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Atlantic City Electric Co, et al. – ‘10-K’ for 12/31/09

On:  Thursday, 2/25/10, at 6:04pm ET   ·   As of:  2/26/10   ·   For:  12/31/09   ·   Accession #:  1193125-10-41024   ·   File #s:  1-01072, 1-01405, 1-03559, 1-31403

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  As Of               Filer                 Filing    For·On·As Docs:Size             Issuer                      Filing Agent

 2/26/10  Atlantic City Electric Co         10-K       12/31/09   68:18M                                    Donnelley … Solutions/FA
          Delmarva Power & Light Co/DE
          Potomac Electric Power Co
          Pepco Holdings Inc

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Table of Contents

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, 2009

Continued

Securities registered pursuant to Section 12(b) 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).     

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 2010 Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission on or about April 1, 2010 are incorporated by reference into Part III of this report.

Table of Contents

TABLE OF CONTENTS

Table of Contents

GLOSSARY OF TERMS

i

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ii

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Part I

Overview

Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a diversified energy company that, through its operating subsidiaries, is engaged primarily in two businesses:

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

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Conectiv is solely a holding company with no business operations. The activities of Potomac Capital Investment Corporation (PCI) are described below under the heading “Other Business Operations.”

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

Pepco Holdings’ management has identified its operating segments at December 31, 2009 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. 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. Each of Pepco, DPL and ACE has one operating segment.

Investor Information

Each of PHI, Pepco, DPL and ACE files reports under the Securities Exchange Act of 1934, as amended. The Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports, of each of the companies are made available free of charge on PHI’s internet Web site as soon as reasonably practicable after such documents are electronically filed with or furnished to the Securities and Exchange Commission (SEC). These reports may be found at http://www.pepcoholdings.com/investors.

Description of Business

The following is a description of each of PHI’s two principal business operations.

Power Delivery Business

The largest component of PHI’s business is Power Delivery, which consists of the transmission, distribution and default supply of electricity and the delivery and supply of natural gas. In 2009, 2008 and 2007, respectively, PHI’s Power Delivery operations produced 54%, 51%, and 56% of PHI’s consolidated operating revenues (including revenue from intercompany transactions) and 73%, 72%, and 66% of PHI’s consolidated operating income (including income from intercompany transactions).

Each of Pepco, DPL and ACE is a regulated public utility in the jurisdictions that comprise its service territory. Each company owns and operates a network of wires, substations and other equipment that is classified either as transmission or distribution facilities. Transmission facilities carry wholesale electricity into, or across, the utility’s service territory. Distribution facilities carry electricity to end-use customers in the utility’s service territory.

Delivery of Electricity, Natural Gas and Default Electricity Supply

Each of Pepco, DPL and ACE is responsible for the delivery of electricity and, in the case of DPL, natural gas, in its service territory, for which it is paid tariff rates established by the applicable local public service commission. Each company also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Offer Service (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.

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Effective January 2, 2008, DPL sold its retail electric distribution assets and its wholesale electric transmission assets in Virginia. This sale also terminated DPL’s obligations as a supplier of electricity to retail customers in its Virginia service territory who do not elect to purchase electricity from a competitive supplier.

In the aggregate, the Power Delivery business delivers electricity to more than 1.8 million customers in the mid-Atlantic region and distributes natural gas to approximately 123,000 customers in Delaware.

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. The Federal Energy Regulatory Commission (FERC) has designated a number of regional transmission organizations to coordinate the operation and planning of portions of the interstate transmission grid. Pepco, DPL and ACE are members of the PJM Regional Transmission Organization (PJM RTO). In 1997, FERC approved PJM Interconnection, LLC (PJM) as the provider of transmission service in the PJM RTO region, which currently consists 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. As the independent grid operator, PJM coordinates the electric power market and the movement of electricity within the PJM RTO region. Any entity that wishes to have electricity delivered at any point in the PJM RTO region must obtain transmission services from PJM, at rates approved by FERC. 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. Transmission rates are 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.

Seasonality

Power Delivery’s operating results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. In Maryland and the District of Columbia, however, the decoupling of distribution revenue for a given reporting period from the amount of power delivered during the period, as the result of the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers, has had the effect of eliminating changes in customer electricity usage due to weather conditions or other reasons as a factor having an impact on distribution revenue and income. The BSA took effect for Pepco and DPL in Maryland in 2007 and for Pepco in the District of Columbia in 2009.

Regulation

The retail operations of PHI’s utility subsidiaries, including the rates they are permitted to charge customers for the delivery 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 they provide utility service as follows:

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Blueprint for the Future

During 2007, Pepco, DPL and ACE each announced an initiative that they refer to as the “Blueprint for the Future.” This initiative includes installation of smart meters, further automation of the electric distribution system, and enhanced communication infrastructure, and combines traditional demand-side management (DSM) programs with new technologies and systems. Not all of these elements are being pursued in all jurisdictions, or within the same timeframe in all jurisdictions. All of these will help residential and non-residential customers manage their energy use, reduce the total cost of energy and provide other benefits. They also allow each utility to better manage and operate the electrical and gas systems.

The programs include energy efficiency and conservation efforts, such as rebates or other financial incentives for residential customers to replace inefficient appliances and for business customers to use more energy efficient equipment, such as improved lighting and heating, ventilation and air condition systems. Under another DSM program initiative, the companies are launching new residential demand response programs, under which customers have the option to receive utility-provided smart thermostats or outdoor smart direct load control equipment. The equipment will be used by each utility to reduce residential air conditioner load during times of high wholesale market prices or periods of system constraints. In exchange, customers will receive additional financial incentives through bill credits and or new dynamic pricing rate structures. In the future, the companies anticipate encouraging non-residential customer peak demand reductions through similar rate structures and select demand response enabling technology. Each utility’s ability to establish specific programs in its service territory is dependent upon public service commission approval.

Under the Blueprint for the Future program, Pepco and ACE each plan over time to install smart meters for all electric customers in their service territories, and DPL plans to install smart meters for all electric and natural gas customers in its service territory, as part of an advanced metering infrastructure (AMI) system. The smart meters will provide the utilities with the ability to remotely read meters, identify the location of power outages and provide customers with more detailed information concerning their energy consumption, among other abilities. The communications infrastructure utilized to communicate with the smart meters will be leveraged in the future to also support distribution system automation.

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The following is a discussion of the current regulatory status of each utilities Blueprint for the Future initiative:

Pepco

In April 2008, the MPSC approved Pepco’s proposed implementation of a new residential direct load control program for air conditioners. Pepco began installing residential direct load control equipment in Maryland in June 2009. In August 2009, the MPSC approved the implementation by Pepco of four residential and four non-residential DSM programs. On January 22, 2010, the MPSC approved surcharges for Pepco to recover the equipment costs for the direct load control program for air conditioners over a 15 year period and to recover the energy efficiency and conservation program costs over a five-year amortization period, with carrying costs set at the utility’s authorized rate of return. A proposal of Pepco before the MPSC for the implementation of an AMI system for its Maryland service territory is pending.

In March 2009, the DCPSC approved proposed budgets for five Pepco DSM programs. The cost recovery of these programs is through an existing surcharge. On December 17, 2009, the DCPSC issued an order permitting Pepco to implement an AMI system in the District of Columbia and establish a regulatory asset for AMI system costs. Pepco expect to commence AMI system deployment in the District of Columbia during the third quarter of 2010. On January 19, 2010, Pepco filed a revised residential direct load control program in the District of Columbia pursuant to a DCPSC order requesting the revised program proposal. In the filing, Pepco has proposed the recovery of the revised program costs through a new surcharge.

DPL

In April 2008, the MPSC approved DPL’s proposed implementation of a new residential direct load control program for air conditioners. DPL began installing residential direct load control equipment in Maryland in June 2009. In August 2009, the MPSC approved the implementation by DPL of four residential and four non-residential DSM programs. On January 22, 2010, the MPSC approved surcharges for DPL to recover the equipment costs for the direct load control program for air conditioners over a 15 year period and to recover the energy efficiency and conservation program costs over a five-year amortization period, with carrying costs set at the utility’s authorized rate of return.

In September 2008, the DPSC approved the establishment of a regulatory asset associated with the deployment of an AMI system in Delaware. In November 2009, DPL began full-scale installation of smart meters for all of its Delaware electric and gas customers. A proposal of DPL before the MPSC for the implementation of an AMI system for its Maryland service territory is pending.

ACE

In July 2009, the NJBPU issued an order approving ACE’s implementation of a new residential direct load control program. Cost recovery for the program will be through a surcharge. The NJBPU is not expected to approve ACE’s proposal for the installation of an AMI system in the near-term.

