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 Washington, D.C. 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 costing methodologies set forth in the service agreement.
Pepco Holdings’ management has identified its operating segments at December 31, 2008 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. 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
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 2008, 2007 and 2006, respectively, PHI’s Power Delivery operations produced 51%, 56%, and 61% of PHI’s consolidated operating revenues (including revenue from intercompany transactions) and 72%, 66%, and 67% 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 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.
Delivery of Electricity, Natural Gas and Default Electricity Supply
The Power Delivery business is conducted by PHI’s three utility subsidiaries: Pepco, DPL and ACE. Each company is responsible for the delivery of electricity and, in the case of DPL, also 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 varies by jurisdiction as follows:
Delaware
Standard Offer Service (SOS)
District of Columbia
SOS
Maryland
SOS
New Jersey
Basic Generation Service (BGS)
Effective January 2, 2008, DPL sold its retail electric distribution assets and its wholesale electric transmission assets in Virginia. This sale 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 this Form 10-K, the supply service obligations of the respective utility subsidiaries are referred to generally as Default Electricity Supply.
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 122,000 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.
Distribution of Electricity and Deregulation
Historically, electric utilities, including Pepco, DPL and ACE, were vertically integrated businesses that generated all or a substantial portion of the electric power supply that they delivered to customers in their service territories over their own distribution facilities. Customers were charged a bundled rate approved by the applicable regulatory authority that covered both the supply and delivery components of the retail electric service. However, legislative and regulatory actions in each of the service territories in which Pepco, DPL and ACE operate have resulted in the “unbundling” of the supply and delivery components of retail electric service and in the opening of the supply component to competition from non-regulated providers. Accordingly, while Pepco, DPL and ACE continue to be responsible for the distribution of electricity in their respective service territories, as the result of deregulation, customers in those service territories now are permitted to choose their electricity supplier from among a number of non-regulated, competitive suppliers. Customers who do not choose a competitive supplier receive Default Electricity Supply on terms that vary depending on the service territory, as described more fully below.
In connection with the deregulation of electric power supply, Pepco, DPL and ACE have divested all of their respective generation assets, by either selling them to third parties or transferring them to the non-regulated affiliates of PHI that comprise PHI’s Competitive Energy businesses. Accordingly, Pepco, DPL and ACE are no longer engaged in generation operations.
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, 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 in 2007 by the Maryland Public Service Commission (MPSC) of a bill stabilization adjustment mechanism for retail customers, has had the effect of eliminating changes in customer usage due to weather conditions or other reasons as a factor having an impact on revenue and income.
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, also 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 MPSC and in Washington, D.C. 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) and, until the sale of
its Virginia assets on January 2, 2008, were regulated in Virginia by the Virginia State Corporation Commission.
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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 is regulated by FERC.
Pepco
Pepco is engaged in the transmission, distribution and default supply of electricity in Washington, D.C. 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, 2008, Pepco delivered electricity to 767,000 customers (of which 247,000 were located in the District of Columbia and 520,000 were located in Maryland), as compared to 760,000 customers as of December 31, 2007 (of which 241,800 were located in the District of Columbia and 518,200 were located in Maryland).
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. In 2007, Pepco delivered a total of 27,451,000 megawatt hours of electricity, of which 30% was delivered to residential customers, 50% to commercial customers, and 20% to United States and District of Columbia government customers.
Pepco has been providing market-based SOS in Maryland since July 2004. Pursuant to an order issued by the MPSC in November 2006, 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 2010. 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 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 $.001651 per kilowatt-hour. Because margins vary by customer class, the actual average margin over any given time period depends on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period. 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 market-based 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, pending investigation by the DCPSC of other alternatives, including the selection of another party to administer the SOS franchise. 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 $.002151 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 from each customer class and the load taken by such customers over the time period. 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, 2008, 50% of Pepco’s Maryland distribution sales (measured by megawatt hours) were to SOS customers, as compared to 51% in 2007, and 33% of its District of Columbia distribution sales were to SOS customers in 2008, as compared to 35% in 2007.
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 other suppliers.
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 Worchester. Prior to January 2, 2008, DPL also provided transmission and distribution of electricity in Accomack and Northampton counties in Virginia. As discussed below, under the heading “Sale of Virginia Retail Electric Distribution and Wholesale Transmission Assets,” DPL, on January 2, 2008, completed the sale of substantially all of its Virginia retail electric distribution and wholesale electric transmission assets.
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, 2008, DPL delivered electricity to 498,000 customers (of which 299,000 were located in Delaware and 199,000 were located in Maryland), as compared to 519,000 electricity customers as of December 31, 2007 (of which 298,000 were located in Delaware, 198,000 were located in Maryland, and 23,000 were located in Virginia).
In 2008, DPL delivered a total of 13,015,000 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 2007, DPL delivered a total of 13,680,000 megawatt hours of electricity, of which 39% was delivered to residential customers, 40% to commercial customers and 21% to industrial customers.
DPL has been providing market-based SOS in Delaware since May 2006. Pursuant to orders issued by the DPSC, DPL will continue to be obligated to provide fixed-price SOS to residential, small commercial and industrial customers through May 2012 and to medium, large and general service commercial customers through May 2010. DPL purchases the power supply required to satisfy its fixed-price 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 customers. Power to supply the HPS customers is acquired on next-day and other short-term PJM RTO markets. DPL’s rates for supplying fixed-price 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 $3 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 55% of total distribution sales (measured by megawatt hours) for the year ended December 31, 2008, as compared to 54% in 2007.
DPL has been providing market-based SOS in Maryland since June 2004. Pursuant to an order issued by the MPSC in November 2006, 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 2010. 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 customers. Power to supply the SOS HPS customers is acquired in next-day and other short-term PJM RTO markets. 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 is entitled to recover from its SOS customers the costs of the SOS supply plus an average margin of $.001630 per kilowatt-hour. Because margins vary by customer class, the actual average margin over any given time period depends on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period. 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 65% of total distribution sales (measured by megawatt hours) for the year ended December 31, 2008, as compared to 67% in 2007.
DPL provided Default Service in Virginia from March 2004 until the sale of its Virginia retail electric distribution and wholesale transmission assets on January 2, 2008. DPL was paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to all electricity customers in its Virginia service territory regardless of whether the customer received Default Service or purchased electricity from another energy supplier.
In Virginia, DPL distribution sales to Default Service customers represented 94% of total distribution sales (measured by megawatt hours) for the year ended December 31, 2007.
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 to A&N Electric Cooperative and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative.
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, or 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 other suppliers. 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 twelve months ended December 31, 2008, DPL supplied 65% of the natural gas that it delivered, compared to 67% in 2007.
DPL distributed natural gas to 122,000 customers as of December 31, 2008 and 2007. In 2008, DPL distributed 20,300,000 Mcf (thousand cubic feet) of natural gas to customers in its Delaware service territory, of which 38% were sales to residential customers, 24% to commercial customers, 3% to industrial customers, and 35% to customers receiving a transportation-only service. In 2007, DPL delivered 20,700,000 Mcf of natural gas, of which 38% were sales to residential customers, 25% were sales to commercial customers, 4% were to industrial customers, and 33% 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, 2008, ACE delivered electricity to 547,000 customers in its service territory, as compared to 544,000 customers as of December 31, 2007. 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. In 2007, ACE delivered a total of 10,187,000 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 2,198 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 33 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 New Jersey service territory regardless of whether the customer receives BGS or purchases electricity from another energy supplier.
ACE distribution sales to BGS customers represented 78% of total distribution sales (measured by megawatt hours) for the year ended December 31, 2008, as compared to 80% in 2007.
In February 2007, ACE completed the sale of its B.L. England generating facility, which is reflected as discontinued operations on ACE’s consolidated statements of earnings for the years ended December 31, 2007 and 2006. ACE’s sale of its interests in the Keystone and Conemaugh generating facilities in September 2006 is also reflected as discontinued operations on the consolidated statement of earnings for the year ended December 31, 2006 of ACE.
ACE has several contracts with non-utility generators (NUGs) under which ACE purchased 3.8 million megawatt hours of power in 2008. 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
The Competitive Energy businesses provide 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 subsidiaries of Conectiv Energy and Pepco Energy Services. For the years ended December 31, 2008, 2007 and 2006, PHI’s Competitive Energy operations produced 53%, 48%, and 43%, respectively, of PHI’s consolidated operating revenues and 36%, 26%, and 20%, respectively, of PHI’s consolidated operating income.
Conectiv Energy
Conectiv Energy divides its activities into two operational categories: (i) Merchant Generation & Load Service and (ii) Energy Marketing.
Merchant Generation & 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 wholesale markets. Conectiv Energy obtains the electricity required to meet its Merchant Generation & Load Service power supply obligations from its own generation 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 generation 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’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, 2008, Conectiv Energy owned and operated mid-merit plants with a combined 2,778 megawatts of capacity, peak-load plants with a combined 639 megawatts of capacity and base-load generating plants with a combined 340 megawatts of capacity. See
Item 2 “Properties” of this Form 10-K. In addition to the generation plants it owns, Conectiv Energy controls another 500 megawatts of 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, 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 its 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.
Pepco Energy Services
Pepco Energy Services provides retail energy supply and energy services primarily to commercial, industrial, and government customers. Pepco Energy Services sells electricity, including electricity from renewable resources, to customers located primarily in the mid-Atlantic and northeastern regions of the U.S., Texas and the Chicago, Illinois areas. As of December 31, 2008, Pepco Energy Services’ estimated retail electricity backlog was approximately 33 million megawatts for delivery through 2014, an increase of approximately 1 million megawatts over December 31, 2007. Pepco Energy Services also sells natural gas to customers located primarily in the mid-Atlantic region.
Pepco Energy Services also provides energy savings performance contracting services principally to federal, state and local government customers, owns and operates two district energy systems and designs, constructs, and operates combined heat and power and central energy plants.
Pepco Energy Services owns three landfill gas-fired electricity plants that have a total generating capacity rating of 10 megawatts and the output of these plants is sold into the wholesale market administered by PJM and a solar photovoltaic plant that has a generating capacity rating of 2 megawatts and the output of this plant is sold to its host facility.
Pepco Energy Services provides high voltage 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 owns and operates two oil-fired power plants. The power plants are located in Washington, D.C. and have a generating capacity rating 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. In May 2007, Pepco Energy Services deactivated one combustion turbine at its Buzzard Point facility with a generating capacity of approximately 16 megawatts. Pepco Energy Services currently plans to deactivate the balance of 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 these units, in whole or in part, may be accelerated or delayed based on the operating condition of the units, economic conditions, and reliability considerations. Deactivation will not have a material impact on PHI’s financial condition, results of operations or cash flows.
Derivatives and Risk Management
PHI’s Competitive Energy businesses use 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 businesses include forward contracts, futures, swaps, and exchange-traded and over-the-counter options. In addition, the Competitive Energy businesses also manage 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.
Conectiv Energy’s goal is to manage the risk associated with the expected power output of its generation facilities and their fuel requirements. The risk management goals are approved by PHI’s Corporate Risk Management Committee and may change from time to time based on market conditions. The actual level of coverage may vary depending on the extent to which Conectiv Energy is successful in implementing its risk management strategies. 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 source of revenue for the Competitive Energy businesses is the sale of capacity by Conectiv Energy and Pepco Energy Services associated with their respective generating facilities. The wholesale market for capacity in PJM is administered by PJM which is responsible for ensuring that within the transmission control area there is sufficient generating capability 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 facilities within the control area or generating facilities outside the control area, which 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 businesses are located in the transmission control area administered by PJM. The capacity of a generating unit is determined based on the demonstrated generating capacity of the unit and its forced outage rate.
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 five 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, 2011. Auctions of capacity for each subsequent 12-month delivery period will be held 36 months ahead of the scheduled delivery year. The next auction, for the period June 2012 through May 2013, will take place in May 2009. The Competitive Energy businesses are exposed to certain 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.
In addition to participating in the PJM auctions, the Competitive Energy businesses participate 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 to 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 both the wholesale and retail levels. At the wholesale level, Conectiv Energy and Pepco Energy Services compete with numerous non-utility generators, independent power producers, wholesale power marketers and brokers, and traditional utilities that continue to operate generation assets. In the retail energy supply market and in providing energy management services, Pepco Energy Services competes with numerous competitive energy marketers and other service providers. Competition in both the wholesale and retail markets for energy and 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 patterns 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 milder than normal in the winter and cooler than normal in the summer. Milder weather can also negatively impact income from these operations. The energy management services of Pepco Energy Services generally are not seasonal.
Other Business Operations
Through its subsidiary PCI, PHI maintains a portfolio of cross-border energy sale-leaseback transactions, with a book value at December 31, 2008 of approximately $1.3 billion. For additional information concerning these cross-border lease transactions, see Note (16), “Commitments and Contingencies” to the consolidated financial statements of PHI set forth in Item 8 “Financial Statements and Supplementary Data” of the Form 10-K. This activity constitutes a separate operating segment for financial reporting purposes, which is designated “Other Non-Regulated.”
EMPLOYEES
At December 31, 2008, PHI had 5,474 employees, including 1,343 employed by Pepco, 898 employed by DPL, 523 employed by ACE and 1,893 employed by PHI Service Company. The remaining were employed by PHI’s Competitive Energy and other non-regulated businesses. Approximately 2,896 employees (including 1,047 employed by Pepco, 727 employed by DPL, 378 employed by ACE, 341 employed by PHI Service Company, and 403 employed by the Competitive Energy businesses) 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 expected to be approximately $37 million in 2009 and $32 million in 2010. These expenditures include $18 million and $11 million, respectively, to comply with multi-pollutant 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, Nitrogen Oxide, Mercury and Nickel 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 regulate nitrogen oxide (NOx) emissions from generating units and allocate 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 and NOx in two stages beginning in 2009 for NOx and in 2010 for SO2. 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 held that CAIR nevertheless would remain in effect pending such rulemaking.
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 will 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 SO2 annual allowance for each 0.5 ton of SO2 emitted during the year and beginning in 2015, one SO2 allowance for each 0.35 ton of SO2 emitted during the year. To implement CAIR, the New Jersey Department of Environmental Protection (NJDEP) adopted a new NOx trading program to replace its prior NOx trading program. This new trading program allocates NOx annual and NOx ozone season allowances to Conectiv Energy’s Carll’s Corner, Cedar, Cumberland, Deepwater, Middle, Mickleton, and Sherman generating units, and will operate in a manner similar to NJDEP’s prior NOx trading program. Conectiv Energy’s Edge Moor, Christiana and Hay Road generating units in Delaware will be subject to federal CAIR for NOx and SO2. Pennsylvania promulgated CAIR regulations in 2008 that are applicable to Conectiv Energy’s Bethlehem generating units and the generating units being constructed in Peach Bottom Township, Pennsylvania. 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 Crisfield generating units in Maryland, Bayview units in Virginia, Edge Moor 10, Delaware City 10 and West 10 units in Delaware, and Missouri Avenue generating units in New Jersey produce fewer megawatts 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 requirements. 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.
Conectiv Energy and Pepco Energy Services units 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 significant impact on the financial results of its business.
In August 2008, NJDEP proposed amendments to its air pollution control regulations applicable to generating units in New Jersey to implement a multi-pollutant 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, which are units capable of generating 15 or more megawatts and which are operated less than or equal to an average of 50 percent of the time during the ozone season. The units that will be subject to NJDEP’s multi-pollutant regulations when promulgated also are subject to CAIR requirements, and accordingly, must hold sufficient NOx and SO2 allowances to cover their NOx and SO2 emissions. The proposed multi-pollutant regulations may require the installation of pollution control equipment at the Deepwater generating station in order to comply with the more stringent maximum allowable emission rates. For the period 2009 through 2014, the proposed HEDD regulations do not impose specific emission limits at any specific source, but require reductions from HEDD units that Conectiv Energy chooses to operate in accordance with a protocol submitted to NJDEP. Beginning in May 2015, the proposed regulations establish specific maximum allowable emissions rates for HEDD units. NJDEP’s regulations are expected to become final in May 2009. Conectiv Energy is evaluating its options for complying with the proposed regulations.
In 2005, EPA finalized its Clean Air Mercury Rule (CAMR), which established mercury emissions standards for new or modified sources and capped state-wide emissions of mercury beginning in 2010. The regulations, which permitted states to implement CAMR by adopting
EPA’s market-based cap-and trade allowance program for coal-fired utility boilers or through regulations that at a minimum achieve the reductions that would be achieved through EPA’s program, were vacated by the United States Court of Appeals for the District of Columbia Circuit in February 2008.
In December 2004, NJDEP published final rules regulating mercury emissions from power plants and industrial facilities in New Jersey that impose standards, effective December 15, 2007, that are significantly stricter than EPA’s now vacated federal CAMR for coal-fired plants. Conectiv Energy has confirmed, based upon the monitoring of mercury emissions at the Deepwater generating facility, that its only coal-fired generating plant in New Jersey is in compliance with the mercury emissions limit without the need for the installation of additional pollution control equipment.
In November 2006, DNREC adopted multi-pollutant regulations to 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, satisfy the now vacated federal CAMR rule, 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. In addition, DNREC has agreed to increase the annual SO2 mass emission limit as it relates to the Edge Moor residual oil-fired generating unit. Conectiv Energy is installing new pollution control equipment and/or enhancing existing equipment to comply with the multi-pollutant regulations. Conectiv Energy currently estimates that it will cost up to $81 million over a period of six years to install the control equipment necessary to comply with the regulations. These estimated costs do not include increased costs associated with operating control equipment.
Conectiv Energy is installing water injection pollution control equipment on its five stationary combustion turbines in Delaware (Christiana 11 and 14, Edge Moor 10, Delaware City 10 and West 10) to comply with new ozone season NOx emission limits. Conectiv Energy estimates that the cost of compliance will be approximately $3 million.
In a March 2005 rulemaking, EPA removed coal- and oil-fired 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 oil-fired unit at Conectiv Energy’s Edge Moor generating facility. In the decision issued on February 8, 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.
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 then 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 and allowances acquired in the open market equivalent to its CO2 emissions during specified compliance periods. Beginning in 2009, all covered CO2 sources must have an approved plan to monitor tons of CO2 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. Delaware’s program, in 2009, will auction 60% of allowances and allocate 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 period. Conectiv Energy participated in the September and December 2008 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 by July 1, 2009 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. These programs are in addition to New Jersey’s participation in RGGI for electric generating units.
Water Quality Regulation
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 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 are 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. These regulations may require changes to cooling water intake structures as part of the NPDES permit renewal process. 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. In April 2008, the U.S. Supreme Court agreed to review the Riverkeeper II decision. Briefing and oral argument before the Court have been completed, but no decision has been rendered. Regardless of the outcome of the pending judicial proceedings, additional EPA rulemaking is expected, and the capital expenditures, if any, that may be needed as a consequence of such new regulations will not be known until the rulemaking process is concluded and each affected facility completes additional studies and addresses related permit requirements.
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 structures 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 Riverkeeper II and the remand of substantial portions of the 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 June 2007, Conectiv Energy filed a timely application for renewal of the NJPDES permit for the Deepwater generating facility, which administratively extended the existing permit. The existing NJPDES permit for Deepwater requires that Conectiv Energy perform several studies to determine whether or not Deepwater’s cooling water intake structures satisfy applicable requirements for protection of the environment. While those study requirements were consistent with requirements under EPA’s regulations implementing CWA Section 316(b), the result of the Riverkeeper II decision and any subsequent EPA rulemaking may require reevaluation of the design and operational measures that Conectiv Energy anticipated using for future compliance with Section 316(b) at Deepwater. In view of the uncertainty associated with Riverkeeper II, NJDEP, at Conectiv Energy’s request, has agreed to stay a cooling water intake structure design upgrade requirement in Deepwater’s existing NJPDES permit. NJDEP is preparing a renewal permit for Deepwater, which will be published as a draft NJPDES renewal permit together with a request for public comments.
Pepco and a subsidiary of Pepco Energy Services discharge water from a steam generating plant and service center located in the District of Columbia under a NPDES permit
issued by EPA in November 2000. Pepco filed a petition with EPA’s Environmental Appeals Board seeking review and reconsideration of certain provisions of EPA’s permit determination. In May 2001, Pepco and EPA reached a settlement on Pepco’s petition, under which EPA withdrew certain contested provisions and agreed to issue a revised draft permit for public comment. A timely renewal application was filed in May 2005 and the companies are operating under the November 2000 permit, excluding the withdrawn conditions, in accordance with the settlement agreement. In June 2008, EPA issued a draft permit. Pepco filed comments on the draft permit in January 2009. In February 2009, EPA issued the final draft permit and initiated a 30-day public comment period, closing on March 16, 2009. The capital expenditures, if any, that may be needed as a consequence of new permit conditions, will not be known until the permit process is concluded.
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, which took effect November 5, 2007, 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 and that is otherwise regulated under a number of other state and federal programs. ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey on November 3, 2008. PHI cannot predict at this time the costs of complying with the FHACA regulations due, among other things, to the potential for additional rulemaking as a result of the appeal, as well as the possibility that NJDEP will issue exemptions from the new regulations.
On October 6, 2008, NJDEP adopted amendments to the agency’s regulations under the Freshwater Wetlands Protection Act (FWPA). PHI believes that the amended FWPA regulations unnecessarily restrict, among other things, various types of electric transmission and distribution system maintenance and construction activity and PHI is evaluating whether to appeal the FWPA regulations to the Appellate Division of the Superior Court of New Jersey. PHI cannot predict at this time the costs of complying with the amendments to the FWPA regulations due to the potential for additional rulemaking if an appeal is filed, as well as the possibility that NJDEP may issue exemptions from certain aspects of the new 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 implement and amend Spill Prevention, Control, and Countermeasure (SPCC) Plans. PHI facilities subject to the regulations must now comply with these regulatory requirements by July 1, 2009. In December 2008, EPA published a final rule to clarify its regulations and streamline certain requirements. In a February 3, 2009 Federal Register notice, EPA delayed until April 4, 2009 the effective date of the December 2008 final rule and indicated that it is reviewing the dates by which facilities must prepare or amend SPCC Plans and implement those plans. PHI continues to analyze its facilities to identify equipment and sites for which physical modifications may be necessary to reduce the risk of a release of oil and comply with EPA’s SPCC regulations. As provided in EPA’s regulations, SPCC Plans for PHI facilities for which the installation of structures or equipment is not practicable include an oil spill contingency plan and a written commitment of manpower, equipment and materials to respond to a discharge of oil. PHI anticipates that compliance with the EPA 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 $50 million.
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 (16), “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 compose 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 also 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 of future regulatory activities of any of these agencies 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 and Maryland. (PHI and Pepco only)
Pepco currently is involved in regulatory proceedings in Maryland and 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 and Maryland allocated or assigned property. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory and Other Matters - Divestiture Cases” for additional information.
The operating results of the Power Delivery business and the Competitive Energy businesses fluctuate on a seasonal basis and can be adversely affected by changes in weather.
The Power Delivery business historically has been seasonal and weather patterns have 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. In Maryland, the adoption in 2007 of a bill stabilization adjustment mechanism for retail customers of Pepco and DPL, 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 revenue and income.
Historically, the competitive energy operations of Conectiv Energy and Pepco Energy Services also have produced less revenue 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 businesses’ 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 that are defined as elements of the Bulk Electric System, which is defined by the North American Electric Reliability Corporation (NERC) as transmission facilities operating at a voltage of 100 kilovolts and above, are subject to mandatory compliance with the reliability standards established by the NERC and the Reliability First Regional Entity, which is the NERC-designated regional entity with jurisdiction in the PJM region. Failure to comply with the standards may result in substantial monetary penalties and reflect poorly on the public image of PHI.
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 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. 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 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 new environmental laws may increase expenses.
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 can require significant capital and other expenditures to, among other things, meet emissions and effluent standards, conduct site remediation 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 about CO2 and other greenhouse gas emissions. As a result, it is possible that, in addition to RGGI, state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. Any of these factors could result in increased capital expenditures and/or operating costs for one or more generating plants operated by PHI’s Conectiv Energy and Pepco Energy Services businesses. Until specific regulations 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. PHI, Pepco, DPL and ACE each continues to monitor federal and state activity related to environmental matters in order to analyze their potential operational and cost implications.
New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on the operations of PHI’s subsidiaries or require them to incur significant additional costs. Current compliance strategies may not successfully address the relevant standards and interpretations of the future.
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 businesses are highly competitive. (PHI only)
The unregulated energy generation, supply and marketing businesses primarily in the mid-Atlantic region are characterized by intense competition at both the wholesale and retail levels. PHI’s Competitive Energy businesses compete 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 businesses rely 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 businesses depend 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 businesses’ 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 generation plants is disrupted and storage or other alternative sources of supply are not available, the Competitive Energy businesses’ ability to operate their generating facilities could be adversely affected.
Changes in technology may adversely affect the Power Delivery business and the Competitive Energy businesses.
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 businesses 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 businesses of Pepco, DPL and ACE and the Competitive Energy businesses. 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 businesses. (PHI only)
The operations of PHI’s Competitive Energy businesses are conducted in accordance with sophisticated risk management systems that are designed to quantify 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 businesses may not protect them from significant losses caused by volatile commodity prices. (PHI only)
To lower the financial exposure related to commodity price fluctuations, PHI’s Competitive Energy businesses routinely enter into contracts to hedge the value of their assets and operations. As part of this strategy, PHI’s Competitive Energy businesses utilize 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 PHI’s energy assets. PHI must apply judgment in determining the application and effectiveness of each hedge instrument. Changes in 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 the costs of fuel used to operate those facilities so it is not completely exposed to energy price movements. Hedge targets are approved by PHI’s Corporate Risk Management Committee and may change from time to time based on market conditions. Conectiv Energy generally establishes hedge targets annually for the next three succeeding 12-month periods. Within a given 12-month horizon, the actual hedged positioning in any month may be outside of the targeted range, even if the average for a 12-month period falls within the stated range. Management exercises judgment in determining which months present the most significant risk, or opportunity, and hedge levels are adjusted accordingly. Since energy markets can move significantly in a short period of time, hedge levels may also be adjusted to reflect revised assumptions. Such factors 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 facilities, Pepco Energy Services generally does not enter into wholesale contracts to lock in the forward value of its plants. To the extent that PHI’s Competitive Energy businesses have unhedged positions or their 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 businesses can give rise to significant collateral requirements. The inability to fund those requirements may prevent the businesses 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 businesses 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 businesses to forego new business opportunities, by requiring the businesses to curtail their hedging activity, thereby increasing their 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 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 businesses are 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 businesses 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 or any of 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 and cash flows for the Power Delivery businesses of Pepco, DPL and ACE and the Competitive Energy businesses.
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, 2008, had an equity value of approximately $1.3 billion and from which PHI currently derives approximately $56 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 a notice 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 connection with the audit of PHI’s 2001 and 2002 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to six of 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 believes that its tax position with regard to its cross-border energy lease investments is appropriate based on applicable statutes, regulations and case law and is protesting the IRS adjustments and the unresolved audit issues have been forwarded to the Appeals Office of the IRS. In the event that PHI were not to prevail and were to suffer a total disallowance of the tax benefits and incur imputed original issue discount income due to the recharacterization of the leases as loans, as of December 31, 2008, PHI would have been obligated to pay approximately $520 million in additional federal and state taxes and $83 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, however that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a recharacterization of leases as loans would be recoverable in the form of lower taxes over the remaining term of the investments.
For further discussion of this matter see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory and Other Matters - Federal Tax Treatment of Cross-Border Leases” of this Form 10-K.
PHI and its subsidiaries are dependent on their ability to successfully access capital markets. An inability to access capital may adversely affect their businesses.
PHI, Pepco, DPL and ACE all rely on access to both short-term money markets and long-term capital markets as sources of liquidity and to satisfy their capital requirements that are not met by cash flow from their operations. Capital market disruptions, or a downgrade in their respective credit ratings, could increase the cost of borrowing or could prevent the companies from accessing one or more financial markets. Factors that could affect the ability of PHI and its subsidiaries to access one or more financial markets could include, but are not limited to:
· recession or an economic slowdown;
· the bankruptcy of one or more energy companies or financial institutions;
· significant changes in energy prices;
· a terrorist attack or threatened attacks; or
· a significant transmission failure.
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.
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 our liabilities, PHI, Pepco, DPL or ACE may be required to make significant unplanned cash contributions to fund these plans.
PHI holds assets in trust to meet its obligations under the PHI Retirement Plan (a defined benefit pension 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 post-retirement 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 recent years. 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 Pepco’s, DPL’s and ACE’s 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, but may also take into account the business plans and financial requirements of PHI and its other subsidiaries.
Item 1B.
Item 1B. UNRESOLVED STAFF COMMENTS
Pepco Holdings
None.
Pepco
None.
DPL
None.
ACE
None.
Item 2.
Item 2. PROPERTIES
Generation Facilities
The following table identifies the electric generating facilities owned by PHI’s subsidiaries at December 31, 2008.
a
All holdings of Conectiv Energy are owned by its various subsidiaries.
b
These facilities are owned by a subsidiary of Pepco Energy Services.
c
This facility is owned by Bethlehem Renewable Energy LLC, of which Pepco Energy Services holds a 80% membership interest.
d
This facility is owned by Eastern Landfill Gas, LLC, of which Pepco Energy Services holds a 75% membership interest.
e
This facility is owned by Pepco Energy Services, Inc.
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, 2008, taking into account the sale by DPL of its Virginia retail electric distribution and wholesale electric transmission assets in January 2008, consisted of approximately 3,200 transmission circuit miles of overhead lines, 300 transmission circuit miles of underground cables, 18,200 distribution circuit miles of overhead lines, and 15,500 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 48,210 Mcf per day. DPL owns eight natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total sendout capacity of 255,500 Mcf per day. DPL also owns approximately 111 pipeline miles of natural gas transmission mains, 1,802 pipeline miles of natural gas distribution mains, and 1,301 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 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 (16), “Commitments and Contingencies-Legal Proceedings” to the consolidated financial statements of PHI set forth in 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 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 (14), “Commitments and Contingencies-Legal Proceedings” to the financial statements of DPL set forth in 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 financial statements of ACE set forth in 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 fiscal 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, 2008, there were approximately 61,347 holders of record of Pepco Holdings common stock.
Dividends
On January 22, 2009, the Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2009, to shareholders of record on March 10, 2009.
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 fiscal years.
Period
Aggregate
Dividends
2008:
First Quarter
$
20,000,000
Second Quarter
-
Third Quarter
44,000,000
Fourth Quarter
25,000,000
$
89,000,000
2007:
First Quarter
$
15,000,000
Second Quarter
14,000,000
Third Quarter
45,000,000
Fourth Quarter
12,000,000
$
86,000,000
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 fiscal years. Dividends received by Conectiv were used to pay down short-term debt owed to PHI.
Period
Aggregate
Dividends
2008:
First Quarter
$
27,000,000
Second Quarter
15,000,000
Third Quarter
-
Fourth Quarter
10,000,000
$
52,000,000
2007:
First Quarter
$
8,000,000
Second Quarter
19,000,000
Third Quarter
-
Fourth Quarter
12,000,000
$
39,000,000
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 fiscal years. Dividends received by Conectiv were used to pay down short-term debt owed to PHI.
Period
Aggregate
Dividends
2008:
First Quarter
$
-
Second Quarter
31,000,000
Third Quarter
-
Fourth Quarter
15,000,000
$
46,000,000
2007:
First Quarter
$
20,000,000
Second Quarter
10,000,000
Third Quarter
20,000,000
Fourth Quarter
-
$
50,000,000
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 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.
(b)
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.
(c)
Includes $33 million ($20 million after-tax) from settlement of Mirant bankruptcy claims.
(d)
Includes $20 million ($18 million net of fees) benefit related to Maryland income tax settlement.
(e)
Includes $19 million of impairment losses ($14 million after-tax) related to certain energy services business assets.
(f)
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.
(g)
Includes $68 million ($41 million after-tax) gain from sale of non-utility land owned by Pepco at Buzzard Point.
(h)
Includes $71 million ($42 million after-tax) gain (net of customer sharing) from settlement of Mirant bankruptcy claims.
(i)
Includes $13 million ($9 million after-tax) related to PCI’s liquidation of a financial investment that was written off in 2001.
(j)
Includes $11 million in income tax expense related to the mixed service cost issue under IRS Revenue Ruling 2005-53.
(k)
Includes a $20 million charge related to an IRS settlement. Also includes $13 million tax benefit related to issuance of a local jurisdiction’s final consolidated tax return regulations.
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:
Registrants
Page No.
Pepco Holdings
Pepco
DPL
ACE
THIS PAGE LEFT INTENTIONALLY BLANK.
PEPCO HOLDINGS
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
PEPCO HOLDINGS, INC.
