Item 1. BUSINESS
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:
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The distribution, transmission and default supply of electricity and the delivery and supply of natural gas (Power Delivery), conducted through the following regulated public utility companies:
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Potomac Electric Power Company (Pepco), which was incorporated in the District of Columbia in 1896 and became a domestic Virginia corporation in 1949,
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Delmarva Power & Light Company (DPL), which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979, and
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Atlantic City Electric Company (ACE), which was incorporated in New Jersey in 1924.
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Competitive energy generation, marketing and supply (Competitive Energy) conducted through subsidiaries of Conectiv Energy Holding Company (collectively Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries (collectively Pepco Energy Services).
The following chart shows, in simplified form, the corporate structure of PHI and its principal subsidiaries.
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.
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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Pepco’s electricity delivery operations are regulated in Maryland by the Maryland Public Service Commission (MPSC) and in the District of Columbia by the District of Columbia Public Service Commission (DCPSC).
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DPL’s electricity delivery operations are regulated in Maryland by the MPSC and in Delaware by the Delaware Public Service Commission (DPSC).
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DPL’s natural gas distribution and intrastate transportation operations in Delaware are regulated by the DPSC.
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ACE’s electricity delivery operations are regulated by the New Jersey Board of Public Utilities (NJBPU).
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The transmission and wholesale sale of electricity by each of PHI’s utility subsidiaries are regulated by FERC.
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The interstate transportation and wholesale sale of natural gas by DPL are regulated by FERC.
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.
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.
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
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
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.
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:
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BGS-Fixed Price (BGS-FP), which is supplied to smaller commercial and residential customers at seasonally-adjusted fixed prices. BGS-FP rates change annually on June 1 and are based on the average BGS price obtained at auction in the current year and the two prior years. ACE’s BGS-FP load is approximately 1,957 megawatts, which represents approximately 99% of ACE’s total BGS load. Approximately one-third of this total load is auctioned off each year for a three-year term.
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BGS-Commercial and Industrial Energy Price (BGS-CIEP), which is supplied to larger customers at hourly PJM RTO real-time market prices for a term of 12 months. ACE’s BGS-CIEP load is approximately 9 megawatts, which represents approximately 1% of ACE’s BGS load. This total load is auctioned off each year for a one-year term.
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
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
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:
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providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing, and operating combined heat and power and central energy plants owned by customers.
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providing high voltage electric construction and maintenance services to customers throughout the United States and low voltage electric construction and maintenance services and streetlight construction and asset management services to utilities, municipalities and other customers in the Washington, D.C. area.
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,
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.
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.
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.
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.
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, SO2, 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,
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 NOx 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.
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
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
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.
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.
Item 1A.
Item 1A. RISK FACTORS
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.
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.
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.
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.
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.
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.
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.
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:
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a recession or an economic slowdown;
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the bankruptcy of one or more energy companies or financial institutions;
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a significant change in energy prices;
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a terrorist attack or threatened attacks; or
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a significant electricity transmission disruption.
In accordance with the requirements of the Sarbanes-Oxley Act of 2002 and the SEC rules thereunder, PHI’s management is responsible for establishing and maintaining internal control over financial reporting and is required to assess annually the effectiveness of these controls. The inability to certify the effectiveness of these controls due to the identification of one or more material weaknesses in these controls also could increase financing costs or could adversely affect the ability to access one or more financial markets.
PHI has a significant goodwill balance related to its Power Delivery business. A determination that goodwill is impaired could result in a significant 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.
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.
Item 1B.
Item 1B. UNRESOLVED STAFF COMMENTS
Pepco Holdings
None.
Pepco
None.
DPL
None.
ACE
None.
Item 2.
Item 2. PROPERTIES
Generating Plants
The following table identifies the electric generating plants owned by PHI’s subsidiaries at December 31, 2009.
(a) In the fourth quarter of 2009, Conectiv Energy modified its staffing levels and procedures at the Deepwater generating plant to allow for seasonal dispatch of Unit 6/8 on natural gas (summer) and coal (winter). These changes were made in response to current market conditions in order to enhance the value of the facility.
(b) This facility is owned by Eastern Landfill Gas, LLC, of which Pepco Energy Services holds a 75% membership interest.
(c) This facility is owned by Bethlehem Renewable Energy LLC, of which Pepco Energy Services holds a 80% membership interest.
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.
Item 3.
Item 3. LEGAL PROCEEDINGS
Pepco Holdings
Other than litigation incidental to PHI and its subsidiaries’ business, PHI is not a party to, and PHI and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (17), “Commitments and Contingencies-Legal Proceedings” to the consolidated financial statements of PHI, set forth in Part II, Item 8 of this Form 10-K.
Pepco
Other than litigation incidental to its business, Pepco is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (13), “Commitments and Contingencies-Legal Proceedings” to the financial statements of Pepco, set forth in Part II, Item 8 of this Form 10-K.
DPL
Other than litigation incidental to its business, DPL is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (15), “Commitments and Contingencies-Legal Proceedings” to the financial statements of DPL, set forth in Part II, Item 8 of this Form 10-K.
ACE
Other than litigation incidental to its business, ACE is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (14), “Commitments and Contingencies-Legal Proceedings” to the consolidated financial statements of ACE, set forth in Part II, Item 8 of this Form 10-K.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
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.
Part II
Item 5.
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The New York Stock Exchange is the principal market on which Pepco Holdings common stock is traded. The following table presents the dividends declared per share on the Pepco Holdings common stock and the high and low sales prices for the common stock based on composite trading as reported by the New York Stock Exchange during each quarter in the last two years.
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.
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.
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.
Item 6.
Item 6. SELECTED FINANCIAL DATA
PEPCO HOLDINGS CONSOLIDATED FINANCIAL HIGHLIGHTS
(a) Includes $40 million ($24 million after-tax) gain related to settlement of Mirant bankruptcy claims.
(b) Includes a $13 million state income tax benefit (after Federal tax) related to a change in the state income tax reporting for the disposition of certain assets in prior years and a benefit of $6 million related to additional analysis of current and deferred tax balances completed in 2009.
(c) Includes a pre-tax charge of $124 million ($86 million after-tax) related to the adjustment to the equity value of cross-border energy lease investments, and included in Income Taxes is a $7 million after-tax charge for the additional interest accrued on the related tax obligation.
(d) Includes $23 million of after-tax net interest income on uncertain and effectively settled tax positions (primarily associated with the reversal of previously accrued interest payable resulting from the final and tentative settlements, respectively, with the IRS on the like-kind exchange and mixed service cost issues and a claim made with the IRS related to the tax reporting for fuel over- and under-recoveries) and a benefit of $8 million (including a $3 million correction of prior period errors) related to additional analysis of deferred tax balances completed in 2008.
(e) Includes $33 million ($20 million after-tax) from settlement of Mirant bankruptcy claims.
(f) Includes $20 million ($18 million net of fees) benefit related to Maryland income tax settlement.
(g) Includes $19 million of impairment losses ($14 million after-tax) related to certain energy services business assets.
(h) Includes $12 million gain ($8 million after-tax) on the sale of Conectiv Energy’s equity interest in a joint venture which owns a wood burning cogeneration facility.
(i) Includes $68 million ($41 million after-tax) gain from sale of non-utility land owned by Pepco at Buzzard Point.
(j) Includes $71 million ($42 million after-tax) gain (net of customer sharing) from settlement of Mirant bankruptcy claims.
(k) Includes $13 million ($9 million after-tax) related to PCI’s liquidation of a financial investment that was written off in 2001.
(l) Includes $11 million in income tax expense related to the mixed service cost issue under IRS Revenue Ruling 2005-53.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 7.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information required by this item is contained herein, as follows:
PEPCO HOLDINGS
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Pepco Holdings, Inc.
General Overview
Pepco Holdings, Inc. (PHI or Pepco Holdings) is a diversified energy company that, through its operating subsidiaries, is engaged primarily in two businesses:
•
the distribution, transmission and default supply of electricity and the delivery and supply of natural gas (Power Delivery)
•
competitive energy generation, marketing and supply (Competitive Energy).
The following table sets forth the percentage contributions to consolidated operating revenue and operating income attributable to the Power Delivery and Competitive Energy businesses.
Power Delivery Electric consists primarily of the transmission, distribution and default supply of electricity, and Power Delivery Gas consists of the distribution and supply of natural gas. Power Delivery represents one operating segment for financial reporting purposes.
The Power Delivery business is conducted by PHI’s three utility subsidiaries: Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE). Each of these companies is a regulated public utility in the jurisdictions that comprise its service territory. Each company 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 Office Service in Delaware, the District of Columbia and Maryland and Basic Generation Service in New Jersey. In this Form 10-K, these supply services are referred to generally as Default Electricity Supply.
Pepco, DPL and ACE are also responsible for the transmission of wholesale electricity into and across their service territories. The rates each company is permitted to charge for the wholesale transmission of electricity are regulated by the Federal Energy Regulatory Commission (FERC). Transmission rates are updated annually based on a FERC-approved formula methodology.
The profitability of the Power Delivery business depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge. The Power Delivery operating results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. Operating results also can be affected by economic conditions, energy prices and the impact of energy efficiency measures on customer usage of electricity.
PEPCO HOLDINGS
Effective June 2007, the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers of Pepco and DPL. The District of Columbia Public Service Commission (DCPSC) also approved a BSA for Pepco’s retail customers, effective in November 2009. For customers to whom the BSA applies, Pepco and DPL recognize distribution revenue based on the approved distribution charge per customer. From a revenue recognition standpoint, this has the effect of decoupling distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a consequence, the only factors that will cause distribution revenue in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. For customers to whom the BSA applies, changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue.
As a result of the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (a) a positive adjustment equal to the amount by which revenue from Maryland and District and Columbia retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer or (b) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer.
The Competitive Energy business provides competitive generation, marketing and supply of electricity and gas, and energy management services primarily in the mid-Atlantic region. These operations are conducted through:
•
Subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy), which engage primarily in the generation and wholesale supply and marketing of electricity and gas within the PJM Interconnection, LLC (PJM) and Independent System Operator - New England (ISONE) wholesale markets.
•
Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), which provide retail energy supply and energy services primarily to commercial, industrial, and governmental customers.
Each of Conectiv Energy and Pepco Energy Services is a separate operating segment for financial reporting purposes. For the years ended December 31, 2009, 2008 and 2007, amounts equal to 6%, 7% and 10%, respectively, of the operating revenues of the Competitive Energy business were attributable to electric energy and capacity, and natural gas sold to the Power Delivery segment.
Conectiv Energy’s primary business objective is to maximize the value of its generation fleet by leveraging its operational and fuel flexibilities. Pepco Energy Services’ primary objective is to provide energy savings performance contracting services to federal, state and local government and commercial customers throughout the United States. The financial results of the Competitive Energy business can be significantly affected by wholesale and retail energy prices, the cost of fuel and gas to operate the Conectiv Energy generating facilities, the cost of purchased energy necessary to meet its power and gas supply obligations, and the cost of construction services provided by Pepco Energy Services.
The Competitive Energy business, like the Power Delivery business, is seasonal, and therefore weather can have a material impact on operating results.
On December 7, 2009, PHI announced that it will wind down the retail electric and natural gas supply business that it conducts through Pepco Energy Services. The decision was made after considering, among other factors, the return PHI earns by investing capital in the retail energy supply business as compared to alternative investments. To effectuate 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
PEPCO HOLDINGS
the needs of its customers, but will not be entering into any new retail energy supply contracts. Operating revenues related to the retail energy supply business for the years ended December 31, 2009, 2008 and 2007 were $2.3 billion, $2.5 billion and $2.1 billion, respectively, and operating income amounts for the same periods were $88 million, $54 million and $39 million, respectively.
PHI expects the retail energy supply business to remain profitable through December 31, 2012, based on its existing contract backlog and its corresponding portfolio of wholesale hedges, with minimal losses beyond that date. Substantially all of Pepco Energy Services’ retail customer obligations will be fully performed by June 1, 2014.
In connection with the operation of the retail energy supply business, as of December 31, 2009, Pepco Energy Services had collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, of approximately $280 million committed to its wholesale energy suppliers. Of this collateral amount, $157 million was in the form of letters of credit and $123 million was posted in cash. Pepco Energy Services estimates that at current market prices, with the wind down of the retail energy supply business, this collateral will be released as follows: 53% by December 31, 2010, an aggregate of 81% by December 31, 2011, an aggregate of 94% by December 31, 2012, and substantially all collateral by June, 1, 2014.
As a result of the decision to wind down the retail energy supply business, Pepco Energy Services in the fourth quarter of 2009 recorded (i) a $4 million pre-tax impairment charge reflecting the write off of all goodwill allocated to the business and (ii) a pre-tax charge of less than $1 million related to employee severance.
Pepco Energy Services’ remaining businesses will not be significantly affected by the wind down of the retail energy supply business.
Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments with a book value at December 31, 2009 of approximately $1.4 billion. This activity constitutes a fourth operating segment, which is designated as “Other Non-Regulated,” for financial reporting purposes. For a discussion of PHI’s cross-border energy lease investments, see Note (17), “Commitments and Contingencies-Regulatory and Other Matters - PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI, set forth in Part II, Item 8 of this Form 10-K.
Business Strategy
PHI’s business strategy is to remain a mid-Atlantic regional diversified energy delivery utility and competitive energy services company focused on value creation, operational excellence and environmental responsibility. The components of this strategy include:
•
Achieving earnings growth in the Power Delivery business by focusing on transmission and distribution infrastructure investments and constructive regulatory outcomes, while maintaining a high level of operational excellence.
•
Pursuing technologies and practices that promote energy efficiency, energy conservation and the reduction of greenhouse gas emissions.
•
Supplementing PHI’s utility earnings through competitive energy businesses
•
engaged in generation of electricity and the wholesale supply of electricity and natural gas primarily within the PJM RTO, and
PEPCO HOLDINGS
•
providing energy performance services and renewable energy and combined heat and power alternatives to commercial, industrial and government customers.
To further this business strategy, PHI may from time to time examine a variety of transactions involving its existing businesses, including the entry into joint ventures or the disposition of one or more businesses, as well as possible acquisitions. PHI also may reassess or refine the components of its business strategy as it deems necessary or appropriate in response to a wide variety of factors, including the requirements of its businesses, competitive conditions and regulatory requirements.
Earnings Overview
Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008
PHI’s net income for the year ended December 31, 2009 was $235 million, or $1.06 per share, compared to $300 million, or $1.47 per share, for the year ended December 31, 2008.
Net income for the year ended December 31, 2009, included the credits set forth below in the Power Delivery segment, which are presented net of federal and state income taxes and are in millions of dollars:
Net income for the year ended December 31, 2008, included the charges set forth below in the Other Non-Regulated operating segment, which are presented net of federal and state income taxes and are in millions of dollars:
Excluding the items listed above, net income would have been $200 million, or $0.91 per share, in 2009 and $393 million, or $1.93 per share, in 2008.
PHI’s net income for the years ended December 31, 2009 and 2008, by operating segment, is set forth in the table below (in millions of dollars):
PEPCO HOLDINGS
Discussion of Operating Segment Net Income Variances:
Power Delivery’s $51 million decrease in earnings is primarily due to the following:
•
$30 million decrease due to higher operating and maintenance expenses (primarily higher pension expenses).
•
$17 million decrease due to higher interest expense associated with an increase in outstanding debt.
•
$10 million decrease due to favorable income tax adjustments in 2008, primarily interest resulting from Financial Accounting Standards Board (FASB) guidance on income taxes (Accounting Standards Codification (ASC) 740).
•
$7 million decrease due to higher depreciation expense as the result of increased plant.
•
$5 million decrease attributable to a decrease in unbilled revenue associated with ACE Basic Generation Service (primarily lower usage and migration to competitive suppliers).
•
$4 million decrease due to lower Default Electricity Supply margins, primarily due to increased bad debt expense and commercial customer migration to competitive suppliers.
•
$24 million increase due to the release of restricted cash as the result of Pepco’s settlement of its Mirant bankruptcy claim following rulings by the DCPSC and MPSC on customer sharing of the settlement proceeds.
•
$11 million increase due to a Maryland income tax benefit, net of $1 million (after-tax) in professional fees, related to a change in the tax reporting for the disposition of certain assets in prior years.
Conectiv Energy’s $107 million decrease in earnings is primarily due to the following:
Merchant Generation and Load Service earnings decreased approximately $101 million primarily due to:
•
$79 million decrease resulting from significantly reduced spark (natural gas) spreads and dark (coal) spreads (lower by 57%), and lower run-time (lower by 27% excluding tolled generation).
•
$63 million decrease primarily related to economic fuel hedges that were favorable in 2008 due to rising fuel prices and unfavorable in 2009 due to falling fuel prices.
•
$39 million increase due to an increase in capacity margins, primarily due to higher Reliability Pricing Model (RPM) clearing prices in the eastern part of the PJM RTO region.
Energy Marketing earnings decreased approximately $6 million primarily due to lower natural gas marketing results primarily due to lower prices and demand.
Pepco Energy Services’ $1 million increase in earnings is primarily due to the following:
•
$25 million increase due to the lower cost of energy and energy supply costs.
PEPCO HOLDINGS
•
$17 million decrease due to higher interest and other expenses primarily associated with credit and collateral facilities for the retail energy supply business.
•
$4 million decrease due to lower construction activities.
•
$3 million decrease due to impairment of goodwill for the retail energy supply business.
Other Non-Regulated’s $89 million increase in earnings is primarily due to the impact of the cross-border energy lease investment re-evaluation adjustment recorded in June 2008.
Consolidated Results Of Operations
The following results of operations discussion is for the year ended December 31, 2009, compared to the year ended December 31, 2008. All amounts in the tables (except sales and customers) are in millions of dollars.
Operating Revenue
A detail of the components of PHI’s consolidated operating revenue is as follows:
Power Delivery Business
The following table categorizes Power Delivery’s operating revenue by type of revenue.
Regulated Transmission & Distribution (T&D) Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM.
Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier, and which, depending on the jurisdiction, is also known as Standard Office Service (SOS) or Basic Generation Service (BGS).
PEPCO HOLDINGS
The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges and other restructuring related revenues.
Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees, and collection fees.
Regulated Gas Revenue consists of revenues for on-system natural gas sales and the transportation of natural gas for customers by DPL within its service territory at regulated rates.
Other Gas Revenue consists of DPL’s off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.
Regulated T&D Electric
Other Regulated T&D Electric Revenue consists primarily of: (i) transmission service revenue and (ii) revenue from the resale by Pepco in the PJM RTO market of energy and capacity purchased under a power purchase agreement between Panda-Brandywine, L.P. (Panda) and Pepco (the Panda PPA) prior to the transfer of the Panda PPA to an unaffiliated third party in September 2008.
PEPCO HOLDINGS
The Pepco, DPL and ACE service territories are located within a corridor extending from the District of Columbia to southern New Jersey. These service territories are economically diverse and include key industries that contribute to the regional economic base.
•
Commercial activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, casinos, stand alone construction, and tourism.
•
Industrial activity in the region includes chemical, glass, pharmaceutical, steel manufacturing, food processing, and oil refining.
Regulated T&D Electric Revenue decreased by $37 million primarily due to:
•
A decrease of $53 million in Other Regulated T&D Electric Revenue (which is matched by a corresponding decrease in Fuel and Purchased Energy) due to the absence of revenues from the resale of energy and capacity purchased under the Panda PPA after September 2008.
•
A decrease of $12 million due to lower non-weather related customer usage.
The aggregate amount of these decreases was partially offset by:
•
An increase of $16 million due to a distribution rate increase (which is substantially offset by a corresponding increase in Deferred Electric Service Costs) as part of a higher New Jersey Societal Benefit Charge that became effective in June 2008.
•
An increase of $15 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of increases in utility taxes that are collected on behalf of taxing jurisdictions.
Default Electricity Supply
Other Default Electricity Supply Revenue consists primarily of revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated non-utility generators (NUGs).
PEPCO HOLDINGS
Default Electricity Supply Revenue, decreased by $423 million primarily due to:
•
A decrease of $175 million in wholesale energy revenues due to lower market prices for the sale of electricity purchased from NUGs.
•
A decrease of $167 million due to lower sales, primarily the result of commercial customer migration to competitive suppliers.
•
A decrease of $49 million due to lower non-weather related customer usage.
•
A decrease of $33 million due to lower sales as a result of milder weather primarily during the 2009 summer months as compared to 2008.
The decrease in total Default Electricity Supply Revenue includes a decrease of $8 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the New Jersey Board of Public Utilities (NJBPU), ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, then the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the year ended December 31, 2009, BGS unbilled revenue decreased by $8 million as compared to the year ended December 31, 2008, which resulted in a $5 million decrease in PHI’s net income. The decrease was due to increased customer migration and lower customer usage during the unbilled revenue period at the end of 2009 as compared to the corresponding period in 2008.
Regulated Gas
PEPCO HOLDINGS
DPL’s natural gas service territory is located in New Castle County, Delaware. Several key industries contribute to the economic base as well as to growth:
•
Commercial activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, stand alone construction, and tourism.
•
Industrial activity in the region includes chemical and pharmaceutical.
Regulated Gas Revenue increased by $24 million primarily due to:
•
An increase of $15 million due to the Gas Cost Rate increase effective November 2008, partially offset by rate decreases in March 2009 and November 2009.
•
An increase of $14 million (which is offset by a corresponding increase in Fuel and Purchased Energy) associated with the recognition of the unbilled portion of Gas Cost Rate revenue in 2009 which was not previously recognized.
The aggregate amount of these increases was partially offset by:
•
A decrease of $5 million due to lower non-weather related customer usage.
•
A decrease of $4 million due to lower sales as result of warmer weather during the fourth quarter of 2009 as compared to the corresponding period in 2008.
Other Gas Revenue
Other Gas Revenue decreased by $74 million primarily due to lower revenue from off-system sales resulting from:
•
A decrease of $67 million due to lower market prices.
•
A decrease of $9 million due to lower demand from electric generators and gas marketers.
Conectiv Energy
The impact of Operating Revenue changes and Fuel and Purchased Energy and Other Services Cost of Sales changes with respect to the Conectiv Energy component of the Competitive Energy business are encompassed within the discussion that follows.
Operating Revenues of the Conectiv Energy segment are derived primarily from the sale of electricity. The primary components of its costs of sales are Fuel and Purchased Energy and Other Services Cost of Sales. Because fuel and electricity prices tend to move in tandem, price changes in these commodities from period to period can have a significant impact on Operating Revenue, Fuel and Purchased Energy and Other Services Cost of Sales without signifying any change in the performance of the Conectiv Energy segment. Conectiv Energy also uses a number of and various types of derivative contracts to lock in sales margins,
PEPCO HOLDINGS
and to economically hedge its power and fuel purchases and sales. Gains and losses on derivative contracts are netted in Operating Revenue, Fuel and Purchased Energy and Other Services Cost of Sales as appropriate under the applicable accounting rules. For these reasons, PHI from a managerial standpoint focuses on gross margin as a measure of performance.
Conectiv Energy Gross Margin
Merchant Generation and Load Service consists primarily of electric power, capacity and ancillary services sales from Conectiv Energy’s generating plants; tolling arrangements entered into to sell energy and other products from Conectiv Energy’s generating plants and to purchase energy and other products from generating plants of other companies; hedges of power, capacity, fuel and load; the sale of excess fuel (primarily natural gas); natural gas transportation and storage; emission allowances; electric power, capacity, and ancillary services sales pursuant to competitively bid contracts entered into with affiliated and non-affiliated companies to fulfill their default electricity supply obligations; and fuel switching activities made possible by the multi-fuel capabilities of some of Conectiv Energy’s generating plants.
Energy Marketing activities consist primarily of wholesale natural gas and fuel oil marketing, the activities of the short-term power desk, which generates margin by capturing price differences between power pools and locational and timing differences within a power pool, and power origination activities, which primarily represent the fixed margin component of structured power transactions such as default supply service.
PEPCO HOLDINGS
(a) Includes $310 million and $397 million of affiliate transactions for 2009 and 2008, respectively.
(b) Includes less than $1 million and $6 million of affiliate transactions for 2009 and 2008, respectively. Also, excludes depreciation and amortization expense of $40 million and $37 million, respectively.
(c) Consists solely of Merchant Generation and Load Service expenses; does not include the cost of fuel not consumed by the generating plants and intercompany tolling expenses.
(d) Includes tolled generation.
(e) Includes associated hedging gains and losses.
(f) Includes emissions expenses, fuel additives, and other fuel-related costs.
(g) Edge Moor Units 3 and 4 and Deepwater Unit 6.
(h) Hay Road and Bethlehem, all units.
(i) Edge Moor Unit 5, Deepwater Unit 1 and Vineland Solar.
(j) Consists of all default electricity supply sales; does not include standard product hedge volumes.
(k) Calculated from data reported in Conectiv Energy’s Electric Quarterly Report (EQR) filed with the FERC; does not include capacity or ancillary services revenue. Prices may differ from those originally reported in prior periods due to normal load true-ups requiring EQR filing amendments.
(l) Consists of default electricity supply sales, standard product power sales, and spot power sales other than merchant generation as reported in Conectiv Energy’s EQR.
(m) Source: PJM website (www.pjm.com).
(n) Source: Average delivered natural gas price at Tetco Zone M3 as published in Gas Daily.
(o) Source: National Oceanic and Atmospheric Administration National Weather Service data.
PEPCO HOLDINGS
Conectiv Energy’s Operating Revenue and cost of sales were lower in 2009 primarily due to decreased generating facility output and lower default electricity supply volumes, in each case due to a decreased demand for power and lower spark and dark spreads driven by the economic recession, milder weather and the mix of contracts that were in effect each year. Conectiv Energy’s ability to use its fleet of mid-merit and peaking generation assets to generate high gross margins during peak usage periods was limited by the low energy commodity prices.
Merchant Generation and Load Service gross margin decreased approximately $171 million primarily due to:
•
A decrease of approximately $133 million in gross margin derived from reduced spark and dark spreads (lower by 57%), and lower run-time (lower by 27% excluding tolled generation).
•
A decrease of approximately $106 million in gross margin primarily attributable to economic fuel hedges that were favorable in a rising market during the first half of 2008 and unfavorable in a falling market throughout 2009.
•
An increase of approximately $66 million due to higher gross margin attributable to capacity sales, primarily due to higher RPM clearing prices in the eastern part of the PJM RTO region.
Energy Marketing gross margin decreased approximately $10 million primarily due to lower natural gas marketing results primarily due to lower prices and demand.
Pepco Energy Services
Pepco Energy Services’ operating revenue decreased $265 million primarily due to:
•
A $170 million decrease due to lower volumes of retail electric load served as a result of the expiration of existing retail contracts.
•
A $72 million decrease due to lower construction activities as a result of reduced high voltage construction and maintenance projects.
•
A $20 million decrease due to lower retail natural gas prices partially offset by higher customer load as a result of customer acquisitions.
•
A $3 million decrease due to lower generation output as a result of milder weather and lower overall load levels for the PJM RTO control area.
Other Non-Regulated
Other Non-Regulated revenues increased by $111 million from a $60 million loss in 2008 to a $51 million gain in 2009. This was primarily the result of a non-cash charge of $124 million that was recorded in the quarter ended June 30, 2008 as a result of revised assumptions regarding the estimated timing of tax benefits from PCI’s cross-border energy lease investments. In accordance with FASB guidance on leases (ASC 840), the charge was recorded as a reduction to lease revenue from these transactions, which is included in Other Non-Regulated revenues.
PEPCO HOLDINGS
Operating Expenses
Fuel and Purchased Energy and Other Services Cost of Sales
A detail of PHI’s consolidated Fuel and Purchased Energy and Other Services Cost of Sales is as follows:
Power Delivery Business
Power Delivery’s Fuel and Purchased Energy (other than expense associated with Regulated Gas Revenue and Other Gas revenue) consists of the cost of electricity purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Fuel and Purchased Energy expense decreased by $335 million primarily due to:
•
A decrease of $236 million primarily due to commercial customer migration to competitive suppliers.
•
A decrease of $73 million in the cost of gas purchases for off-systems sales, the result of lower average gas prices and volumes purchased.
•
A decrease of $53 million (which is matched by a corresponding decrease in Other Regulated T&D Electric Revenue) due to the transfer of the Panda PPA.
•
A decrease of $33 million due to lower electricity sales as a result of milder weather primarily during the 2009 summer months as compared to 2008.
•
A decrease of $30 million in the cost of gas purchases for system sales, the result of lower average gas prices and volumes purchased.
•
A decrease of $23 million due to lower average electricity costs under Default Electricity Supply contracts.
The aggregate amount of these decreases was partially offset by:
•
An increase of $63 million due to a higher rate of recovery of electricity supply costs resulting in a decrease in the Default Electricity Supply deferral balance.
•
An increase of $43 million from the settlement of financial hedges entered into as part of DPL’s hedge program for regulated natural gas.
•
An increase of $12 million due to a higher rate of recovery of natural gas supply costs primarily as a result of recognizing the unbilled portion of Gas Cost Rate revenue in 2009, as discussed under Regulated Gas Revenue.
PEPCO HOLDINGS
Conectiv Energy
The impact of Fuel and Purchased Energy and Other Services Cost of Sales changes with respect to the Conectiv Energy component of the Competitive Energy business is encompassed within the prior discussion under the heading “Conectiv Energy Gross Margin.”
Pepco Energy Services
Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $310 million primarily due to:
•
A $212 million decrease due to lower volumes of electricity purchased to serve decreased retail customer load as the result of the continuing expiration of existing retail contracts.
•
A $45 million decrease due to lower wholesale natural gas prices partially offset by higher retail customer load as the result of customer acquisitions.
•
A $42 million decrease due to lower construction activities as a result of reduced high voltage construction and maintenance projects.
•
A $11 million decrease due to lower generation output due to milder weather and lower overall load levels for the PJM control area.
Other Operation and Maintenance
A detail of PHI’s other operation and maintenance expense is as follows:
Other Operation and Maintenance expense for Power Delivery increased by $50 million; however, excluding a decrease of $5 million primarily related to administrative expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense increased by $55 million. The $55 million increase was primarily due to:
•
An increase of $39 million in employee-related costs, primarily due to higher pension and other postretirement benefit expenses.
•
An increase of $13 million primarily due to higher preventative and corrective maintenance, and emergency restoration costs.
•
An increase of $4 million in regulatory expenses primarily incurred in connection with the District of Columbia distribution rate case.
•
An increase of $3 million due to higher non-deferrable bad debt expenses.
PEPCO HOLDINGS
During 2008, PHI recorded adjustments, on a consolidated basis, to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 during which (i) customer late payment fees were incorrectly recognized and (ii) stock-based compensation expense related to certain restricted stock awards granted under the Long-Term Incentive Plan was understated. The late payment fees and stock-based compensation adjustments resulted in increases in Other Operation and Maintenance expenses for the year ended December 31, 2008 of $6 million and $9 million, respectively. These adjustments were not considered material either individually or in the aggregate.
Depreciation and Amortization
Depreciation and Amortization expenses increased by $14 million to $391 million in 2009 from $377 million in 2008 primarily due to an increase of $17 million due to generating plant additions and $4 million due to the accelerated depreciation of generating plants, partially offset by a decrease of $7 million due to lower amortization by ACE of stranded costs primarily as the result of lower revenue due to decreases in the Market Transition Charge Tax rate in October 2009 and October 2008 (partially offset in Default Electricity Supply Revenue).
Other Taxes
Other Taxes increased by $13 million to $372 million in 2009 from $359 million in 2008. The increase was primarily due to increased pass-throughs experienced by Power Delivery (which are substantially offset by a corresponding increase in Regulated T&D Electric Revenue) resulting from rate increases in utility taxes imposed by the taxing jurisdictions.
Deferred Electric Service Costs
Deferred Electric Service Costs, which relate only to ACE, decreased by $152 million, to an expense reduction of $161 million in 2009 as compared to an expense reduction of $9 million in 2008. The decrease was primarily due to:
•
A decrease of $186 million due to a lower rate of recovery of costs from the resale in the PJM RTO market of energy and capacity purchased under the NUG contracts.
The decrease was partially offset by:
•
An increase of $15 million due to a higher rate of recovery through customer rates of deferred energy costs of Default Electricity Supply (included in Default Electricity Supply Revenue).
•
An increase of $13 million due to a higher rate of recovery through customer rates of New Jersey Societal Benefit program costs (included in Regulated T&D Electric Revenue).
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An increase of $5 million due to a higher rate of recovery through customer rates of deferred transmission costs of Default Electricity Supply (included in Default Electricity Supply Revenue).
Effect of Settlement of Mirant Bankruptcy Claims
In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party. In March 2009, the DCPSC approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $14 million reflecting the District of Columbia proceeds retained by Pepco. In July 2009, the MPSC approved an allocation between Pepco and its Maryland customers of the Maryland portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $26 million reflecting the Maryland proceeds retained by Pepco.
PEPCO HOLDINGS
Gain on Sale of Assets
Gain on Sale of Assets decreased by $3 million in 2009 due to a $3 million gain on the sale of the Virginia retail electric distribution and wholesale transmission assets in January 2008.
Other Income (Expenses)
Other Expenses (which are net of Other Income) increased by $50 million to a net expense of $350 million in 2009 from a net expense of $300 million in 2008, primarily due to an increase in interest expense. The increase in interest expense was due to a $33 million increase in interest expense on long-term debt as the result of a higher amount of outstanding debt, and an increase of $13 million in interest expense on short-term debt due primarily to the Pepco Energy Services credit intermediation agreement, as described below under the heading “Capital Resources and Liquidity - Collateral Requirements of the Competitive Energy Business.”
Income Tax Expense
PHI’s consolidated effective tax rates for the years ended December 31, 2009 and 2008 were 31.9 % and 35.9% respectively. The decrease in the rate primarily resulted from a refund of $6 million (after-tax) of state income taxes and the establishment of a state tax benefit carryforward of $7 million (after-tax) related to a change in the tax reporting for the disposition of certain assets in prior years, and from the 2008 charge related to the cross-border energy lease investments described in Note (17), “Commitments and Contingencies,” and corresponding state tax benefits related to the charge.
The following results of operations discussion is for the year ended December 31, 2008, compared to the year ended December 31, 2007. All amounts in the tables (except sales and customers) are in millions of dollars.
Operating Revenue
A detail of the components of PHI’s consolidated operating revenue is as follows:
PEPCO HOLDINGS
Power Delivery Business
The following table categorizes Power Delivery’s operating revenue by type of revenue.
Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM.
Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier, and which, depending on the jurisdiction, is also known as SOS or BGS service. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from transition bond charges and other restructuring related revenues.
Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees, and collection fees.
Regulated Gas Revenue consists of revenues from on-system natural gas sales and the transportation of natural gas for customers by DPL within its service territories at regulated rates.
Other Gas Revenue consists of DPL’s off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.
In response to an order issued by the New Jersey Board of Public Utilities (NJBPU) regarding changes to ACE’s retail transmission rates, ACE has established deferred accounting treatment for the difference between the rates that ACE is authorized to charge its customers for the transmission of Default Electricity Supply and the cost that ACE incurs. Under the deferral arrangement, any over or under recovery is deferred as part of Deferred Electric Service Costs pending an adjustment of retail rates in a future proceeding. As a consequence of the order, effective January 1, 2008, ACE’s retail transmission revenue is being recorded as Default Electricity Supply Revenue, rather than as Regulated T&D Electric Revenue, thereby conforming to the practice of PHI’s other utility subsidiaries, which previously established deferred accounting treatment for any over or under recovery of retail transmission rates relative to the cost incurred. ACE’s retail transmission revenue for the period prior to January 1, 2008 has been reclassified to Default Electricity Supply Revenue in order to conform to the current period presentation.
PEPCO HOLDINGS
Regulated T&D Electric
Regulated T&D Electric Revenue
Other Regulated T&D Electric Revenue consists primarily of: (i) transmission service revenue and (ii) revenue from the resale by Pepco in the PJM RTO market of energy and capacity purchased under the Panda PPA prior to the transfer of the Panda PPA to an unaffiliated third party in September 2008.
Regulated T&D Electric Sales (GWh)
Regulated T&D Electric Customers (in thousands)
Due to the sale of DPL’s Virginia retail electric distribution assets in January 2008, the numbers of Regulated T&D Electric Customers listed above include a decrease of approximately 19,000 residential customers and 3,000 commercial customers.
The Pepco, DPL and ACE service territories are located within a corridor extending from the District of Columbia to southern New Jersey. These service territories are economically diverse and include key industries that contribute to the regional economic base.
•
Commercial activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, casinos, stand alone construction, and tourism.
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Industrial activity in the region includes chemical, glass, pharmaceutical, steel manufacturing, food processing, and oil refining.
Regulated T&D Electric Revenue increased by $98 million primarily due to:
•
An increase of $28 million due to a distribution rate change under the 2007 Maryland Rate Orders that became effective in June 2007, including a positive $19 million Revenue Decoupling Adjustment.
PEPCO HOLDINGS
•
An increase of $24 million due to a distribution rate change in the District of Columbia that became effective in February 2008.
•
An increase of $24 million due to a distribution rate change as part of a higher New Jersey Societal Benefit Charge that became effective in June 2008 (substantially offset in Deferred Electric Service Costs).
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An increase of $24 million in transmission service revenue primarily due to transmission rate changes in June 2008 and 2007.
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An increase of $24 million in Other Regulated T&D Electric Revenue (offset in Fuel and Purchased Energy and Other Services Cost of Sales) from the resale of energy and capacity purchased under the Panda PPA.
•
An increase of $4 million due to customer growth of 1% in 2008 (excluding customers associated with the sale of DPL’s Virginia retail electric distribution and wholesale transmission assets in January 2008).
The aggregate amount of these increases was partially offset by:
•
A decrease of $20 million due to lower sales as a result of milder weather during 2008 as compared to 2007.
•
A decrease of $12 million due to the sale of DPL’s Virginia retail electric distribution and wholesale transmission assets in January 2008.
Default Electricity Supply
Default Electricity Supply Revenue
Other Default Electricity Supply Revenue consists primarily of revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs.
Default Electricity Supply Sales (GWh)
PEPCO HOLDINGS
Default Electricity Supply Customers (in thousands)
Due to the sale of DPL’s Virginia retail electric distribution assets in January 2008, the number of Default Electricity Supply Customers listed above includes a decrease of approximately 19,000 residential customers and 3,000 commercial customers.
Default Electricity Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Deferred Electric Service Costs, increased by $118 million primarily due to:
•
An increase of $202 million as a result of higher Default Electricity Supply rates.
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An increase of $48 million in wholesale energy revenues due to higher market prices for the sale of electricity purchased from NUGs.
The aggregate amount of these increases was partially offset by:
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A decrease of $55 million due to lower sales as a result of milder weather during 2008 as compared to 2007.
•
A decrease of $33 million due to lower sales primarily the result of commercial and industrial customer migration to competitive suppliers.
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A decrease of $32 million due to the sale of DPL’s Virginia retail electric distribution and wholesale transmission assets in January 2008.
•
A decrease of $12 million due to lower non-weather related customer usage.
Regulated Gas
Regulated Gas Revenue
Regulated Gas Sales (billion cubic feet)
PEPCO HOLDINGS
Regulated Gas Customers (in thousands)
DPL’s natural gas service territory is located in New Castle County, Delaware. Several key industries contribute to the economic base as well as to growth.
•
Commercial activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, stand alone construction and tourism.
•
Industrial activity in the region includes chemical and pharmaceutical.
Regulated Gas Revenue decreased by $7 million primarily due to:
•
A decrease of $4 million due to lower non-weather related customer usage.
•
A decrease of $3 million due to lower sales as the result of milder weather in 2008 as compared to 2007.
•
A decrease of $2 million primarily due to Gas Cost Rate changes effective April 2007, November 2007 and November 2008.
The aggregate amount of these decreases was partially offset by:
•
An increase of $2 million due to a distribution base rate change effective April 2007.
Other Gas Revenue
Other Gas Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, increased by $34 million primarily due to revenue from higher off-system sales, the result of an increase in market prices.
Conectiv Energy
The impact of Operating Revenue changes and Fuel and Purchased Energy and Other Services Cost of Sales changes with respect to the Conectiv Energy component of the Competitive Energy business are encompassed within the discussion that follows.
Operating Revenues of the Conectiv Energy segment are derived primarily from the sale of electricity. The primary components of its costs of sales are Fuel and Purchased Power and Other Services Cost of Sales. Because fuel and electricity prices tend to move in tandem, price changes in these commodities from period to period can have a significant impact on Operating Revenue and costs of sales without signifying any change in the performance of the Conectiv Energy segment. Conectiv Energy also uses a number of and various types of derivative contracts to lock in sales margins, and to economically hedge its power and fuel purchases and sales. Gains and losses on derivative contracts are netted in Operating Revenue and cost of sales as appropriate under the applicable accounting rules. For these reasons, PHI from a managerial standpoint focuses on gross margin as a measure of performance.
PEPCO HOLDINGS
Conectiv Energy Gross Margin
Merchant Generation and Load Service consists primarily of electric power, capacity and ancillary services sales from Conectiv Energy’s generating plants; tolling arrangements entered into to sell energy and other products from Conectiv Energy’s generating plants and to purchase energy and other products from generating plants of other companies; hedges of power, capacity, fuel and load; the sale of excess fuel (primarily natural gas); natural gas transportation and storage; emission allowances; electric power, capacity, and ancillary services sales pursuant to competitively bid contracts entered into with affiliated and non-affiliated companies to fulfill their default electricity supply obligations; and fuel switching activities made possible by the multi-fuel capabilities of some of Conectiv Energy’s generating plants.
Energy Marketing activities consist primarily of wholesale natural gas and fuel oil marketing, the activities of the short-term power desk, which generates margin by capturing price differences between power pools and locational and timing differences within a power pool, and power origination activities, which primarily represent the fixed margin component of structured power transactions such as default supply service.
PEPCO HOLDINGS
(a) Includes $397 million and $442 million of affiliate transactions for 2008 and 2007, respectively.
(b) Includes $6 million and $7 million of affiliate transactions for 2008 and 2007, respectively. Also, excludes depreciation and amortization expense of $37 million and $38 million, respectively.
(c) Consists solely of Merchant Generation and Load Service expenses; does not include the cost of fuel not consumed by generating plants and intercompany tolling expenses.
(d) Includes tolled generation.
(e) Includes associated hedging gains and losses.
(f) Includes emissions expenses, fuel additives, and other fuel-related costs.
(g) Edge Moor Units 3 and 4 and Deepwater Unit 6.
(h) Hay Road and Bethlehem, all units.
(i) Edge Moor Unit 5 and Deepwater Unit 1.
(j) Consists of all default electricity supply sales; does not include standard product hedge volumes.
(k) Calculated from data reported in Conectiv Energy’s Electric Quarterly Report (EQR) filed with the FERC; does not include capacity or ancillary services revenue. Prices may differ from those reported in prior periods due to normal load true-ups requiring EQR filing amendments.
(l) Consists of default electricity supply sales, standard product power sales, and spot power sales other than merchant generation as reported in Conectiv Energy’s EQR.
(m) Source: PJM website (www.pjm.com).
(n) Source: Average delivered natural gas price at Tetco Zone M3 as published in Gas Daily.
(o) Source: National Oceanic and Atmospheric Administration National Weather Service data.
PEPCO HOLDINGS
Conectiv Energy’s revenue and cost of sales are higher in 2008 primarily due to increased default electricity supply volumes and higher energy commodity prices. In 2008, Conectiv Energy expanded its default electricity supply business into ISONE.
Conectiv Energy’s margins were favorably impacted by higher energy commodity prices in the first half of 2008, and unfavorably impacted by the decrease in prices and spark spreads during the second half of the year. Volatile commodity prices contributed to significant movements in the value of transactions accounted for at fair value.
Merchant Generation and Load Service gross margin increased approximately $73 million primarily due to:
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An increase of approximately $37 million primarily due to short-term sales of firm natural gas, and natural gas transportation and storage rights, the dual-fuel capability of the combined cycle mid-merit units (fuel switching), cross-commodity hedging (use of natural gas to hedge power positions), and the opportunities created by the mid-merit combined cycle units’ operating flexibility (option value) in conjunction with short-term power and fuel price volatility. This combination of strategies positioned Conectiv Energy to realize the upside potential of its overall portfolio during the winter period. The magnitude of gain was due partly to significant fuel price increases in conjunction with less significant increases in power prices.
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An increase of approximately $46 million due to higher PJM capacity prices net of capacity hedges.
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An increase of approximately $18 million due to the application of fair value accounting treatment and associated settlements with respect to excess coal hedges.
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A decrease of approximately $15 million due to a lower of cost or market adjustment to the value of oil inventory held at the generating plants at year-end 2008.
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A decrease of approximately $15 million due to lower sales of emissions allowances.
Energy Marketing gross margin increased approximately $15 million primarily due to:
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An increase of approximately $9 million in short-term power desk margins in 2008.
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An increase of approximately $9 million due to additional default electricity supply contracts in 2008.
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A decrease of approximately $4 million due to lower wholesale gas margins.
Pepco Energy Services
Pepco Energy Services’ operating revenue increased by $339 million to $2,648 million in 2008 from $2,309 million in 2007 primarily due to:
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An increase of $259 million due to higher volumes of retail electric load served due to customer acquisitions and higher prices in 2008.
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An increase of $64 million due to higher natural gas volumes driven by customer acquisitions and higher prices in 2008.
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An increase of $26 million due to increased construction activities in 2008.
PEPCO HOLDINGS
The aggregate amount of these increases was partially offset by:
•
A decrease of $11 million due to RPM-related charges that lowered capacity revenues for the generating plants.
Other Non-regulated
Other Non-regulated operating revenue decreased by $136 million primarily due to:
•
A non-cash charge of $124 million recorded during 2008 as a result of revised assumptions regarding the estimated timing of tax benefits from PCI’s cross-border energy lease investments. This charge was recorded as a reduction to lease revenue from these transactions, which is included in Other Non-regulated revenues.
Operating Expenses
Fuel and Purchased Energy and Other Services Cost of Sales
A detail of PHI’s consolidated Fuel and Purchased Energy and Other Services Cost of Sales is as follows:
Power Delivery Business
Power Delivery’s Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $218 million primarily due to:
•
An increase of $333 million due to higher average electricity costs under Default Electricity Supply contracts.
•
An increase of $32 million in the cost of gas purchases for off-system sales, the result of higher average gas prices.
•
An increase of $24 million for energy and capacity purchased under the Panda PPA.
The aggregate amount of these increases was partially offset by:
•
A decrease of $61 million primarily due to commercial and industrial customer migration to competitive suppliers.
•
A decrease of $60 million due to lower electricity sales as a result of milder weather during 2008 as compared to 2007.
•
A decrease of $45 million due to the sale of Virginia retail electric distribution and wholesale transmission assets in January 2008.
PEPCO HOLDINGS
Fuel and Purchased Energy expense is substantially offset in Regulated T&D Electric Revenue, Default Electricity Supply Revenue, Regulated Gas Revenue and Other Gas Revenue.
Conectiv Energy
The impact of Fuel and Purchased Energy and Other Services Cost of Sales changes with respect to the Conectiv Energy component of the Competitive Energy business are encompassed within the prior discussion under the heading “Conectiv Energy Gross Margin.”
Pepco Energy Services
Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales increased $328 million primarily due to:
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An increase of $236 million due to higher volumes of electricity purchased at higher prices in 2008 to serve increased retail customer load.
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An increase of $65 million due to higher volumes of natural gas purchased at higher prices in 2008 to serve increased retail customer load.
•
An increase of $15 million due to increased construction activities in 2008.
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An increase of $12 million for the generating plants primarily due to capacity costs related to RPM.
Other Operation and Maintenance
A detail of PHI’s other operation and maintenance expense is as follows:
Other Operation and Maintenance expenses of the Power Delivery segment increased by $35 million; however, excluding $3 million resulting from the operation of ACE’s B.L. England electric generating facility prior to its sale in February 2007, Other Operation and Maintenance expenses increased by $38 million. The $38 million increase was primarily due to:
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An increase of $17 million in deferred administrative expenses associated with Default Electricity Supply (offset in Default Supply Revenue) due to (i) the inclusion of $10 million of customer late payment fees in the calculation of the deferral and (ii) a higher rate of recovery of bad debt and administrative expenses as a result of an increase in Default Electricity Supply revenue rates. See the discussion below regarding a 2008 correction of errors in recording customer late payment fees, including $6 million related to prior periods.
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An increase of $11 million due to higher bad debt expenses associated with distribution and Default Electricity Supply customers, of which approximately $6 million was deferred.
PEPCO HOLDINGS
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An increase of $9 million in employee-related costs primarily due to the recording of additional stock-based compensation expense as discussed below, including $6 million related to prior periods.
•
An increase of $3 million in Demand Side Management program costs (offset in Deferred Electric Service Costs).
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An increase of $3 million in legal expenses.
The aggregate amount of these increases was partially offset by:
•
A decrease of $3 million in corrective and preventative maintenance and emergency restoration costs.
•
A decrease of $4 million in regulatory expenses primarily due to higher expenses in 2007 relating to the District of Columbia distribution rate case.
•
A decrease of $3 million due to higher construction project write-offs in 2007 related to customer requested work.
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A decrease of $2 million in accounting services related to tax consulting fees.
Other Operation and Maintenance expense for Conectiv Energy increased by $16 million primarily due to increased planned maintenance at its generating plants.
Other Operation and Maintenance expense for Pepco Energy Services increased by $13 million due to increased compensation, benefit, outside contractor and regulatory costs related to growth in its businesses.