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 as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM RTO system. At that time, it was contemplated that the transmission line would originate at Possum Point substation in northern Virginia, connect into three substations across southern Maryland, cross the Chesapeake Bay, tie into two substations across the Delmarva Peninsula and terminate at Salem substation in southern New Jersey and would become operational by June 1, 2013. In December 2008, the PJM Board of Managers approved a direct-current technology for segments of the project including the portion under the Chesapeake Bay.

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In May 2009, the PJM Board revised its regional transmission expansion plan and (i) deferred until June 1, 2014, the date as of which the segment of the transmission line from Possum Point substation to the Indian River substation, the second substation on the Delmarva Peninsula, is required to be operational and (ii) determined that the Indian River to Salem portion of the proposed transmission line is not required at the present time. The proposed 150-mile transmission line from the Possum Point substation to the Indian River substation is referred to as the Mid-Atlantic Power Pathway (MAPP) project. The cost of the MAPP project, as currently constituted, is estimated at $1.2 billion.

PHI understands that PJM is in the process of reassessing reliability requirements of the PJM RTO system in the context of the preparation of its 2010 Regional Transmission Expansion Plan, which is scheduled to be completed in June 2010. This reassessment could result in a further deferral of the required operational date of all or a portion of the MAPP transmission line.

On January 14, 2010, the MPSC granted PHI’s request to suspend the procedural schedule on its application to build the MAPP project, pending completion of a study to re-evaluate the region’s over-all transmission needs by PJM, the independent regional power grid operator. This study is scheduled to be completed by June 2010 and will evaluate any impact on the planned in service date for the project.

MAPP/DOE Loan Program

PHI has applied for a $684 million loan guarantee from the Department of Energy (DOE) for a substantial portion of the MAPP project, primarily the Calvert Cliffs to Indian River segment. The loan guarantee is available under a federal loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes the guarantee would allow PHI to acquire financing at a lower cost than it would otherwise be able to obtain in the capital markets. Whether PHI’s application will be granted and, if so, the amount of debt guaranteed is subject to the discretion of the DOE and the negotiation of terms that will satisfy the conditions of the guarantee program.

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 suburban Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.1 million. As of December 31, 2009, Pepco delivered electricity to 778,000 customers (of which 252,000 were located in the District of Columbia and 526,000 were located in Maryland), as compared to 767,000 customers as of December 31, 2008 (of which 247,000 were located in the District of Columbia and 520,000 were located in Maryland).

In 2009, Pepco delivered a total of 26,549,000 megawatt hours of electricity, of which 29% was delivered to residential customers, 50% to commercial customers, and 21% to United States and District of Columbia government customers. In 2008, Pepco delivered a total of 26,863,000 megawatt hours of electricity, of which 29% was delivered to residential customers, 51% to commercial customers, and 20% 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, Pepco will continue to be obligated to provide SOS to residential and small commercial customers indefinitely, until further action of the Maryland General Assembly, and to medium-sized commercial customers through May 2011. Pepco purchases the power supply required to satisfy its SOS obligation from wholesale suppliers under contracts entered into pursuant to competitive bid procedures approved and supervised by the MPSC. Pepco also has an on-going obligation to provide SOS service, known as

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Hourly Priced Service (HPS), for the largest Maryland customers. Power to supply the SOS 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 the SOS supply plus an average margin of $.00165 per kilowatt-hour. Pepco is paid tariff delivery rates for the delivery 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 energy supplier.

Pepco has been providing SOS in the District of Columbia since February 2005. Pursuant to orders issued by the DCPSC, Pepco will continue to be obligated to provide SOS to residential and small and large commercial customers indefinitely. Pepco purchases the power supply required to satisfy its SOS obligation from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the DCPSC. Pepco is entitled to recover from its SOS customers the costs associated with the acquisition of the SOS supply, plus administrative charges that are intended to allow Pepco to recover the administrative costs incurred to provide the SOS. These administrative charges include an average margin for Pepco of $.00211 per kilowatt-hour. Because margins vary 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 load taken by such customers. Pepco is paid tariff delivery rates for the delivery 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 energy supplier.

For the year ended December 31, 2009, 49% of Pepco’s Maryland distribution sales (measured by megawatt hours) were to SOS customers, as compared to 50% in 2008, and 31% of its District of Columbia distribution sales were to SOS customers in 2009, as compared to 33% in 2008.

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 distributes natural gas to retail customers and provides transportation-only services to retail customers that purchase natural gas from another supplier.

Transmission and Distribution of Electricity

In Delaware, electricity service is provided in the counties of Kent, New Castle, and Sussex and in Maryland in the counties of Caroline, Cecil, Dorchester, Harford, Kent, Queen Anne’s, Somerset, Talbot, Wicomico and Worcester. Prior to January 2, 2008, DPL also provided transmission and distribution of electricity in Accomack and Northampton counties in Virginia. In January 2008, DPL completed the sale of its retail electric distribution assets and its wholesale electric transmission assets located on the Eastern Shore of Virginia.

DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.3 million. As of December 31, 2009 and 2008, DPL delivered electricity to 498,000 customers (of which 299,000 were located in Delaware and 199,000 were located in Maryland).

In 2009, DPL delivered a total of 12,494,000 megawatt hours of electricity to its customers, of which 39% was delivered to residential customers, 41% to commercial customers and 20% to industrial customers. In 2008, DPL delivered a total of 13,015,000 megawatt hours of electricity, of which 39% was delivered 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, DPL will continue to be obligated to provide SOS to residential, small commercial and industrial customers through May 2013 and to medium, large and general service commercial customers through May 2011. DPL purchases the power supply required to satisfy its SOS obligation from wholesale suppliers under

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contracts entered into pursuant to competitive bid procedures approved by the DPSC. DPL also has an obligation to provide SOS service, 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, transmission, and ancillary services costs and a Reasonable Allowance for Retail Margin (RARM). Components of the RARM 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 of the capitalized costs of the billing system used for billing HPS customers. DPL is paid tariff delivery rates for the delivery 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 energy supplier.

In Delaware, DPL distribution sales to SOS customers represented 51% of total distribution sales (measured by megawatt hours) for the year ended December 31, 2009, as compared to 55% in 2008.

DPL has been providing SOS in Maryland since June 2004. Pursuant to orders issued by the MPSC, DPL will continue to be obligated to provide SOS to residential and small commercial customers indefinitely until further action of the Maryland General Assembly, and to medium-sized commercial customers through May 2011. DPL purchases the power supply required to satisfy its SOS obligation from wholesale suppliers under contracts entered into pursuant to competitive bid procedures approved and supervised by the MPSC. DPL also has an on-going obligation to provide SOS service, known as HPS, for the largest Maryland customers. Power to supply the SOS 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 the SOS supply plus an average margin of $.00162 per kilowatt-hour. DPL is paid tariff delivery rates for the delivery 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 energy supplier.

In Maryland, DPL distribution sales to SOS customers represented 63% of total distribution sales (measured by megawatt hours) for the year ended December 31, 2009, as compared to 65% in 2008.

Natural Gas Distribution

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 transport natural gas for 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 delivery arrangements. For the year ended December 31, 2009, DPL supplied 68% of the natural gas that it delivered, compared to 65% in 2008.

As of December 31, 2009, DPL distributed natural gas to 123,000 customers as compared to 122,000 customers as of December 31, 2008. In 2009, DPL distributed 19,000,000 Mcf (thousand cubic feet) of natural gas to customers in its Delaware service territory, of which 42% were sales to residential customers, 25% to commercial customers, 1% to industrial customers, and 32% to customers receiving a transportation-only service. In 2008, DPL delivered 20,300,000 Mcf of natural gas, of which 38% were sales to residential customers, 24% were sales to commercial customers, 3% were sales to industrial customers, and 35% were sales to customers receiving a transportation-only service.

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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, 2009 and 2008, ACE delivered electricity to 547,000 customers in its service territory. In 2009, ACE delivered a total of 9,659,000 megawatt hours of electricity to its customers, of which 45% was delivered to residential customers, 45% to commercial customers and 10% to industrial customers. In 2008, ACE delivered a total of 10,089,000 megawatt hours of electricity to its customers, of which 44% was delivered to residential customers, 44% to commercial customers, and 12% 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 procure the supply to meet their BGS obligations from competitive suppliers selected through auctions authorized by the NJBPU for New Jersey’s total BGS requirements. The winning bidders in the auction are required to supply a specified 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 rates established by the NJBPU that compensate it for the cost of obtaining the BGS supply. ACE does not make any profit or incur any loss on the supply component of the BGS it provides to customers.

ACE is paid tariff delivery rates for the delivery 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 energy supplier.

ACE distribution sales to BGS customers represented 73% of total distribution sales (measured by megawatt hours) for the year ended December 31, 2009, as compared to 78% in 2008.