GENERAL OVERVIEW
In 2008, 2007 and 2006, respectively, PHI’s Power Delivery operations produced 51%, 56%, and 61% of PHI’s consolidated operating revenues (including revenues from intercompany transactions) and 72%, 66%, and 67% of PHI’s consolidated operating income (including income from intercompany transactions).
The Power Delivery business consists primarily of the transmission, distribution and default supply of electricity, which for 2008, 2007, and 2006, was responsible for 94%, 94%, and 95%, respectively, of Power Delivery’s operating revenues. The distribution of natural gas contributed 6%, 6% and 5% of Power Delivery’s operating revenues in 2008, 2007 and 2006, respectively. 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 varies by jurisdiction as follows:
Delaware
Standard Offer Service (SOS)
District of Columbia
SOS
Maryland
SOS
New Jersey
Basic Generation Service (BGS)
Effective January 2, 2008, DPL sold its retail electric distribution assets and its wholesale electric transmission assets in Virginia. Prior to that date, DPL supplied electricity at regulated rates to retail customers in its service territory who did not elect to purchase electricity from a competitive energy supplier, which is referred to in Virginia as Default Service.
In this Form 10-K, the supply service obligations of the respective utility subsidiaries 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.
PEPCO HOLDINGS
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.
In connection with its approval of new electric service distribution base rates for Pepco and DPL in Maryland, effective in June 2007 (the 2007 Maryland Rate Orders), the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to which the BSA applies, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA thus decouples the distribution revenue recognized in a reporting period from the amount of power delivered during the period. This change in the reporting of distribution revenue has the effect of eliminating changes in retail customer usage (whether due to weather conditions, energy prices, energy efficiency programs or other reasons) as a factor having an impact on reported revenue. As a consequence, the only factors that will cause distribution revenue from retail customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer.
The Competitive Energy businesses provide competitive generation, marketing and supply of electricity and gas, and related 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 provides 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, 2008, 2007 and 2006, the operating revenues of the Competitive Energy businesses (including revenue from intercompany transactions) were equal to 53%, 48%, and 43%, respectively, of PHI’s consolidated operating revenues, and the operating income of the Competitive Energy businesses (including operating income from intercompany transactions) was 36%, 26%, and 20% of PHI’s consolidated operating income for the years ended December 31, 2008, 2007 and 2006, respectively. For the years ended December 31, 2008, 2007 and 2006, amounts equal to 7%, 10%, and 13% respectively, of the operating revenues of the Competitive Energy businesses were attributable to electric energy and capacity, and natural gas sold to the Power Delivery segment.
Conectiv Energy’s primary objective is to maximize the value of its generation fleet by leveraging its operational and fuel flexibilities. Pepco Energy Services’ primary objective is to capture retail energy supply and service opportunities predominantly in the mid-Atlantic region.
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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 plants, and the cost of purchased energy necessary to meet its power and gas supply obligations.
The Competitive Energy businesses, like the Power Delivery business, are seasonal, and therefore weather patterns can have a material impact on operating results.
Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy sale-leaseback transactions with a book value at December 31, 2008 of approximately $1.3 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 leasing transactions, see “Regulatory and Other Matters - PHI’s Cross-Border Energy Lease Investments” in this Management’s Discussion and Analysis.
IMPACT OF THE CURRENT CAPITAL AND CREDIT MARKET DISRUPTIONS
The recent disruptions in the capital and credit markets, combined with the volatility of energy prices, have had an impact on several aspects of PHI’s businesses. While these conditions have required PHI and its subsidiaries to make certain adjustments in their financial management activities, PHI believes that it and its subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations. These market conditions, should they continue, could have a negative effect on PHI’s financial condition, results of operations and cash flows.
Liquidity Requirements
PHI and its subsidiaries depend on access to the capital and credit markets to meet their liquidity and capital requirements. To meet their liquidity requirements, PHI’s utility subsidiaries and its Competitive Energy businesses historically have relied on the issuance of commercial paper and short-term notes and on bank lines of credit to supplement internally generated cash from operations. PHI’s primary credit source is its $1.5 billion syndicated credit facility, which can be used by PHI and its utility subsidiaries to borrow funds, obtain letters of credit and support the issuance of commercial paper. This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total $1.5 billion commitment. The terms and conditions of the facility are more fully described below under the heading “Capital Resources and Liquidity ¾ Credit Facilities.”
Due to the capital and credit market disruptions, the market for commercial paper in the latter part of 2008 was severely restricted for most companies. As a result, PHI and its subsidiaries have not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that they have typically required for cash management purposes. To address the challenges posed by the current capital and credit market environment and to ensure that PHI and its subsidiaries will continue to have sufficient access to cash to meet their liquidity needs, PHI and its subsidiaries have undertaken a number of actions, including the following:
·
PHI has conducted a review to identify cash and liquidity conservation measures, including opportunities to reduce collateral obligations and to defer capital expenditures due to lower than anticipated growth. Several measures to reduce
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collateral obligations and expenditures have been taken. Additional measures could be undertaken if conditions warrant.
·
PHI issued an additional 16.1 million shares of the Company’s common stock at a price per share of $16.50 in November 2008, for net proceeds of $255 million.
·
PHI added a 364-day $400 million credit facility in November 2008.
·
In November 2008, ACE issued $250 million of First Mortgage Bonds, 7.75% Series due November 15, 2018.
·
In November 2008, DPL issued $250 million of First Mortgage Bonds, 6.40% Series due December 1, 2013.
·
In December 2008, Pepco issued $250 million of First Mortgage Bonds, 7.90% Series due December 15, 2038.
At December 31, 2008, the amount of cash, plus borrowing capacity under the syndicated credit facility and PHI’s new 364-day credit facility, available to meet the liquidity needs of PHI on a consolidated basis totaled $1.5 billion, of which $843 million consisted of the combined cash and borrowing capacity of PHI’s utility subsidiaries. During the months of January and February 2009, the average daily amount of the combined cash and borrowing capacity of PHI on a consolidated basis was $1.4 billion, and of its utility subsidiaries was $831 million. This decrease in liquidity of PHI on a consolidated basis was primarily due to increased collateral requirements of the Competitive Energy businesses. During the months of January and February 2009, the combined cash and borrowing capacity of PHI’s utility subsidiaries ranged from a low of $673 million to a high of $1 billion.
Collateral Requirements of the Competitive Energy Businesses
In conducting its retail energy sales business, Pepco Energy Services typically enters into electricity and natural gas sales 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. Generally, Pepco Energy Services acquires the energy to serve this load by entering into wholesale purchase contracts. To protect the respective parties against the risk of nonperformance by the other party, these wholesale purchase contracts typically impose collateral requirements that are tied to changes in the price of the contract commodity. In periods of energy market price volatility, these collateral obligations can fluctuate materially on a day-to-day basis.
Pepco Energy Services’ practice of offsetting its retail energy sale obligations with corresponding wholesale purchases of energy has the effect of substantially reducing the exposure of its margins to energy price fluctuations. In addition, the non-performance risks associated with its retail energy sales are relatively low due to the inclusion of governmental entities among its customers and the purchase of insurance on a significant portion of its commercial and other accounts receivable. However, because its retail energy sales contracts typically do not have collateral obligations, during periods of declining energy prices Pepco Energy Services is exposed to the asymmetrical risk of having to post collateral under its
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wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. In the second half of 2008, the decrease in energy prices has caused a significant increase in the collateral obligations of Pepco Energy Services.
In addition, 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, 2008, the Competitive Energy businesses had posted net cash collateral of $331 million and letters of credit of $558 million.
At December 31, 2008, the amount of cash, plus borrowing capacity under the syndicated credit facility and PHI’s new 364-day credit facility, available to meet the liquidity needs of the Competitive Energy businesses on a consolidated basis totaled $684 million. During the months of January and February 2009, the combined cash and borrowing capacity available to PHI’s Competitive Energy businesses ranged from a low of $378 million to a high of $757 million.
Ongoing Monitoring of Financial and Market Conditions
PHI monitors its liquidity position on a daily basis and routinely conducts stress testing to assess the impact of changes in commodity prices on its collateral requirements. Stress testing conducted over the months of January and February 2009, based on contractual rights and obligations in effect at the time, indicated that a 1% change in forward prices corresponding to the periods under the various contractual arrangements with respect to which collateral was required would have caused an estimated change of approximately $6 million in Conectiv Energy’s net collateral requirements and a change of approximately $17 million in Pepco Energy Services’ net collateral requirements. PHI’s net collateral obligations decrease when forward prices increase and increase when forward prices decrease.
PHI also closely monitors its credit ratings and outlooks and those of its rated subsidiaries, and computes the hypothetical effect that changes in credit ratings would have on collateral requirements and the cost of capital. Based on contractual provisions in effect at December 31, 2008, a one-level downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries, which would decrease ratings to below “investment grade,” would increase the collateral obligations of PHI and its subsidiaries by up to $462 million.
Counterparty Credit Risk
PHI is exposed to the risk that the counterparties to contracts may fail to meet their contractual payment obligations or may fail to deliver purchased commodities or services at the contracted price. PHI attempts to minimize these risks through, among other things, formal credit policies, regular assessments of counterparty creditworthiness, and the establishment of a credit limit for each counterparty.
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Pension and Postretirement Benefit Plans
PHI and its subsidiaries sponsor pension and postretirement benefit plans 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 have caused a decrease in the market value of benefit plan assets over the twelve months ended December 31, 2008. The negative return did not have an impact on PHI’s results of operations for 2008; however, this reduction in benefit plan assets will result in increased pension and postretirement benefit costs in future years.
PHI currently estimates that its net periodic pension benefit cost will be approximately $85 million in 2009, as compared to $24 million in 2008. The utility subsidiaries are generally responsible for approximately 80% to 85% of the total PHI net periodic pension benefit cost. Approximately 30% of net periodic pension benefit cost is capitalized.
PHI expects to make a discretionary tax deductible contribution to the pension plan in 2009 of approximately $300 million. The utility subsidiaries will be responsible for funding their share of the contribution of approximately $170 million for Pepco, $10 million for DPL and $60 million for ACE. PHI Service Company is responsible to fund the remaining share of the contribution. PHI will monitor the markets and evaluate any additional discretionary funding needs later in the year. See Note (10), “Pensions and Other Postretirement Benefits,” to the consolidated financial statements of PHI set forth in 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 and operational excellence. 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.
·
Supplementing PHI’s utility earnings through competitive energy businesses that focus on serving the competitive wholesale and retail markets primarily within the PJM Regional Transmission Organization (PJM RTO) market.
·
Pursuing technologies and practices that promote energy efficiency, energy conservation and the reduction of greenhouse gas emissions.
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.
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Strategic Analysis of Pepco Energy Services’ Retail Energy Supply Business
Over the past several months, PHI has been conducting a strategic analysis of the retail energy supply business of Pepco Energy Services. This review has included, among other things, the evaluation of potential alternative supply arrangements to reduce collateral requirements or a possible restructuring, sale or wind down of the business. As discussed above under the heading, “Impact of Current Capital and Credit Market Disruption -- Collateral Requirements of the Competitive Energy Businesses,” as energy prices have declined in the second half of 2008, the collateral that Pepco Energy Services has been required to post to secure its obligations under its wholesale energy purchase contracts has increased substantially. Among the factors being considered is the return PHI earns by investing capital in the retail energy supply business as compared to alternative investments. PHI expects the retail energy supply business to remain profitable based on its existing contract backlog and the margins that have been locked in with corresponding wholesale energy purchase contracts. The increased cost of capital associated with its collateral obligations has been factored into its retail pricing and, as a consequence, PES is experiencing reduced retail customer retention levels and reduced levels of new retail customer acquisitions.
EARNINGS OVERVIEW
Year Ended December 31, 2008 Compared to the Year Ended December 31,
PHI’s net income for the year ended December 31, 2008 was $300 million, or $1.47 per share, compared to $334 million, or $1.72 per share, for the year ended December 31, 2007.
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:
Adjustment to the equity value of cross-border energy lease investments to reflect the impact of a change in assumptions regarding the estimated timing of the tax benefits
$
(86)
Additional interest accrued under Financial Accounting Standards Board Interpretation No. 48 (FIN 48) related to the estimated federal and state income tax obligations from the change in assumptions regarding the estimated timing of the tax benefits on cross-border energy lease investments
$
(7)
Net income for the year ended December 31, 2007, included the credits set forth below in the Power Delivery operating segment, which are presented net of federal and state income taxes and are in millions of dollars.
Mirant Corporation (Mirant) bankruptcy damage claims settlement
$
Maryland income tax settlement, net of fees
$
Excluding the items listed above, net income would have been $393 million, or $1.93 per share, in 2008 and $296 million, or $1.53 per share, in 2007.
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PHI’s net income for the years ended December 31, 2008 and 2007, by operating segment, is set forth in the table below (in millions of dollars):
Change
Power Delivery
$
$
$
Conectiv Energy
Pepco Energy Services
Other Non-Regulated
(59)
(105)
Corp. & Other
(52)
(55)
Total PHI Net Income
$
$
$
(34)
Discussion of Operating Segment Net Income Variances:
Power Delivery’s $18 million increase in earnings is primarily due to the following:
·
$38 million increase due to the impact of the distribution base rate orders ($23 million related to Maryland, which became effective in June 2007 for Pepco and DPL, and $15 million related to the District of Columbia, which became effective in February 2008 for Pepco).
·
$23 million increase due to favorable income tax adjustments primarily related to FIN 48 interest impact.
·
$15 million increase due to FERC network transmission service rate changes in June 2007 and 2008.
·
$20 million decrease due to the Mirant bankruptcy damage claims settlement in 2007.
·
$18 million decrease due to the Maryland tax settlement, net of fees in 2007.
·
$16 million decrease primarily due to lower sales (primarily decreased customer usage, including an unfavorable impact of weather compared to 2007).
·
$5 million decrease due to higher operating and maintenance costs (primarily higher employee-related costs and bad-debt expense).
Conectiv Energy’s $49 million increase in earnings is primarily due to the following:
·
$43 million increase in Merchant Generation & Load Service primarily due to:
(i)
an increase of $22 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,
(ii)
an increase of $28 million due to higher PJM capacity prices net of capacity hedges,
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(iii)
an increase of $11 million due to the application of fair value accounting treatment and associated settlements with respect to excess coal hedges accounted for at fair value,
(iv)
a decrease of $9 million due to a lower of cost or market adjustment to the value of oil inventory held at the power plants at year-end 2008, and
(v)
a decrease of $9 million due to lower sales of emissions allowances.
·
$9 million increase in Energy Marketing primarily due to increased short-term power desk margins, and new default electricity supply contracts.
·
$5 million increase due to favorable income tax adjustments primarily due to the reversal of FIN 48 interest accruals.
·
$10 million decrease primarily due to higher plant maintenance.
Pepco Energy Services’ $1 million increase in earnings is primarily due to the following:
·
$6 million increase resulting from higher volumes due to growth in the retail gas supply business.
·
$2 million increase in the retail electricity business due to more favorable congestion costs; partially offset by higher cost of electricity and other electricity supply costs.
·
$2 million increase resulting from favorable income tax adjustments related to deferred income taxes.
·
$9 million decrease for the generation plants primarily due to Reliability Pricing Model (RPM) related charges.
Other Non-Regulated’s $105 million decrease in earnings is primarily due to the following:
·
$86 million after-tax charge resulting from a $124 million adjustment to the equity value of PHI’s cross-border energy lease investments.
·
$7 million after-tax charge for interest accrued under FIN 48 related to estimated federal and state income tax obligations for the period from January 1, 2001 through June 30, 2008 resulting from the change in assumptions regarding the estimated timing of the tax benefits of PHI’s cross-border energy lease investments.
·
$9 million decrease primarily due to favorable valuation adjustments to certain other PCI portfolio investments in 2007; partially offset by lower interest expense.
Corporate and Other’s $3 million increase in earnings is primarily due to lower interest expense and corporate governance costs.
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CONSOLIDATED RESULTS OF OPERATIONS
The following results of operations discussion compares the year ended December 31, 2008, to the year ended December 31, 2007. All amounts in the tables (except sales and customers) are in millions.
Operating Revenue
A detail of the components of PHI’s consolidated operating revenue is as follows:
Power Delivery
The following table categorizes Power Delivery’s operating revenue by type of revenue.
Regulated Transmission and 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 Supply Revenue is the revenue received for Default Electricity Supply. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy and Other Services Cost of Sales. Default 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
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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 sale of excess system 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 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 Supply Revenue in order to conform to the current period presentation.
Electric Operating Revenue
Other Regulated T&D Electric Revenue consists primarily of (i) transmission service revenue, (ii) revenue from the resale of energy and capacity under power purchase agreements between Pepco and unaffiliated third parties in the PJM RTO market, and (iii) either (a) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the distribution charge per customer approved in the 2007 Maryland Rate Orders 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).
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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 Washington, D.C. 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 automotive, 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.
·
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).
·
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 from the resale of energy and capacity purchased under the power purchase agreement between Panda-Brandywine, L.P. (Panda) and Pepco (the Panda PPA) (offset in Fuel and Purchased Energy and Other Services Cost of Sales.
·
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 weather-related sales (a 2% decrease in Heating Degree Days and a 10% decrease in Cooling Degree Days).
·
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
Other Default Supply Revenue consists primarily of revenue from the resale of energy and capacity purchased under non-utility generating contracts (NUGs) in the PJM RTO market.
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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 Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales and Deferred Electric Service Costs, increased by $118 million primarily due to:
·
An increase of $202 million in market-based Default Electricity Supply rates.
·
An increase of $48 million in wholesale energy revenues due to the sale in PJM RTO at higher market prices of electricity purchased from NUGs.
The aggregate amount of these increases was partially offset by:
·
A decrease of $55 million due to lower weather-related sales (a 2% decrease in Heating Degree Days and a 10% decrease in Cooling Degree Days).
·
A decrease of $33 million primarily due to existing commercial and industrial customers electing to purchase electricity from competitive suppliers.
·
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 differences in consumption among the various customer rate classes.
Gas Operating Revenue
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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 automotive, chemical and pharmaceutical.
Regulated Gas Revenue decreased by $7 million primarily due to:
·
A decrease of $4 million due to differences in consumption among the various customer rate classes.
·
A decrease of $3 million due to lower weather-related sales (a 3% decrease in Heating Degree Days).
·
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. Off-system sales are made possible due to available pipeline capacity that results from low demand for natural gas from regulated customers.
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.
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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. 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 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.
Conectiv Energy Gross Margin
Merchant Generation & 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 power 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.
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Includes $397 million and $442 million of affiliate transactions for 2008 and 2007, respectively.
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.
Consists solely of Merchant Generation & Load Service expenses; does not include the cost of fuel not consumed by the power plants and intercompany tolling expenses.
Includes tolled generation.
Includes associated hedging gains and losses.
Includes emissions expenses, fuel additives, and other fuel-related costs.
Edge Moor Units 3 and 4 and Deepwater Unit 6.
Hay Road and Bethlehem, all units.
Edge Moor Unit 5 and Deepwater Unit 1.
Consists of all default electricity supply sales; does not include standard product hedge volumes.
Calculated from data reported in Conectiv Energy’s Electric Quarterly Report (EQR) filed with the FERC; does not include capacity or ancillary services revenue.
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.
Source: PJM website (www.pjm.com).
Source: Average delivered natural gas price at Tetco Zone M3 as published in Gas Daily.
Source: National Oceanic and Atmospheric Administration National Weather Service data.
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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 & Load Service gross margin increased approximately $73 million primarily due to:
·
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.
·
An increase of approximately $46 million due to higher PJM capacity prices net of capacity hedges.
·
An increase of approximately $18 million due to the application of fair value accounting treatment and associated settlements with respect to excess coal hedges.
·
A decrease of approximately $15 million due to a lower of cost or market adjustment to the value of oil inventory held at the power plants at year-end 2008.
·
A decrease of approximately $15 million due to lower sales of emissions allowances.
Energy Marketing gross margin increased approximately $15 million primarily due to:
·
An increase of approximately $9 million in short-term power desk margins in 2008.
·
An increase of approximately $9 million due to additional default electricity supply contracts in 2008.
·
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,
·
An increase of $64 million due to higher natural gas volumes driven by customer acquisitions and higher prices in 2008,
·
An increase of $26 million due to increased construction activities in 2008;
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 generation plants.
Other Non-regulated
Other Non-Regulated operating revenue decreased by $136 million primarily due to:
·
A non-cash charge of $124 million was recorded during 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 Financial Accounting Standards Board Staff Position 13-2, 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
Power Delivery’s Fuel and Purchased Energy and Other Services Cost of Sales, which is primarily associated with Default Electricity Supply sales, increased by $218 million primarily due to:
·
An increase of $333 million in average energy costs, the result of new Default Electricity Supply contracts.
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·
An increase of $32 million in gas purchases for off-system sales, the result of higher average gas costs.
·
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 customers electing to purchase electricity from competitive suppliers.
·
A decrease of $60 million due to lower weather-related sales.
·
A decrease of $45 million due to the sale of Virginia retail electric distribution and wholesale transmission assets in January 2008.
Fuel and Purchased Energy expense is substantially offset in Regulated T&D Electric Revenue, Default 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:
·
An increase of $236 million due to higher volumes of electricity purchased at higher prices in 2008 to serve increased retail customer load.
·
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.
·
An increase of $12 million for the generation plants primarily due to capacity costs related to RPM.
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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:
·
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.
·
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.
·
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).
·
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 power 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.
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:
·
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 Supply Revenue)
·
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.
Deferred Electric Service Costs
Deferred Electric Service Costs, which relate only to ACE, decreased by $77 million to income of $9 million in 2008 from an expense of $68 million in 2007. The decrease was primarily due to:
·
A decrease of $46 million due to a lower rate of recovery associated with deferred energy costs.
·
A decrease of $29 million due to a lower rate of recovery of costs associated with energy and capacity purchased under the NUGs.
·
A decrease of $17 million due to a lower rate of recovery associated with deferred transmission costs.
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The aggregate amount of these decreases was partially offset by:
·
An increase of $15 million primarily due to a higher rate of recovery associated with Demand Side Management program costs.
Deferred Electric Service Costs are substantially offset in Regulated T&D Electric Revenue 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 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 reduced its overall effective tax rate, primarily representing net interest income accrued on effectively settled and uncertain tax positions (including interest related to the tentative settlements with the IRS on the mixed service cost and like-kind exchange issues 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
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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 (16), “Commitments and Contingencies-Regulatory and Other Matters - IRS Mixed Service Cost Issue,” to the consolidated financial statements of PHI set forth in 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. See Note (16), “Commitments and Contingencies - Regulatory and Other Matters - IRS Examination of Like-Kind Exchange Transaction” to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K.
The following results of operations discussion compares the year ended December 31, 2007, to the year ended December 31, 2006. All amounts in the tables (except sales and customers) are in millions.
Operating Revenue
A detail of the components of PHI’s consolidated operating revenue is as follows:
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Power Delivery
The following table categorizes Power Delivery’s operating revenue by type of revenue.
Change
Regulated T&D Electric Revenue
$
1,592
$
1,496
$
Default Supply Revenue
3,295
3,309
(14)
Other Electric Revenue
Total Electric Operating Revenue
4,953
4,863
Regulated Gas Revenue
Other Gas Revenue
Total Gas Operating Revenue
Total Power Delivery Operating Revenue
$
5,244
$
5,119
$
Regulated Transmission and 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 Supply Revenue is the revenue received for Default Electricity Supply. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy and Other Services Cost of Sales. Default 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 for 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 sale of excess system capacity.
In response to an order issued by the 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 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
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recovery of retail transmission rates relative to the cost incurred. In addition, ACE’s retail transmission revenue for the period prior to January 1, 2008 has been reclassified to Default Supply Revenue in order to conform to the current period presentation.
Electric Operating Revenue
Other Regulated T&D Electric Revenue consists primarily of (i) transmission service revenue, (ii) revenue from the resale of energy and capacity under power purchase agreements between Pepco and unaffiliated third parties in the PJM RTO market, and (iii) any necessary Revenue Decoupling Adjustments.
Regulated T&D Electric Revenue increased by $96 million primarily due to:
·
An increase of $43 million in sales due to higher weather-related sales (a 17% increase in Cooling Degree Days and a 12% increase in Heating Degree Days).
·
An increase of $29 million in Other Regulated T&D Electric Revenue from the resale of energy and capacity purchased under the Panda PPA, (offset in Fuel and Purchased Energy and Other Services Cost of Sales).
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·
An increase of $20 million due to a distribution rate change under the 2007 Maryland Rate Orders that became effective in June 2007, including a positive $5 million Revenue Decoupling Adjustment.
·
An increase of $12 million due to higher pass-through revenue primarily resulting from tax rate increases in the District of Columbia (primarily offset in Other Taxes).
·
An increase of $5 million due to customer growth of 1% in 2007.
The aggregate amount of these increases was partially offset by:
·
A decrease of $10 million due to a change in the Delaware rate structure effective May 1, 2006, which shifted revenue from Regulated T&D Electric Revenue to Default Supply Revenue.
·
`A decrease of $4 million due to a Delaware base rate reduction effective May 1, 2006.
Default Electricity Supply
Other Default Supply Revenue consists primarily of revenue from the resale of energy and capacity purchased under NUGs in the PJM RTO market.
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Default Supply Revenue, which is partially offset in Fuel and Purchased Energy and Other Services Cost of Sales, decreased by $14 million primarily due to:
·
A decrease of $346 million primarily due to commercial and industrial customers electing to purchase electricity from competitive suppliers.
·
A decrease of $95 million due to differences in consumption among the various customer rate classes.
·
A decrease of $46 million in wholesale energy revenue primarily the result of the sales by ACE of its Keystone and Conemaugh interests and the B.L. England generating facilities.
·
A decrease of $4 million due to a DPL adjustment to reclassify market-priced supply revenue from Regulated T&D Electric Revenue in 2006.
The aggregate amount of these decreases was partially offset by:
·
An increase of $379 million due to annual increases in market-based Default Electricity Supply rates.
·
An increase of $87 million due to higher weather-related sales (a 17% increase in Cooling Degree Days and a 12% increase in Heating Degree Days).
·
An increase of $10 million due to a change in Delaware rate structure effective May 1, 2006 that shifted revenue from Regulated T&D Electric Revenue to Default Supply Revenue.
Other Electric Revenue
Other Electric Revenue increased $8 million to $66 million in 2007 from $58 million in 2006 primarily due to increases in revenue related to pole rentals and late payment fees.
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Gas Operating Revenue
Regulated Gas Revenue increased by $6 million primarily due to:
·
An increase of $12 million due to colder weather (a 15% increase in Heating Degree Days).
·
An increase of $6 million due to base rate increases effective in November 2006 and April 2007.
·
An increase of $5 million due to differences in consumption among the various customer rate classes.
·
An increase of $3 million due to customer growth of 1% in 2007.
The aggregate amount of these increases was partially offset by:
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·
A decrease of $18 million due to Gas Cost Rate decreases effective November 2006, April 2007 and November 2007 resulting from lower natural gas commodity costs (offset in Fuel and Purchased Energy and Other Services Cost of Sales).
Other Gas Revenue
Other Gas Revenue increased by $29 million to $80 million in 2007 from $51 million in 2006 primarily due to higher off-system sales (partially offset in Fuel and Purchased Energy and Other Services Cost of Sales). The gas sold off-system resulted from increased demand from unaffiliated third party electric generators during periods of low customer demand for natural gas.
Conectiv Energy
Conectiv Energy Gross Margin
Merchant Generation & 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 power 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.
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Includes $442 million and $471 million of affiliate transactions for 2007 and 2006, respectively. The 2006 amount has been reclassified to exclude $193 million of intra-affiliate transactions that were reported gross in 2006 at the segment level.
Includes $7 million and $5 million of affiliate transactions for 2007 and 2006, respectively. The 2006 amount has been reclassified to exclude $193 million of intra-affiliate transactions that were reported gross in 2006 at the segment level. Also, excludes depreciation and amortization expense of $38 million and $36 million, respectively.
Consists solely of Merchant Generation & Load Service expenses; does not include the cost of fuel not consumed by the power plants and intercompany tolling expenses.
Includes tolled generation.
Includes associated hedging gains and losses.
Includes adjusted 2006 amount related to change in natural gas hedge allocation methodology.
Includes emissions expenses, fuel additives, and other fuel-related costs.
Edge Moor Units 3 and 4 and Deepwater Unit 6.
Hay Road and Bethlehem, all units.
Edge Moor Unit 5 and Deepwater Unit 1. Generation output for these units was negative for the first and fourth quarters of 2006 because of station service consumption.
Consists of all default electricity supply sales; does not include standard product hedge volumes.
Calculated from data reported in Conectiv Energy’s Electric Quarterly Report (EQR) filed with the FERC; does not include capacity or ancillary services revenue.
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.
Source: PJM website (www.pjm.com).
Source: Average delivered natural gas price at Tetco Zone M3 as published in Gas Daily.
Source: National Oceanic and Atmospheric Administration National Weather Service data.
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Merchant Generation & Load Service gross margin increased $69 million primarily due to:
·
An increase of approximately $77 million primarily due to 43% higher generation output attributable to more favorable weather and improved availability at the Hay Road and Deepwater generating plants and improved spark spreads.
·
An increase of approximately $26 million due to higher capacity prices due to the implementation of the PJM Reliability Pricing Model.
·
A decrease of $33 million due to less favorable natural gas fuel hedges, and the expiration, in 2006, of an agreement with an international investment banking firm to hedge approximately 50% of the commodity price risk of Conectiv Energy’s generation and Default Electricity Supply commitment to DPL.
Energy Marketing gross margin decreased $5 million primarily due to:
·
A decrease of $5 million due to lower margins in oil marketing.
·
A decrease of $4 million due to lower margins in natural gas marketing.
·
An increase of $3 million for adjustments related to an unaffiliated generation operating services agreement that expired in 2006.
Pepco Energy Services
Pepco Energy Services’ operating revenue increased $640 million to $2,309 million in 2007 from $1,669 million in 2006 primarily due to:
·
An increase of $646 million due to higher volumes of retail electric load served at higher prices in 2007 driven by customer acquisitions.
·
An increase of $27 million due to higher volumes of wholesale natural gas sales in 2007 that resulted from increased natural gas supply transactions to deliver gas to retail customers.
The aggregate amount of these increases was partially offset by:
·
A decrease of $32 million due primarily to lower construction activity in 2007 and to the sale of five construction businesses in 2006.
Other Non-Regulated
Other Non-Regulated operating revenue decreased $15 million to $76 million in 2007 from $91 million in 2006. The operating revenue of this segment primarily consists of lease earnings recognized under Statement of Financial Accounting Standards No. 13, “Accounting for Leases.” The revenue decrease is primarily due to:
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·
A change in state income tax lease assumptions that resulted in increased revenue in 2006 as compared to 2007.
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
Power Delivery’s Fuel and Purchased Energy and Other Services Cost of Sales, which is primarily associated with Default Electricity Supply sales, increased by $56 million primarily due to:
·
An increase of $445 million in average energy costs, the result of new Default Electricity Supply contracts.
·
An increase of $93 million due to higher weather-related sales.
·
An increase of $29 million for energy and capacity purchased under the Panda PPA.
The aggregate amount of these increases was partially offset by:
·
A decrease of $472 million primarily due to commercial and industrial customers electing to purchase an increased amount of electricity from competitive suppliers.
·
A decrease of $36 million in the Default Electricity Supply deferral balance.
·
Fuel and Purchased Energy expense is primarily offset in Regulated T&D Electric Revenue, Default Supply Revenue, Regulated Gas Revenue or Other Gas Revenue.
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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 $630 million primarily due to:
·
An increase of $636 million due to higher volumes of purchased electricity at higher prices in 2007 to serve increased retail customer load.
·
An increase of $40 million due to higher volumes of wholesale natural gas sales in 2007 that resulted from increased natural gas supply transactions to deliver gas to retail customers.
The aggregate amount of these increases was partially offset by:
·
A decrease of $45 million due primarily to lower construction activity in 2007 and to the sale of five construction businesses in 2006.
Other Operation and Maintenance
A detail of PHI’s other operation and maintenance expense is as follows:
Other Operation and Maintenance expense of the Power Delivery segment increased by $27 million; however, excluding the favorable variance of $34 million primarily resulting from ACE’s sale of the B.L. England electric generating facility in February 2007, Other Operation and Maintenance expenses increased by $61 million. The $61 million increase was primarily due to:
·
An increase of $16 million in employee-related costs.
·
An increase of $11 million in preventative maintenance and system operation costs.
·
An increase of $7 million in customer service operation expenses.
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·
An increase of $4 million in costs associated with Default Electricity Supply (primarily deferred and recoverable).