During 2008, PHI recorded adjustments, on a consolidated basis, to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 during which (i) customer late payment fees were incorrectly recognized and (ii) stock-based compensation expense related to certain restricted stock awards granted under the Long-Term Incentive Plan was understated. The late payment fees and stock-based compensation adjustments resulted in increases in Other Operation and Maintenance expenses for the year ended December 31, 2008 of $6 million and $9 million, respectively. These adjustments were not considered material either individually or in the aggregate.
Depreciation and Amortization
Depreciation and Amortization expenses increased by $11 million to $377 million in 2008 from $366 million in 2007. The increase was primarily due to:
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An increase of $21 million due to higher amortization by ACE of stranded costs as a result of an October 2007 Transition Bond Charge rate increase (offset in Default Electricity Supply Revenue)
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An increase of $7 million due to utility plant additions.
The aggregate amount of these increases was partially offset by:
•
A decrease of $15 million due to a change in depreciation rates in accordance with the 2007 Maryland Rate Orders.
PEPCO HOLDINGS
Deferred Electric Service Costs
Deferred Electric Service Costs, which relate only to ACE, decreased by $77 million, to an expense reduction of $9 million in 2008 as compared to an expense increase of $68 million in 2007. The decrease was primarily due to:
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A decrease of $46 million due to a lower rate of recovery of deferred energy costs.
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A decrease of $29 million due to a lower rate of recovery of costs from energy and capacity purchased under the NUG contracts.
•
A decrease of $17 million due to a lower rate of recovery of deferred transmission costs.
The aggregate amount of these decreases was partially offset by:
•
An increase of $15 million primarily due to a higher rate of recovery of New Jersey Societal Benefit program costs.
Deferred Electric Service Costs are substantially offset in Regulated T&D Electric Revenue, Default Electricity Supply Revenue, Fuel and Purchased Energy, and Other Operation and Maintenance.
Impairment Losses
During 2008, Pepco Holdings recorded pre-tax impairment losses of $2 million ($1 million after-tax) related to a joint-venture investment owned by Conectiv Energy. During 2007, Pepco Holdings recorded pre-tax impairment losses of $2 million ($1 million after-tax) related to certain energy services business assets owned by Pepco Energy Services.
Effect of Settlement of Mirant Bankruptcy Claims
The Effect of Settlement of Mirant Bankruptcy Claims reflects the recovery in 2007 of $33 million in operating expenses and certain other costs as damages in the Mirant bankruptcy settlement. See “Capital Resources and Liquidity - Cash Flow Activity - Proceeds from Settlement of Mirant Bankruptcy Claims” herein.
Other Income (Expenses)
Other Expenses (which are net of Other Income) increased by $16 million to a net expense of $300 million in 2008 from a net expense of $284 million in 2007 due to:
•
A decrease of $15 million in income from equity investments.
•
A decrease of $5 million in Contribution in Aid of Construction tax gross-up income.
The aggregate amount of these decreases in income was partially offset by:
•
A net decrease of $10 million in interest expense.
Income Tax Expense
PHI’s consolidated effective tax rates for the years ended December 31, 2008 and 2007 were 35.9% and 36.0%, respectively. While the change in the effective rate between 2008 and 2007 was minimal, the effective rate in each year was impacted by certain non-recurring items. In 2008, PHI recorded certain tax benefits that
PEPCO HOLDINGS
reduced its overall effective tax rate, primarily representing net interest income accrued on effectively settled and uncertain tax positions (including interest related to the settlements with the Internal Revenue Service (IRS) of the like-kind exchange issue and the tentative settlement of the mixed service cost issue, as discussed below, and a claim made with the IRS related to ACE’s tax reporting of fuel over- and under-recoveries), interest income received in 2008 on the Maryland state tax refund referred to below, and deferred tax adjustments related to additional analysis of its deferred tax balances completed in 2008. These benefits were partially offset by limited federal and state tax benefits related to the charge taken on the cross-border energy lease investments in the second quarter of 2008. In 2007, PHI recorded the receipt of Pepco’s Maryland state tax refund in the third quarter of 2007 as a reduction in income tax expense.
During the second quarter 2008, PHI reached a tentative settlement with the IRS concerning the treatment by Pepco, DPL and ACE of mixed service construction costs for income tax purposes during the period 2001 to 2004. On the basis of the tentative settlement, PHI updated its estimated liability related to mixed service costs and, as a result, recorded a net reduction in its liability for unrecognized tax benefits of $19 million and recognized after-tax interest income of $7 million in the second quarter of 2008. See Note (17), “Commitments and Contingencies-Regulatory and Other Matters - IRS Mixed Service Cost Issue,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.
During the fourth quarter of 2008, PHI reached a final settlement with the IRS concerning a transaction between Conectiv and an unaffiliated third party that was treated by Conectiv as a “like-kind exchange” under Internal Revenue Code Section 1031. PHI’s reserve for this issue was more conservative than the actual settlement and resulted in the reversal of a total of $5 million (after-tax) in excess accrued interest related to this matter in the fourth quarter of 2008.
Capital Resources and Liquidity
This section discusses Pepco Holdings’ working capital, cash flow activity, capital requirements and other uses and sources of capital.
Working Capital
At December 31, 2009, Pepco Holdings’ current assets on a consolidated basis totaled $1.9 billion and its current liabilities totaled $2.3 billion. At December 31, 2008, Pepco Holdings’ current assets on a consolidated basis totaled $2.6 billion and its current liabilities totaled $2 billion. The decrease in working capital from December 31, 2008 to December 31, 2009 is primarily due to a $300 million pension plan contribution and a $451 million increase in current maturities of long-term debt.
At December 31, 2009, Pepco Holdings’ cash and current cash equivalents totaled $46 million, of which $22 million was invested in money market funds that invest in U.S. Treasury obligations, and the balance was held as cash and uncollected funds. Current restricted cash equivalents (cash that is available to be used only for designated purposes) totaled $11 million. At December 31, 2008, Pepco Holdings’ cash and current cash equivalents totaled $384 million and its current restricted cash equivalents totaled $10 million.
PHI expects the working capital deficit will be funded during 2010 through cash flow from operations, reduced collateral requirements of the Pepco Energy Services retail electric services business, delayed capital expenditures related to the MAPP project, and the refinancing of long-term debt currently due within a year.
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A detail of PHI’s short-term debt balance and its current maturities of long-term debt and project funding balance follows.
Credit Facilities
PHI, Pepco, DPL and ACE maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under this credit facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million. The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate and the federal funds effective rate plus 0.5% or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. The facility also includes a “swingline loan sub-facility” pursuant to which each company may make same day borrowings in an aggregate amount not to exceed $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof.
The facility commitment expiration date is May 5, 2012, with each company having the right to elect to have 100% of the principal balance of the loans outstanding on the expiration date continued as non-revolving term loans for a period of one year from such expiration date.
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The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens.
The absence of a material adverse change in the borrower’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers.
In November 2008, PHI entered into a second unsecured credit facility in the amount of $400 million with a syndicate of nine lenders, which was amended and restated in October 2009, to extend the facility termination date to October 15, 2010. Under this facility, PHI may obtain revolving loans and swingline loans over the term of the facility. The facility does not provide for the issuance of letters of credit. The interest rate payable on funds borrowed under the facility is, at PHI’s election, based on either (a) the prevailing Eurodollar rate or (b) the highest of (i) the prevailing prime rate, (ii) the federal funds effective rate plus 0.5% or (iii) the one-month Eurodollar rate plus 1.0%, plus a margin that varies according to the credit rating of PHI. Under the swingline loan sub-facility, PHI may obtain loans for up to seven days in an aggregate principal amount which does not exceed 10% of the aggregate borrowing limit under the facility. In order to obtain loans under the facility, PHI must be in compliance with the same covenants and conditions that it is required to satisfy for utilization of the $1.5 billion credit facility. The absence of a material adverse change in PHI’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers. These two facilities are referred to herein collectively as PHI’s “primary credit facilities.” As of December 31, 2009, each borrower was in compliance with the covenants of each of the primary credit facilities.
Cash and Credit Facilities Available as of December 31, 2009
(a) Of this amount, $50 million is available under a bi-lateral agreement expiring in November 2010 that can be used only for the purpose of obtaining letters of credit.
(b) Cash and cash equivalents reported on the Balance Sheet total $46 million, which includes the $22 million invested in money market funds and $24 million held in cash and uncollected funds.
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The disruptions in the capital and credit markets in 2008, combined with the volatility of energy prices, impacted the borrowing capacity and liquidity of PHI and its subsidiaries. To address the challenges posed by the capital and credit market environment and to ensure that PHI and its subsidiaries continued to have sufficient access to cash to meet their liquidity needs, PHI and its subsidiaries undertook a number of actions during 2009:
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In March 2009, Pepco resold $110 million of its Pollution Control Revenue Refunding Bonds, which previously had been issued for the benefit of Pepco by the Maryland Economic Development Corporation.
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In March 2009, Pepco Energy Services entered into a credit intermediation arrangement with an investment banking firm to reduce the collateral requirements associated with its retail energy sales business (see “Collateral Requirements of the Competitive Energy Business”).
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In May 2009, PHI entered into a $50 million, 18-month bi-lateral credit agreement, which can only be used for the purpose of obtaining letters of credit.
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In October 2009, PHI amended its $400 million unsecured credit facility to extend the facility termination date to October 15, 2010.
Collateral Requirements of the Competitive Energy Business
In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, is exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) has assumed by novation the electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts and (ii) has agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any obligation to post collateral based on changes in electricity prices. As of December 31, 2009, approximately 17% of Pepco Energy Services’ wholesale electricity purchase obligations (measured in megawatt hours) were covered by this credit intermediation arrangement with MSCG. The fees in the amount of $25 million incurred by Pepco Energy Services in connection with the entry into this agreement are being amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation. For the year ended December 31, 2009, approximately $16 million of the fees have been amortized. As the retail electric and natural gas supply business are wound down, Pepco Energy Services’ collateral requirements will be further reduced.
In addition to Pepco Energy Services’ retail energy supply business, Conectiv Energy and Pepco Energy Services in the ordinary course of business enter into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce their financial exposure to changes in the value of their assets and obligations due to energy price fluctuations. These contracts also typically have collateral requirements.
Depending on the contract terms, the collateral required to be posted by Pepco Energy Services and Conectiv Energy can be of varying forms, including cash and letters of credit. As of December 31, 2009, Pepco Energy Services and Conectiv Energy had posted net cash collateral of $123 million and $240 million, respectively, and letters of credit of $157 million and $22 million, respectively. At December 31, 2008, Pepco Energy Services and Conectiv Energy had posted net cash collateral of $125 million and $206 million, respectively, and letters of credit of $474 million and $84 million, respectively.
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At December 31, 2009 and 2008, the amount of cash, plus borrowing capacity under the PHI credit facilities available to meet the future liquidity needs of the Competitive Energy business totaled $820 million and $684 million, respectively.
Pension and Postretirement Benefit Plans
PHI and its subsidiaries sponsor pension and postretirement benefit plans for their employees. The pension and postretirement benefit plans experienced significant declines in the fair value of plan assets in 2008, which has resulted in increased pension and postretirement benefit costs in 2009 and increased plan funding requirements.
Based on the results of the 2009 actuarial valuation, PHI’s net periodic pension and other postretirement benefit costs were approximately $149 million in 2009 versus $64 million in 2008. The current estimate of benefit cost for 2010 is $116 million. The utility subsidiaries are generally responsible for approximately 80% to 85% of the total PHI net periodic pension and other postretirement benefit costs. Approximately 30% of net periodic pension and other postretirement benefit costs are capitalized. PHI estimates that its net periodic pension and other postretirement benefit expense will be approximately $80 million in 2010, as compared to $103 million in 2009 and $44 million in 2008.
Pension benefits are provided under PHI’s defined benefit pension plan (the PHI Retirement Plan), a non contributory retirement plan that covers substantially all employees of Pepco, DPL and ACE and certain employees of other PHI subsidiaries. PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the funding target as defined under the Pension Protection Act of 2006. The funding target under the Pension Protection Act is an amount that is being phased in over time, and will reach 100% of accrued pension liability by 2011. The funding target was 94% of the accrued liability for 2009 and is 96% of the accrued liability for 2010.
During 2009, PHI has made discretionary tax-deductible contributions totaling $300 million to the PHI Retirement Plan, which brought plan assets to at least the funding target level for 2009 under the Pension Protection Act. Of this amount, $240 million was contributed through tax-deductible contributions from Pepco, ACE and DPL in the amounts of $170 million, $60 million and $10 million, respectively. The remaining $60 million contribution was made through tax-deductible contributions from the PHI Service Company. In 2008, no contributions were made to the PHI Retirement Plan.
Under the Pension Protection Act, if a plan incurs a funding shortfall in the preceding plan year, there can be required minimum quarterly contributions in the current and following plan years. PHI satisfied the minimum required contribution rules in 2008 and 2009 and does not expect to have any required contributions in 2010. Although PHI projects there will be no minimum funding requirement under the Pension Protection Act guidelines in 2010, PHI currently estimates it may make discretionary tax-deductible contributions in 2010 of approximately $100 million to bring its plan assets to at least the funding target level for 2010 under the Pension Protection Act. For additional discussion of PHI’s Pension and Other Postretirement Benefits, see Note (10), “Pensions and Other Postretirement Benefits,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.
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Cash Flow Activity
PHI’s cash flows for 2009, 2008, and 2007 are summarized below:
Operating Activities
Cash flows from operating activities are summarized below for 2009, 2008, and 2007:
Net cash from operating activities was $193 million higher for the year ended December 31, 2009, compared to the same period in 2008. A portion of this increase is attributable to the release from restricted cash of $102 million related to the Mirant settlement (previously discussed in the “Earnings Overview” section above), and the 2009 receipt of the Federal income tax refund from the IRS of $138 million associated with the carry-back of the net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions paid in 2009 (which were deductible for 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs. In addition, the 2009 net income included unrealized losses on derivatives of $59 million. PHI also experienced reduced cash requirements related to purchases of inventory (associated with lower gas and electric prices). Offsetting these increases were the pension plan contributions of $300 million made during 2009.
Included in the 2008 net cash from operating activities was a non-cash charge taken on the cross-border energy lease investments (described in the “Earnings Overview” section above) and additional collateral requirements of the Competitive Energy business of $274 million.
Net cash from operating activities was $382 million lower for the year ended December 31, 2008 compared to the year ended December 31, 2007. In addition to a $34 million decrease in net income, the primary contributor was a $336 million increase in cash collateral requirements associated with Competitive Energy activities. The cash collateral requirements of the Competitive Energy business fluctuate significantly based on changes in energy market prices.
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Investing Activities
Cash flows used by investing activities during 2009, 2008, and 2007 are summarized below.
Net cash used by investing activities increased $146 million for the year ended December 31, 2009 compared to 2008. The increase was due primarily to an $83 million increase in capital expenditures, of which $62 million was attributable to Conectiv Energy and $35 million was attributable to Power Delivery, partially offset by a decrease in Pepco Energy Services capital expenditures. The increase in Conectiv Energy capital expenditures was primarily due to the construction of new generating facilities. The increase in Power Delivery capital expenditures was primarily attributable to capital costs associated with the Mid-Atlantic Power Pathway (MAPP) and Blueprint for the Future projects. The increase was also affected by the $52 million reduction in cash proceeds from the sale of other assets. Cash proceeds from the sale of assets in 2008 consisted primarily of $54 million received by DPL from the sale of its retail electric distribution assets and its wholesale electric transmission assets in Virginia.
Net cash used by investing activities increased $132 million for the year ended December 31, 2008 compared to the year ended December 31, 2007. The increase was due primarily to (i) $158 million increase in capital expenditures, of which $96 million was attributable to Conectiv Energy and $33 million was attributable to Power Delivery, and (ii) the receipt by Pepco in 2007 of the proceeds of the Mirant bankruptcy settlement, of which $15 million was designated as a reimbursement of certain investments in property, plant and equipment, offset by (iii) an increase of $45 million in cash proceeds from the sale of assets. The increase in Conectiv Energy capital expenditures was primarily due to the construction of new generating facilities. The increase in Power Delivery capital expenditures was primarily attributable to capital costs associated with new customer services, distribution reliability, and transmission. Proceeds from the sale of assets in 2007 consisted primarily of $9 million received from the sale by ACE of the B.L. England generating facility.
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Financing Activities
Cash flows used by financing activities during 2009, 2008 and 2007 are summarized below.
Net cash from financing activities decreased $714 million for the year ended 2009, compared to the same period in 2008, principally due to the decrease in 2009 of issuances of long-term debt and common stock, partially offset by the decrease in amounts spent to reacquire long-term debt.
Net cash provided by financing activities in 2008 was $837 million higher than in 2007, primarily due to an increase in issuances of common stock, long-term debt and 2008 borrowings under the credit facilities, and a decrease in repayments of outstanding long-term debt.
Common Stock Dividends
Common stock dividend payments were $238 million in 2009, $222 million in 2008, and $203 million in 2007. The increase in common dividends paid in 2009 was the result of additional shares outstanding, primarily from PHI’s sale of 16.1 million shares of common stock in November 2008. The increase in common dividends paid in 2008 was the result of (i) additional shares outstanding, primarily from PHI’s sale of 6.5 million shares of common stock in November 2007, and (ii) a quarterly dividend increase from 26 cents per share to 27 cents per share beginning in the first quarter of 2008.
Changes in Outstanding Common Stock
In November 2008, PHI sold 16.1 million shares of common stock in a registered offering at a price per share of $16.50, resulting in gross proceeds of $265 million. In November 2007, PHI sold 6.5 million shares of common stock in a registered offering at a price per share of $27.00, resulting in gross proceeds of $176 million.
Under the Shareholder Dividend Reinvestment Plan (DRP), PHI issued 2.2 million shares of common stock in 2009, 1.3 million shares of common stock in 2008, and 1 million shares of common stock in 2007.
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Changes in Outstanding Preferred Stock
Cash flows from the redemption of preferred stock in 2009, 2008 and 2007 are summarized in the chart below.
Changes in Outstanding Long-Term Debt
Cash flows from the issuance and redemption of long-term debt in 2009, 2008 and 2007 are summarized in the charts below.
(a) Secured by an outstanding series of Collateral First Mortgage Bonds. See Note (11), “Debt,” to the consolidated financial statements of PHI in Part II, Item 8 of this Form 10-K.
(b) Excludes DPL $150 million two-year bank loan that was converted to a 364-day bank loan.
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(a) Repurchased by the indicated company pending resale to the public. See “Purchase and Resale of Tax-Exempt Auction Rate Bonds” below.
Purchase and Resale of Tax-Exempt Auction Rate Bonds
The redemptions in 2008 shown above include the purchase at par by PHI subsidiaries of $276 million in aggregate principal amount of insured tax-exempt auction rate bonds issued by municipal authorities for the benefit of the respective PHI subsidiaries. These purchases were made in response to disruption in the market for municipal auction rate securities that made it difficult for the remarketing agent to successfully remarket the bonds, at that time. These bond purchases consisted of the following:
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The purchase by Pepco of Pollution Control Revenue Refunding Bonds issued by the Maryland Economic Development Corporation of an aggregate principal amount of $110 million (the Purchased Pepco Tax-Exempt Bonds).
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The purchase by DPL of Exempt Facilities Refunding Revenue Bonds issued by The Delaware Economic Development Authority in the aggregate principal amount of $112 million (the Purchased DPL Tax-Exempt Bonds).
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The purchase by ACE of (i) Pollution Control Revenue Refunding Bonds issued by Cape May County in the aggregate principal amount of $32 million and (ii) Pollution Control Revenue Refunding Bonds issued by Salem County in the aggregate principal amount of $23 million (the Purchased ACE Tax-Exempt Bonds).
Upon the purchase of the tax-exempt bonds, the obligations of the PHI subsidiaries with respect to these tax-exempt bonds were considered to be extinguished for accounting purposes; however, each of the companies continued to hold the bonds, while monitoring the market and evaluating the options for reselling the bonds to the public at some time in the future.
In 2009, PHI subsidiaries resold or redeemed the following tax-exempt bonds that they purchased in 2008:
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Pepco resold the entire $110 million of the Purchased Pepco Tax-Exempt Bonds, which is accounted for as long-term debt.
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DPL redeemed $33 million of the Purchased DPL Tax-Exempt Bonds.
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ACE redeemed $32 million of the Purchased ACE Tax-Exempt Bonds.
Changes in Short-Term Debt
During 2009, the market for commercial paper was less restrictive than it had been in 2008. As a result PHI and its utility subsidiaries were able to issue commercial paper and repay their bank loans and their loans outstanding under the $1.5 billion credit facility. As of December 31, 2009, PHI had a total of $384 million of commercial paper outstanding, as compared to no commercial paper outstanding at December 31, 2008 and $137 million of commercial paper outstanding at December 31, 2007.
Due to the capital and credit market disruptions in 2008, the market for commercial paper was severely restricted. As a result, PHI and its subsidiaries were unable to issue commercial paper on a day-to-day basis either in amounts, or with maturities, that were typically required for cash management purposes. Given their restricted access to the commercial paper market and the general uncertainty in the credit markets, PHI and each of its subsidiaries borrowed under the $1.5 billion credit facility to create a cash reserve for future short-term operating needs. As of December 31, 2008, PHI had a loan of $50 million outstanding and Pepco had a loan of $100 million outstanding under this facility. These loans were repaid in 2009.
In 2008, both DPL and Pepco entered into short-term bank loans. In March 2008, DPL obtained a $150 million unsecured bank loan that matured in July 2009. In May 2008, Pepco obtained a $25 million bank loan that matured in April 2009 and a $25 million bank loan that matured in September 2008.
In 2008 and 2009, the following insured Variable Rate Demand Bonds (VRDBs) were tendered to The Bank of New York Mellon, as bond trustee, by the holders and purchased by The Bank of New York Mellon pursuant to standby bond purchase agreements for the respective series:
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$18.2 million of Pollution Control Revenue Refunding Bonds 1997 Series A issued by Salem County for the benefit of ACE, and
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$4.4 million of Pollution Control Revenue Refunding Bonds 1997 Series B issued by Salem County for the benefit of ACE.
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In June 2009, the VRDBs were resold to the public. In connection with this remarketing, the financial guaranty insurance policies issued as credit support for the VRDBs were cancelled and replaced with letters of credit issued by The Bank of New York Mellon. The letters of credit will expire on June 23, 2010 unless extended. The expiration, cancellation, or termination of a letter of credit prior to the maturity of the related VRDBs will require DPL to repurchase the VRDBs.
In November 2008, DPL repurchased $9 million of VRDBs due 2024.
In 2007, with cash from operations, PHI redeemed $36 million in short-term debt.
Sale of Virginia Retail Electric Distribution and Wholesale Transmission Assets
In January 2008, DPL completed (i) the sale of its retail electric distribution assets on the Eastern Shore of Virginia for a purchase price of approximately $49 million, and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia for a purchase price of approximately $5 million.
Sales of ACE Generating Facilities
In 2007, ACE completed the sale of the B.L. England generating facility for a price of $9 million. In 2008, ACE received an additional $4 million in an arbitration settlement relating to the sale. For a discussion of the accounting treatment of the gains from these sales, see Note (7), “Regulatory Assets and Regulatory Liabilities,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.
Proceeds from Settlement of Mirant Bankruptcy Claims
In 2000, Pepco sold substantially all of its electricity generating assets to Mirant. As part of the sale, Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco was obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco was obligated to pay to Panda. In 2003, Mirant commenced a voluntary bankruptcy proceeding in which it sought to reject certain obligations that it had undertaken in connection with the asset sale. As part of the settlement of Pepco’s claims against Mirant arising from the bankruptcy, Pepco agreed not to contest the rejection by Mirant of its obligations under the “back-to-back” arrangement in exchange for the payment by Mirant of damages corresponding to the estimated amount by which the purchase price that Pepco was obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $414 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. In September 2008, Pepco transferred the Panda PPA to Sempra Energy Trading LLC (Sempra), along with a payment to Sempra, thereby terminating all further rights, obligations and liabilities of Pepco under the Panda PPA. In March 2009, the DCPSC issued an order approving Pepco’s sharing proposal for the District of Columbia under which approximately $24 million was distributed to District of Columbia customers as a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of approximately $14 million for the quarter ended March 31, 2009. On July 2, 2009, the MPSC approved a settlement agreement among Pepco, the Maryland Office of People’s Counsel and the MPSC staff under which Pepco distributed approximately $38 million to Maryland customers during the billing month of August 2009 through a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of approximately $26 million in the quarter ended September 30, 2009. The final resolution of this matter allowed for the release of $64 million previously accounted for as restricted cash and the extinguishment of the corresponding regulatory liability.
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Capital Requirements
Capital Expenditures
Pepco Holdings’ total capital expenditures for the year ended December 31, 2009 totaled $864 million, of which $622 million was incurred by Power Delivery, $200 million by Conectiv Energy, $12 million by Pepco Energy Services and $30 million by Corporate and Other. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability, and transmission.
The table below shows the projected capital expenditures for Power Delivery, Conectiv Energy, Pepco Energy Services and Corporate and Other for the five-year period 2010 through 2014. Pepco Holdings expects to fund these expenditures through internally generated cash and external financing.
(a) Amounts are presented on a gross basis on the assumption that the awards are not subject to federal or state tax.
In 2009, the U.S. Department of Energy (DOE) announced awards under the American Recovery and Reinvestment Act of 2009 of:
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$105 million and $44 million in Pepco’s Maryland and the District of Columbia service territories respectively for the implementation of an advanced metering infrastructure (AMI) system, direct load control, distribution automation, and communications infrastructure.
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$19 million to ACE for the implementation of direct load control, distribution automation, and communications infrastructure in its New Jersey service territory.
PHI is currently in the process of finalizing certain terms and conditions of the awards with the DOE. Of the $168 million, $130 million, as shown in the table above, will offset Blueprint for the Future and other capital expenditures that the PHI subsidiaries are projected to incur. The remaining $38 million will be used to help offset ongoing expenses associated with direct load control and other Power Delivery programs.
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Distribution, Transmission and Gas Delivery
The projected capital expenditures listed in the table for distribution (other than Blueprint for the Future), transmission (other than the MAPP project) and gas delivery are primarily for facility replacements and upgrades to accommodate customer growth and reliability.
Blueprint for the Future
For a discussion of the Blueprint for the Future initiative, see Item 1, “Business - Description of Business - Blueprint for the Future” of this Form 10-K.
MAPP Project
The total cost of the MAPP project is currently estimated to be $1.2 billion. For a discussion of the MAPP project, see Item 1, “Business - Description of Business - MAPP Project” of this Form 10-K.
MAPP/DOE Loan Program
PHI has applied for a $684 million loan guarantee from the DOE for a substantial portion of the MAPP project, primarily the Calvert Cliffs to Indian River segment. The loan guarantee is available under a loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes that the guarantee would allow PHI to obtain 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 terms of the guarantee program.
Delta Project
Conectiv Energy is constructing a 545 megawatt natural gas and oil-fired combined-cycle electricity generation plant in Peach Bottom Township, Pennsylvania (Delta Project). The total construction expenditures including capitalized interest for the Delta Project are expected to be $470 million, of which $178 million was expended in 2009, $62 million in 2008 and $63 million in 2007. Projected expenditures of $147 million in 2010 and $20 million in 2011 are included in Conectiv Energy’s projected capital expenditures shown in the table above. The plant is expected to become operational during the second quarter of 2011.
Cumberland Project
In 2009, Conectiv Energy completed construction of a new 100 megawatt combustion turbine power plant in Millville, New Jersey. The total construction expenditure including capitalized interest for this project was $75 million. The plant became operational during the second quarter of 2009.
Dividends
Pepco Holdings’ annual dividend rate on its common stock is determined by the Board of Directors on a quarterly basis and takes into consideration, among other factors, current and possible future developments that may affect PHI’s income and cash flows. In 2009, PHI’s Board of Directors declared quarterly dividends of 27 cents per share of common stock payable on March 31, 2009, June 30, 2009, September 30, 2009 and December 31, 2009.
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On January 28, 2010, the 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, on a stand-alone basis, generates no operating income of its own. Accordingly, its ability to pay dividends to its shareholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of PHI’s direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and, in the case of ACE, the regulatory requirement that it obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by the subsidiaries, and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Pepco and DPL have no shares of preferred stock outstanding. Currently, the capitalization ratio limitation to which ACE is subject and the restriction in the ACE charter do not limit ACE’s ability to pay common stock dividends.
Contractual Obligations and Commercial Commitments
Summary information about Pepco Holdings’ consolidated contractual obligations and commercial commitments at December 31, 2009, is as follows:
(a) Includes transition bonds issued by Atlantic City Electric Transition Funding, LLC.
(b) Excludes contracts for the purchase of electricity to satisfy Default Electricity Supply load service obligations which have neither a fixed commitment amount nor a minimum purchase amount. In addition, costs are recoverable from customers.
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Third Party Guarantees, Indemnifications and Off-Balance Sheet Arrangements
For a discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (17), “Commitments and Contingencies,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.
The following table provides detail on changes in the net asset or liability position of the Competitive Energy business (consisting of the activities of the Conectiv Energy and Pepco Energy Services segments) with respect to energy commodity contracts for the year ended December 31, 2009. The balances reflected in the table are stated gross, pre-tax and before the netting of collateral as required by FASB guidance on the offsetting of balance sheet accounts (ASC 210-20).
Notes:
(a) Includes all hedging and trading activities recorded at fair value through Accumulated Other Comprehensive Loss (AOCL) or on the Statements of Income, as required.
The $328 million net liability on energy contracts at December 31, 2009 was primarily attributable to losses on power swaps and natural gas futures and swaps designated as hedges of future energy purchases or production under FASB guidance on derivatives and hedging (ASC 815). Prices of electricity and natural gas declined during the year, which resulted in unrealized losses on the energy contracts of the Competitive Energy business. Competitive Energy recorded unrealized losses of $340 million on energy contracts in Accumulated Other Comprehensive Loss as these energy contracts were effective hedges under the guidance. When these energy contracts settle, the related realized gains or losses are expected to be largely offset by the realized loss or gain on future energy purchases or production that will be used to settle the sales obligations of the Competitive Energy business with its customers.
PEPCO HOLDINGS
PHI uses its best estimates to determine the fair value of the commodity and derivative contracts that are held and sold by its Competitive Energy business. The fair values in each category presented below reflect forward prices and volatility factors as of December 31, 2009 and are subject to change as a result of changes in these factors:
Notes:
(a) Includes all hedge activity and trading activities recorded at fair value through AOCL or on the Statements of Income, as required.
(b) Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms that are readily observable in the market.
(c) Modeled values include significant inputs, usually representing more than 10% of the valuation, not readily observable in the market. The modeled valuation above represents the fair valuation of certain long-dated power transactions based on limited observable broker prices extrapolated for periods beyond two years into the future.
Contractual Arrangements with Credit Rating Triggers or Margining Rights
Under certain contractual arrangements entered into by PHI’s subsidiaries in connection with the Competitive Energy business and other transactions, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of the subsidiary are downgraded. In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade. Based on contractual provisions in effect at December 31, 2009, a one-level downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries, which would decrease PHI’s rating to below “investment grade,” would increase the collateral obligation of PHI and its subsidiaries by up to $460 million, $246 million of which is the net settlement amount attributable to derivatives, normal purchase and normal sale contracts, collateral, and other contracts under master netting agreements as described in Note (15), “Derivative Instruments and Hedging Activities,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K. The remaining $214 million is attributable primarily to energy services contracts and accounts payable to independent system operators and distribution companies under full requirements contracts entered into by Pepco Energy Services. PHI believes that it and its utility subsidiaries currently have sufficient liquidity under the primary credit facilities and otherwise to fund these financial obligations were they to be incurred.
Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with Competitive Energy and Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the applicable arrangements. Pursuant to these margining rights, the affected PHI subsidiary may receive, or be required to post, collateral due to energy price movements. As of December 31, 2009, Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities provided net cash collateral in the amount of $364 million in connection with these activities.
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Environmental Remediation Obligations
PHI’s accrued liabilities as of December 31, 2009 include approximately $12 million, of which approximately $6 million is expected to be incurred in 2010, for potential environmental cleanup and other costs related to sites at which an operating subsidiary is a potentially responsible party, is alleged to be a third-party contributor, or has made a decision to clean up contamination on its own property. For information regarding projected expenditures for environmental control facilities, see Item 1 “Business - Environmental Matters,” of this Form 10-K. The most significant environmental remediation obligations as of December 31, 2009, were:
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Approximately $2 million, of which approximately $1 million is expected to be incurred in 2010, payable by DPL in accordance with a 2001 consent agreement reached with the Delaware Department of Natural Resources and Environmental Control, for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination that resulted from an oil release at the Indian River power plant, which was sold in June 2001.
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Approximately $4 million in environmental remediation costs, of which approximately $2 million is expected to be incurred in 2010, payable by Conectiv Energy associated with the Deepwater generating facility.
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Approximately $2 million, constituting Pepco’s liability for a remedy at the Metal Bank/Cottman Avenue site.
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Approximately $2 million, nearly 90% of which is expected to be incurred in 2010, payable by DPL in connection with the Wilmington Coal Gas South site located in Wilmington, Delaware, to remediate residual material from the historical operation of a manufactured gas plant.
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Less than $1 million, of which approximately 10% is expected to be incurred in 2010, payable by Pepco for long-term monitoring associated with a pipeline oil release that occurred in 2000.
Sources of Capital
Pepco Holdings’ sources to meet its long-term funding needs, such as capital expenditures, dividends, and new investments, and its short-term funding needs, such as working capital and the temporary funding of long-term funding needs, include internally generated funds, securities issuances and bank financing under new or existing facilities. PHI’s ability to generate funds from its operations and to access capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of PHI’s potential funding sources. See Item 1A, “Risk Factors,” of this Form 10-K, for additional discussion of important factors that may impact these sources of capital.
Cash flow from Operations
Cash flow generated by regulated utility subsidiaries in the Power Delivery business is the primary source of PHI’s cash flow from operations. Additional cash flows are generated by PHI’s non-regulated subsidiaries and from the sale of non-core assets.
Short-Term Funding Sources
Pepco Holdings and its regulated utility subsidiaries have traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs but may also be used to fund temporarily long-term capital requirements.
PEPCO HOLDINGS
Pepco Holdings maintains an ongoing commercial paper program of up to $875 million. Pepco and DPL have ongoing commercial paper programs of up to $500 million, and ACE up to $250 million. The commercial paper can be issued with maturities of up to 270 days.
Long-Term Funding Sources
The sources of long-term funding for PHI and its subsidiaries are the issuance of debt and equity securities and borrowing under long-term credit agreements. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures and new investments, and to repay or refinance existing indebtedness.
Regulatory Restrictions on Financing Activities
The issuance of debt securities by PHI’s principal subsidiaries requires approval of either FERC or one or more state public utility commissions. Neither FERC approval nor state public utility commission approval is required as a condition to the issuance of securities by PHI.
State Financing Authority
Pepco’s long-term financing activities (including the issuance of securities and the incurrence of debt) are subject to authorization by the DCPSC and MPSC. DPL’s long-term financing activities are subject to authorization by MPSC and the DPSC. ACE’s long-term and short-term (consisting of debt instruments with a maturity of one year or less) financing activities are subject to authorization by the NJBPU. Each utility, through periodic filings with the state public service commission(s) having jurisdiction over its financing activities, typically seeks to maintain standing authority sufficient to cover its projected financing needs over a multi-year period.
FERC Financing Authority
Under the Federal Power Act (FPA), FERC has jurisdiction over the issuance of long-term and short-term securities of public utilities, but only if the issuance is not regulated by the state public utility commission in which the public utility is organized and operating. Under these provisions, FERC has jurisdiction over the issuance of short-term debt by Pepco and DPL. Pepco and DPL have obtained FERC authority for the issuance of short-term debt. Because Conectiv Energy and Pepco Energy Services also qualify as public utilities under the FPA and are not regulated by a state utility commission, FERC also has jurisdiction over the issuance of securities by those companies. Conectiv Energy and Pepco Energy Services have obtained the requisite FERC financing authority in their respective market-based rate orders.
Money Pool
Pepco Holdings operates a system money pool under a blanket authorization adopted by FERC. The money pool is a cash management mechanism used by Pepco Holdings to manage the short-term investment and borrowing requirements of its subsidiaries that participate in the money pool. Pepco Holdings may invest in but not borrow from the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by Pepco Holdings. Eligible subsidiaries with cash requirements may borrow from the money pool. Borrowings from the money pool are unsecured. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on Pepco Holdings’ short-term borrowing rate. Pepco Holdings deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require Pepco Holdings to borrow funds for deposit from external sources.
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Regulatory And Other Matters
For a discussion of material pending regulatory and legal proceedings, and certain other commitments and contingencies, see Note (17), “Commitments and Contingencies,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.
Critical Accounting Policies
General
Pepco Holdings has identified the following accounting policies, including certain estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes in its financial condition or results of operations under different conditions or using different assumptions. Pepco Holdings has discussed the development, selection and disclosure of each of these policies with the Audit Committee of the Board of Directors.
Goodwill Impairment Evaluation
PHI believes that the estimates involved in its goodwill impairment evaluation process represent “Critical Accounting Estimates” because they are subjective and susceptible to change from period to period as management makes assumptions and judgments, and the impact of a change in assumptions and estimates could be material to financial results.
Substantially all of PHI’s goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated to the Power Delivery reporting unit for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350). Management has identified Power Delivery as a single reporting unit based on the aggregation of components which have similar economic characteristics, similar products and services and operate in a similar regulatory environment. The first step of the goodwill impairment test compares the fair value of the reporting unit with its carrying amount, including goodwill. Management uses its best judgment to make reasonable projections of future cash flows for Power Delivery when estimating the reporting unit’s fair value. In addition, PHI selects a discount rate for the associated risk with those estimated cash flows. These judgments are inherently uncertain, and actual results could vary from those used in PHI’s estimates. The impact of such variations could significantly alter the results of a goodwill impairment test, which could materially impact the estimated fair value of Power Delivery and potentially the amount of any impairment recorded in the financial statements.
PHI has historically tested its goodwill for impairment annually as of July 1 from 2002 to 2009, and on an interim basis whenever an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. After completion of the July 1, 2009 annual test, PHI changed the date of its annual test to November 1, and accordingly PHI has performed its next annual impairment test as of November 1, 2009. Factors that may result in an interim impairment test include, but are not limited to: a change in identified reporting units; an adverse change in business conditions; a protracted decline in stock price causing market capitalization to fall below book value; an adverse regulatory action; or impairment of long-lived assets in the reporting unit.
PHI’s November 1, 2009 annual impairment test indicated that its goodwill was not impaired. See Note (6), “Goodwill,” to the consolidated financial statements of Pepco Holdings, set forth in Part II, Item 8 of this Form 10-K. PHI performed an interim test of goodwill for impairment as of March 31, 2009 which updated an interim test performed as of December 31, 2008 as its market capitalization was below its book value at both points in time and its market capitalization relative to book value had declined significantly from the December 31, 2008 market capitalization. PHI concluded that its goodwill was not impaired at either July 1, 2009, March 31, 2009, or December 31, 2008. Although PHI’s market capitalization remained below book value as of December 31, 2009, PHI did not perform an interim goodwill impairment test because its market capitalization relative to book value improved compared to earlier periods and there were no other indicators of potential impairment.
PEPCO HOLDINGS
In order to estimate the fair value of the Power Delivery reporting unit, PHI uses two discounted cash flow models. The models differ in the method used to calculate the terminal value of the reporting unit. One model estimates terminal value based on a constant annual cash flow growth rate that is consistent with Power Delivery’s long-term view of the business, and the other model estimates terminal value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. The models use a cost of capital appropriate for a regulated utility as the discount rate for the estimated cash flows associated with the reporting unit. PHI has consistently used this valuation methodology to estimate the fair value of Power Delivery.
The estimation of fair value is dependent on a number of factors that are sourced from the Power Delivery reporting unit’s business forecast, including but not limited to interest rates, growth assumptions, returns on rate base, operating and capital expenditure requirements, and other factors, changes in which could materially impact the results of impairment testing. Assumptions and methodologies used in the models were consistent with historical experience. A hypothetical 10 percent decrease in fair value of the Power Delivery reporting unit at November 1, 2009 would not have resulted in the Power Delivery reporting unit failing the first step of the impairment test, as defined in the guidance, as the estimated fair value of the reporting unit would have been above its carrying value Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the Power Delivery reporting unit include utility sector market performance, sustained adverse business conditions, change in forecasted revenues, higher operating and capital expenditure requirements, a significant increase in the cost of capital, and other factors.
Long-Lived Assets Impairment Evaluation
Pepco Holdings believes that the estimates involved in its long-lived asset impairment evaluation process represent “Critical Accounting Estimates” because (i) they are highly susceptible to change from period to period because management is required to make assumptions and judgments about undiscounted and discounted future cash flows and fair values, which are inherently uncertain, (ii) actual results could vary from those used in Pepco Holdings’ estimates and the impact of such variations could be material, and (iii) the impact that recognizing an impairment would have on Pepco Holdings’ assets as well as the net loss related to an impairment charge could be material. The primary assets subject to a long-lived asset impairment evaluation are property, plant, and equipment.
The FASB guidance on the accounting for the impairment or disposal of long-lived assets (ASC 360), requires that certain long-lived assets must be tested for recoverability whenever events or circumstances indicate that the carrying amount may not be recoverable, such as (1) a significant decrease in the market price of a long-lived asset or asset group, (2) a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition, (3) a significant adverse change in legal factors or in the business climate, including an adverse action or assessment by a regulator, (4) an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset or asset group, (5) a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group, and (6) a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
An impairment loss may only be recognized if the carrying amount of an asset is not recoverable and the carrying amount exceeds its fair value. The asset is deemed not to be recoverable when its carrying amount exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. In order to estimate an asset’s future cash flows, Pepco Holdings considers historical cash flows. Pepco Holdings uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel costs, legislative initiatives, and operating costs. If necessary, the process of determining fair value is done consistent with the process described in assessing the fair value of goodwill discussed above.
PEPCO HOLDINGS
Accounting for Derivatives
Pepco Holdings believes that the estimates involved in accounting for its derivative instruments represent “Critical Accounting Estimates” because management exercises judgment in the following areas, any of which could have a material impact on its financial statements: (i) the application of the definition of a derivative to contracts to identify derivatives, (ii) the election of the normal purchases and normal sales exception from derivative accounting, (iii) the application of cash flow hedge accounting (iv) the estimation of fair value used in the measurement of derivatives and hedged items, which are highly susceptible to changes in value over time due to market trends or, in certain circumstances, significant uncertainties in modeling techniques used to measure fair value that could result in actual results being materially different from Pepco Holdings’ estimates. See Note (2), “Significant Accounting Policies - Accounting for Derivatives” and Note (15), “Derivative Instruments and Hedging Activities,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K for information on PHI’s accounting for derivatives.
Pepco Holdings and its subsidiaries use derivative instruments primarily to manage risk associated with commodity prices. The definition of a derivative in the FASB guidance results in management having to exercise judgment, such as whether there is a notional amount or net settlement provision in contracts. Management assesses a number of factors before determining whether it can designate derivatives for the normal purchase or normal sale exception from derivative accounting, including whether it is probable that the contracts will physically settle with delivery of the underlying commodity. The application of cash flow hedge accounting often requires judgment in the prospective and retrospective assessment and measurement of hedge effectiveness as well as whether it is probable that the forecasted transaction will occur. The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, external broker quotes are used to determine fair value. Internal models use market information when external broker quotes are not available for some custom and complex instruments. For certain long-dated instruments, broker or exchange data is extrapolated for future periods where limited market information is available. Models are also used to estimate volumes for certain transactions. The same valuation methods are used for risk management purposes to determine the value of non-derivative, commodity exposure.
Pension and Other Postretirement Benefit Plans
Pepco Holdings believes that the estimates involved in reporting the costs of providing pension and other postretirement benefits represent “Critical Accounting Estimates” because (i) they are based on an actuarial calculation that includes a number of assumptions which are subjective in nature, (ii) they are dependent on numerous factors resulting from actual plan experience and assumptions of future experience, and (iii) changes in assumptions could impact Pepco Holdings’ expected future cash funding requirements for the plans and would have an impact on the projected benefit obligations, and the reported annual net periodic pension and other postretirement benefit cost on the income statement.
Assumptions about the future, including the expected return on plan assets, discount rate applied to benefit obligations, the anticipated rate of increase in health care costs and participant compensation have a significant impact on employee benefit costs. In terms of quantifying the anticipated impact of a change in the critical assumptions while holding all other assumptions constant, Pepco Holdings estimates that a .25% decrease in the discount rate used to value the benefit obligations could result in a $5 million increase in net periodic benefit cost. Additionally, Pepco Holdings estimates that a .25% reduction in the expected return on plan assets could result in a $4 million increase in net periodic benefit cost. A 1.0% increase in the assumed healthcare cost trend rate could result in a $2 million increase net periodic benefit cost. In addition to its impact on cost, a .25% decrease in the discount rate would increase PHI’s projected pension benefit obligation by $46 million and would increase the accumulated postretirement benefit
PEPCO HOLDINGS
obligation by $16 million at December 31, 2009. Pepco Holdings’ management consults with its actuaries and investment consultants when selecting its plan assumptions, and benchmarks its critical assumptions against other corporate plans.
The impact of changes in assumptions and the difference between actual and expected or estimated results on pension and postretirement obligations is generally recognized over the working lives of the employees who benefit under the plans rather than immediately recognized in the statements of income.
For additional discussion, see Note (10), “Pensions and Other Postretirement Benefits,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.
Accounting for Regulated Activities
FASB guidance on the accounting for regulated activities applies to the Power Delivery businesses of Pepco, DPL, and ACE and can result in the deferral of costs or revenue that would otherwise be recognized by non-regulated entities. PHI defers the recognition of costs and records regulatory assets when it is probable those costs will be recovered in future rates charged to its customers. PHI defers the recognition of revenues and records regulatory liabilities when it is probable that it will refund payments received from customers in the future or that it will incur future costs related to the payments currently received from customers. Pepco Holdings believes that the judgments involved in accounting for its regulated activities represent “Critical Accounting Estimates” because (i) management must interpret laws and regulatory commission orders to assess the probability of the recovery of costs from customers or the return of revenues to customers when determining whether those costs or revenues should be deferred, (ii) decisions made by regulatory commissions or legislative changes at a later date could vary from earlier interpretations made by management and the impact of such variations could be material, and (iii) writing off a regulatory asset because deferred costs are no longer probable of recovery in future rates charged to customers could have a material negative impact on Pepco Holdings’ assets and earnings.
Management’s most significant judgment is whether to defer costs or revenues when there is not a current regulatory order specific to the item being considered for deferral. In those cases, management considers relevant historical precedents of the regulatory commissions, the results of recent rate orders, and any new information from its more current interactions with the regulatory commissions on that item. Management regularly reviews its regulatory assets and liabilities to determine whether adjustments to its previous conclusions are necessary based on the current regulatory and legislative environment as well as recent rate orders.
Unbilled Revenue
Unbilled revenue represents an estimate of revenue earned from services rendered by Pepco Holdings’ utility operations that have not yet been billed. Pepco Holdings’ utility operations calculate unbilled revenue using an output-based methodology. The calculation is based on the supply of electricity or gas distributed to customers but not yet billed and adjusted for estimated line loss.
Pepco Holdings believes that the estimates involved in its unbilled revenue process represent “Critical Accounting Estimates” because management is required to make assumptions and judgments about input factors to the unbilled revenue calculation. Specifically, the determination of estimated line loss is inherently uncertain. Estimated line loss is defined as the estimates of electricity and gas expected to be lost in the process of its transmission and distribution to customers. A change in estimated line loss can change the output available for sale which is a factor in the unbilled revenue calculation. Certain factors can influence the estimated line loss such as seasonality and a change in customer mix. These factors may vary between companies due to geography and density of service territory and the impact of changes in these factors could be material. The risk of misstatement in the unbilled revenue calculation is mitigated through corroboration of the resultant unbilled revenue with historical information and other available metrics.
PEPCO HOLDINGS
Accounting for Income Taxes
Pepco Holdings exercises significant judgment about the outcome of income tax matters in its application of the FASB guidance on accounting for income taxes and believes it represents a “Critical Accounting Estimate” because: (1) it records a current tax liability for estimated current tax expense on its federal and state tax returns; (2) it records deferred tax assets for temporary differences between the financial statement and tax return determination of pre-tax income and the carrying amount of assets and liabilities that are more likely than not going to result in tax deductions in future years; (3) it determines whether a valuation allowance is needed against deferred tax assets if it is more likely than not that some portion of the future tax deductions will not be realized; (4) it records deferred tax liabilities for temporary differences between the financial statement and tax return determination of pre-tax income and the carrying amount of assets and liabilities if it is more likely than not that they are expected to result in tax payments in future years; (5) the measurement of deferred tax assets and deferred tax liabilities requires it to estimate future effective tax rates and future taxable income on its federal and state tax returns; (6) it must consider the effect of newly enacted tax law on its estimated effective tax rate and in measuring deferred tax balances; (7) it asserts that tax positions in its tax returns or expected to be taken in its tax returns are more likely than not to be sustained assuming that the tax positions will be examined by taxing authorities with full knowledge of all relevant information prior to recording the related tax benefit in the financial statements and that the benefit recognized in the financial statements is the largest amount of benefit that is greater than 50% likely of being realized.
