 2006 and in March 2009 in connection with the audits of PHI’s federal 2001-2002, and 2003-2005 income tax returns, respectively, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to its cross-border energy lease investments. In addition, the IRS has sought to recharacterize the leases as loan transactions as to which PHI would be subject to original issue discount income. PHI disagrees with the IRS’ proposed adjustments and filed tax protests.

In November 2010, the IRS approved a settlement with respect to the 2001-2002 tax returns in which PHI agreed to a disallowance of its depreciation and interest deductions in excess of rental income, but reserved the right to file refund claims contesting the allowances. In January 2011, PHI paid $74 million of additional tax, plus penalties of $1 million, in accordance with the terms of the settlement. PHI intends to file a claim for refund for the disallowed deductions, pursue litigation against the IRS if claim is denied. The 2003-2005 case is currently pending with the IRS Appeals Office.

In the event that that IRS were to be successful in disallowing 100% of the tax benefits associated with these leases and recharacterizing these leases as loans, PHI estimates that, as of December 31, 2010, it would be obligated to pay approximately $692 million in additional federal and state taxes and $133 million of interest, of which $74 million2012. Dynamic pricing has been satisfied by the payment madeapproved in January 2011. In

addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due. PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a re-characterization of the leases as loans would be recoverableconcept pending AMI deployment authorization for DPL’s Maryland customers and has been deferred for ACE’s customers in the form of lower taxes over the remaining terms of the affected leases. Moreover, the entire amount of any additional tax would not be due immediately. Rather, the federal and state taxes would be payable when the open audit years are closed and PHI amends subsequent tax returns not then under audit.

To the extent that PHI does not prevail in this matter and suffers a disallowance of the tax benefits and incurs imputed original issue discount income due to the recharacterization of the leases as loans, PHI would be required under Financial Accounting Standards Board guidance on leases (Accounting Standards Codification (ASC) 840 and ASC 850) to recalculate the timing of the tax benefits generated by the cross-border energy lease investments and adjust the equity value of the investments, which would result in a non-cash charge to earnings that could be material.New Jersey.

For furthera discussion of this matter, see Part II, Item 8, Financial Statements and Supplementary Data — PHI — Note (17), “Commitments and Contingencies — Regulatory and Other Matters — PHI’s Cross-Border Energy Lease Investments,” of this Form 10-K.

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

PHI, Pepco, DPL and ACE each have significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. The companies rely primarily on cash flow from operations and access to the capital markets to meet these financing needs. The operating activities of the companies also require access to short-term money markets and bank financing as sources of liquidity that are not met by cash flow from operations. Adverse business developments or market disruptions could increase the cost of financing or prevent the companies from accessing one or more financial markets.

The financing costs of each of PHI, Pepco, DPL and ACE are closely linked, directly or indirectly, to its credit rating. The collateral requirements of Pepco Energy Services’ retail energy supply business also are determined in part by the unsecured debt rating of PHI. Negative ratings actions by one or more of the credit rating agencies resulting from a change in PHI’s or the utility’s operating results or prospects would increase funding costs and collateral requirements and could make financing more difficult to obtain.

Under the terms of PHI’s primary credit facilities, the consolidated indebtedness of PHI cannot exceed 65% of its consolidated capitalization. If PHI’s equity were to decline to a level that caused PHI’s debt to exceed this limit, lenders would be entitled to refuse any further extension of credit and to declare all of the outstanding debt under the credit facilities immediately due and payable. To avoid such a default, a renegotiation of this covenant would be required which would likely increase funding costs and could result in additional covenants that would restrict PHI’s operational and financing flexibility. Events that could cause a reduction in PHI’s equity include a further write down of PHI’s cross-border energy lease investments or a significant write down of PHI’s goodwill.

Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:

In accordance with the requirements of the Sarbanes-Oxley Act of 2002 and the SEC rules thereunder, PHI’s management is responsible for establishing and maintaining internal control over financial reporting and is required to assess annually the effectiveness of these controls. The inability to certify the effectiveness of these controls due to the identification of one or more material weaknesses in these controls also could increase financing costs or could adversely affect the ability to access one or more financial markets.