·
An increase of $4 million in regulatory expenses.
·
An increase of $4 million in accounting service expenses.
·
An increase of $3 million due to various construction project write-offs related to customer requested work.
·
An increase of $3 million in Demand Side Management program costs (offset in Deferred Electric Service Costs).
·
An increase of $3 million due to higher bad debt expenses.
Other Operation and Maintenance expense for Conectiv Energy increased by $11 million primarily due to:
·
Higher plant maintenance costs due to more scheduled outages in 2007 and higher costs of materials and labor.
Other Operation and Maintenance expense for Pepco Energy Services increased by $6 million due to:
·
Higher retail electric and gas operating costs to support the growth in the retail business in 2007.
Other Operation and Maintenance expense for Corporate & Other increased by $7 million due to:
·
An increase in employee-related costs.
Depreciation and Amortization
Depreciation and Amortization expenses decreased by $47 million to $366 million in 2007 from $413 million in 2006. The decrease is primarily due to:
·
A decrease of $31 million in ACE’s regulatory asset amortization resulting primarily from the 2006 sale of ACE’s interests in Keystone and Conemaugh.
·
A decrease of $19 million in depreciation due to a change in depreciation rates in accordance with the 2007 Maryland Rate Order.
Other Taxes
Other Taxes increased by $14 million to $357 million in 2007 from $343 million in 2006. The increase was primarily due to:
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·
An increase in pass-throughs resulting from tax rate increases (partially offset in Regulated T&D Electric Revenue).
Deferred Electric Service Costs
Deferred Electric Service Costs, which relate only to ACE, increased by $46 million to $68 million in 2007 from $22 million in 2006. The increase is primarily due to:
·
An increase of $38 million due to a higher rate of recovery associated with energy and capacity purchased under the NUGs.
·
An increase of $12 million due to a higher rate of recovery associated with deferred energy costs.
The aggregate amount of these increases was partially offset by:
·
A decrease of $3 million due to a lower rate of recovery associated with Demand Side Management program costs.
Deferred Electric Service Costs are substantially offset in Regulated T&D Electric Revenue and Other Operation and Maintenance.
Impairment Losses
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. During 2006, Pepco Holdings recorded pre-tax impairment losses of $19 million ($14 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 - Proceeds from Settlement of Mirant Bankruptcy Claims” herein.
Income Tax Expense
PHI’s effective tax rates for the years ended December 31, 2007 and 2006 were 36.0% and 39.3%, respectively. The decrease in the effective tax rate in 2007 was primarily the result of a 2007 Maryland state income tax refund. The refund was due to an increase in the tax basis of certain assets sold in 2000, and as a result, PHI’s 2007 income tax expense was reduced by approximately $20 million, with a corresponding decrease to the effective tax rate of 3.7%.
CAPITAL RESOURCES AND LIQUIDITY
This section discusses Pepco Holdings’ working capital, cash flow activity, capital requirements and other uses and sources of capital.
PEPCO HOLDINGS
Working Capital
At December 31, 2008, Pepco Holdings’ current assets on a consolidated basis totaled $2.6 billion and its current liabilities totaled $2 billion. At December 31, 2007, Pepco Holdings’ current assets on a consolidated basis totaled $2 billion and its current liabilities totaled $2 billion. The increase in working capital from December 31, 2007 to December 31, 2008 is primarily due to an increase in cash as a result of the issuance of long-term debt during the fourth quarter of 2008.
At December 31, 2008, Pepco Holdings’ cash and current cash equivalents totaled $384 million, of which $343 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 (cash that is available to be used only for designated purposes) totaled $10 million. At December 31, 2007, Pepco Holdings’ cash and current cash equivalents totaled $55 million and its current restricted cash totaled $15 million. See “Capital Requirements - Contractual Arrangements with Credit Rating Triggers or Margining Rights” herein for additional information.
A detail of PHI’s short-term debt balance and its current maturities of long-term debt and project funding balance follows.
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Credit Facilities
PHI, Pepco, DPL and ACE maintain a credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under this primary 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. All indebtedness incurred under the facility is unsecured.
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 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 credit facility in the amount of $400 million with a syndicate of nine lenders. Under the facility, PHI may obtain revolving loans and swingline loans over the term of the facility, which expires on November 6, 2009. The facility does not provide for the issuance of letters of credit. All indebtedness incurred under the facility is unsecured. 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 primary credit facility. The absence of a material adverse
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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.
Typically, PHI and its utility subsidiaries issue commercial paper if required to meet their short-term working capital requirements. Given the recent lack of liquidity in the commercial paper markets, however, the companies have borrowed under the primary credit facility to maintain sufficient cash on hand to meet daily short-term operating needs. As of December 31, 2008, PHI had an outstanding loan of $50 million and Pepco had an outstanding loan of $100 million under the facility. In January 2009, PHI borrowed an additional $150 million under the facility.
Cash and Credit Facilities Available as of December 31, 2008
(a)
Cash and cash equivalents reported on the Balance Sheet total $384 million, which includes the $343 million invested in money market funds and $41 million held in cash and uncollected funds.
During the months of January and February 2009, the total cash and credit facilities available to PHI on a consolidated basis ranged from a low of $1.1 billion to a high of $1.7 billion, and averaged $1.4 billion. The total cash and credit facilities available to the utility subsidiaries collectively ranged from a low of $673 million to a high of $1 billion, and averaged $831 million.
Cash Flow Activity
PHI’s cash flows for 2008, 2007, and 2006 are summarized below.
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Operating Activities
Cash flows from operating activities are summarized below for 2008, 2007, and 2006.
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 businesses fluctuate significantly based on changes in energy market prices.
As of December 31, 2008 and 2007, the combined net cash collateral positions of the Pepco Energy Services and Conectiv Energy businesses were net cash posted of $331 million and $90 million, respectively. As energy prices have declined in the second half of 2008, the collateral that the Competitive Energy businesses have been required to post has increased substantially.
In addition, the transfer by Pepco of the Panda PPA to Sempra Energy Trading LLC had an impact on 2008 cash flows from operating activities. Non-cash adjustments to net income reflect the change in restricted cash equivalents used to make the payment and changes in working capital include the reduction in the regulatory liability established to help offset future above-market capacity and energy purchase costs.
Net cash from operating activities in 2007 was $592 million higher than in 2006. In addition to an increase in net income, the factors that primarily contributed to the increase were: (i) a decrease of $203 million in taxes paid in 2007, partially attributable to a tax payment of $121 million made in February 2006 in connection with an unresolved tax matter (see Note (16), “Commitments and Contingencies ¾ Regulatory and Other Matters - IRS Mixed Service Cost Issue” to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K), (ii) a decrease in cash collateral requirements associated with Competitive Energy activities, and (iii) the receipt of the proceeds of the Mirant bankruptcy settlement, of which $399 million was designated as operating cash flows and $15 million was designated as investing cash flows.
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Investing Activities
Cash flows used by investing activities during 2008, 2007, and 2006 are summarized below.
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 generation plants. The increase in Power Delivery capital expenditures was primarily attributable to capital costs associated with new customer services, distribution reliability, and transmission. The proceeds from the sale of assets in 2008 consisted primarily of $54 million received from DPL’s sale of its Virginia retail electric distribution assets and wholesale electric transmission assets. 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.
Net cash used by investing activities in 2007 was $352 million higher than in 2006 primarily due to: (i) a $148 million increase in capital expenditures, $107 million of which relates to Power Delivery, and (ii) a decrease of $171 million in cash proceeds from the sale of property. The increase in Power Delivery capital expenditures is primarily due to major transmission projects and new substations for Pepco and ACE. The proceeds from the sale of other assets in 2006 consisted primarily of $175 million from the sale of ACE’s interest in the Keystone and Conemaugh generating facilities. Proceeds from the sale of other assets in 2007 consisted primarily of $9 million received from the sale of the B.L. England generating facility. Cash flows from investing activities in 2007 also include $15 million of the net settlement proceeds received by Pepco in the Mirant bankruptcy settlement that were specifically designated as a reimbursement of certain investments in property, plant and equipment.
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Financing Activities
Cash flows used by financing activities during 2008, 2007 and 2006 are summarized below.
Net cash provided by financing activities in 2008 was $837 million higher than in 2007. Net cash used by financing activities in 2007 was $161 million higher than in 2006.
Common Stock Dividends
Common stock dividend payments were $222 million in 2008, $203 million in 2007, and $198 million in 2006. The increase in common dividends paid in 2008 was the result of additional shares outstanding (primarily from PHI’s sale of 6.5 million shares of common stock in November 2007) and a quarterly dividend increase from 26 cents per share to 27 cents per share beginning in the first quarter of 2008. The increase in common dividends paid in 2007 was due to the issuance of the additional shares under the DRP.
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 DRP, PHI issued approximately 1.3 million shares of common stock in 2008, approximately 1 million shares of common stock in 2007 and approximately 1.2 million shares of common stock in 2006.
Changes in Outstanding Preferred Stock
Cash flows from the redemption of preferred stock in 2008, 2007 and 2006 are summarized in the chart below.
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Changes in Outstanding Long-Term Debt
Cash flows from the issuance and redemption of long-term debt in 2008, 2007 and 2006 are summarized in the charts below.
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Purchase of Tax-Exempt Auction Rate Bonds
The redemptions in 2008 shown below 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
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difficult for the remarketing agent to successfully remarket the bonds. These bond purchases consisted of the following:
·
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.
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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 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 obligations of the PHI subsidiaries with respect to these tax-exempt bonds are considered to be extinguished for accounting purposes; however, each of the companies continues 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.
Changes in Short-Term Debt
Due to the recent capital and credit market disruptions, the market for commercial paper in 2008 has been severely restricted for most companies. As a result, PHI and its subsidiaries have not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that they have 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 utility subsidiaries borrowed under the primary 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. In January 2009, PHI borrowed an additional $150 million under this facility.
In March 2008, DPL obtained a $150 million unsecured bank loan that matures in July 2009. Interest on the loan is calculated at a variable rate. In May 2008, Pepco obtained a $25 million bank loan that matures on April 30, 2009. Interest on the loan is calculated at a variable rate.
The following insured Variable Rate Demand Bonds (VRDBs) repurchased in 2008 by The Bank of New York Mellon, as bond trustee, were tendered to the trustee by the holders in accordance with the terms of the VRDBs for purchase at par:
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$17 million of Pollution Control Revenue Refunding Bonds 1997 Series A issued by Salem County for the benefit of ACE, and
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$5 million of Pollution Control Revenue Refunding Bonds 1997 Series B issued by Salem County for the benefit of ACE.
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The purchase of these VRDBs was financed by The Bank of New York Mellon under Standby Bond Purchase Agreements for the respective series. If these VRDBs cannot be remarketed by the remarketing agent prior to the first anniversary of the purchase of the VRDBs by the bond trustee, ACE will be obligated to redeem 1/10th of the principal amount of each series of VRDBs held by the bond trustee every six months thereafter. While the VRDBs are held by the bond trustee, ACE is obligated to pay interest on such bonds at a rate equal to the prime rate or LIBOR plus 50 basis points.
In November 2008, DPL repurchased $9 million of Variable Rate Demand Bonds due 2024.
In 2007, PHI redeemed a total of $36 million in short-term debt with cash from operations.
In 2006, Pepco and DPL issued short-term debt of $67 million and $91 million, respectively, in order to cover capital expenditures and tax obligations throughout the year.
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 to A&N Electric Cooperative for a purchase price of approximately $49 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative for a purchase price of approximately $5 million, after closing adjustments.
Sales of ACE Generating Facilities
On September 1, 2006, ACE completed the sale of its interest in the Keystone and Conemaugh generating facilities for $175 million (after giving effect to post-closing adjustments). On February 8, 2007, ACE completed the sale of the B.L. England generating facility for a price of $9 million and in February 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 Item 8 of this Form 10-K.
Sale of Interest in Cogeneration Joint Venture
During the first quarter of 2006, Conectiv Energy recognized a $12 million pre-tax gain ($8 million after-tax) on the sale of its equity interest in a joint venture which owns a wood burning cogeneration facility.
Proceeds from Settlement of Mirant Bankruptcy Claims
On September 5, 2008, Pepco transferred the Panda PPA to Sempra Energy Trading LLC (Sempra), along with a payment to Sempra, terminating all further rights, obligations and liabilities of Pepco under the Panda PPA. The use of the damages received from Mirant to offset above-market costs of energy and capacity under the Panda PPA and to make the payment to Sempra reduced the balance of proceeds from the Mirant settlement to approximately $102 million as of December 31, 2008.
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In November 2008, Pepco filed with the District of Columbia Public Service Commission (DCPSC) and the MPSC proposals to share with customers the remaining balance of proceeds from the Mirant settlement in accordance with divestiture sharing formulas previously approved by the respective commissions. Under Pepco’s proposals, District of Columbia and Maryland customers would receive a total of approximately $25 million and $29 million, respectively. On December 12, 2008, the DCPSC issued a Notice of Proposed Rulemaking concerning the sharing of the Mirant divestiture proceeds, including the bankruptcy settlement proceeds. The public comment period for the proposed rules has expired without any comments being submitted. This matter remains pending before the DCPSC.
On February 17, 2009, Pepco, the Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff filed a settlement agreement with the MPSC. The settlement, among other things, provides that of the remaining balance of the Mirant settlement, Pepco shall distribute $39 million to its Maryland customers through a one-time billing credit. If the settlement is approved by the MPSC, Pepco currently estimates that it will result in a pre-tax gain in the range of $15 million to $20 million, which will be recorded when the MPSC issues its final order approving the settlement.
Pending the final disposition of these funds, the remaining $102 million in proceeds from the Mirant settlement is being accounted for as restricted cash and as a regulatory liability.
Capital Requirements
Capital Expenditures
Pepco Holdings’ total capital expenditures for the year ended December 31, 2008 totaled $781 million of which $587 million was incurred by Power Delivery, $138 million was incurred by Conectiv Energy, $31 million was incurred by Pepco Energy Services and $25 million was incurred 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 2009 through 2013.
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Pepco Holdings expects to fund these expenditures through internally generated cash and external financing.
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)) and gas delivery are primarily for facility replacements and upgrades to accommodate customer growth and reliability.
Blueprint for the Future
During 2007, Pepco, DPL and ACE each announced an initiative that is referred to as the “Blueprint for the Future.” These initiatives combine traditional energy efficiency programs with new technologies and systems to help customers manage their energy use and reduce the total cost of energy. The programs include demand side management (DSM) 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 HVAC systems. Under the programs, customers also could receive credits on their bills for allowing the utility company to “cycle,” or intermittently turn off, their central air conditioning or heat pumps when wholesale electricity prices are high. The programs contemplate that business customers would receive financial incentives for using energy efficient equipment, and would be rewarded for reducing use during periods of peak demand. Additionally, plans include the installation of “smart meters” for all customers in the District of Columbia, Maryland, Delaware and New Jersey, providing the utilities with the ability to remotely read the meters and identify the location of a power outage. Pepco, DPL and ACE have made filings with their respective regulatory commissions for approval of certain aspects of these programs. Delaware has approved a recovery mechanism associated with these plans, and work has proceeded to prepare for the installation of an Advanced Metering Infrastructure (AMI) by the last quarter of 2009.
On December 18, 2008, the DCPSC conditionally approved five DSM programs. The cost of these programs will be recovered through a rate surcharge. On December 31, 2008 the MPSC conditionally approved for both Pepco and DPL, four residential and four non-residential DSM/energy efficiency programs. The MPSC will consider an AMI program in a separate proceeding. PHI anticipates that the costs of these programs will be recovered through a previously approved surcharge mechanism.
MAPP Project
In October 2007, the PJM Board of Managers approved PHI’s proposed MAPP transmission project for construction of a new 230-mile, 500-kilovolt interstate transmission project at a then-estimated cost of $1 billion. This MAPP project will 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. This MAPP project is part of PJM’s Regional Transmission Expansion Plan required to address the reliability objectives of the PJM RTO system. On December 4, 2008, the PJM Board approved a direct-current technology for segments of the project including the Chesapeake Bay Crossing. With this modification, the cost of the MAPP project currently is estimated at $1.4 billion. PJM has determined that the line
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segment from Possum Point substation to the second substation on the Delmarva Peninsula (Indian River substation) is required to be operational by June 1, 2013. PJM is continuing to evaluate the in-service date for the remaining 80-miles of line segment to connect the Indian River substation to the Salem substation. Construction is expected to occur in sections over the next five year period.
Delta Project
In December 2007, Conectiv Energy announced a decision to construct a 545 megawatt natural gas and oil-fired combined-cycle electricity generation plant to be located in Peach Bottom Township, Pennsylvania (Delta Project). The total construction expenditures for the Delta Project are expected to be $470 million, of which $62 million was expended in 2008 and $63 million in 2007 for three combustion turbines. Projected expenditures of $230 million in 2009, $95 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 2007, Conectiv Energy began construction of a new 100 megawatt combustion turbine power plant in Millville, New Jersey. The total construction expenditures for this project are expected to be $75 million (of which $41 million and $23 million, respectively, were incurred in 2008 and 2007), with projected expenditures of $10 million in 2009. These future expenditures 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 2009.
Compliance with Delaware Multipollutant Regulations
As required by the Delaware multipollutant emissions regulations adopted by the Delaware Department of Natural Resources and Environmental Control, PHI, in June 2007, filed a compliance plan for controlling nitrogen oxide (NOx), sulfur dioxide (SO2) and mercury emissions from its Edge Moor power plant. The plan includes installation of a sodium-based sorbent injection system and a Selective Non-Catalytic Reduction (SNCR) system and carbon injection for Edge Moor Units 3 and 4, and use of an SNCR system and lower sulfur oil at Edge Moor Unit 5. Conectiv Energy currently believes that with these modifications, it will be able to meet the requirements of the new regulations at an estimated capital cost of $81 million (of which $47 million was expended through December 2008) with projected expenditures of $18 million in 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 2008, PHI’s Board of Directors declared quarterly dividends of 27 cents per share of common stock payable on March 31, 2008, June 30, 2008, September 30, 2008 and December 31, 2008.
On January 22, 2009, the Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2009, to shareholders of record on March 10, 2009.
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PHI 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 and regulatory laws, which impose limitations on the funds that can be used to pay dividends and, in the case of regulatory laws, as applicable, may require the prior approval of the relevant utility regulatory commissions before dividends can be paid, (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 certificate of incorporation which provides that, if any preferred stock is outstanding, no dividends may be paid on the ACE common stock if, after payment, ACE’s common stock capital plus surplus would be less than the involuntary liquidation value of the outstanding preferred stock. Pepco and DPL have no shares of preferred stock outstanding. Currently, the restriction in the ACE charter does not limit its ability to pay dividends.
Pension Funding
Pepco Holdings has a noncontributory retirement plan (the PHI Retirement Plan) that covers substantially all employees of Pepco, DPL and ACE and certain employees of other Pepco Holdings subsidiaries.
As of the 2008 valuation, the PHI Retirement Plan satisfied the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) without requiring any additional funding. PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level in excess of 100% of its accumulated benefit obligation (ABO) and 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 100% of accrued liabilities phased in over time. The funding target was 92% for 2008 and is 94% of the accrued liability for 2009. In 2008 and 2007, no contributions were made to the PHI Retirement Plan.
In 2008, the ABO for the PHI Retirement Plan decreased to $1.57 billion from $1.59 billion in 2007, due to an increase in the discount rate from 6.25% to 6.50%. The PHI Retirement Plan assets experienced a negative return of 24% in 2008, below the 8.25% level assumed in the valuation. As a result of the combination of these factors, the funding level at year-end 2008 was below both 100% of the ABO and the funding target for January 1, 2009. Although PHI projects there will be no minimum funding requirement for 2009 under the Pension Protection Act, PHI expects to make a discretionary tax-deductible contribution of approximately $300 million to bring its plan assets to at least the funding target level for 2009 under the Pension Protection Act. For additional discussion of PHI’s Pension and Other Postretirement Benefits, see Note (10), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K.
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Contractual Obligations and Commercial Commitments
Summary information about Pepco Holdings’ consolidated contractual obligations and commercial commitments at December 31, 2008, is as follows:
(a) Includes transition bonds issued by ACE Funding.
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 (16), “Commitments and Contingencies,” to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K.
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Energy Contract Net Asset/Liability Activity
The following table provides detail on changes in the net asset or liability position of the Competitive Energy businesses (consisting of the activities of the Conectiv Energy and Pepco Energy Services segments) with respect to energy commodity contracts from one period to the next:
(a)
Includes all SFAS No. 133 hedge activity and trading activities recorded at fair value through Accumulated Other Comprehensive Income (AOCI) or on the Statements of Earnings, as required.
The $314 million net liability on energy contracts at December 31, 2008 was primarily attributable to losses on power swaps and natural gas futures and swaps designated as hedges of future energy purchases or production under Statement of Financial Accounting Standards (SFAS) No. 133. Prices of electricity and natural gas declined during the second half of 2008, which resulted in unrealized losses on the energy contracts of the Competitive Energy businesses. These businesses recorded unrealized losses of $315 million on energy contracts in Other Comprehensive Income as these energy contracts were effective hedges under SFAS No. 133. 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 businesses to their customers.
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PHI uses its best estimates to determine the fair value of the commodity and derivative contracts that its Competitive Energy businesses hold and sell. The fair values in each category presented below reflect forward prices and volatility factors as of December 31, 2008 and are subject to change as a result of changes in these factors:
(a)
Includes all SFAS No. 133 hedge activity and trading activities recorded at fair value through AOCI or on the Statements of Earnings, 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 is 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 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, 2008, 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 $462 million. PHI believes that it and its utility subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.
Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with 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
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receive, or be required to post, collateral due to energy price movements. As of December 31, 2008, Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities provided net cash collateral in the amount of $365 million in connection with these activities.
Environmental Remediation Obligations
PHI’s accrued liabilities as of December 31, 2008 include approximately $14 million, of which $6 million is expected to be incurred in 2009, 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, 2008, were:
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$4 million, of which $1 million is expected to be incurred in 2009, 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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$5 million in environmental remediation costs, of which $1 million is expected to be incurred in 2009, payable by Conectiv Energy associated with the Deepwater generating facility.
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Less than $1 million for environmental remediation costs related to former manufactured gas plant operations at a Cambridge, Maryland site on DPL-owned property, adjacent property and the adjacent Cambridge Creek, all of which is expected to be incurred in 2009.
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$2 million, constituting Pepco’s liability for a remedy at the Metal Bank/Cottman Avenue site.
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$2 million, most of which is expected to be incurred in 2009, 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 a small portion is expected to be incurred in 2009, 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
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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 efficient 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.
Internally Generated Cash
The primary source of Pepco Holdings’ internally generated funds is the cash flow generated by its regulated utility subsidiaries in the Power Delivery business. Additional sources of funds include cash flow generated from its non-regulated subsidiaries and 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 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. Due to the recent capital and credit market disruptions, however, the market for commercial paper has been severely restricted for most companies. As a result, PHI and its subsidiaries have not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that they have typically required for cash management purposes.
A further description of the existence and availability of the sources of short-term funding, and the impact of the ongoing capital and credit market disruptions, is set forth above under the headings “Impact of the Current Capital and Credit Market Disruptions - Collateral Requirements of the Competitive Energy Businesses” and “Credit Facilities.”
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 Delaware Public Service
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Commission (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, or an intra-system cash management program 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.
REGULATORY AND OTHER MATTERS
For a discussion of material pending matters such as regulatory and legal proceedings, and other commitments and contingencies, see Note (16), “Commitments and Contingencies,” to the consolidated financial statements of PHI set forth in 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.
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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 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 SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). Management has identified Power Delivery as a single reporting unit based on the aggregation of components. The first step of the goodwill impairment test under SFAS No. 142 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 tests its goodwill for impairment annually as of July 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 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 July 1, 2008 annual impairment test indicated that its goodwill was not impaired. PHI performed an interim test of goodwill for impairment at December 31, 2008 as its market capitalization was below its book value for a significant part of the fourth quarter of 2008, and it concluded that its goodwill was not impaired. Details about the interim test at year-end and the results are included in Note (6), “Goodwill,” in PHI’s consolidated financial statements in Item 8 of this Form 10-K.
In order to estimate the fair value of the Power Delivery reporting unit, PHI 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 estimate of terminal value is based on a constant, annual cash flow growth rate that is consistent with Power Delivery’s plan, and the other estimate of terminal value is based on a multiple of earnings before interest, taxes, depreciation, and amortization that management believes is consistent with relevant market multiples for comparable utilities. Each model uses a cost of capital appropriate for a regulated utility as the discount rate for the estimated cash flows associated with the reporting unit. Neither valuation model evidenced impairment of goodwill. PHI has consistently used this valuation model to estimate the fair value of Power Delivery since the adoption of SFAS No. 142.
The estimation of fair value is dependent on a number of factors, including but not limited to interest rates, growth assumptions, assumptions about regulatory ratemaking
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proceedings, 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 December 31, 2008 would not have resulted in the Power Delivery reporting unit failing the first step of the impairment test as defined in SFAS No. 142. 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, the results of rate-making proceedings, 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.
SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” requires that certain long-lived assets must be tested for recoverability whenever events or circumstances indicate that the carrying amount may not be recoverable. 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.
Accounting for Derivatives
Pepco Holdings believes that the estimates involved in accounting for its derivative instruments represent “Critical Accounting Estimates” because (i) the fair value of the instruments are highly susceptible to changes in market value and/or interest rate fluctuations, (ii) there are significant uncertainties in modeling techniques used to measure fair value in certain circumstances, (iii) actual results could vary from those used in Pepco Holdings’ estimates and the impact of such variations could be material, and (iv) changes in fair values and market prices could result in material impacts to Pepco Holdings’ assets, liabilities, other comprehensive income (loss), and results of operations. See Note (2), “Significant Accounting Policies ¾ Accounting for Derivatives,” to the consolidated financial statements of PHI set forth in 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 and interest rates. SFAS No. 133, “Accounting for Derivative
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Instruments and Hedging Activities,” as amended, governs the accounting treatment for derivatives and requires that derivative instruments be measured at fair value. 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. 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 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 to determine the value of non-derivative, commodity exposure for risk management purposes.
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 $7 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 $6 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 $60 million and would increase the accumulated postretirement benefit obligation by $18 million at December 31, 2008. 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 earnings.
For additional discussion, see Note (10), “Pensions and Other Postretirement Benefits,” to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K.
Regulation of Power Delivery Operations
The requirements of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” apply to the Power Delivery businesses of Pepco, DPL, and ACE. Pepco Holdings believes that the judgment involved in accounting for its regulated activities
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represent “Critical Accounting Estimates” because (i) a significant amount of judgment is required (including but not limited to the interpretation of laws and regulatory commission orders) to assess the probability of the recovery of regulatory assets, (ii) actual results and interpretations could vary from those used in Pepco Holdings’ estimates and the impact of such variations could be material, and (iii) the impact that writing off a regulatory asset would have on Pepco Holdings’ assets and the net loss related to the charge could be material.
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. This methodology is based on the supply of electricity or gas distributed to customers. 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 such as customer sales mix and estimated power 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, the impact of which could be material.
Accounting for Income Taxes
Pepco Holdings and the majority of its subsidiaries file a consolidated federal income tax return. Pepco Holdings accounts for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes,” and effective January 1, 2007, adopted FIN 48 “Accounting for Uncertainty in Income Taxes.” FIN 48 clarifies the criteria for recognition of tax benefits in accordance with SFAS No. 109, and prescribes a financial statement recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Specifically, it clarifies that an entity’s tax benefits must be “more likely than not” of being sustained assuming that position will be examined by taxing authorities with full knowledge of all relevant information prior to recording the related tax benefit in the financial statements. If the position drops below the “more likely than not” standard, the benefit can no longer be recognized.
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 income taxes. Pepco Holdings’ assumptions, judgments and estimates take into account current tax laws, interpretation of current tax laws 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 or its interpretation of tax laws and the resolutions of the current and any future investigations could significantly impact the amounts provided for income taxes in the consolidated financial statements.
Under SFAS No. 109, deferred income tax assets and liabilities are recorded, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Pepco Holdings evaluates quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and
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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.
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 Item 8 of this Form 10-K.
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 Council 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
GENERAL OVERVIEW
Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in Washington, D.C. and major portions of Montgomery County and Prince George’s 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 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, 2008, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to Washington, D.C. customers.
In connection with its approval of new electric service distribution base rates for Pepco in Maryland, effective in June, 2007 (the 2007 Maryland Rate Order), the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to which the BSA applies, Pepco recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA thus decouples the distribution revenue recognized in a reporting period from the amount of power delivered during the period. This change in the reporting of distribution revenue has the effect of eliminating changes in retail customer usage (whether due to weather conditions, energy prices, energy efficiency programs or other reasons) as a factor having an impact on reported revenue. As a consequence, the only factors that will cause distribution revenue from retail customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer.
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 Federal Energy Regulatory Commission under PUHCA 2005.
IMPACT OF THE CURRENT CAPITAL AND CREDIT MARKET DISRUPTIONS
The recent disruptions in the capital and credit markets have had an impact on Pepco’s business. While these conditions have required Pepco to make certain adjustments in its financial management activities, Pepco believes that it currently has sufficient liquidity to fund its operations and meet its financial obligations. These market conditions, should they continue, however, could have a negative effect on Pepco’s financial condition, results of operations and cash flows.
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Liquidity Requirements
Pepco depends on access to the capital and credit markets to meet its liquidity and capital requirements. To meet its liquidity requirements, Pepco historically has relied on the issuance of commercial paper and short-term notes and on bank lines of credit to supplement internally generated cash from operations. Pepco’s primary credit source is PHI’s $1.5 billion syndicated credit facility, under which Pepco can borrow funds, obtain letters of credit and support the issuance of commercial paper in an amount up to $500 million (subject to the limitation that the total utilization by Pepco and PHI’s other utility subsidiaries cannot exceed $625 million). This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total commitment.
Due to the recent capital and credit market disruptions, the market for commercial paper was severely restricted for most companies. As a result, Pepco has not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that it typically has required for cash management purposes. Given its restricted access to the commercial paper market and the uncertainty in the credit markets generally, Pepco borrowed $100 million under the credit facility to create a cash reserve for future short-term operating needs at December 31, 2008. After giving effect to outstanding letters of credit and commercial paper, PHI’s utility subsidiaries have an aggregate of $843 million in combined cash and borrowing capacity under the credit facility at December 31, 2008. During the months of January and February 2009, the average daily amount of the combined cash and borrowing capacity of PHI’s utility subsidiaries was $831 million and ranged from a low of $673 million to a high of $1 billion.
To address the challenges posed by the current capital and credit market environment and to ensure that it will continue to have sufficient access to cash to meet its liquidity needs, Pepco has identified a number of cash and liquidity conservation measures, including opportunities to defer capital expenditures due to lower than anticipated growth. Several measures to reduce expenditures have been taken. Additional measures could be undertaken if conditions warrant.
Due to the financial market conditions, which have caused uncertainty of short-term funding, Pepco issued $250 million in long-term debt securities in December, with the proceeds used to refund short-term debt incurred to finance utility construction and operations on a temporary basis and incurred to fund the temporary repurchase of tax-exempt auction rate securities.
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 recent stock market declines have caused a decrease in the market value of benefit plan assets in 2008. Pepco expects to contribute approximately $170 million to the pension plan in 2009.
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RESULTS OF OPERATIONS
The following results of operations discussion compares the year ended December 31, 2008 to the year ended December 31, 2007. Other than this disclosure, information under this item has been omitted in accordance with General Instruction I(2)(a) to the Form 10-K. 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 and Distribution (T&D) Electric Revenue and Default 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 Supply Revenue is the revenue received for Default Electricity Supply. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy.
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 T&D Electric
Other Regulated T&D Electric Revenue consists primarily of (i) transmission service revenue, (ii) revenue from the resale of energy and capacity under power purchase agreements between Pepco and unaffiliated third parties in the PJM Regional Transmission Organization (PJM RTO) market, and (iii) either (a) a positive adjustment equal to the amount by which revenue from Maryland 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 or
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(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).
Regulated T&D Electric Revenue increased by $50 million primarily due to:
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An increase of $24 million in Other Regulated T&D Electric Revenue from the resale of energy and capacity purchased under the power purchase agreement between Panda-Brandywine, L.P. (Panda) and Pepco (the Panda PPA) (offset in Fuel and Purchased Energy).
·
An increase of $24 million due to a distribution rate change in the District of Columbia that became effective in February 2008.
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An increase of $16 million due to a distribution rate change under the 2007 Maryland Rate Order that became effective in June 2007, including a positive $13 million Revenue Decoupling Adjustment.