ACE has several contracts with non-utility generators (NUGs) under which ACE purchased 2.4 million megawatt hours of power in 2009. ACE sells the electricity purchased under the contracts with NUGs into the wholesale market administered by PJM.

In 2001, ACE established Atlantic City Electric Transition Funding LLC (ACE Funding) solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds have been 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

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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.

Competitive Energy Business

The Competitive Energy business provides competitive generation, marketing and supply of electricity and natural gas, and related energy management services primarily in the mid-Atlantic region. These operations are conducted through Conectiv Energy and Pepco Energy Services. For the years ended December 31, 2009, 2008 and 2007, Competitive Energy operations produced 49%, 53% and 48%, respectively, of PHI’s consolidated operating revenues and 20%, 36% and 26%, respectively, of PHI’s consolidated operating income.

Conectiv Energy

Conectiv Energy divides its activities into two operational categories: (i) Merchant Generation and Load Service and (ii) Energy Marketing.

Merchant Generation and Load Service

Conectiv Energy provides wholesale electric power, capacity and ancillary services in the wholesale markets and also supplies electricity to other wholesale market participants under long- and short-term bilateral contracts. Conectiv Energy supplies electric power to Pepco, DPL and ACE to satisfy a portion of their Default Electricity Supply load, as well as the default electricity supply load shares of other utilities within the PJM RTO and Independent System Operator – New England (ISONE) wholesale markets. As of January 1, 2010, ISONE load will be included in the Energy Marketing category. Conectiv Energy obtains the electricity required to meet these power supply obligations from its own generating plants, tolling agreements, bilateral contract purchases from other wholesale market participants and purchases in the wholesale market. Conectiv Energy’s primary fuel source for its generating plants is natural gas. Conectiv Energy manages its natural gas supply using a portfolio of long-term, firm storage and transportation contracts, and a variety of derivative instruments. Conectiv Energy refers to these activities, with the exception of its ISONE default service obligations, as Merchant Generation and Load Service.

Conectiv Energy’s generation capacity is concentrated in mid-merit plants, which due to their operating flexibility and multi-fuel capability can quickly change their output level on an economic basis. Like “peak-load” plants, mid-merit plants generally operate during times when demand for electricity rises and prices are higher. However, mid-merit plants usually operate more frequently and for longer periods of time than peak-load plants because of better heat rates. As of December 31, 2009, Conectiv Energy owned and operated mid-merit plants with a combined 2,250 megawatts of generating capacity, peak-load plants with a combined 722 megawatts of generating capacity, base-load generating plants with a combined 340 megawatts of generating capacity, and other plants with a combined 532 megawatts of generating capacity. See Item 2, “Properties,” of this Form 10-K. In addition to the generating plants it owns, Conectiv Energy controls another 389 megawatts of generating capacity through tolling agreements.

Conectiv Energy is constructing a 545 megawatt natural gas and oil-fired combined-cycle electricity generation plant located in Peach Bottom Township, Pennsylvania known as the Delta Project. The plant will be owned and operated as part of Conectiv Energy and is expected to go into commercial operation in 2011. Conectiv Energy has entered into a six-year tolling agreement with an unaffiliated energy company under which Conectiv Energy will sell the energy, generating capacity and most of the ancillary services from the plant for the period June 2011 through May 2017 to the other party. Under the terms of the

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tolling agreement, Conectiv Energy will be responsible for the operation and maintenance of the plant, subject to the other party’s control over the dispatch of the plant’s output. The other party will be responsible for the purchase and scheduling of the fuel to operate the plant and all required emissions allowances.

Energy Marketing

Conectiv Energy also sells natural gas and fuel oil to very large end-users and to wholesale market participants under bilateral agreements. Conectiv Energy obtains the natural gas and fuel oil required to meet these supply obligations through market purchases for next day delivery and under long- and short-term bilateral contracts with other market participants. In addition, Conectiv Energy operates a short-term power desk, which generates margin by identifying and capturing price differences between power pools and locational and timing differences within a power pool. Conectiv Energy also engages in power origination activities, which primarily represent the fixed margin component of structured power transactions such as default supply service. Conectiv Energy refers to these operations collectively as Energy Marketing. Beginning effective January 1, 2010, all elements of ISONE default electricity supply service will be included as part of Energy Marketing.

Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

Pepco Energy Services also has 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., Texas and the Chicago, Illinois areas and the sale of natural gas to customers located primarily in the mid-Atlantic region. On December 7, 2009, PHI announced that Pepco Energy Services will wind down its retail electricity and natural gas supply business and is not entering into any new retail energy supply contracts. To affect the wind-down, Pepco Energy Services will continue to fulfill all of its commercial and regulatory obligations and perform its customer service functions to ensure that it meets the needs of its customers. As of December 31, 2009, Pepco Energy Services’ estimated retail electricity backlog was approximately 20.1 million megawatts for delivery through 2014, a decrease of approximately 13.2 million megawatts when compared to December 31, 2008. 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,” of this Form 10-K.

Pepco Energy Services owns and operates two oil-fired generating plants. The plants are located in Washington, D.C. and have a generating capacity of approximately 790 megawatts. See Item 2, “Properties” of this Form 10-K. Pepco Energy Services sells the output of these plants into the wholesale market administered by PJM. In February 2007, Pepco Energy Services provided notice to PJM of its intention to deactivate these plants. Pepco Energy Services currently plans to deactivate both plants by May 2012. PJM has informed Pepco Energy Services that these facilities are not expected to be needed for reliability after that time, but that its evaluation is dependent on the completion of transmission and distribution upgrades. Pepco Energy Services’ timing for deactivation of the plants, in whole or in part,

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may be accelerated or delayed based on the operating condition of the plants, economic conditions, and reliability considerations. 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 plants that have a total generating capacity rating of ten megawatts, the output of which is sold into the wholesale market administered by PJM and a solar photovoltaic plant 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 down of the retail energy supply business.

Risk Management

PHI’s Competitive Energy business uses derivative instruments primarily to reduce their financial exposure to changes in the value of their assets and obligations due to commodity price fluctuations. The derivative instruments used by the Competitive Energy business include forward contracts, futures, swaps, and exchange-traded and over-the-counter options. In addition, the Competitive Energy business also manages commodity risk with contracts that are not classified as derivatives. The two primary risk management objectives are (1) to manage the spread between the cost of fuel used to operate electric generation plants and the revenue received from the sale of the power produced by those plants, and (2) to manage the spread between retail sales commitments and the cost of supply used to service those commitments to ensure stable cash flows, and lock in favorable prices and margins when they become available. To accomplish this, Conectiv Energy hedges a portion of the expected power output of its generation facilities and a portion the costs of fuel used to operate those facilities so it is not completely exposed to energy price movements.

Conectiv Energy employs dynamic option models to capture the value of its energy portfolio. Specifically for generation, the models compute the probability of run-time derived from forward market prices for power and fuel, and then compute the desired hedge positions, over the succeeding 36 months. Conectiv Energy executes power and fuel hedges according to the model’s projections if earnings are within defined parameters. Management exercises judgment in determining which months present the most significant risk, or opportunity, and hedge levels are adjusted accordingly. These adjustments will affect the results produced by the model. Because energy markets can move significantly in a short period of time, hedge levels may also be adjusted to reflect, among other factors, changes in projected plant output, revisions to fuel requirements, transmission constraints, prices of alternate fuels, and improving or deteriorating supply and demand conditions. In addition, short-term occurrences, such as abnormal weather, operational events, or intra-month commodity price volatility may also cause the actual level of hedging coverage to vary from the established hedge targets. These events can cause fluctuations in PHI’s earnings from period to period.

Since the inception of the Reliability Pricing Model (RPM) in PJM, Conectiv Energy has taken steps to ensure a reasonable return on its generation capacity. Prior to the commencement of the first RPM auction for the 2007-2008 PJM planning year, Conectiv Energy sold a portion of its capacity forward into the over-the-counter market in the event that auction prices settled low. Conectiv Energy continues to sell some of its capacity into the forward market when it believes prices are favorable. Conectiv Energy also reserves some of its capacity to serve full requirements load within PJM. Conectiv Energy recovers the value of this capacity by including it in the price offered for the bundled load service in individual load auctions.

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Due to the high heat rate of the Pepco Energy Services generating facilities, Pepco Energy Services generally does not enter into wholesale contracts to lock in the forward value of its plants.

Conectiv Energy’s risk management goals are approved by PHI’s Corporate Risk Management Committee and may change from time to time based on market conditions. For additional discussion of Conectiv Energy’s risk management Activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” set forth in Part II of this Form 10-K.