Assumptions, judgment and the use of estimates are required in determining if the “more likely than not” standard has been met when developing the provision for current and deferred income taxes and the associated current and deferred tax assets and liabilities. Pepco Holdings’ assumptions, judgments and estimates take into account current tax laws and regulations, interpretation of current tax laws and regulations, the impact of newly enacted tax laws and regulations, developments in case law, settlements of tax positions, and the possible outcomes of current and future investigations conducted by tax authorities. Pepco Holdings has established reserves for income taxes to address potential exposures involving tax positions that could be challenged by tax authorities. Although Pepco Holdings believes that these assumptions, judgments and estimates are reasonable, changes in tax laws and regulations or its interpretation of tax laws and regulations as well as the resolutions of the current and any future investigations or legal proceedings could significantly impact the financial results from applying the accounting for income taxes in the consolidated financial statements. Pepco Holdings reviews its application of the “more likely than not” standard quarterly.
Pepco Holdings also evaluates quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets and the amount of any associated valuation allowance. The forecast of future taxable income is dependent on a number of factors that can change over time, including growth assumptions, business conditions, returns on rate base, operating and capital expenditures, cost of capital, tax laws and regulations, the legal structure of entities and other factors, which could materially impact the realizability of deferred tax assets and the associated financial results in the consolidated financial statements.
New Accounting Standards and Pronouncements
For information concerning new accounting standards and pronouncements that have recently been adopted by PHI and its subsidiaries or that one or more of the companies will be required to adopt on or before a specified date in the future, see Note (3), “Newly Adopted Accounting Standards,” and Note (4), “Recently Issued Accounting Standards, Not Yet Adopted,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.
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Forward-Looking Statements
Some of the statements contained in this Annual Report on Form 10-K are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding Pepco Holdings’ intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause PHI’s actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.
The forward-looking statements contained herein are qualified in their entirety by reference to the following important factors, which are difficult to predict, contain uncertainties, are beyond Pepco Holdings’ control and may cause actual results to differ materially from those contained in forward-looking statements:
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Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;
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Changes in and compliance with environmental and safety laws and policies;
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Weather conditions;
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Population growth rates and demographic patterns;
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Competition for retail and wholesale customers;
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General economic conditions, including potential negative impacts resulting from an economic downturn;
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Growth in demand, sales and capacity to fulfill demand;
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Changes in tax rates or policies or in rates of inflation;
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Changes in accounting standards or practices;
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Changes in project costs;
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Unanticipated changes in operating expenses and capital expenditures;
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The ability to obtain funding in the capital markets on favorable terms;
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Rules and regulations imposed by federal and/or state regulatory commissions, PJM and other regional transmission organizations (New York Independent System Operator, ISONE), the North American Electric Reliability Corporation and other applicable electric reliability organizations;
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Legal and administrative proceedings (whether civil or criminal) and settlements that affect PHI’s business and profitability;
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Pace of entry into new markets;
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Volatility in market demand and prices for energy, capacity and fuel;
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Interest rate fluctuations and credit and capital market conditions; and
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Effects of geopolitical events, including the threat of domestic terrorism.
Any forward-looking statements speak only as to the date of this Annual Report and Pepco Holdings undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for Pepco Holdings to predict all of such factors, nor can Pepco Holdings assess the impact of any such factor on Pepco Holding’s business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
The foregoing review of factors should not be construed as exhaustive.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Potomac Electric Power Company
Pepco meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction I(2)(a) to the Form 10-K.
General Overview
Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Montgomery County and Prince George’s County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.1 million. As of December 31, 2009, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to the District of Columbia customers.
Effective June 2007, the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers. The District of Columbia Public Service Commission (DCPSC) also approved a BSA for retail customers, effective in November 2009. For customers to whom the BSA applies, Pepco recognizes distribution revenue based on the approved distribution charge per customer. From a revenue recognition standpoint, this has the effect of decoupling distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a consequence, the only factors that will cause distribution revenue in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. For customers to whom the BSA applies, changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue.
As a result of the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (a) a positive adjustment equal to the amount by which revenue from Maryland and District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the distribution charge per customer approved in the 2007 Maryland Rate Order and the DCPSC order approving a BSA for Pepco in the District of Columbia effective November 1, 2009 or (b) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer.
Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (PHI or Pepco Holdings). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and Pepco and certain activities of Pepco are subject to the regulatory oversight of the Federal Energy Regulatory Commission under PUHCA 2005.
PEPCO
Results Of Operations
The following results of operations discussion compares the year ended December 31, 2009 to the year ended December 31, 2008. All amounts in the tables (except sales and customers) are in millions of dollars.
Operating Revenue
The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated Transmission & Distribution (T&D) Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).
Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, to Pepco’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that Pepco receives as a transmission owner from PJM Interconnection, LLC (PJM).
Default Electricity Supply Revenue is the revenue received from the supply of electricity by Pepco at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which is also known as Standard Offer Service (SOS). The costs related to Default Electricity Supply are included in Purchased Energy.
Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees, and collection fees.
Regulated T&D Electric
Other Regulated T&D Electric Revenue consists primarily of: (i) transmission service revenue and (ii) revenue from the resale in the PJM Regional Transmission Organization (PJM RTO) market of energy and capacity purchased under a power purchase agreement between Panda-Brandywine, L.P. (Panda) and Pepco (the Panda PPA) prior to the transfer of the Panda PPA to an unaffiliated third party in September 2008.
PEPCO
Regulated T&D Electric Revenue decreased by $31 million primarily due to:
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A decrease of $53 million in Other Regulated T&D Electric Revenue (which is matched by a corresponding decrease in Purchased Energy) due to the absence of revenues from the resale of energy and capacity purchased under the Panda PPA after September 2008.
The decrease was partially offset by:
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An increase of $15 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in utility taxes that are collected on behalf of the taxing jurisdictions
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An increase of $4 million due to a distribution rate increase in the District of Columbia that became effective in February 2008.
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An increase of $4 million as a result of the BSA in the District of Columbia that become effective in November 2009 (includes a positive $2 million Revenue Decoupling Adjustment).
Default Electricity Supply
Default Electricity Supply Revenue decreased by $58 million primarily due to:
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A decrease of $49 million due to lower sales, primarily the result of commercial customer migration to competitive suppliers.
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A decrease of $18 million due to lower sales as a result of milder weather primarily during the 2009 summer months as compared to 2008.
PEPCO
The aggregate amount of these decreases was partially offset by:
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An increase of $9 million as the result of higher Default Electricity Supply rates.
The following table shows the percentages of Pepco’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply from Pepco. Amounts are for the year ended December 31.
Operating Expenses
Purchased Energy
Purchased Energy consists of the cost of electricity purchased by Pepco to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $112 million to $1,223 million in 2009 from $1,335 million in 2008 primarily due to:
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A decrease of $53 million (which is matched by a corresponding decrease in Other Regulated T&D Electric Revenue) due to the transfer of the Panda PPA.
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A decrease of $48 million primarily due to commercial customer migration to competitive suppliers.
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A decrease of $40 million due to lower average electricity costs under Default Electricity Supply contracts.
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A decrease of $17 million due to lower electricity sales as a result of milder weather primarily during the 2009 summer months as compared to 2008.
The aggregate amount of these decreases was partially offset by:
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An increase of $47 million due to a higher rate of recovery of electricity supply costs resulting in a decrease in the Default Electricity Supply deferral balance.
Other Operation and Maintenance
Other Operation and Maintenance increased by $26 million to $328 million in 2009 from $302 million in 2008. The increase was primarily due to:
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An increase of $14 million in employee-related costs, primarily due to higher pension and other postretirement benefit expenses.
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An increase of $6 million primarily due to higher preventative and corrective maintenance costs.
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An increase of $5 million in regulatory expenses primarily incurred in connection with the District of Columbia distribution rate case.
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An increase of $4 million due to higher non-deferrable bad debt expenses.
PEPCO
During 2008, Pepco recorded adjustments to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 during which (i) customer late payment fees were incorrectly recognized and (ii) stock-based compensation expense related to certain restricted stock awards granted under the Long-Term Incentive Plan was understated. These adjustments resulted in a total increase in Other Operation and Maintenance expenses for the year ended December 31, 2008 of $6 million. These adjustments were not considered material either individually or in the aggregate.
Other Taxes
Other Taxes increased by $14 million to $302 million in 2009 from $288 million in 2008. The increase (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue) was primarily due to increased pass-throughs resulting from rate increases in utility taxes imposed by the taxing jurisdictions.
Effect of Settlement of Mirant Bankruptcy Claims
In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party. In March 2009, the District of Columbia Public Service Commission approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant Corporation (Mirant) bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $14 million reflecting the District of Columbia proceeds retained by Pepco. In July 2009, MPSC approved an allocation between Pepco and its Maryland customers of the Maryland portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $26 million reflecting the Maryland proceeds retained by Pepco.
Other Income (Expenses)
Other Expenses (which are net of Other Income) increased by $15 million to a net expense of $91 million in 2009 from a net expense of $76 million in 2008. The increase was primarily due to a $20 million increase in interest expense on long-term debt as the result of a higher amount of outstanding debt.
Income Tax Expense
Pepco’s effective tax rates for the years ended December 31, 2009 and 2008 were 41.8% and 35.6%, respectively. The increase in the rate primarily resulted from the change in estimates and interest related to uncertain tax positions which was the result of the reduction in previously accrued interest and estimates resulting from the tentative settlement of the mixed service cost issue. Also contributing to the increase in the rate was the 2008 benefit recorded for interest received on the state income tax refund.
Capital Requirements
Sources of Capital
Pepco has a range of capital sources available, in addition to internally generated funds, to meet its long-term and short-term funding needs. The sources of long-term funding include the issuance of mortgage bonds and other debt securities and bank financings, as well as the ability to issue preferred stock. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures, and to repay or refinance existing indebtedness. Pepco traditionally has used a number of sources to fulfill short-term funding needs, including commercial paper, short-term notes, bank lines of credit and borrowings under the PHI money pool. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to fund temporary long-term capital requirements. Pepco’s ability to generate funds from its operations and to access the capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions,
PEPCO
diminished liquidity and tightening credit may affect access to certain of Pepco’s potential funding sources. See Item 1A, “Risk Factors,” of this Form 10-K, for additional discussion of important factors that may have an effect on Pepco’s sources of capital.
Mortgage Bonds, Senior Notes, Medium-Term Notes, and Tax-Exempt Bonds
Pepco has a Mortgage and Deed of Trust (the Mortgage) under which it issues First Mortgage Bonds. First Mortgage Bonds issued under the Mortgage are secured by a lien on substantially all of Pepco’s property, plant and equipment. The principal amount of First Mortgage Bonds that Pepco may issue under the Mortgage is limited by the principal amount of retired First Mortgage Bonds and 60% of the lesser of the cost or fair value of new property additions that have not been used as the basis for the issuance of additional First Mortgage Bonds. Pepco also has an Indenture under which it issues senior notes secured by First Mortgage Bonds and an Indenture under which it can issue unsecured debt securities, including medium-term notes. To fund the construction of pollution control facilities, Pepco also has from time to time issued tax-exempt bonds through a municipality or public agency, the proceeds of which are loaned to Pepco by the municipality or agency.
Information concerning the principal amount and terms of Pepco’s outstanding First Mortgage Bonds, senior notes and medium-term notes, and tax-exempt bonds issued for the benefit of Pepco, as of December 31, 2009, is set forth in Note (10), “Debt,” to the Pepco financial statements set forth in Part II, Item 8 of this Form 10-K.
Bank Financing
As further discussed in Note (10), “Debt,” to the Pepco financial statements set forth in Part II, Item 8 of this Form 10-K, Pepco participates in a $1.5 billion credit facility, along with PHI, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE). The facility, all or any portion of which may be used to obtain loans or to issue letters of credit, expires in 2012. Pepco’s credit limit under the facility is the lesser of $500 million and the maximum amount of debt Pepco is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time may not collectively exceed $625 million.
Commercial Paper Program
Pepco maintains an ongoing commercial paper program of up to $500 million under which it can issue commercial paper with maturities of up to 270 days. The commercial paper is backed by Pepco’s borrowing capacity under the PHI $1.5 billion credit facility.
Money Pool
Pepco participates in the money pool operated by PHI under authorization received from the Federal Energy Regulatory Commission (FERC). The money pool is a cash management mechanism used by PHI and eligible subsidiaries to manage their short-term investment and borrowing requirements. PHI may invest in, but not borrow from, the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by PHI. Eligible subsidiaries with cash requirements may borrow from the money pool. Borrowings from the money pool are unsecured. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on PHI’s short-term borrowing rate. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which PHI may obtain from external sources.
PEPCO
Preferred Stock
Under its Articles of Incorporation, Pepco is authorized to issue and have outstanding up to 6 million shares of preferred stock in one or more series, with each series having such rights, preferences and limitations, including dividend and voting rights and redemption provisions, as the Board of Directors may establish. As of December 31, 2009, there were no shares of Pepco preferred stock outstanding.
Regulatory Restrictions on Financing Activities
Pepco’s long-term financing activities (including the issuance of securities and the incurrence of debt) are subject to authorization by the DCPSC and MPSC. Through its periodic filings with the respective utility commissions, Pepco generally seeks to maintain standing authority sufficient to cover its projected financing needs over a multi-year period. Under the Federal Power Act, FERC has jurisdiction over the issuance of long-term and short-term securities of public utilities, but only if the issuance is not regulated by the state public utility commission in which the public utility is organized and operating. Under these provisions, Pepco is required to obtain FERC authorization for the issuance of short-term debt.
Capital Expenditures
Pepco’s capital expenditures for the year ended December 31, 2009, totaled $288 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.
The following table shows Pepco’s projected capital expenditures for the five year period 2010 through 2014. Pepco expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.
(a) Amounts are presented on a gross basis on the assumption that the awards are not subject to federal or state tax.
In 2009, the U.S. Department of Energy (DOE) announced a $149 million award to Pepco under the American Recovery and Reinvestment Act of 2009 for the implementation of an advanced metering infrastructure (AMI) system, direct load control, distribution automation, and communications infrastructure. The Pepco service territory in Maryland and the District of Columbia were awarded $105 million and $44 million respectively. PHI is currently in the process of finalizing certain terms and conditions of the awards with the DOE. Of the $149 million, $118 million, as shown in the table above, will offset Blueprint for the Future and other capital expenditures that Pepco is projected to incur. The remaining $31 million will be used to help offset ongoing expenses associated with direct load control and other Power Delivery programs.
PEPCO
Distribution and Transmission
The projected capital expenditures listed in the table for distribution (other than Blueprint for the Future) and transmission (other than the Mid-Atlantic Power Pathway (MAPP) project) are primarily for facility replacements and upgrades to accommodate customer growth and reliability.
Blueprint for the Future
For a discussion of the Blueprint for the Future initiative, see Item 1, “Business - Description of Business - Blueprint for the Future” of this Form 10-K.
MAPP Project
The total cost of the MAPP project is currently estimated to be $1.2 billion. For a discussion of the MAPP project, see Item 1, “Business - Description of Business - MAPP Project” of this Form 10-K. The cost of Pepco’s portion of the MAPP project, as currently constituted, is estimated at $548 million.
MAPP/DOE Loan Program
PHI has applied for a $684 million loan guarantee from the DOE for a substantial portion of the MAPP project, primarily the Calvert Cliffs to Indian River segment. The loan guarantee is available under a loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes that the guarantee would allow PHI to obtain 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 terms of the guarantee program.
Pension and Postretirement Benefit Plans
Pepco participates in pension and postretirement benefit plans sponsored by PHI for its employees. While the plans have not experienced any significant impact in terms of liquidity or counterparty exposure due to the disruption of the capital and credit markets, the stock market declines in 2008 caused a decrease in the market value of benefit plan assets at the end of 2008. Pepco contributed $170 million to the pension plan during 2009.
Forward-Looking Statements
Some of the statements contained in this Annual Report on Form 10-K are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding Pepco’s intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause Pepco’s actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.
The forward-looking statements contained herein are qualified in their entirety by reference to the following important factors, which are difficult to predict, contain uncertainties, are beyond Pepco’s control and may cause actual results to differ materially from those contained in forward-looking statements:
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Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;
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Changes in and compliance with environmental and safety laws and policies;
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Weather conditions;
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Population growth rates and demographic patterns;
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Competition for retail and wholesale customers;
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General economic conditions, including potential negative impacts resulting from an economic downturn;
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Growth in demand, sales and capacity to fulfill demand;
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Changes in tax rates or policies or in rates of inflation;
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Changes in accounting standards or practices;
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Changes in project costs;
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Unanticipated changes in operating expenses and capital expenditures;
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The ability to obtain funding in the capital markets on favorable terms;
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Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;
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Legal and administrative proceedings (whether civil or criminal) and settlements that influence Pepco’s business and profitability;
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Volatility in market demand and prices for energy, capacity and fuel;
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Interest rate fluctuations and credit and capital market conditions; and
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Effects of geopolitical events, including the threat of domestic terrorism.
Any forward-looking statements speak only as to the date of this Annual Report and Pepco undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for Pepco to predict all of such factors, nor can Pepco assess the impact of any such factor on Pepco’s business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
The foregoing review of factors should not be construed as exhaustive.
DPL
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Delmarva Power & Light Company
DPL meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction I(2)(a) to the Form 10-K.
General Overview
Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland. DPL also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. 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, approximately 67% of delivered electricity sales were to Delaware customers and approximately 33% were to Maryland customers. In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers that purchase natural gas from other suppliers. DPL’s natural gas distribution service territory covers approximately 275 square miles and has a population of approximately 500,000.
Effective January 2, 2008, DPL sold its Virginia retail electric distribution assets and its Virginia wholesale electric transmission assets.
Effective June 2007, the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to whom the BSA applies, DPL recognizes distribution revenue based on the approved distribution charge per customer. From a revenue recognition standpoint, this has the effect of decoupling distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a consequence, the only factors that will cause distribution revenue in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. For customers to whom the BSA applies, changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue.
DPL is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (PHI or Pepco Holdings). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and DPL and certain activities of DPL are subject to the regulatory oversight of the Federal Energy Regulatory Commission under PUHCA 2005.
DPL
Results Of Operations
The following results of operations discussion compares the year ended December 31, 2009 to the year ended December 31, 2008. All amounts in the tables (except sales and customers) are in millions of dollars.
Electric Operating Revenue
The table above shows the amount of Electric Operating Revenue earned that is subject to price regulation (Regulated Transmission & Distribution (T&D) Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).
Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, to DPL’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that DPL receives as a transmission owner from PJM Interconnection, LLC (PJM).
Default Electricity Supply Revenue is the revenue received from the supply of electricity by DPL at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, which is also known as SOS service. The costs related to Default Electricity Supply are included in Purchased Energy.
Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees, and collection fees.
Regulated T&D Electric
Other Regulated T&D Electric Revenue consists primarily of transmission service revenue.
DPL
Regulated T&D Electric Revenue decreased by $10 million primarily due to:
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A decrease of $5 million primarily due to lower non-weather related customer usage.
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A decrease of $4 million in transmission service revenue primarily due to a transmission rate decrease in June 2009.
Default Electricity Supply
Default Electricity Supply Revenue decreased by $77 million primarily due to:
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A decrease of $53 million due to lower sales, primarily the result of commercial and industrial customer migration to competitive suppliers.
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A decrease of $23 million due to lower non-weather related customer usage.
DPL
The following table shows the percentages of DPL’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply distribution from DPL. Amounts are for the years ended December 31:
Natural Gas Operating Revenue
The table above shows the amounts of Natural Gas Operating Revenue from sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other Gas Revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.
Regulated Gas
DPL
Regulated Gas Revenue increased by $24 million primarily due to:
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An increase of $15 million due to the Gas Cost Rate increase effective November 2008, partially offset by rate decreases in March 2009 and November 2009.
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An increase of $14 million (which is offset by a corresponding increase in Gas Purchased) associated with the recognition of the unbilled portion of Gas Cost Rate revenue in 2009, which was not previously recognized.
The aggregate amount of these increases was partially offset by:
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A decrease of $5 million due to lower non-weather related customer usage.
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A decrease of $4 million due to lower sales as a result of warmer weather during the fourth quarter of 2009, as compared to the corresponding period in 2008.
Other Gas Revenue
Other Gas Revenue decreased by $74 million primarily due to lower revenue from off-system sales resulting from:
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A decrease of $67 million due to lower market prices.
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A decrease of $9 million due to lower demand from electric generators and gas marketers.
Operating Expenses
Purchased Energy
Purchased Energy consists of the cost of electricity purchased by DPL to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $70 million to $751 million in 2009 from $821 million in 2008 primarily due to:
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A decrease of $74 million primarily due to commercial and industrial customer migration to competitive suppliers.
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A decrease of $13 million due to lower average electricity costs under Default Electricity Supply contracts.
The aggregate amount of these decreases was partially offset by:
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An increase of $15 million due to a higher rate of recovery of electricity supply costs resulting in a decrease in the Default Electricity Supply deferral balance.
Gas Purchased
Gas Purchased consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Total Gas Purchased decreased by $52 million to $193 million in 2009 from $245 million in 2008 primarily due to:
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A decrease of $73 million in the cost of gas purchases for off-system sales, the result of lower average gas prices and volumes purchased.
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A decrease of $30 million in the cost of gas purchases for on-system sales, the result of lower average gas prices and volumes purchased.
The aggregate amount of these decreases was partially offset by:
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An increase of $43 million from the settlement of financial hedges entered into as part of DPL’s hedge program for regulated natural gas.
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An increase of $12 million due to a higher rate of recovery of natural gas supply costs primarily as a result of recognizing the unbilled portion of Gas Cost Rate revenue in 2009, as discussed under Regulated Gas Revenue.
Other Operation and Maintenance
Other Operation and Maintenance increased by $16 million to $238 million in 2009 from $222 million in 2008. Excluding a decrease of $5 million primarily related to administrative expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance increased by $21 million. The $21 million increase was primarily due to:
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An increase of $15 million in employee-related costs, primarily due to higher pension and other post retirement benefit expenses.
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An increase of $6 million primarily due to higher emergency restoration and tree trimming costs.
During 2008, DPL recorded adjustments to correct errors in Other Operation and Maintenance for prior periods dating back to May 2006 during which (i) customer late payment fees were incorrectly recognized and (ii) stock-based compensation expense related to certain restricted stock awards granted under the Long-Term Incentive Plan was understated. These adjustments resulted in a total increase in Other Operation and Maintenance for the year ended December 31, 2008 of $5 million. These adjustments were not considered material either individually or in the aggregate.
Gain on Sale of Assets
Gain on Sale of Assets decreased by $4 million in 2009 due to a $4 million gain on the sale of the Virginia retail electric distribution and wholesale transmission assets in January 2008.
Other Income (Expenses)
Other Expenses (which are net of Other Income) increased by $7 million to a net expense of $42 million in 2009 from a net expense of $35 million in 2008. The increase was primarily due to a $10 million increase in interest expense on long-term debt as the result of a higher amount of outstanding debt.
Income Tax Expense
DPL’s effective tax rates for the years ended December 31, 2009 and 2008 were 23.5 % and 39.8%, respectively. The decrease in the rate primarily resulted from the refund of $6 million (after-tax) of state income taxes and the establishment of a state tax benefit carryforward of $7 million (after-tax), each related to a change in the tax reporting for the disposition of certain assets in prior years. This decrease is partially offset by the changes in estimates and interest related to uncertain and effectively settled tax positions and the non-recurring adjustments to prior years’ taxes.
DPL
Capital Requirements
Sources of Capital
DPL has a range of capital sources available, in addition to internally generated funds, to meet its long-term and short-term funding needs. The sources of long-term funding include the issuance of mortgage bonds and other debt securities and bank financings, as well as the ability to issue preferred stock. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures, and to repay or refinance existing indebtedness. DPL traditionally has used a number of sources to fulfill short-term funding needs, including commercial paper, short-term notes, bank lines of credit, and borrowings under the PHI money pool. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to fund temporary long-term capital requirements. DPL’s ability to generate funds from its operations and to access the capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of DPL’s potential funding sources. See Item 1A, “Risk Factors,” of this Form 10-K, for additional discussion of important factors that may have an effect on DPL’s sources of capital.
Mortgage Bonds, Senior Notes, Medium Term Notes, Variable Rate Demand Bonds, and Tax-Exempt Bonds
DPL has a Mortgage and Deed of Trust (the Mortgage) under which it issues First Mortgage Bonds. First Mortgage Bonds issued under the Mortgage are secured by a lien on substantially all of DPL’s property, plant and equipment. The principal amount of First Mortgage Bonds that DPL may issue under the Mortgage is limited by the principal amount of retired First Mortgage Bonds and 60% of the lesser of the cost or fair value of new property additions that have not been used as the basis for the issuance of additional First Mortgage Bonds. DPL also has an Indenture under which it issues unsecured senior notes, medium-term notes and Variable Rate Demand Bonds. To fund the construction of pollution control facilities, DPL also has from time to time issued tax-exempt bonds, including tax-exempt Variable Rate Demand Bonds, through a public agency, the proceeds of which are loaned to DPL by the agency.
Information concerning the principal amount and terms of DPL’s outstanding First Mortgage Bonds, senior notes, medium-term notes and Variable Rate Demand Bonds, and tax-exempt bonds issued for the benefit of DPL, as of December 31, 2009, is set forth in Note (11), “Debt,” to the DPL financial statements set forth in Part II, Item 8 of this Form 10-K.
Bank Financing
As further discussed in Note (11), “Debt,” to the DPL financial statements set forth in Part II, Item 8 of this Form 10-K, DPL participates in a $1.5 billion credit facility, along with PHI, Potomac Electric Power Company (Pepco) and Atlantic City Electric Company (ACE). The facility, all or any portion of which may be used to obtain loans or to issue letters of credit, expires in 2012. DPL’s credit limit under the facility is the lesser of $500 million and the maximum amount of debt DPL is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by DPL, Pepco and ACE at any given time may not collectively exceed $625 million.
DPL
Commercial Paper Program
DPL maintains an ongoing commercial paper program of up to $500 million under which it can issue commercial paper with maturities of up to 270 days. The commercial paper is backed by DPL’s borrowing capacity under the PHI $1.5 billion credit facility.
Money Pool
DPL participates in the money pool operated by PHI under authorization received from the Federal Energy Regulatory Commission (FERC). The money pool is a cash management mechanism used by PHI and eligible subsidiaries to manage their short-term investment and borrowing requirements. PHI may invest in, but not borrow from, the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by PHI. Eligible subsidiaries with cash requirements may borrow from the money pool. Borrowings from the money pool are unsecured. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on PHI’s short-term borrowing rate. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which PHI may obtain from external sources.
Regulatory Restrictions on Financing Activities
DPL’s long-term financing activities (including the issuance of securities and the incurrence of debt) is subject to authorization by the Delaware Public Service Commission (DPSC) and MPSC. Through its periodic filings with the respective utility commissions, DPL generally seeks to maintain standing authority sufficient to cover its projected financing needs over a multi-year period. Under the Federal Power Act, FERC has jurisdiction over the issuance of long-term and short-term securities of public utilities, but only if the issuance is not regulated by the state public utility commission in which the public utility is organized and operating. Under these provisions, DPL is required to obtain FERC authorization for the issuance of short-term debt.
Capital Expenditures
DPL’s capital expenditures for the year ended December 31, 2009, totaled $193 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.
The following table shows DPL’s projected capital expenditures for the five-year period 2010 through 2014. DPL expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.
DPL
DPL has not received any awards from the U. S. Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009 in support of its Blueprint for the Future and other initiatives.
Distribution, Transmission and Gas Delivery
The projected capital expenditures listed in the table for distribution (other than Blueprint for the Future), transmission (other than the Mid-Atlantic Power Pathway (MAPP) project) and gas delivery are primarily for facility replacements and upgrades to accommodate customer growth and reliability.
Blueprint for the Future
For a discussion of the Blueprint for the Future initiative, see Item 1, “Business - Description of Business - Blueprint for the Future” of this Form 10-K.
MAPP Project
The total cost of the MAPP project is currently estimated to be $1.2 billion. For a discussion of the MAPP project, see Item 1, “Business - Description of Business - MAPP Project” of this Form 10-K. The cost of DPL’s portion of the MAPP project, as currently constituted, is estimated at $673 million.
MAPP/DOE Loan Program
PHI has applied for a $684 million loan guarantee from the Department of Energy for a substantial portion of the MAPP project, primarily the Calvert Cliffs to Indian River segment. The loan guarantee is available under a loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes that the guarantee would allow PHI to obtain 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 terms of the guarantee program.
Pension and Postretirement Benefit Plans
DPL participates in several of the pension and postretirement benefit plans sponsored by PHI and its subsidiaries for their employees. While the plans have not experienced any significant impact in terms of liquidity or counterparty exposure due to the disruption of the capital and credit markets, the stock market declines in 2008 caused a decrease in the market value of benefit plan assets at the end of 2008. DPL contributed $10 million to the pension plan during 2009.
Forward-Looking Statements
Some of the statements contained in this Annual Report on Form 10-K are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding DPL’s intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause DPL’s actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.
DPL
The forward-looking statements contained herein are qualified in their entirety by reference to the following important factors, which are difficult to predict, contain uncertainties, are beyond DPL’s control and may cause actual results to differ materially from those contained in forward-looking statements:
•
Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;
•
Changes in and compliance with environmental and safety laws and policies;
•
Weather conditions;
•
Population growth rates and demographic patterns;
•
Competition for retail and wholesale customers;
•
General economic conditions, including potential negative impacts resulting from an economic downturn;
•
Growth in demand, sales and capacity to fulfill demand;
•
Changes in tax rates or policies or in rates of inflation;
•
Changes in accounting standards or practices;
•
Changes in project costs;
•
Unanticipated changes in operating expenses and capital expenditures;
•
The ability to obtain funding in the capital markets on favorable terms;
•
Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;
•
Legal and administrative proceedings (whether civil or criminal) and settlements that influence DPL’s business and profitability;
•
Volatility in market demand and prices for energy, capacity and fuel;
•
Interest rate fluctuations and credit and capital market conditions; and
•
Effects of geopolitical events, including the threat of domestic terrorism.
Any forward-looking statements speak only as to the date of this Annual Report and DPL undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for DPL to predict all of such factors, nor can DPL assess the impact of any such factor on DPL’s business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
The foregoing review of factors should not be construed as exhaustive.
ACE
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Atlantic City Electric Company
ACE meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction I(2)(a) to the Form 10-K.
General Overview
Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is also known as Basic Generation Service in New Jersey. ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.1 million.
ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (PHI or Pepco Holdings). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and ACE and certain activities of ACE are subject to the regulatory oversight of the Federal Energy Regulatory Commission under PUHCA 2005.
ACE
RESULTS OF OPERATIONS
The following results of operations discussion compares the year ended December 31, 2009 to the year ended December 31, 2008. All amounts in the tables (except sales and customers) are in millions of dollars.
Operating Revenue
The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated Transmission & Distribution (T&D) Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).
Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, to ACE’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that ACE receives as a transmission owner from PJM Interconnection, LLC (PJM).
Default Electricity Supply Revenue is the revenue received from the supply of electricity by ACE at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which is also known as Basic Generation Service (BGS). The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges and other restructuring related revenues.
Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees, and collection fees.
Regulated T&D Electric
Other Regulated T&D Electric Revenue consists primarily of transmission service revenue.
ACE
Regulated T&D Electric Revenue increased by $4 million primarily due to:
•
An increase of $16 million due to a distribution rate increase (which is substantially offset by a corresponding increase in Deferred Electric Service Costs) as part of a higher New Jersey Societal Benefit Charge that became effective in June 2008.
The increase was partially offset by:
•
A decrease of $7 million due to lower non-weather related customer usage.
•
A decrease of $5 million due to lower sales as a result of milder weather primarily during the 2009 spring and summer months as compared to 2008.
Default Electricity Supply
Other Default Electricity Supply Revenue consists primarily of revenue from the resale in the PJM Regional Transmission Organization market of energy and capacity purchased under contracts with unaffiliated, non-utility generators (NUGs).
ACE
Default Electricity Supply Revenue decreased by $288 million primarily due to:
•
A decrease of $175 million in wholesale energy revenues due to lower market prices for the sale of electricity purchased from NUGs.
•
A decrease of $65 million due to lower sales, primarily the result of commercial customer migration to competitive suppliers.
•
A decrease of $22 million due to lower non-weather related customer usage.
•
A decrease of $14 million due to lower sales as a result of milder weather primarily during the 2009 spring and summer months as compared to 2008.
•
A decrease of $12 million as the result of lower Default Electricity Supply rates.
The decrease in total Default Electricity Supply Revenue includes a decrease of $8 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the New Jersey Board of Public Utilities (NJBPU), ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, then the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the year ended December 31, 2009, BGS unbilled revenue decreased by $8 million as compared to the year ended December 31, 2008, which resulted in a $5 million decrease in ACE’s net income. The decrease was due to increased customer migration and lower customer usage during the unbilled revenue period at the end of 2009 as compared to the corresponding period in 2008.
For the years ended December 31, 2009 and 2008, the percentage of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 73% and 78%, respectively.
Operating Expenses
Purchased Energy
Purchased Energy consists of the cost of electricity purchased by ACE to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $102 million to $1,076 million in 2009 from $1,178 million in 2008 primarily due to:
•
A decrease of $115 million primarily due to commercial customer migration to competitive suppliers.
•
A decrease of $17 million due to lower electricity sales as a result of milder weather primarily during the 2009 spring and summer months as compared to 2008.
The aggregate amount of these decreases was partially offset by:
•
An increase of $30 million due to higher average electricity costs under Default Electricity Supply contracts.
Other Operation and Maintenance
Other Operation and Maintenance increased by $7 million to $190 million in 2009 from $183 million in 2008 primarily due to an increase of $10 million in employee-related pension and other postretirement benefit expenses.
During 2008, ACE recorded an adjustment to correct errors in Other Operation and Maintenance expenses for certain restricted stock awards granted under the Long-Term Incentive Plan. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the year ended December 31, 2008 of $1 million. This adjustment was not considered material.
ACE
Deferred Electric Service Costs
Deferred Electric Service Costs decreased by $152 million, to an expense reduction of $161 million in 2009 as compared to an expense reduction of $9 million in 2008. The decrease was primarily due to:
•
A decrease of $186 million due to a lower rate of recovery of costs from the resale in the PJM RTO market of energy and capacity purchased under the NUG contracts.
The decrease was partially offset by:
•
An increase of $15 million due to a higher rate of recovery through customer rates of deferred energy costs of Default Electricity Supply (included in Default Electricity Supply Revenue).
•
An increase of $13 million due to a higher rate of recovery through customer rates of New Jersey Societal Benefit program costs (included in Regulated T&D Electric Revenue).
•
An increase of $5 million due to a higher rate of recovery through customer rates of deferred transmission costs of Default Electricity Supply (included in Default Electricity Supply Revenue).
Other Income (Expenses)
Other Expenses (which are net of Other Income) increased by $6 million to a net expense of $65 million in 2009 from a net expense of $59 million in 2008 primarily due to an increase of $13 million in interest expense on long-term debt as the result of a higher amount of outstanding debt, partially offset by a decrease of $6 million in interest expense on the Default Electricity Supply deferral balance primarily due to lower short-term debt rates.
Income Tax Expense
ACE’s consolidated effective tax rates for the years ended December 31, 2009 and 2008 were 29.3 % and 31.9% respectively. The decrease in the rate primarily resulted from the reduction of deferred tax adjustments, a decrease in tax credits and adjustments to prior years’ taxes, partially offset by the impact of certain permanent state tax differences as a percentage of pre-tax income and changes in estimates and interest related to uncertain and effectively settled tax positions related to casualty losses and fuel.
Income Tax Adjustment
During 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. These adjustments, which are not considered material, resulted in a decrease in income tax expense of $1 million for the year ended December 31, 2009.
Capital Requirements
Sources of Capital
ACE has a range of capital sources available, in addition to internally generated funds, to meet its long-term and short-term funding needs. The sources of long-term funding include the issuance of mortgage bonds and other debt securities and bank financings, as well as preferred stock. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures, and to repay or refinance existing indebtedness. ACE traditionally has used a number of sources to fulfill short-term funding needs, including commercial paper, short-term notes, bank lines of credit, and borrowings
ACE
under the PHI money pool. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to fund temporary long-term capital requirements. ACE’s ability to generate funds from its operations and to access the capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of ACE’s potential funding sources. See Item 1A, “Risk Factors,” of this Form 10-K, for additional discussion of important factors that may have an effect on ACE’s sources of capital.
Mortgage Bonds, Senior Notes, Variable Rate Demand Bonds, and Tax-Exempt Bonds
ACE has a Mortgage and Deed of Trust (the Mortgage) under which it issues First Mortgage Bonds. First Mortgage Bonds issued under the Mortgage are secured by a lien on substantially all of ACE’s property, plant and equipment. The principal amount of First Mortgage Bonds that ACE may issue under the Mortgage is limited by the principal amount of retired First Mortgage Bonds and 65% of the lesser of the cost or fair value of new property additions that have not been used as the basis for the issuance of additional First Mortgage Bonds. ACE also has an Indenture under which it issues senior notes secured by First Mortgage Bonds and an Indenture under which it can issue unsecured debt securities, including Variable Rate Demand Bonds. To fund the construction of pollution control facilities, ACE also has from time to time issued tax-exempt bonds, including tax-exempt Variable Rate Demand Bonds, through a municipality, the proceeds of which are loaned to ACE by the municipality.
Information concerning the principal amount and terms of ACE’s outstanding First Mortgage Bonds, senior notes and Variable Rate Demand Bonds, and tax-exempt bonds issued for the benefit of ACE, as of December 31, 2009, is set forth in Note (10), “Debt,” to the ACE financial statements set forth in Part II, Item 8 of this Form 10-K.
Bank Financing
As further discussed in Note (10), “Debt,” to the ACE financial statements set forth in Part II, Item 8 of this Form 10-K, ACE participates in a $1.5 billion credit facility, along with PHI, Potomac Electric Power Company (Pepco) and Delmarva Power & Light Company (DPL). The facility, all or any portion of which may be used to obtain loans or to issue letters of credit expires in 2012. ACE’s credit limit under the facility is the lesser of $500 million and the maximum amount of debt ACE is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by ACE, Pepco and DPL at any given time may not collectively exceed $625 million.
Commercial Paper Program
ACE maintains an ongoing commercial paper program of up to $250 million under which it can issue commercial paper with maturities of up to 270 days. The commercial paper is backed by ACE’s borrowing capacity under the PHI $1.5 billion credit facility.
Money Pool
ACE participates in the money pool operated by PHI under authorization received from the Federal Energy Regulatory Commission (FERC). The money pool is a cash management mechanism used by PHI and eligible subsidiaries to manage their short-term investment and borrowing requirements. PHI may invest in, but not borrow from, the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by PHI. Eligible subsidiaries with cash requirements may borrow from the money pool. Borrowings from the money pool are unsecured. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on PHI’s short-term borrowing rate. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which PHI may obtain from external sources. By regulatory order, the NJBPU has restricted ACE’s participation in the PHI money pool. ACE may not invest in the money pool, but may borrow from it if the rates are lower than the rates at which ACE could borrow funds externally.
ACE
Preferred Stock
Under its Certificate of Incorporation, ACE is authorized to issue and have outstanding up to (i) 799,979 shares of Cumulative Preferred Stock, (ii) 2 million shares of No Par Preferred Stock and (iii) 3 million shares of Preference Stock, each such type of preferred stock having such terms and conditions as are set forth in or authorized by the Certificate of Incorporation. Information concerning the numbers of shares and the terms of ACE’s outstanding shares of Cumulative Preferred Stock as of December 31, 2009, is set forth in Note (12), “Preferred Stock,” to the ACE financial statements set forth in Part II, Item 8 of this Form 10-K. As of December 31, 2009, no shares of No Par Preferred Stock or Preference Stock were outstanding.
Regulatory Restrictions on Financing Activities
ACE’s long-term and short-term (consisting of debt instruments with a maturity of one year or less) financing activities are subject to authorization by the NJBPU. Through its periodic filings with the NJBPU, ACE generally seeks to maintain standing authority sufficient to cover its projected financing needs over a multi-year period. ACE’s long-term and short-term financing activities do not require FERC approval.
State corporate laws impose limitations on the funds that can be used to pay dividends. In addition, ACE must obtain the approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%.
Capital Expenditures
ACE’s capital expenditures for the year ended December 31, 2009, totaled $141 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.
The following table shows ACE’s updated projected capital expenditures for the five-year period 2010 through 2014. ACE expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.
(a) Amounts are presented on a gross basis on the assumption that the awards are not subject to federal or state tax.
ACE
In 2009, the U.S. Department of Energy (DOE) announced a $19 million award to ACE under the American Recovery and Reinvestment Act of 2009 for the implementation of direct load control, distribution automation, and communications infrastructure in ACE’s service territory. PHI is currently in the process of finalizing certain terms and conditions of the awards with the DOE. Of the $19 million, $12 million, as shown in the table above, will offset Blueprint for the Future and other capital expenditures that ACE is projected to incur. The remaining $7 million will be used to help offset ongoing expenses associated with direct load control and other Power Delivery programs.
Distribution and Transmission
The projected capital expenditures listed in the table for distribution (other than Blueprint for the Future) and transmissions are primarily for facility replacements and upgrades to accommodate customer growth and reliability.
Blueprint for the Future
For a discussion of the Blueprint for the Future initiative, see Item 1, “Business - Description of Business - Blueprint for the Future” of this Form 10-K.
Distribution
On April 16, 2009, the NJBPU approved ACE’s proposed Infrastructure Investment Plan and the revenue requirement associated with recovering the cost of these projects, subject to a prudency review in the next rate case. The approved projects will simultaneously enhance reliability of ACE’s distribution system and support economic activity and job growth in New Jersey in the near term. Cost recovery will be achieved through an Infrastructure Investment Surcharge, which became effective on June 1, 2009. This approved plan added incremental capital spending of approximately $8 million for 2009 and is expected to add an additional $19 million of capital spending for 2010, which is included in Distribution capital expenditures in the table above. ACE is required to file a rate case no later than April 1, 2011. As part of this base rate case, the remaining unamortized amounts associated with these projects will be placed into rate base.
Pension and Postretirement Benefit Plans
ACE participates in pension and postretirement benefit plans sponsored by PHI for employees. While the plans have not experienced any significant impact in terms of liquidity or counterparty exposure due to the disruption of the capital and credit markets, the stock market declines in 2008 caused a decrease in the market value of benefit plan assets at the end of 2008. ACE contributed $60 million to the pension plan during 2009.
Forward-Looking Statements
Some of the statements contained in this Annual Report on Form 10-K are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding ACE’s intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause ACE’s actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.
The forward-looking statements contained herein are qualified in their entirety by reference to the following important factors, which are difficult to predict, contain uncertainties, are beyond ACE’s control and may cause actual results to differ materially from those contained in forward-looking statements:
•
Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;
ACE
•
Changes in and compliance with environmental and safety laws and policies;
•
Weather conditions;
•
Population growth rates and demographic patterns;
•
Competition for retail and wholesale customers;
•
General economic conditions, including potential negative impacts resulting from an economic downturn;
•
Growth in demand, sales and capacity to fulfill demand;
•
Changes in tax rates or policies or in rates of inflation;
•
Changes in accounting standards or practices;
•
Changes in project costs;
•
Unanticipated changes in operating expenses and capital expenditures;
•
The ability to obtain funding in the capital markets on favorable terms;
•
Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;
•
Legal and administrative proceedings (whether civil or criminal) and settlements that influence ACE’s business and profitability;
•
Volatility in market demand and prices for energy, capacity and fuel;
•
Interest rate fluctuations and credit and capital market conditions; and
•
Effects of geopolitical events, including the threat of domestic terrorism.
Any forward-looking statements speak only as to the date of this Annual Report and ACE undertakes no obligation to update any forward looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for ACE to predict all of such factors, nor can ACE assess the impact of any such factor on ACE’s business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
The foregoing review of factors should not be construed as exhaustive.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk management policies for PHI and its subsidiaries are determined by PHI’s Corporate Risk Management Committee, the members of which are PHI’s Chief Risk Officer, Chief Operating Officer, Chief Financial Officer, General Counsel, Chief Information Officer and other senior executives. The Corporate Risk Management Committee monitors interest rate fluctuation, commodity price fluctuation, and credit risk exposure, and sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements. For information about PHI’s derivative activities, other than the information disclosed herein, refer to Note (2), “Significant Accounting Policies - Accounting For Derivatives” and Note (15), “Derivative Instruments and Hedging Activities” to the consolidated financial statements of PHI set forth in Part II, Item 8
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Listed below is a table that sets forth, for each registrant, the page number where the information is contained herein.
* Pepco and DPL have no subsidiaries and therefore their financial statements are not consolidated.
PEPCO HOLDINGS
Management’s Report on Internal Control over Financial Reporting
The management of Pepco Holdings is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed its internal control over financial reporting as of December 31, 2009 based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of Pepco Holdings concluded that Pepco Holdings’ internal control over financial reporting was effective as of December 31, 2009.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the financial statements of Pepco Holdings included in this Annual Report on Form 10-K, has also issued its attestation report on the effectiveness of Pepco Holdings’ internal control over financial reporting, which is included herein.
PEPCO HOLDINGS
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of
Pepco Holdings, Inc.
In our opinion, the consolidated financial statements listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Pepco Holdings, Inc. and its subsidiaries at December 31, 2009 and December 31, 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedules and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
PEPCO HOLDINGS
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 26, 2010
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PEPCO HOLDINGS, INC.
(1) ORGANIZATION
Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a diversified energy company that, through its operating subsidiaries, is engaged primarily in two businesses:
•
The distribution, transmission and default supply of electricity and the delivery and supply of natural gas (Power Delivery), conducted through the following regulated public utility companies, each of which is a reporting company under the Securities Exchange Act of 1934, as amended:
•
Potomac Electric Power Company (Pepco), which was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949,
•
Delmarva Power & Light Company (DPL), which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979,
•
Atlantic City Electric Company (ACE), which was incorporated in New Jersey in 1924.
•
Competitive energy generation, marketing and supply (Competitive Energy) conducted through subsidiaries of Conectiv Energy Holding Company (collectively Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries (collectively Pepco Energy Services).
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.
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. 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 are high-voltage systems that carry wholesale electricity into, or across, the utility’s service territory. Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utility’s service territory. Together the three companies constitute a single segment for financial reporting purposes.
Each company 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 commissions. 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 Office 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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Competitive Energy Business
The Competitive Energy business provides competitive generation, marketing and supply of electricity and gas, and energy management services, primarily in the mid-Atlantic region. PHI’s Competitive Energy operations are conducted through Conectiv Energy and Pepco Energy Services, each of which is treated as a separate operating segment for financial reporting purposes.
On December 7, 2009, PHI announced that it will wind down the retail electric and natural gas supply business, which it conducts through its subsidiary Pepco Energy Services. The retail energy supply business historically has generated a substantial portion of the operating revenues and net income of PHI’s Pepco Energy Services operating segment. Operating revenues related to the retail energy supply business for the years ended December 31, 2009, 2008 and 2007 were $2.3 billion, $2.5 billion and $2.1 billion, respectively, while operating income for the same periods was $88 million, $54 million and $39 million, respectively. In connection with the operation of the retail energy supply business, as of December 31, 2009, Pepco Energy Services provided letters of credit of $157 million and posted cash collateral of $123 million. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will be released by June 1, 2014. Substantially all of Pepco Energy Services’ retail customer obligations will be fully performed and Pepco Energy Services’ remaining line of business will not be affected by the wind down of the retail energy supply business.
As further discussed in Note (6), “Goodwill,” as a result of the decision to wind down the retail energy supply business, Pepco Energy Services in the fourth quarter of 2009 recorded (i) a $4 million pre-tax impairment charge reflecting the write off of all goodwill allocated to this business and (ii) a pre-tax charge of less than $1 million related to employee severance. In accordance with Financial Accounting Standards Board (FASB) guidance, the Pepco Energy Services retail electric and natural gas supply business will only be reflected as a discontinued operation once the wind-down is complete.
Other Business Operations
Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments, with a book value at December 31, 2009 of approximately $1.4 billion. This activity constitutes a fourth operating segment for financial reporting purposes, which is designated as “Other Non-Regulated.” For a discussion of PHI’s cross-border energy lease investments, see Note (2), “Significant Accounting Policies - Changes in Accounting Estimates,” Note (8), “Leasing Activities - Investment in Finance Leases Held in Trust,” Note (12), “Income Taxes,” and Note (17), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments.”
(2) SIGNIFICANT ACCOUNTING POLICIES
Consolidation Policy
The accompanying consolidated financial statements include the accounts of Pepco Holdings and its wholly owned subsidiaries. All material intercompany balances and transactions between subsidiaries have been eliminated. Pepco Holdings uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies in which it holds a 20% to 50% voting interest and cannot exercise control over the operations and policies of the investment. Undivided interests in several jointly owned electric plants previously held by PHI, and certain transmission and other facilities currently held, are consolidated in proportion to PHI’s percentage interest in the facility.
Change in Accounting Principle
Historically PHI performed its goodwill impairment test on July 1 each year. After the completion of the July 1, 2009 goodwill impairment test, PHI adopted a new accounting policy whereby PHI’s annual impairment review of goodwill will be performed as of November 1 each year. Management believes that
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PHI’s new annual impairment testing date is preferable because it better aligns the timing of the test with management’s annual update of its long-term financial forecast. This change in accounting principle had no effect on PHI’s consolidated financial statements. For additional discussion on this matter see Note (6), “Goodwill.”
Consolidation of Variable Interest Entities
In accordance with the provisions of FASB guidance on variable interest entities (Accounting Standards Codification (ASC) 810), Pepco Holdings consolidates those variable interest entities with respect to which Pepco Holdings or a subsidiary is the primary beneficiary. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. Subsidiaries of Pepco Holdings have power purchase agreements (PPAs) with several entities to which the guidance applies.