The aggregate amount of these increases was partially offset by:
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A decrease of $11 million due to lower weather-related sales (a 4% decrease in Heating Degree Days and a 6% decrease in Cooling Degree Days).
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A decrease of $6 million due to differences in consumption among the various customer rate classes.
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Default Electricity Supply
Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy, increased by $68 million primarily due to:
·
An increase of $126 million in market-based Default Electricity Supply rates.
The increase was partially offset by:
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A decrease of $27 million due to lower weather-related sales (a 4% decrease in Heating Degree Days and a 6% decrease in Cooling Degree Days).
·
A decrease of $22 million primarily due to existing commercial customers electing to purchase electricity from competitive suppliers.
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A decrease of $10 million primarily due to differences in consumption among the various customer rate classes.
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.
Sales to District of Columbia customers
33%
35%
Sales to Maryland customers
50%
51%
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Operating Expenses
Fuel and Purchased Energy
Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply revenue, increased by $89 million to $1,335 million in 2008 from $1,246 million in 2007. The increase was primarily due to the following:
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An increase of $138 million in average energy costs, the result of new Default Electricity Supply contracts.
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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 $39 million primarily due to commercial customers electing to purchase electricity from competitive suppliers.
·
A decrease of $29 million due to lower weather-related sales.
Fuel and Purchased Energy expense is substantially offset in Regulated T&D Electric Revenue and Default Supply Revenue.
Other Operation and Maintenance
Other Operation and Maintenance increased by $2 million to $302 million in 2008 from $300 million in 2007. The increase was primarily due to the following:
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An increase of $7 million in deferred administrative expenses associated with Default Electricity Supply (offset in Default Supply Revenue) as the result of the inclusion of $5 million of customer late payment fees in the calculation of the deferral. See the discussion below regarding the 2008 correction of an error in recording customer late payment fees, including $3 million related to prior periods.
·
An increase of $3 million due to higher bad debt expenses associated with distribution and Default Electricity Supply customers, of which approximately $1 million was deferred.
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An increase of $3 million in employee-related costs primarily due to the recording of additional stock-based compensation expense as discussed below, including $3 million related to prior periods.
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An increase of $1 million in legal expenses.
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An increase of $1 million in environmental costs related to spill prevention and waste disposal.
The aggregate amount of these increases was partially offset by:
·
A decrease of $5 million in corrective and preventative maintenance costs.
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A decrease of $4 million in regulatory expenses primarily related to the District of Columbia distribution rate case in 2007.
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A decrease of $3 million due to various construction project write-offs in 2007 related to customer requested work.
·
A decrease of $3 million in accounting fees related to tax consulting services.
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.
Depreciation and Amortization
Depreciation and Amortization expenses decreased by $10 million to $141 million in 2008, from $151 million in 2007. The decrease was primarily due to a change in depreciation rates in accordance with the 2007 Maryland Rate Order.
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 Corporation (Mirant) bankruptcy settlement.
Other Income (Expenses)
Other Expenses (which are net of Other Income) increased by $15 million to a net expense of $76 million in 2008 from a net expense of $61 million in 2007. This increase was primarily due to:
·
An increase of $12 million in interest expense due to higher outstanding long-term debt during 2008.
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A decrease of $2 million in Contribution in Aid of Construction tax gross-up income.
Income Tax Expense
Pepco’s effective tax rates for the years ended December 31, 2008 and 2007 were 35.6% and 33.2%, respectively. While the change in the effective rate between 2008 and 2007 was not significant, the effective rate in each year was impacted by certain non-recurring items. In 2008, Pepco recorded certain tax benefits that reduced its overall effective tax rate, including net interest income accrued on the tentative settlement with the IRS on the mixed service cost issue
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discussed below, interest income accrued on other effectively settled and uncertain tax positions, 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. In 2007, Pepco recorded the receipt of the Maryland state tax refund in the third quarter of 2007 as a reduction in income tax expense. This benefit was partially offset by certain income tax charges recorded in the third quarter of 2007 related to additional analysis of Pepco’s deferred tax balances.
During the second quarter 2008, Pepco reached a tentative settlement with the Internal Revenue Service (IRS) concerning the treatment of mixed service costs for income tax purposes during the period 2001 to 2004. On the basis of the tentative settlement, Pepco 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 $16 million and recognized after-tax interest income of $3 million in the second quarter of 2008. See Note (13), “Commitments and Contingencies - Regulatory and Other Matters - IRS Mixed Service Cost Issue,” to the financial statements of Pepco set forth in Item 8 of this Form 10-K.
Capital Requirements
Capital Expenditures
Pepco’s total capital expenditures for the year ended December 31, 2008, totaled $275 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.
The table below shows Pepco’s projected capital expenditures for the five year period 2009 through 2013:
Pepco expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.
As further discussed in Note (10), “Debt” to the Pepco financial statements set forth in Item 8 of this Form 10-K, PHI, Pepco, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) maintain credit facilities to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facilities is $1.9 billion. The primary facility consists of a $1.5 billion facility which expires in 2012, 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 Pepco is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities which is $500 million,
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except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.
Distribution and Transmission
The projected capital expenditures listed in the table for distribution (other than Blueprint for the Future) and transmission (other than MAPP) are primarily for facility replacements and upgrades to accommodate customer growth and reliability.
Blueprint for the Future
During 2007, Pepco announced an initiative it refers to as the “Blueprint for the Future.” The initiative combines traditional energy efficiency programs with new technologies and systems to help customers manage their energy use and reduce the total cost of energy. Pepco has made filings with the District of Columbia Public Service Commission (DCPSC) and the MPSC for approval of certain aspects of these programs. On December 18, 2008, the DCPSC conditionally approved five DSM programs. The cost of these programs will be recovered through a rate surcharge. On December 31, 2008, the MPSC conditionally approved for both Pepco and DPL, four residential and four non-residential DSM/energy efficiency programs. The MPSC will consider an Advanced Metering Infrastructure program in a separate proceeding. Pepco anticipates that the costs of these programs will be recovered through a previously approved surcharge mechanism.
MAPP Project
In October 2007, the PJM Board of Managers approved PHI’s proposed MAPP transmission project for construction of a new 230-mile, 500-kilovolt interstate transmission project at a then-estimated cost of $1 billion. This MAPP project will 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. This MAPP project is part of PJM’s Regional Transmission Expansion Plan required to address the reliability objectives of the PJM RTO system. On December 4, 2008, the PJM Board approved a direct-current technology for segments of the project including the Chesapeake Bay Crossing. With this modification, the cost of the MAPP project currently is estimated at $1.4 billion. PJM has determined that the line segment from Possum Point substation to the second substation on the Delmarva Peninsula (Indian River substation) is required to be operational by June 1, 2013. PJM is continuing to evaluate the in-service date for the remaining 80-miles of line segment to connect the Indian River substation to the Salem substation. Construction is expected to occur in stages over the next five year period.
Proceeds from Settlement of Mirant Bankruptcy Claims
On September 5, 2008, Pepco transferred the Panda PPA to Sempra Energy Trading LLC (Sempra), along with a payment to Sempra, terminating all further rights, obligations and liabilities of Pepco under the Panda PPA. The use of the damages received from Mirant to offset above-market costs of energy and capacity under the Panda PPA and to make the payment to Sempra reduced the balance of proceeds from the Mirant settlement to approximately $102 million as of December 31, 2008.
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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 previously approved by the respective commissions. Under Pepco’s proposals, District of Columbia and Maryland customers would receive a total of approximately $25 million and $29 million, respectively. On December 12, 2008, the DCPSC issued a Notice of Proposed Rulemaking concerning the sharing of the Mirant divestiture proceeds, including the bankruptcy settlement proceeds. The public comment period for the proposed rules has expired without any comments being submitted. This matter remains pending before the DCPSC.
On February 17, 2009, Pepco, the Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff filed a settlement agreement with the MPSC. The settlement, among other things, provides that of the remaining balance of the Mirant settlement, Pepco shall distribute $39 million to its Maryland customers through a one-time billing credit. If the settlement is approved by the MPSC, Pepco currently estimates that it will result in a pre-tax gain in the range of $15 million to $20 million, which will be recorded when the MPSC issues its final order approving the settlement.
Pending the final disposition of these funds, the remaining $102 million in proceeds from the Mirant settlement is being accounted for as restricted cash and as a regulatory liability.
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:
·
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;
PEPCO
·
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 Council and other applicable electric reliability organizations;
·
Legal and administrative proceedings (whether civil or criminal) and settlements that influence Pepco’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 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.
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DPL
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
DELMARVA POWER & LIGHT COMPANY
GENERAL OVERVIEW
Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland. 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. Default Electricity Supply is also known as Standard Offer Service in Maryland and in Delaware. 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, 2008, 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 retail electric distribution assets and its wholesale electric transmission assets in Virginia. Prior to that date, DPL supplied electricity at regulated rates to retail customers in its service territory who did not elect to purchase electricity from a competitive energy supplier, which is referred to in Virginia as Default Service.
In connection with its approval of new electric service distribution base rates for DPL in Maryland, effective in June, 2007 (the 2007 Maryland Rate Order), the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to which the BSA applies, DPL recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA thus decouples the distribution revenue recognized in a reporting period from the amount of power delivered during the period. This change in the reporting of distribution revenue has the effect of eliminating changes in retail customer usage (whether due to weather conditions, energy prices, energy efficiency programs or other reasons) as a factor having an impact on reported revenue. As a consequence, the only factors that will cause distribution revenue from retail customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer.
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 Federal Energy Regulatory Commission under PUHCA 2005.
IMPACT OF THE CURRENT CAPITAL AND CREDIT MARKET DISRUPTIONS
The recent disruptions in the capital and credit markets have had an impact on DPL’s business. While these conditions have required DPL to make certain adjustments in its financial
DPL
management activities, DPL believes that it currently has sufficient liquidity to fund its operations and meet its financial obligations. These market conditions, should they continue, however, could have a negative effect on DPL’s financial condition, results of operations and cash flows.
Liquidity Requirements
DPL depends on access to the capital and credit markets to meet its liquidity and capital requirements. To meet its liquidity requirements, DPL historically has relied on the issuance of commercial paper and short-term notes and on bank lines of credit to supplement internally generated cash from operations. DPL’s primary credit source is PHI’s $1.5 billion syndicated credit facility, under which DPL can borrow funds, obtain letters of credit and support the issuance of commercial paper in an amount up to $500 million (subject to the limitation that the total utilization by DPL and PHI’s other utility subsidiaries cannot exceed $625 million). This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total commitment.
Due to the recent capital and credit market disruptions, the market for commercial paper was severely restricted for most companies. As a result, DPL has not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that it typically has required for cash management purposes. After giving effect to outstanding letters of credit and commercial paper, PHI’s utility subsidiaries have an aggregate of $843 million in combined cash and borrowing capacity under the credit facility at December 31, 2008. During the months of January and February 2009, the average daily amount of the combined cash and borrowing capacity of PHI’s utility subsidiaries was $831 million and ranged from a low of $673 million to a high of $1 billion.
To address the challenges posed by the current capital and credit market environment and to ensure that it will continue to have sufficient access to cash to meet its liquidity needs, DPL has identified a number of cash and liquidity conservation measures, including opportunities to defer capital expenditures due to lower than anticipated growth. Several measures to reduce expenditures have been taken. Additional measures could be undertaken if conditions warrant.
Due to the financial market conditions, which have caused uncertainty of short-term funding, DPL issued $250 million in long-term debt securities in November, with the proceeds used to refund short-term debt incurred to finance utility construction and operations on a temporary basis and incurred to fund the temporary repurchase of tax-exempt auction rate securities.
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 recent stock market declines have caused a decrease in the market value of benefit plan assets in 2008. DPL expects to contribute approximately $10 million to the pension plan in 2009.
DPL
RESULTS OF OPERATIONS
The following results of operations discussion compares the year ended December 31, 2008 to the year ended December 31, 2007. Other than this disclosure, information under this item has been omitted in accordance with General Instruction I(2)(a) to the Form 10-K. 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 and Distribution (T&D) Electric Revenue and Default 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 Supply Revenue is the revenue received for Default Electricity Supply. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy.
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 include 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) 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 distribution charge per customer approved in the 2007 Maryland Rate Order or (b) a negative
DPL
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).
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.
Regulated T&D Electric Revenue increased by $16 million primarily due to:
·
An increase of $15 million primarily due to transmission rate changes in June 2008 and 2007.
·
An increase of $12 million due to a distribution rate change under the 2007 Maryland Rate Order that became effective in June 2007, including a positive $6 million Revenue Decoupling Adjustment.
·
An increase of $7 million due to differences in consumption among the various customer rate classes.
The aggregate amount of these increases was partially offset by:
·
A decrease of $12 million due to the sale of Virginia retail electric distribution and wholesale transmission assets in January 2008.
·
A decrease of $6 million due to lower weather-related sales (a 2% increase in Heating Degree Days and a 23% decrease in Cooling Degree Days).
DPL
Default Electricity Supply
Due to the sale of DPL’s Virginia retail electric distribution assets in January 2008, the numbers of Default Electricity Supply Customers listed above include a decrease of approximately 19,000 residential customers and 3,000 commercial customers.
Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy, did not change primarily due to:
·
An increase of $42 million in market-based Default Electricity Supply rates.
·
An increase of $8 million primarily due to existing commercial customers electing to purchase a decreased amount of electricity from competitive suppliers.
The aggregate amount of these increases was offset by:
·
A decrease of $32 million due to the sale of Virginia retail electric distribution and wholesale transmission assets in January 2008.
·
A decrease of $17 million due to lower weather-related sales (a 2% increase in Heating Degree Days and a 23% decrease in Cooling Degree Days).
The following table shows the percentages of DPL’s total sales by jurisdiction that are derived from customers receiving Default Electricity Supply distribution from DPL.
DPL
Sales to Delaware customers
55%
54%
Sales to Maryland customers
65%
67%
Sales to Virginia customers
-%
94%
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. Other Gas Revenue includes off-system natural gas sales and the sale of excess system capacity.
Regulated Gas Revenue
DPL
Regulated Gas Revenue decreased by $7 million primarily due to:
·
A decrease of $4 million due to differences in consumption among the various customer rate classes.
·
A decrease of $3 million due to lower weather-related sales (a 3% decrease in Heating Degree Days).
·
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 in April 2007.
Other Gas Revenue
Other Gas Revenue, which is substantially offset in Gas Purchased expense, increased by $34 million primarily due to revenue from higher off-system sales, the result of an increase in market prices. Off-system sales are made possible due to available pipeline capacity that results from low demand for natural gas from regulated customers.
Operating Expenses
Fuel and Purchased Energy
Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply revenue, decreased by $18 million to $821 million in 2008 from $839 million in 2007. The decrease was primarily due to:
·
A decrease of $45 million due to the sale of Virginia retail electric distribution and wholesale transmission assets in January 2008.
·
A decrease of $18 million due to lower weather-related sales.
The aggregate amount of these decreases was partially offset by:
·
An increase of $33 million in average energy costs, the result of new Default Electricity Supply contracts.
·
An increase of $11 million due to a higher rate of recovery of electric supply costs resulting in a change in the Default Electric Supply deferral balance.
Fuel and Purchased Energy expense is substantially offset in Default Supply Revenue.
DPL
Gas Purchased
Total Gas Purchased, which is primarily offset in Regulated Gas Revenue and Other Gas Revenue, increased by $25 million to $245 million in 2008 from $220 million in 2007. The increase is primarily due to:
·
An increase of $32 million in gas purchases for off-system sales, the result of higher average gas costs.
The increase was partially offset by:
·
A decrease of $10 million due to a lower rate of recovery of natural gas supply costs resulting in a change in the deferred gas fuel balance.
Other Operation and Maintenance
Other Operation and Maintenance increased by $16 million to $222 million in 2008 from $206 million in 2007. The increase was primarily due to the following:
·
An increase of $10 million in deferred administrative expenses associated with Default Electricity Supply (offset in Default Supply Revenue) due to (i) the inclusion of $5 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 the 2008 correction of an error in recording customer late payment fees, including $3 million related to prior periods.
·
An increase of $5 million due to higher bad debt expenses associated with distribution and Default Electricity Supply customers, of which approximately $2 million was deferred.
·
An increase of $2 million in employee-related costs due to the recording of additional stock-based compensation expense as discussed below, including $2 million related to prior periods.
The aggregate amount of these increases was partially offset by:
·
A decrease of $2 million primarily in emergency restoration costs.
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 for the year ended December 31, 2008 of $5 million.
DPL
Gain on Sale of Assets
Gain on Sale of Assets increased by $3 million to $4 million in 2008 from $1 million in 2007. The increase was primarily due to a $4 million gain on the sale of Virginia retail electric distribution and wholesale transmission assets in January 2008.
Other Income (Expenses)
Other Expenses (which are net of Other Income) decreased by $5 million to a net expense of $35 million in 2008 from a net expense of $40 million in 2007. The decrease was primarily due to a $4 million net decrease in interest expense on short and long-term debt.
Income Tax Expense
DPL’s effective tax rates for the years ended December 31, 2008 and 2007 were 39.8% and 45.1%, respectively. While the change in the effective rate between 2008 and 2007 was not significant, the effective rate in each year was impacted by certain non-recurring items. In 2008, DPL recorded certain tax benefits that reduced its overall effective tax rate, primarily representing net interest income accrued on the tentative settlement with the Internal Revenue Service (IRS) on the mixed service cost issue discussed below. This benefit was largely offset by income tax charges recorded in the fourth quarter of 2008 related to additional analysis of DPL’s deferred tax balances. In 2007, DPL recorded certain income tax charges in the third quarter of 2007 related to additional analysis of DPL’s deferred tax balances.
During the second quarter 2008, DPL reached a tentative settlement with the Internal Revenue Service concerning the treatment of mixed service costs for income tax purposes during the period 2001 to 2004. On the basis of the tentative settlement, DPL 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 $1 million and recognized after-tax interest income of $2 million in the second quarter of 2008. See Note (14), “Commitments and Contingencies - Regulatory and Other Matters - IRS Mixed Service Cost Issue,” to the financial statements of DPL set forth in Item 8 of this Form 10-K.
Capital Requirements
Capital Expenditures
DPL’s total capital expenditures for the year ended December 31, 2008, totaled $150 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.
DPL
The table below shows DPL’s projected capital expenditures for the five-year period 2009 through 2013:
DPL expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.
As further discussed in Note (11), “Debt,” to the DPL financial statements set forth in Item 8 of this Form 10-K, PHI, Potomac Electric Power Company (Pepco), DPL and Atlantic City Electric Company (ACE) maintain credit facilities to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facilities is $1.9 billion. The primary facility consists of a $1.5 billion facility which expires in 2012, 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 for DPL is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities which is $500 million, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.
Distribution, Transmission and Gas Delivery
The projected capital expenditures listed in the table for distribution (other than Blueprint for the Future), transmission (other than MAPP) and gas delivery are primarily for facility replacements and upgrades to accommodate customer growth and reliability.
Blueprint for the Future
During 2007, DPL announced an initiative that is referred to as the “Blueprint for the Future.” This initiative combines traditional energy efficiency programs with new technologies and systems to help customers manage their energy use and reduce the total cost of energy, and includes the installation of “smart meters” for all customers in Delaware and Maryland. DPL has made filings with the Delaware Public Service Commission (DPSC) and the MPSC for approval of certain aspects of these programs. Delaware has approved a recovery mechanism associated with these plans, and work has proceeded to prepare to begin installation of an Advanced Metering Infrastructure (AMI) by the last quarter of 2009. On December 31, 2008, the MPSC conditionally approved four residential and four non-residential DSM/energy efficiency programs. The MPSC will consider an AMI program in a separate proceeding. DPL anticipates that the costs of these programs will be recovered through a previously approved surcharge mechanism.
DPL
MAPP Project
In October 2007, the PJM Board of Managers approved PHI’s proposed MAPP transmission project for construction of a new 230-mile, 500-kilovolt interstate transmission project at a then-estimated cost of $1 billion. This MAPP project will 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. This MAPP project is part of PJM’s Regional Transmission Expansion Plan required to address the reliability objectives of the PJM RTO system. On December 4, 2008, the PJM Board approved a direct-current technology for segments of the project including the Chesapeake Bay Crossing. With this modification, the cost of the MAPP project is currently estimated at $1.4 billion. PJM has determined that the line segment from Possum Point substation to the second substation on the Delmarva Peninsula (Indian River substation) is required to be operational by June 1, 2013. PJM is continuing to evaluate the in-service date for the remaining 80-miles of line segment to connect the Indian River substation to the Salem substation. Construction is expected to occur in sections over the next five year period.
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.
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;
DPL
·
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 Council 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.
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ACE
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ATLANTIC CITY ELECTRIC COMPANY
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 (BGS) 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 Federal Energy Regulatory Commission under PUHCA 2005.
DISCONTINUED OPERATIONS
In February 2007, ACE completed the sale of the B.L. England generating facility. B.L. England comprised a significant component of ACE’s generation operations and its sale required discontinued operations presentation under Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets,” on ACE’s Consolidated Statements of Earnings for the years ended December 31, 2007 and 2006. In September 2006, ACE sold its interests in the Keystone and Conemaugh generating facilities, which for the year ended December 31, 2006, is also reflected as discontinued operations.
The following table summarizes information related to the discontinued operations for the years presented (millions of dollars):
Operating Revenue
$
-
$
$
Income Before Income Tax Expense
$
-
$
-
$
Net Income
$
-
$
-
$
IMPACT OF THE CURRENT CAPITAL AND CREDIT MARKET DISRUPTIONS
The recent disruptions in the capital and credit markets have had an impact on ACE’s business. While these conditions have required ACE to make certain adjustments in its financial management activities, ACE believes that it currently has sufficient liquidity to fund its operations and meet its financial obligations. These market conditions, should they continue, however, could have a negative effect on ACE’s financial condition, results of operations and cash flows.
ACE
Liquidity Requirements
ACE depends on access to the capital and credit markets to meet its liquidity and capital requirements. To meet its liquidity requirements, ACE historically has relied on the issuance of commercial paper and short-term notes and on bank lines of credit to supplement internally generated cash from operations. ACE’s primary credit source is PHI’s $1.5 billion syndicated credit facility, under which ACE can borrow funds, obtain letters of credit and support the issuance of commercial paper in an amount up to $500 million (subject to the limitation that the total utilization by ACE and PHI’s other utility subsidiaries cannot exceed $625 million). This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total commitment.
Due to the recent capital and credit market disruptions, the market for commercial paper was severely restricted for most companies. As a result, ACE has not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that it typically has required for cash management purposes. After giving effect to outstanding letters of credit and commercial paper, PHI’s utility subsidiaries have an aggregate of $843 million in combined cash and borrowing capacity under the credit facility at December 31, 2008. During the months of January and February 2009, the average daily amount of the combined cash and borrowing capacity of PHI’s utility subsidiaries was $831 million and ranged from a low of $673 million to a high of $1 billion.
To address the challenges posed by the current capital and credit market environment and to ensure that it will continue to have sufficient access to cash to meet its liquidity needs, ACE has identified a number of cash and liquidity conservation measures, including opportunities to defer capital expenditures due to lower than anticipated growth. Several measures to reduce expenditures have been taken. Additional measures could be undertaken if conditions warrant.
Due to the financial market conditions, which have caused uncertainty of short-term funding, ACE issued $250 million in long-term debt securities in November. The proceeds were used to refund short-term debt incurred to finance utility construction and operations on a temporary basis and incurred to fund the temporary repurchase of tax-exempt auction rate securities.
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 recent stock market declines have caused a decrease in the market value of benefit plan assets in 2008. ACE expects to contribute approximately $60 million to the pension plan in 2009.
ACE
RESULTS OF OPERATIONS
The following results of operations discussion compares the year ended December 31, 2008 to the year ended December 31, 2007. Other than this disclosure, information under this item has been omitted in accordance with General Instruction I(2)(a) to the Form 10-K. 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 and Distribution (T&D) Electric Revenue and Default 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 Supply Revenue is the revenue received for Default Electricity Supply. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default 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.
In response to an order issued by the New Jersey Board of Public Utilities 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 based on transmission formula rates approved by the Federal Energy Regulatory Commission (FERC). 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 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 based on FERC-approved transmission formula rates. ACE’s retail transmission revenue for the period prior to January 1, 2008 has been reclassified to Default Supply Revenue in order to conform to the current period presentation.
ACE
Regulated T&D Electric
Other Regulated T&D Electric Revenue consists primarily of transmission service revenue.
Regulated T&D Electric Revenue increased by $32 million primarily due to:
·
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).
·
An increase of $8 million primarily due to transmission rate changes in June 2008 and 2007.
ACE
Default Electricity Supply
Other Default Supply Revenue consists primarily of revenue from the resale in the PJM RTO market of energy and capacity purchased under contracts with non-utility generators (NUGs).
Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Deferred Electric Service Costs, increased by $59 million primarily due to:
·
An increase of $57 million in wholesale energy revenues due to the sale at higher market prices of electricity purchased from NUGs.
·
An increase of $34 million in market-based Default Electricity Supply rates.
The aggregate amount of these increases was partially offset by:
·
A decrease of $19 million primarily due to existing commercial and industrial customers electing to purchase electricity from competitive suppliers.
·
A decrease of $10 million due to lower weather-related sales (a 2% decrease in Heating Degree Days and a 3% decrease in Cooling Degree Days).
ACE
For the years ended December 31, 2008 and 2007, the percentage of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 78% and 80%, respectively.
Operating Expenses
Fuel and Purchased Energy
Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $127 million to $1,178 million in 2008 from $1,051 million in 2007. The increase was primarily due to:
·
An increase of $162 million in average energy costs, the result of new Default Electricity Supply contracts.
The increase was partially offset by:
·
A decrease of $21 million primarily due to commercial and industrial customers electing to purchase electricity from competitive suppliers.
·
A decrease of $14 million due to lower weather-related sales.
Fuel and Purchased Energy is substantially offset in Default Supply Revenue and Deferred Electric Service Costs.
Other Operation and Maintenance
Other Operation and Maintenance increased by $18 million to $183 million in 2008 from $165 million in 2007. The increase was primarily due to the following:
·
An increase of $4 million in preventative maintenance and system operation costs.
·
An increase of $3 million due to higher bad debt expenses associated with distribution customers (offset in Deferred Electric Service Costs).
·
An increase of $3 million in Demand Side Management program costs (offset in Deferred Electric Service Costs).
·
An increase of $2 million in employee-related costs, primarily due to the recording of additional stock-based compensation expense as discussed below, including $1 million related to prior periods.
·
An increase of $2 million in costs associated with Default Electricity Supply.
·
An increase of $1 million in legal 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.
ACE
Depreciation and Amortization
Depreciation and Amortization expenses increased by $24 million to $104 million in 2008 from $80 million in 2007. This increase was primarily due to higher amortization of stranded costs as a result of an October 2007 Transition Bond Charge rate increase (offset in Default Supply Revenue).
Deferred Electric Service Costs
Deferred Electric Service Costs decreased by $75 million to income of $9 million in 2008 from an expense of $66 million in 2007. The decrease was primarily due to:
·
A decrease of $46 million due to a lower rate of recovery associated with deferred energy costs.
·
A decrease of $29 million due to a lower rate of recovery of costs associated with energy and capacity purchased under the NUGs.
·
A decrease of $17 million due to a lower rate of recovery associated with 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 associated with Demand Side Management program costs.
Deferred Electric Service Costs are substantially offset in Regulated T&D Electric Revenue and Other Operation and Maintenance.
Income Tax Expense
ACE’s effective tax rates for the years ended December 31, 2008 and 2007 were 31.9% and 40.6%, respectively. The significant year-over-year decline in the effective tax rate reflects certain non-recurring items recorded in 2008. In 2008, ACE recorded certain tax benefits that reduced its overall effective tax rate, primarily representing net interest income accrued on uncertain tax positions (including interest related to the tentative settlement with the IRS on the mixed service cost issue discussed below and a claim made with the IRS related to the tax reporting of fuel over- and under-recoveries). This benefit was partially offset by income tax charges recorded in the fourth quarter of 2008 related to additional analysis of ACE’s deferred tax balances completed in 2008. In 2007, ACE recorded certain income tax credits in the third quarter of 2007 related to additional analysis of ACE’s deferred tax balances.
During the second quarter 2008, ACE reached a tentative settlement with the Internal Revenue Service concerning the treatment of mixed service costs for income tax purposes during the period 2001 to 2004. On the basis of the tentative settlement, ACE 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 $2 million and recognized after-tax interest income of $2 million in the second quarter of 2008. See Note (14), “Commitments and Contingencies - Regulatory and Other Matters - IRS Mixed Service Cost Issue,” to the consolidated financial statements of ACE set forth in Item 8 of this Form 10-K.
ACE
Capital Requirements
Capital Expenditures
ACE’s total capital expenditures for the year ended December 31, 2008, totaled $162 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.
The table below shows ACE’s projected capital expenditures for the five-year period 2009 through 2013:
ACE expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.
As further discussed in Note (10), “Debt,” to the ACE consolidated financial statements set forth in Item 8 of this Form 10-K, PHI, Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and ACE maintain credit facilities to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facilities is $1.9 billion. The primary facility consists of a $1.5 billion facility which expires in 2012, 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 for ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities which is $250 million, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.
Distribution and Transmission
The projected capital expenditures listed in the table for distribution (other than Blueprint for the Future) and transmission (other than MAPP) are primarily for facility replacements and upgrades to accommodate customer growth and reliability.
Blueprint for the Future
During 2007, ACE announced an initiative that is referred to as the “Blueprint for the Future.” This initiative combines traditional energy efficiency programs with new technologies and systems to help customers manage their energy use and reduce the total cost of energy, and includes the installation of “smart meters” for all customers in New Jersey. In November 2007, ACE filed its “Blueprint for the Future” proposal with the New Jersey Board of Public Utilities.
ACE
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;
·
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;
ACE
·
Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Council 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.
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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 (17), “Use of Derivatives in Energy and Interest Rate Hedging Activities” to the consolidated financial statements of PHI set forth in 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. Because of 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, 2008 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 its internal control over financial reporting was effective as of December 31, 2008.
PricewaterhouseCoopers LLP, the registered public accounting firm that audited the financial statements of Pepco Holdings included in this Annual Report on Form 10-K, has issued its attestation report on Pepco Holdings’ internal control over financial reporting, which is included herein.
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Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of
Pepco Holdings, Inc.
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Pepco Holdings, Inc. and its subsidiaries at December 31, 2008 and December 31, 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 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, 2008, 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.
As discussed in Note 12 to the consolidated financial statements, the Company changed its manner of accounting and reporting for uncertain tax positions in 2007.
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
PEPCO HOLDINGS
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.
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.
PricewaterhouseCoopers LLP
Washington, DC
March 2,
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The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
The accompanying Notes are an integral part of these Consolidated Financial Statements
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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:
o
Potomac Electric Power Company (Pepco), which was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949,
o
Delmarva Power & Light Company (DPL), which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979, and
o
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 costing methodologies set forth in the service agreement.
The following is a description of each of PHI’s two principal business operations.
Power Delivery
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
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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 varies by jurisdiction as follows:
Delaware
Standard Offer Service (SOS)
District of Columbia
SOS
Maryland
SOS
New Jersey
Basic Generation Service (BGS)
Effective January 2, 2008, DPL sold its retail electric distribution assets and its wholesale electric transmission assets in Virginia. Prior to that date, DPL supplied electricity at regulated rates to retail customers in its service territory who did not elect to purchase electricity from a competitive energy supplier.
In this Form 10-K, these supply services are referred to generally as Default Electricity Supply.
Competitive Energy
The Competitive Energy business provides competitive generation, marketing and supply of electricity and gas, and related 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.
Over the past several months, PHI has been conducting a strategic analysis of the retail energy supply business of Pepco Energy Services. This review has included, among other things, the evaluation of potential alternative supply arrangements to reduce collateral requirements or a possible restructuring sale or wind down of the business. Among the factors being considered is the return PHI earns by investing capital in the retail energy supply business as compared to alternative investments. PHI expects the retail energy supply business to remain profitable based on its existing contract backlog and the margins that have been locked in with corresponding wholesale energy purchase contracts. The increased cost of capital associated with its collateral obligations has been factored into its retail pricing and, as a consequence, PES is experiencing reduced retail customer retention levels and reduced levels of new retail customer acquisitions.
Other Business Operations
Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy sale-leaseback transactions, with a book value at December 31, 2008 of approximately $1.3 billion. This activity constitutes a fourth operating segment for
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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 (16), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments.”