PJM Capacity Markets

A significant source of revenue for the Competitive Energy business is the sale of capacity by Conectiv Energy and Pepco Energy Services associated with their respective generating plants. 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 of electricity in the PJM market are required to maintain capacity from generating plants 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. All of the generating facilities owned by the Competitive Energy business 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.” One of the primary objectives of RPM is to encourage the development of new generation sources, particularly in constrained areas.

Under RPM, PJM has held six auctions, each covering capacity to be supplied over consecutive 12-month periods, with the most recent auction covering the 12-month period beginning June 1, 2012. Auctions of capacity for each subsequent 12-month delivery period will be held 36 months ahead of the scheduled delivery period. The next auction, for the period June 2013 through May 2014, will take place in May 2010. The Competitive Energy business is exposed to deficiency charges payable to PJM if their generation units fail 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 plants by May 2012, Pepco Energy Services did not include the plants’ capacity in the auction for the 12-month period beginning June 1, 2012, and will not include those plants in any other future capacity auctions.

In addition to participating in the PJM auctions, the Competitive Energy business participates in the forward capacity market as both sellers and buyers in accordance with PHI’s risk management policy, and accordingly, prices realized in the PJM capacity auctions may not be indicative of gross margin that PHI earns in respect of its capacity purchases and sales during a given period.

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Competition

The unregulated energy generation, supply and marketing businesses located primarily in the mid-Atlantic region are characterized by intense competition at the wholesale level. At the wholesale level, Conectiv Energy competes with numerous non-utility generators, independent power producers, wholesale power marketers and brokers, and traditional utilities that continue to operate generation assets. In providing energy management services, Pepco Energy Services competes with numerous other providers of the same energy management services. Competition in the wholesale energy market is based primarily on price. Competition in the market for energy management services is based primarily on price and, to a lesser extent, the range and quality of services offered to customers.

Seasonality

The power generation, supply and marketing businesses are seasonal and weather can have a material impact on operating performance. Demand for electricity generally is higher in the summer months associated with cooling and demand for electricity and natural gas generally is higher in the winter months associated with heating, as compared to other times of the year. Historically, the competitive energy operations of Conectiv Energy and Pepco Energy Services have generated less revenue when temperatures are warmer than normal in the winter and cooler than normal in the summer. Milder weather can also negatively impact gross margin from these operations. The energy management services of Pepco Energy Services generally are not seasonal.

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. As of December 31, 2009, PHI’s equity investment in its cross-border energy leases was approximately $1.4 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 set forth in Part II, Item 8 of this Form 10-K. This activity constitutes a separate operating segment for financial reporting purposes, which is designated “Other Non-Regulated.”

Employees

At December 31, 2009, PHI had 5,110 employees, including 1,291 employed by Pepco, 868 employed by DPL, 522 employed by ACE and 1,951 employed by PHI Service Company. The remaining employees were employed by the Competitive Energy business. Approximately 2,600 employees (including 1,014 employed by Pepco, 699 employed by DPL, 370 employed by ACE, 364 employed by the PHI Service Company, and 153 employed by the Competitive Energy business) are covered by collective bargaining agreements with various locals of the International Brotherhood of Electrical Workers.

Environmental Matters

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

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PHI’s subsidiaries’ currently projected capital expenditures plan for the replacement of existing or installation of new environmental control facilities that are necessary for compliance with environmental laws, rules or agency orders are approximately $34 million in 2010 and approximately $16 million in 2011. These expenditures include approximately $8 million for 2010 and $11 million for 2011, to comply with multipollutant regulations adopted by the Delaware Department of Natural Resources and Environmental Control (DNREC), as more fully discussed below. The actual costs of environmental compliance may be materially different from this capital expenditures plan 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.

Air Quality Regulation

The generating facilities and operations of PHI’s subsidiaries 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 CAA regulate total sulfur 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 PHI’s subsidiaries that require SO₂ allowances use allocated allowances or allowances acquired, as necessary, in the open market to satisfy the applicable regulatory requirements. Also, under current regulations implementing CAA standards, each of the states in which PHI subsidiaries own and operate generating units regulates nitrogen oxide (NOx) emissions from generating units and allocates NOx allowances. Most of the generating units operated by PHI subsidiaries are subject to NOx emission limits. These units use allocated allowances or allowances acquired, as necessary, in the open market to maintain compliance with the regulatory requirements during the calendar year and during the ozone season (May 1 to September 30).

In 2005, the United States Environmental Protection Agency (EPA) issued its Clean Air Interstate Rule (CAIR), which imposes further reductions of SO₂ and NOx emissions from electric generating units in 28 eastern states and the District of Columbia, including each of the states in which PHI subsidiaries own and operate generating units. CAIR uses an allowance system to cap state-wide emissions 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 are required beginning in 2010. States may implement CAIR by adopting EPA’s trading program or through regulations that at a minimum achieve the level of reductions that would be achieved through implementation of EPA’s program. Each state covered by CAIR 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. Generating 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.

In July 2008, the United States Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) vacated CAIR and remanded the rule to the EPA for further rulemaking to address the flaws it found with the rule, including EPA’s (1) failure to ensure that CAIR emission reductions from upwind states would assist downwind states in meeting air quality standards, (2) method for allocating SO₂ and NOx emission caps among the states and (3) efforts to terminate or limit acid rain SO₂ allowances. In December 2008, the D.C. Circuit, upon reconsideration, withdrew its vacatur of CAIR, and thus CAIR remains in effect pending rulemaking to address the flaws noted by the court, which EPA has indicated could take about two years.

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The states in which PHI subsidiaries own and operate generating units have either adopted regulations to implement CAIR or will require compliance with the federal CAIR program. In either case, the regulatory programs require, beginning in 2009, the surrender of one NOx annual allowance for each ton of NOx emitted during the year and one NOx ozone season allowance for each ton of NOx emitted during the ozone season; and between 2010 and 2014, the surrender of one acid rain SO₂ annual allowance for each 0.5 ton of SO₂ emitted during the year and beginning in 2015, one acid rain SO₂ allowance for each 0.35 ton of SO₂ emitted during the year. New Jersey adopted regulations to implement CAIR for both SO₂ and NOx but has elected to allocate fewer NOx annual and NOx ozone season allowances to New Jersey sources than would be permitted by CAIR, including Conectiv Energy’s Carlls Corner, Cedar, Cumberland, Deepwater, Middle, Mickleton, and Sherman generating units. Conectiv Energy’s Edge Moor, Christiana and Hay Road generating units in Delaware are subject to federal CAIR for NOx and SO₂. Pennsylvania promulgated CAIR regulations for NOx and SO₂ in 2008 that are applicable to Conectiv Energy’s Bethlehem generating units and the Delta plant that is under construction. Virginia is implementing CAIR by participating in EPA’s cap and trade program making Conectiv Energy’s Tasley peaking unit subject to federal CAIR for NOx and SO₂. Conectiv Energy’s other generating units in Maryland, Virginia Delaware, and New Jersey have an electric output (megawatts) rating lower than CAIR’s applicability threshold and therefore are not subject to CAIR.

Pepco Energy Services’ Benning Road generating units located in the District of Columbia are subject to CAIR. 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.

In 2009, Conectiv Energy installed water injection pollution control equipment on its five stationary combustion turbines in Delaware (at Christiana 11 and 14, Edge Moor 10, Delaware City 10 and West 10) to comply with new ozone season NOx emission limits applicable to stationary generators at a cost of $6 million.

Conectiv Energy and Pepco Energy Services units that are subject to CAIR use NOx annual, NOx ozone season and SO₂ allowances allocated or acquired, as necessary, in the open market to comply with CAIR. Although implementation of CAIR will increase costs for Conectiv Energy and Pepco Energy Services units, PHI currently does not anticipate that CAIR will have a material adverse impact on its results of operations, financial position or cash flows.

Federal Regional Haze Rule

In 1999, EPA promulgated the federal Regional Haze Rule to address a type of visibility impairment known as regional haze created by the emission of identified pollutants by certain types of large stationary sources. EPA amended the rule in 2005, following a decision by the D.C. Circuit striking down portions of the original rule. The regulation requires installation of best available retrofit technology (BART) to boilers that emit 250 tons or more per year of a visibility-impairing air pollutant, were placed in service between 1962 and 1977, and which may reasonably be anticipated to cause or contribute to visibility impairment in any federally protected park or wilderness area. Such sources are known as BART-eligible sources. Pepco Energy Services’ Benning Road generating units are BART-eligible sources for particulate matter less than ten microns in diameter (PM₁₀ ) and for SO₂ and NOx to the extent not addressed by CAIR. Pepco Energy Services is evaluating the manner of addressing BART, including ceasing operation of the Benning Road generating units consistent with its previously announced plan to deactivate those units. Pepco Energy Services’ Buzzard Point generating units and its landfill gas generating units are not subject to BART. Conectiv Energy’s Edge Moor units 4 and 5 in Delaware are BART-eligible units for particulate matter, SO_2, NOx and ammonia. DNREC has concluded that Edge Moor units 4 and 5 demonstrate BART compliance by complying with the Delaware multipollutant regulations described below. No other Conectiv Energy unit is a BART-eligible source.