ACE and Pepco PPAs
Pepco Holdings, through its ACE subsidiary, is a party to three PPAs with unaffiliated, non-utility generators (NUGs). Due to a variable element in the pricing structure of the NUGs, Pepco Holdings potentially assumes the variability in the operations of the plants related to the NUGs and, therefore, has a variable interest in the entities. Pepco Holdings continued, during 2009, to conduct exhaustive efforts to obtain information from these three entities, but was unable to obtain sufficient information to conduct the analysis required under FASB guidance to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, Pepco Holdings has applied the scope exemption from the guidance for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.
Net purchase activities with the NUGs for the years ended December 31, 2009, 2008, and 2007, were approximately $282 million, $349 million and $327 million, respectively, of which approximately $262 million, $305 million and $292 million, respectively, related to power purchases under the PPAs. Pepco Holdings does not have loss exposure under the NUGs because the costs are recoverable from ACE’s customers through regulated rates.
During the third quarter of 2008, Pepco transferred to Sempra Energy Trading LLP (Sempra) an agreement with Panda-Brandywine, L.P. (Panda) under which Pepco was obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA). Net purchase activities under the Panda PPA for the years ended December 31, 2008 and 2007 were approximately $59 million and $85 million, respectively.
DPL Wind Transactions
PHI, through its DPL subsidiary, has entered into four wind PPAs in amounts up to a total of 350 megawatts. Three of the PPAs are with land-based facilities and one of the PPAs is with an offshore facility. When completed and operational, DPL is obligated to purchase energy and renewable energy credits (RECs) from the four wind facilities and capacity from one of the wind facilities. The RECs help DPL fulfill a portion of its requirements under the State of Delaware’s Renewable Energy Portfolio Standards Act, which requires that 20 percent of total load needed in Delaware be produced from renewable sources by 2019. The Delaware Public Service Commission (DPSC) has approved the four agreements, each of which sets forth the prices to be paid by DPL over the life of the contract, and has approved the recovery of DPL’s purchase costs through customer rates.
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One of the land-based facilities became operational and went into service in December 2009. DPL is obligated to purchase energy and RECs from this facility over 15 years in amounts generated and delivered not to exceed 50.25 megawatts at rates that are fixed. Payments under the other agreements are currently expected to start in 2010 for the other two land-based contracts and 2014 for the offshore contract, if the projects are ultimately completed and operational.
The terms of the agreements, with facilities that are not yet operational, range between 20 and 25 years. When they become operational, DPL is obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed under these agreements. Recent disruptions in the capital and credit markets, as well as permitting delays, could result in setbacks in the construction schedules and the operational start dates of the wind facilities. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs.
DPL concluded that consolidation is not required for any of these PPAs under FASB guidance on the consolidation of variable interest entities (ASC 810). DPL will need to reassess its accounting conclusions if there are material changes to the contractual arrangements or wind facilities.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.
Significant matters that involve the use of estimates include the assessment of goodwill and long-lived assets for impairment, fair value calculations for certain derivative instruments, the costs of providing pension and other postretirement benefits, evaluation of the probability of recovery of regulatory assets, and the recognition of income tax benefits as it relates to investments in finance leases held in trust associated with PHI’s portfolio of cross-border energy lease investments. Additionally, PHI is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims, when the loss is determined to be probable and is reasonably estimable.
Changes in Accounting Estimates
As further discussed in Note (8), “Leasing Activities,” Note (12), “Income Taxes,” and Note (17), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” PHI maintains a portfolio of cross-border energy lease investments. The book equity value of these cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income are based on the timing and amount of all cash flows related to the cross-border energy lease investments, including income tax-related cash flows. These investments are more commonly referred to as sale-in lease-out or SILO transactions. PHI currently derives tax benefits from these investments based on the extent to which rental income is exceeded by depreciation deductions on the purchase price of the assets and interest deductions on the non-recourse debt financing (obtained to fund a substantial portion of the purchase price of the assets). The Internal Revenue Service (IRS) has announced broadly its intention to disallow the tax benefits recognized by all taxpayers on these types of investments, and, more specifically, the IRS has disallowed interest and depreciation deductions claimed by PHI related to its investments on the 2001 through 2005 PHI federal income tax returns currently under audit and has sought to recharacterize the leases as loan transactions as to which PHI would be subject to original issue discount income.
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In the last several years, IRS challenges to certain cross-border energy lease investment transactions have been the subject of litigation. This litigation has resulted in several decisions in favor of the IRS which were factored into PHI’s decision to adjust the values of the cross-border energy lease investments at June 30, 2008. While PHI believes that its tax position with regard to its cross-border energy lease investments was appropriate based on applicable statutes, regulations and case law, after evaluating the court rulings available at the time, PHI at June 30, 2008 reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of the tax benefits from its cross-border energy lease investments. Based on this reassessment, PHI recorded an after-tax charge to net income of $93 million which was comprised of a non-cash pre-tax charge of $124 million ($86 million after-tax) to reduce the equity value of these cross-border energy lease investments and a non-cash charge of $7 million after-tax to reflect the anticipated additional interest expense.
On October 21, 2009, the U.S. Court of Federal Claims issued a decision in favor of a taxpayer regarding a cross-border energy lease investment transaction. PHI views this ruling as a favorable development in PHI’s dispute with the IRS because the transaction that is the subject of the ruling is similar in many respects to PHI’s cross-border energy lease investments. Based on an assessment of the timing of the litigation and an update of its assumptions with respect to the timing of taxes due, PHI recorded an additional non-cash charge to income of $3 million ($2 million after-tax) in the fourth quarter of 2009.
Revenue Recognition
Regulated Revenue
The Power Delivery business recognizes revenue upon delivery of electricity and gas to its customers, including amounts for services rendered but not yet billed (unbilled revenue). Pepco Holdings recorded amounts for unbilled revenue of $199 million and $195 million as of December 31, 2009 and 2008, respectively. These amounts are included in Accounts Receivable. Pepco Holdings’ utility subsidiaries calculate unbilled revenue using an output based methodology. This methodology is based on the supply of electricity or gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature and estimated line losses (estimates of electricity and gas expected to be lost in the process of its transmission and distribution to customers), all of which are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material.
Taxes related to the consumption of electricity and gas by the utility customers, such as fuel, energy, or other similar taxes, are components of the tariff rates charged by PHI subsidiaries and, as such, are billed to customers and recorded in Operating Revenues. Accruals for these taxes are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by PHI and its subsidiaries in the normal course of business is charged to operations, maintenance or construction, and is not material.
Competitive Revenue
The Competitive Energy business recognizes revenue upon delivery of electricity and gas to the customer, including amounts for electricity and gas delivered, but not yet billed. Sales and purchases of electric power to Independent System Operators (ISO) are netted hourly and classified as operating revenue or operating expenses, as appropriate. Unrealized derivative gains and losses are recognized in current earnings as revenue if the derivative activity does not qualify for hedge accounting or normal sales treatment under FASB guidance on derivatives and hedging (ASC 815). Revenue for Pepco Energy Services’ energy efficiency construction business is recognized using the percentage-of-completion method, which recognizes revenue as work is completed on the contract, and revenues from its operation and maintenance and other products and services contracts are recognized when earned.
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Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in Pepco Holdings’ gross revenues were $323 million, $311 million and $318 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Accounting for Derivatives
Pepco Holdings and its subsidiaries use derivative instruments primarily to manage risk associated with commodity prices and interest rates. Risk management policies are determined by PHI’s Corporate Risk Management Committee (CRMC). The CRMC monitors interest rate fluctuation, commodity price fluctuation, and credit risk exposure, and sets risk management policies that establish limits on unhedged risk.
PHI accounts for its derivative activities in accordance with FASB guidance on derivatives and hedging. The guidance requires derivative instruments to be measured at fair value. Derivatives are recorded on the Consolidated Balance Sheets as other assets or other liabilities unless designated as “normal purchases and sales.”
Mark-to-market gains and losses on derivatives that are not designated as hedges are presented on the Consolidated Statements of Income as operating revenue. PHI uses mark-to-market accounting through earnings for derivatives that either do not qualify for hedge accounting or that management does not designate as hedges.
The gain or loss on a derivative that hedges exposure to variable cash flow of a forecasted transaction is initially recorded in Other Comprehensive Income (a separate component of common stockholders’ equity) and is subsequently reclassified into earnings in the same category as the item being hedged when the gain or loss from the forecasted transaction occurs. If a forecasted transaction is no longer probable, the deferred gain or loss in accumulated other comprehensive income is immediately reclassified to earnings. Gains or losses related to any ineffective portion of cash flow hedges are also recognized in earnings immediately as operating revenue or as a Fuel and Purchased Energy expense.
Changes in the fair value of derivatives designated as fair value hedges, as well as changes in the fair value of the hedged asset, liability, or firm commitment, are recorded as operating revenue in the Consolidated Statements of Income.
PHI designates certain commodity forwards as “normal purchase or normal sales,” which are not required to be recorded on a mark-to-market basis of accounting under FASB guidance. This type of contract is used in normal operations, settles physically, and follows standard accrual accounting. Unrealized gains and losses on these contracts do not appear on the Consolidated Balance Sheets. Examples of these transactions include purchases of fuel to be consumed in generating plants and actual receipts and deliveries of electric power. Normal purchases and sales transactions are presented on a gross basis, with normal sales recorded as operating revenue and normal purchases recorded as Fuel and Purchased Energy expenses.
The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, pricing services and external broker quotes are used to determine fair value. For some custom and complex instruments, internal models are used to interpolate broker-quality price information. For certain long-dated instruments, broker or exchange data are extrapolated for future periods where limited market information is available. Models are also used to estimate volumes for certain transactions. See Note (15), “Derivative Instruments and Hedging Activities,” for more information about the types of derivatives employed by PHI and the methodologies used to value them.
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The impact of derivatives that are marked-to-market through current earnings, the ineffective portion of cash flow hedges, and the portion of fair value hedges that flows to current earnings are presented on a net basis in the Consolidated Statements of Income as operating revenue or as a Fuel and Purchased Energy expense. When a hedging gain or loss is realized, it is presented on a net basis in the same line item as the underlying item being hedged. Normal purchase and sale transactions are presented gross on the Consolidated Statements of Income as they are realized. Unrealized derivative gains and losses are presented gross on the Consolidated Balance Sheets except where contractual netting agreements are in place with individual counterparties.
Stock-Based Compensation
Pepco Holdings recognizes compensation expense for stock-based awards, modifications or cancellations based on the grant-date fair value. Compensation expense is recognized over the requisite service period. In addition, compensation expense recognized includes the cost for all stock-based awards granted prior to, but not yet vested as of January 1, 2006, measured at the grant-date fair value. A deferred tax asset and deferred tax benefit are also recognized concurrently with compensation expense for the tax effect of the deduction of stock options and restricted stock awards, which are deductible only upon exercise and vesting/release from restriction, respectively.
PHI has issued awards for both time-based restricted stock and performance-based restricted stock units that vest over a three year period. The compensation expense associated with these awards is based upon estimated fair value at grant date and is recognized over the three-year service period. The time-based awards have been issued annually beginning with the 2007-2009 period.
Pepco Holdings estimates the fair value of each stock option award on the date of grant using the Black-Scholes-Merton option pricing model. This model uses assumptions related to expected option term, expected volatility, expected dividend yield, and risk-free interest rate. Pepco Holdings uses historical data to estimate option exercise and employee termination within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding.
Pepco Holdings’ current policy is to issue new shares to satisfy stock option exercises and the vesting of restricted stock awards.
Income Taxes
PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement, which was approved by the Securities and Exchange Commission (SEC) in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss amounts.
On May 2, 2007, the FASB issued guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. PHI applied the guidance on January 1, 2007.
The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on PHI’s and its subsidiaries’ federal and state income tax returns. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and are measured using presently enacted tax rates. See Note (12), “Income Taxes,” for a listing of primary deferred tax assets and liabilities. The portions of Pepco’s, DPL’s, and ACE’s deferred tax liabilities applicable to their
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utility operations that have not been recovered from utility customers represent income taxes recoverable in the future and are included in Regulatory assets on the Consolidated Balance Sheets. See Note (7), “Regulatory Assets and Regulatory Liabilities,” for additional information.
PHI recognizes interest on under/over payments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.
Investment tax credits are being amortized to income over the useful lives of the related property.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, cash invested in money market funds, and commercial paper held with original maturities of three months or less.
Restricted Cash Equivalents
The restricted cash equivalents included in Current Assets and the restricted cash equivalents included in Investments and Other Assets represent (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated, based on management’s intent with respect to the use of such cash equivalents. The classification as current or non-current conforms to the classification of the related liabilities.
Accounts Receivable and Allowance for Uncollectible Accounts
Pepco Holdings’ accounts receivable balances primarily consist of customer accounts receivable, other accounts receivable, and accrued unbilled revenue generated by subsidiaries in the Power Delivery and Competitive Energy business. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).
PHI maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other Operation and Maintenance expense in the Consolidated Statements of Income. PHI determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a general reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors, such as the aging of the receivables, historical collection experience, the economic and competitive environment, and changes in the creditworthiness of its customers. Although management believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, PHI records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment becomes known.
Inventories
Inventory is valued at the lower of cost or market value. Included in inventories are:
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generation, transmission, and distribution materials and supplies;
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natural gas, fuel oil, and coal; and
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emission allowances, RECs and Regional Greenhouse Gas Initiative allowances.
PHI utilizes the weighted average cost method of accounting for inventory items, other than fuel oil held for resale. Under this method, an average price is determined for the quantity of units acquired at each
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price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies inventory are generally charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
The costs of natural gas, coal, and fuel oil for generating plants, including transportation costs, are included in inventory when purchased and charged to fuel expense when used. The first in first out (FIFO) method is used for fuel oil inventory held for resale in Conectiv Energy’s oil marketing business. For PHI the FIFO method is not materially different from the weighted average cost method due to the high inventory turnover rate in the oil marketing business.
Emission allowances received from the U.S. Environmental Protection Agency (EPA) are added to current inventory each year at a zero cost. Purchased emission allowances are recorded at cost. Emission allowances sold or consumed at the generating plants are expensed at a weighted-average cost. This cost tends to be relatively low due to the inclusion of the zero-basis allowances. At December 31, 2009 and 2008, the book value of emission allowances was $8 million and $11 million, respectively. Pepco Holdings has established a committee to monitor compliance with emissions regulations and to ensure its generating plants have the required number of allowances.
RECs are transferrable, intangible energy certificates that represent proof that one megawatt-hour (MWh) of electricity was generated from an eligible renewable energy resource. RECs are added to current inventory each year at cost. RECs sold or consumed, to satisfy load requirements, are expensed at a weighted-average cost. At December 31, 2009 and 2008, the book value of RECs was $10 million and $3 million, respectively.
At December 31, 2008, the market value of Conectiv Energy’s oil inventory was lower than cost and accordingly a pre-tax charge of $15 million was recorded. This charge is included in Fuel and Purchased Energy expense in the Consolidated Statements of Income.
Goodwill
Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. Substantially all of Pepco Holdings’ goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and was allocated to Pepco Holdings’ Power Delivery reporting unit based on the aggregation of its components. Pepco Holdings tests its goodwill for impairment annually as of November 1, and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a decline in PHI’s stock price causing market capitalization to fall further below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its annual impairment test on November 1, 2009 and did not record an impairment charge as described in Note (6), “Goodwill.”
Regulatory Assets and Regulatory Liabilities
The Power Delivery operations of Pepco are regulated by the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC).
The Power Delivery operations of DPL are regulated by the DPSC and the MPSC and, until the sale of its Virginia assets on January 2, 2008, were also regulated by the Virginia State Corporation Commission. DPL’s interstate transportation and wholesale sale of natural gas are regulated by the Federal Energy Regulatory Commission (FERC).
The Power Delivery operations of ACE are regulated by the New Jersey Board of Public Utilities (NJBPU).
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The transmission and wholesale sale of electricity by Pepco, DPL, and ACE are regulated by FERC.
The FASB guidance on Regulated Operations (ASC 980) applies to the Power Delivery businesses of Pepco, DPL, and ACE. It allows regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities and to defer the income statement impact of certain costs that are expected to be recovered in future rates. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders, and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, then the regulatory asset will be eliminated through a charge to earnings.
Effective June 2007, the MPSC approved a bill stabilization adjustment mechanism (BSA) for retail customers of Pepco and DPL. The DCPSC also approved a BSA for Pepco’s retail customers, effective in November 2009. See Note (17) “Commitments and Contingencies - Regulatory and Other Matters - Rate Proceedings.” For customers to whom the BSA applies, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. Pursuant to this mechanism, Pepco and DPL recognize either (a) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer, or (b) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.
Leasing Activities
Pepco Holdings’ lease transactions can include plant, office space, equipment, software, vehicles, and power purchase agreements. In accordance with FASB guidance on leases (ASC 840), these leases are classified as either leveraged leases, operating leases or capital leases.
Leveraged Leases
Income from investments in leveraged lease transactions, in which PHI is an equity participant, is accounted for using the financing method. In accordance with the financing method, investments in leased property are recorded as a receivable from the lessee to be recovered through the collection of future rentals. Income, including investment tax credits, on leveraged equipment leases is recognized over the life of the lease at a constant rate of return on the positive net investment. Each quarter, PHI reviews the carrying value of each lease, which includes a review of the underlying lease financial assumptions, the timing and collectibility of cash flows, and the credit quality (including, if available, credit ratings) of the lessee. Changes to the underlying assumptions, if any, would be accounted for in accordance with FASB guidance on leases and reflected in the carrying value of the lease effective for the quarter within which they occur.
Operating Leases
An operating lease generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, PHI’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.
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Capital Leases
For ratemaking purposes, capital leases are treated as operating leases; therefore, in accordance with FASB guidance on Regulated Operations, the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life.
Arrangements Containing a Lease
PPAs might fall within the criteria of contracts containing a lease if the arrangement conveys the right to use and control property, plant or equipment. If so, PHI is required to determine whether capital or operating lease accounting is appropriate.
Property, Plant and Equipment
Property, plant and equipment are recorded at original cost, including labor, materials, asset retirement costs, and other direct and indirect costs including capitalized interest. The carrying value of property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation. For non-regulated property, the cost and accumulated depreciation of the property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition.
The annual provision for depreciation on electric and gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Property, plant and equipment, other than electric and gas facilities, is generally depreciated on a straight-line basis over the useful lives of the assets. The table below provides system-wide composite annual depreciation rates for the years ended December 31, 2009, 2008, and 2007.
(a) Increase in 2009 due to accelerated depreciation of the Benning Road and Buzzard Point generating plants scheduled for retirement in May 2012.
In accordance with FASB guidance, costs associated with planned major maintenance activities related to generation facilities are expensed as incurred.
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Long-Lived Asset Impairment Evaluation
Pepco Holdings evaluates long-lived assets to be held and used, such as generating property and equipment and real estate, to determine if they are impaired whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount.
For long-lived assets held for sale, an impairment loss is recognized to the extent that the asset’s carrying amount exceeds its fair value including costs to sell.
Capitalized Interest and Allowance for Funds Used During Construction
In accordance with FASB guidance on Regulated Operations (ASC 980), PHI’s utility subsidiaries can capitalize as Allowance for Funds Used During Construction (AFUDC) the capital costs of financing the construction of plant and equipment. The debt portion of AFUDC is recorded as a reduction of “interest expense” and the equity portion of AFUDC is credited to “other income” in the accompanying Consolidated Statements of Income.
Pepco Holdings recorded AFUDC for borrowed funds of $7 million, $5 million, and $7 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Pepco Holdings recorded amounts for the equity component of AFUDC of $3 million, $5 million and $4 million for the years ended December 31, 2009, 2008, and 2007, respectively.
Amortization of Debt Issuance and Reacquisition Costs
Pepco Holdings defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issues. When refinancing existing debt of PHI’s utility subsidiaries, any unamortized premiums, discounts and debt issuance costs are classified as regulatory assets and are amortized generally over the life of the original issue. Any costs associated with the redemption of the existing debt are amortized generally over the life of the original issue.
Asset Removal Costs
In accordance with FASB guidance on asset retirement obligations (ASC 410), asset removal costs are recorded as regulatory liabilities. At December 31, 2009 and 2008, $352 million and $341 million, respectively, are included within regulatory liabilities in the accompanying Consolidated Balance Sheets.
Pension and Other Postretirement Benefit Plans
Pepco Holdings sponsors a non-contributory defined benefit retirement plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through a nonqualified retirement plan and provides certain postretirement health care and life insurance benefits for eligible retired employees.
Pepco Holdings accounts for the PHI Retirement Plan, nonqualified retirement plans and its retirement healthcare and life insurance benefits for eligible employees in accordance with FASB guidance on Retirement Benefits (ASC 715).
See Note (10), “Pensions and Other Postretirement Benefits,” for additional information.
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Preferred Stock
As of December 31, 2009 and 2008, PHI had 40 million shares of preferred stock authorized for issuance, with a par value of $.01 per share. No shares of preferred stock were outstanding at December 31, 2009 and 2008.
Subsequent Events
PHI has evaluated all subsequent events through February 26, 2010, the date of the issuance of the Consolidated Financial Statements.
Reclassifications and Adjustments
Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustments have been recorded which are not considered material either individually or in the aggregate.
In 2009, DPL recorded additional revenue of $14 million related to the unbilled portion of the Gas Cost Rate (GCR) revenue, which was not previously recognized. Because the GCR revenue is deferred, an additional expense of $14 million has also been recorded in 2009. Consequently, there is no impact on consolidated net income as a result of this adjustment.
In the fourth quarter of 2009, PHI recorded certain adjustments to correct errors related to income taxes. These adjustments, which primarily resulted from the completion of additional analysis of the current and deferred income tax balances, resulted in a decrease in income tax expense of $6 million.
During 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan that resulted in an understatement of stock-based compensation expense in 2006 and 2007. Pepco and DPL also recorded adjustments to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 for which late payment fees were incorrectly recognized. These errors were corrected in 2008, resulting in an increase in Other Operation and Maintenance expenses for the year ended December 31, 2008 of $15 million.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Business Combinations (ASC 805)
The accounting guidance on business combinations was amended by the FASB effective beginning January 1, 2009. The amendment did not change the fundamental concepts that the acquisition method of accounting be used and that an acquirer must be identified for each business combination. However, the guidance expanded the definition of a business subject to this guidance and also requires the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.
On April 1, 2009, the FASB issued additional guidance to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The additional guidance requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with FASB guidance on contingencies (ASC 450).
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The new guidance applied prospectively to business combinations for which the acquisition date was on or after January 1, 2009. The adoption of the guidance did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.
Fair Value Measurement and Disclosures (ASC 820)
There is a variety of new accounting guidance from the FASB that was effective for different financial reporting periods during 2009. Nonrecurring fair value measurement guidance for non-financial assets and non-financial liabilities was effective beginning January 1, 2009 for PHI. The adoption of this guidance did not have a material impact on the fair value measurements of PHI’s nonfinancial assets and non-financial liabilities.
New FASB guidance for the fair value measurement of liabilities issued with inseparable third-party credit enhancements was also effective beginning January 1, 2009 for PHI. The guidance applies to liabilities such as debt, derivatives, and other instruments that are guaranteed by third parties. The effect of the credit enhancement may not be included in the fair value measurement of the liability, even if the liability has an inseparable third-party credit enhancement. The issuer is required to disclose the existence of the inseparable third-party credit enhancement on the issued liability. The adoption of the guidance did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.
PHI adopted new FASB guidance in the second quarter of 2009 for fair value measurement when markets are inactive and distressed. This guidance was effective for interim periods ending after June 15, 2009. The guidance outlines a two-step test to identify inactive and distressed markets and provides a fair value application example for financial instruments when both conditions are met. The guidance primarily applies to PHI’s valuation of derivatives valued using information from inactive and distressed markets. Use of such information requires management to exercise judgment regarding how the market information is incorporated into the measurement of fair value. This guidance did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.
Effective beginning with its June 30, 2009 financial statements, PHI began disclosing the fair value of debt issued by PHI and its utilities on a quarterly basis in Note (16), “Fair Value Disclosures,” in accordance with FASB guidance which was effective for interim reporting periods ending after June 15, 2009.
The FASB issued new guidance on the fair value measurement of liabilities when there is a lack of observable market information. The guidance clarifies that, when a quoted price is not available for the identical liability, an entity can use the quoted price of the identical liability when it is traded as an asset, the quoted price for a similar liability, or the quoted price for a similar liability when it is traded as an asset. If these prices are not available, then entities can employ an income or market valuation approach that considers what the entity would pay to transfer the identical liability or would receive to enter into the identical liability. The guidance was effective for PHI starting October 1, 2009, and did not have an impact on PHI’s overall financial condition, results of operations, or cash flows.
Consolidation (ASC 810)
The FASB established new accounting and reporting standards for a non-controlling interest (also called a “minority interest”) in a subsidiary and for the deconsolidation of a subsidiary. The new guidance clarified that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.
The guidance was effective prospectively for financial statement reporting periods beginning January 1, 2009 for PHI, except for the financial statement presentation and disclosure requirements which also apply to prior reporting periods presented. As of January 1, 2009, PHI adopted the provisions of this guidance and reclassified $6 million of non-controlling interests from the minority interest line item of its balance sheet to a component of equity. Otherwise, the adoption of the guidance did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.
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Derivatives and Hedging Disclosures (ASC 815)
The FASB issued new disclosure requirements for derivatives and hedging effective for financial statement reporting periods beginning January 1, 2009 for PHI. Some of the new disclosures include derivative objectives and strategies, derivative volumes by product type, classification and gross fair values of derivative assets and liabilities, classification and amounts of gains and losses on derivatives and related hedged items, and credit-risk-related contingent features in derivatives. PHI adopted the new requirements beginning with its March 31, 2009 financial statements with comparative disclosures for prior reporting periods. The disclosures are included within Note (15), “Derivative Instruments and Hedging Activities.”
Earnings Per Share (ASC 260)
The FASB issued new guidance to determine when unvested instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS). As of January 1, 2009, PHI adopted the provisions of this guidance for the presentation of EPS data in the Consolidated Statements of Income and Note (14), “Stock-based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock.” All prior period EPS information presented was adjusted retrospectively to conform to the provisions of the guidance. The adoption did not result in a change in the reported EPS for prior periods presented.
Investments - Equity Method and Joint Ventures (ASC 323)
The FASB issued guidance addressing the accounting for equity method investments including: (i) how an equity method investment should initially be measured, (ii) how it should be tested for impairment, and (iii) how to account for an equity method investee’s issuance of shares. As of January 1, 2009, PHI adopted the provisions of this guidance and there was no material impact on PHI’s overall financial condition, results of operations, or cash flows.
Investments - Debt and Equity Securities (ASC 320)
The FASB issued new guidance on other-than-temporary impairment (OTTI) of debt and equity securities. The guidance requires information about the credit and noncredit component of an OTTI event and when an OTTI event has occurred. It requires separate display of losses related to credit deterioration and losses related to other market factors on the statements of income. Market-related losses would be recorded in other comprehensive income if it is not likely that the investor will have to sell the security prior to recovery. PHI adopted this guidance as of April 1, 2009, and concluded that none of its debt and equity securities investments were within its scope. The new guidance, therefore, did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.
Subsequent Events (ASC 855)
Beginning with its June 30, 2009 financial statements, PHI adopted new FASB guidelines for the disclosure of events that occur after the balance sheet reporting date, but before the financial statements are issued. The new guidance requires the disclosure of the date through which PHI has assessed the impact of subsequent events on the financial statements. The new guidance was effective for interim or annual financial periods ending after June 15, 2009. PHI has disclosed this subsequent events date in Note (2), “Significant Accounting Policies.”
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FASB Accounting Standards Codification (ASC 105)
The ASC identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of nongovernmental financial statements presented under GAAP. In addition, it replaces the reference system for standards and guidance with a new numerical designation system known as the ASC. The ASC is the single source reference system for all authoritative GAAP.
The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. PHI adopted the ASC guidance and referencing system for GAAP in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references to GAAP. The adoption of ASC did not result in a change in accounting principle for PHI, therefore, it did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.
Disclosures about Pension and Postretirement Plan Assets (ASC 715)
The FASB issued new annual disclosure requirements about the fair value measurements and disclosures for plan assets of a defined benefit pension or other postretirement plan that are effective beginning with financial statements issued after December 15, 2009. The disclosures require entities to provide users an understanding of: (i) the investment allocation decisions made, (ii) factors used in investment policies and strategies, (iii) plan assets by major investment types, (iv) inputs and valuation techniques used to measure the fair value of plan assets, (v) significant concentrations of risk within the plan, and (vi) the effects of fair value measurement using significant unobservable inputs on changes in the value of plan assets for the period.
PHI has provided the new disclosures beginning with its December 31, 2009 financial statements in Note (10), “Pensions and Other Postretirement Benefits.” Comparative disclosures are not required for earlier periods presented.
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
Transfers and Servicing (ASC 860)
The FASB issued new guidance that removes the concept of a qualifying special-purpose entity (QSPE) from the current guidance on transfers and servicing and the QSPE scope exception in current guidance on consolidation. The new guidance also changes the requirements for derecognizing financial assets and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets.
The new guidance is effective for transfers of financial assets occurring in fiscal periods beginning after November 15, 2009; therefore, this guidance will be effective on January 1, 2010 for PHI. PHI does not expect this standard will have a material impact on its overall financial condition, results of operations, or cash flows.
Consolidation of Variable Interest Entities (ASC 810)
The FASB issued new consolidation guidance regarding variable interest entities that eliminates the existing quantitative analysis requirement and adds new qualitative factors to determine whether consolidation is required. The new qualitative factors would be applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retained the existing provision that allowed entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine the primary beneficiary.
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The new guidance is effective for fiscal periods beginning after November 15, 2009 for existing and newly created entities; therefore, this guidance will be effective on January 1, 2010 for PHI. PHI does not expect that the new guidance will result in a material change in accounting or disclosures in its financial statements.
Fair Value Measurement and Disclosures (ASC 820)
The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. Some of the requirements will be effective for PHI beginning with its March 31, 2010 financial statements and include: (i) a disaggregation of balance sheet categories that are measured at fair value into classes (i.e. subsets of assets or liabilities within a balance sheet line item), (ii) a description of pricing inputs and valuation methodologies for instruments with Level 2 and 3 valuation inputs, and (iii) a reconciliation of transfers of instruments between Level 1 and 2 valuation categories. Beginning with its March 31, 2011 financial statements, PHI will be required to disaggregate the Level 3 fair value measurement reconciliations into separate categories for purchases, sales, issuances, and settlements. PHI is evaluating the impact of this new guidance on its financial statement footnote disclosures.
(5) SEGMENT INFORMATION
Pepco Holdings’ management has identified its operating segments at December 31, 2009 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Corporate and Other includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization expense related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. Segment financial information for the years ended December 31, 2009, 2008, and 2007, is as follows:
(a) The Total Assets line item in this column includes Pepco Holdings’ goodwill balance which is primarily attributable to Power Delivery. Corporate and Other includes intercompany amounts of $(326) million for Operating Revenue, $(318) million for Operating Expense, $(76) million for Interest Income, $(73) million for Interest Expense, and $(3) million for Preferred Stock Dividends.
(b) Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $272 million for the year ended December 31, 2009.
(c) Includes depreciation and amortization expense of $391 million, consisting of $323 million for Power Delivery, $40 million for Conectiv Energy, $18 million for Pepco Energy Services, $2 million for Other Non-Regulated, and $8 million for Corporate and Other.
(d) Includes $40 million ($24 million after-tax) gain related to settlement of Mirant bankruptcy claims.
(e) Includes $11 million after-tax state income tax benefit, net of fees, related to a change in the tax reporting for the disposition of certain assets in prior years.
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(a) The Total Assets line item in this column includes Pepco Holdings’ goodwill balance which is primarily attributable to Power Delivery. Included in Corporate and Other are intercompany amounts of $(422) million for Operating Revenue, $(417) million for Operating Expense, $(70) million for Interest Income, $(67) million for Interest Expense, and $(3) million for Preferred Stock Dividends.
(b) Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $374 million for the year ended December 31, 2008.
(c) Includes depreciation and amortization of $377 million, consisting of $317 million for Power Delivery, $37 million for Conectiv Energy, $13 million for Pepco Energy Services, $2 million for Other Non-Regulated and $8 million for Corporate and Other.
(d) Included in Operating Revenue is a pre-tax charge of $124 million ($86 million after-tax) related to the adjustment to the equity value of cross-border energy lease investments, and included in Income Tax Benefit is a $7 million after-tax charge for the additional interest accrued on the related tax obligations.
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(a) The Total Assets line item in this column includes Pepco Holdings’ goodwill balance which is primarily attributable to Power Delivery. Included in Corporate and Other are intercompany amounts of $(469) million for Operating Revenue, $(464) million for Operating Expense, $(93) million for Interest Income, $(90) million for Interest Expense, and $(3) million for Preferred Stock Dividends.
(b) Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy and Pepco Energy Services in the amount of $431 million for the year ended December 31, 2007.
(c) Includes depreciation and amortization of $366 million, consisting of $305 million for Power Delivery, $38 million for Conectiv Energy, $12 million for Pepco Energy Services, $2 million for Other Non-Regulated and $9 million for Corporate and Other.
(d) Includes $33 million ($20 million, after-tax) gain related to settlement of Mirant bankruptcy claims.
(e) Includes $20 million benefit ($18 million net of fees) related to Maryland income tax settlement.
(f) Includes stock-based compensation expense of $4 million, consisting primarily of $3 million for Power Delivery and $1 million for Conectiv Energy.
(6) GOODWILL
Substantially all of PHI’s $1.4 billion goodwill balance was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated to the Power Delivery reporting unit based on the aggregation of its components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350). PHI’s annual impairment test as of November 1, 2009 indicated that goodwill was not impaired. As of December 31, 2009, after review of its significant assumptions in the goodwill impairment analysis, PHI concluded that there were no events requiring PHI to perform an interim goodwill impairment test. Although PHI’s market capitalization was below book value at December 31, 2009, PHI’s market capitalization has improved compared to earlier periods. PHI performed its previous annual goodwill impairment test as of July 1, 2009, and interim impairment tests as of March 31, 2009 and December 31, 2008 when its market capitalization was further below book value than at November 1, 2009, and concluded that its goodwill was not impaired at those earlier dates.
In order to estimate the fair value of its Power Delivery reporting unit, PHI uses two discounted cash flow models. The models differ in the method used to calculate the terminal value of the reporting unit. One model estimates terminal value based on a constant annual cash flow growth rate that is consistent with PHI’s long-term view of the business, and the other model estimates terminal value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. The models use a cost of capital appropriate for a regulated utility as the discount rate for the estimated cash flows associated with the reporting unit. PHI has consistently used this valuation methodology to estimate the fair value of Power Delivery.
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The estimation of fair value is dependent on a number of factors that are derived from the Power Delivery reporting unit’s business forecast, including but not limited to interest rates, growth assumptions, returns on rate base, operating and capital expenditure requirements, and other factors, changes in which could materially affect the results of impairment testing. Assumptions used in the models were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the Power Delivery reporting unit include utility sector market performance, sustained adverse business conditions, changes in forecasted revenues, higher operating and capital expenditure requirements, a significant increase in the cost of capital and other factors.
In addition to estimating the fair value of its Power Delivery reporting unit, PHI estimated the fair value of its other reporting units (Conectiv Energy, Pepco Energy Services, Other Non-Regulated, and Corporate and Other) at November 1, 2009. The sum of the fair value of all reporting units was reconciled to PHI’s market capitalization at November 1, 2009 to corroborate estimates of the fair value of its reporting units. The sum of the estimated fair values of all reporting units exceeded the market capitalization of PHI at November 1, 2009. PHI believes that the excess of the estimated fair value of PHI’s reporting units as compared to PHI’s market capitalization reflects a reasonable control premium that is comparable to control premiums observed in historical acquisitions in the utility industry during various economic environments. Given the lack of a fundamental change in the Power Delivery reporting unit’s business, PHI does not believe that the decline in its stock price since mid-2008 indicated a commensurate decline in the fair value of PHI’s Power Delivery reporting unit. PHI’s Power Delivery reporting unit consists of regulated companies with regulated recovery rates and approved rates of return allowing for generally predictable and steady streams of revenues and cash flows over an extended period of time.
PHI will continue to closely monitor for indicators of goodwill impairment, including the sustained period of time that PHI’s stock price has been below its book value
As discussed in Note 1, “Organization,” on December 7, 2009, PHI announced the wind-down of the Pepco Energy Services retail energy supply business. As a result of this decision, PHI determined that all goodwill allocated to this business was impaired, and therefore, PHI recorded a goodwill impairment charge of $4 million in the fourth quarter of 2009 to write-off the goodwill associated with this business.
A roll forward of PHI’s goodwill balance is set forth below in millions of dollars:
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(7) REGULATORY ASSETS AND REGULATORY LIABILITIES
The components of Pepco Holdings’ regulatory asset balances at December 31, 2009 and 2008 are as follows:
The components of Pepco Holdings’ regulatory liability balances at December 31, 2009 and 2008 are as follows:
A description for each category of regulatory assets and regulatory liabilities follows:
Securitized Stranded Costs: Includes contract termination payments under a contract between ACE and an unaffiliated non-utility generator and costs associated with the regulated operations of ACE’s electricity generation business which are no longer recoverable through customer rates. The recovery of these stranded costs has been securitized through the issuance by Atlantic City Electric Transition Funding LLC (ACE Funding) of transition bonds (Transition Bonds). A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. The stranded costs are amortized over the life of the Transition Bonds, which mature between 2010 and 2023. A return is earned on these deferrals with the exception of income tax balances.
Pension and OPEB Costs: Represents the unfunded portion of Pepco Holdings’ defined benefit pension and other postretirement benefit (OPEB) plans that is probable of recovery by Pepco, DPL and ACE in rates. A return is earned on these deferrals.
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Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco and DPL. A return is earned on these deferrals. The regulatory liability represents primarily deferred costs associated with a net over-recovery by ACE of Default Electricity Supply costs and other restructuring related costs incurred by ACE. A return is not earned on these deferrals.
Deferred Income Taxes: Represents a receivable from Power Delivery’s customers for tax benefits applicable to utility operations of Pepco, DPL, and ACE previously flowed through before the companies were ordered to account for the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed. There is no return earned on these deferrals.
Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment of Pepco, DPL and ACE for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period. A return is earned on these deferrals.
Unrecovered Purchased Power Contract Costs: Represents deferred costs related to purchase power contracts entered into by ACE. The amortization period began in July 1994 and will end in May 2014. A return is earned on these deferrals.
Deferred Other Postretirement Benefit Costs: Represents the non-cash portion of other postretirement benefit costs deferred by ACE during 1993 through 1997. This cost is being recovered over a 15-year period that began on January 1, 1998. There is no return earned on this deferral.
Phase In Credits: Represented phase-in credits for participating Maryland and Delaware residential and small commercial customers to mitigate the immediate impact of significant rate increases due to energy costs in 2006. The deferral period for Delaware was May 1, 2006 to January 1, 2008, with recovery occurring over a 17-month period beginning January 2008. The Delaware deferral was recovered from participating customers on a straight-line basis. The deferral period for Maryland was June 1, 2006 to June 1, 2007, with the recovery occurring over an 18-month period beginning June 2007. Recovery of all deferred amounts was completed during 2009. There was no return earned on these deferrals.
Gas derivatives: Represents losses associated with the hedge of gas transactions that are recoverable by DPL through the Gas Cost Rate approved by the Delaware Public Service Commission. A return is earned on these deferrals.
Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years. Also includes the under-recovery of administrative costs associated with Default Electricity Supply in the District of Columbia and Maryland. These regulatory assets generally do not earn a return.
Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax liabilities applicable to utility operations of Pepco, DPL, and ACE that have not been reflected in current customer rates for which future payment to customers is probable. As temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return earned on these deferrals.
Federal and New Jersey Tax Benefits, Related to Securitized Stranded Costs: Securitized stranded costs include a portion of stranded costs attributable to the future tax benefit expected to be realized when the higher tax basis of generating plants divested by ACE is deducted for New Jersey state income tax purposes, as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE’s regulated electricity delivery customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service issues its final regulations with respect to normalization of these federal excess deferred taxes. There is no return earned on these deferrals.
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Asset Removal Costs: The depreciation rates for Pepco and DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. As such, Pepco and DPL have recorded regulatory liabilities for their estimate of the difference between incurred removal costs and the level of removal costs recovered through depreciation rates. There is no return earned on these deferrals.
Excess Depreciation Reserve: The excess depreciation reserve was recorded as part of an ACE New Jersey rate case settlement. This excess reserve is the result of a change in estimated depreciable lives and a change in depreciation technique from remaining life to whole life. The excess is being amortized over an 8.25 year period, which began in June 2005. There is no return earned on these deferrals.
Settlement Proceeds - Mirant Bankruptcy Claims: In 2007, Pepco received $414 million of net proceeds from settlement of a Mirant Corporation (Mirant) bankruptcy claim, plus interest earned, which was designated to pay for future above-market capacity and energy purchases under the Panda PPA. In 2008, Pepco transferred the Panda PPA to Sempra in a transaction in which Pepco made a payment to Sempra and all further Pepco rights, obligations and liabilities under the Panda PPA were terminated. The balance at December 31, 2008 reflects the funds remaining after the Sempra payment.
In March 2009, the DCPSC issued an order approving Pepco’s sharing proposal for the District of Columbia under which approximately $24 million was distributed to District of Columbia customers as a one-time billing credit. In July 2009, the MPSC approved a settlement under which Pepco distributed approximately $38 million to Maryland customers during the billing month of August 2009 through a one-time billing credit. The $40 million balance was recorded by PHI as income in 2009. See Note (17), “Commitments and Contingencies - Proceeds from Settlement of Mirant Bankruptcy Claims,” for additional information. There was no return earned on this deferral.
Gain from Sale of Divested Assets: Represents (i) the balance of the net gain realized by ACE from the sale in 2006 of its interests in the Keystone and Conemaugh generating facilities and (ii) the balance of the net proceeds realized by ACE from the sale in 2007 of the B.L. England generating facility and the monetization of associated emission allowance credits. Both gains, including interest on the unamortized balance, have been returned to ACE’s ratepayers as a credit on their bills - the Keystone and Conemaugh gain over a 33-month period that began during the October 2006 billing period and the B.L. England and emission allowances proceeds over a 12-month period that began during the June 2008 billing period. There was no return earned on these deferrals.
Other: Includes miscellaneous regulatory liabilities such as the over-recovery of administrative costs associated with Default Electricity Supply in Delaware and Maryland. These regulatory liabilities generally do not earn a return.
(8) LEASING ACTIVITIES
Investment in Finance Leases Held in Trust
As of December 31, 2009 and 2008, Pepco Holdings had cross-border energy lease investments of $1.4 billion and $1.3 billion, respectively, consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks located outside of the United States.
As further discussed in Note (2), “Significant Accounting Policies - Changes in Accounting Estimates,” and Note (17), “Commitments and Contingencies-PHI’s Cross-Border Energy Lease Investments,” during 2009 and 2008, PHI reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of tax benefits generated from its cross-border energy lease investments.
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Based on these reassessments, PHI recorded a reduction in its cross-border energy lease investment revenue of $3 million in 2009 and $124 million in 2008.
The components of the cross-border energy lease investments, as of December 31, are summarized below:
Income recognized from cross-border energy lease investments was comprised of the following for the years ended December 31:
Scheduled lease payments from the cross-border energy lease investments are net of non-recourse debt. Minimum lease payments receivable from the cross-border energy lease investments for each of the years 2010 through 2014 and thereafter are $16 million for 2010, zero for each of the years 2011 through 2014, and $1,370 million thereafter.
Lease Commitments
Pepco leases its consolidated control center, which is an integrated energy management center used by Pepco to centrally control the operation of its transmission and distribution systems. This lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments, which totaled $152 million. The lease requires semi-annual payments of approximately $8 million over a 25-year period beginning in December 1994, and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under FASB guidance on leases, the amortization of leased assets is modified so that the total interest on the obligation and amortization of the leased asset is equal to the rental expense allowed for rate-making purposes. The amortization expense is included as Depreciation and Amortization in the Consolidated Statements of Income. This lease has been treated as an operating lease for rate-making purposes.
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Capital lease assets recorded within Property, Plant and Equipment at December 31, 2009 and 2008, in millions of dollars, are comprised of the following:
The approximate annual commitments under all capital leases are $15 million for each year 2010 through 2014, and $77 million thereafter.
Rental expense for operating leases was $70 million, $69 million, and $50 million for the years ended December 31, 2009, 2008, and 2007, respectively.
Total future minimum operating lease payments for Pepco Holdings as of December 31, 2009, are $79 million in 2010, $49 million in 2011, $34 million in 2012, $22 million in 2013, $23 million in 2014, and $354 million thereafter.
(9) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of the following:
The non-operating and other property amounts include balances for general plant, distribution and transmission plant held for future use as well as other property held by non-utility subsidiaries.
Pepco Holdings’ utility subsidiaries use separate depreciation rates for each electric plant account. The rates vary from jurisdiction to jurisdiction.
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Asset Sales
In January 2008, DPL completed (i) the sale of its retail electric distribution assets on the Eastern Shore of Virginia for a purchase price of approximately $49 million, and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia for a purchase price of approximately $5 million.
In 2007, ACE completed the sale of the B.L. England generating facility for a price of $9 million. In 2008, ACE received an additional $4 million in settlement of an arbitration proceeding concerning the terms of the purchase agreement. See Note (7), “Regulatory Assets and Regulatory Liabilities,” for treatment of gains from these sales.
Jointly Owned Plant
PHI’s Consolidated Balance Sheets include its proportionate share of assets and liabilities related to jointly owned plant. At December 31, 2009 and 2008, PHI’s subsidiaries had a $14 million and $15 million net book value ownership interest in transmission and other facilities in which various parties also have ownership interests, respectively. PHI’s share of the operating and maintenance expenses of the jointly-owned plant is included in the corresponding expenses in the Consolidated Statements of Income. PHI is responsible for providing its share of the financing for the above jointly-owned facilities.
(10) PENSIONS AND OTHER POSTRETIREMENT BENEFITS
Pension Benefits and Other Postretirement Benefits
Pepco Holdings sponsors the PHI Retirement Plan, which covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings’ subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans.
Pepco Holdings provides certain postretirement health care and life insurance benefits for eligible retired employees. Most employees hired on January 1, 2005 or later will not have company subsidized retiree medical coverage; however, they will be able to purchase coverage at full cost through PHI.
Net periodic benefit cost is included in other operation and maintenance expense, net of the portion of the net periodic benefit cost that is capitalized as part of the cost of labor for internal construction projects. After intercompany allocations, the three utility subsidiaries are generally responsible for approximately 80% to 85% of total PHI net periodic benefit cost.
Pepco Holdings accounts for the PHI Retirement Plan, nonqualified retirement plans, and its postretirement health care and life insurance benefits for eligible employees in accordance with FASB guidance on retirement benefits. PHI’s financial statement disclosures are also prepared in accordance with FASB guidance on retirement benefits.
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All amounts in the following tables are in millions of dollars:
(a) Other Postretirement Benefits paid is net of Medicare Part D subsidy receipts of $3 million in 2009 and $2 million in 2008.
At December 31, 2009, PHI Retirement Plan assets were $1.5 billion and the accumulated benefit obligation (ABO) was approximately $1.6 billion. At December 31, 2008, PHI’s Retirement Plan assets were approximately $1.1 billion and the ABO was approximately $1.6 billion.
The following table provides the amounts recognized in PHI’s Consolidated Balance Sheets as of December 31, in millions of dollars:
Amounts included in accumulated other comprehensive loss (pre-tax) and regulatory assets at December 31, in millions of dollars, consist of:
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The estimated net actuarial loss and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year are $47 million and zero, respectively. The estimated net loss and prior service credit for the other postretirement benefit plan that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year are $13 million and $4 million, respectively.
The table below provides the components of net periodic benefit costs recognized for the years ended December 31, in millions of dollars:
The table below provides the split of the combined pension and other postretirement net periodic benefit costs among subsidiaries for the years ended December 31, in million of dollars:
The following weighted average assumptions were used to determine the benefit obligations at December 31:
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Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects, in millions of dollars:
The following weighted average assumptions were used to determine the net periodic benefit cost for the years ended December 31:
The discount rate is developed using a cash flow matched bond portfolio approach to value liabilities. A hypothetical bond portfolio is created comprised of high quality fixed income securities with cash flows and maturities that mirror the expected benefit payments to be made under the plans.
In selecting an expected rate of return on plan assets, PHI considers actual historical returns, economic forecasts and the judgment of its investment consultants on expected long-term performance for the types of investments held by the plan. The plan assets consist of equity, fixed income investments, real estate and private equity and, when viewed over a long-term horizon, are expected to yield a return on assets of 8.25%.
In 2008, PHI and its actuaries conducted an experience study, a periodic analysis of plan experience against actuarial assumptions. The study reviewed withdrawal, retirement and salary increase assumptions. As a result of the study, assumed retirement rates were changed and the age-related salary scale assumption was increased from an average over an employee’s career of 4.50% to 5.00%. No changes were made in the 2009 valuation.
In addition, for the 2008 Other Postretirement Benefit Plan valuation, the medical trend rate was changed to 8.5%, declining .5% per year to 5.00% in 2015 and beyond, from the 2007 valuation assumption for 2008 of 7%, declining 1% per year to 5% in 2010 and beyond. No changes were made for the 2009 valuation.