Impact of the Current Capital and Credit Market Disruptions
The recent disruptions in the capital and credit markets, combined with the volatility of energy prices, have had an impact on several aspects of PHI’s businesses. While these conditions have required PHI and its subsidiaries to make certain adjustments in their financial management activities, PHI believes that it and its subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations. These market conditions, should they continue, could have a negative effect on PHI’s financial condition, results of operations and cash flows.
Liquidity Requirements
PHI and its subsidiaries depend on access to the capital and credit markets to meet their liquidity and capital requirements. To meet their liquidity requirements, PHI’s utility subsidiaries and its Competitive Energy businesses historically have relied on the issuance of commercial paper and short-term notes and on bank lines of credit to supplement internally generated cash from operations. PHI’s primary credit source is its $1.5 billion syndicated credit facility, which can be used by PHI and its utility subsidiaries to borrow funds, obtain letters of credit and support the issuance of commercial paper. This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total $1.5 billion commitment. The terms and conditions of the facility are more fully described below in Note (11), “Debt.”
Due to the capital and credit market disruptions, the market for commercial paper in the latter part of 2008 was severely restricted for most companies. As a result, PHI and its subsidiaries have not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that they have typically required for cash management purposes. To address the challenges posed by the current capital and credit market environment and to ensure that PHI and its subsidiaries will continue to have sufficient access to cash to meet their liquidity needs, PHI and its subsidiaries have undertaken a number of actions, including the following:
·
PHI has conducted a review to identify cash and liquidity conservation measures, including opportunities to reduce collateral obligations and to defer capital expenditures due to lower than anticipated growth. Several measures to reduce collateral obligations and expenditures have been taken. Additional measures could be undertaken if conditions warrant.
·
PHI issued an additional 16.1 million shares of the Company’s common stock at a price per share of $16.50 in November 2008, for net proceeds of $255 million.
·
PHI added a 364-day $400 million credit facility in November 2008.
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·
In November 2008, ACE issued $250 million of First Mortgage Bonds, 7.75% Series due November 15, 2018.
·
In November 2008, DPL issued $250 million of First Mortgage Bonds, 6.40% Series due December 1, 2013.
·
In December 2008, Pepco issued $250 million of First Mortgage Bonds, 7.90% Series due December 15, 2038.
At December 31, 2008, the amount of cash, plus borrowing capacity under the syndicated credit facility and PHI’s new 364-day credit facility, available to meet the liquidity needs of PHI on a consolidated basis totaled $1.5 billion, of which $843 million consisted of the combined cash and borrowing capacity of PHI’s utility subsidiaries. During the months of January and February 2009, the average daily amount of the combined cash and borrowing capacity of PHI on a consolidated basis was $1.4 billion, and of its utility subsidiaries was $831 million. This decrease in liquidity of PHI on a consolidated basis was primarily due to increased collateral requirements of the Competitive Energy businesses. During the months of January and February 2009, the combined cash and borrowing capacity of PHI’s utility subsidiaries ranged from a low of $673 million to a high of $1 billion.
Collateral Requirements of the Competitive Energy Businesses
In conducting its retail energy sales business, Pepco Energy Services typically enters into electricity and natural gas sales 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. Generally, Pepco Energy Services acquires the energy to serve this load by entering into wholesale purchase contracts. To protect the respective parties against the risk of nonperformance by the other party, these wholesale purchase contracts typically impose collateral requirements that are tied to changes in the price of the contract commodity. In periods of energy market price volatility, these collateral obligations can fluctuate materially on a day-to-day basis.
Pepco Energy Services’ practice of offsetting its retail energy sale obligations with corresponding wholesale purchases of energy has the effect of substantially reducing the exposure of its margins to energy price fluctuations. In addition, the non-performance risks associated with its retail energy sales are relatively low due to the inclusion of governmental entities among its customers and the purchase of insurance on a significant portion of its commercial and other accounts receivable. However, because its retail energy sales contracts typically do not have collateral obligations, during periods of declining energy prices Pepco Energy Services 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. In the second half of 2008, the decrease in energy prices has caused a significant increase in the collateral obligations of Pepco Energy Services.
In addition, 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
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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, 2008, the Competitive Energy businesses had posted net cash collateral of $331 million and letters of credit of $558 million.
At December 31, 2008, the amount of cash, plus borrowing capacity under the syndicated credit facility and PHI’s new 364-day credit facility, available to meet the liquidity needs of the Competitive Energy businesses on a consolidated basis totaled $684 million. During the months of January and February 2009, the combined cash and borrowing capacity available to PHI’s Competitive Energy businesses ranged from a low of $378 million to a high of $757 million.
Counterparty Credit Risk
PHI is exposed to the risk that the counterparties to contracts may fail to meet their contractual payment obligations or may fail to deliver purchased commodities or services at the contracted price. PHI attempts to minimize these risks through, among other things, formal credit policies, regular assessments of counterparty creditworthiness, and the establishment of a credit limit for each counterparty.
Pension and Postretirement Benefit Plans
PHI and its subsidiaries sponsor pension and postretirement benefit plans 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 have caused a decrease in the market value of benefit plan assets over the twelve months ended December 31, 2008. The negative return did not have an impact on PHI’s results of operations for 2008; however, this reduction in benefit plan assets will result in increased pension and postretirement benefit costs in future years.
PHI expects to make a discretionary tax deductible contribution to the pension plan in 2009 of approximately $300 million. The utility subsidiaries will be responsible for funding their share of the contribution of approximately $170 million for Pepco, $10 million for DPL and $60 million for ACE. PHI Service Company is responsible to fund the remaining share of the contribution. PHI will monitor the markets and evaluate any additional discretionary funding needs later in the year. See Note (10), “Pensions and Other Postretirement Benefits.”
(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
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PHI, and certain transmission and other facilities currently held, are consolidated in proportion to PHI’s percentage interest in the facility.
Consolidation of Variable Interest Entities
In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R entitled “Consolidation of Variable Interest Entities” (FIN 46R), Pepco Holdings consolidates those variable interest entities where Pepco Holdings or a subsidiary has been determined to be primary beneficiary. FIN 46R 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 a number of entities to which FIN 46R applies.
Pepco and ACE 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 counterparties. In accordance with the provisions of FIN 46R, Pepco Holdings continued, during 2008, to conduct exhaustive efforts to obtain information from these three entities, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R to determine whether these three entities were variable interest entities or if the Pepco Holdings subsidiaries were the primary beneficiary. As a result, Pepco Holdings has applied the scope exemption from the application of FIN 46R 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, 2008, 2007, and 2006, were approximately $349 million, $327 million, and $324 million, respectively, of which approximately $305 million, $292 million, and $288 million, respectively, related to power purchases under the NUGs. Pepco Holdings does not have loss exposure under the NUGs because cost recovery will be achieved 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, 2007 and 2006 were approximately $59 million, $85 million and $79 million, respectively. See Note (16), “Commitments and Contingencies - Regulatory and Other Matters - Proceeds from Settlement of Mirant Bankruptcy Claims.”
DPL Onshore Wind Transactions
In 2008, DPL entered into three onshore wind PPAs for energy and renewable energy credits (RECs) to help serve 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 all three agreements, and payments under the agreements are expected to start in 2009 at the earliest.
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DPL has exclusive rights to the energy and RECs in amounts up to a total between 120 and 150 megawatts under the PPAs. The lengths of the contracts range between 15 and 20 years. DPL is only obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed. Recent disruptions in the capital and credit markets could result in delays in the start dates for these PPAs. If the PPAs are not initiated by the specified dates, DPL has the right to terminate the PPAs. DPL’s maximum exposure to loss under the PPAs is the extent to which the market prices for energy and RECs fall below the contractual purchase price.
DPL concluded that two of the PPAs were leases in accordance with the guidance in Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease” (EITF 01-8), but that DPL did not own the assets under the lease during construction in accordance with EITF Issue No. 97-10, “The Effect of Lessee Involvement in Asset Construction.” DPL concluded that it is not the primary beneficiary under the third PPA because it will only receive 50 percent of the output from the facility and it will not absorb a majority of the risks or rewards as compared to the debt and equity investors in the facility. DPL concluded that consolidation is not required for any of these PPAs under FIN 46(R).
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 sale-leaseback 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 (16), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” PHI maintains a portfolio of cross-border energy sale-leaseback 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 (SILO)
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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 and 2002 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.
In 2008, several court decisions in favor of the IRS disallowed deductions in cases involving other taxpayers with certain cross-border energy lease investments. Under FIN 48, “Accounting for Uncertainty in Income Taxes,” the financial statement recognition of an uncertain tax position is permitted only if it is more likely than not that the position will be sustained. Further, under FASB Staff Position (FSP) No. 13-2, “Accounting for a Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged-Lease Transaction” (FSP 13-2), a company 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 estimated timing of the tax benefits generated from these investments, a recalculation of the value of its equity investment is required.
While PHI believes that its tax position with regard to its cross-border energy lease investments is appropriate based on applicable statutes, regulations and case law and intends to contest the adjustments proposed by the IRS, after evaluating the court rulings described above, PHI, at June 30, 2008, reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of the tax benefits generated from its cross-border energy lease investments. Based on this reassessment, for the quarter ended June 30, 2008, PHI recorded an after-tax charge to net income of $93 million, consisting of the following components:
·
A non-cash pre-tax charge of $124 million ($86 million after tax) under FSP 13-2 to reduce the equity value of these cross-border energy lease investments. This pre-tax charge was recorded in the Consolidated Statement of Earnings as a reduction in other operating revenue.
·
A non-cash after-tax charge of $7 million to reflect the anticipated additional interest expense under FIN 48 related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed (January 1, 2001 through June 30, 2008). This after-tax charge was recorded in the Consolidated Statement of Earnings as an increase in income tax expense.
The charge pursuant to FSP 13-2 reflected 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. This amount is being recognized as income over the remaining term of the affected leases, which expire between 2017 and 2047. The tax benefits associated with the lease transactions represent timing differences that do not change the aggregate amount of lease net income over the life of the transactions. No additional charges were considered necessary in the third and fourth quarters of 2008.
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During 2007, as a result of depreciation studies presented as part of Pepco’s and DPL’s Maryland rate cases, the Maryland Public Service Commission (MPSC) approved new, lower depreciation rates for Maryland distribution assets owned by Pepco and DPL. This resulted in lower depreciation expense of approximately $19 million in 2007.
Revenue Recognition
Regulated Revenue
The Power Delivery businesses recognize revenue upon delivery of electricity and gas to their customers, including amounts for services rendered but not yet billed (unbilled revenue). Pepco Holdings recorded amounts for unbilled revenue of $195 million and $170 million as of December 31, 2008 and 2007, 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 power 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.
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 de minimis.
Competitive Revenue
The Competitive Energy businesses recognize revenue upon delivery of electricity and gas to the customer, including amounts for electricity and gas delivered, but not yet billed. ISO sales and purchases of electric power 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 Statement of Financial Accounting Standards (SFAS) No. 133. 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. Revenue from the Other Non-Regulated business lines is principally recognized when services are performed or products are delivered; however, revenues from utility industry services contracts are recognized using the percentage-of-completion method.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in Pepco Holdings’ gross revenues were $311 million, $318 million and $260 million for the years ended December 31, 2008, 2007 and 2006, respectively.
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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 SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 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 Earnings 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 in the Consolidated Statements of Earnings as operating revenue.
PHI designates certain commodity forwards as “normal purchase or normal sales” under SFAS No. 133, which are not required to be recorded on a mark-to-market basis of accounting under SFAS No. 133. 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 power 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 is extrapolated for future periods where limited market information is available. Models are also used to estimate volumes for certain transactions. See Note (15), “Fair Value
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Disclosures,” for more information about the types of derivatives employed by PHI and the methodologies used to value them.
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 Earnings 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 Earnings 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 adopted and implemented SFAS No. 123R, on January 1, 2006, using the modified prospective method. Under this method, Pepco Holdings recognizes compensation expense for share-based awards, modifications or cancellations after the effective date, based on the grant-date fair value. Compensation expense is recognized over the requisite service period. In addition, compensation cost recognized includes the cost for all share-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. No modifications were made to outstanding stock options or restricted stock awards outstanding prior to the adoption of SFAS No.123R and no changes in valuation methodology or assumptions in estimating their fair value have occurred with its adoption. There were no cumulative adjustments recorded in the financial statements as a result of this new pronouncement; the percentage of forfeitures of outstanding stock options issued prior to SFAS No. 123R’s adoption is estimated to be zero.
In November 2005, the FASB issued FSP 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards” (FSP 123R-3). FSP 123R-3 provides an elective alternative transition method that includes a computation that establishes the beginning balance of the additional paid-in capital (APIC pool) related to the tax effects of employee and director stock-based compensation, and a simplified method to determine the subsequent impact on the APIC pool of employee and director stock-based awards that are outstanding upon adoption of SFAS No. 123R. Entities may make a one-time election to apply the transition method discussed in FSP 123R-3. That one-time election may be made within one year of an entity’s adoption of SFAS No. 123R, or the FSP’s effective date (November 11, 2005), whichever is later. Pepco Holdings adopted the alternative transition method at December 31, 2006.
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
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derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding.
As of January 1, 2008, there were no outstanding options that were not fully vested. Consequently, no compensation cost related to the vesting of options was recorded in 2008. Cash received from stock options exercised under all share-based payment arrangements for the years ended December 31, 2008, 2007 and 2006, was $3 million, $13 million, and $16 million, respectively. The actual tax benefit realized from these option exercises totaled zero, $1 million, and $1 million, respectively, for the years ended December 31, 2008, 2007 and 2006.
PHI has issued both time-based and performance-based restricted stock awards 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 beginning with the 2006-2008 period, and vest in full at the end of the three-year period. The performance-based restricted stock awards for the 2005-2007 performance period contained market conditions that determine the number of shares issuable upon vesting. The market conditions were based on PHI’s total shareholder return relative to a peer group of companies and were reflected in the estimated grant date fair value using a Monte Carlo simulation. The assumptions used in this valuation method included risk free interest rates, expected PHI common stock volatility, and expected correlation to estimate the number of shares to be issued upon vesting. The expected volatility and correlation inputs were based on PHI’s and the peer companies’ shareholder returns over a three-year look back period from the valuation date.
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 as part of Pepco’s acquisition of Conectiv on August 1, 2002. 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.
In 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes.” FIN 48 clarifies the criteria for recognition of tax benefits in accordance with SFAS No. 109, “Accounting for Income Taxes,” and prescribes a financial statement recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Specifically, it clarifies that an entity’s tax benefits must be “more likely than not” of being sustained prior to recording the related tax benefit in the financial statements. If the position drops below the “more likely than not” standard, the benefit can no longer be recognized. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.
On May 2, 2007, the FASB issued FSP FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48” (FIN 48-1), which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously
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unrecognized tax benefits. PHI applied the guidance of FIN 48-1 with its adoption of FIN 48 on January 1, 2007.
The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amounts 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 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 portion of Pepco’s, DPL’s, and 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 (7), “Regulatory Assets and Regulatory Liabilities,” for additional information.
PHI recognizes interest on under/over payments of income taxes, interest on unrecognized tax benefits, 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 from utility plants purchased in prior years are reported on the Consolidated Balance Sheets as “Investment tax credits.” These investment tax credits are being amortized to income over the useful lives of the related utility plant.
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 to use 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 businesses. 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 Earnings. 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
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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 the new information is known.
Inventories
Inventory is valued at the lower of cost or market value. Included in inventories are:
- generation, transmission, and distribution materials and supplies;
- natural gas, fuel oil, and coal; and
- emission allowances, renewable energy credits and RGGI 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 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, coal, and fuel oil for power 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. The FIFO method is not materially different from the weighted average cost method for PHI due to the high inventory turnover rate in the oil marketing business.
Emission allowances from United States Environmental Protection Agency (EPA) allocations 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 power 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, 2008 and 2007, the book value of emission allowances was $11 million and $9 million, respectively. Pepco Holdings has established a committee to monitor compliance with emissions regulations and to ensure its power plants have the required number of allowances.
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 in the Consolidated Statements of Earnings.
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 July 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
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business conditions; a protracted decline in stock price causing market capitalization to fall below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its annual impairment test on July 1, 2008 and an interim impairment test at December 31, 2008, and no impairment was recorded 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 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 (VSCC). 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).
The transmission and wholesale sale of electricity by Pepco, DPL, and ACE are regulated by FERC.
The requirements of SFAS No. 71 apply to the Power Delivery businesses of Pepco, DPL, and ACE. SFAS No. 71 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.
As part of the new electric service distribution base rates for Pepco and DPL approved by the MPSC, effective in June 2007, the MPSC approved for both companies a bill stabilization adjustment mechanism (BSA) for retail customers. See Note (16) “Commitments and Contingencies - Regulatory and Other Matters - Rate Proceedings.” For customers to which the BSA applies, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA thus decouples 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 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 positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a negative Revenue Decoupling Adjustment is recorded as a regulatory liability. The net Revenue Decoupling Adjustment at December 31, 2008 is a regulatory asset and is included in the “Other” line item on the table of regulatory asset balances in Note (7), “Regulatory Assets and Regulatory Liabilities.”
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Leasing Activities
Pepco Holdings’ lease transactions can include plant, office space, equipment, software, vehicles, and power purchase agreements. In accordance with SFAS No. 13, “Accounting for Leases” (SFAS No. 13), these leases are classified as either capital leases, operating leases or leveraged leases. In addition, PHI assesses whether a power purchase agreement contains a lease within the scope of SFAS No. 13 using guidance in EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease.”
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 collectability 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 SFAS No. 13 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 the increases 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 SFAS No. 71, the amortization of the leased asset is based on the rental payments recovered from customers. 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 under SFAS No. 13.
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
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circumstances indicate the carrying value of those assets may not be recoverable under the provisions of SFAS No. 144. 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, 2008, 2007, and 2006.
(a)
Rate reflects the Consolidated Balance Sheet classification of ACE’s generation assets as “assets held for sale” in 2006 and, therefore, de minimis depreciation expense was recorded.
In accordance with FSP American Institute of Certified Public Accountants Industry Audit Guide, Audits of Airlines-”Accounting for Planned Major Maintenance Activities” (FSP AUG AIR-1), costs associated with planned major maintenance activities related to generation facilities are expensed as incurred.
Long-Lived Assets Impairment
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 assets’ carrying amount exceeds their fair value including costs to sell.
Capitalized Interest and Allowance for Funds Used During Construction
In accordance with the provisions of SFAS No. 71, 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
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reduction of “interest expense” and the equity portion of AFUDC is credited to “other income” in the accompanying Consolidated Statements of Earnings.
Pepco Holdings recorded AFUDC for borrowed funds of $5 million, $7 million, and $3 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Pepco Holdings recorded amounts for the equity component of AFUDC of $5 million, $4 million and $4 million for the years ended December 31, 2008, 2007, and 2006, 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. Costs associated with the redemption of debt for PHI’s subsidiaries are also deferred and amortized over the lives of the new issues.
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 and nonqualified retirement plans in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” as amended by SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R)” (SFAS No. 158), and its postretirement health care and life insurance benefits for eligible employees in accordance with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” as amended by SFAS No. 158. PHI’s financial statement disclosures are prepared in accordance with SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” as amended by SFAS No. 158.
See Note (10), “Pensions and Other Postretirement Benefits,” for additional information.
Preferred Stock
As of December 31, 2008 and 2007, 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, 2008 and 2007.
Reclassifications and Adjustments
Certain prior year amounts have been reclassified in order to conform to current year presentation.
During 2008, PHI 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
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to certain restricted stock awards granted under the Long-Term Incentive Plan was understated. These adjustments, which were not considered material either individually or in the aggregate, resulted in increases in Other Operation and Maintenance expenses of $15 million for the year ended December 31, 2008, all of which related to prior periods.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS No. 157)
SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. Under SFAS No. 157, 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 in the most advantageous market using the best available information. The provisions of SFAS No. 157 were effective for financial statements beginning January 1, 2008 for PHI.
In February 2008, the FASB issued FSP 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” (FSP 157-1), that removed fair value measurement for the recognition and measurement of lease transactions from the scope of SFAS No. 157. The effective date of FSP 157-1 was for financial statement periods beginning January 1, 2008 for PHI.
Also in February 2008, the FASB issued FSP 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2), which deferred the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually), until financial statement reporting periods beginning January 1, 2009 for PHI.
PHI applied the guidance of FSP 157-1 and FSP 157-2 with its adoption of SFAS No. 157. The adoption of SFAS No. 157 on January 1, 2008 did not result in a transition adjustment to beginning retained earnings and did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows. SFAS No. 157 also required new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value. This additional disclosure is provided in Note (15), “Fair Value Disclosures.” PHI is currently evaluating the impact of FSP 157-2 and does not anticipate that the application of FSP 157-2 to its other non-financial assets and non-financial liabilities will materially affect its overall financial condition, results of operations, or cash flows.
In September 2008, the SEC and FASB issued guidance on fair value measurements, which was clarified in October 2008 by the FASB in FSP 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active.” This guidance clarifies the application of SFAS No. 157 to assets in an inactive market and illustrates how to determine the fair value of a financial asset in an inactive market. The guidance was effective beginning with the September 30, 2008 reporting period for PHI, and has not had a material impact on PHI’s results.
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SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities-including an Amendment of FASB Statement No. 115” (SFAS No. 159)
SFAS No. 159 permits entities to elect to measure eligible financial instruments at fair value. SFAS No. 159 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. On January 1, 2008, PHI elected not to apply the fair value option for its eligible financial assets and liabilities.
FASB Staff Position (FSP) FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1)
FSP FIN 39-1 amended certain portions of FIN 39. The FSP replaces the terms “conditional contracts” and “exchange contracts” in FIN 39 with the term “derivative instruments” as defined in SFAS No. 133. The FSP also amends FIN 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivables, or the obligation to return cash collateral or payables, arising from the same master netting arrangement as the derivative instruments. FSP FIN 39-1 applied to financial statements beginning January 1, 2008 for PHI.
PHI retrospectively adopted the provisions of FSP FIN 39-1 and elected to offset the net 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. Additional disclosure of collateral positions that have been offset against net derivative positions is provided in Note (17), “Use of Derivatives in Energy and Interest Rate Hedging Activities.” The effect of retrospective application of FSP FIN 39-1 was not material at December 31, 2007 and, as such, no amounts were reclassified.
Emerging Issues Task Force (EITF) Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11)
EITF 06-11 provides that a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and paid to employees for equity classified non-vested equity shares, non-vested equity share units, and outstanding equity share options should be recognized as an increase to additional paid-in capital (APIC). The amount recognized in APIC for the realized income tax benefit from dividends on those awards should be included in the pool of excess tax benefits available to absorb tax deficiencies on share-based payment awards. If the estimated amount of forfeitures increases or actual forfeitures reduce the amount of tax benefits previously recognized in APIC and if the APIC pool is depleted, then the reduction in tax benefit would be an adjustment to the income statement.
EITF 06-11 applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are granted during financial statement reporting periods beginning on January 1, 2008 for PHI. PHI adopted the provisions of EITF 06-11 on January 1, 2008, and it did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.
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SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162)
In May 2008, the FASB issued SFAS No. 162, which identifies the sources of accounting principles and the hierarchy for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. Moving the GAAP hierarchy into the accounting literature directs the responsibility for applying the hierarchy to the reporting entity, rather than just to the auditors.
SFAS No. 162 was effective for PHI as of November 15, 2008 and did not result in a change in accounting for PHI. Therefore, the provisions of SFAS No. 162 did not have a material impact on PHI’s overall financial condition, results of operations, cash flows and disclosure.
FSP FAS 133-1 and FIN 45-4, “Disclosure About Credit Derivatives and Certain Guarantees” (FSP FAS 133-1 and FIN 45-4)
In September 2008, the FASB issued FSP FAS 133-1 and FIN 45-4, which require enhanced disclosures by entities that provide credit protection through credit derivatives (including embedded credit derivatives) within the scope of SFAS No. 133, and guarantees within the scope of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”
For credit derivatives, FSP FAS 133-1 and FIN 45-4 requires disclosure of the nature and fair value of the credit derivative, the approximate term, the reasons for entering the derivative, the events requiring performance, and the current status of the payment/performance risk. It also requires disclosures of the maximum potential amount of future payments without any reduction for possible recoveries under collateral provisions, recourse provisions, or liquidation proceeds. PHI has not provided credit protection to others through the credit derivatives within the scope of SFAS No. 133.
For guarantees, FSP FAS 133-1 and FIN 45-4 requires disclosure on the current status of the payment/performance risk and whether the current status is based on external credit ratings or current internal groupings used to manage risk. If internal groupings are used, then information is required about how the groupings are determined and used for managing risk.
The new disclosures are required starting with financial statement reporting periods ending December 31, 2008 for PHI. Comparative disclosures are only required for periods ending after initial adoption. The new guarantee disclosures did not have a material impact on PHI.
FSP FAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities” (FSP FAS 140-4 and FIN 46(R)-8)
In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8 to expand the disclosures under the original pronouncements. The disclosure requirements in SFAS No. 140 for transfers of financial assets are to include disclosure of (i) a transferor’s continuing involvement in transferred financial assets, and (ii) how a transfer of financial assets to a special-
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purpose entity affects an entity’s financial position, financial performance, and cash flows. The principal objectives of the disclosure requirements in Interpretation 46(R) are to outline (i) the significant judgments in determining whether an entity should consolidate a variable interest entity (VIE), (ii) the nature of any restrictions on consolidated assets, (iii) the risks associated with the involvement in the VIE, and (iv) how the involvement with the VIE affects an entity’s financial position, financial performance, and cash flows.
FSP FAS 140-4 and FIN 46(R)-8 is effective for PHI’s December 31, 2008 financial statements. This FSP has no material impact to PHI’s overall financial condition, results of operations, or cash flows as it relates to SFAS No. 140. PHI’s FIN 46(R) disclosures are provided in Note (2), “Significant Accounting Policies - Consolidation of Variable Interest Entities.”
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
SFAS No. 141(R), “Business Combinations-a Replacement of FASB Statement No. 141” (SFAS No. 141 (R))
SFAS No. 141(R) replaces FASB Statement No. 141, “Business Combinations,” and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141 (R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require 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.
In January 2009, the FASB proposed FSP FAS 141(R)-a “Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP FAS 141(R)-a), to clarify the accounting on the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The FSP FAS 141(R)-a requires that assets acquired and liabilities assumed in a business combination that arise from contingences be measured at fair value in accordance with SFAS No. 157 if the acquisition date can be reasonably determined. If not, then the asset or liability would be measured at the amount in accordance with SFAS 5, “Accounting for Contingencies,” and FIN 14, “Reasonable Estimate of the Amount of Loss.”
SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-a applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009 for PHI. PHI has evaluated the impact of SFAS No. 141(R) and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, or cash flows.
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an Amendment of ARB No. 51” (SFAS No. 160)
SFAS No. 160 establishes 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. It clarifies that a minority interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.
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SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity, and presented separately on the face of the consolidated statement of income, (ii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.
SFAS No. 160 is effective prospectively for financial statement reporting periods beginning January 1, 2009 for PHI, except for the presentation and disclosure requirements. The presentation and disclosure requirements apply retrospectively for all periods presented. PHI has evaluated the impact of SFAS No. 160 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, cash flows or disclosure.
SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an Amendment of FASB Statement No. 133” (SFAS No. 161)
In March 2008, the FASB issued SFAS No. 161, which changes the disclosure requirements for derivative instruments and hedging activities. Entities will be required to provide qualitative disclosures about derivatives objectives and strategies, fair value amounts of gains and losses on derivative instruments which before were optional, disclosure about credit-risk-related contingent features in derivative agreements, and information on the potential effect on an entity’s liquidity from using derivatives.
SFAS No. 161 requires that the gross fair value of derivative instruments and gross gains and losses be quantitatively disclosed in a tabular format to provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. The FASB provides an option for hedged items to be presented in tabular or non-tabular format.
SFAS No. 161 is effective for financial statement reporting periods beginning January 1, 2009 for PHI. SFAS No. 161 encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. PHI is currently evaluating the impact SFAS No. 161 may have on its March 31, 2009 quarterly disclosures.
FSP EITF No. 03-6-1, “Determining whether Instruments Granted in Share-Based Payment Transactions are Participating Securities” (FSP EITF 03-6-1)
In June 2008, the FASB issued FSP EITF 03-6-1, which addresses whether 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) under the two-class method described in SFAS No. 128, “Earnings per Share.”
FSP EITF 03-6-1 is effective for financial reporting periods beginning January 1, 2009 for PHI. All prior period EPS data presented shall be adjusted retrospectively (including interim financial statements, summaries of earnings, and selected financial data) to conform with the
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provisions of FSP EITF 03-6-1. PHI is currently evaluating the impact FSP EITF 03-6-1 will have on its earnings per share calculations.
EITF Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third Party Credit Enhancement” (EITF 08-5)
In September 2008, the FASB issued EITF 08-5 to provide guidelines for the determination of the unit of accounting for a liability issued with an inseparable third-party credit enhancement when it is measured or disclosed at fair value on a recurring basis. EITF 08-5 applies to entities that incur liabilities with inseparable third-party credit enhancements or guarantees that are recognized or disclosed at fair value. This would include guaranteed debt obligations, 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 is 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.
EITF 08-5 is effective on a prospective basis for reporting periods beginning on and after January 1, 2009 for PHI. The effect of initial application must be included in the change in fair value in the period of adoption. PHI is currently evaluating the impact on its accounting and disclosures.
EITF Issue No. 08-6, “Equity Method Investment Accounting Consideration” (EITF 08-6)
In November 2008, the FASB issued EITF 08-6 to address 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 an equity method investee’s issuance of shares should be accounted for. The EITF provides that initial carrying value of an equity method investment can be determined using the accumulation model in SFAS 141(R), “Business Combination (revised 2007),” and other-than-temporary impairments should be recognized in accordance with paragraph 19(h) of Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”
This EITF is effective for PHI beginning January 1, 2009. PHI is currently evaluating the impact on its accounting and disclosures.
FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP FAS 132(R)-1)
In December 2008, the FASB issued FSP FAS 132(R)-1 to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The required disclosures under this FSP would expand current disclosures under SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits-an amendment of FASB Statements No. 87, 88, and 106,” to be in line with SFAS No. 157 required disclosures.
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The disclosures are to provide users an understanding of the investment allocation decisions made, factors used in the investment policies and strategies, plan assets by major investment types, inputs and valuation techniques used to measure fair value of plan assets, significant concentration of risk within the plan, and the effects of fair value measurement using significant unobservable inputs (Level 3 as defined in SFAS No. 157) on changes in plan assets for the period.
The new disclosures are required starting with financial statement reporting periods ending December 31, 2009 for PHI and earlier application is permitted. Comparative disclosures under this provision are not required for earlier periods presented. PHI is currently evaluating the impact on its disclosures.
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(5) SEGMENT INFORMATION
Based on the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” Pepco Holdings’ management has identified its operating segments at December 31, 2008 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Segment financial information for the years ended December 31, 2008, 2007, and 2006, is as follows:
(a)
Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. For consolidation purposes, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance which is primarily attributable to Power Delivery. Included in Corp. & 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 Corp. & 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 Taxes is a $7 million after-tax charge for the additional interest accrued on the related tax obligations.
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(a)
Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. For consolidation purposes, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance which is primarily attributable to Power Delivery. Included in Corp. & 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 Corp. & Other.
(d)
Includes $33 million ($20 million, after-tax) from 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.
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(a)
Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. For consolidation purposes, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance which is primarily attributable to Power Delivery. Included in Corp. & Other are intercompany amounts of $(481) million for Operating Revenue, $(475) million for Operating Expense, $(90) million for Interest Income, $(88) 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 $461 million for the year ended December 31, 2006.
(c)
Includes depreciation and amortization of $413 million, consisting of $354 million for Power Delivery, $36 million for Conectiv Energy, $12 million for Pepco Energy Services, $2 million for Other Non-Regulated and $9 million for Corp. & Other.
(d)
Includes $12 million gain ($8 million after-tax) on the sale of its equity interest in a joint venture which owns a wood burning cogeneration facility in California.
(e)
Includes $19 million of impairment losses ($14 million after-tax) related to certain energy services business assets.
(f)
In 2006, PHI resolved certain, but not all, tax matters that were raised in Internal Revenue Service 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 Corp. & Other). To the extent that the matters resolved related to tax contingencies from the Conectiv legacy companies that existed at the August 2002 acquisition 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 Corp. & Other to eliminate the tax benefits recorded by Power Delivery and Other Non-Regulated against the goodwill balance that resulted from the acquisition. 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 Corp. & Other).
(g)
Includes stock-based compensation expense of $5 million, consisting primarily of $4 million for Power Delivery and $1 million for Conectiv Energy.