New Jersey Multipollutant Regulations

In March 2009, the New Jersey Department of Environmental Protection (NJDEP) adopted amendments to its air pollution control regulations applicable to generating units in New Jersey to implement a multipollutant strategy to reduce fine particulate matter,

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SO₂ and NOx emissions from coal-fired boilers serving electric generating units and NOx emissions from high electric demand day (HEDD) units (units capable of generating 15 or more megawatts that are operated for 50 percent or less of the time during the ozone season). The units to which the amendments apply also are subject to CAIR requirements, and accordingly the units must hold sufficient NOx and SO₂ allowances under CAIR to cover their NOx and SO₂ emissions.

The following Conectiv Energy units in New Jersey qualify as HEDD units: Deepwater 1, Carlls Corner 1 and 2, Cedar 1W, 1E and 2, Cumberland 1, Mickleton 1, Middle 1, 2, and 3, Missouri Avenue B, C, and D, and Sherman Avenue 1. For the period May 1, 2009 through September 30, 2014, the regulations do not impose specific NOx emission limits at any specific source, but rather require reductions of NOx emissions from units that Conectiv Energy chooses to operate in accordance with a protocol that Conectiv Energy submitted to NJDEP in May 2009 and subsequently revised in December 2009. The protocol requires Deepwater Unit 6/8 to use selective non-catalytic reduction to reduce NOx emissions when it is operating above 55 MW during HEDDs, and requires that a certain combination of units at the Carlls Corner and Middle stations be placed in Maximum Emergency Generation Alert status during HEDDs, meaning that the units operate only if PJM declares a maximum emergency in its region. Beginning in May 2015, the regulations establish specific maximum allowable NOx emission rates for HEDD units. Conectiv Energy is evaluating its options for complying with these more stringent emissions requirements, and is developing a 2015 HEDD Emission Limit Achievement Plan, which it is required to submit to the NJDEP by May 1, 2010. The cost of the compliance options is still being evaluated.

Conectiv Energy’s Deepwater Unit 6/8 is subject to the NJDEP multipollutant regulations applicable to coal-fired boilers serving electric generating units. These regulations require compliance with a 0.03 lb/mmbtu particulate emission rate, 0.25 lb/mmbtu (daily average) and 0.15 lb/mmbtu (30-day average) SO₂ emission rates, and a 1.5 lb/MWh NO_x emission rate by December 15, 2012. Under the regulations, Deepwater Unit 1 also must comply with a more stringent NOx emission rate by 2012. The regulations also impose even more stringent NOx emission rates on Deepwater Units 1 and 6/8 effective May 1, 2015. Estimated expenditures for compliance with these new emission rates are $2 million in 2012 and $7 million in 2014.

Delaware Multipollutant Regulations

In November 2006, DNREC adopted multipollutant regulations that require large coal-fired and residual oil-fired electric generating units to develop control strategies to address air quality in Delaware. These control strategies are intended to assure attainment of ambient air quality standards for ozone and fine particulate matter, address local scale fine particulate emission problems, reduce mercury emissions, improve visibility and help satisfy Delaware’s regional haze obligations. For Conectiv Energy’s Edge Moor coal-fired units, these regulations establish stringent short-term limits for emissions of NOx, SO₂ and mercury, and for Edge Moor’s residual oil-fired generating unit, impose more stringent sulfur in fuel oil limits and establish stringent short-term limits for NOx emissions. The regulations also cap annual mass emissions of NOx and SO₂ from Edge Moor’s coal-fired and residual oil-fired units, and mercury from Edge Moor’s coal-fired units. In December 2006, Conectiv Energy filed a complaint with the Delaware Superior Court seeking review of the adoption of the new regulations. In December 2008, Conectiv Energy reached a settlement with DNREC. Under the terms of the settlement agreement, Conectiv Energy will comply with the NOx, SO₂ and mercury emission reduction requirements by the regulatory compliance dates, except that it will comply with the Phase II mercury emission limit by January 1, 2012, which is one year earlier than the regulatory compliance date, and DNREC agreed to increase the annual SO₂ mass emission limit as it relates to the Edge Moor residual oil-fired generating unit. Through December 31, 2009, Conectiv Energy has expended approximately $62 million to install new pollution control equipment and/or enhance existing equipment at its Edge Moor facility to comply with the multipollutant regulations. Conectiv Energy currently estimates that it will incur $19 million in additional expenditures over the next two years to install the control equipment necessary to comply with the regulations, with anticipated expenditures of approximately $8 million in 2010 and $11 million in 2011. These estimated costs do not include increased costs associated with operating control equipment.

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Hazardous Air Pollutant Emissions

In a March 2005 rulemaking, EPA removed coal- and oil-fired electric generating units from the list of source categories requiring Maximum Achievable Control Technology for hazardous air pollutants such as mercury and nickel under CAA Section 112, thus, for the time being, eliminating the possibility that control devices would be required under this section of the CAA to reduce nickel emissions from the residual oil-fired unit at Conectiv Energy’s Edge Moor generating facility. In a decision issued in February 2008, the U.S. Court of Appeals for the District of Columbia Circuit determined that the delisting of coal- and oil-fired units from regulation under CAA Section 112 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 the EPA an Information Collection Request (ICR) under Section 114 of the Clean Air Act, requesting that Benning Units 15 and 16 provide information that will allow EPA to assess the emissions of hazardous air pollutants from those Units. Conectiv Energy received a similar ICR regarding Deepwater Unit 6/8 and Edge Moor Units 3, 4 and 5. EPA has provided ICRs to numerous other coal-and oil-fired electric utility steam generating units. The requested information includes historical data with respect to Benning Unit 15 and Benning Unit 16, Deepwater Unit 6/8, Edge Moor Units 3, 4, and 5, as well as data to be obtained by stack testing during the operation of Benning Unit 16 and Edge Moor Units 4 and 5. Pepco Energy Services and Conectiv Energy are analyzing the requirements of the ICR and the actions necessary to comply.

In December 2004, NJDEP published final rules regulating mercury emissions from coal-fired boilers and certain other industrial facilities, effective December 15, 2007. Conectiv Energy has confirmed, based upon the monitoring of mercury emissions that Deepwater, Conectiv Energy’s only coal-fired generating facility in New Jersey, complies with the mercury emissions limit without the need for the installation of additional pollution control equipment.

Carbon Dioxide Emissions

Delaware, Maryland and New Jersey (along with Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, Vermont and New York) are signatories to the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by ten Northeast and mid-Atlantic states to first stabilize and, beginning in 2015, incrementally reduce carbon dioxide (CO₂) emissions with the goal of achieving an overall 10% reduction from baseline by 2018. Under RGGI, each of the participating states has adopted legislation or regulations to implement a regional CO₂ budget and an allowance trading program to regulate emissions from fossil fuel-fired electric generating units rated at 25 megawatts or greater. Under the program each covered fossil fuel-fired electric generating unit is required, commencing January 1, 2009, to hold allocated CO₂ allowances or allowances acquired in the open market equivalent to its CO₂ emissions during specified compliance periods. Beginning in 2009, all covered CO₂ sources were required to have an approved plan to monitor tons of CO ₂ emitted. The Maryland and New Jersey CO₂ allowance trading programs each provides for auction of substantially all of the allowances allocated to the state by RGGI. In 2009 Delaware auctioned 60% of allowances and allocated 40% of allowances to existing CO₂ sources. For each year after 2009, Delaware will increase the percentage of allowances for auction by 8%, such that 100% of allowances will be auctioned in 2014. The first compliance period is the three-year period from 2009 to 2011. The period may be extended to four years if a safety-valve mechanism is triggered by meeting certain market price targets. In early 2012, each source will be required to surrender one CO₂ allowance for each ton of CO₂ emitted during the first compliance period. Conectiv Energy participated in each of the four quarterly 2009 RGGI auctions and anticipates participating in subsequent RGGI auctions as necessary.

In February 2007, the New Jersey Governor signed an Executive Order that requires New Jersey to stabilize its statewide greenhouse gas emissions at 1990 levels by 2020, and to reduce statewide greenhouse gas emissions to 80% below 2006 levels by 2050. The Executive Order requires NJDEP to coordinate with NJBPU, New Jersey’s Department of Transportation, New Jersey’s Department of

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Community Affairs and other interested parties to evaluate policies and measures that will enable New Jersey to achieve the statewide greenhouse gas emissions reduction levels set forth in the Executive Order. In July 2007, New Jersey enacted legislation requiring NJDEP to promulgate regulations that establish a statewide greenhouse gas emissions monitoring and reporting program covering all sources within the state to evaluate progress toward the 2020 and 2050 greenhouse gas limits. In January 2009, NJDEP published proposed rules establishing such a program. This initiative is in addition to New Jersey’s participation in RGGI, which addresses emissions only from fossil fuel-fired electric generating units.