Plan Assets
Investment Policies and Strategies
The goal of PHI’s investment policy is to preserve capital and maximize investment earnings in excess of inflation within acceptable levels of volatility to meet the actuarial projected liabilities of the benefit plans. To accomplish this goal, PHI actively manages its plan assets with the objective of optimizing long-term returns while maintaining a high standard of portfolio quality and proper diversification.
In developing its allocation policy for the assets in the PHI Retirement Plan and the other postretirement plan, PHI examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, PHI evaluated the risk return tradeoffs of alternative asset classes and asset mixes given long-term historical relationships as well as prospective capital market returns. PHI also conducted an asset liability study to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. PHI developed its asset mix guidelines by incorporating the results of these analyses with an assessment of its risk posture, and taking into account industry practices.
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Under these guidelines, PHI diversifies assets in order to protect against large investment losses and to reduce the probability of excessive volatility while earning a return that is commensurate with an acceptable risk level. Assets are diversified by allocating investments to various asset classes and investment styles within those asset classes and by retaining investment management firms with complementary investment styles and approaches.
Based on the assessment of employee demographics, actuarial funding, and PHI’s business and financial circumstances, PHI believes that its risk posture is slightly below average relative to other pension plans. Consequently, PHI believes that a slightly below average equity exposure (i.e., a target equity asset allocation of 60%) is appropriate for the PHI Retirement Plan and other postretirement plan. On a periodic basis, PHI reviews its asset mix and rebalances assets back to the target allocation over a reasonable period of time.
The PHI Retirement Plan asset allocations at December 31, 2009 and 2008, by asset category, were as follows:
PHI’s other postretirement plan asset allocations at December 31, 2009 and 2008, by asset category, were as follows:
Risk Management and General Investment Manager Guidelines
Plan assets may be invested in separately managed accounts in which there is ownership of individual securities, shares of commingled funds or mutual funds, or limited partnerships. Commingled funds and mutual funds are subject to detailed policy guidelines set forth in the fund’s prospectus or fund declaration, and limited partnerships are subject to the terms of the partnership agreement.
Separate account investment managers are responsible for achieving a level of diversification in their portfolio that is consistent with their investment approach and their role in PHI’s overall investment structure. Separate account investment managers must follow risk management guidelines established by PHI unless authorized otherwise in writing by PHI.
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For equity managers, the maximum position in a single issuer’s securities should not exceed 5% of the portfolio’s cost or 8% of the portfolio’s market value. The holdings in any one industry should not exceed 25% of the portfolio’s market value, and the holdings in any one economic sector should not exceed 40% of the portfolio’s market value. International equity managers shall not invest more than 25% of the portfolio’s market value in emerging markets and no more than 50% in any single country. Market and currency hedges are limited to defensive purposes.
For fixed income managers, the maximum position in a single issuer’s securities should not exceed 5% of the portfolio’s market value, with the exception of US Treasury or US Government agencies and instrumentalities. The investment manager is expected to maintain a weighted average bond portfolio quality rating of at least “A.” The manager may invest up to 20% of the portfolio’s market value in bonds rated below investment grade. A manager may invest in non-dollar securities up to 20% of the portfolio’s market value, and currency hedging is allowed if it is a normal approach to international fixed income management. No more than 30% of the portfolio’s market value can be invested in combined non-dollar and below investment grade securities.
Derivative instruments are permissible in an investment portfolio to the extent they comply with policy guidelines and are consistent with risk and return objectives. Under no circumstances may such instruments be used speculatively or to leverage the portfolio. PHI common stock is not a permitted plan asset.
Fair Value of Plan Assets
Effective January 1, 2008, PHI adopted FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and disclosing information about fair value measurements.
As defined in the FASB guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The FASB’s fair value framework includes a hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurements). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument. Investments are classified as follows in the fair value hierarchy:
•
Level 1: Investments are valued using quoted prices in active markets for identical investments.
•
Level 2: Investments are valued using other significant observable inputs (e.g., quoted prices for similar investments, interest rates, credit risks, etc).
•
Level 3: Investments are valued using significant unobservable inputs, including internal assumptions.
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The following table presents the fair values of PHI’s Retirement Plan and other postretirement plan assets by asset category, as of December 31, 2009:
(a) Includes predominantly domestic common and preferred stock, warrants and commingled funds.
(b) Includes predominantly foreign common and preferred stock.
(c) Predominantly includes corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations, asset backed securities, commingled funds and guaranteed investment contracts.
(d) Cash and cash equivalents includes $21 million held in equity accounts and $2 million held in fixed income accounts.
(e) Includes domestic and international commingled funds.
(f) Includes fixed income commingled funds.
There were no significant concentrations of risk in pension and other postretirement plan assets at December 31, 2009.
Valuation Techniques Used to Determine Fair Value
Equity
Equity securities were primarily comprised of securities issued by public companies in domestic and foreign markets plus investments in commingled funds, all of which are valued on a daily basis. PHI can exchange shares of the publicly traded securities and their fair values are primarily sourced from their closing prices on stock exchanges where there is active trading, therefore they would be classified as Level 1 in the fair value measurement hierarchy. If there is less active trading, then the publicly traded securities would typically be priced using observable data, such as bid ask prices, and these measurements would be classified as Level 2 in the fair value measurement hierarchy.
The fair values of PHI’s interests in commingled funds are based on the Net Asset Value (NAV). These funds have ongoing subscription and redemption activities. Commingled funds with publicly quoted NAV and active trading are classified as Level 1 investments. Commingled funds with less active trading are classified as Level 2 in the fair value measurement hierarchy because the NAV of these funds is based on the quoted prices of underlying securities.
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Fixed Income
Fixed income investments are primarily fixed income securities and fixed income commingled funds. The prices for direct investments in fixed income securities are generated on a daily basis. Like the equity securities, fair values generated from active trading on exchanges are classified as Level 1 in the fair value measurement hierarchy. Prices generated from less active trading with wider bid ask prices are classified as Level 2 in the fair value measurement hierarchy. If prices are based on uncorroborated and unobservable inputs, then the investments are classified as Level 3.
The fair values of PHI’s interests in commingled funds are based on the NAV. These funds have ongoing subscription and redemption activities. Commingled funds with publicly quoted NAV and active trading are classified as Level 1 investments. Commingled funds with less active trading are classified as Level 2 in the fair value measurement hierarchy because the NAV of these funds is based on the quoted prices of underlying securities.
Other - Private Equity and Real Estate
Investments in private equity and real estate funds primarily invest in privately held real estate investment properties, trusts, and partnerships as well as equity and debt issued by public or private companies. PHI’s interest in the fund or partnership is valued at the net asset value. PHI’s interest in these funds cannot be readily redeemed due to the inherent lack of liquidity and the primarily long-term nature of the underlying assets. Distribution is made through the liquidation of the underlying assets. PHI views these investments as part of a long-term investment strategy. These investments are valued by each investment manager based on the underlying assets. The majority of the underlying assets are valued using significant unobservable inputs and often require significant management judgment or estimation based on best available information. Market data includes observations of the trading multiples of public companies considered comparable to the private companies being valued. The funds utilize valuation techniques consistent with the market, income, and cost approach to measure fair value. As a result, PHI classifies the measurement of these investments as Level 3 in the fair value measurement hierarchy.
The investments in private equity and real estate funds require capital commitments, which may be called over a specific number of years. Unfunded capital commitments as of December 31, 2009 totaled $26 million.
A reconciliation of the beginning and ending balance of PHI’s fair value measurements using significant unobservable inputs (Level 3) for investments in the pension plan is shown below:
Cash Flows
Contributions - PHI Retirement Plan
PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the funding target level under the Pension Protection Act of 2006. During 2009, discretionary tax-deductible contributions totaling $300 million were made to the PHI Retirement Plan, which brought plan assets to at least the funding target level for 2009 under the Pension Protection Act. Of this amount, $240
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million consisted of tax-deductible contributions made by Pepco, ACE and DPL in the amounts of $170 million, $60 million and $10 million, respectively. The remaining $60 million consisted of tax-deductible contributions made by the PHI Service Company. No contributions were made in 2008.
Although PHI projects there will be no quarterly minimum funding requirements under the Pension Protection Act guidelines in 2010, PHI currently plans to make a discretionary tax-deductible contribution of approximately $100 million to bring its plan assets to at least the funding target level for 2010 under the Pension Protection Act.
Contributions - Other Postretirement Benefits
In 2009 and 2008, Pepco contributed $8 million and $9 million, respectively, DPL contributed $10 million and $9 million, respectively, and ACE contributed $6 million and $7 million, respectively, to the other postretirement benefit plan. In 2009 and 2008, contributions of $16 million and $14 million, respectively, were made by other PHI subsidiaries. Assuming no changes to the other postretirement benefit pension plan assumptions, PHI expects similar amounts to be contributed in 2010.
Expected Benefit Payments
Estimated future benefit payments to participants in PHI’s pension and other postretirement welfare benefit plans, which reflect expected future service as appropriate, are as follows (millions of dollars):
Medicare Prescription Drug Improvement and Modernization Act of 2003
On December 8, 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Medicare Act) became effective. The Medicare Act introduced a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Pepco Holdings sponsors postretirement health care plans that provide prescription drug benefits that PHI plan actuaries have determined are actuarially equivalent to Medicare Part D. At December 31, 2009, the estimated reduction in accumulated postretirement benefit obligation is $27 million. In 2009 and 2008, Pepco Holdings received $3 million and $2 million, respectively, in federal Medicare prescription drug subsidies.
Pepco Holdings Retirement Savings Plan
Pepco Holdings has a defined contribution retirement savings plan. Participation in the plan is voluntary. All participants are 100% vested and have a nonforfeitable interest in their own contributions and in the Pepco Holdings company matching contributions, including any earnings or losses thereon. Pepco Holdings’ matching contributions were $12 million, $12 million, and $11 million for the years ended December 31, 2009, 2008, and 2007, respectively.
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(11) DEBT
Long-Term Debt
The components of long-term debt are shown below.
(a) Represents a series of First Mortgage Bonds issued by the indicated company (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued for the benefit of the company. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligations in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes and tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.
(b) Represents a series of Collateral First Mortgage Bonds issued by the indicated company that will, at such time as there are no First Mortgage Bonds of the issuing company outstanding (other than Collateral First Mortgage Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.
(c) In September 2009, DPL issued Collateral First Mortgage Bonds to secure its reimbursement obligations under a bond insurance policy insuring the principal and interest payments on this series of tax-exempt bonds previously issued for the benefit of DPL. Because this series of tax-exempt bonds and the related series of Collateral First Mortgage Bonds effectively represents a single financial obligation, the tax-exempt bonds are no longer shown as outstanding on the table and instead the debt obligation is represented by the related series of Collateral First Mortgage Bonds.
(d) The bonds are subject to mandatory tender on July 1, 2010.
(e) The bonds are subject to mandatory tender on May 1, 2011.
NOTE: Schedule is continued on next page.
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(f) In September 2009, DPL issued Collateral First Mortgage Bonds to secure its reimbursement obligations under a bond insurance policy insuring the principal and interest payments on this series of notes previously issued by DPL. Because this series of notes and the related series of Collateral First Mortgage Bonds effectively represent a single financial obligation, the notes are no longer shown as outstanding on the table and instead the debt obligation is represented by the related series of Collateral First Mortgage Bonds.
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The outstanding First Mortgage Bonds issued by each of Pepco, DPL and ACE are subject to a lien on substantially all of the issuing company’s property, plant and equipment.
ACE Funding was established in 2001 solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds 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 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.
The aggregate amounts of maturities for long-term debt and Transition Bonds outstanding at December 31, 2009, are $533 million in 2010, $70 million in 2011, $787 million in 2012, $558 million in 2013, $334 million in 2014, and $3,103 million thereafter.
PHI’s long-term debt is subject to certain covenants. PHI and its subsidiaries are in compliance with all requirements.
Long-Term Project Funding
As of December 31, 2009 and 2008, Pepco Energy Services had outstanding total long-term project funding (including current maturities) of $20 million and $21 million, respectively, related to energy savings contracts performed by Pepco Energy Services. The aggregate amounts of maturities for the project funding debt outstanding at December 31, 2009, are $3 million for 2010, $2 million for each year 2011 through 2014, and $9 million thereafter.
Short-Term Debt
Pepco Holdings and its regulated utility subsidiaries have traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. A detail of the components of Pepco Holdings’ short-term debt at December 31, 2009 and 2008 is as follows:
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Commercial Paper
Pepco Holdings maintains an ongoing commercial paper program of up to $875 million. Pepco, DPL, and ACE have ongoing commercial paper programs of up to $500 million, $500 million, and $250 million, respectively. The commercial paper programs of each of PHI, Pepco, DPL and ACE are backed by that company’s borrowing capacity under the $1.9 billion in credit facilities, which are described under the heading “Credit Facilities” below.
Pepco Holdings and ACE had $324 million and $60 million, respectively, of commercial paper outstanding at December 31, 2009. Pepco did not issue any commercial paper during 2009, and DPL had no commercial paper outstanding at December 31, 2009. The weighted average interest rate for Pepco Holdings, DPL and ACE commercial paper issued during 2009 was 1.35%, 0.56% and 0.63%, respectively. The weighted average maturity for Pepco Holdings, DPL and ACE was 11, 5, and 8 days, respectively, for all commercial paper issued during 2009.
Variable Rate Demand Bonds
Variable Rate Demand Bonds (VRDB) are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. PHI expects that the bonds submitted for purchase will be remarketed successfully due to the credit worthiness of the issuing company and because the remarketing resets the interest rate to the then-current market rate. The issuing company also may utilize one of the fixed rate fixed term conversion options of the bonds to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. The VRDBs outstanding at December 31, 2009 mature as follows: 2014 to 2017 ($49 million), 2024 ($33 million) and 2028 to 2031 ($64 million). The weighted average interest rate for VRDB was 1.44% during 2009 and 3.10% during 2008. Of the $146 million in VRDB, $72 million are secured by Collateral First Mortgage Bonds issued by DPL, the issuer of the VRDB.
In June 2009, ACE completed the remarketing of $23 million in VRDBs that are supported by letters of credit issued by The Bank of New York Mellon. The letter of credit will expire on June 23, 2010, unless extended. The expiration, cancellation, or termination of a letter of credit prior to the maturity of the related VRDBs will require ACE to repurchase the VRDBs.
Credit Facilities
PHI, Pepco, DPL and ACE maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under this credit facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million. The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate and the federal funds effective rate plus 0.5% or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. The facility also includes a “swingline loan sub-facility” pursuant to which each company may make same day borrowings in an aggregate amount not to exceed $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof.
The facility commitment expiration date is May 5, 2012, with each company having the right to elect to have 100% of the principal balance of the loans outstanding on the expiration date continued as non-revolving term loans for a period of one year from such expiration date.
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The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens.
The absence of a material adverse change in the borrower’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers.
In November 2008, PHI entered into a second unsecured credit facility in the amount of $400 million with a syndicate of nine lenders, which was amended and restated in October 2009, to extend the facility termination date to October 15, 2010. Under this facility, PHI may obtain revolving loans and swingline loans over the term of the facility. The facility does not provide for the issuance of letters of credit. The interest rate payable on funds borrowed under the facility is, at PHI’s election, based on either (a) the prevailing Eurodollar rate or (b) the highest of (i) the prevailing prime rate, (ii) the federal funds effective rate plus 0.5% or (iii) the one-month Eurodollar rate plus 1.0%, plus a margin that varies according to the credit rating of PHI. Under the swingline loan sub-facility, PHI may obtain loans for up to seven days in an aggregate principal amount which does not exceed 10% of the aggregate borrowing limit under the facility. In order to obtain loans under the facility, PHI must be in compliance with the same covenants and conditions that it is required to satisfy for utilization of the $1.5 billion credit facility. The absence of a material adverse change in PHI’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any ratings triggers.
The $1.5 billion credit facility and the $400 million credit facility are referred to herein collectively as PHI’s “primary credit facilities.” As of December 31, 2009, each borrower was in compliance with the covenants of each of the primary credit facilities.
In May 2009, PHI entered into a $50 million, 18-month bi-lateral credit agreement, which can only be used for the purpose of obtaining letters of credit. As of December 31, 2009, $29 million in letters of credit were outstanding under this agreement.
Collateral Requirements of the Competitive Energy Business
In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, is exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees: (i) has assumed by novation certain electricity purchase obligations of Pepco Energy Services in years 2009 through 2011
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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under several wholesale purchase contracts, and (ii) has agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any obligation to post collateral based on changes in electricity prices. As of December 31, 2009, approximately 17% of Pepco Energy Services’ wholesale electricity purchase obligations (measured in megawatt hours) were covered by this credit intermediation arrangement with MSCG. The fees in the amount of $25 million incurred by Pepco Energy Services in connection with the entry into this agreement are being amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of novation. For the year ended December 31, 2009, approximately $16 million of the fees have been amortized and reflected in interest expense.
In addition to Pepco Energy Services’ retail energy supply business, Conectiv Energy and Pepco Energy Services, in the ordinary course of business, enter into various other contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce their financial exposure to changes in the value of their assets and obligations due to energy price fluctuations. These contracts also typically have collateral requirements.
Depending on the contract terms, the collateral required to be posted by Pepco Energy Services and Conectiv Energy can be of varying forms, including cash and letters of credit. As of December 31, 2009, Pepco Energy Services and Conectiv Energy had posted net cash collateral of $123 million and $240 million, respectively, and letters of credit of $157 million and $22 million, respectively. At December 31, 2008, Pepco Energy Services and Conectiv Energy had posted net cash collateral of $125 million and $206 million, respectively, and letters of credit of $474 million and $84 million, respectively.
At December 31, 2009 and 2008, the amount of cash, plus borrowing capacity under the primary credit facilities available to meet the future liquidity needs of the Competitive Energy business totaled $820 million and $684 million, respectively.
(12) INCOME TAXES
PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement that was approved by the SEC in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.
The provision for consolidated income taxes, reconciliation of consolidated income tax rate, and components of consolidated deferred tax liabilities (assets) are shown below.
Provision for Consolidated Income Taxes
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
Reconciliation of Consolidated Income Tax Rate
During 2009, PHI received a refund of $6 million (after-tax) of state income taxes and established a state tax benefit carryforward of $7 million (after-tax), each related to a change in tax reporting for certain asset dispositions occurring in prior years.
During 2009, the IRS issued a Revenue Agent’s Report (RAR) for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to PHI’s deductions related to cross-border energy lease investments, the capitalization of overhead costs for tax purposes and the deductibility of certain casualty losses. PHI has appealed certain of the proposed adjustments and believes it has adequately reserved for the adjustments proposed in the RAR. See Note (17), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” for additional information.
During 2009, PHI also received a refund of taxes paid in prior years of approximately $138 million, a substantial portion of which is associated with PHI’s utility subsidiaries. The refund results from the carry back of a 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions made in 2009 (which were deductible for 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs.
During 2008, Pepco Holdings completed an analysis of its current and deferred income tax accounts and, as a result, recorded an $8 million net credit to income tax expense in 2008, which is primarily included in “Other, net” in the reconciliation provided above. In conjunction with the analysis, Pepco Holdings also identified a $1 million adjustment of its current and deferred income tax accounts that related to pre-acquisition tax contingencies associated with the Conectiv acquisition in 2002, which was recorded as an increase in goodwill. Also identified as part of the analysis were new uncertain tax positions under ASC 740 (primarily representing overpayments of income taxes in previously filed tax returns) that resulted in the recording of after-tax net interest income of $4 million, which is included as a reduction of income tax expense.
In addition, during 2008, Pepco Holdings recorded after-tax net interest income of $18 million under ASC 740 primarily related to the reversal of previously accrued interest payable resulting from tentative and final settlements, respectively, on the mixed service cost and like-kind exchange issues with the IRS, and a claim made with the IRS related to the tax reporting for fuel over- and under-recoveries. This amount was offset by $7 million in after-tax interest expense related to the change in assumptions regarding the estimated timing of the tax benefits on cross-border energy lease investments.
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate
Unrecognized tax benefits represent those tax benefits related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Unrecognized tax benefits at December 31, 2009 included $18 million that, if recognized, would lower the effective tax rate.
Interest and Penalties
PHI recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2009, 2008 and 2007, PHI recognized $5 million of interest income pre-tax ($3 million after-tax), $25 million of interest income pre-tax ($15 million after-tax), and $4 million of interest expense pre-tax ($2 million after-tax), respectively, as a component of income tax expense. As of December 31, 2009, 2008 and 2007, PHI had $13 million, $16 million and $31 million, respectively, of accrued interest payable related to effectively settled and uncertain tax positions.
Possible Changes to Unrecognized Tax Benefits
It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of PHI’s uncertain tax positions will significantly increase or decrease within the next 12 months. The possible settlement of the cross-border energy lease investments issue, the final resolution of the mixed service cost issue, or other federal or state audits could impact the balances significantly. At this time, other than the mixed service cost issue, an estimate of the range of reasonably possible outcomes cannot be determined. The unrecognized benefit related to the mixed service cost issue could decrease by $55 million within the next 12 months upon the final resolution of the tentative settlement with the IRS. See Note (17), “Commitments and Contingencies,” for additional information.
Tax Years Open to Examination
PHI’s federal income tax liabilities for Pepco legacy companies for all years through 2000, and for Conectiv legacy companies for all years through 1999, have been determined by the IRS, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where PHI files state income tax returns (District of Columbia, Maryland, Delaware, New Jersey, Pennsylvania and Virginia) are the same as for the federal returns.
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
Components of Consolidated Deferred Tax Liabilities (Assets)
The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to PHI’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet.
The Tax Reform Act of 1986 repealed the investment tax credit (ITC) for property placed in service after December 31, 1985, except for certain transition property. ITC previously earned on Pepco’s, DPL’s and ACE’s property continues to be amortized to income over the useful lives of the related property.
Resolution of Certain Internal Revenue Service Audit Matters
In 2006, PHI resolved certain, but not all, tax matters that were raised in IRS audits related to the 2001 and 2002 tax years. Adjustments recorded related to these resolved tax matters resulted in a $6 million increase in net income ($3 million for Power Delivery and $5 million for Other Non-Regulated, partially offset by an unfavorable $2 million impact in Corporate and Other). To the extent that the matters resolved related to tax contingencies from the Conectiv legacy companies that existed at the August 2002 merger date, in accordance with accounting rules, an additional adjustment of $9 million ($3 million related to Power Delivery and $6 million related to Other Non-Regulated) was recorded in Corporate and Other to eliminate the tax benefits recorded by Power Delivery and Other Non-Regulated against the goodwill balance that resulted from the merger. Also during 2006, the total favorable impact of $3 million was recorded that resulted from changes in estimates related to prior year tax liabilities subject to audit ($4 million for Power Delivery, partially offset by an unfavorable $1 million for Corporate and Other).
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below. The total amounts below include $358 million, $347 million and $348 million, for the years ended December 31, 2009, 2008 and 2007, respectively, related to the Power Delivery business, which are recoverable through rates.
(13) NONCONTROLLING INTEREST
The outstanding preferred stock issued by subsidiaries of PHI as of December 31, 2009 and 2008 consisted of the following series of serial preferred stock issued by ACE. The shares of each of the series are redeemable solely at the option of the issuer.
(14) STOCK-BASED COMPENSATION, DIVIDEND RESTRICTIONS, AND CALCULATIONS OF EARNINGS PER SHARE OF COMMON STOCK
Stock-Based Compensation
PHI maintains a Long-Term Incentive Plan (LTIP), the objective of which is to increase shareholder value by providing a long-term incentive to reward officers, key employees, and directors of Pepco Holdings and its subsidiaries and to increase the ownership of Pepco Holdings’ common stock by such individuals. Any officer or key employee of Pepco Holdings or its subsidiaries may be designated by the PHI board of directors as a participant in the LTIP. Under the LTIP, awards to officers and key employees may be in the form of restricted stock, stock options, performance units, stock appreciation rights, and dividend equivalents. At inception, 10 million shares of common stock were authorized for issuance under the LTIP.
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
Total stock-based compensation expense recorded in the Consolidated Statements of Income for the years ended December 31, 2009, 2008, and 2007 was as follows:
During 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the LTIP that resulted in an understatement of stock-based compensation expense in 2006 and 2007. This error was corrected in 2008, resulting in an increase in stock-based compensation expense for the year ended December 31, 2008 of $9 million.
No material amount of stock compensation expense was capitalized for the years ended December 31, 2009, 2008 and 2007.
Restricted Stock Awards
Description of awards
A number of programs have been established under the LTIP involving the issuance of Restricted Stock Awards, including awards of performance-based restricted stock units, time-based restricted stock, retention stock and the Conectiv performance accelerated restricted stock (PARS). A summary of each of these programs is as follows:
•
Under the performance-based restricted stock program, performance criteria are selected and measured over a three-year period. Depending on the extent to which the performance criteria are satisfied, the participants are eligible to earn shares of common stock and dividends accrued thereon over the vesting period, ranging from 0% to 200% of the target stock unit award opportunities, inclusive of dividends accrued.
•
Time-based restricted stock award opportunities have a requisite service period of three years and participants have the right to receive dividends on the shares.
•
In connection with the acquisition of Conectiv by Pepco in 2002, Conectiv PARS were converted to shares of Pepco Holdings restricted stock. These shares typically vested over 5 to 7 years. In January 2009, all 6,669 remaining shares outstanding fully vested.
•
In September 2007, retention awards in the form of 9,015 shares of restricted stock were granted to certain PHI executives, with vesting periods of two or three years. In September 2009, 5,409 of these shares vested.
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
Activity for the year
The 2009 activity for non-vested restricted stock and performance-based restricted stock unit awards is summarized below:
(a) Includes share activity under the Conectiv PARS and retention awards.
Grants included in the table above reflect 2009 grants of performance-based restricted stock units and time-based restricted stock. PHI recognizes compensation expense related to performance-based restricted stock awards and time-based restricted stock awards based on the fair value of the awards at date of grant. The fair value is based on the market value of PHI common stock at the date the award opportunity is granted. The following table provides the weighted average grant date fair value of those awards for each of the three years ended December 31, 2009:
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
As of December 31, 2009, there was approximately $5 million of unrecognized compensation cost (net of estimated forfeitures) related to non-vested stock and stock units granted under the LTIP. That cost is expected to be recognized over a weighted-average period of approximately two years.
Stock options
Non-qualified stock options to purchase shares of PHI’s common stock are granted under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of the option grant. Stock options granted under the LTIP generally become exercisable upon a specified vesting date. All stock options have an expiration date of ten years from the date of grant. No options have been granted since May 1, 2002.
Non-employee directors are entitled, under the terms of the LTIP, to a grant on May 1 of each year of a nonqualified stock option for 1,000 shares of common stock. However, the Board of Directors has determined that these grants will not be made.
Stock option activity for the year ended December 31, 2009 is summarized below:
(a) Range of exercise prices is $13.08 to $29.78
The following table summarizes additional information regarding stock options for the years ended December 31, 2009, 2008 and 2007:
Directors’ Deferred Compensation
Under the Pepco Holdings’ Executive and Director Deferred Compensation Plan, Pepco Holdings directors may elect to defer all or part of their retainer or meeting fees that constitute normal compensation. Deferred retainer or meeting fees can be invested in phantom Pepco Holdings shares and receive accruals equal to the dividends paid on the corresponding number of shares of Pepco Holdings common stock. The phantom share account balances are settled in cash. The amount deferred and invested in phantom Pepco Holdings shares in the years ended December 31, 2009, 2008 and 2007 was not material.
Compensation expense recognized in respect of dividends and increase in fair value in the years ended December 31, 2009, 2008 and 2007 was not material. The balance of deferred compensation invested in phantom Pepco Holdings’ shares was approximately $1 million at December 31, 2009 and 2008.
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
Dividend Restrictions
PHI, on a stand-alone basis, generates no operating income of its own. Accordingly, its ability to pay dividends to its shareholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of PHI’s direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and, in the case of ACE, the regulatory requirement that it obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by the subsidiaries, and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Pepco and DPL have no shares of preferred stock outstanding. Currently, the capitalization ratio limitation to which ACE is subject and the restriction in the ACE charter do not limit ACE’s ability to pay common stock dividends.
For the years ended December 31, Pepco Holdings received dividends from its subsidiaries as follows:
Calculations of Earnings per Share of Common Stock
The numerator and denominator for basic and diluted earnings per share of common stock calculations are shown below.
Shareholder Dividend Reinvestment Plan
PHI maintains a Shareholder Dividend Reinvestment Plan through which shareholders may reinvest cash dividends and both existing shareholders and new investors can make purchases of shares of PHI common stock through the investment of not less than $25 each calendar month nor more than $200,000 each calendar year. Shares of common stock purchased through the DRP may be new shares or, at the election of PHI, shares purchased in the open market. Approximately 2 million new shares were issued and sold under the DRP in 2009, and approximately 1 million in each of 2008 and 2007.
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
Pepco Holdings Common Stock Reserved and Unissued
The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2009:
(a) No further awards will be made under this plan.
(15) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
PHI’s Competitive Energy business uses derivative instruments primarily to reduce its financial exposure to changes in the value of its 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. The Competitive Energy business also manages commodity risk with contracts that are not classified or accounted for as derivatives. The two primary risk management objectives are: (i) to manage the spread between the cost of fuel used to operate electric generating facilities and the revenue received from the sale of the power produced by those facilities, and (ii) 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.
Conectiv Energy purchases energy commodity contracts in the form of futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas, oil and coal to fuel its generation assets and for sale to customers. Conectiv Energy also purchases energy commodity contracts in the form of electricity swaps, options and forward contracts to hedge price risk in connection with the purchase of electricity for delivery to requirements-load customers. Conectiv Energy sells electricity swaps, options and forward contracts to hedge price risk in connection with electric output from its generation fleet. Conectiv Energy accounts for most of its futures, swaps and certain forward contracts as cash flow hedges of forecasted transactions. Derivative contracts purchased or sold in excess of probable amounts of forecasted hedge transactions are marked-to-market through current earnings. All option contracts are marked-to-market through current earnings. Certain natural gas and oil futures and swaps are used as fair value hedges to protect the value of natural gas transportation contracts and physical fuel inventory. Some forward contracts are accounted for using standard accrual accounting because these contracts meet the requirements for normal purchase and normal sale accounting.
Pepco Energy Services purchases energy commodity contracts in the form of electric and natural gas futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for delivery to customers. Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of forecasted transactions. Certain commodity contracts that do not qualify as cash flow hedges of forecasted transactions or do not meet the requirements for normal purchase and normal sale accounting are marked-to-market through current earnings. Forward contracts are accounted for using standard accrual accounting because these contracts meet the requirements for normal purchase and normal sale accounting.
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
In the Power Delivery business, DPL uses derivative instruments in the form of forward contracts, futures, swaps, and exchange-traded and over-the-counter options primarily to reduce gas commodity price volatility and limit its customers’ exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that are not classified as derivatives. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered through a fuel adjustment clause approved by the DPSC.
PHI and its subsidiaries also use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt incurred in connection with the operation of their businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in July 2002. Upon issuance of the fixed-rate debt, the rate locks were terminated at a loss. The loss has been deferred in accumulated other comprehensive (loss) income and is being recognized in income over the life of the debt issued.
The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2009 and 2008:
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), PHI offsets the fair value amounts recognized for derivative instruments and the fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. The amount of cash collateral that was offset against these derivative positions is as follows:
(a) Includes cash deposits on commodity brokerage accounts
As of December 31, 2009 and 2008, PHI had no cash collateral pledged or received related to derivative instruments accounted for at fair value that it was not entitled to be offset under master netting agreements.
Cash Flow Hedges
Competitive Energy
For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive (loss) income (AOCL) and is reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current income. This information for the activity during the years ended December 31, 2009, 2008 and 2007 is provided in the tables below:
(a) Included in the $345 million loss for the year ended December 31, 2009, is a $3 million loss realized on the derivative transaction but not yet recognized into income. Included in the $315 million loss for the year ended December 31, 2008, is a $2 million gain realized on the derivative transaction but not yet recognized into income. Included in the $9 million loss for the year ended December 31, 2007, is a $9 million loss realized on the derivative transaction but not yet recognized into income.
(b) Included in the above table is a loss of $5 million, $1 million and $2 million for the years ended December 31, 2009, 2008 and 2007, respectively, which was reclassified from AOCL to income because the forecasted hedged transactions were deemed no longer probable.
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
As of December 31, 2009 and 2008, PHI’s Competitive Energy business had the following types and volumes of energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.
Power Delivery
As described above, all premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered through a fuel adjustment clause approved by the DPSC. The following table indicates the amounts deferred as regulatory assets or liabilities and the location in the consolidated statements of income of amounts reclassified to income through the fuel adjustment clause for the years ended December 31, 2009 and 2008:
As of December 31, 2009 and 2008, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
The tables below provide details regarding effective cash flow hedges included in PHI’s consolidated balance sheet as of December 31, 2009 and 2008. Cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to AOCL. The data in the tables indicate the cumulative net gain (loss) after-tax related to effective cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:
(a) Accumulated Other Comprehensive Loss on PHI’s consolidated balance sheet as of December 31, 2009, includes a $17 million balance related to minimum pension liability. This balance is not included in this table as it is not a cash flow hedge.
(b) The large unrealized derivative losses recorded in Accumulated Other Comprehensive Loss are largely offset by wholesale and retail load service sales contracts in gain positions that are subject to accrual accounting. These forward sales contracts to commercial and industrial customers, utilities, municipalities, and electric cooperatives are exempted from mark-to-market accounting because they either qualify as normal sales under FASB guidance on derivatives and hedging, or they are not derivative contracts at all. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and revenue is not recognized until the period of delivery.
(a) Accumulated Other Comprehensive Loss on PHI’s consolidated balance sheet as of December 31, 2008, includes a $10 million balance related to minimum pension liability. This balance is not included in this table as it is not a cash flow hedge.
(b) The large unrealized derivative losses recorded in Accumulated Other Comprehensive Loss are largely offset by wholesale and retail load service sales contracts in gain positions that are subject to accrual accounting. These forward sales contracts to commercial and industrial customers, utilities, municipalities, and electric cooperatives are exempted from mark-to-market accounting because they either qualify as normal sales under FASB guidance on derivatives and hedging, or they are not derivative contracts at all. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and revenue is not recognized until the period of delivery.
Fair Value Hedges
In connection with its energy commodity activities, the Competitive Energy business designates certain derivatives as fair value hedges. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk is recognized in current income. For the years ended December 31, 2009 and 2008, the amounts of the derivative net gain (loss) on energy commodity contracts recognized for hedges, by consolidated statements of income line item, are as follows:
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
As of December 31, 2009 and 2008, PHI’s Competitive Energy business had the following outstanding commodity forward contract volumes and net position on derivatives that were accounted for as fair value hedges of fuel inventory and natural gas transportation:
Other Derivative Activity
Competitive Energy Business
In connection with its energy commodity activities, the Competitive Energy business holds certain derivatives that do not qualify as hedges. Under FASB guidance on derivatives and hedging, these derivatives are recorded at fair value through income with corresponding adjustments on the balance sheet.
For the years ended December 31, 2009, 2008 and 2007, the amounts of the derivative gain (loss) for the Competitive Energy business recognized in income are provided in the table below:
As of December 31, 2009 and 2008, PHI’s Competitive Energy business had the following net outstanding commodity forward contract volumes and net position on derivatives that did not qualify for hedge accounting:
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
Power Delivery
DPL holds certain derivatives that do not qualify as hedges. These derivatives are recorded at fair value on the balance sheet with the gain or loss recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred. For the years ended December 31, 2009 and 2008, the amounts of the derivative gain (loss) recognized by line item in the consolidated statements of income are provided in the table below:
As of December 31, 2009 and 2008, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:
Contingent Credit Risk Features
The primary contracts used by the Competitive Energy and Power Delivery businesses for derivative transactions are entered into under an International Swaps and Derivatives Association Master Agreement (ISDA) or similar agreements that closely mirror the principal credit provisions of the ISDA. The ISDAs include a Credit Support Annex (CSA) that governs the mutual posting and administration of collateral security. The failure of a party to comply with an obligation under the CSA, including an obligation to transfer collateral security when due or the failure to maintain any required credit support, constitutes an event of default under the ISDA for which the other party may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.
The collateral requirements under the ISDA or similar agreements generally work as follows. The parties establish a dollar threshold of unsecured credit for each party in excess of which the party is required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold generally varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on the balance sheet or normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions is a net loss position that exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of the Competitive Energy business typically are guaranteed by PHI. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If PHI’s or DPL’s credit rating were to fall below “investment grade,” the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PEPCO HOLDINGS, INC.
The gross fair value of PHI’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on December 31, 2009, was $287 million. As of that date, PHI had posted cash collateral of $23 million in the normal course of business against the gross derivative liability resulting in a net liability of $264 million before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. PHI’s net settlement amount in the event of a downgrade of PHI and DPL below “investment grade” as of December 31, 2009, would have been approximately $246 million after taking into consideration the master netting agreements. The offsetting transactions or collateral that would reduce PHI’s obligation to the net settlement amount include derivatives and normal purchase and normal sale contracts in a gain position as well as letters of credit already posted as collateral.
PHI’s primary sources for posting cash collateral or letters of credit are its primary credit facilities. At December 31, 2009, the aggregate amount of cash plus borrowing capacity under the credit facilities available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $1.4 billion, of which $820 million was available for the Competitive Energy business.
(16) FAIR VALUE DISCLOSURES
Fair Value of Assets and Liabilities Excluding Debt
Effective January 1, 2008, PHI adopted FASB guidance on fair value measurement and disclosures (ASC 820) which established a framework for measuring fair value and expanded disclosures about fair value measurements.
As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). PHI utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, PHI utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. PHI is able to classify fair value balances based on the observability of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets, and other observable pricing data. Level 2 also includes those financial instruments that are valued using internally developed methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 - Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies. Level 3 instruments classified as derivative assets are primarily power and capacity swaps. The majority of Conectiv Energy’s pricing information for its level 3 valuations was obtained from a third party pricing system used widely throughout the energy industry.
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Level 3 instruments classified as derivative liabilities also include natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC. Some non-standard assumptions are used in their forward valuation to adjust for the pricing; otherwise, most of the options follow NYMEX valuation. A few of the options have no significant NYMEX components, and have to be priced using internal volatility assumptions.
Level 3 instruments classified as executive deferred compensation plan assets and liabilities consist of life insurance policies that are valued using the cash surrender value of the policies which does not represent a quoted price in an active market.
The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009 and 2008. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
(a) Includes a contra-liability balance of $6 million related to the impact of netting certain counterparties across the levels of the fair value hierarchy.
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Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2009 and 2008 are shown below:
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Fair Value of Debt Instruments
The estimated fair values of PHI’s non-derivative financial instruments at December 31, 2009 and 2008 are shown below:
The methods and assumptions described below were used to estimate, as of December 31, 2009 and 2008, the fair value of each class of non-derivative financial instruments shown above for which it is practicable to estimate a value.
The fair value of Long-Term Debt issued by PHI and its utility subsidiaries was based on actual trade prices as of December 31, 2009 and 2008, or bid prices obtained from brokers if actual trade prices were not available. The fair values of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on bid prices obtained from brokers if actual trade prices were not available or were based on discounted cash flows using current rates for similar issues with similar credit ratings, terms, and remaining maturities for issues with no market price available.
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The fair value of the Redeemable Serial Preferred Stock, excluding amounts due within one year, was derived based on quoted market prices or discounted cash flows using current rates for preferred stock with similar terms.
The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.
(17) COMMITMENTS AND CONTINGENCIES
Regulatory and Other Matters
Proceeds from Settlement of Mirant Bankruptcy Claims
In 2000, Pepco sold substantially all of its electricity generating assets to Mirant. As part of the sale, Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco was obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco was obligated to pay to Panda. In 2003, Mirant commenced a voluntary bankruptcy proceeding in which it sought to reject certain obligations that it had undertaken in connection with the asset sale. As part of the settlement of Pepco’s claims against Mirant arising from the bankruptcy, Pepco agreed not to contest the rejection by Mirant of its obligations under the “back-to-back” arrangement in exchange for the payment by Mirant of damages corresponding to the estimated amount by which the purchase price that Pepco was obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $414 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. In September 2008, Pepco transferred the Panda PPA to Sempra, along with a payment to Sempra, thereby terminating all further rights, obligations and liabilities of Pepco under the Panda PPA. In November 2008, Pepco filed with the DCPSC and the MPSC proposals to share with customers the remaining balance of proceeds from the Mirant settlement in accordance with divestiture sharing formulas approved previously by the respective commissions.
In March 2009, the DCPSC issued an order approving Pepco’s sharing proposal for the District of Columbia under which approximately $24 million was distributed to District of Columbia customers as a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of approximately $14 million for the quarter ended March 31, 2009.
On July 2, 2009, the MPSC approved a settlement agreement among Pepco, the Maryland Office of People’s Counsel and the MPSC staff under which Pepco distributed approximately $38 million to Maryland customers during the billing month of August 2009 through a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of $26 million in the quarter ended September 30, 2009.
As a consequence of the MPSC order, $64 million previously accounted for as restricted cash was released and the corresponding regulatory liability was extinguished.
Rate Proceedings
In recent electric service distribution base rate cases, PHI’s utility subsidiaries have proposed the adoption of revenue decoupling methods for retail customers. To date:
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A BSA has been approved and implemented for both Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia.
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A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric service in Delaware and may be implemented in DPL’s pending electric base rate case.
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•
A MFVRD has been approved in concept for DPL natural gas service in Delaware and may be implemented either in the context of a pending decoupling case or DPL’s next Delaware natural gas distribution base rate case
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A proposed BSA remains pending for ACE in New Jersey.
Under the BSA, customer delivery rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The BSA increases rates if actual distribution revenues fall below the approved level and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, the utility collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” distribution revenue from unit sales consumption and ties the growth in distribution revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for the regulated utilities to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and distribution revenues. The MFVRD adopted in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, PHI views the MFVRD as an appropriate distribution revenue decoupling mechanism.
Delaware
In August 2008, DPL submitted its 2008 GCR filing to the DPSC, requesting an increase in the level of GCR, which permits DPL to recover gas procurement costs through customer rates. In September 2008, the DPSC issued an initial order approving the requested increase, which became effective on November 1, 2008, subject to refund pending final DPSC approval after evidentiary hearings. Due to a significant decrease in wholesale gas prices, DPL in January 2009 submitted to the DPSC an interim GCR filing, requesting a decrease in the level of GCR. The proposed decrease became effective on a temporary basis on March 1, 2009, and when combined with the increase that became effective November 1, 2008, had the net effect of a 13.8% increase in the level of GCR. On October 6, 2009, the DPSC issued a final order approving the 13.8% net increase, reflecting a settlement agreement among DPL, the DPSC staff and the Delaware Public Advocate.
On August 31, 2009, DPL submitted its 2009 GCR filing to the DPSC, requesting a 10.2% decrease in the level of GCR, to become effective on a temporary basis on November 1, 2009. This rate proposal was approved by the DPSC on September 9, 2009, subject to refund and pending final DPSC approval.
On September 18, 2009, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $28 million, assuming approval of the implementation of the MFVRD, based on a requested return on equity (ROE) of 10.75% (if implementation of the MFVRD is not approved, the increase would be $29 million, based on an ROE of 11.00%). DPL placed an increase of approximately $2.5 million annually into effect on a temporary basis on November 17, 2009, subject to refund and pending final DPSC approval of the entirety of the requested increase. As permitted by Delaware law, DPL currently anticipates that it will place the remaining $25.5 million of the requested increase into effect on April 19, 2010, subject to refund and pending the final DPSC order. The DPSC has established a procedural schedule that provides for hearings in April 2010 and a DPSC decision in July 2010.
On June 25, 2009, DPL filed an application requesting approval for the implementation of the MFVRD for gas distribution rates. This filing is based on revenues established in DPL’s last gas distribution base rate case, and accordingly is revenue neutral. On August 4, 2009, the DPSC issued an order opening a docket for the matter. A similar application on June 25, 2009 requesting approval for the implementation of the MFVRD for electric distribution rates has been consolidated with the electric distribution base rate proceeding discussed above.
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District of Columbia
In January 2008, the DCPSC approved, effective February 20, 2008, a revenue requirement increase for Pepco of approximately $28 million, based on an authorized return on rate base of 7.96%, including a 10% ROE. In June 2008, the District of Columbia Office of People’s Counsel (the DC OPC), citing alleged errors by the DCPSC, filed with the DCPSC a motion for reconsideration of the order, which was denied by the DCPSC. In August 2008, the DC OPC filed with the District of Columbia Court of Appeals a petition for review of the DCPSC’s order denying its motion for reconsideration. Briefs have been filed by the parties and oral argument was held on March 23, 2009. On February 18, 2010, the Court of Appeals issued its decision affirming the decision of the DCPSC.
On May 22, 2009, Pepco submitted an application to the DCPSC to increase electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $50 million with the BSA, based on a requested ROE of 11.25% (subsequently revised by Pepco to 10.75%). The filing also proposes recovery of pension expenses and uncollectible costs through a surcharge mechanism. If the proposed surcharge mechanism is approved, the annual rate increase requested would be reduced by approximately $3 million. Evidentiary hearings were held in mid-November 2009 and a decision is expected from the DCPSC in early 2010.
Maryland
On May 6, 2009, DPL filed an electric distribution base rate case in Maryland. The filing sought approval of an annual rate increase of approximately $14 million, based on a requested ROE of 11.25%. On December 2, 2009, the MPSC approved an annual increase of approximately $7.5 million, based on an overall rate of return of 7.96%, including an ROE of 10%. The MPSC rejected a proposed surcharge mechanism for pension, OPEB and uncollectible expenses. The rate increase was implemented through rates that are effective for electric usage on and after December 2, 2009.
On December 30, 2009, Pepco filed an electric distribution base rate case in Maryland. The filing seeks approval of an annual rate increase of approximately $40 million, based on a requested ROE of 10.75%. A decision by the MPSC is expected by the end of July, 2010.
New Jersey
On August 14, 2009, ACE submitted a petition to the NJBPU to increase its electric distribution base rates, including a request for the implementation of a BSA. Based on a test year ending December 31, 2009, adjusted for known and measurable changes, ACE requested an annual net increase in its current retail distribution rates for electric service in the amount of approximately $54 million (which includes a reduction to its Regulatory Asset Recovery Charge) based on a requested ROE of 11.50% (or an increase of approximately $52 million, based on an ROE of 11.25%, if the BSA is approved). Hearings are scheduled for late May and June 2010.
District of Columbia Divestiture Case
In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets. An unresolved issue relating to the application filed with the DCPSC by Pepco to implement the divestiture settlement is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) 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. As of December 31, 2009, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6 million each.
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Pepco believes that a sharing of EDIT and ADITC with its District of Columbia customers would violate the IRS normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned by Pepco, there is no book life over which the EDIT and ADITC can be returned. If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property. Also, in addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco’s District of Columbia jurisdictional generation-related ADITC balance ($6 million as of December 31, 2009), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of December 31, 2009), in each case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.
In March 2008, the IRS approved final regulations, effective March 20, 2008, which allow utilities whose assets cease to be utility property (whether by disposition, deregulation or otherwise) to return to its utility customers the normalization reserve for EDIT and part or all of the normalization reserve for ADITC. This ruling applies to assets divested after December 21, 2005. For utility property divested on or before December 21, 2005, the IRS stated that it would continue to follow the holdings set forth in private letter rulings prohibiting the flow through of EDIT and ADITC associated with the divested assets. Pepco made a filing in April 2008, advising the DCPSC of the adoption of the final regulations and requesting that the DCPSC issue an order consistent with the IRS position. If the DCPSC issues the requested order, no accounting adjustments to the gain recorded in 2000 would be required.
Pepco believes that its calculation of the District of Columbia customers’ share of divestiture proceeds is correct. Nevertheless, if Pepco is required by the DCPSC to share its EDIT and ADITC balances with its District of Columbia customers, the additional gain-sharing payments, along with any required ADITC-related payments to the IRS, could have a material adverse effect on Pepco’s and PHI’s results of operations for periods in which the payments are required to be made. However, neither PHI nor Pepco believes that such payments would have a material adverse impact on its financial position or cash flows.
ACE Sale of B.L. England Generating Facility
In February 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC. In July 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement in the amount of $25 million. RC Cape May contends that one of the assets it purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been declared by Citgo to have been terminated due to a failure by ACE to renew the contract in a timely manner. The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo.
RC Cape May commenced an arbitration proceeding against Citgo seeking a determination that the TSA remains in effect and notified ACE of the proceedings. On July 1, 2009, the arbitrator issued its interim award, ruling that the TSA remains in effect and is enforceable by RC Cape May against Citgo. PHI believes this ruling invalidates RC Cape May’s indemnification claim against ACE, but cannot predict whether RC Cape May will continue to pursue indemnification.
General Litigation
In 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.” Pepco and other corporate entities were brought into
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these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepco’s property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings are not entirely clear, it appears that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant.
Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of December 31, 2009, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant under which Pepco sold its generation assets to Mirant in 2000.
While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) is approximately $360 million, PHI and Pepco believe the amounts claimed by the remaining plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time; however, based on information and relevant circumstances known at this time, neither PHI nor Pepco believes these suits will have a material adverse effect on its financial condition, results of operations or cash flows. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco’s and PHI’s financial condition, results of operations and cash flows.
Environmental Litigation
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. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of the operating utilities, environmental clean-up costs incurred by Pepco, DPL and ACE would be included by each company in its respective cost of service for ratemaking purposes.