(6) GOODWILL
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 SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). PHI’s July 1, 2008 annual impairment test indicated that its goodwill was not impaired. PHI performed an interim impairment test at December 31, 2008, as its market capitalization for a significant period in the fourth quarter of 2008 was lower than its book value. The test at December 31, 2008 indicated that the goodwill balance was not impaired.
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To estimate the fair value of its Power Delivery reporting unit for its goodwill impairment test, PHI reviewed 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 estimate of terminal value is based on a constant, annual cash flow growth rate that is consistent with Power Delivery’s plan, and the other estimate of terminal value is based on a multiple of earnings before interest, taxes, depreciation, and amortization that management believes is consistent with relevant market multiples for comparable utilities. Each model uses a cost of capital appropriate for a regulated utility as the discount rate for the estimated cash flows associated with the reporting unit. Neither valuation model evidenced impairment of goodwill. PHI has consistently used this valuation model to estimate the fair value of Power Delivery since the adoption of SFAS No. 142.
The estimation of fair value is dependent on a number of factors, including but not limited to future growth assumptions, operating and capital expenditure requirements, and capital costs, and changes in these factors could materially impact the results of impairment testing. The estimated cash flows were sourced from the Power Delivery reporting unit’s business forecast, and they incorporate current plans for capital expenditures and regulatory ratemaking cases. Assumptions and methodologies used in the models were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures. The discount rate employed reflected PHI’s estimated cost of capital. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the Power Delivery reporting unit include utility sector market performance, sustained poor economic conditions, the results of rate-making proceedings, higher operating and capital expenditure requirements, a significant increase in the cost of capital and other factors.
PHI reconciled its total market capitalization at year-end with the sum of the fair value of its business segments to further substantiate the estimated fair value of the Power Delivery reporting unit. PHI determined its market capitalization as of December 31, 2008 for purposes of the reconciliation, which was 7 percent below book value. PHI estimated the fair value of its other business segments (Conectiv Energy, Pepco Energy Services, Other Non-Regulated, and Corporate & Other). The sum of the estimated fair values of the segments exceeded the market capitalization of PHI at December 31, 2008. Management believes that the excess fair value is reflective of a reasonable control premium that reconciles PHI’s market capitalization to the estimated fair value of its business segments. The control premium calculated was consistent with control premiums paid in historical acquisitions in the utility industry.
With the current volatile general market conditions and the disruptions in the credit and capital markets, PHI will continue to closely monitor for indicators of goodwill impairment.
A roll forward of PHI’s goodwill balance is set forth below (millions of dollars):
Balance, December 31,
$
1,409
Add: Adjustment due to resolution of pre-merger tax contingencies
and correction of pre-merger deferred tax balances
Balance, December 31,
1,410
Less:Changes in estimates related to pre-merger tax contingencies and adjustments to deferred tax balance
Balance, December 31, 2008
$
1,411
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(7) REGULATORY ASSETS AND REGULATORY LIABILITIES
The components of Pepco Holdings’ regulatory asset balances at December 31, 2008 and 2007 are as follows:
The components of Pepco Holdings’ regulatory liability balances at December 31, 2008 and 2007 are as follows:
A description for each category of regulatory assets and regulatory liabilities follows:
Securitized Stranded Costs: Represents stranded costs associated with contract termination payments associated with a contract between ACE and an unaffiliated non-utility generator (NUG) and the discontinuation of the application of SFAS No. 71 for ACE’s electricity generation business. 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 received on these deferrals with the exception of taxes.
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Pension and OPEB Costs: Represents the funded portion of Pepco Holdings’ defined benefit pension and other postretirement benefit plans that is probable of recovery in rates under SFAS No. 71 by Pepco, DPL and ACE. There is no return on these deferrals.
Deferred Energy Supply Costs: The regulatory asset primarily represents deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco and DPL. The regulatory liability primarily represents deferred costs associated with a net over-recovery by ACE connected with the provision of Default Electricity Supply and other restructuring related costs incurred by ACE. A return is generally received on these deferrals other than the Default Electricity Supply deferrals which do not earn a return.
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 provide deferred income taxes. As the temporary differences between the financial statement and tax basis of assets reverse, the deferred recoverable balances are reversed. There is no return 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 received 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 and earns a return.
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 on this deferral.
Phase In Credits: Represents 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 to occur over a 17-month period beginning January 2008. The Delaware deferral will be 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 and ending in 2008. There is no return on these deferrals.
Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years and generally do not receive a return.
Deferred Income Taxes Due to Customers: Represents the portion of deferred income tax liabilities applicable to utility operations of Pepco, DPL, and ACE that has not been reflected in current customer rates for which future payment to customers is probable. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return 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
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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 on these deferrals.
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.
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 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 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 are being 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 is no return on these deferrals.
Settlement Proceeds - Mirant Bankruptcy Claims: In 2007, Pepco received $414 million of net proceeds from settlement of a Mirant Corporation (Mirant) 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 Energy Trading LLC (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. Pepco filed rate applications with the DCPSC and the MPSC in the fourth quarter of 2008 to provide for the disposition of the remaining funds. See Note (16), “Commitments and Contingencies - Proceeds from Settlement of Mirant Bankruptcy Claims” for additional information. Currently there is no return on these deferrals.
Other: Includes miscellaneous regulatory liabilities such as the over-recovery of administrative costs associated with Maryland, Delaware and District of Columbia SOS. These regulatory liabilities generally do not receive a return.
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(8) LEASING ACTIVITIES
Investment in Finance Leases Held in Trust
As of December 31, 2008 and December 31, 2007, Pepco Holdings had cross-border energy lease investments of $1.3 billion and $1.4 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 (16), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” during the second quarter of 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. Based on this reassessment, PHI for the quarter ended June 30, 2008, recorded a reduction in its cross-border energy lease investments of $124 million. No further charges were considered necessary in the third and fourth quarters of 2008.
The components of the cross-border energy lease investments at December 31, 2008 (reflecting the effects of recording this charge) and at December 31, 2007 are summarized below:
Income recognized from cross-border energy lease investments was comprised of the following for the years ended December 31, 2008, 2007 and 2006:
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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 2009 through 2013 and thereafter are zero for 2009, $16 million for 2010, zero for 2011, 2012 and 2013, and $1,319 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 $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 SFAS No. 71, 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. This lease has been treated as an operating lease for rate-making purposes.
Capital lease assets recorded within Property, Plant and Equipment at December 31, 2008 and 2007, in millions of dollars, are comprised of the following:
At December 31, 2008
Original
Cost
Accumulated
Amortization
Net Book
Value
Transmission
$76
$24
$52
Distribution
General
-
Total
$155
$50
$105
At December 31, 2007
Transmission
$ 76
$ 21
$ 55
Distribution
General
-
Total
$155
$ 44
$111
The approximate annual commitments under all capital leases are $15 million for each year 2009 through 2013, and $92 million thereafter.
Rental expense for operating leases was $69 million, $50 million, and $53 million for the years ended December 31, 2008, 2007, and 2006, respectively.
Total future minimum operating lease payments for Pepco Holdings as of December 31, 2008, are $56 million in 2009, $75 million in 2010, $44 million in 2011, $28 million in 2012, $19 million in 2013 and $369 million after 2013.
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(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.
Asset Sales
In the third quarter of 2006, ACE completed the sale of its interest in the Keystone and Conemaugh generating facilities for approximately $175 million (after giving effect to post-closing adjustments). In the first quarter of 2007, ACE completed the sale of the B.L. England generating facility for a price of $9 million. In February 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.
In January 2008, DPL completed (i) the sale of its retail electric distribution assets on the Eastern Shore of Virginia to A&N Electric Cooperative for a purchase price of approximately $49 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative for a purchase price of approximately $5 million, after closing adjustments.
Jointly Owned Plant
PHI’s Consolidated Balance Sheet includes its proportionate share of assets and liabilities related to jointly owned plant. PHI’s subsidiaries have ownership interests in transmission facilities and other facilities in which various parties also have ownership interests. PHI’s
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proportionate share of operating and maintenance expenses of the jointly owned plant is included in the corresponding expenses in PHI’s Consolidated Statements of Earnings. PHI is responsible for providing its share of financing for the jointly owned facilities. Information with respect to PHI’s share of jointly owned plant as of December 31, 2008 is shown below.
Asset Retirement Obligations (AROs)
A reconciliation of the balances of PHI’s AROs is shown in the table below for the years ended December 31, 2008 and 2007 (millions of dollars):
During the first quarter of 2006, ACE recorded an asset retirement obligation of $60 million for the B.L. England plant demolition and environmental remediation costs; the obligation was to be amortized over a two-year period. In the first quarter of 2007, ACE completed the sale of the B.L. England generating facilities and the asset retirement obligation and asset retirement costs were reversed.
(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.
Pepco Holdings accounts for the PHI Retirement Plan and nonqualified retirement plans in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” and its postretirement
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health care and life insurance benefits for eligible employees in accordance with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” In addition, on December 31, 2006, Pepco Holdings implemented SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R)” (SFAS No. 158), which requires that companies recognize a net liability or asset to report the funded status of their defined benefit pension and other postretirement benefit plans on the balance sheet, with an offset to accumulated other comprehensive income in shareholders’ equity or a deferral in a regulatory asset or liability if probable of recovery in rates under SFAS No. 71, “Accounting For the Effects of Certain Types of Regulation.” SFAS No.158 does not change how pension and other postretirement benefits expenses are accounted for and reported in the consolidated statements of earnings. PHI’s financial statement disclosures are prepared in accordance with SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” as revised and amended by SFAS No. 158. Refer to Note (2), “Significant Accounting Policies - Pension and Other Postretirement Benefit Plans,” for additional information.
All amounts in the following tables are in millions of dollars.
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The following table provides the amounts recognized in PHI’s Consolidated Balance Sheets as of December 31, 2008, in compliance with SFAS No. 158:
Amounts included in accumulated other comprehensive income (pre-tax) and regulatory assets at December 31, 2008 in compliance with SFAS No. 158 consist of:
The table below provides the components of net periodic benefit costs recognized for the years ended December 31.
The table below provides the split of the combined pension and other postretirement net periodic benefit costs between subsidiaries:
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The following weighted average assumptions were used to determine the benefit obligations at December 31:
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 (millions of dollars):
1-Percentage-
Point Increase
1-Percentage-
Point Decrease
Increase (decrease) on total service and interest cost
$ 2
$ (2)
Increase (decrease) on postretirement benefit obligation
$36
$(31)
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 SFAS No. 87 and SFAS No. 106 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%.
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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%.
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% in 2015 and later, from the 2007 valuation assumption for 2008 of 7% declining 1% per year to 5% in 2010 and later.
Plan Assets
The PHI Retirement Plan weighted average asset allocations at December 31, 2008, and 2007, by asset category are as follows:
Pepco Holdings’ other postretirement plan weighted average asset allocations at December 31, 2008, and 2007, by asset category are as follows:
In developing an asset allocation policy for the PHI Retirement Plan and other postretirement plan, PHI examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, PHI examined 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. By incorporating the results of these analyses with an assessment of its risk posture, and taking into account industry practices, PHI developed its asset mix guidelines. Under these guidelines, PHI diversifies assets in order to protect against large investment losses and to reduce the probability of excessive performance volatility while maximizing return at an acceptable risk level. Diversification of assets is implemented by allocating monies to various asset classes and investment styles within asset classes, and by retaining investment management firm(s) with complementary investment philosophies, styles and approaches. Based on the assessment of demographics, actuarial/funding, and business and financial characteristics, PHI believes that its risk posture is slightly below average relative to
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other pension plans. Consequently, Pepco Holdings 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 the other postretirement plan.
On a periodic basis, Pepco Holdings reviews its asset mix and rebalances assets back to the target allocation over a reasonable period of time. During 2008, the volatility in the stock market made it challenging to maintain the target asset allocation. PHI expects to return to its target asset allocation during 2009 through a combination of contributions to the plan and payment of monthly benefits.
No Pepco Holdings common stock is included in pension or postretirement program assets.
Cash Flows
Contributions - PHI Retirement Plan
PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level in excess of 100% of its accumulated benefit obligation (ABO) and that is at least equal to the funding target as defined under the Pension Protection Act of 2006. As of the January 1, 2008 valuation, the PHI Retirement Plan satisfied the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) without requiring any additional funding. In 2008 and 2007, no contributions were made to the PHI Retirement Plan.
At December 31, 2008, PHI’s Plan assets were approximately $1.1 billion and the ABO was approximately $1.6 billion. At December 31, 2007, PHI’s Plan assets were approximately $1.6 billion and the ABO was approximately $1.6 billion. Although PHI projects there will be no minimum funding requirement under the Pension Protection Act guidelines in 2009, PHI expects to make discretionary tax-deductible contribution of approximately $300 million to bring its plan assets to at least the funding target level for 2009 under the Pension Protection Act.
Contributions - Other Postretirement Benefits
In 2008 and 2007, Pepco contributed $9 million and $10 million, respectively, DPL contributed $9 million and $8 million, respectively, and ACE contributed $7 million and $7 million, respectively, to the other postretirement benefit plan. In 2008 and 2007, contributions of $14 million and $13 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 2009.
Expected Benefit Payments
Estimated future benefit payments to participants in PHI’s pension and postretirement welfare benefit plans, which reflect expected future service as appropriate, as of December 31, 2008 are as follows (millions of dollars):
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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 benefits 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, 2008, the estimated reduction in accumulated postretirement benefit obligation is $30 million. In 2008 and 2007, Pepco Holdings received $2 million 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, $11 million, and $11 million for the years ended December 31, 2008, 2007, and 2006, 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 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 First Mortgage Bonds issued by the indicated company as collateral for an outstanding series of senior notes as described in footnote (a) above 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)
The bonds are subject to mandatory tender on July 1, 2010.
(d)
The bonds are subject to mandatory tender on May 1, 2011.
(e)
Represents tax exempt bonds issued by municipal authorities for the benefit of the company that were purchased at par by the company in 2008. The obligations of the company with respect to the bonds are considered to be extinguished for accounting purposes. The company currently intends to hold the bonds until such time as they can be resold to the public.
(f)
The bonds were subject to mandatory tender on August 1, 2008.
NOTE: Schedule is continued on next page.
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(a)
Debt issued at a fixed rate of 8.24%. The debt was swapped into variable rate debt at the time of issuance.
NOTE: Schedule is continued on next page.
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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, 2008, are $82 million in 2009, $532 million in 2010, $70 million in 2011, $787 million in 2012, $558 million in 2013, and $3,328 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, 2008 and 2007, Pepco Energy Services had outstanding total long-term project funding (including current maturities) of $21 million and $29 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, 2008, are $2 million for each year 2009 through 2013, and $11 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, 2008 and 2007 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 PHI, Pepco, DPL and ACE are backed by $1.9 billion in credit facilities, which are described under the heading “Credit Facilities” below.
Pepco Holdings, Pepco, DPL and ACE had no commercial paper outstanding at December 31, 2008. The weighted average interest rate for Pepco Holdings, Pepco, DPL and ACE commercial paper issued during 2008 was 3.18%, 3.45%, 3.88% and 3.12% respectively. The weighted average maturity for Pepco Holdings, Pepco, DPL and ACE was three, two, five and four days respectively for all commercial paper issued during 2008.
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 continue to 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, 2008 mature as follows: 2009 to 2010 ($3 million), 2014 to 2017 ($49 million), 2024 ($24 million) and 2028 to 2031 ($64 million). The weighted average interest rate for VRDB was 3.10% during 2008 and 3.79% during 2007. Of the $118 million in VRDB, $72 million are secured by First Mortgage Bonds issued by DPL, the issuer of the VRDB.
Bank Loans
In March 2008, DPL obtained a $150 million unsecured term loan that matures in July 2009. Interest on the loan is calculated at a variable rate.
In May 2008, Pepco obtained a $25 million bank loan that matures on April 30, 2009. Interest on the loan is calculated at a variable rate.
Credit Facilities
PHI, Pepco, DPL and ACE maintain a credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under this primary 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
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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. All indebtedness incurred under the facility is unsecured.
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 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 credit facility in the amount of $400 million with a syndicate of nine lenders. Under the facility, PHI may obtain revolving loans and swingline loans over the term of the facility, which expires on November 6, 2009. The facility does not provide for the issuance of letters of credit. All indebtedness incurred under the facility is unsecured. 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 primary 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.
Typically, PHI and its utility subsidiaries issue commercial paper if required to meet their short-term working capital requirements. Given the recent lack of liquidity in the commercial paper markets, the companies have borrowed under the primary credit facility to maintain sufficient cash on hand to meet daily short-term operating needs. As of December 31, 2008, PHI had an outstanding loan of $50 million and Pepco had an outstanding loan of $100 million under this facility. In January 2009, PHI borrowed an additional $150 million under the facility.
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(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 as part of Pepco’s acquisition of Conectiv on August 1, 2002. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.
The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below.
Provision for Consolidated Income Taxes
Reconciliation of Consolidated Income Tax Rate
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 “Deferred tax adjustments” in the reconciliation provided above.
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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 FIN 48 (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 FIN 48 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.
FIN 48, “Accounting for Uncertainty in Income Taxes”
As disclosed in Note (2), “Significant Accounting Policies,” PHI adopted FIN 48 effective January 1, 2007. Upon adoption, PHI recorded the cumulative effect of the change in accounting principle of $7 million as a decrease in retained earnings. Also upon adoption, PHI had $187 million of unrecognized tax benefits and $24 million of related accrued interest.
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, in accordance with FIN 48, 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, 2008, included $18 million that, if recognized, would lower the effective tax rate.
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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, 2008 and 2007, PHI recognized $25 million of interest income before tax ($15 million after-tax) and $4 million of interest expense before tax ($2 million after-tax), respectively, as a component of income tax expense. As of December 31, 2008 and 2007, PHI had $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 and the obligation becomes certain. See Note (16), “Commitments and Contingencies,” for additional information.
Tax Years Open to Examination
PHI and the majority of its subsidiaries file a consolidated federal income tax return. 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 noted above.
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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 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 normalized over the remaining service lives of the related assets.
Resolution of Certain Internal Revenue Service Audit Matters
In 2006, PHI resolved certain, but not all, tax matters that were raised in Internal Revenue Service 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 Corp. & 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 Corp. & 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 Corp. & Other).
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Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below. The total amounts below include $347 million, $348 million, and $333 million, for the years ended December 31, 2008, 2007, and 2006, respectively, related to the Power Delivery Business, which are recoverable through rates.
(13) MINORITY INTEREST
The outstanding preferred stock issued by subsidiaries of PHI as of December 31, 2008 and 2007 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 the time of the adoption of the LTIP, 10 million shares of common stock were reserved for issuance under the LTIP over a period of 10 years commencing August 1, 2002.
Total stock-based compensation expense recorded in the Consolidated Statements of Earnings for the years ended December 31, 2008, 2007, and 2006 is $16 million, $4 million, and
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$6 million, respectively. During 2008, PHI recorded a correction to its prior-year stock based compensation expense. See discussion of the correction in Note (2), “Significant Accounting Policies ¾ Reclassification.” For the years ended December 31, 2008, 2007, and 2006, $1 million in tax expense and $2 million and zero, respectively, in tax benefits were recognized in relation to stock-based compensation costs of stock awards. No compensation costs related to restricted stock grants were capitalized for the years ended December 31, 2008, 2007 and 2006.
PHI recognizes compensation expense related to performance restricted stock awards and time-restricted share awards based on the fair value of the awards at date of grant. PHI estimated the fair value of market condition awards for its 2005-2007 performance restricted stock awards using a Monte Carlo simulation model, in a risk-neutral framework, based on the following assumptions:
Performance Period 2005-2007
Risk-free interest rate (%)
3.37
Peer volatilities (%)
15.5 - 60.1
Peer correlations
0.15 - 0.72
Fair value of restricted share
$26.92
Prior to the acquisition of Conectiv by Pepco in 2002, each company had a long-term incentive plan under which stock options were granted. At the time of the acquisition, certain Conectiv options were exchanged on a 1 for 1.28205 basis for Pepco Holdings stock options under the LTIP, resulting in the conversion of 590,198 Conectiv stock options into 756,660 Pepco Holdings stock options. At December 31, 2008, 116,404 of these options remained outstanding, all of which are exercisable at exercise prices of either $13.08 or $19.03.
At the same time, all outstanding Pepco options were exchanged on a one-for-one basis for Pepco Holdings stock options granted under the LTIP. At December 31, 2008, 258,500 of these options remained outstanding, all of which are exercisable. The exercise prices of these options are $21.825, $22.4375, $22.57, $22.685, $23.15625, $24.59 and $29.78125.
Stock option activity for the three years ended December 31, 2008, 2007 and 2006 is summarized below. The information presented in the table is for Pepco Holdings, including converted Pepco and Conectiv options.
All stock options have an expiration date of ten years from the date of grant.
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The aggregate intrinsic value of stock options outstanding and exercisable at December 31, 2008, 2007, and 2006 was zero, $4 million, and $4 million, respectively.
The total intrinsic value of stock options exercised during the years ended December 31, 2008, 2007, and 2006 was less than $1 million, $3 million, and $2 million, respectively. For the years ended December 31, 2008, 2007, and 2006, less than $1 million, $1 million, and $1 million, respectively, in tax benefits were recognized in relation to stock-based compensation costs of stock options.
As of December 31, 2008, an analysis of options outstanding by exercise prices is as follows:
There were no options granted in 2008, 2007, or 2006.
The Performance Restricted Stock Program and the Merger Integration Success Program have been established under the LTIP. Under the Performance Restricted Stock Program, performance criteria are selected and measured over a three-year period. The target number of share award opportunities established in 2008, 2007 and 2006 under Pepco Holdings’ Performance Restricted Stock Program for performance periods 2008-2010, 2007-2009, and 2006-2008 were 187,175, 200,885, and 218,108, respectively. Additionally, beginning in 2006, time-restricted share award opportunities with a requisite service period of three years were established under the LTIP. The target number of share award opportunities for these awards was 93,584 for the 2008-2010 time period, 100,430 for the 2007-2009 time period and 109,057 for the 2006-2008 time period. The fair value per share on award date for the performance restricted stock was $25.36 for the 2008-2010 award, $25.54 for the 2007-2009 award, and $23.28 for the 2006-2008 award. Depending on the extent to which the performance criteria are satisfied, the executives are eligible to earn shares of common stock and dividends accrued thereon over the vesting period, under the Performance Restricted Stock Program ranging from 0% to 200% of the target share award opportunities, inclusive of dividends accrued. There were 454,632 awards earned with respect to the 2005-2007 share award opportunity.
Under the LTIP, non-employee directors are entitled 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.
In connection with the acquisition of Conectiv by Pepco, 80,602 shares of Conectiv performance accelerated restricted stock (PARS) were converted to 104,298 shares of Pepco Holdings restricted stock vesting over periods ranging from 5 to 7 years from the original grant date. As of December 31, 2008, 87,507 converted shares had vested, 10,122 were forfeited and 6,669 shares remain unvested. On January 2, 2009, all remaining shares vested at an average market price of $17.635 per share.
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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. The 2008 activity for non-vested share opportunities with respect to PHI common stock (including Conectiv PARS converted to Pepco Holdings restricted stock) is summarized below.
The total fair value of restricted stock awards vested during the years ended December 31, 2008, 2007, and 2006 was $12 million, $10 million, and $2 million, respectively.
As of December 31, 2008, there was approximately $8 million of unrecognized compensation cost (net of estimated forfeitures) related to non-vested stock granted under the plans. That cost is expected to be recognized over a weighted-average period of approximately two years.
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 and regulatory laws, which impose limitations on the funds that can be used to pay dividends and, in the case of regulatory laws, as applicable, may require the prior approval of the relevant utility regulatory commissions before dividends can be paid; (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 restriction in the ACE charter does not limit its ability to pay dividends. Restricted net assets related to PHI’s consolidated subsidiaries amounted to approximately $2.1 billion at December 31, 2008 and $1.8 billion at December 31, 2007. PHI had no restricted retained earnings or restricted net income at December 31, 2008 and 2007.
PEPCO HOLDINGS
For the years ended December 31, 2008, 2007 and 2006, Pepco Holdings recorded dividends from its subsidiaries as follows:
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 sharers 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, 2008, 2007 and 2006 was de minimis.
Compensation recognized in respect of dividends and increase in fair value in the years ended December 31, 2008, 2007 and 2006 was de minimis. The balance of deferred compensation invested in phantom Pepco Holdings’ shares at December 31, 2008 and 2007 was $1 million and $2 million, respectively.
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.
(a)
Approximately 1 million shares at December 31, 2006 related to options to purchase common stock have been excluded from the calculation of diluted EPS as they are considered to be anti-dilutive.
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Shareholder Dividend Reinvestment Plan
PHI maintains a Shareholder Dividend Reinvestment Plan (DRP) 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 original issue shares or, at the election of PHI, shares purchased in the open market. There were approximately 1 million original issue shares sold under the DRP in 2008, 2007 and 2006.
Pepco Holdings Common Stock Reserved and Unissued
The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2008:
Name of Plan
Number of
Shares
DRP
1,436,151
Conectiv Incentive Compensation Plan (a)
1,187,157
Potomac Electric Power Company Long-Term Incentive Plan (a)
327,059
Pepco Holdings Long-Term Incentive Plan
8,473,554
Pepco Holdings Non-Management Directors Compensation Plan
488,713
Pepco Holdings Retirement Savings Plan (b)
3,617,173
Total
15,529,807
(a)
No further awards will be made under this plan.
(b)
Effective January 30, 2006, Pepco Holdings established the Retirement Savings Plan which is an amalgam of, and a successor to, (i) the Potomac Electric Power Company Savings Plan for Bargaining Unit Employees, (ii) the Potomac Electric Power Company Retirement Savings Plan for Management Employees (which resulted from the merger, effective January 1, 2005, of the Potomac Electric Power Company Savings Plan for Non-Bargaining Unit, Non-Exempt Employees and the Potomac Electric Power Company Savings Plan for Exempt Employees), (iii) the Conectiv Savings and Investment Plan, and (iv) the Atlantic City Electric 401(k) Savings and Investment Plan - B.
(15)
FAIR VALUES DISCLOSURES
Effective January 1, 2008, PHI adopted SFAS No. 157, as discussed earlier in Note (3), which established a framework for measuring fair value and expanded disclosures about fair value measurements.
As defined in SFAS No. 157, 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. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The
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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 defined by SFAS No. 157 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 liabilities are primarily natural gas options. 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. Some of the options do not expire until December 2011. All of the options are part of the natural gas hedging program approved by the Delaware Public Service Commission.
Level 3 instruments classified as executive deferred compensation plan assets and liabilities 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 table sets 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, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
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A reconciliation of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (level 3) is shown below:
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The estimated fair values of Pepco Holdings’ non-derivative financial instruments at December 31, 2008 and 2007 are shown below.
The methods and assumptions described below were used to estimate, at December 31, 2008 and 2007, 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 at December 31, 2008 and 2007, or bid prices obtained from brokers, if actual trade prices were not available. Long-term debt includes recourse and non-recourse debt issued by PCI. The fair value of this debt, including amounts due within one year, was determined based on current rates offered to companies with similar credit ratings in the same industry as PHI for debt with similar remaining maturities. The fair values of all other Long-Term Debt and Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on current market prices, or for issues with no market price available, were based on discounted cash flows using current rates for similar issues with similar credit ratings, terms, and remaining maturities.
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 of preferred stock with similar terms.
The carrying amounts of all other financial instruments in Pepco Holdings’ accompanying financial statements approximate fair value.
(16) 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
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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.
On September 5, 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. The use of the damages received from Mirant to offset above-market costs of energy and capacity under the Panda PPA and to make the payment to Sempra reduced the balance of proceeds from the Mirant settlement to approximately $102 million as of December 31, 2008.
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 previously approved by the respective commissions. Under Pepco’s proposals, District of Columbia and Maryland customers would receive a total of approximately $25 million and $29 million, respectively. On December 12, 2008, the DCPSC issued a Notice of Proposed Rulemaking concerning the sharing of the Mirant divestiture proceeds, including the bankruptcy settlement proceeds. The public comment period for the proposed rules has expired without any comments being submitted. This matter remains pending before the DCPSC.
On February 17, 2009, Pepco, the Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff filed a settlement agreement with the MPSC. The settlement, among other things, provides that of the remaining balance of the Mirant settlement, Pepco shall distribute $39 million to its Maryland customers through a one-time billing credit. If the settlement is approved by the MPSC, Pepco currently estimates that it will result in a pre-tax gain in the range of $15 million to $20 million, which will be recorded when the MPSC issues its final order approving the settlement.
Pending the final disposition of these funds, the remaining $102 million in proceeds from the Mirant settlement is being accounted for as restricted cash and as a regulatory liability.
Rate Proceedings
In the most recent electric service distribution base rate cases filed by Pepco in the District of Columbia and Maryland and by DPL in Maryland, and in a natural gas distribution case filed by DPL in Delaware, Pepco and DPL proposed the adoption of a BSA for retail customers. As more fully discussed below, the implementation of a BSA has been approved for both Pepco and DPL electric service in Maryland and remains pending for Pepco in the District of Columbia. A method of revenue decoupling similar to a BSA, referred to as a modified fixed variable rate design (MFVRD), has been adopted for DPL in Delaware, which will be implemented in the context of DPL’s next Delaware base rate case.
Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount. The BSA increases rates if actual distribution revenues fall below the level approved by the applicable commission 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” revenue from unit sales consumption and ties the growth in revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue
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fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable utility 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 delivery revenues. The MVFRD adopted in Delaware relies primarily upon 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 believes that the MFRVD can serve as an appropriate revenue decoupling mechanism.
Delaware
On August 29, 2008, DPL submitted its 2008 Gas Cost Rate (GCR) filing to the DPSC, requesting a 14.8% increase in the level of GCR. On September 16, 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.
On January 26, 2009, DPL submitted to the DPSC an interim GCR filing, requesting a 6.6% decrease in the level of GCR. On February 5, 2009, the DPSC issued an initial order approving the requested decrease, to become effective on March 1, 2009, subject to refund pending final DPSC approval after evidentiary hearings.
District of Columbia
In December 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. In January 2008, the DCPSC approved, effective February 20, 2008, a revenue requirement increase of approximately $28 million, based on an authorized return on rate base of 7.96%, including a 10% return on equity (ROE). This increase did not include a BSA mechanism. While finding a BSA to be an appropriate ratemaking concept, the DCPSC cited potential statutory problems in its authority to implement the BSA. In February 2008, the DCPSC established a Phase II proceeding to consider these implementation issues. In August 2008, the DCPSC issued an order concluding that it has the necessary statutory authority to implement the BSA proposal and that further evidentiary proceedings are warranted to determine whether the BSA is just and reasonable. On January 2, 2009, the DCPSC issued an order designating the issues and establishing a procedural schedule for the BSA proceeding. Hearings are scheduled for the second quarter of 2009.
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 January 2008 order granting Pepco’s rate increase, 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 order denying its motion for reconsideration. The District of Columbia Court of Appeals granted the petition; briefs have been filed by the parties and oral argument is scheduled for March 2009.
Maryland
In July 2007, the MPSC issued orders in the electric service distribution rate cases filed by DPL and Pepco, each of which included approval of a BSA. The DPL order approved an
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annual increase in distribution rates of approximately $15 million (including a decrease in annual depreciation expense of approximately $1 million). The Pepco order approved an annual increase in distribution rates of approximately $11 million (including a decrease in annual depreciation expense of approximately $31 million). In each case, the approved distribution rate reflects an ROE of 10%. The rate increases were effective as of June 16, 2007, and remained in effect for an initial period until July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of audits of each company’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required. On July 18, 2008, the MPSC issued one order covering the Phase II proceedings for both DPL and Pepco, denying any further adjustment to the rates for each company, thus making permanent the rate increases approved in the July 2007 orders. The MPSC also issued an order on August 4, 2008, further explaining its July 18 order.
DPL and Pepco each have filed a general notice of appeal of the MPSC July 2007 and the July 18 and August 4, 2008 orders. The appeals challenge the MPSC’s failure to implement permanent rates in accordance with Maryland law, and seek judicial review of the MPSC’s denial of both companies’ rights to recover an increased share of the PHI Service Company costs and the costs of performing a MPSC-mandated management audit. The case currently is pending before the Circuit Court for Baltimore City, which issued an order consolidating the appeals on January 27, 2009. Under the procedural schedule set by the court, Pepco and DPL will file a consolidated brief on or before March 9, 2009, specifying the basis for their requested relief.
Federal Energy Regulatory Commission
On August 18, 2008, PHI, Pepco, DPL and ACE submitted an application with FERC for incentive rate treatments in connection with PHI’s MAPP project. The application requested that FERC include Construction Work in Progress of each of Pepco, DPL and ACE in its transmission rate base, an ROE adder of 150 basis points (for a total ROE of 12.8%) and the recovery of prudently incurred costs in the event the project is abandoned or terminated for reasons beyond the control of the applicants. On October 31, 2008, FERC issued an order approving the application.