In October 2009, EPA issued its final greenhouse gas (GHG) reporting rule, which requires annual reporting of GHGs from all sectors of the economy. The regulations do not require GHG controls, but establish thresholds of regulated GHGs – CO₂, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and other fluorinated gases (e.g., nitrogen trifluoride and hydrofluorinated ethers) – which trigger an annual reporting requirement. The first annual report is for calendar year 2010 and is due March 31, 2011. Under the regulations, DPL’s gas distribution operations will be required, beginning with calendar year 2010, to report CO₂ emissions that would result assuming the complete combustion or oxidation of the annual volume of natural gas it distributes to its customers. Although Conectiv Energy’s generating units are subject to the regulations, the operating permits for most of Conectiv Energy’s generating units already require quarterly reporting of GHG emissions to EPA. Contrary to an earlier proposal, the final regulations do not require the reporting of sulfur hexafluoride (SF₆) emissions from electrical equipment, which would have applied to ACE, DPL and Pepco.

In December 2009, the EPA Administrator issued a finding that “greenhouse gases in the atmosphere may reasonably be anticipated both to endanger public health and to endanger public welfare.” This finding triggers a requirement for further regulatory action to set standards for the control of emissions of GHGs. The EPA finding relates to emissions from new motor vehicles, and EPA has stated its intent to control tailpipe emissions of GHGs beginning with new motor vehicle model year 2012. By law, EPA has until March 31, 2010 to impose regulations on model year 2012 motor vehicles. Once EPA establishes regulations to control tailpipe emissions of GHGs, GHGs become pollutants “subject to regulation” under the CAA. Under the Prevention of Significant Deterioration (PSD) requirements of the CAA, all new and modified major stationary sources of any pollutant subject to regulation must control emissions of that pollutant with the best available control technology (BACT). Accordingly, following EPA’s establishment of GHGs as pollutants subject to regulation, any major source of GHG emissions that Conectiv Energy or Pepco Energy Services modifies or constructs will be required to undergo a BACT analysis for GHGs, and GHG emission limits will be incorporated into the new or modified source’s operating permits. Under the current PSD program, a source is considered major if it emits 250 tons per year or more of any air pollutant, or 100 tons per year from certain source categories specified in the CAA. Because sources typically emit far greater quantities of GHGs than other pollutants, Conectiv Energy’s and Pepco Energy Services’ sources that have not previously been considered major would become major under the 250 or 100 tons per year major source thresholds. In October 2009, EPA proposed a rule that would increase the major source thresholds solely for GHG emissions to 25,000 and 10,000 tons per year. If that rule is adopted as proposed, Conectiv Energy and Pepco Energy Services sources that are not currently considered major are much more likely to remain so following EPA’s establishment of GHGs as pollutants subject to regulation.

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 CWA requires that any person wishing to discharge pollutants from a point source (generally a confined, discrete conveyance such as a pipe) obtain a National

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Pollutant Discharge Elimination System (NPDES) permit issued by EPA or by a state agency under a federally authorized state program. Each of the steam-electric generating facilities operated by PHI’s subsidiaries has a NPDES permit authorizing pollutant discharges, which is subject to periodic renewal.

In July 2004, EPA issued final regulations under Section 316(b) of the CWA that were intended to minimize potential adverse environmental impacts from power plant cooling water intake structures on aquatic resources by establishing performance-based standards for the operation of these structures at large existing electric generating plants, including Conectiv Energy’s Deepwater and Edge Moor generating facilities and Pepco Energy Services’ Benning Road generating facility. In January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision in Riverkeeper, Inc. v. United States Environmental Protection Agency (commonly known as the Riverkeeper II decision), that remanded to EPA for additional rulemaking substantial portions of these regulations for large existing electric generating plants. As a result, EPA suspended the regulations pending the additional rulemaking required by the Riverkeeper II decision. Subsequently, the operators of a number of electric generating plants, including a consortium in which Conectiv Energy is a member, challenged certain aspects of the Second Circuit’s decision before the U.S. Supreme Court. In an April 2009 opinion, the Supreme Court reversed in part the judgment of the Second Circuit. Although EPA is conducting additional rulemaking as a result of the Riverkeeper II decision, as modified by the Supreme Court’s partial reversal, proposed regulations have not been published. Those regulations, when issued, may require changes to cooling water intake system operations or intake structures as part of the NPDES permit renewal process. The capital expenditures for Conectiv Energy and Pepco Energy Services, if any, that may be needed as a consequence of the new regulations will not be known until the rulemaking process is concluded.

EPA has delegated authority to administer the NPDES program to a number of state agencies including DNREC. The NPDES permit for Conectiv Energy’s Edge Moor generating facility expired on October 30, 2003, but has been administratively extended until DNREC issues a renewal permit. Conectiv Energy submitted a renewal application to the DNREC in April 2003. Studies required under the existing permit to determine the impact on aquatic organisms of the plant’s cooling water intake systems were completed in 2002. Site-specific alternative technologies and operational measures have been evaluated and discussed with DNREC. DNREC, however, has not announced how it intends to address Section 316(b) requirements in the renewal NPDES permit in light of the suspended federal regulations.

Under the New Jersey Water Pollution Control Act, NJDEP implements regulations, administers the New Jersey Pollutant Discharge Elimination System (NJPDES) program with EPA oversight, and issues and enforces NJPDES permits. In July 2009, NJDEP issued a renewal NJPDES permit for the Deepwater generating facility. In connection with the issuance of the renewal permit, the NJDEP concluded that Deepwater’s cooling water intake system satisfies applicable requirements for protection of the environment, including CWA Section 316(b). Nevertheless, the additional rulemaking EPA will conduct as a result of the Riverkeeper II decision, as modified by the Supreme Court’s partial reversal, may require reevaluation of the design and/or operational measures that Conectiv Energy anticipates using for future compliance with Section 316(b) at Deepwater.

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 (TMDL) 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 BMPs for minimizing the presence of the substances in storm water. The capital expenditures, if any, that may be needed to implement BMPs to satisfy these new permit conditions will not be known until these studies are completed.

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New Jersey Flood Hazard Area Control Act

NJDEP has adopted amendments to the agency’s regulations under the Flood Hazard Area Control Act (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 that was 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, ACE filed an appeal of these regulations with the Appellate Division 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 case is currently in the briefing process before the appellate court.

New Jersey Freshwater Wetlands Protection Act

NJDEP has adopted amendments to the agency’s regulations under the Freshwater Wetlands Protection Act (FWPA). The amended regulations became effective on November 2, 2009 and include a new requirement for mitigation following construction activity under FWPA general permits for underground and above ground utility lines that results in the permanent loss or disturbance of 0.1 acres or more of affected wetlands. ACE believes that the amended regulations unnecessarily restrict various types of electric transmission and distribution system maintenance and construction activity and is evaluating whether to appeal the regulations to the Appellate Division of the Superior Court of New Jersey.

EPA Oil Pollution Prevention Regulations

In 2002, EPA amended its oil pollution prevention regulations to require facilities that, because 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, 2010. 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 $58 million. PHI does not expect the compliance costs for Conectiv Energy and Pepco Energy Services to be material.

Hazardous Substance Regulation

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) authorizes EPA, and comparable state laws authorize state environmental authorities, to issue orders and bring enforcement actions to compel responsible parties to investigate and take remedial actions at any site that is determined to present an actual or potential threat to human health or the environment because of an actual or threatened release of one or more hazardous substances. Parties that generated or transported hazardous substances to such sites, as well as the owners and operators of such sites, may be deemed liable under CERCLA or comparable state laws. Pepco, DPL and ACE each has been named by EPA or a state environmental agency as a potentially responsible party in pending proceedings involving certain contaminated sites. See (i) Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Capital Requirements – Environmental Remediation Obligations,” and (ii) Note (17), “Commitments and Contingencies – Legal Proceedings – Environmental Litigation” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.

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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.