Delilah Road Landfill Site. In 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with two other PRPs, signed an administrative consent order with NJDEP to remediate the site. The soil cap remedy for the site has been implemented and, in August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years. In September 2007, NJDEP approved the PRP group’s petition to conduct semi-annual, rather than quarterly, ground water monitoring for two years and deferred until the end of the two-year period a decision on the PRP group’s request for annual groundwater monitoring thereafter. In August 2007, the PRP group agreed to reimburse the costs of the EPA in the amount of $81,400 in full satisfaction of EPA’s claims for all past and future response costs relating to the site (of which ACE’s share is one-third). Effective April 2008, EPA and the PRP group entered into a settlement agreement which will allow EPA to reopen the settlement in the event of new information or unknown conditions at the site. On November 23, 2008, Lenox, Inc., a member of the PRP group, filed a bankruptcy petition under Chapter 11 of the U.S. Bankruptcy Code. ACE has filed a proof of claim in the Lenox bankruptcy seeking damages
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resulting from the rejection by Lenox, Inc., of its cost sharing obligations to ACE. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows, regardless of the impact of the Lenox bankruptcy. Effective October 13, 2009, EPA deleted the Delilah Road Landfill site from the national priorities list, after determining that all appropriate response actions under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) have been completed. Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000.
Frontier Chemical Site. In June 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y. based on hazardous waste manifests indicating that ACE sent in excess of 7,500 gallons of manifested hazardous waste to the site. ACE has entered into an agreement with the other parties identified as PRPs to form a PRP group and has informed NYDEC that it has entered into good faith negotiations with the PRP group to address ACE’s responsibility at the site. In February 2010, ACE accepted the PRP group’s offer of a deminimis cash-out settlement under which ACE paid a total of $16,000 to receive a release from liability and be relieved from any further involvement at the site.
Franklin Slag Pile Site. On November 26, 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a PRP that may have liability with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency and for the costs of implementing an EPA-mandated remedy. The EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983 (ACE owned B.L. England at that time and MDC formerly operated the Franklin Slag Pile site). EPA further claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under CERCLA, and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA’s letter also states that as of the date of the letter, EPA’s expenditures for response measures at the site exceed $6 million. EPA estimates approximately $6 million as the cost for future response measures it recommends. ACE understands that the EPA sent similar general notice letters to three other companies and various individuals.
ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications, and therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by the EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE.
Peck Iron and Metal Site. EPA informed Pepco in a May 20, 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, or for costs EPA has incurred in cleaning up the site. EPA’s letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by Peck Iron and Metal personnel, who informed the EPA that Pepco was a customer at the site. Pepco has advised the EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales are entitled to the recyclable material exemption from CERCLA liability. At this time Pepco cannot predict how EPA will proceed regarding this matter, or what portion, if any, of the Peck Iron and Metal Site response costs EPA would seek to recover from Pepco. In a notice published on November 4, 2009, EPA placed the Peck Iron and Metal Site on the National Priorities List.
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Ward Transformer Site. In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against ACE, DPL and Pepco with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. With the court’s permission, the plaintiffs filed amended complaints on September 1, 2009. ACE, DPL and Pepco, as part of a group of defendants, filed a motion to dismiss on October 13, 2009. Although it is too early in the process to characterize the magnitude of the potential liability at this site, it does not appear that any of the three PHI utilities had extensive business transactions, if any, with the Ward Transformer site.
Deepwater Generating Facility. In December 2005, NJDEP issued a Title V operating permit (the Title V Permit) to Deepwater generating facility (Deepwater) owned by Conectiv Energy. In January 2006, Conectiv Energy filed an appeal (the Title V Appeal) with the New Jersey Office of Administrative Law (OAL) challenging several provisions of the Title V Permit, including newly imposed limits on unit heat input (the amount of energy introduced to the boiler in a specified time period). In an October 2007 order, the OAL administrative law judge (ALJ) granted a summary decision in favor of Conectiv Energy, finding that NJDEP does not have the authority to use hourly heat input as a basis to condition or limit electric generating operations, which the ALJ subsequently amended also to include annual heat limitations (as amended, the October 2007 Order).
On July 29, 2009, the ALJ issued an initial decision incorporating the October 2007 Order, an intervening December 2008 order regarding other challenged permit conditions and the parties’ partial stipulation of settlement, and transmitted the matter to the NJDEP Commissioner for a final decision. On December 8, 2009, the NJDEP Commissioner issued a final decision rejecting the ALJ’s initial October 2007 Order as it related to hourly and annual heat input limits and remanding to the ALJ for further consideration Conectiv Energy’s challenge to NJDEP’s asserted legal basis for including annual fuel use limits in the Title V Permit. Upon resolution of the fuel use limit issue, Conectiv Energy will evaluate whether to appeal the NJDEP Commissioner’s decision.
In April 2007, NJDEP initiated enforcement action by issuing an Administrative Order and Notice of Civil Administrative Penalty Assessment (the April 2007 Order) alleging that on several occasions Deepwater Unit 1 exceeded the maximum allowable hourly heat input in calendar year 2005 and that Unit 6/8 exceeded its maximum allowable hourly heat input in calendar years 2005 and 2006. The April 2007 Order required Conectiv Energy to operate the Deepwater units in compliance with their hourly heat input limits and assessed a penalty of approximately $1 million. In May 2007, NJDEP initiated a second enforcement action (the May 2007 Order, and collectively with the April 2007 Order, the Enforcement Orders) alleging that each of the Deepwater units exceeded its maximum allowable hourly heat input in calendar year 2004. The May 2007 Order required Conectiv Energy to operate the units in compliance with their hourly heat input limits and assessed a penalty of $811,600. Conectiv Energy appealed the Enforcement Orders in the OAL. Because the ALJ for the AOL was already reviewing NJDEP’s authority to impose heat input limits as part of the Deepwater Title V appeal, the ALJ placed the appeal of the Enforcement Orders on inactive status. The ALJ has indicated that the Enforcement Orders will remain inactive pending resolution, including any appeal of Conectiv Energy’s challenge to the NJDEP’s authority to impose heat input limits as a basis to condition or limit electric generating operations.
Appeal of New Jersey Flood Hazard Regulations. In November 2007, NJDEP 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
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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.
PHI’s Cross-Border Energy Lease Investments
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. PHI’s current annual tax benefits from these eight cross-border energy lease investments are approximately $55 million. As of December 31, 2009, PHI’s equity investment in its cross-border energy leases was approximately $1.4 billion, which included the impact of the reassessments discussed below. From January 1, 2001, the earliest year that remains open to audit, to December 31, 2009, PHI has derived approximately $516 million in federal and state income tax benefits from the depreciation and interest deductions in excess of rental income with respect to these cross-border energy lease investments.
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 RARs 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 each of its cross-border energy lease investments. In addition, the IRS has sought to recharacterize each of 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.
Under applicable accounting guidance ASC 840, PHI is required to assess on a periodic basis the likely outcome of tax positions relating to its cross-border energy lease investments and, if there is a change or a projected change in the timing of the tax benefits generated by the transactions, it is required to recalculate the value of its equity investment. While PHI believes that its tax position with regard to its cross-border energy lease investments was appropriate based on applicable statutes, regulations and case law, after evaluating the court rulings available at the time, PHI at June 30, 2008 reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of the tax benefits from its cross-border energy lease investments. Based on this reassessment, PHI for the quarter ended June 30, 2008, recorded an after-tax charge to net income of $93 million consisting of (i) a non-cash pre-tax charge of $124 million ($86 million after-tax) to reduce the equity value of these cross-border energy lease investments and (ii) a non-cash charge of $7 million after-tax to reflect the anticipated additional interest expense.
The tax benefits associated with the lease transactions represent timing differences that do not change the aggregate amount of the lease net income over the life of the transactions. The $124 million charge reflects changes to the book equity value of the cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income that will be recognized as income over the remaining term of the affected leases, which expire between 2017 and 2047. Beginning with the 2007 tax return, PHI has reduced the tax benefits claimed on its federal and state tax returns consistent with the
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revised assumptions regarding the estimated timing of the tax benefits. Other than these adjustments, PHI has made no additional cash payments of federal or state income taxes or interest thereon as a result of the reassessment discussed above. Whether PHI makes any additional payments, and the amount and timing thereof, will depend on a number of factors, including PHI’s litigation strategy and whether a settlement with the IRS can be reached.
PHI believes that it is unlikely that a resolution will be reached with the Appeals Office and, therefore, PHI currently intends to pursue litigation against the IRS to defend its tax position, which, absent a settlement, may take several years to resolve. In the last several years, IRS challenges to certain cross-border lease transactions have been the subject of litigation, including several decisions in favor of the IRS which were factored into PHI’s decision to adjust the lease values in June 2008. On October 21, 2009, the U.S. Court of Federal Claims issued a decision in favor of a taxpayer regarding a cross-border lease transaction. PHI views this ruling as a favorable development in PHI’s dispute with the IRS because the transaction that is the subject of the ruling is similar in many respects to PHI’s cross-border energy lease investments.
At December 31, 2009, PHI modified its tax cash flow assumptions under its cross-border energy lease investments for the period 2010-2012 to reflect the anticipated timing of potential litigation with the IRS concerning the investments. As the result of the recalculation of the equity investment, PHI recorded an additional $2 million after-tax non-cash earnings charge in 2009, and expects to record an additional $3 million after-tax non-cash earnings benefit in 2010.
In the event that the 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. To mitigate the taxes due in the event of a total disallowance of tax benefits, PHI could, were it to so elect, choose to liquidate all or a portion of its cross-border energy lease portfolio, which PHI estimates could be accomplished over a period of six months to one year. Based on current market values, PHI estimates that liquidation of the entire portfolio would generate sufficient cash proceeds to cover the estimated $723 million in federal and state taxes and interest due as of December 31, 2009, in the event of a total disallowance of tax benefits and a recharacterization of the transactions as loans. If payments of additional taxes and interest preceded the receipt of liquidation proceeds, the payments would be funded by currently available sources of liquidity.
To the extent that PHI does not to 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 FASB guidance on leases (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.
IRS Mixed Service Cost Issue
During 2001, Pepco, DPL, and ACE changed their methods of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed the companies to accelerate the deduction of certain expenses that were previously capitalized and depreciated. As a result of this method change, PHI generated incremental tax cash flow benefits of approximately $205 million (consisting of $94 million for Pepco, $62 million for DPL, and $49 million for ACE).
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In 2005, the IRS issued Revenue Ruling 2005-53, which limited the ability of Pepco, DPL and ACE to utilize its tax accounting method on their 2001 through 2004 tax returns. In accordance with this Revenue Ruling, the RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco, DPL and ACE had claimed on those returns.
In March 2009, PHI reached a tentative settlement with the IRS for all years (2001 through 2004). The terms of the tentative settlement reduced the tax benefits related to the mixed service costs deductions by $35 million ($17 million for Pepco, $12 million for DPL, and $6 million for ACE) from $205 million claimed on originally filed returns to $170 million.
District of Columbia Tax Legislation
On January 4, 2010, the Mayor of the District of Columbia signed emergency legislation adopting mandatory combined unitary business reporting effective for tax year 2011, and revising the District’s related party expense disallowance effective for tax year 2009. This emergency legislation is effective for 90 days from the date it was signed by the Mayor and, therefore, will expire in early April 2010.
On December 24, 2009, the Mayor approved permanent legislation adopted by the City Council that mirrors the emergency legislation. The permanent legislation was transmitted to Congress on January 5, 2010. If Congress does not intervene during a 30-day period (consisting of days in which the Congress is “in session”), the permanent legislation will become binding law. The 30-day Congressional review period is expected to end on March 2, 2010. Because the 30-day period begins in 2010 and the City Council must still write and pass further legislation providing guidance on how to implement unitary reporting before these provisions are effective, PHI believes that the legislative process was not complete as of December 31, 2009, and, therefore, the effect of neither the emergency nor the permanent legislation (both for combined unitary business tax reporting and related party expense disallowance) was accounted for as of December 31, 2009.
The permanent legislation does not define the term “unitary business” and does not specify how combined tax reporting would differ from our current consolidated tax reporting in the District of Columbia. However, based upon PHI’s interpretation of combined unitary business tax reporting in other taxing jurisdictions, the legislation would likely result in a change in PHI’s overall state income tax rate and, therefore, would likely require an adjustment to PHI’s net deferred income tax liabilities. Further, to the extent that the change in rate increases net deferred income tax liabilities, PHI must determine if these increased tax liabilities are probable of recovery in future rates. The related party expense disallowance provisions of the permanent legislation would likely result in a change in PHI’s overall state income tax rate. No timetable has been established by the City Council to write and pass further legislation and, therefore, uncertainty exists as to whether combined unitary reporting will be effective for PHI.
Management is currently analyzing the impact of this legislation on the financial position, results of operations and cash flows of PHI and its subsidiaries.
Third Party Guarantees, Indemnifications, and Off-Balance Sheet Arrangements
Pepco Holdings and certain of its subsidiaries have various financial and performance guarantees and indemnification obligations that they have entered into in the normal course of business to facilitate commercial transactions with third parties as discussed below.
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As of December 31, 2009, Pepco Holdings and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, performance residual value, and other commitments and obligations. The commitments and obligations, in millions of dollars, were as follows:
(a) Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties under routine energy sales and procurement obligations, including retail customer load obligations of Pepco Energy Services and requirements under BGS contracts entered into by Conectiv Energy with ACE.
(b) Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value of certain equipment and fleet vehicles held through lease agreements. As of December 31, 2009, obligations under the guarantees were approximately $6 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantees have not been made by the guarantor as, under normal conditions, the contract runs to full term at which time the residual value is minimal. As such, Pepco Holdings believes the likelihood of payments being required under the guarantees is remote.
(c) Pepco Holdings has guaranteed a subsidiary building lease of $1 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.
Pepco Holdings and certain of its subsidiaries have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These indemnification agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements over various periods of time depending on the nature of the claim. The maximum potential exposure under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The total maximum potential amount of future payments under these indemnification agreements is not estimable due to several factors, including uncertainty as to whether or when claims may be made under these indemnities.
Dividends
On January 28, 2010, Pepco Holdings’ 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.
Contractual Obligations
As of December 31, 2009, Pepco Holdings’ contractual obligations under non-derivative fuel and purchase power contracts were $1,112 million in 2010, $1,109 million in 2011 to 2012, $592 million in 2013 to 2014, and $2,130 million in 2015 and thereafter.
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(18) ACCUMULATED OTHER COMPREHENSIVE LOSS
A detail of the components of Pepco Holdings’ Accumulated Other Comprehensive (Loss) Income is as follows. For additional information, see the Consolidated Statements of Comprehensive Income.
A detail of the income tax expense (benefit) allocated to the components of Pepco Holdings’ Other Comprehensive (Loss) Income for each year is as follows.
(a) Represents income tax expense on amortization of gains and losses for prior service costs.
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(19) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations, differences between summer and winter rates, and the scheduled downtime and maintenance of electric generating units. The totals of the four quarterly basic and diluted earnings per common share amounts may not equal the basic and diluted earnings per common share for the year due to changes in the number of common shares outstanding during the year.
(a) Includes gains during the first and third quarters related to settlement of Mirant bankruptcy claims of $14 million ($8 million after-tax) and $26 million ($16 million after-tax), respectively.
(b) Includes benefit of $13 million related to a change in the Maryland state income tax reporting for the disposition of certain assets in prior years.
(c) Includes a $6 million benefit related to additional analysis of current and deferred income tax balances completed during the fourth quarter and a $2 million benefit related to the resolution of an uncertain state income tax position.
(d) Includes $7 million of after-tax net interest income on uncertain tax positions primarily related to casualty losses.
(e) Includes a $124 million charge ($86 million after-tax) related to the adjustment to the equity value of cross-border energy lease investments.
(f) Includes a $4 million adjustment to correct an understatement of operating expenses for prior periods dating back to February 2005 where late payment fees were incorrectly recognized.
(g) Includes $7 million of after-tax interest income related to the tentative settlement of the IRS mixed service cost issue and $2 million of after-tax interest income received in 2008 on the Maryland state tax refund offset by a $7 million after-tax charge for interest related to the increased tax obligation associated with the adjustment to the equity value of cross-border energy lease investments.
(h) Includes a $9 million charge related to an adjustment in the accounting for certain restricted stock awards granted under the Long-Term Incentive Plan and a $4 million adjustment to correct an understatement of operating expenses for prior periods dating back to May 2006 where late payment fees were incorrectly recognized.
(i) Includes $11 million of after-tax net interest income on uncertain and effectively settled tax positions (primarily associated with the final settlement with the IRS on the like-kind exchange issue, a claim made with the IRS related to the tax reporting for fuel over- and under-recoveries, and the reversal of the majority of the interest income recognized on uncertain tax positions related to casualty losses in the first quarter) and a benefit of $8 million (including a $3 million correction of prior period errors) related to additional analysis of deferred tax balances completed in 2008.
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Management’s Report on Internal Control over Financial Reporting
The management of Pepco is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed its internal control over financial reporting as of December 31, 2009 based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of Pepco concluded that Pepco’s internal control over financial reporting was effective as of December 31, 2009.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the financial statements of Pepco included in this Annual Report on Form 10-K, has also issued its attestation report on the effectiveness of Pepco’s internal control over financial reporting, which is included herein.
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Report of Independent Registered Public Accounting Firm
To the Shareholder and Board of Directors of Potomac Electric Power Company
In our opinion, the financial statements listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Potomac Electric Power Company (a wholly owned subsidiary of Pepco Holdings, Inc.) at December 31, 2009 and December 31, 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule and on the Company’s internal control over financial reporting based on our audits, which was an integrated audit in 2009. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 26, 2010
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POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF INCOME
The accompanying Notes are an integral part of these Financial Statements.
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POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
The accompanying Notes are an integral part of these Financial Statements.
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POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
The accompanying Notes are an integral part of these Financial Statements.
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POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of these Financial Statements.
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POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF EQUITY
The accompanying Notes are an integral part of these Financial Statements.
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NOTES TO FINANCIAL STATEMENTS
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(1) ORGANIZATION
Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier, in both the District of Columbia and Maryland. Default Electricity Supply is known as Standard Offer Service (SOS) in both the District of Columbia and Maryland. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI).
(2) SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although Pepco believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.
Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. Pepco records an estimated liability for these proceedings and claims when the loss is determined to be probable and is reasonably estimable.
Change in Accounting Estimates
During 2007, as a result of the depreciation study presented as part of Pepco’s Maryland rate case, the Maryland Public Service Commission (MPSC) approved new lower depreciation rates for Pepco’s Maryland distribution assets. This change resulted in lower depreciation expense of approximately $19 million for the last six months of 2007.
Revenue Recognition
Pepco recognizes revenue upon delivery of electricity to its customers, including amounts for services rendered, but not yet billed (unbilled revenue). Pepco recorded amounts for unbilled revenue of $89 million and $98 million as of December 31, 2009 and 2008, respectively. These amounts are included in Accounts Receivable. Pepco calculates unbilled revenue using an output based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers), all of which are inherently uncertain and susceptible to change from period to period, and if actual results differ from projected results, the impact could be material.
Taxes related to the consumption of electricity by its customers, such as fuel, energy, or other similar taxes, are components of Pepco’s tariffs and, as such, are billed to customers and recorded in Operating Revenues.
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Accruals for these taxes by Pepco are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by Pepco in the normal course of business is charged to operations, maintenance or construction, and is not material.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in Pepco’s gross revenues were $254 million, $241 million and $243 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Long-Lived Assets Impairment
Pepco evaluates certain long-lived assets to be held and used (for example, equipment and real estate) to determine if they are impaired whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner an asset is being used or its physical condition. A long-lived asset to be held and used is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount.
For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying amount exceeds its fair value including costs to sell.
Income Taxes
Pepco, as a direct subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco based upon the taxable income or loss amounts, determined on a separate return basis.
On May 2, 2007, the Financial Accounting Standards Board (FASB) issued guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. Pepco applied the guidance on January 1, 2007.
The financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on Pepco’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.
Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities and are measured using presently enacted tax rates. The portion of Pepco’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the Balance Sheets. See Note (6), “Regulatory Assets and Regulatory Liabilities,” for additional information.
Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.
Pepco recognizes interest on under/over payments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.
Investment tax credits are being amortized to income over the useful lives of the related property.
Consolidation of Variable Interest Entities
Due to a variable element in the pricing structure of Pepco’s purchase power agreement with Panda-Brandywine, L.P. (Panda) entered into in 1991, pursuant to which Pepco was obligated to purchase from
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Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA), Pepco potentially assumed the variability in the operations of the plants related to the Panda PPA and therefore had a variable interest in the entity.
During the third quarter of 2008, Pepco transferred the Panda PPA to Sempra Energy Trading LLP. Net purchase activities under the Panda PPA for the years ended December 31, 2008 and 2007 were approximately $59 million and $85 million, respectively.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, cash invested in money market funds, and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s “money pool,” which Pepco and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.
Restricted Cash Equivalents
The restricted cash equivalents included in Current Assets and the restricted cash equivalents included in Investments and Other Assets represent (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated, based on management’s intent with respect to the use of such cash equivalents. The classification as current or non-current conforms to the classification of the related liabilities.
Accounts Receivable and Allowance for Uncollectible Accounts
Pepco’s accounts receivable balance primarily consists of customer accounts receivable, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).
Pepco maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other Operation and Maintenance expense in the Statements of Income. Pepco determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a general reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment, and changes in the creditworthiness of its customers. Although management believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, Pepco records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment becomes known.
Inventories
Included in inventories are transmission and distribution materials and supplies.
Pepco utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies inventory are generally charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
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NOTES TO FINANCIAL STATEMENTS-(Continued)
POTOMAC ELECTRIC POWER COMPANY
Regulatory Assets and Regulatory Liabilities
Pepco is regulated by the MPSC and the District of Columbia Public Service Commission (DCPSC). The transmission and wholesale sale of electricity by Pepco are regulated by the Federal Energy Regulatory Commission (FERC).
Based on the regulatory framework in which it has operated, Pepco has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (Accounting Standards Codification (ASC) 980). The guidance allows regulated entities, in appropriate circumstances, to establish regulatory assets and to defer the income statement impact of certain costs that are expected to be recovered in future rates. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders, and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset will be eliminated through a charge to earnings.
Effective June 2007, the MPSC approved a bill stabilization adjustment mechanism (BSA) for retail customers. The DCPSC also approved a BSA for retail customers, effective in November 2009. See Note (13) “Commitments and Contingencies - Regulatory and Other Matters - Rate Proceedings.” For customers to whom the BSA applies, Pepco recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. Pursuant to this mechanism, Pepco recognizes either (a) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer, or (b) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.
Investment in Trust
Represents assets held in a trust for the benefit of participants in the Pepco Owned Life Insurance plan.
Property, Plant and Equipment
Property, plant and equipment are recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation. For additional information regarding the treatment of removal obligations, see the “Asset Removal Costs” section included in this Note.
The annual provision for depreciation on electric property, plant and equipment is computed on the straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Property, plant and equipment other than electric facilities is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite depreciation rates for 2009, 2008, and 2007 for Pepco’s transmission and distribution system property were approximately 2.7%, 2.7%, and 3.0%, respectively.
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NOTES TO FINANCIAL STATEMENTS-(Continued)
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Capitalized Interest and Allowance for Funds Used During Construction
In accordance with FASB guidance on regulated operations (ASC 980), utilities can capitalize as Allowance for Funds Used During Construction (AFUDC) the capital costs of financing the construction of plant and equipment. The debt portion of AFUDC is recorded as a reduction of “interest expense” and the equity portion of AFUDC is credited to “other income” in the accompanying Statements of Income.
Pepco recorded AFUDC for borrowed funds of $4 million, $2 million, and $5 million for the years ended December 31, 2009, 2008, and 2007, respectively.
Pepco recorded amounts for the equity component of AFUDC of $3 million for each of the years ended December 31, 2009, 2008 and 2007.
Leasing Activities
Pepco’s lease transactions can include office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as either operating leases or capital leases.
Operating Leases
An operating lease generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, Pepco’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.
Capital Leases
For ratemaking purposes, capital leases are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations, the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life.
Amortization of Debt Issuance and Reacquisition Costs
Pepco defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issues. When refinancing existing debt, any unamortized premiums, discounts and debt issuance costs are classified as regulatory assets and are amortized generally over the life of the new issue. Any costs associated with the redemption of the existing debt are amortized over the life of the new issue.
Asset Removal Costs
In accordance with FASB guidance on Asset Retirement Obligations (ASC 410), asset removal costs are recorded as regulatory liabilities. At December 31, 2009 and 2008, $113 million and $107 million, respectively, are included within regulatory liabilities in the accompanying Balance Sheets.
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Pension and Other Postretirement Benefit Plans
Pepco Holdings sponsors a non-contributory retirement plan that covers substantially all employees of Pepco (the PHI Retirement Plan) and certain employees of other Pepco Holdings subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.
The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).
Dividend Restrictions
All of Pepco’s shares of outstanding common stock are held by PHI, its parent company. In addition to its future financial performance, the ability of Pepco to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by Pepco and any other restrictions imposed in connection with the incurrence of liabilities. Pepco has no shares of preferred stock outstanding. Pepco had approximately $730 million and $624 million of retained earnings available for payment of common stock dividends at December 31, 2009 and 2008, respectively.
Subsequent Events
Pepco has evaluated all subsequent events through February 26, 2010, the date of issuance of the financial statements.
Reclassifications and Adjustments
Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustments have been recorded, which are not considered material either individually or in the aggregate.
During 2008, Pepco recorded adjustments to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 during which (i) customer late payment fees were incorrectly recognized and (ii) stock-based compensation expense related to certain restricted stock awards granted under the Long-Term Incentive Plan was understated. These adjustments resulted in a total increase in Other Operation and Maintenance expenses of $6 million for the year ended December 31, 2008, all of which related to prior periods.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Business Combinations (ASC 805)
The accounting guidance on business combinations was amended by the FASB effective beginning January 1, 2009. The amendment did not change the fundamental concepts that the acquisition method of accounting be used and that an acquirer must be identified for each business combination. However, the guidance expanded the definition of a business subject to this guidance and also requires the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.
On April 1, 2009, the FASB issued additional guidance to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The additional guidance requires that assets acquired and
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liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with FASB guidance on contingencies (ASC 450).
The new guidance applied prospectively to business combinations for which the acquisition date was on or after January 1, 2009. The adoption of the guidance did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.
Fair Value Measurement and Disclosures (ASC 820)
There is a variety of new accounting guidance from the FASB that was effective for different financial reporting periods during 2009. Nonrecurring fair value measurement guidance for non-financial assets and non-financial liabilities was effective beginning January 1, 2009 for Pepco. The adoption of this guidance did not have a material impact on the fair value measurements of Pepco’s nonfinancial assets and non-financial liabilities.
New FASB guidance for the fair value measurement of liabilities issued with inseparable third-party credit enhancements was also effective beginning January 1, 2009 for Pepco. The guidance applies to liabilities such as debt, derivatives, and other instruments that are guaranteed by third parties. The effect of the credit enhancement may not be included in the fair value measurement of the liability, even if the liability has an inseparable third-party credit enhancement. The issuer is required to disclose the existence of the inseparable third-party credit enhancement on the issued liability. The adoption of the guidance did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.
Pepco adopted new FASB guidance in the second quarter of 2009 for fair value measurement when markets are inactive and distressed. This guidance was effective for interim periods ending after June 15, 2009. The guidance outlines a two-step test to identify inactive and distressed markets and provides a fair value application example for financial instruments when both conditions are met. Use of such information requires management to exercise judgment regarding how the market information is incorporated into the measurement of fair value. This guidance did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.
Effective beginning with its June 30, 2009 financial statements, Pepco began disclosing the fair value of debt issued by Pepco on a quarterly basis in Note (12), “Fair Value Disclosures,” in accordance with FASB guidance which was effective for interim reporting periods ending after June 15, 2009.
The FASB issued new guidance on the fair value measurement of liabilities when there is a lack of observable market information. The guidance clarifies that, when a quoted price is not available for the identical liability, an entity can use the quoted price of the identical liability when it is traded as an asset, the quoted price for a similar liability, or the quoted price for a similar liability when it is traded as an asset. If these prices are not available, then entities can employ an income or market valuation approach that considers what the entity would pay to transfer the identical liability or would receive to enter into the identical liability. The guidance was effective for Pepco starting October 1, 2009, and it did not have an impact on Pepco’s overall financial condition, results of operations, or cash flows.
Subsequent Events (ASC 855)
Beginning with its June 30, 2009 financial statements, Pepco adopted new FASB guidelines for the disclosure of events that occur after the balance sheet reporting date, but before the financial statements are issued. The new guidance requires the disclosure of the date through which Pepco has assessed the impact of subsequent events on the financial statements. The new guidance was effective for interim or annual financial periods ending after June 15, 2009. Pepco has disclosed this subsequent events date in Note (2), “Significant Accounting Policies.”
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FASB Accounting Standards Codification (ASC 105)
The ASC identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of nongovernmental financial statements presented under GAAP. In addition, it replaces the reference system for standards and guidance with a new numerical designation system known as the ASC. The ASC is the single source reference system for all authoritative GAAP.
The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. Pepco adopted the ASC guidance and referencing system for GAAP in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references to GAAP. The adoption of ASC did not result in a change in accounting principle for Pepco, therefore, it did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
Transfers and Servicing (ASC 860)
The FASB issued new guidance that removes the concept of a qualifying special-purpose entity (QSPE) from the current guidance on transfers and servicing and the QSPE scope exception in current guidance on consolidation. The new guidance also changes the requirements for derecognizing financial assets and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets.
The new guidance is effective for transfers of financial assets occurring in fiscal periods beginning after November 15, 2009; therefore, this guidance will be effective on January 1, 2010 for Pepco. Pepco does not expect this standard will have a material impact on its overall financial condition, results of operations, or cash flows.
Consolidation of Variable Interest Entities (ASC 810)
The FASB issued new consolidation guidance regarding variable interest entities that eliminates the existing quantitative analysis requirement and adds new qualitative factors to determine whether consolidation is required. The new qualitative factors would be applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retained the existing provision that allowed entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine the primary beneficiary.
The new guidance is effective for fiscal periods beginning after November 15, 2009 for existing and newly created entities; therefore, this guidance will be effective on January 1, 2010 for Pepco. Pepco does not expect that the new guidance will result in a material change in accounting or disclosures in its financial statements.
Fair Value Measurement and Disclosures (ASC 820)
The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. Some of the requirements will be effective for Pepco beginning with its March 31, 2010 financial statements and include: (i) a disaggregation of balance sheet categories that are measured at fair value into classes (i.e. subsets of assets or liabilities within a balance sheet line item), (ii) a description of pricing inputs and
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valuation methodologies for instruments with Level 2 and 3 valuation inputs, and (iii) a reconciliation of transfers of instruments between Level 1 and 2 valuation categories. Beginning with its March 31, 2011 financial statements, Pepco will be required to disaggregate the Level 3 fair value measurement reconciliations into separate categories for purchases, sales, issuances, and settlements. Pepco is evaluating the impact of this new guidance on its financial statement footnote disclosures.
(5) SEGMENT INFORMATION
The company operates its business as one regulated utility segment, which includes all of its services as described above.
(6) REGULATORY ASSETS AND REGULATORY LIABILITIES
The components of Pepco’s regulatory asset balances at December 31, 2009 and 2008 are as follows:
The components of Pepco’s regulatory liability balances at December 31, 2009 and 2008 are as follows:
A description of the regulatory assets and regulatory liabilities is as follows:
Deferred Energy Supply Costs: This regulatory asset represents primarily deferred energy costs associated with a net under-recovery of Default Electricity Supply costs in the District of Columbia. The regulatory liability represents deferred transmission and energy costs associated with a net over-recovery of Default Electricity Supply costs incurred in the District of Columbia and Maryland. A return is earned on these deferrals.
Deferred Income Taxes: Represents a receivable from our customers for tax benefits Pepco has previously flowed through before the company was ordered to account for the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed. There is no return earned on these deferrals.
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Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period. A return is earned on these deferrals.
Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years. Also includes the under-recovery of administrative costs associated with Default Electricity Supply in the District of Columbia and Maryland. These regulatory assets generally do not earn a return.
Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax liabilities applicable to Pepco’s utility operations that have not been reflected in current customer rates for which future payment to customers is probable. As temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return earned on these deferrals.
Asset Removal Costs: Pepco’s depreciation rates include a component for removal costs, as approved by its federal and state regulatory commissions. Pepco has recorded a regulatory liability for its estimate of the difference between incurred removal costs and the level of removal costs recovered through rates. There is no return earned on these deferrals.
Settlement proceeds - Mirant Bankruptcy Claims: In 2007, Pepco received $414 million of net proceeds from settlement of a Mirant Corporation (Mirant) bankruptcy claim, plus interest earned, which was designated to pay for future above-market capacity and energy purchases under the Panda PPA. In 2008, Pepco transferred the Panda PPA to Sempra in a transaction in which Pepco made a payment to Sempra and all further Pepco rights, obligations and liabilities under the Panda PPA were terminated. The balance at December 31, 2008 reflects the funds remaining after the Sempra payment.
In March 2009, the DCPSC issued an order approving Pepco’s sharing proposal for the District of Columbia under which approximately $24 million was distributed to District of Columbia customers as a one-time billing credit. In July 2009, the MPSC approved a settlement under which Pepco distributed approximately $38 million to Maryland customers during the billing month of August 2009 through a one-time billing credit. The $40 million balance was recorded by Pepco as income in 2009. See Note (13), “Commitments and Contingencies - Proceeds from Settlement of Mirant Bankruptcy Claims,” for additional information.
Other: Represents miscellaneous regulatory liabilities. There is no return earned on these deferrals.
(7) LEASING ACTIVITIES
Lease Commitments
Pepco leases its consolidated control center, which is an integrated energy management center used by Pepco to centrally control the operation of its transmission and distribution systems. This lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments, which totaled $152 million. The lease requires semi-annual payments of approximately $8 million over a 25-year period beginning in December 1994, and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under FASB guidance on regulated operations, the amortization of leased assets is modified so that the total interest expense charged on the obligation and amortization expense of the leased asset is equal to the rental expense allowed for rate-making purposes. This lease has been treated as an operating lease for rate-making purposes.
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Capital lease assets recorded within Property, Plant and Equipment at December 31, 2009 and 2008 are comprised of the following:
The approximate annual commitments under capital leases are $15 million for each year 2010 through 2014, and $77 million thereafter.
Rental expense for operating leases was $3 million, $4 million and $4 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Total future minimum operating lease payments for Pepco as of December 31, 2009 are $8 million in 2010, $1 million in each of the years 2011 through 2014, and $2 million thereafter.
(8) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of the following:
The non-operating and other property amounts include balances for general plant, distribution and transmission plant held for future use, intangible plant and non-utility property.
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(9) PENSIONS AND OTHER POSTRETIREMENT BENEFITS
Pepco accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. For 2009, 2008, and 2007, Pepco was responsible for $38 million, $24 million and $22 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings. Pepco made discretionary, tax-deductible contributions of $170 million to the PHI Retirement Plan for the year ended December 31, 2009. No contributions were made for the years ended December 31, 2008 and 2007. In addition, Pepco made contributions of $8 million, $9 million, and $10 million, respectively, to the other postretirement benefit plans for the years ended December 31, 2009, 2008 and 2007. At December 31, 2009 and 2008, Pepco’s prepaid pension expense of $295 million and $142 million, and other postretirement benefit obligation of $71 million and $49 million, effectively represent assets and benefit obligations resulting from Pepco’s participation in the Pepco Holdings benefit plans.
(10) DEBT
Long-Term Debt
Long-term debt outstanding as of December 31, 2009 and 2008 is presented below.
(a) Represents a series of First Mortgage Bonds issued by Pepco (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued by or for the benefit of Pepco. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligations in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes and tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.
(b) Represents a series of Collateral First Mortgage Bonds issued by Pepco that will, at such time as there are no First Mortgage Bonds of Pepco outstanding (other than Collateral First Mortgage Collateral Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.
The outstanding First Mortgage Bonds are subject to a lien on substantially all of Pepco’s property, plant and equipment.
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The aggregate principal amount of long-term debt outstanding at December 31, 2009, that will mature in each of 2010 through 2014 and thereafter is as follows: $16 million in 2010, zero in 2011 and 2012, $200 million in 2013, $175 million in 2014, and $1,173 million thereafter.
Pepco’s long-term debt is subject to certain covenants. Pepco is in compliance with all requirements.
Short-Term Debt
Pepco has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. A detail of the components of Pepco’s short-term debt at December 31, 2009 and 2008 is as follows:
Commercial Paper
Pepco maintains an ongoing commercial paper program of up to $500 million. The commercial paper notes can be issued with maturities up to 270 days from the date of issue. The commercial paper program is backed by Pepco’s borrowing capacity under the $1.5 billion credit facility described below under the heading “Credit Facility.”
Pepco had no commercial paper outstanding at December 31, 2009 and 2008. Pepco did not issue commercial paper during 2009. The weighted average interest rate for commercial paper issued during 2008 was 3.45%. The weighted average maturity for commercial paper issued during 2008 was two days.
Credit Facility
PHI, Pepco, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under this credit facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million. The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate and the federal funds effective rate plus 0.5% or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. The facility also includes a “swingline loan sub-facility” pursuant to which each company may make same day borrowings in an aggregate amount not to exceed $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof.
The facility commitment expiration date is May 5, 2012, with each company having the right to elect to have 100% of the principal balance of the loans outstanding on the expiration date continued as non-revolving term loans for a period of one year from such expiration date.
The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general
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corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. As of December 31, 2009, each borrower was in compliance with the covenants of the credit facility.
The absence of a material adverse change in the borrower’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers.
At December 31, 2009 and 2008, the amount of cash plus borrowing capacity under the PHI credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $582 million and $843 million, respectively.
(11) INCOME TAXES
Pepco, as a direct subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.
The provision for income taxes, reconciliation of income tax rate, and components of deferred income tax liabilities (assets) are shown below.
Provision for Income Taxes
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Reconciliation of Income Tax Rate
In March 2009, the Internal Revenue Service (IRS) issued a Revenue Agent’s Report (RAR) for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to Pepco’s capitalization of overhead costs for tax purposes and the deductibility of certain Pepco casualty losses. In conjunction with PHI, Pepco has appealed certain of the proposed adjustments and believes it has adequately reserved for the adjustments included in the RAR.
In November 2009, Pepco received a refund of prior years’ Federal income taxes of $51 million. The refund results from the carry back of PHI’s 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions paid in 2009 (which were deducted in 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs.
During 2009, a reconciliation of current and deferred income tax accounts was completed and, as a result, $1 million net credit was booked to income tax expense. The 2009 adjustment is primarily included in “Adjustments to prior years’ taxes” in the reconciliation above.
During 2008, Pepco completed an analysis of its current and deferred income tax accounts and, as a result, recorded a $3 million net credit to income tax expense in 2008, which is primarily included in “Adjustments to prior years’ taxes” in the reconciliation provided above. In addition, during 2008, Pepco recorded after-tax net interest income of $5 million under ASC 740 primarily related to the reversal of previously accrued interest payable resulting from a favorable tentative settlement of the mixed service cost issue with the IRS, and after-tax interest income of $2 million for interest received in 2008 on the Maryland state tax refund.
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Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate
Unrecognized tax benefits represent those tax benefits related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2009, Pepco had no unrecognized tax benefits that, if recognized, would lower the effective tax rate.
Interest and Penalties
Pepco recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2009, 2008 and 2007, Pepco recognized $7 million of interest expense pre-tax ($4 million after-tax), $8 million of interest income pre-tax ($5 million after-tax), and $1 million of interest income pre-tax (less than $1 million after-tax), respectively, as a component of income tax expense. As of December 31, 2009, 2008 and 2007, Pepco had $8 million, $4 million and $9 million, respectively, of accrued interest payable related to effectively settled and uncertain tax positions.
Possible Changes to Unrecognized Tax Benefits
It is reasonably possible that the amount of the unrecognized tax benefit with respect to certain of Pepco’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The final settlement of the mixed service cost issue or other federal or state audits could impact the balances significantly. At this time, other than the mixed service cost issue, an estimate of the range of reasonably possible outcomes cannot be determined. The unrecognized benefit related to the mixed service cost issue could decrease by $20 million within the next 12 months upon final resolution of the tentative settlement with the IRS. See Note (13), “Commitments and Contingencies,” herein for additional information.
Tax Years Open to Examination
Pepco, as a direct subsidiary of PHI, is included on PHI’s consolidated federal income tax return. Pepco’s federal income tax liabilities for all years through 2000 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where Pepco files state income tax returns (District of Columbia and Maryland) are the same as for the federal returns.
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Components of Deferred Income Tax Liabilities (Assets)
The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to Pepco’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2009 and 2008.
The Tax Reform Act of 1986 repealed the investment tax credit (ITC) for property placed in service after December 31, 1985, except for certain transition property. ITC previously earned on Pepco’s property continues to be amortized to income over the useful lives of the related property.
Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.
(12) FAIR VALUE DISCLOSURES
Fair Value of Assets and Liabilities Excluding Debt
Effective January 1, 2008, Pepco adopted FASB guidance on fair value measurement and disclosures (ASC 820) which established a framework for measuring fair value and expanded disclosures about fair value measurements.
As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Pepco utilizes market data or assumptions that market participants would use in pricing the asset or liability,
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including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, Pepco utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Pepco is able to classify fair value balances based on the observability of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets, and other observable pricing data. Level 2 also includes those financial instruments that are valued using internally developed methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 - Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial investments that are valued using models or other valuation methodologies. Level 3 instruments classified as executive deferred compensation plan assets are life insurance policies that are valued using the cash surrender value of the policies. Since these values do not represent a quoted price in an active market they are considered level 3.
The following tables sets forth by level within the fair value hierarchy Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009 and 2008. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
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Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2009 and 2008 are shown below:
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Fair Value of Debt Instruments
The estimated fair values of Pepco’s non-derivative financial instruments as of December 31, 2009 and 2008 are shown below:
The fair values of the Long-Term Debt, which include First Mortgage Bonds and Medium-Term Notes, including amounts due within one year, were based on the current market prices, or were based on discounted cash flows using current rates for similar issues with similar terms and remaining maturities for issues with no market price available.
(13) COMMITMENTS AND CONTINGENCIES
Regulatory and Other Matters
Proceeds from Settlement of Mirant Bankruptcy Claims
In 2000, Pepco sold substantially all of its electricity generating assets to Mirant. As part of the sale, Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco was obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco was obligated to pay to Panda. In 2003, Mirant commenced a voluntary bankruptcy proceeding in which it sought to reject certain
PEPCO
NOTES TO FINANCIAL STATEMENTS-(Continued)
POTOMAC ELECTRIC POWER COMPANY
obligations that it had undertaken in connection with the asset sale. As part of the settlement of Pepco’s claims against Mirant arising from the bankruptcy, Pepco agreed not to contest the rejection by Mirant of its obligations under the “back-to-back” arrangement in exchange for the payment by Mirant of damages corresponding to the estimated amount by which the purchase price that Pepco was obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $414 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. In September 2008, Pepco transferred the Panda PPA to Sempra, along with a payment to Sempra, thereby terminating all further rights, obligations and liabilities of Pepco under the Panda PPA. In November 2008, Pepco filed with the DCPSC and the MPSC proposals to share with customers the remaining balance of proceeds from the Mirant settlement in accordance with divestiture sharing formulas approved previously by the respective commissions.
In March 2009, the DCPSC issued an order approving Pepco’s sharing proposal for the District of Columbia under which approximately $24 million was distributed to District of Columbia customers as a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of approximately $14 million for the quarter ended March 31, 2009.
On July 2, 2009, the MPSC approved a settlement agreement among Pepco, the Maryland Office of People’s Counsel and the MPSC staff under which Pepco distributed approximately $38 million to Maryland customers during the billing month of August 2009 through a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of $26 million in the quarter ended September 30, 2009.
As a consequence of the MPSC order, $64 million previously accounted for as restricted cash was released and the corresponding regulatory liability was extinguished.
Rate Proceedings
In recent electric service distribution base rate cases, Pepco has proposed the adoption of revenue decoupling methods for retail customers. A BSA has been approved and implemented for Pepco electric service in Maryland and in the District of Columbia. Under the BSA, customer delivery rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The BSA increases rates if actual distribution revenues fall below the approved level and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, Pepco collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” distribution revenue from unit sales consumption and ties the growth in distribution revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for Pepco to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and distribution revenues.
District of Columbia
In January 2008, the DCPSC approved, effective February 20, 2008, a revenue requirement increase for Pepco of approximately $28 million, based on an authorized return on rate base of 7.96%, including a 10% return on equity (ROE). In June 2008, the District of Columbia Office of People’s Counsel (the DC OPC), citing alleged errors by the DCPSC, filed with the DCPSC a motion for reconsideration of the order, which was denied by the DCPSC. In August 2008, the DC OPC filed with the District of Columbia Court of Appeals a petition for review of the DCPSC’s order denying its motion for reconsideration. Briefs have been filed by the parties and oral argument was held on March 23, 2009. On February 18, 2010, the Court of Appeals issued its decision affirming the decision of the DCPSC.
PEPCO
NOTES TO FINANCIAL STATEMENTS-(Continued)
POTOMAC ELECTRIC POWER COMPANY
On May 22, 2009, Pepco submitted an application to the DCPSC to increase electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $50 million with the BSA, based on a requested ROE of 11.25% (subsequently revised by Pepco to 10.75%). The filing also proposes recovery of pension expenses and uncollectible costs through a surcharge mechanism. If the proposed surcharge mechanism is approved, the annual rate increase requested would be reduced by approximately $3 million. Evidentiary hearings were held in mid-November 2009 and a decision is expected from the DCPSC in early 2010.
Maryland
On December 30, 2009, Pepco filed an electric distribution base rate case in Maryland. The filing seeks approval of an annual rate increase of approximately $40 million, based on a requested ROE of 10.75%. A decision by the MPSC is expected by the end of July, 2010.
District of Columbia Divestiture Case
In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets. An unresolved issue relating to the application filed with the DCPSC by Pepco to implement the divestiture settlement is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) 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. As of December 31, 2009, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6 million each.
Pepco believes that a sharing of EDIT and ADITC with its District of Columbia customers would violate the IRS normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned by Pepco, there is no book life over which the EDIT and ADITC can be returned. If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property. Also, in addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco’s District of Columbia jurisdictional generation-related ADITC balance ($6 million as of December 31, 2009), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of December 31, 2009), in each case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.
In March 2008, the IRS approved final regulations, effective March 20, 2008, which allow utilities whose assets cease to be utility property (whether by disposition, deregulation or otherwise) to return to its utility customers the normalization reserve for EDIT and part or all of the normalization reserve for ADITC. This ruling applies to assets divested after December 21, 2005. For utility property divested on or before December 21, 2005, the IRS stated that it would continue to follow the holdings set forth in private letter rulings prohibiting the flow through of EDIT and ADITC associated with the divested assets. Pepco made a filing in April 2008, advising the DCPSC of the adoption of the final regulations and requesting that the DCPSC issue an order consistent with the IRS position. If the DCPSC issues the requested order, no accounting adjustments to the gain recorded in 2000 would be required.
Pepco believes that its calculation of the District of Columbia customers’ share of divestiture proceeds is correct. Nevertheless, if Pepco is required by the DCPSC to share its EDIT and ADITC balances with its District of Columbia customers, the additional gain-sharing payments, along with any required ADITC-related payments to the IRS, could have a material adverse effect on Pepco’s and PHI’s results of operations for periods in which the payments are required to be made. However, neither PHI nor Pepco believes that such payments would have a material adverse impact on its financial position or cash flows.
PEPCO
NOTES TO FINANCIAL STATEMENTS-(Continued)
POTOMAC ELECTRIC POWER COMPANY
General Litigation
In 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.” Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepco’s property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings are not entirely clear, it appears that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant.
Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of December 31, 2009, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant under which Pepco sold its generation assets to Mirant in 2000.
While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) is approximately $360 million, Pepco believes the amounts claimed by the remaining plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time; however, based on information and relevant circumstances known at this time, Pepco does not believe these suits will have a material adverse effect on its financial condition, results of operations or cash flows. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco’s financial condition, results of operations and cash flows.
Environmental Litigation
Pepco is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. Pepco 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. Although penalties assessed for violations of environmental laws and regulations are not recoverable from Pepco’s customers, environmental clean-up costs incurred by Pepco would be included in its cost of service for ratemaking purposes.
Peck Iron and Metal Site. The U.S. Environmental Protection Agency (EPA) informed Pepco in a May 20, 2009 letter that Pepco may be a potentially responsible party (PRP) under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, or for costs EPA has incurred in cleaning up the site. EPA’s letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by Peck Iron and Metal personnel, who informed the EPA that Pepco was a customer at the site. Pepco has advised the EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales are entitled to the recyclable material exemption from CERCLA liability. At this time Pepco cannot predict how EPA will proceed regarding this matter, or what portion, if any, of the Peck Iron and Metal Site response costs EPA would seek to recover from Pepco. In a notice published on November 4, 2009, EPA placed the Peck Iron and Metal Site on the National Priorities List.
PEPCO
NOTES TO FINANCIAL STATEMENTS-(Continued)
POTOMAC ELECTRIC POWER COMPANY
Ward Transformer Site. In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against Pepco with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. With the court’s permission, the plaintiffs filed amended complaints on September 1, 2009. Pepco, as part of a group of defendants, filed a motion to dismiss on October 13, 2009. Although it is too early in the process to characterize the magnitude of the potential liability at this site, it does not appear that Pepco had extensive business transactions, if any, with the Ward Transformer site.