Divestiture Cases
District of Columbia
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 (IRC) and its implementing regulations. As of December 31, 2008, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $7 million and $6 million, respectively. Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.
PEPCO HOLDINGS
Pepco believes that a sharing of EDIT and ADITC 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. 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, 2008), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of December 31, 2008) 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.
As part of the proposal filed with the DCPSC in November 2008 concerning the sharing of the proceeds of the Mirant settlement, as discussed above under “Proceeds from Settlement of Mirant Bankruptcy Claims,” Pepco again requested that the DCPSC rule on all of the issues related to the divestiture of Pepco’s generating assets that remain outstanding. On December 12, 2008, the DCPSC issued a Notice of Proposed Rulemaking, which gave notice of Pepco’s November 2008 sharing of proceeds filing and requested comments. The public comment period for the proposed rules has expired without any comments being submitted. This matter remains pending before the DCPSC.
Pepco believes that its calculation of the District of Columbia customers’ share of divestiture proceeds is correct. However, depending on the ultimate outcome of this proceeding, Pepco could be required to make additional gain-sharing payments to District of Columbia customers, including the payments described above related to EDIT and ADITC. Such additional payments (which, other than the EDIT and ADITC related payments, cannot be estimated) would be charged to expense in the quarter and year in which a final decision is rendered and could have a material adverse effect on Pepco’s and PHI’s results of operations for those periods. However, neither PHI nor Pepco believes that additional gain-sharing payments, if any, or the ADITC-related payments to the IRS, if required, would have a material adverse impact on its financial position or cash flows.
Maryland
Pepco filed its divestiture proceeds plan application with the MPSC in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been
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raised in the District of Columbia case. See the discussion above under “Divestiture Cases - District of Columbia.” As of December 31, 2008, the Maryland allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $9 million and $10 million, respectively. Other issues deal with the treatment of certain costs as deductions from the gross proceeds of the divestiture. In November 2003, the Hearing Examiner in the Maryland proceeding issued a proposed order with respect to the application that concluded that Pepco’s Maryland divestiture settlement agreement provided for a sharing between Pepco and customers of the EDIT and ADITC associated with the sold assets. Pepco believes that such a sharing would violate the normalization rules (as discussed above) and would result in Pepco’s inability to use accelerated depreciation on Maryland allocated or assigned property. If the proposed order is affirmed, Pepco would have to share with its Maryland customers, on an approximately 50/50 basis, the Maryland allocated portion of the generation-related EDIT ($9 million as of December 31, 2008), and the Maryland-allocated portion of generation-related ADITC. Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco’s Maryland jurisdictional generation-related ADITC balance ($10 million as of December 31, 2008), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($6 million as of December 31, 2008), in each case as those balances exist as of the later of the date a MPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the MPSC order becomes operative. The Hearing Examiner decided all other issues in favor of Pepco, except for the determination that only one-half of the severance payments that Pepco included in its calculation of corporate reorganization costs should be deducted from the sales proceeds before sharing of the net gain between Pepco and customers.
In December 2003, Pepco appealed the Hearing Examiner’s decision to the MPSC as it relates to the treatment of EDIT and ADITC and corporate reorganization costs. The MPSC has not issued any ruling on the appeal, pending completion of the IRS rulemaking regarding sharing of EDIT and ADITC related to divested assets. Pepco made a filing in April 2008, advising the MPSC of the adoption of the final IRS normalization regulations (described above under “Divestiture Cases - District of Columbia”) and requesting that the MPSC issue a ruling on the appeal consistent with the IRS position. If the MPSC issues the requested ruling, no accounting adjustments to the gain recorded in 2000 would be required. However, depending on the ultimate outcome of this proceeding, Pepco could be required to share with its customers approximately 50 percent of the EDIT and ADITC balances described above in addition to the additional gain-sharing payments relating to the disallowed severance payments. Such additional payments would be charged to expense in the quarter and year in which a final decision is rendered and could have a material adverse effect on Pepco’s and PHI’s results of operations for those periods. However, neither PHI nor Pepco believes that additional gain-sharing payments, if any, or the ADITC-related payments to the IRS, if required, would have a material adverse impact on its financial position or cash flows.
As part of the proposal filed with the MPSC in November 2008 concerning the sharing of the proceeds of the Mirant settlement, as discussed above under “Proceeds from Settlement of Mirant Bankruptcy Claims,” Pepco again requested that the MPSC rule on all of the issues related to the divestiture of Pepco’s generating assets that remain outstanding.
On February 17, 2009, Pepco, the Maryland OPC and the MPSC staff filed a settlement agreement with the MPSC. The settlement agreement, among other things, provides that Pepco will be allowed to retain the EDIT and ADITC reserves associated with Pepco’s divested
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generating assets and that none of those amounts will be available for sharing with Pepco’s Maryland customers. The matter is pending before the MPSC.
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. RC Cape May has commenced an arbitration proceeding against Citgo seeking a determination that the TSA remains in effect and has notified ACE of the proceeding. The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo. While ACE believes that it has defenses to the indemnification claim, should the arbitrator rule that the TSA has terminated, the outcome of this matter is uncertain. ACE notified RC Cape May of its intent to participate in the pending arbitration. The arbitration hearings were conducted in November 2008. A decision is expected late in the second quarter of 2009, after the filing of post-hearing memoranda in the first quarter of 2009.
DPL 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 to A&N Electric Cooperative (A&N) for a purchase price of approximately $49 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5 million, after closing adjustments. Each of A&N and ODEC assumed certain post-closing liabilities and unknown pre-closing liabilities related to the respective assets they purchased (including, in the A&N transaction, most environmental liabilities). A&N delayed final payment of approximately $3 million, which was due on June 2, 2008, due to a dispute in the final true-up amounts. On October 21, 2008, DPL and A&N entered into a Settlement Agreement pursuant to which A&N paid $3 million to DPL, and an additional $1 million was distributed to DPL pursuant to an escrow agreement.
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,
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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, 2008, 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 position, 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 position, results of operations or cash flows.
Cash Balance Plan Litigation
In 1999, Conectiv established a cash balance retirement plan to replace defined benefit retirement plans then maintained by ACE and DPL. Following the acquisition by Pepco of Conectiv, this plan became the Conectiv Cash Balance Sub-Plan within the PHI Retirement Plan. In September 2005, three management employees of PHI Service Company filed suit in the U.S. District Court for the District of Delaware (the Delaware District Court) against the PHI Retirement Plan, PHI and Conectiv (the PHI Parties), alleging violations of ERISA, on behalf of a class of management employees who did not have enough age and service when the Cash Balance Sub-Plan was implemented in 1999 to assure that their accrued benefits would be calculated pursuant to the terms of the predecessor plans sponsored by ACE and DPL. A fourth plaintiff was added to the case to represent DPL-legacy employees who were not eligible for grandfathered benefits.
The plaintiffs challenged the design of the Cash Balance Sub-Plan and sought a declaratory judgment that the Cash Balance Sub-Plan was invalid and that the accrued benefits of each member of the class should be calculated pursuant to the terms of the predecessor plans. Specifically, the complaint alleged that the use of a variable rate to compute the plaintiffs’ accrued benefit under the Cash Balance Sub-Plan resulted in reductions in the accrued benefits that violated ERISA. The complaint also alleged that the benefit accrual rates and the minimal accrual requirements of the Cash Balance Sub-Plan violated ERISA as did the notice that was given to plan participants upon implementation of the Cash Balance Sub-Plan.
In September 2007, the Delaware District Court issued an order granting summary judgment in favor of the PHI Parties. In October 2007, the plaintiffs filed an appeal of the decision to the U.S. Court of Appeals for the Third Circuit (the Third Circuit). In November 2008, the Third Circuit affirmed the Delaware District Court ruling. On December 16, 2008, the Third Circuit denied a petition for rehearing filed by the plaintiffs. Plaintiffs have until March 23, 2009, to petition the U.S. Supreme Court for review of the Third Circuit decision.
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If the plaintiffs were to prevail in this litigation, the ABO and projected benefit obligation (PBO) calculated in accordance with SFAS No. 87 each would increase by approximately $12 million, assuming no change in benefits for persons who have already retired or whose employment has been terminated and using actuarial valuation data as of the time the suit was filed. The ABO represents the present value that participants have earned as of the date of calculation. This means that only service already worked and compensation already earned and paid is considered. The PBO is similar to the ABO, except that the PBO includes recognition of the effect that estimated future pay increases would have on the pension plan obligation.
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.
Metal Bank/Cottman Avenue Site. In the early 1970s, both Pepco and DPL sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In 1987, Pepco and DPL were notified by the EPA that they, along with a number of other utilities and non-utilities, were potentially responsible parties (PRPs) in connection with the PCB contamination at the site.
In 1997, the EPA issued a Record of Decision that set forth a remedial action plan for the site with estimated implementation costs of approximately $17 million. In May 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In October 2003, the bankruptcy court confirmed a reorganization plan that incorporates the terms of a settlement among the two debtor owner/operator entities, the United States and a group of utility PRPs including Pepco (the Utility PRPs). Under the bankruptcy settlement, the reorganized entity/site owner will pay a total of approximately $13 million to remediate the site (the Bankruptcy Settlement).
In March 2006, the U.S. District Court for the Eastern District of Pennsylvania approved global consent decrees for the Metal Bank/Cottman Avenue site, entered into on August 23, 2005, involving the Utility PRPs, the U.S. Department of Justice, EPA, The City of Philadelphia and two owner/operators of the site. Under the terms of the settlement, the two owner/operators will make payments totaling approximately $6 million to the U.S. Department of Justice and totaling approximately $4 million to the Utility PRPs. The Utility PRPs will perform the remedy at the site and will be able to draw on the approximately $13 million from the Bankruptcy Settlement to accomplish the remediation (the Bankruptcy Funds). The Utility PRPs will contribute funds to the extent remediation costs exceed the Bankruptcy Funds available. The Utility PRPs also will be liable for EPA costs associated with overseeing the monitoring and
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operation of the site remedy after the remedy construction is certified to be complete and also the cost of performing the “5 year” review of site conditions required by the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Any Bankruptcy Funds not spent on the remedy may be used to cover the Utility PRPs’ liabilities for future costs. No parties are released from potential liability for damages to natural resources.
As of December 31, 2008, Pepco had accrued approximately $2 million to meet its liability for a remedy at the Metal Bank/Cottman Avenue site. While final costs to Pepco of the settlement have not been determined, Pepco believes that its liability at this site will not have a material adverse effect on its financial position, results of operations or cash flows.
In 1999, DPL entered into a de minimis settlement with the EPA and paid less than a million dollars to resolve its liability for cleanup costs at the Metal Bank/Cottman Avenue site. The de minimis settlement did not resolve DPL’s responsibility for natural resource damages, if any, at the site. DPL believes that any liability for natural resource damages at this site will not have a material adverse effect on its financial position, results of operations or cash flows.
Delilah Road Landfill Site. In 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a 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. 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. 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 filed a proof of claim in the Lenox bankruptcy case in February 2009. 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.
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. ACE believes that its responsibility at the site will not have a material adverse effect on its financial position, results of operations or cash flows.
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Franklin Slag Pile Superfund Site. On November 26, 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile Superfund 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 the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA’s letter also states that to date its 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, such 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 such claims made by the EPA. At this time ACE cannot predict how EPA will proceed or what portion, if any, of the Franklin Slag Pile Site response costs EPA would seek to recover from ACE.
Deepwater Generating Station Revocation Order. In December 2005, NJDEP issued a Title V operating permit (the 2005 Permit) to Deepwater Generating Station (Deepwater) owned by Conectiv Energy. Conectiv Energy appealed several provisions of the 2005 Permit and a revised Title V operating permit issued in 2008 (the 2008 Permit). Administrative litigation concerning the provisions of the operating permit is ongoing. In February 2008, NJDEP issued an Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment (the First Revocation Order) revoking the Deepwater operating permit. The First Revocation Order is based on the NJDEP’s contention that Deepwater Unit 6/8 operated in violation of its emission limit for hydrogen chloride (HCl) and total suspended particles (TSP) during a December 2007 stack test. The First Revocation Order also assessed a $20,000 penalty for the HCl incident and a $10,000 penalty for the TSP incident. Conectiv Energy has filed an appeal of both the revocation order and the penalty with the Office of Administrative Law. Subsequent stack tests have confirmed that Unit 6/8 complies with its TSP emission limit and Conectiv Energy and NJDEP entered into a settlement agreement that resolves the $10,000 penalty for TSP from the First Order.
In July 2008, NJDEP issued an Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment (the Second Revocation Order) revoking the Deepwater operating permit. The Second Revocation Order is based on the NJDEP’s contention that Deepwater Unit 6/8 operated in violation of its emission limit for particulate matter less than 10 microns (PM-10) during the December 2007 stack test. The Second Revocation Order also assessed a penalty for the incident in the amount of $10,000. Conectiv Energy has filed an appeal of both the revocation order and the penalty with the Office of Administrative Law. NJDEP has issued a letter stating that elevated PM-10 levels indicated during the July 2008 stack
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test were the result of laboratory error. Subsequent stack testing has shown that Unit 6/8 complies with its PM-10 emission limit.
In September 2008, NJDEP issued an additional and separate Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment (the Third Revocation Order) requiring Conectiv Energy to operate Deepwater Unit 6/8 in compliance with its HCl limit or in the alternative revoking Unit 6/8’s operating permit effective October 21, 2008. The Third Revocation Order is based on the NJDEP’s contention that Unit 6/8 violated the HCl limit on 106 days between December 5, 2007 and April 24, 2008 stack tests. The Third Revocation Order assessed a penalty in the amount of $5.3 million. Conectiv Energy has appealed both the revocation order and the penalty with the Office of Administrative Law. The effectiveness of the three revocation orders has been stayed by the NJDEP through February 28, 2009. On February 23, 2009, NJDEP extended the stay of the three revocation orders until May 28, 2009.
Conectiv Energy is operating Deepwater 6/8 while firing coal at a reduced load, or at full load with lime injection, to comply with the challenged HCl permit limit at all potential coal chloride contents. Operation with lime injection was authorized by the Environmental Improvement Pilot Test permit issued by NJDEP in September 2008, which facilitates assessment of the feasibility and practicality of hydrated lime injection technology in controlling HCl emissions from Unit 6/8 at full load without significantly impacting boiler operations. Testing indicates that hydrated lime injection technology effectively controls HCl emissions without significantly impacting boiler operations and without affecting Conectiv Energy’s ability to meet emissions limits for other parameters. Conectiv Energy has not yet determined the costs of converting the hydrated lime injection from a temporary pollution control device to a permanent pollution control device.
Conectiv Energy believes that it has strong legal arguments that NJDEP cannot revoke the permit prior to an administrative hearing and believes that the probability of a complete shut-down of the unit is low because the unit appears to be in compliance with the HCl limit. In addition, Conectiv Energy believes that its appeal asserts strong arguments against the assessment of the $5.3 million penalty.
Appeal of Delaware Multi-Pollutant Regulations. In November 2006, Delaware Department of Natural Resources and Environmental Control (DNREC) adopted multi-pollutant regulations to require large coal-fired and residual oil-fired electric generating units to develop control strategies to address air quality in Delaware. 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 nitrogen oxide, sulfur dioxide (SO2) and mercury emission reduction requirements required by the regulations 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. In addition, DNREC has agreed to increase the annual SO2 mass emission limit as it relates to the Edge Moor residual oil-fired generating unit.
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, which took effect November 5, 2007, impose a new regulatory program to
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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 and that is otherwise regulated under a number of other state and federal programs. ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey on November 3, 2008. See Item I “Business - Environmental Matters- Air Quality Regulation - Sulfur Dioxide, Nitrogen Oxide, Mercury and Nickel Emissions.”
IRS Examination of Like-Kind Exchange Transaction
In 2001, Conectiv and certain of its subsidiaries (the Conectiv Group) were engaged in the implementation of a strategy to divest non-strategic electric generating facilities and replace these facilities with mid-merit electric generating capacity. As part of this strategy, the Conectiv Group exchanged its interests in two older coal-fired plants for the more efficient gas-fired Hay Road II generating facility owned by an unaffiliated third party. For tax purposes, Conectiv treated the transaction as a “like-kind exchange” under IRC Section 1031. As a result, approximately $88 million of taxable gain was deferred for federal income tax purposes.
The transaction was examined by the IRS as part of the normal Conectiv tax audit. In May 2006, the IRS issued a revenue agent’s report (RAR) for the audit of Conectiv’s 2000, 2001 and 2002 income tax returns, in which the IRS disallowed the qualification of the transaction as an exchange under IRC Section 1031. In July 2006, Conectiv filed a protest of this disallowance to the U.S. Office of Appeals of the IRS (Appeals Office).
In October 2008, Conectiv and the IRS agreed on a settlement under which Conectiv will pay approximately $2 million of tax and $1 million of interest (pre-tax) representing tax and interest due for the years settled with the IRS. PHI will recover the payment of this tax through additional tax depreciation deductions over the remaining tax life of the facility. PHI’s reserve on this issue was more conservative than the actual settlement with the IRS. As a result, PHI reversed a total of $5 million (after-tax) in excess accrued interest in the fourth quarter of 2008.
PHI’s Cross-Border Energy Lease Investments
Between 1994 and 2002, Potomac Capital Investment Corporation (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. Prior to the reassessment discussed below, PHI had historically derived approximately $74 million per year in tax benefits from these eight cross-border energy lease investments (reflecting 100% of the tax benefits) to the extent that rental income under the leases is exceeded by the depreciation deductions on the purchase price of the assets and interest deductions on the non-recourse debt financing (obtained by PCI to fund a substantial portion of the purchase price of the assets). PHI’s annual tax benefits are now approximately $56 million after giving effect to the reassessment. As of December 31, 2008, PHI’s equity investment in its cross-border energy leases was approximately $1.3 billion which included the impact of the reassessment discussed below. During the period from January 1, 2001 to December 31, 2008, PHI has derived approximately $461 million in federal income tax benefits from the depreciation
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and interest deductions in excess of rental income with respect to these cross-border energy lease investments, which includes the effect of the reassessment discussed below.
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 RAR issued in June 2006 in connection with the audit of PHI’s 2001 and 2002 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to six of 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 is protesting the IRS adjustments and the unresolved audit issues have been forwarded to the Appeals Office. PHI is in the early stages of discussions with the Appeals Office. If these discussions are unsuccessful, PHI currently intends to pursue litigation proceedings against the IRS to defend its tax position. While the audits of PHI’s federal income tax returns for subsequent tax years are ongoing or have not yet commenced, PHI anticipates that the IRS will take the same position with respect to each of the subsequent years on all eight of its cross-border energy lease investments.
In the last several years, IRS challenges to certain cross-border lease transactions have been the subject of litigation. This litigation has resulted in several decisions in favor of the IRS, including two decisions in the second quarter of 2008. In one of the cases decided in the second quarter relating to a lease-in/lease-out transaction, a United States Court of Appeals upheld a lower court decision in favor of the IRS to disallow the tax benefits taken by the taxpayer. In the second case, a United States District Court rendered an opinion concerning a SILO transaction in which it upheld the IRS’s disallowance of tax benefits taken by the taxpayer. Under FIN 48, “Accounting for Uncertainty in Income Taxes,” the financial statement recognition of an uncertain tax position is permitted only if it is more likely than not that the position will be sustained. Further, under FSP 13-2, “Accounting for a Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged-lease Transaction,” a company 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, the company 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 is appropriate based on applicable statutes, regulations and case law, after evaluating the court rulings described above, 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 the following components:
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A non-cash pre-tax charge of $124 million ($86 million after tax) under FSP 13-2 to reduce the equity value of these cross-border energy lease investments. This
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pre-tax charge has been recorded in the Consolidated Statement of Earnings as a reduction in other operating revenue.
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A non-cash charge of $7 million after-tax to reflect the anticipated additional interest expense under FIN 48 on the estimated federal and state income tax that would be payable for the period January 1, 2001 through June 30, 2008, based on the revised assumptions regarding the estimated timing of the tax benefits. This after-tax charge has been recorded in the Consolidated Statement of Earnings as an increase in income tax expense.
The charge pursuant to FSP 13-2 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. This amount will be recognized as income over the remaining term of the affected leases, which expire between 2017 and 2047. 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. Consistent with the revised assumptions regarding the estimated timing of the tax benefits, PHI reduced the tax benefits recorded on its 2007 tax return filed in September 2008 and accordingly paid additional federal and state income taxes. Other than these payments made with the 2007 tax return and estimated tax payments made in 2008 associated with the reduced tax benefits, 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 an additional payment, and the amount and the timing thereof, will depend on a number of factors, including PHI’s litigation strategy, whether a settlement with the IRS can be reached or whether the company decides to deposit funds with the IRS to avoid higher interest costs, until the issue is resolved. PHI is continuing to defend vigorously its tax position with the IRS.
In connection with the recording of the above adjustment, PHI calculated as of June 30, 2008, the additional non-cash charge to earnings that would have been recorded resulting from the disallowance of the entire amount of the tax benefits from the depreciation and interest deductions in excess of rental income and the recharacterization of the transactions as loans over the period from January 1, 2001 through the end of the lease term. PHI would have incurred an additional non-cash charge to earnings at June 30, 2008 of approximately $346 million consisting of:
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A non-cash charge of $324 million ($293 million after tax) under FSP 13-2 to further reduce the equity value of these cross-border energy lease investments.
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A non-cash charge of $53 million after-tax to reflect the anticipated additional interest expense under FIN 48 on the estimated federal and state income tax for the period from January 1, 2001 through June 30, 2008.
As of December 31, 2008, no changes in the assumptions have occurred that would materially impact these estimates.
In the event of the total disallowance of the tax benefits and the imputing of original issue discount income due to the recharacterization of the leases as loans, PHI would have been obligated to pay, as of December 31, 2008, approximately $520 million in additional federal and
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state taxes and $83 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 recharacterization of the leases as loans would be recoverable in the form of lower taxes over the remaining term of the investments.
On August 7, 2008, PHI received a global settlement offer from the IRS with respect to its SILO transactions. PHI is continuing its discussion with the Appeals Office and has not responded to the global settlement offer.
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. Through December 31, 2005, these accelerated deductions 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) for the companies, primarily attributable to their 2001 tax returns.
In 2005, the Treasury Department issued proposed regulations that, if adopted in their current form, would require Pepco, DPL, and ACE to change their method of accounting with respect to capitalizable construction costs for income tax purposes for tax periods beginning in 2005. Based on those proposed regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believed would be acceptable to the IRS.
At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which was intended to limit the ability of certain taxpayers to utilize the method of accounting for income tax purposes they utilized on their tax returns for 2004 and prior years with respect to capitalizable construction costs. In line with this Revenue Ruling, the IRS revenue agent’s report 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 by requiring the companies to capitalize and depreciate certain expenses rather than treat such expenses as current deductions. PHI’s protest of the IRS adjustments is among the unresolved audit matters relating to the 2001 and 2002 audits pending before the U.S. Office of Appeals of the IRS.
In February 2006, PHI paid approximately $121 million of taxes to cover the amount of additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, adopted on its 2005 tax return. In June 2008, PHI received from the IRS an offer of settlement pertaining to each of Pepco, DPL and ACE for the tax years 2001 through 2004. PHI is substantially in agreement with this proposed settlement. Based on the terms of the proposal, PHI expects the final settlement amount to be less than the $121 million previously deposited.
On the basis of the tentative settlement, PHI updated its estimated liability related to mixed service costs and as a result, recorded in the quarter ended June 30, 2008, a net reduction in its liability for unrecognized tax benefits of $19 million and recognized after-tax interest income of $7 million.
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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.
As of December 31, 2008, 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, 2008, obligations under the guarantees were approximately $7 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 payment being required under the guarantee is remote.
(c)
Other guarantees consist of:
·
Pepco Holdings has guaranteed a subsidiary building lease of $2 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.
·
PCI has guaranteed facility rental obligations related to contracts entered into by Starpower Communications LLC, a joint venture in which PCI, prior to December 2004, had a 50% interest. As of December 31, 2008, the guarantees cover the remaining $1 million in rental obligations.
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.
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Dividends
On January 22, 2009, the Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2009 to shareholders of record on March 10, 2009.
Contractual Obligations
As of December 31, 2008, Pepco Holdings’ contractual obligations under non-derivative fuel and purchase power contracts were $3,211 million in 2009, $2,902 million in 2010 to 2011, $729 million in 2012 to 2013, and $2,225 million in 2014 and after.
(17) USE OF DERIVATIVES IN ENERGY AND INTEREST RATE HEDGING ACTIVITIES
PHI’s Competitive Energy businesses use 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 businesses include forward contracts, futures, swaps, and exchange-traded and over-the-counter options. In addition, the Competitive Energy businesses also manage commodity risk with contracts that are not classified as derivatives. The two primary risk management objectives are (i) 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 (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 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 resale. Conectiv Energy also purchases 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 quantitative limits 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 physical fuel inventory. Some forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and sale accounting under SFAS No. 133.
Pepco Energy Services purchases 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. Option contracts are marked-to-market through current earnings. Forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and sale accounting under SFAS No. 133.
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
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businesses. In June 2002, PHI entered into several treasury lock transactions in anticipation of the issuance of several series of fixed rate debt commencing in July 2002.
Cash Flow Hedges
The table below provides detail on effective cash flow hedges under SFAS No. 133 included in PHI’s Consolidated Balance Sheet as of December 31, 2008. Under SFAS No. 133, cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to Accumulated Other Comprehensive Income. The data in the table indicates the magnitude of the effective cash flow hedges by hedge type (i.e., energy commodity and interest rate hedges), maximum term, and portion expected to be reclassified to earnings during the next 12 months.
(a)
Accumulated Other Comprehensive Income 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.
The following table shows the pre-tax gain (loss) recognized in earnings for cash flow hedge ineffectiveness for the years ended December 31, 2008, 2007 and 2006, respectively, and where they were reported in PHI’s Consolidated Statements of Earnings during the periods.
For the years ended December 31, 2008, 2007 and 2006, $1 million, $2 million and zero, respectively, in losses were reclassified from Other Comprehensive Income to earnings because the forecasted hedged transactions were deemed no longer probable.
Fair Value Hedges
In connection with their energy commodity activities, the Competitive Energy businesses designate 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 loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings.
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The net pre-tax gains (losses) recognized during the twelve months ended December 31, 2008, 2007 and 2006 included in the Consolidated Statements of Earnings for fair value hedges and the associated hedged items are shown in the following table:
Other Derivative Activity
In connection with their energy commodity activities, the Competitive Energy businesses hold certain derivatives that do not qualify as hedges. Under SFAS No. 133, these derivatives are recorded at fair value through earnings with corresponding adjustments on the balance sheet.
The pre-tax gains (losses) on these derivatives are included in “Competitive Energy Operating Revenues” and are summarized in the following table:
(a)
There were no ineffective fair value hedge gains for the years ended December 31, 2008, 2007 and 2006, respectively.
As indicated in Note (3), PHI 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 net derivative positions is as follows:
As of December 31, 2008 and 2007, PHI had no cash collateral pledged or received related to derivatives accounted for at fair value that was not eligible for offset under master netting arrangements.
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(18) ACCUMULATED OTHER COMPREHENSIVE LOSS
A detail of the components of Pepco Holdings’ Accumulated Other Comprehensive (Loss) Earnings is as follows. For additional information, see the Consolidated Statements of Comprehensive Earnings.
A detail of the income tax (benefit) expense allocated to the components of Pepco Holdings’ Other Comprehensive (Loss) Earnings for each year is as follows.
(a)
Represents the income tax benefit on an adjustment for nonqualified pension plan minimum liability.
(b)
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 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 $7 million of after-tax net interest income on uncertain tax positions primarily related to casualty losses.
(b)
Includes a $124 million charge ($86 million after-tax) related to the adjustment to the equity value of cross-border energy lease investments under FSP 13-2.
(c)
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.
(d)
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.
(e)
Includes a $9 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.
(f)
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.
(g)
Includes adjustment related to timing of recognition of certain operating expenses which were overstated by $5 million in the fourth quarter and understated by $1 million and $4 million in the second and third quarters, respectively.
(h)
Includes adjustment related to timing of recognition of certain operating revenues which were overstated by $2 million in the third quarter and understated by $2 million in the fourth quarter.
(i)
Includes $33 million benefit ($20 million after-tax) from settlement of Mirant bankruptcy claims.
(j)
Includes $20 million benefit ($18 million net of fees) related to Maryland income tax refund.
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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. Because of 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, 2008 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 its internal control over financial reporting was effective as of December 31, 2008.
This Annual Report on Form 10-K does not include an attestation report of Pepco’s registered public accounting firm, PricewaterhouseCoopers LLP, regarding internal control over financial reporting. Management’s report was not subject to attestation by PricewaterhouseCoopers LLP pursuant to temporary rules of the Securities and Exchange Commission that permit Pepco to provide only management’s report in this Form 10-K.
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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 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, 2008 and December 31, 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008 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. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 11 to the financial statements, the company changed its manner of accounting and reporting for uncertain tax positions in 2007.
PricewaterhouseCoopers LLP
Washington, DC
March 2,
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The accompanying Notes are an integral part of these Financial Statements.
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The accompanying Notes are an integral part of these Financial Statements.
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The accompanying Notes are an integral part of these Financial Statements.
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The accompanying Notes are an integral part of these Financial Statements.
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The accompanying Notes are an integral part of these Financial Statements.
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The accompanying Notes are an integral part of these Financial Statements.
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NOTES TO FINANCIAL STATEMENTS
POTOMAC ELECTRIC POWER COMPANY
(1) ORGANIZATION
Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in Washington, D.C. 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).
The recent disruptions in the capital and credit markets have had an impact on Pepco’s business. While these conditions have required Pepco to make certain adjustments in its financial management activities, Pepco believes that it currently has sufficient liquidity to fund its operations and meet its financial obligations. These market conditions, should they continue, however, could have a negative effect on Pepco’s financial condition, results of operations and cash flows.
Liquidity Requirements
Pepco depends on access to the capital and credit markets to meet its liquidity and capital requirements. To meet its liquidity requirements, Pepco historically has relied on the issuance of commercial paper and short-term notes and on bank lines of credit to supplement internally generated cash from operations. Pepco’s primary credit source is PHI’s $1.5 billion syndicated credit facility, under which Pepco can borrow funds, obtain letters of credit and support the issuance of commercial paper in an amount up to $500 million (subject to the limitation that the total utilization by Pepco and PHI’s other utility subsidiaries cannot exceed $625 million). This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total commitment.
Due to the recent capital and credit market disruptions, the market for commercial paper was severely restricted for most companies. As a result, Pepco has not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that it typically has required for cash management purposes. Given its restricted access to the commercial paper market and the uncertainty in the credit markets generally, Pepco borrowed $100 million under the credit facility to create a cash reserve for future short-term operating needs at December 31, 2008. After giving effect to outstanding letters of credit and commercial paper, PHI’s utility subsidiaries have an aggregate of $843 million in combined cash and borrowing capacity under the credit facility at December 31, 2008. During the months of January and February 2009, the average daily amount of the combined cash and borrowing capacity of PHI’s utility subsidiaries was $831 million and ranged from a low of $673 million to a high of $1 billion.
To address the challenges posed by the current capital and credit market environment and to ensure that it will continue to have sufficient access to cash to meet its liquidity needs, Pepco has identified a number of cash and liquidity conservation measures, including opportunities to
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defer capital expenditures due to lower than anticipated growth. Several measures to reduce expenditures have been taken. Additional measures could be undertaken if conditions warrant.
Due to the financial market conditions, which have caused uncertainty of short-term funding, Pepco issued $250 million in long-term debt securities in December, with the proceeds used to refund short-term debt incurred to finance utility construction and operations on a temporary basis and incurred to fund the temporary repurchase of tax-exempt auction rate securities.
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 recent stock market declines have caused a decrease in the market value of benefit plan assets in 2008. Pepco expects to contribute approximately $170 million to the pension plan in 2009.
(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 resulted in lower depreciation expense of approximately $19 million for the last six months of 2007.
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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 $98 million and $82 million as of December 31, 2008 and 2007, 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 power 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.” 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 de minimis.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in Pepco’s gross revenues were $241 million, $243 million and $223 million for the years ended December 31, 2008, 2007 and 2006, 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 assets’ carrying amount exceeds their 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.
In 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). FIN 48 clarifies the
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criteria for recognition of tax benefits in accordance with Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes,” and prescribes a financial statement recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Specifically, it clarifies that an entity’s tax benefits must be “more likely than not” of being sustained prior to recording the related tax benefit in the financial statements. If the position drops below the “more likely than not” standard, the benefit can no longer be recognized. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.