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, 2010, of approximately $1.4 billion, primarily attributable to Pepco’s acquisition of Conectiv in 2002. Under accounting principles generally accepted in the United States of America, an impairment charge must be recorded 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 a decline in PHI’s stock price causing market capitalization to fall further below book value, an adverse change in business conditions or an adverse regulatory action. 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 and results of operations, but would not have an impact on 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 performance of plan assets. If market performance decreases plan assets or changes in assumptions regarding the valuation of benefit obligations increase plan liabilities, PHI, Pepco, DPL or ACE 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 (the PHI Retirement Plan) and its postretirement 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 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 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 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 PHI, Pepco, DPL and ACE. Future increases in pension plan and other postretirement 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 results of operations and financial condition of PHI, Pepco, DPL and ACE.

PHI’s cash flow, ability to pay dividends and ability to satisfy debt obligations depend on the performance of its operating subsidiaries. PHI’s unsecured obligations are effectively subordinated to the liabilities and the outstanding preferred stock of its subsidiaries. (PHI only)

PHI is a holding company that conducts its operations entirely through its 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 the subsidiaries and the distribution of such earnings to PHI in the form of dividends. The 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. Because the claims of

the creditors of PHI’s subsidiaries and the preferred stockholders of ACE 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 and to the rights of the holders of ACE’s preferred stock to receive dividend payments.

Provisions of the Delaware General Corporation Law may discourage an acquisition of PHI. (PHI only)

As a Delaware corporation, PHI is subject to the business combination law set forth in Section 203 of the Delaware General Corporation Law, which could have the effect of delaying, discouraging or preventing an acquisition of PHI.

Because Pepco, DPL and ACE are direct or indirect wholly owned subsidiaries of PHI, PHI can exercise substantial control over their dividend policies and businesses and operations. (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. Among other decisions, each of Pepco’s, DPL’s and ACE’s board is responsible for decisions regarding payment of dividends, financing and capital raising activities and 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 the company’s earnings, cash flow and capital structure and also may take into account the business plans and financial requirements of PHI and its other subsidiaries.

Item 1B.

UNRESOLVED STAFF COMMENTS

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

Item 2.

PROPERTIES

Generating Facilities

The following table identifies the electric generating facilities owned by PHI’s subsidiaries at December 31, 2010.

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.

Transmission and Distribution Systems

On a combined basis, the electric transmission and distribution systems owned by Pepco, DPL and ACE at December 31, 2010, consisted of approximately 3,500 transmission circuit miles of overhead lines, 400 transmission circuit miles of underground cables, 18,600 distribution circuit miles of overhead lines, and 16,100 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 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,expenditures associated with a storage capacity of approximately 3 million gallons and an emergency sendout capability of 49,000 Mcf per day. DPL owns 8 natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 262,961 Mcf per day. DPL also owns approximately 104 pipeline miles of natural gas transmission mains, 1,912 pipeline miles of natural gas distribution mains, and 1,309 natural gas pipeline miles of 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 (11), “Debt” to the consolidated financial statements of PHI, set forth in Part II, Item 8 of this Form 10-K.

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 (17), “Commitments and Contingencies—Legal Proceedings,” to the consolidated financial statements of PHI, set forth in Part II, Item 8 of this Form 10-K.

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 (13), “Commitments and Contingencies—Legal Proceedings,” to the financial statements of Pepco, set forth in Part II, Item 8 of this Form 10-K.

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 (15), “Commitments and Contingencies—Legal Proceedings,” to the financial statements of DPL, set forth in Part II, Item 8 of this Form 10-K.

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 (14), “Commitments and Contingencies—Legal Proceedings,” to the consolidated financial statements of ACE, set forth in Part II, Item 8 of this Form 10-K.

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 pricesBlueprint for the common stock based on composite trading as reported by the New York Stock Exchange during each quarter in the last two years.