The regulated utilities that comprise PHI’s 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 state regulatory agencies in its service territories, with respect to, among other things, the rates it can charge retail customers for the supply and distribution of electricity (and additionally for DPL the supply and distribution 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 supply, distribution, or transmission rates without approval by the applicable regulatory authority. While the approved distribution and transmission rates are intended to permit the companies to recover their costs of service and earn a reasonable rate of return, 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 transmission and distribution 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 subsidiaries that are regulated subsidiaries, as well as subsidiaries engaged in the Competitive Energy business, are required to have numerous permits, approvals and certificates from governmental agencies that regulate their businesses. PHI believes that each of its subsidiaries has, and each of Pepco, DPL and ACE believes it has, obtained or sought renewal of the material permits, approvals and certificates necessary for its existing operations and that its business is conducted in accordance with applicable laws; however, none of the companies is 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 more of PHI’s subsidiaries to incur additional expenses or significant capital expenditures or to change the way it conducts its operations.

Pepco may be required to make additional divestiture proceeds gain-sharing payments to customers in the District of Columbia. (PHI and Pepco only)

Pepco currently is involved in regulatory proceedings in the District of Columbia related to the sharing of the net proceeds from the sale of its generation-related assets. The principal issue in the proceedings is whether Pepco should be required to share with customers the excess deferred income taxes and accumulated deferred investment tax credits associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations. Depending on the outcome of the proceedings, Pepco could be required to make additional gain-sharing payments to customers and payments to the Internal Revenue Service (IRS) in the amount of the associated accumulated deferred investment tax credits, and Pepco might be unable to use accelerated depreciation on District of Columbia allocated or assigned property. See Item 8, “Financial Statements and Supplemental Data—Note (17) Commitments and Contingencies—District of Columbia Divestiture Case,” of this Form 10-K for additional information.

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The operating results of the Power Delivery business and the Competitive Energy business 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 electricity and natural gas is generally higher in the winter months associated with heating as compared to other times of the year. Accordingly, each of PHI, Pepco, DPL and ACE historically has generated less revenue and income when temperatures are warmer than normal in the winter and cooler than normal in the summer. The adoption in 2007, for retail customers of Pepco and DPL in Maryland and in 2009 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 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 electricity 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 performance continues to be affected by weather conditions.

Historically, the competitive energy operations of Conectiv Energy and Pepco Energy Services also have produced less gross margin when weather conditions are milder than normal, which can negatively impact PHI’s income from these operations. The energy management services business of Pepco Energy Services 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 the Competitive Energy business’ generation facilities 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 keep them operating at peak efficiency, to comply with changing environmental requirements, or to provide reliable operations. Natural disasters and weather-related incidents, including tornadoes, hurricanes and snow and ice storms, also can disrupt generation, transmission and distribution delivery systems. Operation of generation, transmission and distribution facilities below expected capacity 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 generation facilities at a rate of up to two times the capacity payment that the generation facility receives. Furthermore, the generation and transmission facilities of the PHI companies are subject to reliability standards imposed by the North American Electric Reliability Corporation. Failure to comply with the standards may result in substantial monetary penalties.

PHI’s announced Blueprint for the Future program includes the replacement of customers’ existing electric and gas meters with an advanced metering infrastructure (AMI) system. In addition to the replacement of existing meters, the AMI system involves the construction of a wireless network across the service territories of PHI’s utility subsidiaries and the implementation and integration of new and existing information technology systems to collect and manage the data made available by the advanced meters. The implementation of the AMI system involves a combination of technologies provided by multiple vendors. If the AMI system results in lower than projected performance, PHI’s utility subsidiaries could experience higher than anticipated maintenance expenditures, which could have a material adverse effect on their, and correspondingly PHI’s, results of operations.

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The transmission facilities 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 directly interconnected with the transmission facilities of contiguous utilities and, as such, 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. In 1997, FERC approved PJM as the provider of transmission service in the PJM RTO region, which currently consists 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. Pepco, DPL and ACE operate their transmission facilities under the direction and control of PJM. 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 impact 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 always be adequate to prevent problems at other utilities from causing service interruptions in the transmission facilities of Pepco, DPL or ACE. If any of Pepco, DPL or ACE were to suffer such a service interruption, it could have a negative impact on it and on PHI.

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, rules and regulations relating to air quality, water quality, spill prevention, waste management, natural resources, 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 in the assessment of civil or criminal penalties and liabilities and the need to expend significant sums to come into 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 CO ₂ and other greenhouse gas emissions on the global climate. As a result, it is likely that, in addition to existing RGGI requirements in effect in Maryland, New Jersey, Delaware and other northeast states, new and more far reaching state regulations will be developed in the region that will impose more stringent limitations on emissions than are currently in effect. In addition, the U.S. Congress is considering climate change legislation, including the possibility of a carbon cap and trade program.

The adoption of a federal cap and trade program for CO₂ and other greenhouse gases could require PHI’s Conectiv Energy and Pepco Energy Services businesses to incur increased capital expenditures or operating costs associated with one or more of their generating units to replace existing equipment, install additional pollution control equipment or purchase of CO₂ allowances and offsets. Alternatively, Conectiv Energy or Pepco Energy Services could be required to discontinue or curtail the operations of one or more units.

A cap and trade program also would likely increase the wholesale cost of power purchased by the Power Delivery business for supply to customers. It is likely that CO₂ allowance costs will be factored into dispatch pricing in the competitive electricity markets along with fuel and other operating costs. If the price of wholesale electricity increases due to climate change regulation, it will be necessary for the electric distribution companies to pass-through the escalated cost of power purchased by the Power Delivery business for supply to customers.

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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, to implement its business strategy is dependent on its ability to recruit, retain 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 company’s business, operations and financial condition.

PHI’s Competitive Energy business is highly competitive. (PHI only)

The unregulated energy generation, supply and marketing businesses, which are primarily in the mid-Atlantic region, are characterized by intense competition at both the wholesale and retail levels. PHI’s Competitive Energy business competes with numerous non-utility generators, independent power producers, wholesale and retail energy marketers, and traditional utilities. This competition generally has the effect of reducing margins and requires a continual focus on controlling costs.

PHI’s Competitive Energy business relies on some generation, transmission, storage, and distribution assets that they do not own or control to deliver wholesale and retail electricity and natural gas and to obtain fuel for their generation facilities. (PHI only)

PHI’s Competitive Energy business depends on electric generation and transmission facilities, natural gas pipelines, and natural gas storage facilities owned and operated by others. The operation of their generation facilities also depends on coal, natural gas or diesel fuel supplied by others. If electric generation or transmission, natural gas pipelines, or natural gas storage are disrupted or capacity is inadequate or unavailable, the Competitive Energy business’ ability to buy and receive and/or sell and deliver wholesale and retail power and natural gas, and therefore to fulfill their contractual obligations, could be adversely affected. Similarly, if the fuel supply to one or more of their generating plants is disrupted and storage or other alternative sources of supply are not available, the Competitive Energy business’ ability to operate their generating facilities could be adversely affected.

Changes in technology may adversely affect the Power Delivery business and the Competitive Energy business.

Research and development activities are ongoing to improve alternative technologies to produce electricity, including fuel cells, wind energy, micro turbines and photovoltaic (solar) cells. It is possible that advances in these or other alternative technologies will reduce the costs of electricity production from these technologies, thereby making the generating facilities of the Competitive Energy business less competitive. In addition, increased conservation efforts and advances in technology could reduce demand for electricity supply and distribution, which could adversely affect the Power Delivery business of Pepco, DPL and ACE and the Competitive Energy business. Changes in technology also could alter the channels through which retail electricity is distributed to customers which could adversely affect the Power Delivery businesses of Pepco, DPL and ACE.

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PHI’s risk management procedures may not prevent losses in the operation of its Competitive Energy business. (PHI only)

The operations of PHI’s Competitive Energy business 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. In particular, risks in PHI’s energy commodity activities are measured and monitored utilizing value-at-risk models to determine the effects of potential one-day favorable or unfavorable price movements. These estimates are based on historical price volatility and assume a normal distribution of price changes and a 95% probability of occurrence. Consequently, if prices significantly deviate from historical prices, PHI’s risk management systems, including assumptions supporting risk limits, may not protect PHI from significant losses. In addition, adverse changes in energy prices may result in economic losses in PHI’s earnings and cash flows and reductions in the value of assets on its balance sheet under applicable accounting rules.

The commodity hedging procedures used by the Competitive Energy business may not protect it from significant losses caused by volatile commodity prices. (PHI only)

To lower the financial exposure related to commodity price fluctuations, PHI’s Competitive Energy business routinely enters into contracts to hedge the value of its assets and operations. As part of this strategy, PHI’s Competitive Energy business utilizes fixed-price, forward, physical purchase and sales contracts, tolling agreements, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Each of these various hedge instruments can present a unique set of risks in its application to Conectiv Energy’s energy assets. Conectiv Energy must apply judgment in determining the application and effectiveness of each hedge instrument. New accounting rules, or revised interpretations to existing rules, may cause hedges to be deemed ineffective as an accounting matter. This could have material earnings implications for the period or periods in question.