IRS Mixed Service Cost Issue
During 2001, Pepco changed its method of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed the company to accelerate the deduction of certain expenses that were previously capitalized and depreciated. As a result of this method change, Pepco generated incremental tax cash flow benefits of approximately $94 million.
In 2005, the IRS issued Revenue Ruling 2005-53, which limited the ability of Pepco to utilize its tax accounting method on its 2001 through 2004 tax returns. In accordance with this Revenue Ruling, the RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco had claimed on those returns.
In March 2009, PHI reached a tentative settlement with the IRS for all years (2001 through 2004). The terms of the settlement reduced the tax benefits related to the mixed service costs deductions by $17 million for Pepco.
District of Columbia Tax Legislation
On January 4, 2010, the Mayor of the District of Columbia signed emergency legislation adopting mandatory combined unitary business reporting effective for tax year 2011, and revising the District’s related party expense disallowance effective for tax year 2009. This emergency legislation is effective for 90 days from the date it was signed by the Mayor and, therefore, will expire in early April 2010.
On December 24, 2009, the Mayor approved permanent legislation adopted by the City Council that mirrors the emergency legislation. The permanent legislation was transmitted to Congress on January 5, 2010. If Congress does not intervene during a 30-day period (consisting of days in which the Congress is “in session”), the permanent legislation will become binding law. The 30-day Congressional review period is expected to end on March 2, 2010. Because the 30-day period begins in 2010 and the City Council must still write and pass further legislation providing guidance on how to implement unitary reporting before these provisions are effective, PHI believes that the legislative process was not complete as of December 31, 2009, and, therefore, the effect of neither the emergency nor the permanent legislation (both for combined unitary business tax reporting and related party expense disallowance) was accounted for as of December 31, 2009.
The permanent legislation does not define the term “unitary business” and does not specify how combined tax reporting would differ from our current consolidated tax reporting in the District of Columbia. However, based upon PHI’s interpretation of combined unitary business tax reporting in other taxing jurisdictions, the legislation would likely result in a change in Pepco’s overall state income tax rate and, therefore, would likely require an adjustment to Pepco’s net deferred income tax liabilities. Further, to the extent that the change in rate increases Pepco’s net deferred income tax liabilities, Pepco must determine if these increased tax liabilities are probable of recovery in future rates. The related party expense disallowance provisions of the permanent legislation would likely result in a change in Pepco’s overall state income tax rate. No timetable has been established by the City Council to write and pass further legislation and, therefore, uncertainty exists as to whether combined unitary reporting will be effective for Pepco.
PEPCO
NOTES TO FINANCIAL STATEMENTS-(Continued)
POTOMAC ELECTRIC POWER COMPANY
Management is currently analyzing the impact of this legislation on the financial position, results of operations and cash flows of Pepco.
Contractual Obligations
As of December 31, 2009, Pepco had no contractual obligations under non-derivative fuel and power purchase contracts.
(14) RELATED PARTY TRANSACTIONS
PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including Pepco. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to Pepco for the years ended December 31, 2009, 2008 and 2007 were approximately $175 million, $164 million, and $147 million, respectively.
Certain subsidiaries of Pepco Energy Services perform utility maintenance services, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by these companies for the years ended December 31, 2009, 2008 and 2007 were approximately $9 million, $11 million and $26 million, respectively.
In addition to the transactions described above, Pepco’s financial statements include the following related party transactions in its Statements of Income:
(a) Included in purchased energy expense.
PEPCO
NOTES TO FINANCIAL STATEMENTS-(Continued)
POTOMAC ELECTRIC POWER COMPANY
As of December 31, 2009 and 2008, Pepco had the following balances on its Balance Sheets due (to) from related parties:
(a) Pepco bills customers on behalf of Pepco Energy Services where customers have selected Pepco Energy Services as their alternative supplier or where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement.
PEPCO
NOTES TO FINANCIAL STATEMENTS-(Continued)
POTOMAC ELECTRIC POWER COMPANY
(15) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.
(a) Includes gains during the first and third quarters related to settlement of Mirant bankruptcy claims of $14 million ($8 million after-tax) and $26 million ($16 million after-tax), respectively.
(b) Includes a $4 million adjustment to correct an understatement of operating expenses for prior periods dating back to February 2005 where late payment fees were incorrectly recognized.
(c) Includes $3 million of after-tax interest income related to the tentative settlement of the IRS mixed service cost issue and $2 million of after-tax interest income received in 2008 on the Maryland state tax refund.
(d) Includes a $3 million charge related to an adjustment in the accounting for certain restricted stock awards granted under the Long-Term Incentive Plan (LTIP).
(e) Includes $2 million of after-tax net interest income on uncertain and effectively settled tax positions, and a benefit of $3 million (including a $2 million correction of prior period errors) related to additional analysis of deferred tax balances completed in 2008.
DPL
Management’s Report on Internal Control over Financial Reporting
The management of DPL is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed its internal control over financial reporting as of December 31, 2009 based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of DPL concluded that DPL’s internal control over financial reporting was effective as of December 31, 2009.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the financial statements of DPL included in this Annual Report on Form 10-K, has also issued its attestation report on the effectiveness of DPL’s internal control over financial reporting, which is included herein.
DPL
Report of Independent Registered Public Accounting Firm
To the Shareholder and Board of Directors of Delmarva Power & Light Company
In our opinion, the financial statements listed in the accompanying index appearing under Item 15(a)(i) present fairly, in all material respects, the financial position of Delmarva Power & Light Company (a wholly owned subsidiary of Pepco Holdings, Inc.) at December 31, 2009 and December 31, 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule and on the Company’s internal control over financial reporting based on our audits, which was an integrated audit in 2009. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
DPL
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 26, 2010
DPL
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF INCOME
The accompanying Notes are an integral part of these Financial Statements.
DPL
DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
The accompanying Notes are an integral part of these Financial Statements.
DPL
DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
The accompanying Notes are an integral part of these Financial Statements.
DPL
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of these Financial Statements.
DPL
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF EQUITY
The accompanying Notes are an integral part of these Financial Statements.
DPL
NOTES TO FINANCIAL STATEMENTS
DELMARVA POWER & LIGHT COMPANY
(1) ORGANIZATION
Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and provides gas distribution service in northern Delaware. Additionally, DPL provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier, in both Delaware and Maryland. Default Electricity Supply is known as Standard Offer Service (SOS) in both Delaware and Maryland. DPL is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).
In January 2008, DPL completed the sale of its retail electric distribution assets and the sale of its wholesale electric transmission assets, both located on Virginia’s Eastern Shore.
(2) SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although DPL believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.
Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, fair value calculations (based on estimated market pricing) associated with derivative instruments, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims when the loss is determined to be probable and is reasonably estimable.
Change in Accounting Principle
After the completion of the July 1, 2009 goodwill impairment test, DPL adopted a new accounting policy whereby DPL’s annual impairment review of goodwill will be performed as of November 1 each year. Management believes that DPL’s new annual impairment testing date is preferable because it better aligns the timing of the test with management’s annual update of its long-term financial forecast. This change in accounting principle has had no effect on DPL’s financial statements.
Change in Accounting Estimates
During 2007, as a result of the depreciation study presented as part of DPL’s Maryland rate case, the Maryland Public Service Commission (MPSC) approved new lower depreciation rates for DPL’s Maryland distribution assets.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
Revenue Recognition
DPL recognizes revenues upon delivery of electricity and gas to its customers, including amounts for services rendered, but not yet billed (unbilled revenue). DPL recorded amounts for unbilled revenue of $68 million and $52 million as of December 31, 2009 and 2008, respectively. These amounts are included in Accounts Receivable. DPL calculates unbilled revenue using an output based methodology. This methodology is based on the supply of electricity or gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity and gas expected to be lost in the process of its transmission and distribution to customers), all of which are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material. Revenues from non-regulated electricity and gas sales are included in Electric revenues and Natural Gas revenues, respectively.
Taxes related to the consumption of electricity and gas by its customers, such as fuel, energy, or other similar taxes, are components of DPL’s tariffs and, as such, are billed to customers and recorded in Operating Revenues. Accruals for these taxes by DPL are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by DPL in the normal course of business is charged to operations, maintenance or construction, and is not material.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in DPL’s gross revenues were $17 million, $15 million and $13 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Accounting for Derivatives
DPL uses derivative instruments (forward contracts, futures, swaps, and exchange-traded and over-the-counter options) primarily to reduce gas commodity price volatility while limiting its customers’ exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that are not classified as derivatives. The primary goal of these activities is to reduce the exposure of its regulated retail gas customers to natural gas price fluctuations. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are fully recoverable through the fuel adjustment clause approved by the Delaware Public Service Commission (DPSC), and are deferred under Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980) until recovered. At December 31, 2009, there was a net deferred derivative liability of $39 million, offset by a $42 million regulatory asset. At December 31, 2008, there was a net deferred derivative liability of $55 million, offset by a $56 million regulatory asset.
Long-Lived Asset Impairment Evaluation
DPL evaluates certain long-lived assets to be held and used (for example, equipment and real estate) to determine if they are impaired whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner an asset is being used or its physical condition. A long-lived asset to be held and used is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount.
For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying amount exceeds its fair value including costs to sell.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
Income Taxes
DPL, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL based upon the taxable income or loss amounts, determined on a separate return basis.
On May 2, 2007, the FASB issued guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. DPL applied the guidance on January 1, 2007.
The financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on DPL’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.
Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and are measured using presently enacted tax rates. The portion of DPL’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the Balance Sheets. See Note (7), “Regulatory Assets and Regulatory Liabilities,” for additional information.
Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.
DPL recognizes interest on under over payments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.
Investment tax credits are being amortized to income over the useful lives of the related property.
Consolidation of Variable Interest Entities
In accordance with FASB guidance on variable interest entities (ASC 810), DPL consolidates those variable interest entities with respect to which DPL is the primary beneficiary. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests.
DPL Wind Transactions
PHI, through its DPL subsidiary, has entered into four wind PPAs in amounts up to a total of 350 megawatts. Three of the PPAs are with land-based facilities and one of the PPAs is with an offshore facility. When completed and operational, DPL is obligated to purchase energy and renewable energy credits (RECs) from the four wind facilities and capacity from one of the wind facilities. The RECs help DPL fulfill a portion of its requirements under the State of Delaware’s Renewable Energy Portfolio Standards Act, which requires that 20 percent of total load needed in Delaware be produced from renewable sources by 2019. The DPSC has approved the four agreements, each of which sets forth the prices to be paid by DPL over the life of the contract, and has approved the recovery of DPL’s purchase costs through customer rates.
One of the land-based facilities became operational and went into service in December 2009. DPL is obligated to purchase energy and RECs from this facility over 15 years in amounts generated and delivered not to exceed 50.25 megawatts at rates that are fixed. Payments under the other agreements are currently expected to start in 2010 for the other two land-based contracts and 2014 for the offshore contract, if the projects are ultimately completed and operational.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
The terms of the agreements, with facilities that are not yet operational, range between 20 and 25 years. When they become operational, DPL is obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed under these agreements. Recent disruptions in the capital and credit markets, as well as permitting delays, could result in setbacks in the construction schedules and the operational start dates of the wind facilities. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs.
DPL concluded that consolidation is not required for any of these PPAs under FASB guidance on the consolidation of variable interest entities (ASC 810). DPL will need to reassess its accounting conclusions if there are material changes to the contractual arrangements or wind facilities.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, cash invested in money market funds, and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s “money pool,” which DPL and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.
Accounts Receivable and Allowance for Uncollectible Accounts
DPL’s accounts receivable balance primarily consists of customer accounts receivable, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).
DPL maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other Operation and Maintenance expense in the Statements of Income. DPL determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a general reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment, and changes in the creditworthiness of its customers. Although management believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, DPL records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment becomes known.
Inventories
Included in inventories are:
•
transmission and distribution materials and supplies; and
•
natural gas.
DPL utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies inventory are generally charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
The cost of natural gas, including transportation costs, is included in inventory when purchased and charged to Gas purchased when used.
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Goodwill
Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. All of DPL’s goodwill was generated by DPL’s acquisition of Conowingo Power Company in 1995. DPL tests its goodwill for impairment annually and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of DPL below its carrying amount. After the completion of its July 1, 2009 annual impairment test, DPL changed the date of its annual impairment test to November 1. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; an adverse regulatory action; or an impairment of DPL’s long-lived assets. As described in Note (6), “Goodwill,” no impairment charge has been recorded for the year ended December 31, 2009.
Regulatory Assets and Regulatory Liabilities
Certain aspects of DPL’s business are subject to regulation by the DPSC and the MPSC, and, until the sale of its Virginia assets on January 2, 2008, were regulated by the Virginia State Corporation Commission. The transmission and wholesale sale of electricity by DPL are regulated by the Federal Energy regulatory Commission (FERC). DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC.
Based on the regulatory framework in which it has operated, DPL has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to establish regulatory assets and to defer the income statement impact of certain costs that are expected to be recovered in future rates. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders, and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset will be eliminated through a charge to earnings.
Effective June 2007, the MPSC approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to whom the BSA applies, DPL recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. Pursuant to this mechanism, DPL recognizes either (a) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer, or (b) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.
Property, Plant and Equipment
Property, plant and equipment are recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation. For additional information regarding the treatment of retirement obligations, see the “Asset Removal Costs” section included in this Note.
The annual provision for depreciation on electric and gas property, plant and equipment is computed on the straight-line basis using composite rates by classes of depreciable property. Accumulated
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DELMARVA POWER & LIGHT COMPANY
depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Property, plant and equipment other than electric and gas facilities is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite depreciation rates for 2009, 2008 and 2007 for DPL’s transmission and distribution system property were approximately 2.8%, 2.8% and 2.9%, respectively.
Capitalized Interest and Allowance for Funds Used During Construction
In accordance with FASB guidance on regulated operations (ASC 980), utilities can capitalize as Allowance for Funds Used During Construction (AFUDC) the capital costs of financing the construction of plant and equipment. The debt portion of AFUDC is recorded as a reduction of “interest expense” and the equity portion of AFUDC is credited to “other income” in the accompanying Statements of Income.
DPL recorded AFUDC for borrowed funds of $1 million for each of the years ended December 31, 2009, 2008, and 2007.
DPL recorded amounts for the equity component of AFUDC of zero, $1 million and zero for the years ended December 31, 2009, 2008 and 2007, respectively.
Leasing Activities
DPL’s lease transactions can include plant, office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.
Operating Leases
An operating lease generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, DPL’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.
Amortization of Debt Issuance and Reacquisition Costs
DPL defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issues. When refinancing existing debt, any unamortized premiums, discounts and debt issuance costs are classified as regulatory assets and are amortized generally over the life of the original issue. Any costs associated with the redemption of the existing debt are amortized over the life of the original issue.
Asset Removal Costs
In accordance with FASB guidance on asset retirement obligations (ASC 410), asset removal costs are recorded as regulatory liabilities. At December 31, 2009 and 2008, $239 million and $234 million, respectively, are included within regulatory liabilities in the accompanying Balance Sheets.
Pension and Other Postretirement Benefit Plans
Pepco Holdings sponsors a non-contributory retirement plan that covers substantially all employees of DPL (the PHI Retirement Plan) and certain employees of other Pepco Holdings subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.
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DELMARVA POWER & LIGHT COMPANY
The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).
Dividend Restrictions
All of DPL’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of DPL to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by DPL and any other restrictions imposed in connection with the incurrence of liabilities. DPL has no shares of preferred stock outstanding. DPL had approximately $472 million and $448 million of retained earnings available for payment of common stock dividends at December 31, 2009 and 2008, respectively.
Subsequent Events
DPL has evaluated all subsequent events through February 26, 2010, the date of issuance of the financial statements.
Reclassifications and Adjustments
Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustments have been recorded which are not considered material either individually or in the aggregate.
In 2009, DPL recorded additional revenue of $14 million related to the unbilled portion of the Gas Cost Rate (GCR) revenue, which was not previously recognized. Because the GCR revenue is deferred, an additional expense of $14 million has also been recorded in 2009. Consequently, there is no impact on net income as a result of this adjustment.
During 2009, DPL recorded an adjustment to correct certain errors in the BSA calculation. The adjustment resulted in a decrease in revenue of $1 million for the year ended December 31, 2009.
During 2008, DPL recorded adjustments to correct errors in Other Operation and Maintenance expenses for prior periods dating back to May 2006 during which (i) customer late payment fees were incorrectly recognized and (ii) stock-based compensation expense related to certain restricted stock awards granted under the Long-Term Incentive Plan was understated. These adjustments resulted in a total increase in Other Operation and Maintenance expenses of $5 million for the year ended December 31, 2008, all of which related to prior periods.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Business Combinations (ASC 805)
The accounting guidance on business combinations was amended by the FASB effective beginning January 1, 2009. The amendment did not change the fundamental concepts that the acquisition method of accounting be used and that an acquirer must be identified for each business combination. However, the guidance expanded the definition of a business subject to this guidance and also requires the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.
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DELMARVA POWER & LIGHT COMPANY
On April 1, 2009, the FASB issued additional guidance to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The additional guidance requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with FASB guidance on contingencies (ASC 450).
The new guidance applied prospectively to business combinations for which the acquisition date was on or after January 1, 2009. The adoption of the guidance did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.
Fair Value Measurement and Disclosures (ASC 820)
There is a variety of new accounting guidance from the FASB that was effective for different financial reporting periods during 2009. Nonrecurring fair value measurement guidance for non-financial assets and non-financial liabilities was effective beginning January 1, 2009 for DPL. The adoption of this guidance did not have a material impact on the fair value measurements of DPL’s nonfinancial assets and non-financial liabilities.
New FASB guidance for the fair value measurement of liabilities issued with inseparable third-party credit enhancements was also effective beginning January 1, 2009 for DPL. The guidance applies to liabilities such as debt, derivatives, and other instruments that are guaranteed by third parties. The effect of the credit enhancement may not be included in the fair value measurement of the liability, even if the liability has an inseparable third-party credit enhancement. The issuer is required to disclose the existence of the inseparable third-party credit enhancement on the issued liability. The adoption of the guidance did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.
DPL adopted new FASB guidance in the second quarter of 2009 for fair value measurement when markets are inactive and distressed. This guidance was effective for interim periods ending after June 15, 2009. The guidance outlines a two-step test to identify inactive and distressed markets and provides a fair value application example for financial instruments when both conditions are met. The guidance primarily applies to DPL’s valuation of derivatives valued using information from inactive and distressed markets. Use of such information requires management to exercise judgment regarding how the market information is incorporated into the measurement of fair value. This guidance did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.
Effective beginning with its June 30, 2009 financial statements, DPL began disclosing the fair value of debt issued by DPL on a quarterly basis in Note (14), “Fair Value Disclosures,” in accordance with FASB guidance which was effective for interim reporting periods ending after June 15, 2009.
The FASB issued new guidance on the fair value measurement of liabilities when there is a lack of observable market information. The guidance clarifies that, when a quoted price is not available for the identical liability, an entity can use the quoted price of the identical liability when it is traded as an asset, the quoted price for a similar liability, or the quoted price for a similar liability when it is traded as an asset. If these prices are not available, then entities can employ an income or market valuation approach that considers what the entity would pay to transfer the identical liability or would receive to enter into the identical liability. The guidance was effective for DPL starting October 1, 2009, and it did not have an impact on DPL’s overall financial condition, results of operations, or cash flows.
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NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
Derivatives and Hedging Disclosures (ASC 815)
The FASB issued new disclosure requirements for derivatives and hedging effective for financial statement reporting periods beginning January 1, 2009 for DPL. Some of the new disclosures include derivative objectives and strategies, derivative volumes by product type, classification and gross fair values of derivative assets and liabilities, classification and amounts of gains and losses on derivatives and related hedged items, and credit-risk-related contingent features in derivatives. DPL adopted the new requirements beginning with its March 31, 2009 financial statements with comparative disclosures for prior reporting periods. The disclosures are included within Note (13), “Derivative Instruments and Hedging Activities.”
Subsequent Events (ASC 855)
Beginning with its June 30, 2009 financial statements, DPL adopted new FASB guidelines for the disclosure of events that occur after the balance sheet reporting date, but before the financial statements are issued. The new guidance requires the disclosure of the date through which DPL has assessed the impact of subsequent events on the financial statements. The new guidance was effective for interim or annual financial periods ending after June 15, 2009. DPL has disclosed this subsequent events date in Note (2), “Significant Accounting Policies.”
FASB Accounting Standards Codification (ASC 105)
The ASC identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of nongovernmental financial statements presented under GAAP. In addition, it replaces the reference system for standards and guidance with a new numerical designation system known as the ASC. The ASC is the single source reference system for all authoritative GAAP.
The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. DPL adopted the ASC guidance and referencing system for GAAP in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references to GAAP. The adoption of ASC did not result in a change in accounting principle for DPL; therefore, it did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
Transfers and Servicing (ASC 860)
The FASB issued new guidance that removes the concept of a qualifying special-purpose entity (QSPE) from the current guidance on transfers and servicing and the QSPE scope exception in current guidance on consolidation. The new guidance also changes the requirements for derecognizing financial assets and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets.
The new guidance is effective for transfers of financial assets occurring in fiscal periods beginning after November 15, 2009; therefore, this guidance will be effective on January 1, 2010 for DPL. DPL does not expect this standard will have a material impact on its overall financial condition and financial statements.
Consolidation of Variable Interest Entities (ASC 810)
The FASB issued new consolidation guidance regarding variable interest entities that eliminates the existing quantitative analysis requirement and adds new qualitative factors to determine whether consolidation is required. The new qualitative factors would be applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the
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NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retained the existing provision that allowed entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine the primary beneficiary.
The new guidance is effective for fiscal periods beginning after November 15, 2009 for existing and newly created entities; therefore, this guidance will be effective on January 1, 2010 for DPL. DPL does not expect that the new guidance will result in a material change in accounting or disclosures in its financial statements.
Fair Value Measurement and Disclosures (ASC 820)
The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. Some of the requirements will be effective for DPL beginning with its March 31, 2010 financial statements and include: (i) a disaggregation of balance sheet categories that are measured at fair value into classes (i.e. subsets of assets or liabilities within a balance sheet line item), (ii) a description of pricing inputs and valuation methodologies for instruments with Level 2 and 3 valuation inputs, and (iii) a reconciliation of transfers of instruments between Level 1 and 2 valuation categories. Beginning with its March 31, 2011 financial statements, DPL will be required to disaggregate the Level 3 fair value measurement reconciliations into separate categories for purchases, sales, issuances, and settlements. DPL is evaluating the impact of this new guidance on its financial statement footnote disclosures.
(5) SEGMENT INFORMATION
The company operates its business as one regulated utility segment, which includes all of its services as described above.
(6) GOODWILL
DPL’s goodwill balance of $8 million was unchanged during the year ended December 31, 2009. All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.
DPL’s annual impairment test as of November 1, 2009 indicated that goodwill was not impaired at October 31, 2009. As of December 31, 2009, after review of its significant assumptions in the goodwill impairment analysis, DPL concluded that there were no events requiring DPL to perform an interim goodwill impairment test. DPL performed an interim impairment test as of December 31, 2008, which indicated that goodwill was not impaired.
In order to estimate the fair value of DPL’s business, DPL reviews the results from two discounted cash flow models. The models differ in the method used to calculate the terminal value of the reporting unit. One model estimates terminal value based on a constant annual cash flow growth rate that is consistent with DPL’s long-term view of the business, and the other model estimates terminal value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. The models use a cost of capital appropriate for a regulated utility as the discount rate. DPL has consistently used this valuation approach to estimate the fair value of DPL’s business.
The estimation of fair value is dependent on a number of factors that are derived from the DPL business forecast, including but not limited to interest rates, growth assumptions, returns on rate base, operating and capital expenditure requirements, and other factors, changes in which could materially affect the results of impairment testing. Assumptions used in the models were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the DPL business include utility sector market performance, sustained adverse business conditions, changes in forecasted revenues, higher operating and capital expenditure requirements, a significant increase in the cost of capital and other factors.
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DELMARVA POWER & LIGHT COMPANY
With the continuing volatile general market conditions and the disruptions in the credit and capital markets, DPL will continue to closely monitor for indicators of goodwill impairment.
(7) REGULATORY ASSETS AND REGULATORY LIABILITIES
The components of DPL’s regulatory asset balances at December 31, 2009 and 2008 are as follows:
The components of DPL’s regulatory liability balances at December 31, 2009 and 2008 are as follows:
A description for each category of regulatory assets and regulatory liabilities follows:
Deferred Energy Supply Costs: This regulatory asset represents primarily deferred energy costs associated with a net under-recovery of Default Electricity Supply costs incurred in Maryland and deferred fuel costs for DPL’s gas business. The gas deferred fuel costs are recovered over a twelve month period and include a return component. The regulatory liability represents primarily deferred energy and transmission costs associated with a net over-recovery of Default Electricity Supply costs incurred in Delaware and does not earn a return.
Deferred Income Taxes: Represents a receivable from our customers for tax benefits DPL has previously flowed through before the company was ordered to account for the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed. There is no return earned on these deferrals.
Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period. A return is earned on these deferrals.
Phase In Credits: Represented phase-in credits for participating Maryland and Delaware residential and small commercial customers to mitigate the immediate impact of significant rate increases due to energy costs in 2006. The deferral period for Delaware was May 1, 2006 to January 1, 2008 with recovery occurring over a 17-month period beginning January 2008. The Delaware deferral was recovered from
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DELMARVA POWER & LIGHT COMPANY
participating customers on a straight-line basis. The deferral period for Maryland was June 1, 2006 to June 1, 2007, with the recovery occurring over an 18-month period beginning June 2007. Recovery of all deferred amounts was completed during 2009. There was no return earned on these deferrals.
COPCO Acquisition Adjustment: On July 19, 2007, the MPSC issued an order which provided for the recovery of a portion of DPL’s goodwill. As a result of this order, $41 million in DPL goodwill was transferred to a regulatory asset. This item earns a 12.95% return and will be amortized from August 2007 through August 2018.
Gas derivatives: Represents losses associated with the hedge of gas transactions that are recoverable through the Gas Cost Rate approved by the Delaware Public Service Commission. A return is earned on these deferrals.
Other: Represents miscellaneous regulatory assets that are generally being amortized over 1 to 20 years and generally do not earn a return.
Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax liabilities applicable to DPL’s utility operations that have not been reflected in current customer rates, for which future payment to customers is probable. As temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return earned on these deferrals.
Asset Removal Costs: DPL’s depreciation rates include a component for removal costs, as approved by its federal and state regulatory commissions. DPL has recorded a regulatory liability for their estimate of the difference between incurred removal costs and the level of removal costs recovered through rates. There is no return earned on these deferrals.
Other: Includes over-recovery of administrative costs associated with Default Electricity Supply in Delaware and Maryland. There is no return earned on these deferrals.
(8) LEASING ACTIVITIES
DPL leases an 11.9% interest in the Merrill Creek Reservoir. The lease is an operating lease and payments over the remaining lease term, which ends in 2032, are $102 million in the aggregate. DPL also has long-term leases for certain other facilities and equipment. Total future minimum operating lease payments for DPL, including the Merrill Creek Reservoir lease, as of December 31, 2009, are $18 million in 2010, $7 million in each of the years 2011 through 2014, and $97 million thereafter.
Rental expense for operating leases, including the Merrill Creek Reservoir lease, was $9 million, $9 million and $10 million for the years ended December 31, 2009, 2008 and 2007, respectively.
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(9) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of the following:
The balances of all property, plant and equipment, which are primarily electric transmission and distribution property, are stated at original cost. Utility plant is generally subject to a first mortgage lien.
Asset Sales
In January 2008, DPL completed (i) the sale of its retail electric distribution assets on the Eastern Shore of Virginia for a purchase price of approximately $49 million, and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia for a purchase price of approximately $5 million.
(10) PENSIONS AND OTHER POSTRETIREMENT BENEFITS
DPL accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. For 2009, 2008, and 2007, DPL was responsible for $25 million, $3 million and $4 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings. DPL made discretionary, tax-deductible contributions of $10 million to the PHI Retirement Plan for the year ended December 31, 2009. No contributions were made for the years ended December 31, 2008 and 2007. In addition, DPL made contributions of $10 million, $9 million and $9 million, respectively to the other postretirement benefit plans for the years ended December 31, 2009, 2008 and 2007. At December 31, 2009 and 2008, DPL’s prepaid pension expense of $157 million and $184 million, and other postretirement benefit obligation of $23 million and $4 million, effectively represent assets and benefit obligations resulting from DPL’s participation in the Pepco Holdings benefit plans.
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(11) DEBT
Long-Term Debt
Long-term debt outstanding as of December 31, 2009 and 2008 is presented below:
(a) The bonds are subject to mandatory tender on July 1, 2010.
(b) The bonds are subject to mandatory tender on May 1, 2011.
(c) Represents a series of First Mortgage Bonds issued by DPL (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued for the benefit of the company. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligations in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes and tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.
(d) In September 2009, DPL issued Collateral First Mortgage Bonds to secure its reimbursement obligations under a bond insurance policy insuring the principal and interest payments on this series of tax-exempt bonds previously issued for the benefit of DPL. Because this series of tax-exempt bonds and the related series of Collateral First Mortgage Bonds effectively represents a single financial obligation, the tax-exempt bonds are no longer shown as outstanding on the table and instead the debt obligation is represented by the related series of Collateral First Mortgage Bonds.
(e) In September 2009, DPL issued Collateral First Mortgage Bonds to secure its reimbursement obligations under a bond insurance policy insuring the principal and interest payments on this series of notes previously issued by DPL. Because this series of notes and the related series of Collateral First Mortgage Bonds effectively represent a single financial obligation, the notes are no longer shown as outstanding on the table and instead the debt obligation is represented by the related series of Collateral First Mortgage Bonds.
The outstanding First Mortgage Bonds issued by DPL are subject to a lien on substantially all of DPL’s property, plant and equipment.
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Maturities of long-term debt and sinking fund requirements during the next five years are as follows: $31 million in 2010, $35 million in 2011, zero in 2012, $250 million in 2013, $100 million in 2014, and $271 million thereafter.
DPL’s long-term debt is subject to certain covenants. DPL is in compliance with all requirements.
Short-Term Debt
DPL has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. A detail of the components of DPL’s short-term debt at December 31, 2009 and 2008 is as follows:
Commercial Paper
DPL maintains an ongoing commercial paper program of up to $500 million. The commercial paper notes can be issued with maturities up to 270 days from the date of issue. The commercial paper program is backed by DPL’s borrowing capacity under the $1.5 billion credit facility described below under the heading “Credit Facility.”
DPL had no commercial paper outstanding at December 31, 2009 and 2008. The weighted average interest rates for commercial paper issued during 2009 and 2008 were 0.56% and 3.88%, respectively. The weighted average maturity for commercial paper issued during 2009 and 2008 was five days.
Variable Rate Demand Bonds
Variable Rate Demand Bonds (VRDBs) are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. DPL expects the bonds submitted for purchase will continue to be remarketed successfully due to the credit worthiness of the company and because the remarketing agent resets the interest rate to the then-current market rate. The company also may utilize one of the fixed rate fixed term conversion options of the bonds to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, DPL views VRDBs as a source of long-term financing. The VRDBs outstanding in 2009 mature as follows: 2017 ($26 million), 2024 ($33 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDBs was 1.78% during 2009 and 3.24% during 2008. Of the $105 million in VRDBs, $72 million of DPL’s obligations are secured by Collateral First Mortgage Bonds, which provide collateral to the investors in the event of a default by DPL.
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DELMARVA POWER & LIGHT COMPANY
Credit Facility
PHI, Potomac Electric Power Company (Pepco), DPL and Atlantic City Electric Company (ACE) maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under this credit facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million. The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate and the federal funds effective rate plus 0.5% or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. The facility also includes a “swingline loan sub-facility” pursuant to which each company may make same day borrowings in an aggregate amount not to exceed $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof.
The facility commitment expiration date is May 5, 2012, with each company having the right to elect to have 100% of the principal balance of the loans outstanding on the expiration date continued as non-revolving term loans for a period of one year from such expiration date.
The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. As of December 31, 2009, each borrower was in compliance with the covenants of the credit facility.
The absence of a material adverse change in the borrower’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers.
At December 31, 2009 and 2008, the amount of cash, plus borrowing capacity under the PHI credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $582 million and $843 million, respectively.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
(12) INCOME TAXES
DPL, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.
The provision for income taxes, reconciliation of income tax rate, and components of deferred income tax liabilities (assets) are shown below.
Provision for Income Taxes
Reconciliation of Income Tax Rate
In March 2009, the Internal Revenue Service (IRS) issued a Revenue Agent’s Report (RAR) for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to DPL’s capitalization of overhead costs for tax purposes and the deductibility of certain DPL casualty losses. In conjunction with PHI, DPL has appealed certain of the proposed adjustments and believes it has adequately reserved for the adjustments included in the RAR.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
In November 2009, DPL received a refund of prior years’ Federal income taxes of $10 million. The refund results from the carry back of a 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions paid in 2009 (which were deducted in 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs.
During 2008, DPL completed an analysis of its current and deferred income tax accounts and, as a result, recorded a $2 million charge to income tax expense in 2008, which is primarily included in “Adjustments to prior years’ taxes” in the reconciliation provided above. In addition, during 2008, DPL recorded after-tax net interest income of $3 million under FASB guidance on income taxes (ASC 740) primarily related to the reversal of previously accrued interest payable resulting from a favorable tentative settlement of the mixed service cost issue with the IRS.
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate
Unrecognized tax benefits represent those tax benefits related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2009, DPL had no unrecognized tax benefits that, if recognized, would lower the effective tax rate.
Interest and Penalties
DPL recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2009, 2008 and 2007, DPL recognized $3 million of interest income pre-tax ($2 million after-tax), $5 million of interest income pre-tax ($3 million after-tax), and $2 million of interest expense pre-tax ($1 million after-tax), respectively, as a component of income tax expense. As of December 31, 2009, 2008 and 2007, DPL had $1 million, $3 million and $6 million, respectively, of accrued interest payable related to effectively settled and uncertain tax positions.
Possible Changes to Unrecognized Tax Benefits
It is reasonably possible that the amount of the unrecognized tax benefit with respect to certain of DPL’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The final settlement of the mixed service cost issue or other federal or state audits could impact the balances significantly. At this time, other than the mixed service cost issue, an estimate of the range of reasonably possible outcomes cannot be determined. The unrecognized benefit related to the mixed service cost issue could decrease by $22 million within the next 12 months upon final resolution of the tentative settlement with the IRS. See Note (15), “Commitments and Contingencies,” for additional information.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
Tax Years Open to Examination
DPL, as an indirect subsidiary of PHI, is included on PHI’s consolidated federal tax return. DPL’s federal income tax liabilities for all years through 1999 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where DPL files state income tax returns (Maryland, Delaware, and Virginia) are the same as for the federal returns.
Components of Deferred Income Tax Liabilities (Assets)
The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to DPL’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2009 and 2008.
The Tax Reform Act of 1986 repealed the investment tax credit (ITC) for property placed in service after December 31, 1985, except for certain transition property. ITC previously earned on DPL’s property continues to be amortized to income over the useful lives of the related property.
Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
DPL uses derivative instruments in the form of forward contracts, futures, swaps, and exchange-traded and over-the-counter options primarily to reduce gas commodity price volatility and limit its customers’ exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that are not classified as derivatives. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered based on the fuel adjustment clause approved by the DPSC.
The table below identifies the balance sheet location and fair values of derivative instruments as of December 31, 2009 and 2008:
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
Under FASB guidance on the offsetting of balance sheet accounts (ASC 210), DPL offsets the fair value amounts recognized for derivative instruments and fair value amounts recognized for related collateral positions executed with the same counterparty under a master netting arrangement. The amount of cash collateral that was offset against these derivative positions is as follows:
As of December 31, 2009 and 2008, DPL had no cash collateral pledged or received related to derivatives accounted for at fair value that was not entitled to be offset under master netting arrangements.
Derivatives Designated as Hedging Instruments
Cash Flow Hedges
As described above, all premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered through a fuel adjustment clause approved by the DPSC. The following table indicates the amounts deferred as regulatory assets or liabilities and the location in the statements of income of amounts reclassified to income through the fuel adjustment clause for the years ended December 31, 2009 and 2008:
As of December 31, 2009 and 2008, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
Other Derivative Activity
DPL holds certain derivatives that do not qualify as hedges. Under FASB guidance on derivatives and hedging, these derivatives are recorded at fair value on the balance sheet with the gain or loss recorded in income. In accordance with FASB guidance on regulatory operations, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred. For the years ended December 31, 2009 and 2008, the amounts of the derivative gain (loss) recognized by line item in the statements of income are provided in the table below:
As of December 31, 2009 and 2008, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:
Contingent Credit Risk Features
The primary contracts used by DPL for derivative transactions are entered into under an International Swaps and Derivatives Association Master Agreement (ISDA) or similar agreements that closely mirror the principal credit provisions of the ISDA. The ISDAs include a Credit Support Annex (CSA) that governs the mutual posting and administration of collateral security. The failure of a party to comply with an obligation under the CSA, including an obligation to transfer collateral security when due or the failure to maintain any required credit support, constitutes an event of default under the ISDA for which the other party may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.
The collateral requirements under the ISDA or similar agreements generally work as follows. The parties establish a dollar threshold of unsecured credit for each party in excess of which the party is required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold generally varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on the balance sheet or normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions is a net loss position that exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If DPL’s credit rating were to fall below “investment grade,” the unsecured credit threshold would typically be zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
The gross fair value of DPL’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit-risk-related contingent features on December 31, 2009, was $28 million. As of that date, DPL had posted cash collateral of less than a million dollars in the normal course of business against the gross derivative liability resulting in a net liability of $28 million before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. PHI’s net settlement amount in the event of a downgrade of DPL below “investment grade” as of December 31, 2009, would have been approximately $24 million after taking into account the master netting agreements.
At December 31, 2009 and 2008, the amount of cash, plus borrowing capacity under the $1.5 billion credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $582 million and $843 million, respectively.
(14) FAIR VALUE DISCLOSURES
Fair Value of Assets and Liabilities Excluding Debt
Effective January 1, 2008, DPL adopted FASB guidance on fair value measurement and disclosures (ASC 820) which established a framework for measuring fair value and expanded disclosures about fair value measurements.
As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). DPL utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, DPL utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. DPL is able to classify fair value balances based on the observability of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets, and other observable pricing data. Level 2 also includes those financial instruments that are valued using internally developed methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 - Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial investments that are valued using models or other valuation methodologies. DPL’s level 3 instruments are natural gas options purchased as part of a natural gas hedging program approved by the DPSC. Some non-standard assumptions are used in their forward valuation to adjust for the pricing; otherwise, most of the options follow NYMEX valuation. A few of the options have no significant NYMEX components, and have to be priced using internal volatility assumptions.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
Executive deferred compensation plan assets classified as Level 3 instruments consist of life insurance policies that are valued using the cash surrender value of the policies which does not represent a quoted price in an active market.
The following tables set forth by level within the fair value hierarchy DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009 and 2008. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2009 and 2008 are shown below:
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
Fair Value of Debt Instruments
The estimated fair values of DPL’s non-derivative financial instruments as of December 31, 2009 and 2008 are shown below:
The fair values of the long-term debt, which includes First Mortgage Bonds, Unsecured Tax-Exempt Bonds, Medium-Term Notes, and Unsecured Notes, including amounts due within one year, were derived based on current market prices, or were based on discounted cash flows using current rates for similar issues with similar terms and remaining maturities for issues with no market price available.
(15) COMMITMENTS AND CONTINGENCIES
Regulatory and Other Matters
Rate Proceedings
In recent electric service distribution base rate cases, DPL has proposed the adoption of revenue decoupling methods for retail customers. To date:
•
A BSA has been approved and implemented for DPL electric service in Maryland.
•
A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric service in Delaware and may be implemented in DPL’s pending electric base rate case.
•
A MFVRD has been approved in concept for DPL natural gas service in Delaware and may be implemented either in the context of a pending decoupling case or DPL’s next Delaware natural gas distribution base rate case.
Under the BSA, customer delivery rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The BSA increases rates if actual distribution revenues fall below the approved level and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, DPL collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” distribution revenue from unit sales consumption and ties the growth in distribution revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for DPL to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and distribution revenues. The MFVRD adopted in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, DPL views the MFVRD as an appropriate distribution revenue decoupling mechanism.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
Delaware
In August 2008, DPL submitted its 2008 GCR filing to the DPSC, requesting an increase in the level of GCR, which permits DPL to recover gas procurement costs through customer rates. In September 2008, the DPSC issued an initial order approving the requested increase, which became effective on November 1, 2008, subject to refund pending final DPSC approval after evidentiary hearings. Due to a significant decrease in wholesale gas prices, DPL in January 2009 submitted to the DPSC an interim GCR filing, requesting a decrease in the level of GCR. The proposed decrease became effective on a temporary basis on March 1, 2009, and when combined with the increase that became effective November 1, 2008, had the net effect of a 13.8% increase in the level of GCR. On October 6, 2009, the DPSC issued a final order approving the 13.8% net increase, reflecting a settlement agreement among DPL, the DPSC staff and the Delaware Public Advocate.
On August 31, 2009, DPL submitted its 2009 GCR filing to the DPSC, requesting a 10.2% decrease in the level of GCR, to become effective on a temporary basis on November 1, 2009. This rate proposal was approved by the DPSC on September 9, 2009, subject to refund and pending final DPSC approval.
On September 18, 2009, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $28 million, assuming approval of the implementation of the MFVRD, based on a requested return on equity (ROE) of 10.75% (if implementation of the MFVRD is not approved, the increase would be $29 million, based on an ROE of 11.00%). DPL placed an increase of approximately $2.5 million annually into effect on a temporary basis on November 17, 2009, subject to refund and pending final DPSC approval of the entirety of the requested increase. As permitted by Delaware law, DPL currently anticipates that it will place the remaining $25.5 million of the requested increase into effect on April 19, 2010, subject to refund and pending the final DPSC order. The DPSC has established a procedural schedule that provides for hearings in April 2010 and a DPSC decision in July 2010.
On June 25, 2009, DPL filed an application requesting approval for the implementation of the MFVRD for gas distribution rates. This filing is based on revenues established in DPL’s last gas distribution base rate case, and accordingly is revenue neutral. On August 4, 2009, the DPSC issued an order opening a docket for the matter. A similar application on June 25, 2009 requesting approval for the implementation of the MFVRD for electric distribution rates has been consolidated with the electric distribution base rate proceeding discussed above.
Maryland
On May 6, 2009, DPL filed an electric distribution base rate case in Maryland. The filing sought approval of an annual rate increase of approximately $14 million, based on a requested ROE of 11.25%. On December 2, 2009, the MPSC approved an annual increase of approximately $7.5 million, based on an overall rate of return of 7.96%, including an ROE of 10%. The MPSC rejected a proposed surcharge mechanism for pension, other postretirement benefits and uncollectible expenses. The rate increase was implemented through rates that are effective for electric usage on and after December 2, 2009.
Environmental Litigation
DPL is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. DPL 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. Although penalties assessed for violations of environmental laws and regulations are not recoverable from DPL’s customers, environmental clean-up costs incurred by DPL would be included in its cost of service for ratemaking purposes.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
Ward Transformer Site. In April 2009, a group of potentially responsible parties (PRPs) with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against DPL with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. With the court’s permission, the plaintiffs filed amended complaints on September 1, 2009. DPL, as part of a group of defendants, filed a motion to dismiss on October 13, 2009. Although it is too early in the process to characterize the magnitude of the potential liability at this site, it does not appear that DPL had extensive business transactions, if any, with the Ward Transformer site.
IRS Mixed Service Cost Issue
During 2001, DPL changed its method of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed the company to accelerate the deduction of certain expenses that were previously capitalized and depreciated. As a result of this method change, DPL generated incremental tax cash flow benefits of approximately $62 million.
In 2005, the IRS issued Revenue Ruling 2005-53, which limited the ability of DPL to utilize its tax accounting method on its 2001 through 2004 tax returns. In accordance with this Revenue Ruling, the RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that DPL had claimed on those returns.
In March 2009, PHI reached a tentative settlement with the IRS for all years (2001 through 2004). The terms of the settlement reduced the tax benefits related to the mixed service costs deductions by $12 million for DPL.
Contractual Obligations
As of December 31, 2009, DPL’s contractual obligations under non-derivative fuel and power purchase contracts were $40 million in 2010, $77 million in 2011 to 2012, $74 million in 2013 to 2014, and $368 million in 2015 and thereafter.
(16) RELATED PARTY TRANSACTIONS
PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the years ended December 31, 2009, 2008 and 2007 were $130 million, $121 million, and $118 million, respectively.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
In addition to the PHI Service Company charges described above, DPL’s financial statements include the following related party transactions in its Statements of Income:
(a) Included in purchased energy expense.
(b) Included in electric revenue.
(c) Included in gas revenue.
(d) Included in gas purchased expense.
As of December 31, 2009 and 2008, DPL had the following balances on its balance sheets due (to) from related parties:
(a) DPL bills customers on behalf of Pepco Energy Services where customers have selected Pepco Energy Services as their alternative supplier.
DPL
NOTES TO FINANCIAL STATEMENTS-(Continued)
DELMARVA POWER & LIGHT COMPANY
(17) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.
(a) Includes benefit of $13 million related to a change in the Maryland state income tax reporting for the disposition of certain assets in prior years.
(b) Includes $3 million of after-tax net interest income on uncertain tax positions primarily related to casualty losses.
(c) Includes $2 million of after-tax interest income related to the tentative settlement of the IRS mixed service cost issue.
(d) Includes a $2 million charge related to an adjustment in the accounting for certain restricted stock awards granted under the Long-Term Incentive Plan (LTIP) and a $4 million adjustment to correct an understatement of operating expenses for prior periods dating back to May 2006 where late payment fees were incorrectly recognized.
(e) Includes $3 million of after-tax net interest expense on uncertain and effectively settled tax positions (primarily associated with the reversal of the majority of the interest income recognized on uncertain tax positions related to casualty losses in the first quarter), and a charge of $2 million to correct prior period errors related to additional analysis of deferred tax balances completed in 2008.
ACE
Management’s Report on Internal Control over Financial Reporting
The management of ACE is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed its internal control over financial reporting as of December 31, 2009 based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of ACE concluded that ACE’s internal control over financial reporting was effective as of December 31, 2009.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the consolidated financial statements of ACE included in this Annual Report on Form 10-K, has also issued its attestation report on the effectiveness of ACE’s internal control over financial reporting, which is included herein.
ACE
Report of Independent Registered Public Accounting Firm
To the Shareholder and Board of Directors of Atlantic City Electric Company
In our opinion, the consolidated financial statements listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Atlantic City Electric Company (a wholly owned subsidiary of Pepco Holdings, Inc.) and its subsidiary at December 31, 2009 and December 31, 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our audits, which was an integrated audit in 2009. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
ACE
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 26, 2010
ACE
ATLANTIC CITY ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
The accompanying Notes are an integral part of these Consolidated Financial Statements.
ACE
ATLANTIC CITY ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
ACE
ATLANTIC CITY ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
ACE
ATLANTIC CITY ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
ACE
ATLANTIC CITY ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF EQUITY
The accompanying Notes are an integral part of these Consolidated Financial Statements.
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ATLANTIC CITY ELECTRIC COMPANY
(1) ORGANIZATION
Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is also known as Basic Generation Service (BGS) in New Jersey. ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).
(2) SIGNIFICANT ACCOUNTING POLICIES
Consolidation Policy
The accompanying consolidated financial statements include the accounts of ACE and its wholly owned subsidiary ACE Transition Funding. All intercompany balances and transactions between subsidiaries have been eliminated. ACE uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies where it holds a 20% to 50% voting interest and cannot exercise control over the operations and policies of the investee. Individual interests in several jointly owned electric plants previously held by ACE, and certain transmission and other facilities currently held are consolidated in proportion to ACE’s percentage interest in the facility.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although ACE believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.
Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, and income tax provisions and reserves. Additionally, ACE is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. ACE records an estimated liability for these proceedings and claims when the loss is determined to be probable and is reasonably estimable.
Revenue Recognition
ACE recognizes revenue upon delivery of electricity to its customers, including amounts for electricity delivered but not yet billed (unbilled revenue). ACE recorded amounts for unbilled revenue of $42 million and $45 million as of December 31, 2009 and December 31, 2008, respectively. These amounts are included in Accounts Receivable. ACE calculates unbilled revenue using an output based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers), all of which are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material.
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
Taxes related to the delivery of electricity to its customers are a component of ACE’s tariffs and, as such, are billed to customers and recorded in Operating Revenues. Accruals for these taxes by ACE are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by ACE in the normal course of business is charged to operations, maintenance or construction, and is not material.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in ACE’s gross revenues were $22 million, $22 million and $23 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Long-Lived Asset Impairment Evaluation
ACE evaluates certain long-lived assets to be held and used (for example, equipment and real estate) to determine if they are impaired whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner an asset is being used or its physical condition. A long-lived asset to be held and used is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount.
For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying amount exceeds its fair value including costs to sell.
Income Taxes
ACE, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of Pepco Holdings. Federal income taxes are allocated to ACE based upon the taxable income or loss amounts, determined on a separate return basis.
On May 2, 2007, the FASB issued guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. ACE applied the guidance on January 1, 2007.
The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on ACE’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.
Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and are measured using presently enacted tax rates. The portion of ACE’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the Consolidated Balance Sheets. See Note (6), “Regulatory Assets and Regulatory Liabilities,” for additional information.
Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.
ACE recognizes interest on under/over payments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.
Investment tax credits are being amortized to income over the useful lives of the related property.
ACE
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ATLANTIC CITY ELECTRIC COMPANY
Consolidation of Variable Interest Entities
In accordance with the provisions of Financial Accounting Standards Board (FASB) guidance on variable interest entities (Accounting Standards Codification (ASC) 810), ACE consolidates those variable interest entities with respect to which ACE is the primary beneficiary. The guidance addresses conditions when an entity should be consolidated based upon variable interests rather than voting interests.
ACE has power purchase agreements (PPAs) with a number of entities, including three contracts with unaffiliated non-utility generators (NUGs). Due to a variable element in the pricing structure of the PPAs, ACE potentially assumes the variability in the operations of the plants operated by the NUGs and, therefore, has a variable interest in the entities. ACE continued, during 2009, to conduct exhaustive efforts to obtain information from these entities, but was unable to obtain sufficient information to conduct the analysis required under FASB guidance to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE has applied the scope exemption from the guidance for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.
Net purchase activities under the PPAs for the years ended December 31, 2009, 2008 and 2007, were approximately $282 million, $349 million and $327 million, respectively, of which approximately $262 million, $305 million and $292 million, respectively, consisted of power purchases under the PPAs. ACE does not have loss exposure under the NUGs because the costs are recoverable from ACE’s customers through regulated rates.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, cash invested in money market funds, and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s “money pool,” which ACE and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.
Restricted Cash Equivalents
Restricted cash equivalents represents cash either held as collateral or pledged as collateral, and is restricted from use for general corporate purposes.
Accounts Receivable and Allowance for Uncollectible Accounts
ACE’s accounts receivable balance primarily consists of customer accounts receivable, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).
ACE maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other Operation and Maintenance expense in the Consolidated Statements of Income. ACE determines the amount of allowance based on specific identification of material amounts at risk by customer and maintains a general reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment, and changes in the creditworthiness of its customers. Although management believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, ACE records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment becomes known.
ACE
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ATLANTIC CITY ELECTRIC COMPANY
Inventories
Included in inventories are transmission and distribution materials and supplies. ACE utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies inventory are generally charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Regulatory Assets and Regulatory Liabilities
Certain aspects of ACE’s business are subject to regulation by the New Jersey Board of Public Utilities (NJBPU). The transmission and wholesale sale of electricity by ACE are regulated by the Federal Energy Regulatory Commission.
Based on the regulatory framework in which it has operated, ACE has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to establish regulatory assets and to defer the income statement impact of certain costs that are expected to be recovered in future rates. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders, and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset will be eliminated through a charge to earnings.
Property, Plant and Equipment
Property, plant and equipment are recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs, including capitalized interest. The carrying value of property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation.
The annual provision for depreciation on electric property, plant and equipment is computed on the straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Property, plant and equipment other than electric facilities is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite depreciation rates for 2009, 2008 and 2007 for ACE’s transmission and distribution system property were approximately 2.8%, 2.8% and 2.9%, respectively.
Capitalized Interest and Allowance for Funds Used During Construction
In accordance with FASB guidance on regulated operations (ASC 980), utilities can capitalize as Allowance for Funds Used During Construction (AFUDC) the capital costs of financing the construction of plant and equipment. The debt portion of AFUDC is recorded as a reduction of “interest expense” and the equity portion of AFUDC is credited to “other income” in the accompanying Consolidated Statements of Income.
ACE recorded AFUDC for borrowed funds of $2 million for each of the years ended December 31, 2009, 2008 and 2007.
ACE recorded amounts for the equity component of AFUDC of $1 million for each of the years ended December 31, 2009, 2008 and 2007.
ACE
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ATLANTIC CITY ELECTRIC COMPANY
Leasing Activities
ACE’s lease transactions can include plant, office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.
Operating Leases
An operating lease generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, ACE’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.
Amortization of Debt Issuance and Reacquisition Costs
ACE defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issues. When refinancing existing debt, any unamortized premiums, discounts and debt issuance costs are classified as regulatory assets and are amortized generally over the life of the original issue. Any costs associated with the redemption of the existing debt are amortized over the life of the original issue.
Pension and Other Postretirement Benefit Plans
Pepco Holdings sponsors a non-contributory retirement plan that covers substantially all employees of ACE (the PHI Retirement Plan) and certain employees of other Pepco Holdings subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.
The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).
Dividend Restrictions
All of ACE’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of ACE to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and the regulatory requirement that ACE obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by ACE and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of the charter of ACE which impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Currently, the restriction in the ACE charter does not limit its ability to pay common stock dividends. ACE had approximately $143 million and $166 million of retained earnings available for payment of common stock dividends at December 31, 2009 and 2008, respectively.
Subsequent Events
ACE has evaluated all subsequent events through February 26, 2010, the date of issuance of the consolidated financial statements.
ACE
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ATLANTIC CITY ELECTRIC COMPANY
Reclassifications and Adjustments
Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustments have been recorded, which are not considered material either individually or in the aggregate.
During 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. These adjustments resulted in a decrease in income tax expense of $1 million for the year ended December 31, 2009.
During 2008, PHI identified an error in the accounting for certain of its restricted stock awards under the Long-Term Incentive Plan which resulted in an understatement of ACE’s stock-based compensation expense in 2006 and 2007. This error was corrected in 2008, resulting in an increase in ACE’s Other Operation and Maintenance expenses for the year ended December 31, 2008 of $1 million.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Business Combinations (ASC 805)
The accounting guidance on business combinations was amended by the FASB effective beginning January 1, 2009. The amendment did not change the fundamental concepts that the acquisition method of accounting be used and that an acquirer must be identified for each business combination. However, the guidance expanded the definition of a business subject to this guidance and also requires the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.
On April 1, 2009, the FASB issued additional guidance to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The additional guidance requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with FASB guidance on contingencies (ASC 450).
The new guidance applied prospectively to business combinations for which the acquisition date was on or after January 1, 2009. The adoption of the guidance did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.
Fair Value Measurement and Disclosures (ASC 820)
There is a variety of new accounting guidance from the FASB that was effective for different financial reporting periods during 2009. Nonrecurring fair value measurement guidance for non-financial assets and non-financial liabilities was effective beginning January 1, 2009 for ACE. The adoption of this guidance did not have a material impact on the fair value measurements of ACE’s nonfinancial assets and non-financial liabilities.
New FASB guidance for the fair value measurement of liabilities issued with inseparable third-party credit enhancements was also effective beginning January 1, 2009 for ACE. The guidance applies to liabilities such as debt, derivatives, and other instruments that are guaranteed by third parties. The effect of the credit enhancement may not be included in the fair value measurement of the liability, even if the liability has an inseparable third-party credit enhancement. The issuer is required to disclose the existence of the inseparable third-party credit enhancement on the issued liability. The adoption of the guidance did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.
ACE
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ATLANTIC CITY ELECTRIC COMPANY
ACE adopted new FASB guidance in the second quarter of 2009 for fair value measurement when markets are inactive and distressed. This guidance was effective for interim periods ending after June 15, 2009. The guidance outlines a two-step test to identify inactive and distressed markets and provides a fair value application example for financial instruments when both conditions are met. Use of such information requires management to exercise judgment regarding how the market information is incorporated into the measurement of fair value. This guidance did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.
Effective beginning with its June 30, 2009 financial statements, ACE began disclosing the fair value of debt issued by ACE on a quarterly basis in Note (13), “Fair Value Disclosures,” in accordance with FASB guidance which was effective for interim reporting periods ending after June 15, 2009.
The FASB issued new guidance on the fair value measurement of liabilities when there is a lack of observable market information. The guidance clarifies that, when a quoted price is not available for the identical liability, an entity can use the quoted price of the identical liability when it is traded as an asset, the quoted price for a similar liability, or the quoted price for a similar liability when it is traded as an asset. If these prices are not available, then entities can employ an income or market valuation approach that considers what the entity would pay to transfer the identical liability or would receive to enter into the identical liability. The guidance was effective for ACE starting October 1, 2009, and it did not have an impact on ACE’s overall financial condition, results of operations, or cash flows.
Consolidation (ASC 810)
The FASB established new accounting and reporting standards for a non-controlling interest (also called a “minority interest”) in a subsidiary and for the deconsolidation of a subsidiary. The new guidance clarified that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.
The guidance was effective prospectively for financial statement reporting periods beginning January 1, 2009 for ACE, except for the financial statement presentation and disclosure requirements which also apply to prior reporting periods presented. As of January 1, 2009, ACE adopted the provisions of this guidance and the provisions did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.
Subsequent Events (ASC 855)
Beginning with its June 30, 2009 financial statements, ACE adopted new FASB guidelines for the disclosure of events that occur after the balance sheet reporting date, but before the financial statements are issued. The new guidance requires the disclosure of the date through which ACE has assessed the impact of subsequent events on the financial statements. The new guidance was effective for interim or annual financial periods ending after June 15, 2009. ACE has disclosed this subsequent events date in Note (2), “Significant Accounting Policies.”
FASB Accounting Standards Codification (ASC 105)
The ASC identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of nongovernmental financial statements presented under GAAP. In addition, it replaces the reference system for standards and guidance with a new numerical designation system known as the ASC. The ASC is the single source reference system for all authoritative GAAP.
ACE
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ATLANTIC CITY ELECTRIC COMPANY
The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. ACE adopted the ASC guidance and referencing system for GAAP in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references to GAAP. The adoption of ASC did not result in a change in accounting principle for ACE; therefore, it did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
Transfers and Servicing (ASC 860)
The FASB issued new guidance that removes the concept of a qualifying special-purpose entity (QSPE) from the current guidance on transfers and servicing and the QSPE scope exception in current guidance on consolidation. The new guidance also changes the requirements for derecognizing financial assets and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets.
The new guidance is effective for transfers of financial assets occurring in fiscal periods beginning after November 15, 2009; therefore, this guidance will be effective on January 1, 2010 for ACE. ACE does not expect this standard will have a material impact on its overall financial condition and financial statements.
Consolidation of Variable Interest Entities (ASC 810)
The FASB issued new consolidation guidance regarding variable interest entities that eliminates the existing quantitative analysis requirement and adds new qualitative factors to determine whether consolidation is required. The new qualitative factors would be applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retained the existing provision that allowed entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine the primary beneficiary.
The new guidance is effective for fiscal periods beginning after November 15, 2009 for existing and newly created entities; therefore, this guidance will be effective on January 1, 2010 for ACE. ACE does not expect that the new guidance will result in a material change in accounting or disclosures in its financial statements.
Fair Value Measurement and Disclosures (ASC 820)
The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. Some of the requirements will be effective for ACE beginning with its March 31, 2010 financial statements and include: (i) a disaggregation of balance sheet categories that are measured at fair value into classes (i.e. subsets of assets or liabilities within a balance sheet line item), (ii) a description of pricing inputs and valuation methodologies for instruments with Level 2 and 3 valuation inputs, and (iii) a reconciliation of transfers of instruments between Level 1 and 2 valuation categories. Beginning with its March 31, 2011 financial statements, ACE will be required to disaggregate the Level 3 fair value measurement reconciliations into separate categories for purchases, sales, issuances, and settlements. ACE is evaluating the impact of this new guidance on its financial statement footnote disclosures.
(5) SEGMENT INFORMATION
The company operates its business as one regulated utility segment, which includes all of its services as described above.
ACE
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ATLANTIC CITY ELECTRIC COMPANY
(6) REGULATORY ASSETS AND REGULATORY LIABILITIES
The components of ACE’s regulatory asset balances at December 31, 2009 and 2008 are as follows:
The components of ACE’s regulatory liability balances at December 31, 2009 and 2008 are as follows:
A description for each category of regulatory assets and regulatory liabilities follows:
Securitized Stranded Costs: Includes contract termination payments under a contract between ACE and an unaffiliated non-utility generator and costs associated with the regulated operations of ACE’s electricity generation business which are no longer recoverable through customer rates. The recovery of these stranded costs has been securitized through the issuance by Atlantic City Electric Transition Funding LLC (ACE Funding) of transition bonds (Transition Bonds). A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. The stranded costs are amortized over the life of the Transition Bonds, which mature between 2010 and 2023. A return is earned on these deferrals with the exception of tax balances.
Deferred Income Taxes: Represents a receivable from our customers for tax benefits ACE has previously flowed through before the company was ordered to account for the tax benefit as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed. There is no return earned on these deferrals.
Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period. A return is earned on these deferrals.
Unrecovered Purchased Power Contract Costs: Represents deferred costs related to purchase power contracts entered into by ACE. The amortization period began in July 1994 and will end in May 2014. A return is earned on these deferrals.
Deferred Other Postretirement Benefit Costs: Represents the non-cash portion of other postretirement benefit costs deferred by ACE during 1993 through 1997. This cost is being recovered over a 15-year period that began on January 1, 1998. There is no return earned on this deferral.
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ATLANTIC CITY ELECTRIC COMPANY
Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years and generally do not earn a return.
Deferred Energy Supply Costs: This regulatory liability represents primarily deferred costs associated with a net over-recovery by ACE of Default Electricity Supply costs and other restructuring related costs incurred by ACE. There is no return earned on these deferrals.
Federal and New Jersey Tax Benefits, Related to Securitized Stranded Costs: Securitized stranded costs include a portion of stranded costs attributable to the future tax benefit expected to be realized when the higher tax basis of the generating plants divested by ACE is deducted for New Jersey state income tax purposes, as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE’s regulated electricity delivery customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service issues its final regulations with respect to normalization of these federal excess deferred taxes. There is no return earned on these deferrals.
Excess Depreciation Reserve: The excess depreciation reserve was recorded as part of an ACE New Jersey rate case settlement. This excess reserve is the result of a change in estimated depreciable lives and a change in depreciation technique from remaining life to whole life. The excess is being amortized over an 8.25 year period, which began in June 2005. There is no return earned on these deferrals.
Gain from Sale of Divested Assets: Represents (i) the balance of the net gain realized by ACE from the sale in 2006 of its interests in the Keystone and Conemaugh generating facilities and (ii) the balance of the net proceeds realized by ACE from the sale in 2007 of the B.L. England generating facility and the monetization of associated emission allowance credits. Both gains, including interest on the unamortized balance, have been returned to ACE’s ratepayers as a credit on their bills - the Keystone and Conemaugh gain over a 33-month period that began during the October 2006 billing period and the B.L. England and emission allowances proceeds over a 12-month period that began during the June 2008 billing period. There was no return earned on these deferrals.
Other: Includes miscellaneous regulatory liabilities that generally do not earn a return.
(7) LEASING ACTIVITIES
ACE leases certain types of property and equipment for use in its operations. Rental expense for operating leases was $9 million, $9 million and $10 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Total future minimum operating lease payments for ACE as of December 31, 2009 are $9 million in 2010, $2 million in each of the years 2011 through 2014, and $19 million thereafter.
ACE
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ATLANTIC CITY ELECTRIC COMPANY
(8) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of the following:
The balances of all property, plant and equipment, which are primarily electric transmission and distribution property, are stated at original cost. Utility plant is generally subject to a first mortgage lien.
Jointly Owned Plant
ACE’s Consolidated Balance Sheets include its proportionate share of assets and liabilities related to jointly owned plant. At December 31, 2009 and 2008, ACE’s subsidiaries had a $9 million net book value ownership interest in transmission and other facilities in which various parties also have ownership interests. ACE’s share of the operating and maintenance expenses of the jointly-owned plant is included in the corresponding expenses in the Consolidated Statements of Income. ACE is responsible for providing its share of the financing for the above jointly-owned facilities.
Asset Sales
In 2007, ACE completed the sale of the B.L. England generating facility for a price of $9 million. In 2008, ACE received an additional $4 million in settlement of an arbitration proceeding concerning the terms of the purchase agreement. See Note (6), “Regulatory Assets and Regulatory Liabilities,” for treatment of gains from these sales.
(9) PENSIONS AND OTHER POSTRETIREMENT BENEFITS
ACE accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. For 2009, 2008, and 2007, ACE was responsible for $20 million, $12 million and $11 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings. ACE made discretionary tax-deductible contributions of $60 million to the PHI Retirement Plan for the year ended December 31, 2009. No contributions were made for the years ended December 31, 2008 and 2007. In addition, ACE made contributions of $6 million, $7 million and $7 million, respectively, to the other postretirement benefit plans for the years ended December 31, 2009, 2008 and 2007. At December 31, 2009 and 2008, ACE’s prepaid pension
ACE
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ATLANTIC CITY ELECTRIC COMPANY
expense of $63 million and $6 million, and other postretirement benefit obligation of $25 million and $41 million, respectively, effectively represent assets and benefit obligations resulting from ACE’s participation in the Pepco Holdings benefit plans.
(10) DEBT
Long-Term Debt
Long-term debt outstanding as of December 31, 2009 and 2008 is presented below.
(a) Represents a series of First Mortgage Bonds issued by ACE (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued by or for the benefit of ACE. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligation in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes and tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.
(b) Represents a series of Collateral First Mortgage Bonds issued by ACE that will, at such time as there are no First Mortgage Bonds of ACE outstanding (other than Collateral First Mortgage Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.
ACE
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ATLANTIC CITY ELECTRIC COMPANY
The outstanding First Mortgage Bonds issued by ACE are subject to a lien on substantially all of ACE’s property, plant and equipment.
ACE Funding was established in 2001 solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds 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 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 Transition Bonds are obligations of ACE Funding and are non-recourse to ACE.
The aggregate principal amount of long-term debt including Transition Bonds outstanding at December 31, 2009, that will mature in each of 2010 through 2014 and thereafter is as follows: $35 million in 2010, $35 million in 2011, $37 million in 2012, $108 million in 2013, $48 million in 2014, and $751 million thereafter.
ACE’s long-term debt is subject to certain covenants. ACE is in compliance with all requirements.
Short-Term Debt
ACE has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. A detail of the components of ACE’s short-term debt at December 31, 2009 and 2008 is as follows:
Commercial Paper
ACE maintains an ongoing commercial paper program of up to $250 million. The commercial paper notes can be issued with maturities up to 270 days from the date of issue. The commercial paper program is backed by ACE’s borrowing capacity under the $1.5 billion credit facility described below under the heading “Credit Facility.”
ACE had $60 million of commercial paper outstanding at December 31, 2009 and no commercial paper outstanding at December 31, 2008. The weighted average interest rates for commercial paper issued during 2009 and 2008 were .63% and 3.12%, respectively. The weighted average maturity for commercial paper issued during 2009 and 2008 was eight days and four days, respectively.
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
Variable Rate Demand Bonds
Variable Rate Demand Bonds (VRDBs) are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. ACE expects the bonds submitted for purchase will be remarketed successfully due to the credit worthiness of the company and because the remarketing resets the interest rate to the then-current market rate. The company also may utilize one of the fixed rate fixed term conversion options of the bonds to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, ACE views VRDBs as a source of long-term financing. The VRDBs outstanding in 2009 mature as follows: 2014 ($19 million) and 2017 ($4 million). The weighted average interest rate for VRDBs was .81% and 3.29% during 2009 and 2008, respectively.
In June 2009, ACE completed the remarketing of $23 million in VRDBs that are supported by letters of credit issued by The Bank of New York Mellon. The letters of credit will expire on June 23, 2010, unless extended. The expiration, cancellation, or termination of a letter of credit prior to the maturity of the related VRDBs will require ACE to repurchase the VRDBs.
Credit Facility
PHI, Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and ACE maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under this credit facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million. The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate and the federal funds effective rate plus 0.5% or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. The facility also includes a “swingline loan sub-facility” pursuant to which each company may make same day borrowings in an aggregate amount not to exceed $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof.
The facility commitment expiration date is May 5, 2012, with each company having the right to elect to have 100% of the principal balance of the loans outstanding on the expiration date continued as non-revolving term loans for a period of one year from such expiration date.
The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties must be true, and the borrower must be in compliance with specified covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. As of December 31, 2009, each borrower was in compliance with the covenants of the credit facility.
The absence of a material adverse change in the borrower’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers.
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
At December 31, 2009 and 2008, the amount of cash, plus borrowing capacity under the PHI credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $582 million and $843 million, respectively.
(11) INCOME TAXES
ACE, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.
The provision for consolidated income taxes, reconciliation of consolidated income tax rate, and components of consolidated deferred income tax liabilities (assets) are shown below.
Provision for Consolidated Income Taxes
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
Reconciliation of Consolidated Income Tax Rate
During the first quarter of 2009, the New Jersey Department of Treasury denied ACE’s 2001-2003 amended returns requesting additional state only amortization of tax basis in those years. As a result, ACE recorded a $1.8 million charge to tax expense. The Company appealed the decision, and in December 2009 learned that New Jersey would in fact accept those returns. As a result, the $1.8 million charge recorded in the first quarter of 2009 was reversed.
In March 2009, the Internal Revenue Service (IRS) issued a Revenue Agent’s Report (RAR) for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to ACE’s capitalization of overhead costs for tax purposes and the deductibility of certain ACE casualty losses. In conjunction with PHI, ACE has appealed certain of the proposed adjustments, and believes it has adequately reserved for the adjustments proposed in the RAR.
In November 2009, ACE received a refund of prior years’ Federal income taxes of $9 million. The refund results from the carry back of PHI’s 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions paid in 2009 (which were deducted in 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs.
During 2008, ACE completed an analysis of its current and deferred income tax accounts and, as a result, recorded a $7 million charge to income tax expense in 2008, which is included in Deferred tax adjustments in the reconciliation provided above. Also identified as part of the analysis were new uncertain tax positions for ACE under ASC 740 (primarily representing overpayments of income taxes in previously filed tax returns) that resulted in the recording of after-tax net interest income of $4 million, which is included as a reduction of income tax expense.
In addition, during 2008, ACE recorded additional after-tax net interest income of $10 million under ASC 740 primarily related to the reversal of previously accrued interest payable resulting from a favorable tentative settlement of the mixed service cost issue with the IRS, and a claim made with the IRS related to the tax reporting of fuel over- and under-recoveries.
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate
Unrecognized tax benefits represent those tax benefits related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Unrecognized tax benefits at December 31, 2009, included $2 million that, if recognized, would lower the effective tax rate.
Interest and Penalties
ACE recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2009, 2008 and 2007, ACE recognized $9 million of interest income pre-tax ($6 million after-tax), $24 million of interest income pre-tax ($14 million after-tax), and $2 million of interest income pre-tax ($1 million after-tax), respectively, as a component of income tax expense. As of December 31, 2009, 2008 and 2007, ACE had $18 million of accrued interest receivable, $13 million of accrued interest receivable and $1 million of accrued interest payable, respectively, related to effectively settled and uncertain tax positions.
Possible Changes to Unrecognized Tax Benefits
It is reasonably possible that the amount of the unrecognized tax benefit with respect to certain of ACE’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The final settlement of the mixed service cost issue or other federal or state audits could impact the balances significantly. At this time, other than the mixed service cost issue, an estimate of the range of reasonably possible outcomes cannot be determined. The unrecognized benefit related to the mixed service cost issue could decrease by $13 million within the next 12 months upon final resolution of the tentative settlement with the IRS. See Note (14), “Commitments and Contingencies,” herein for additional information.
Tax Years Open to Examination
ACE’s federal income tax liabilities for all years through 1999 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where PHI files state income tax returns (New Jersey and Pennsylvania) are the same as for the federal returns.
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
Components of Consolidated Deferred Income Tax Liabilities (Assets)
The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to ACE’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2009 and 2008.
The Tax Reform Act of 1986 repealed the investment tax credit (ITC) for property placed in service after December 31, 1985, except for certain transition property. ITC previously earned on ACE’s property continues to be amortized to income over the useful lives of the related property.
Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
(12) PREFERRED STOCK
The preferred stock amounts outstanding as of December 31, 2009 and 2008 are as follows:
Under the terms of the Company’s Articles of Incorporation, ACE has authority to issue up to 799,979 shares of its $100 par value Cumulative Preferred Stock. The shares of each of the series are redeemable solely at the option of the issuer. In addition, ACE has authority to issue up to two million shares of No Par Preferred Stock and three million shares of Preference Stock without par value.
(13) FAIR VALUE DISCLOSURES
Fair Value of Assets and Liabilities Excluding Debt
Effective January 1, 2008, ACE adopted FASB guidance on fair value measurement and disclosures (ASC 820) which established a framework for measuring fair value and expanded disclosures about fair value measurements.
As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ACE utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, ACE utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. ACE is able to classify fair value balances based on the observability of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets, and other observable pricing data. Level 2 also includes those financial instruments that are valued using internally developed methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
Level 3 - Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial investments that are valued using models or other valuation methodologies.
The following tables set forth by level within the fair value hierarchy ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009 and 2008. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
Fair Value of Debt Instruments
The estimated fair values of ACE’s non-derivative financial instruments as of December 31, 2009 and 2008 are shown below:
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
The methods and assumptions below were used to estimate, as of December 31, 2009 and 2008, the fair value of each class of financial instruments shown above for which it is practicable to estimate a value.
The fair value of Long-Term Debt issued by PHI and its utility subsidiaries was based on actual trade prices as of December 31, 2009 and 2008, or bid prices obtained from brokers if actual trade prices were not available. The fair values of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on bid prices obtained from brokers if actual trade prices were not available or were based on discounted cash flows using current rates for similar issues with similar credit ratings, terms, and remaining maturities for issues with no market price available.
The fair value of the Redeemable Serial Preferred Stock, excluding amounts due within one year, were derived based on quoted market prices or discounted cash flows using current rates of preferred stock with similar terms.
(14) COMMITMENTS AND CONTINGENCIES
Regulatory and Other Matters
Rate Proceedings
On August 14, 2009, ACE submitted a petition to the NJBPU to increase its electric distribution base rates, including a request for the implementation of a bill stabilization adjustment mechanism (BSA). Based on a test year ending December 31, 2009, adjusted for known and measurable changes, ACE requested an annual net increase in its current retail distribution rates for electric service in the amount of approximately $54 million (which includes a reduction to its Regulatory Asset Recovery Charge) based on a requested return on equity (ROE) of 11.50% (or an increase of approximately $52 million, based on an ROE of 11.25%, if the BSA is approved). Hearings are scheduled for late May and June 2010.
Under the BSA, customer delivery rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the NJBPU. The BSA increases rates if actual distribution revenues fall below the approved level and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, ACE would collect its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” distribution revenue from unit sales consumption and ties the growth in distribution revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for ACE to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and distribution revenues.
Sale of B.L. England Generating Facility
In February 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC. In July 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement in the amount of $25 million. RC Cape May contends that one of the assets it purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been declared by Citgo to have been terminated due to a failure by ACE to renew the contract in a timely manner. The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo.
RC Cape May commenced an arbitration proceeding against Citgo seeking a determination that the TSA remains in effect and notified ACE of the proceedings. On July 1, 2009, the arbitrator issued its interim award, ruling that the TSA remains in effect and is enforceable by RC Cape May against Citgo. ACE believes this ruling invalidates RC Cape May’s indemnification claim against ACE, but cannot predict whether RC Cape May will continue to pursue indemnification.
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
Environmental Litigation
ACE is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. ACE 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. Although penalties assessed for violations of environmental laws and regulations are not recoverable from ACE’s customers, environmental clean-up costs incurred by ACE would be included in its cost of service for ratemaking purposes.
Delilah Road Landfill Site. In 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with two other PRPs, signed an administrative consent order with NJDEP to remediate the site. The soil cap remedy for the site has been implemented, and in August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years. In September 2007, NJDEP approved the PRP group’s petition to conduct semi-annual, rather than quarterly, ground water monitoring for two years and deferred until the end of the two-year period a decision on the PRP group’s request for annual groundwater monitoring thereafter. In August 2007, the PRP group agreed to reimburse the costs of the U.S. Environmental Protection Agency (EPA) in the amount of $81,400 in full satisfaction of EPA’s claims for all past and future response costs relating to the site (of which ACE’s share is one-third). Effective April 2008, EPA and the PRP group entered into a settlement agreement which will allow EPA to reopen the settlement in the event of new information or unknown conditions at the site. On November 23, 2008, Lenox, Inc., a member of the PRP group, filed a bankruptcy petition under Chapter 11 of the U.S. Bankruptcy Code. ACE has filed a proof of claim in the Lenox bankruptcy seeking damages resulting from the rejection by Lenox, Inc., of its cost sharing obligations to ACE. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial condition, results of operations or cash flows, regardless of the impact of the Lenox bankruptcy. Effective October 13, 2009, EPA deleted the Delilah Road Landfill site from the national priorities list, after determining that all appropriate response actions under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) have been completed. Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000.
Frontier Chemical Site. In June 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y. based on hazardous waste manifests indicating that ACE sent in excess of 7,500 gallons of manifested hazardous waste to the site. ACE has entered into an agreement with the other parties identified as PRPs to form a PRP group and has informed NYDEC that it has entered into good faith negotiations with the PRP group to address ACE’s responsibility at the site. In February 2010, ACE accepted the PRP group’s offer of a de minimis cash-out settlement under which ACE paid a total of $16,000 to receive a release from liability and be relieved from any further involvement at the site.
Franklin Slag Pile Site. On November 26, 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a PRP that may have liability with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency and for the costs of implementing an EPA-mandated remedy. The EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983 (ACE owned B.L. England at that time and MDC
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
formerly operated the Franklin Slag Pile site). EPA further claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under CERCLA, and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA’s letter also states that as of the date of the letter, EPA’s expenditures for response measures at the site exceed $6 million. EPA estimates approximately $6 million as the cost for future response measures it recommends. ACE understands that the EPA sent similar general notice letters to three other companies and various individuals.
ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications, and therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by the EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE.
Ward Transformer Site. In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against ACE with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. With the court’s permission, the plaintiffs filed amended complaints on September 1, 2009. ACE, as part of a group of defendants, filed a motion to dismiss on October 13, 2009. Although it is too early in the process to characterize the magnitude of the potential liability at this site, it does not appear that ACE had extensive business transactions, if any, with the Ward Transformer site.
Appeal of New Jersey Flood Hazard Regulations. In November 2007, NJDEP 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.
IRS Mixed Service Cost Issue
During 2001, ACE changed its method of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed the company to accelerate the deduction of certain expenses that were previously capitalized and depreciated. As a result of this method change, ACE generated incremental tax cash flow benefits of approximately $49 million.
In 2005, the IRS issued Revenue Ruling 2005-53, which limited the ability of ACE to utilize its tax accounting method on its 2001 through 2004 tax returns. In accordance with this Revenue Ruling, the RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that ACE had claimed on those returns.
In March 2009, PHI reached a tentative settlement with the IRS for all years (2001 through 2004). The terms of the settlement reduced the tax benefits related to the mixed service costs deductions by $6 million for ACE.
Contractual Obligations
As of December 31, 2009, ACE’s contractual obligations under non-derivative fuel and power purchase contracts were $273 million in 2010, $455 million in 2011 to 2012, $467 million in 2013 to 2014, and $1,961 million in 2015 and thereafter.
(15) RELATED PARTY TRANSACTIONS
PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the years ended December 31, 2009, 2008 and 2007 were $100 million, $94 million and $87 million, respectively.
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
In addition to the PHI Service Company charges described above, ACE’s financial statements include the following related party transactions in its consolidated statements of income:
(a) Included in purchased energy expense.
(b) Included in other operation and maintenance expense.
(c) Included in operating revenue.
As of December 31, 2009 and 2008, ACE had the following balances due (to) from related parties:
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
ATLANTIC CITY ELECTRIC COMPANY
(16) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.
(a) Includes a $2 million benefit related to the resolution of an uncertain state income tax position.
(b) Includes $4 million of after-tax net interest income on uncertain tax positions primarily related to casualty losses.
(c) Includes $2 million of after-tax interest income related to the tentative settlement of the IRS mixed service cost issue.
(d) Includes a $1 million charge related to an adjustment in the accounting for certain restricted stock awards granted under the Long-Term Incentive Plan (LTIP).
(e) Includes $8 million of after-tax net interest income on uncertain and effectively settled tax positions (primarily associated with a claim made with the IRS related to the tax reporting for fuel over- and under-recoveries, certain newly identified overpayments of income taxes in previously filed tax returns and the reversal of the majority of the interest income recognized on uncertain tax positions related to casualty losses in the first quarter), and a charge of $7 million to correct prior period errors related to additional analysis of deferred tax balances completed in 2008.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Pepco Holdings, Inc.
None.
Potomac Electric Power Company
None.
Delmarva Power & Light Company
None.
Atlantic City Electric Company
None.
Item 9A.
Item 9A. CONTROLS AND PROCEDURES
Pepco Holdings, Inc.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco Holdings has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2009, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco Holdings have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco Holdings and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (the Exchange Act) (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control over Financial Reporting
See “Management’s Report on Internal Control over Financial Reporting” in Part II, Item 8 of this Form 10-K.
Attestation Report of the Registered Public Accounting Firm
See “Report of Independent Registered Public Accounting Firm” in Part II, Item 8 of this Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2009, there was no change in Pepco Holdings’ internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco Holdings’ internal controls over financial reporting.
Potomac Electric Power Company
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2009, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control over Financial Reporting
See “Management’s Report on Internal Control over Financial Reporting” in Part II, Item 8 of this Form 10-K.
Attestation Report of the Registered Public Accounting Firm
See “Report of Independent Registered Public Accounting Firm” in Part II, Item 8 of this Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2009, there was no change in Pepco’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco’s internal controls over financial reporting.
Delmarva Power & Light Company
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, DPL has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2009, and, based upon this evaluation, the chief executive officer and the chief financial officer of DPL have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to DPL that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control over Financial Reporting
See “Management’s Report on Internal Control over Financial Reporting” in Part II, Item 8 of this Form 10-K.
Attestation Report of the Registered Public Accounting Firm
See “Report of Independent Registered Public Accounting Firm” in Part II, Item 8 of this Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2009, there was no change in DPL’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, DPL’s internal controls over financial reporting.
Atlantic City Electric Company
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, ACE has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2009, and, based upon this evaluation, the chief executive officer and the chief financial officer of ACE have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to ACE and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control over Financial Reporting
See “Management’s Report on Internal Control over Financial Reporting” in Part II, Item 8 of this Form 10-K.
Attestation Report of the Registered Public Accounting Firm
See “Report of Independent Registered Public Accounting Firm” in Part II, Item 8 of this Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2009, there was no change in ACE’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, ACE’s internal controls over financial reporting.
Item 9B.
Item 9B. OTHER INFORMATION
Pepco Holdings, Inc.
None.
Potomac Electric Power Company
None.
Delmarva Power & Light Company
None.
Atlantic City Electric Company
None.
Part III
Item 10.
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Pepco Holdings, Inc.
The following information to be included in PHI’s definitive proxy statement for the 2010 Annual Meeting, which is expected to be filed with the SEC on or about April 1, 2010, is incorporated herein by reference:
•
The information under the heading “Nominees for Election as Directors.”
•
The information under the heading “Security Ownership of Certain Beneficial Owners and Management - Section 16(a) Beneficial Ownership Reporting Compliance.”
•
The information concerning PHI’s Corporate Business Policies under the heading “Where do I find the Company’s Corporate Business Policies, Corporate Governance Guidelines and Committee Charters?”
•
The information regarding the membership and function of the Audit Committee and the financial expertise of its members under the heading “Board Committees - Audit Committee.”
Executive Officers of PHI
The names of the executive officers of PHI and their ages and the positions they held as of February 26, 2010, are set forth in the following table. The business experience of each executive during the past five years is set forth adjacent to his or her name under the heading “Office and Length of Service” in the following table and in the applicable footnote.
PEPCO HOLDINGS
(1) Mr. Rigby was Chief Operating Officer of PHI from September 2007 until February 28, 2009 and Executive Vice President of PHI from September 2007 until March 2008, Senior Vice President of PHI from August 2002 until September 2007 and Chief Financial Officer of PHI from May 2004 until September 2007. Mr. Rigby was President of ACE from July 2001 until May 2004 and Chief Executive Officer of ACE from August 2002 until May 2004. He served as President of DPL from August 2002 until May 2004. Mr. Rigby was President and Chief Executive Officer of ACE, DPL and Pepco from September 1, 2007 to February 28, 2009. Mr. Rigby has been Chairman of Pepco, DPL and ACE since March 1, 2009.
(2) Mr. Velazquez served as President of Conectiv Energy Holding Company, an affiliate of PHI, from June 2006 to February 28, 2009, Chief Executive Officer of Conectiv Energy Holding Company from January 2007 to February 28, 2009 and Chief Operating Officer of Conectiv Energy Holding Company from June 2006 to December 2006. He served as a Vice President of PHI from February 2005 to June 2006 and as Chief Risk Officer of PHI from August 2005 to June 2006. From July 2001 to February 2005, he served as a Vice President of Conectiv Energy Supply, Inc., an affiliate of PHI.
(3) Mr. Emge was Vice President, Legal Services of PHI from August 2002 until March 2008. Mr. Emge has served as General Counsel of ACE, DPL and Pepco since August 2002 and as Senior Vice President of Pepco and DPL since March 1, 2009.
(4) Mr. Kamerick was Senior Vice President and Chief Regulatory Officer of PHI from March 2009 until June 2009. Mr. Kamerick was Vice President and Treasurer of PHI from August 2002 until February 28, 2009.
(5) Mr. Clark has been employed by PHI since June 2005 and has also served as Vice President and Controller of Pepco and DPL and Controller of ACE since August 2005. From July 2004 until June 2005, he was Vice President, Financial Reporting and Policy for MCI, Inc., a telecommunications company not affiliated with PHI.
(6) Mr. Friel was General Auditor of PHI from August 2002 until May 2005.
(7) Mr. Jenkins was Vice President, People Strategy and Performance Improvement - PHI Power Delivery from 2004 until 2005.
(8) Mr. Morsches was Executive Vice President of Conectiv Energy Supply, Inc. from January 2009 until February 28, 2009. Mr. Morsches was a Principal of the Boston Consulting Group, a management consulting firm, which is not affiliated with PHI, from June 2005 until January 2009 and was a self-employed consultant from January 2003 until June 2005.
(9) Mr. Huffman has been employed by Pepco Energy Services since June 2003. He was Chief Operating Officer from April 2006 to February 28, 2009, Senior Vice President from February 2005 to March 2006 and Vice President from June 2003 to February 2005.
Each PHI executive officer is elected annually and serves until his or her respective successor has been elected and qualified or his or her earlier resignation or removal.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 11.
Item 11. EXECUTIVE COMPENSATION
Pepco Holdings, Inc.
The following information to be included in PHI’s definitive proxy statement for the 2010 Annual Meeting, which is expected to be filed with the SEC on or about April 1, 2010, is incorporated herein by reference:
•
The information under the heading “2009 Director Compensation.”
•
The information under the heading “Compensation Discussion and Analysis.”
•
The information under the heading “Executive Compensation.”
•
The information under the heading “Compensation/Human Resources Committee Report.”
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Pepco Holdings, Inc.
The information to be included under the heading “Security Ownership of Certain Beneficial Owners and Management” in PHI’s definitive proxy statement for the 2010 Annual Meeting, which is expected to be filed with the SEC on or about April 1, 2010, is incorporated herein by reference.
The following table provides information as of December 31, 2009, with respect to the shares of PHI’s common stock that may be issued under PHI’s existing equity compensation plans.
Equity Compensation Plans Information
(a) Consists solely of the Pepco Holdings, Inc. Long-Term Incentive Plan.
(b) In connection with the acquisition by Pepco of Conectiv (i) outstanding options granted under the Potomac Electric Power Company Long-Term Incentive Plan were converted into options to purchase shares of PHI common stock and (ii) options granted under the Conectiv Incentive Compensation Plan were converted into options to purchase shares of PHI common stock. As of December 31, 2009, options to purchase an aggregate of 346,504 shares of PHI common stock, having a weighted average exercise price of $22.0875, were outstanding.
(c) Consists of shares of PHI common stock available for future issuance under the PHI Non-Management Directors Compensation Plan. Under this plan, each director who is not an employee of PHI or any of its subsidiaries (“non-management director”) is entitled to elect to receive his or her annual retainer, retainer for service as a committee chairman, if any, and meeting fees in: (i) cash, (ii) shares of PHI’s common stock, (iii) a credit to an account for the director established under PHI’s Executive and Director Deferred Compensation Plan or (iv) any combination thereof. The plan expires on December 31, 2014 unless terminated earlier by the Board of Directors.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Pepco Holdings, Inc.
The information to be included under the heading “Board Review of Transactions With Related Parties” in PHI’s definitive proxy statement for the 2010 Annual Meeting, which is expected to be filed with the SEC on or about April 1, 2010, is incorporated herein by reference.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 14.
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Pepco Holdings, Pepco, DPL and ACE
Audit Fees
The aggregate fees billed by PricewaterhouseCoopers LLP for professional services rendered for the audit of the annual financial statements of Pepco Holdings and its subsidiary reporting companies for the 2009 and 2008 fiscal years, reviews of the financial statements included in the 2009 and 2008 Forms 10-Q of Pepco Holdings and its subsidiary reporting companies, reviews of public filings, comfort letters and other attest services were $6,145,416 and $7,965,978, respectively. The amount for 2008 includes $184,984 for the 2008 audit that was billed after the 2008 amount was disclosed in Pepco Holding’s proxy statement for the 2009 Annual Meeting.
Audit-Related Fees
No fees were billed by PricewaterhouseCoopers LLP for audit-related services for the 2009 or 2008 fiscal years.
Tax Fees
The aggregate fees billed by PricewaterhouseCoopers LLP for tax services rendered for the 2009 and 2008 fiscal years were $504,814 and $284,678 respectively. These services consisted of tax compliance, tax advice and tax planning.
All Other Fees
The aggregate fees billed by PricewaterhouseCoopers LLP for all other services other than those covered under “Audit Fees,” “Audit-Related Fees” and “Tax Fees” for the 2009 and 2008 fiscal years were $3,000 and $4,500, respectively, which represented the costs of training and technical materials provided by PricewaterhouseCoopers LLP.
All of the services described in “Audit Fees,” “Audit-Related Fees,” “Tax Fees” and “All Other Fees” were approved in advance by the Audit Committee, in accordance with the Audit Committee Policy on the Approval of Services Provided by the Independent Auditor which will be attached as Annex A to Pepco Holdings’ definitive proxy statement for the 2010 Annual Meeting of Shareholders, which is expected to be filed with the SEC on or about April 1, 2010, and is incorporated herein by reference.
Part IV
Item 15.
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents List
1. Financial Statements
Pepco Holdings, Inc.
Consolidated Statements of Income for each of the years ended December 31, 2009, 2008 and 2007
Consolidated Statements of Comprehensive Income for each of the years ended December 31, 2009, 2008 and 2007
Consolidated Balance Sheets as of December 31, 2009 and 2008
Consolidated Statements of Cash Flows for each of the years ended December 31, 2009, 2008 and
Consolidated Statements of Equity for each of the years ended December 31, 2009, 2008 and 2007
Notes to Consolidated Financial Statements
Potomac Electric Power Company
Statements of Income for each of the years ended December 31, 2009, 2008 and 2007
Balance Sheets as of December 31, 2009 and 2008
Statements of Cash Flows for each of the years ended December 31, 2009, 2008 and 2007
Statements of Equity for each of the years ended December 31, 2009, 2008 and 2007
Notes to Financial Statements
Delmarva Power & Light Company
Statements of Income for each of the years ended December 31, 2009, 2008 and 2007
Balance Sheets as of December 31, 2009 and 2008
Statements of Cash Flows for each of the years ended December 31, 2009, 2008 and 2007
Statements of Equity for each of the years ended December 31, 2009, 2008 and 2007
Notes to Financial Statements
Atlantic City Electric Company
Consolidated Statements of Income for each of the years ended December 31, 2009, 2008 and 2007
Consolidated Balance Sheets as of December 31, 2009 and 2008
Consolidated Statements of Cash Flows for each of the years ended December 31, 2009, 2008 and 2007
Consolidated Statements of Equity for each of the years ended December 31, 2009, 2008 and 2007
Notes to Consolidated Financial Statements
2. Financial Statement Schedules
The financial statement schedules specified by Regulation S-X, other than those listed below, are omitted because either they are not applicable or the required information is presented in the financial statements included in Part II, Item 8, “Financial Statements and Supplementary Data” of this Form 10-K.
Schedule I, Condensed Financial Information of Parent Company is submitted below.
PEPCO HOLDINGS, INC. (Parent Company)
STATEMENTS OF INCOME
The accompanying Notes are an integral part of these financial statements.
PEPCO HOLDINGS, INC. (Parent Company)
BALANCE SHEETS
The accompanying Notes are an integral part of these financial statements.
PEPCO HOLDINGS, INC. (Parent Company)
STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of these financial statements.
NOTES TO FINANCIAL INFORMATION
(1) BASIS OF PRESENTATION
Pepco Holdings, Inc. is a holding company and conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Pepco Holdings, Inc. included in Part II, Item 8 of this Form 10-K.
Pepco Holdings, Inc. owns 100% of all significant subsidiaries.
(2) RECLASSIFICATIONS AND ADJUSTMENTS
Certain prior period amounts have been reclassified in order to conform to the current period presentation.
(3) DEBT
For information concerning PHI’s long-term debt obligations, see Note (11), “Debt” to the consolidated financial statements of Pepco Holdings included in Part II, Item 8 of this Form 10-K.
(4) COMMITMENTS AND CONTINGENCIES
For information concerning PHI’s material contingencies and guarantees, see Note (17), “Commitments and Contingencies” to the consolidated financial statements of Pepco Holdings included in Part II, Item 8 of this Form 10-K.
(5) INVESTMENT IN CONSOLIDATED COMPANIES
The Parent Company’s majority owned subsidiaries are recorded using the equity method of accounting. A breakout of the balance in Investment in consolidated companies is as follows:
Schedule II, Valuation and Qualifying Accounts, for each registrant is submitted below:
Pepco Holdings, Inc.
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.
Potomac Electric Power Company
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.
Delmarva Power & Light Company
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.
Atlantic City Electric Company
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.
3. EXHIBITS
The documents listed below are being filed herewith or have previously been filed and are incorporated herein by reference from the documents indicated and made a part hereof.
* Management contract or compensatory plan or arrangement.
** The information required by this Exhibit is set forth in Note (14) of the Financial Statements of Pepco Holdings included in Part II, Item 8 “Financial Statements and Supplementary Data” of this Form 10-K.
Regulation S-K Item 10(d) requires registrants to identify the physical location, by SEC file number reference, of all documents incorporated by reference that are not included in a registration statement and have been on file with the SEC for more than five years. The SEC file number references for Pepco Holdings, Inc., those of its subsidiaries that are registrants, Conectiv and ACE Funding are provided below:
Pepco Holdings, Inc. in file number 001-31403
Potomac Electric Power Company in file number 001-1072
Conectiv in file number 001-13895
Delmarva Power & Light Company in file number 001-1405
Atlantic City Electric Company in file number 001-3559
Atlantic City Electric Transition Funding LLC in file number 333-59558
Certain instruments defining the rights of the holders of long-term debt of PHI, Pepco, DPL and ACE (including medium-term notes, unsecured notes, senior notes and tax-exempt financing instruments) have not been filed as exhibits in accordance with Regulation S-K Item 601(b)(4)(iii) because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis. Each of PHI, Pepco, DPL or ACE agrees to furnish to the SEC upon request a copy of any such instruments omitted by it.
INDEX TO FURNISHED EXHIBITS
The documents listed below are being furnished herewith:
(b) Exhibits
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PEPCO HOLDINGS, INC.
(Registrant)
February 26, 2010
By
/S/ JOSEPH M. RIGBY
Joseph M. Rigby
Chairman of the Board, President and Chief Executive Officer
POTOMAC ELECTRIC POWER COMPANY (Pepco)
(Registrant)
February 26, 2010
By
/S/ DAVID M. VELAZQUEZ
David M. Velazquez,
President and Chief Executive Officer
DELMARVA POWER & LIGHT COMPANY (DPL)
(Registrant)
February 26, 2010
By
/S/ DAVID M. VELAZQUEZ
David M. Velazquez,
President and Chief Executive Officer
ATLANTIC CITY ELECTRIC COMPANY (ACE)
(Registrant)
February 26, 2010
By
/S/ DAVID M. VELAZQUEZ
David M. Velazquez,
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the above named registrants and in the capacities and on the dates indicated:
/S/ JOSEPH M. RIGBY
Chairman of the Board, President and Chief Executive Officer of Pepco Holdings, Director of Pepco, DPL and ACE
(Principal Executive Officer of Pepco Holdings)
February 26, 2010
Joseph M. Rigby
/S/ DAVID M. VELAZQUEZ
President and Chief Executive Officer of Pepco, DPL and ACE, Director of Pepco and DPL
(Principal Executive Officer of Pepco, DPL and ACE)
February 26, 2010
David M. Velazquez
/S/ A. J. KAMERICK
Senior Vice President and Chief Financial Officer of Pepco Holdings, Pepco, and DPL, Chief Financial Officer of ACE and Director of Pepco
(Principal Financial Officer of Pepco Holdings, Pepco, DPL and ACE)
February 26, 2010
Anthony J. Kamerick
/S/ RONALD K. CLARK
Vice President and Controller of Pepco Holdings, Pepco and DPL and Controller of ACE
(Principal Accounting Officer of Pepco Holdings, Pepco, DPL and ACE)
February 26, 2010
Ronald K. Clark
INDEX TO EXHIBITS FILED HEREWITH
INDEX TO EXHIBITS FURNISHED HEREWITH