Conectiv Energy’s objective is to hedge a portion of the expected power output of its generation facilities and a portion of the costs of fuel used to operate those facilities so it is not completely exposed to energy price movements. Conectiv Energy employs dynamic option models to capture the value of its energy portfolio. Specifically for generation, the models compute the probability of run-time derived from forward market prices for power and fuel, and then computes the desired hedge positions over the next 36 months with the objective of optimizing the value of its generating plants. Conectiv Energy executes power and fuel hedges according to the model’s projections. Management exercises judgment in determining which months present the most significant risk or opportunity, and hedge levels are adjusted accordingly within risk management guidelines. Since energy markets can move significantly in a short period of time, hedge levels may also be adjusted to reflect revised assumptions, such assumptions may include, but are not limited to, changes in projected plant output, revisions to fuel requirements, transmission constraints, prices of alternate fuels, and improving or deteriorating supply and demand conditions. In addition, short-term occurrences, such as abnormal weather, operational events, or intra-month commodity price volatility may also cause the actual level of hedging coverage to vary from the established hedge targets. These events can cause fluctuations in PHI’s earnings from period to period. Due to the high heat rate of the Pepco Energy Services generating plants, Pepco Energy Services generally does not enter into wholesale contracts to lock in the forward value of its plants. To the extent that the Competitive Energy business has unhedged positions or its hedging procedures do not work as planned, fluctuating commodity prices could result in significant losses. Conversely, by engaging in hedging activities, PHI may not realize gains that otherwise could result from fluctuating commodity prices.

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The operations of the Competitive Energy business can give rise to significant collateral requirements. The inability to fund those requirements may prevent the business from hedging associated price risks or may require curtailment of their operations. (PHI only)

A substantial portion of Pepco Energy Services’ business is the sale of electricity and natural gas to retail customers. In conducting this business Pepco Energy Services typically enters into electricity and natural gas sale contracts under which it is committed to supply the electricity or natural gas requirements of its retail customers over a specified period at agreed upon prices. To acquire this energy, Pepco Energy Services enters 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 is 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. In addition, Conectiv Energy and Pepco Energy Services each enter into contracts to buy and sell electricity, various fuels, and related products, including derivative instruments, to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts usually require the posting of collateral. Under various contracts entered into by both businesses, the required collateral is provided in the form of an investment grade guaranty issued by PHI. Under these contracts, a reduction in PHI’s credit rating can also trigger a requirement to post additional collateral. To satisfy these obligations when required, PHI and its non-utility subsidiaries rely primarily on cash balances, access to the capital markets and existing credit facilities.

Particularly in periods of energy market price volatility, the collateral obligations associated with the Competitive Energy business can be substantial. These collateral demands negatively affect PHI’s liquidity by requiring PHI to draw on its capacity under its credit facilities and other financing sources. The inability of PHI to maintain the necessary liquidity also could have an adverse effect on PHI’s results of operations and financial condition by requiring the Competitive Energy business to forego new business opportunities, by requiring the business to curtail its hedging activity, thereby increasing its exposure to energy market price changes or by rendering them unable to meet their collateral obligations to counterparties.

PHI and its subsidiaries have significant exposure to counterparty risk. (PHI only)

Both Conectiv Energy and Pepco Energy Services, as part of its retail energy supply business that is being wound down, enter 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, the Competitive Energy business 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 the Competitive Energy business when no longer required. Under many of these contracts, Conectiv Energy and Pepco Energy Services are 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 could 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 Conectiv Energy and Pepco Energy Services to surrender collateral held or payments received. In addition, Conectiv Energy and Pepco Energy Services are participants in the wholesale electric markets administered by various independent system operators (ISOs), and in particular PJM. If an ISO incurs losses due to counterparty nonperformance, those losses are allocated to and borne by other market participants in the ISO. Such defaults could adversely affect PHI’s results of operations, liquidity or financial condition. These risks are increased during periods of significant commodity price fluctuations, tightened credit and ratings downgrades.

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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, such as its electric generation, fuel storage, 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, if any, received 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 Competitive Energy business.

The 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, 2009, had an equity value of approximately $1.4 billion and from which PHI currently derives approximately $55 million per year in tax benefits in the form of interest and depreciation deductions in excess of rental income. In 2005, the Treasury Department and IRS issued Notice 2005-13 identifying sale-leaseback transactions with certain attributes entered into with tax-indifferent parties as tax avoidance transactions, and the IRS announced its intention to disallow the associated tax benefits claimed by the investors in these transactions. 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 audit of PHI’s 2001-2002, and 2003-2005 income tax returns, respectively, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to 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 August 2006 and May 2009 in connection with the audit of PHI’s 2001-2002 and 2003-2005 income tax returns, respectively. Both cases have been forwarded to and are under review by 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, 2009, it would be obligated to pay approximately $617 million in additional federal and state taxes and $106 million of interest. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due. PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a re-characterization of the leases as loans would be recoverable in the form of lower taxes over the remaining terms of the affected leases. Moreover, the entire amount of any additional 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.

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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, which depending on the magnitude could be material.

For further 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 funding 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 their 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 the Competitive Energy business also depend in part on 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 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.

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

PHI had a goodwill balance at December 31, 2009, of approximately $1.4 billion primarily attributable to Pepco’s acquisition of Conectiv in 2002. Under generally accepted accounting principles, 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 their 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 flow 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.

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

The energy sector has been among the sectors of the economy that have been the subject of highly publicized allegations of misconduct in the past. In addition, many utility companies have been publicly criticized for their performance during natural disasters and weather related incidents. 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 adverse outcomes with respect to decisions by such bodies.

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 is a wholly owned subsidiary of PHI, and each of DPL and ACE is an indirect wholly owned subsidiary 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 executive officers, are officers of PHI or an affiliate 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 respective earnings, cash flow and capital structure.

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

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Generating Plants

The following table identifies the electric generating plants owned by PHI’s subsidiaries at December 31, 2009.

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The preceding table sets forth the net summer electric generating capacity of the electric generating plants owned by Pepco Holdings’ subsidiaries. Although the generating capacity of these facilities may be higher during the winter months, the plants operated by PHI’s subsidiaries 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 plants.

Transmission and Distribution Systems

On a combined basis, the electric transmission and distribution systems owned by Pepco, DPL and ACE at December 31, 2009, consisted of approximately 3,400 transmission circuit miles of overhead lines, 400 transmission circuit miles of underground cables, 18,100 distribution circuit miles of overhead lines, and 15,700 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 has a liquefied natural gas plant located in Wilmington, Delaware, with a storage capacity of approximately 3 million gallons and an emergency sendout capability of 49,000 Mcf per day. DPL owns eight natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 252,000 Mcf per day. DPL also owns approximately 111 pipeline miles of natural gas transmission mains, 1,806 pipeline miles of natural gas distribution mains, and 1,311 natural gas pipeline miles of service lines. The natural gas transmission mains include approximately 7 miles of pipeline, 10% of which is owned and used by DPL for natural gas operations, and 90% of which is owned and used by Conectiv Energy for delivery of natural gas to electric generation 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.

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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.

Pepco Holdings

None.

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

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Part II

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

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Capital Requirements — Dividends,” of this Form 10-K for information regarding restrictions on the ability of PHI and its subsidiaries to pay dividends.

At December 31, 2009, there were approximately 58,729 holders of record of Pepco Holdings common stock.

Dividends

On January 28, 2010, the PHI Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2010, to shareholders of record on March 10, 2010.

PHI Subsidiaries

All of the common equity of Pepco, DPL and ACE is owned directly or indirectly by PHI. Pepco, DPL and ACE each customarily pays dividends on its common stock on a quarterly basis based on its earnings, cash flow and capital structure, and after taking into account the business plans and financial requirements of PHI and its other subsidiaries.

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Pepco

All of Pepco’s common stock is held by Pepco Holdings. The table below presents the aggregate amount of common stock dividends paid by Pepco to PHI during each quarter in the last two years. Dividends received by PHI in 2008 were used to support the payment of its common stock dividend.

DPL

All of DPL’s common stock is held by Conectiv. The table below presents the aggregate amount of common stock dividends paid by DPL to Conectiv during each quarter in the last two years. Dividends received by Conectiv in 2009 and 2008 were passed through to PHI to support the payment of its common stock dividend.

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ACE

All of ACE’s common stock is held by Conectiv. The table below presents the aggregate amount of common stock dividends paid by ACE to Conectiv during each quarter in the last two years. Dividends received by Conectiv in 2009 and 2008 were passed through to PHI to support the payment of its common stock dividend.

Recent Sales of Unregistered Equity Securities

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

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PEPCO HOLDINGS CONSOLIDATED FINANCIAL HIGHLIGHTS