On May 2, 2007, the FASB issued FASB Staff Position (FSP) FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48” (FIN 48-1), which provides 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 of FIN 48-1 with its adoption of FIN 48 on January 1, 2007.
The financial statements include current and deferred income taxes. Current income taxes represent the amounts 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 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 unrecognized tax benefits, and tax-related penalties in income tax expense.
Investment tax credits from utility plants purchased in prior years are reported on the Balance Sheets as Investment tax credits. These investment tax credits are being amortized to income over the useful lives of the related utility plant.
FIN 46R, “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 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 with the counterparty to the Panda PPA for the years ended December 31, 2008, 2007 and 2006, were approximately $59 million, $85 million and $79 million, respectively. See Note (13), “Commitments and Contingencies - Regulatory and Other Matters - Proceeds from Settlement of Mirant Bankruptcy Claims,” for additional information.
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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 to use 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 Statement of Earnings. 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 allowances 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 the new information is known.
Inventories
Included in inventories are generation, 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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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 is 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, the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 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.
As part of the new electric service distribution base rates for Pepco approved by the MPSC, effective in June 2007, the MPSC approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to which the BSA applies, Pepco recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA thus decouples 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 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 positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a negative Revenue Decoupling Adjustment is recorded as a regulatory liability. The net Revenue Decoupling Adjustment at December 31, 2008 is a regulatory asset and is included in the “Other” line item on the table of regulatory asset balances in Note (6), “Regulatory Assets and Regulatory Liabilities.”
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 under the provisions of SFAS No. 144. 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 Retirement Obligations” section included in this Note.
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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 2008, 2007, and 2006 for Pepco’s transmission and distribution system property were approximately 3%, 3%, and 4%, respectively.
Capitalized Interest and Allowance for Funds Used During Construction
In accordance with the provisions of SFAS No. 71, 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 Earnings.
Pepco recorded AFUDC for borrowed funds of $2 million, $5 million, and $1 million for the years ended December 31, 2008, 2007, and 2006, respectively.
Pepco recorded amounts for the equity component of AFUDC of $3 million for each of the years ended December 31, 2008 and 2007, and $2 million for the year ended December 31, 2006.
Leasing Activities
Pepco’s lease transactions can include office space, equipment, software and vehicles. In accordance with SFAS No. 13, “Accounting for Leases” (SFAS No. 13), these leases are classified as either capital leases or 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, Pepco’s policy is to recognize the increases 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 SFAS No. 71, the amortization of the leased asset is based on the rental payments recovered from customers. 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. Costs associated with the redemption of debt are also deferred and amortized over the lives of the new issues.
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Asset Removal Costs
In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” asset removal costs are recorded as regulatory liabilities. At December 31, 2008 and 2007, $107 million and $98 million, respectively, are reflected as 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 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 SFAS No. 87, “Employers’ Accounting for Pensions,” as amended by SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS No. 158), and its other postretirement benefits in accordance with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” as amended by SFAS No. 158. Pepco Holdings’ financial statement disclosures were prepared in accordance with SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” as amended by SFAS No. 158.
Pepco participates in benefit plans sponsored by Pepco Holdings and as such, the provisions of SFAS No. 158 do not have an impact on its financial condition and cash flows.
Dividend Restrictions
In addition to its future financial performance, the ability of Pepco to pay dividends is subject to limits imposed by: (i) state corporate and regulatory laws, which impose limitations on the funds that can be used to pay dividends and, in the case of regulatory laws, may require the prior approval of Pepco’s utility regulatory commissions before dividends can be paid 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 $125 million and $75 million of restricted retained earnings at December 31, 2008 and 2007, respectively.
Reclassifications and Adjustments
Certain prior year amounts have been reclassified in order to conform to current year presentation.
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, which were not considered material either individually or in the aggregate,
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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
Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS No. 157)
SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. Under SFAS No. 157, 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 in the most advantageous market using the best available information. The provisions of SFAS No. 157 were effective for financial statements beginning January 1, 2008 for Pepco.
In February 2008, the FASB issued FSP 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” (FSP 157-1), that removed fair value measurement for the recognition and measurement of lease transactions from the scope of SFAS No. 157. The effective date of FSP 157-1 was for financial statement periods beginning January 1, 2008 for Pepco.
Also in February 2008, the FASB issued FSP 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2), which deferred the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually), until financial statement reporting periods beginning January 1, 2009 for Pepco.
Pepco applied the guidance of FSP No. 157-1 and FSP 157-2 with its adoption of SFAS No. 157. The adoption of SFAS 157 on January 1, 2008 did not result in a transition adjustment to beginning retained earnings and did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows. SFAS No. 157 also required new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value. This additional disclosure is provided in Note (12), “Fair Value Disclosures.” Pepco is currently evaluating the impact of FSP 157-2 and does not anticipate that the application of FSP 157-2 to its other non-financial assets and non-financial liabilities will materially affect its overall financial condition, results of operations, or cash flows.
In September 2008, the Securities and Exchange Commission and FASB issued guidance on fair value measurements, which was clarifies in October 2008 by the FASB in FSP 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active.” This guidance clarifies the application of SFAS No. 157 to assets in an inactive market and illustrates how to determine the fair value of a financial asset in an inactive market. The guidance was effective beginning with the September 30, 2008 reporting period for Pepco, and has not had a material impact on Pepco’s results.
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SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities-including an Amendment of FASB Statement No. 115” (SFAS No. 159)
SFAS No. 159 permits entities to elect to measure eligible financial instruments at fair value. SFAS No. 159 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. On January 1, 2008, Pepco elected not to apply the fair value option for its eligible financial assets and liabilities.
SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162)
In May 2008, the FASB issued SFAS No. 162, which identifies the sources of accounting principles and the hierarchy for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. Moving the GAAP hierarchy into the accounting literature directs the responsibility for applying the hierarchy to the reporting entity, rather than just to the auditors.
SFAS No. 162 was effective for Pepco as of November 15, 2008 and did not result in a change in accounting for Pepco. Therefore, the provisions of SFAS No. 162 did not have a material impact on Pepco’s overall financial condition, results of operations, cash flows and disclosure.
FSP FAS 133-1 and FIN 45-4, “Disclosure About Credit Derivatives and Certain Guarantees” (FSP FAS 133-1 and FIN 45-4)
In September 2008, the FASB issued FSP FAS 133-1 and FIN 45-4, which requires enhanced disclosures by entities that provide credit protection through credit derivatives (including embedded credit derivatives) within the scope of SFAS No. 133, and guarantees within the scope of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”
For credit derivatives, FSP FAS 133-1 and FIN 45-4 requires disclosure of the nature and fair value of the credit derivative, the approximate term, the reasons for entering the derivative, the events requiring performance, and the current status of the payment/performance risk. It also requires disclosures of the maximum potential amount of future payments without any reduction for possible recoveries under collateral provisions, recourse provisions, or liquidation proceeds. Pepco has not provided credit protection to others through the credit derivatives within the scope of SFAS No. 133.
For guarantees, FSP FAS 133-1 and FIN 45-4 requires disclosure on the current status of the payment/performance risk and whether the current status is based on external credit ratings or current internal groupings used to manage risk. If internal groupings are used, then information is required about how the groupings are determined and used for managing risk.
The new disclosures are required starting with financial statement reporting periods ending December 31, 2008 for Pepco. Comparative disclosures are only required for periods ending after initial adoption. The new guarantee disclosures did not have a material impact on Pepco.
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FSP FAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities” (FSP FAS 140-4 and FIN 46(R)-8)
In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8 to expand the disclosures under the original pronouncements. The disclosure requirements in SFAS No. 140 for transfers of financial assets are to include disclosure of (i) a transferor’s continuing involvement in transferred financial assets, and (ii) how a transfer of financial assets to a special-purpose entity affects an entity’s financial position, financial performance, and cash flows. The principal objectives of the disclosure requirements in Interpretation 46(R) are to outline (i) significant judgments in determining whether an entity should consolidate a variable interest entity (VIE), (ii) the nature of any restrictions on consolidated assets, (iii) the risks associated with the involvement in the VIE, and (iv) how the involvement with the VIE affects an entity’s financial position, financial performance, and cash flows.
FSP FAS 140-4 and FIN 46(R)-8 is effective for Pepco’s December 31, 2008 financial statements. This FSP has no material impact to Pepco’s overall financial condition, results of operations, or cash flows as it relates to SFAS No. 140. Pepco’s FIN 46(R) disclosures are provided in Note (2), “Significant Accounting Policies - FIN 46R, Consolidation of Variable Interest Entities.”
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
SFAS No. 141(R), “Business Combinations-a Replacement of FASB Statement No. 141” (SFAS No. 141 (R))
SFAS No. 141(R) replaces FASB Statement No. 141, “Business Combinations,” and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141 (R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require 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.
In January 2009, the FASB proposed FSP FAS 141(R)-a “Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP FAS 141(R)-a), to clarify the accounting on the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The FSP FAS 141(R)-a requires that assets acquired and liabilities assumed in a business combination that arise from contingences be measured at fair value in accordance with SFAS No. 157 if the acquisition date can be reasonably determined. If not, then the asset or liability would be measured at the amount in accordance with SFAS 5, “Accounting for Contingencies,” and FIN 14, “Reasonable Estimate of the Amount of Loss.”
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SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-a applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009 for Pepco. Pepco has evaluated the impact of SFAS No. 141(R) and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, or cash flows.
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an Amendment of ARB No. 51” (SFAS No. 160)
SFAS No. 160 establishes 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. It clarifies that a minority interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.
SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity, and presented separately on the face of the consolidated statement of income, (ii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.
SFAS No. 160 is effective prospectively for financial statement reporting periods beginning January 1, 2009 for Pepco, except for the presentation and disclosure requirements. The presentation and disclosure requirements apply retrospectively for all periods presented. Pepco has evaluated the impact of SFAS No. 160 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, cash flows or disclosure.
EITF Issue No. 08-6, “Equity Method Investment Accounting Consideration” (EITF 08-6)
In November 2008, the FASB issued EITF 08-6 to address 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 an equity method investee’s issuance of shares should be accounted for. The EITF concludes that initial carrying value of an equity method investment can be determined using the accumulation model in SFAS 141(R), “Business Combination (revised 2007),” and other-than-temporary impairments should be recognized in accordance with paragraph 19(h) of Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”
This EITF is effective for Pepco beginning January 1, 2009. Pepco is currently evaluating the impact on its accounting and disclosures.
FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP FAS 132(R)-1)
In December 2008, the FASB issued FSP FAS 132(R)-1 to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The required disclosures under this FSP would expand current disclosures under SFAS No.
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132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits-an amendment of FASB Statements No. 87, 88, and 106,” to be in line with SFAS No. 157 required disclosures.
The disclosures are to provide users an understanding of the investment allocation decisions made, factors used in the investment policies and strategies, plan assets by major investment types, inputs and valuation techniques used to measure fair value of plan assets, significant concentration of risk within the plan, and the effects of fair value measurement using significant unobservable inputs (Level 3 as defined in SFAS No. 157) on changes in plan assets for the period.
The new disclosures are required starting with financial statement reporting periods ending December 31, 2009 for Pepco and earlier application is permitted. Comparative disclosures under this provision are not required for earlier periods presented. Pepco is currently evaluating the impact on its disclosures.
(5) SEGMENT INFORMATION
In accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” Pepco has one segment, its regulated utility business.
(6) REGULATORY ASSETS AND REGULATORY LIABILITIES
The components of Pepco’s regulatory asset balances at December 31, 2008 and 2007 are as follows:
The components of Pepco’s regulatory liability balances at December 31, 2008 and 2007 are as follows:
A description of the regulatory assets and regulatory liabilities is as follows:
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Deferred Energy Supply Costs: The regulatory asset primarily represents deferred costs associated with a net under-recovery of Default Electricity Supply costs in Maryland. The regulatory liability primarily represents deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred in the District of Columbia. The Default Electricity Supply deferrals do not earn a return.
Deferred Income Taxes: Represents a receivable from our customers for tax benefits Pepco has previously flowed through before the company was ordered to provide deferred income taxes. As the temporary differences between the financial statement and tax basis of assets reverse, the deferred recoverable balances are reversed. There is no return 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 received on these deferrals.
Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years and generally do not receive a return.
Deferred Income Taxes Due to Customers: Represents the portion of deferred income tax liabilities applicable to Pepco’s utility operations that has not been reflected in current customer rates for which future payment to customers is probable. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return 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 their estimate of the difference between incurred removal costs and the level of removal costs recovered through rates.
Settlement proceeds - Mirant Bankruptcy Claims: In 2007, Pepco received $414 million of net proceeds from settlement of a Mirant Corporation (Mirant) 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 Energy Trading LLC (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. Pepco filed rate applications with the DCPSC and the MPSC in the fourth quarter of 2008 to provide for the disposition of the remaining funds. See Note (13), “Commitments and Contingencies - Proceeds From Settlement of Mirant Bankruptcy Claims” for additional information. Currently there is no return on these deferrals.
Other: Includes miscellaneous regulatory liabilities such as the over-recovery of administrative costs associated with Maryland and District of Columbia SOS. These regulatory liabilities generally do not receive a return.
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(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 $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 SFAS No. 71, 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.
Capital lease assets recorded within Property, Plant and Equipment at December 31, 2008 and 2007 are comprised of the following:
The approximate annual commitments under capital leases are $15 million for each year 2009 through 2013 and $92 million thereafter.
Rental expense for operating leases was $4 million for each of the years ended December 31, 2008, 2007 and 2006.
Total future minimum operating lease payments for Pepco as of December 31, 2008 are $3 million in 2009, $8 million in 2010, less than $1 million in each of the years 2011 through 2013, and $2 million after 2013.
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(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.
(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 2008, 2007, and 2006, Pepco was responsible for $24 million, $22 million and $32 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings. In 2008 and 2007, Pepco made no contributions to the PHI Retirement Plan, and $9 million and $10 million, respectively to other postretirement benefit plans. At December 31, 2008 and 2007, Pepco’s prepaid pension expense of $142 million and $152 million, and other postretirement benefit obligation of $49 million and $58 million, effectively represent assets and benefit obligations resulting from Pepco’s participation in the Pepco Holdings benefit plan. Pepco expects to contribute approximately $170 million to the pension plan in 2009.
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(10) DEBT
LONG-TERM DEBT
The components of long-term debt are shown below.
(a)
Represents a series of First Mortgage Bonds issued by Pepco 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 First Mortgage Bonds issued by Pepco as collateral for an outstanding series of senior notes as described in footnote (a) above that will, at such time as there are no First Mortgage Bonds of Pepco 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)
The insured auction rate tax exempt bonds were repurchased by Pepco at par due to the disruption in the credit markets. The bonds are considered extinguished for accounting purposes however Pepco intends to remarket or reissue the bonds to the public in 2009.
The outstanding First Mortgage Bonds are subject to a lien on substantially all of Pepco’s property, plant and equipment.
The aggregate principal amount of long-term debt outstanding at December 31, 2008, that will mature in each of 2009 through 2013 and thereafter is as follows: $50 million in 2009, $16 million in 2010, zero in 2011 and 2012, $200 million in 2013, and $1,238 million thereafter.
Pepco’s long-term debt is subject to certain covenants. Pepco is in compliance with all requirements.
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SHORT-TERM DEBT
Pepco, a regulated utility, 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, 2008 and 2007 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 a $500 million credit facility, described below under the heading “Credit Facility,” shared with PHI’s other utility subsidiaries, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE).
Pepco had no commercial paper outstanding at December 31, 2008 and $84 million of commercial paper outstanding at December 31, 2007. The weighted average interest rate for commercial paper issued during 2008 was 3.45% and 5.27% in 2007. The weighted average maturity for commercial paper issued during 2008 was two days and during 2007 was four days.
Bank Loan
In May 2008, Pepco obtained a $25 million bank loan that matures on April 30, 2009. Interest on the loan is calculated at a variable rate.
Credit Facility
PHI, Pepco, DPL and ACE maintain a credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under this primary 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.
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Any swingline loan must be repaid by the borrower within seven days of receipt thereof. All indebtedness incurred under the facility is unsecured.
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 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.
As a result of severe liquidity constraints in the credit, commercial paper and capital markets during 2008, Pepco borrowed under the $1.5 billion credit facility. Typically, Pepco issues commercial paper if required to meet its short-term working capital requirements. Given the lack of liquidity in the commercial paper markets, Pepco borrowed under the credit facility to maintain sufficient cash on hand to meet daily short-term operating needs. At December 31, 2008, Pepco had borrowed $100 million. The LIBOR-based loan matures in April 2009.
(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 as part of Pepco’s acquisition of Conectiv on August 1, 2002. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.
The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.
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Provision for Income Taxes
Reconciliation of Income Tax Rate
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 “Deferred tax adjustments” in the reconciliation provided above. In addition, during 2008 Pepco recorded after-tax net interest income of $5 million under FIN 48 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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FIN 48, “Accounting for Uncertainty in Income Taxes”
As disclosed in Note (2), “Significant Accounting Policies,” Pepco adopted FIN 48 effective January 1, 2007. Upon adoption, Pepco recorded the cumulative effect of the change in accounting principle of $2 million as a decrease in retained earnings. Also upon adoption, Pepco had $95 million of unrecognized tax benefits and $7 million of related accrued interest.
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, in accordance with FIN 48, 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, 2008, 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, 2008 and 2007, Pepco recognized $8 million of interest income before tax ($5 million after-tax) and $1 million of interest income before tax (less than $1 million after-tax), respectively, as a component of income tax expense. As of December 31, 2008 and 2007, Pepco had $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
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within the next 12 months upon final resolution of the tentative settlement with the IRS and the obligation becomes certain. 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 noted above.
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 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, 2008 and 2007.
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 normalized over the remaining service lives of the related assets.
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Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below. These amounts relate to the Power Delivery business and are recoverable through rates.
(12) FAIR VALUE DISCLOSURES
Effective January 1, 2008, Pepco adopted SFAS No. 157, as discussed earlier in Note (3), which established a framework for measuring fair value and expands disclosures about fair value measurements.
As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Pepco utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, Pepco utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Pepco is able to classify fair value balances based on the observability of those inputs. SFAS No. 157 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 defined by SFAS No. 157 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
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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 table 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, 2008. As required by SFAS No. 157, 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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A reconciliation of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (level 3) is shown below (in millions of dollars):
The estimated fair values of Pepco’s non-financial instruments at December 31, 2008 and 2007 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 for issues with no market price available, were based on discounted cash flows using current rates for similar issues with similar terms and remaining maturities.
(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
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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.
On September 5, 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. The use of the damages received from Mirant to offset above-market costs of energy and capacity under the Panda PPA and to make the payment to Sempra reduced the balance of proceeds from the Mirant settlement to approximately $102 million as of December 31, 2008.
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 previously approved by the respective commissions. Under Pepco’s proposals, District of Columbia and Maryland customers would receive a total of approximately $25 million and $29 million, respectively. On December 12, 2008, the DCPSC issued a Notice of Proposed Rulemaking concerning the sharing of the Mirant divestiture proceeds, including the bankruptcy settlement proceeds. The public comment period for the proposed rules has expired without any comments being submitted. This matter remains pending before the DCPSC.
On February 17, 2009, Pepco, the Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff filed a settlement agreement with the MPSC. The settlement, among other things, provides that of the remaining balance of the Mirant settlement, Pepco shall distribute $39 million to its Maryland customers through a one-time billing credit. If the settlement is approved by the MPSC, Pepco currently estimates that it will result in a pre-tax gain in the range of $15 million to $20 million, which will be recorded when the MPSC issues its final order approving the settlement.
Pending the final disposition of these funds, the remaining $102 million in proceeds from the Mirant settlement is being accounted for as restricted cash and as a regulatory liability.
Rate Proceedings
In the most recent electric service distribution base rate cases filed by Pepco in the District of Columbia and Maryland, Pepco proposed the adoption of a BSA for retail customers. As more fully discussed below, the implementation of a BSA has been approved for electric service in Maryland and remains pending in the District of Columbia. Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount. The BSA increases rates if actual distribution revenues fall below the level approved by the applicable commission and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, Pepco collects its authorized revenues
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for distribution deliveries. As a consequence, a BSA “decouples” revenue from unit sales consumption and ties the growth in 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 utility 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 delivery revenues.
District of Columbia
In December 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. In January 2008, the DCPSC approved, effective February 20, 2008, a revenue requirement increase of approximately $28 million, based on an authorized return on rate base of 7.96%, including a 10% return on equity (ROE). This increase did not include a BSA mechanism. While finding a BSA to be an appropriate ratemaking concept, the DCPSC cited potential statutory problems in its authority to implement the BSA. In February 2008, the DCPSC established a Phase II proceeding to consider these implementation issues. In August 2008, the DCPSC issued an order concluding that it has the necessary statutory authority to implement the BSA proposal and that further evidentiary proceedings are warranted to determine whether the BSA is just and reasonable. On January 2, 2009, the DCPSC issued an order designating the issues and establishing a procedural schedule for the BSA proceeding. Hearings are scheduled for the second quarter of 2009.
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 January 2008 order granting Pepco’s rate increase, 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 order denying its motion for reconsideration. The District of Columbia Court of Appeals granted the petition; briefs have been filed by the parties and oral argument is scheduled for March 2009.
Maryland
In July 2007, the MPSC issued an order in Pepco’s electric service distribution rate case, which included approval of a BSA. The order approved an annual increase in distribution rates of approximately $11 million (including a decrease in annual depreciation expense of approximately $31 million). The approved distribution rate reflects an ROE of 10%. The rate increases were effective as of June 16, 2007, and remained in effect for an initial period until July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of an audit of Pepco’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required. On July 18, 2008, the MPSC issued an order covering the Phase II proceedings, denying any further adjustment to Pepco’s rates, thus making permanent the rate increases approved in the July 2007 order. The MPSC also issued an order on August 4, 2008, further explaining its July 18 order.
Pepco has filed a general notice of appeal of the MPSC July 2007 and the July 18 and August 4, 2008 orders. The appeal challenges the MPSC’s failure to implement permanent rates in accordance with Maryland law, and seek judicial review of the MPSC’s denial of Pepco’s
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rights to recover an increased share of the PHI Service Company costs and the costs of performing a MPSC-mandated management audit. The case currently is pending before the Circuit Court for Baltimore City. Under the procedural schedule set by the court, Pepco will file a consolidated brief on or before March 9, 2009, specifying the basis for its requested relief.
Federal Energy Regulatory Commission
On August 18, 2008, Pepco submitted an application with the Federal Energy Regulatory Commission (FERC) for incentive rate treatments in connection with PHI’s 230-mile, 500-kilovolt Mid-Atlantic Power Pathway Project (the MAPP Project). The application requested that FERC include Pepco’s Construction Work in Progress in its transmission rate base, an ROE adder of 150 basis points (for a total ROE of 12.8%) and the recovery of prudently incurred costs in the event the project is abandoned or terminated for reasons beyond Pepco’s control. On October 31, 2008, FERC issued an order approving the application.
Divestiture Cases
District of Columbia
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, 2008, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $7 million and $6 million, respectively. Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.
Pepco believes that a sharing of EDIT and ADITC would violate the Internal Revenue Service (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. 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, 2008), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of December 31, 2008) 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
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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.
As part of the proposal filed with the DCPSC in November 2008 concerning the sharing of the proceeds of the Mirant settlement, as discussed above under “Proceeds from Settlement of Mirant Bankruptcy Claims,” Pepco again requested that the DCPSC rule on all of the issues related to the divestiture of Pepco’s generating assets that remain outstanding. On December 12, 2008, the DCPSC issued a Notice of Proposed Rulemaking, which gave notice of Pepco’s November 2008 sharing of proceeds filing and requested comments. The public comment period for the proposed rules has expired without any comments being submitted. This matter remains pending before the DCPSC.
Pepco believes that its calculation of the District of Columbia customers’ share of divestiture proceeds is correct. However, depending on the ultimate outcome of this proceeding, Pepco could be required to make additional gain-sharing payments to District of Columbia customers, including the payments described above related to EDIT and ADITC. Such additional payments (which, other than the EDIT and ADITC related payments, cannot be estimated) would be charged to expense in the quarter and year in which a final decision is rendered and could have a material adverse effect on Pepco’s and PHI’s results of operations for those periods. However, neither PHI nor Pepco believes that additional gain-sharing payments, if any, or the ADITC-related payments to the IRS, if required, would have a material adverse impact on its financial position or cash flows.
Maryland
Pepco filed its divestiture proceeds plan application with the MPSC in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case. See the discussion above under “Divestiture Cases - District of Columbia.” As of December 31, 2008, the Maryland allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $9 million and $10 million, respectively. Other issues deal with the treatment of certain costs as deductions from the gross proceeds of the divestiture. In November 2003, the Hearing Examiner in the Maryland proceeding issued a proposed order with respect to the application that concluded that Pepco’s Maryland divestiture settlement agreement provided for a sharing between Pepco and customers of the EDIT and ADITC associated with the sold assets. Pepco believes that such a sharing would violate the normalization rules (as discussed above) and would result in Pepco’s inability to use accelerated depreciation on Maryland allocated or assigned property. If the proposed order is affirmed, Pepco would have to share with its Maryland customers, on an approximately 50/50 basis, the Maryland allocated portion of the generation-related EDIT ($9 million as of December 31, 2008), and the Maryland-allocated portion of generation-related ADITC. Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco’s Maryland jurisdictional generation-related ADITC balance ($10 million as of December 31, 2008), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($6 million as of December 31, 2008), in each case as those balances exist as of the later
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of the date a MPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the MPSC order becomes operative. The Hearing Examiner decided all other issues in favor of Pepco, except for the determination that only one-half of the severance payments that Pepco included in its calculation of corporate reorganization costs should be deducted from the sales proceeds before sharing of the net gain between Pepco and customers.
In December 2003, Pepco appealed the Hearing Examiner’s decision to the MPSC as it relates to the treatment of EDIT and ADITC and corporate reorganization costs. The MPSC has not issued any ruling on the appeal, pending completion of the IRS rulemaking regarding sharing of EDIT and ADITC related to divested assets. Pepco made a filing in April 2008, advising the MPSC of the adoption of the final IRS normalization regulations (described above under “Divestiture Cases - District of Columbia”) and requesting that the MPSC issue a ruling on the appeal consistent with the IRS position. If the MPSC issues the requested ruling, no accounting adjustments to the gain recorded in 2000 would be required. However, depending on the ultimate outcome of this proceeding, Pepco could be required to share with its customers approximately 50 percent of the EDIT and ADITC balances described above in addition to the additional gain-sharing payments relating to the disallowed severance payments. Such additional payments would be charged to expense in the quarter and year in which a final decision is rendered and could have a material adverse effect on Pepco’s and PHI’s results of operations for those periods. However, neither PHI nor Pepco believes that additional gain-sharing payments, if any, or the ADITC-related payments to the IRS, if required, would have a material adverse impact on its financial position or cash flows.
As part of the proposal filed with the MPSC in November 2008 concerning the sharing of the proceeds of the Mirant settlement, as discussed above under “Proceeds from Settlement of Mirant Bankruptcy Claims,” Pepco again requested that the MPSC rule on all of the issues related to the divestiture of Pepco’s generating assets that remain outstanding.
On February 17, 2009, Pepco, the Maryland OPC and the MPSC staff filed a settlement agreement with the MPSC. The settlement agreement, among other things, provides that Pepco will be allowed to retain the EDIT and ADITC reserves associated with Pepco’s divested generating assets and that none of those amounts will be available for sharing with Pepco’s Maryland customers. The matter is pending before the MPSC.
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
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approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of December 31, 2008, 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 position, 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 position, results of operations or 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.
Metal Bank/Cottman Avenue Site. In the early 1970s, Pepco sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In 1987, Pepco was notified by the United States Environmental Protection Agency (EPA) that it, along with a number of other utilities and non-utilities, was a potentially responsible party (PRP) in connection with the PCB contamination at the site.
In 1997, the EPA issued a Record of Decision that set forth a remedial action plan for the site with estimated implementation costs of approximately $17 million. In May 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In October 2003, the bankruptcy court confirmed a reorganization plan that incorporates the terms of a settlement among the two debtor owner/operator entities, the United States and a group of utility PRPs including Pepco (the Utility PRPs). Under the bankruptcy settlement, the reorganized entity/site owner will pay a total of approximately $13 million to remediate the site (the Bankruptcy Settlement).
In March 2006, the U.S. District Court for the Eastern District of Pennsylvania approved global consent decrees for the Metal Bank/Cottman Avenue site, entered into on August 23, 2005, involving the Utility PRPs, the U.S. Department of Justice, EPA, The City of Philadelphia and two owner/operators of the site. Under the terms of the settlement, the two owner/operators
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will make payments totaling approximately $6 million to the U.S. Department of Justice and totaling approximately $4 million to the Utility PRPs. The Utility PRPs will perform the remedy at the site and will be able to draw on the approximately $13 million from the Bankruptcy Settlement to accomplish the remediation (the Bankruptcy Funds). The Utility PRPs will contribute funds to the extent remediation costs exceed the Bankruptcy Funds available. The Utility PRPs also will be liable for EPA costs associated with overseeing the monitoring and operation of the site remedy after the remedy construction is certified to be complete and also the cost of performing the “5 year” review of site conditions required by the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Any Bankruptcy Funds not spent on the remedy may be used to cover the Utility PRPs’ liabilities for future costs. No parties are released from potential liability for damages to natural resources.
As of December 31, 2008, Pepco had accrued approximately $2 million to meet its liability for a remedy at the Metal Bank/Cottman Avenue site. While final costs to Pepco of the settlement have not been determined, Pepco believes that its liability at this site will not have a material adverse effect on its financial position, results of operations or cash flows.
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 Pepco to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions generated incremental tax cash flow benefits of approximately $94 million for Pepco, primarily attributable to Pepco’s 2001 tax returns.
In 2005, the Treasury Department issued proposed regulations that, if adopted in their current form, would require Pepco to change its method of accounting with respect to capitalizable construction costs for income tax purposes for tax periods beginning in 2005. Based on those proposed regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believed would be acceptable to the IRS.
At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which was intended to limit the ability of certain taxpayers to utilize the method of accounting for income tax purposes they utilized on their tax returns for 2004 and prior years with respect to capitalizable construction costs. In line with this Revenue Ruling, the IRS revenue agent’s report for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco had claimed on those returns by requiring it to capitalize and depreciate certain expenses rather than treat such expenses as current deductions. PHI’s protest of the IRS adjustments is among the unresolved audit matters relating to the 2001 and 2002 audits pending before the U.S. Office of Appeals of the IRS.
In February 2006, PHI paid approximately $121 million of taxes to cover the amount of additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, adopted on its 2005 tax return. In June 2008, PHI received from the IRS an offer of settlement pertaining to Pepco for the tax years 2001 through 2004. Pepco is substantially in agreement with this proposed settlement. Based on the terms of the proposal, Pepco expects the final settlement amount to be less than the $121 million previously deposited.
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On the basis of the tentative settlement, Pepco updated its estimated liability related to mixed service costs and as a result, recorded in the quarter ended June 30, 2008, a net reduction in its liability for unrecognized tax benefits of $16 million and recognized after-tax interest income of $3 million.
Contractual Obligations
As of December 31, 2008, Pepco’s contractual obligations under non-derivative fuel and power purchase contracts were $1,202 million in 2009, $975 million in 2010 to 2011, $25 million in 2012 to 2013, and zero in 2014 and thereafter.
(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, 2008, 2007 and 2006 were approximately $145 million, $129 million, and $114 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, 2008, 2007 and 2006 were approximately $11 million, $26 million and $15 million, respectively.
In addition to the transactions described above, Pepco’s financial statements include the following related party transactions in its Statements of Earnings:
(a)
Included in fuel and purchased energy expense.
(b)
Included in other operation and maintenance expense.
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As of December 31, 2008 and 2007, 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.
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(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 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.
(b)
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.
(c)
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).
(d)
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.
(e)
Includes $33 million benefit ($20 million after-tax) from settlement of Mirant bankruptcy claims.
(f)
Includes $20 million benefit ($18 million net of fees) related to Maryland income tax refund and a charge of $3 million related to additional analysis of deferred tax balances completed in 2007.
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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. Because of 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, 2008 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 its internal control over financial reporting was effective as of December 31, 2008.
This Annual Report on Form 10-K does not include an attestation report of DPL’s registered public accounting firm, PricewaterhouseCoopers LLP, regarding internal control over financial reporting. Management’s report was not subject to attestation by PricewaterhouseCoopers LLP pursuant to temporary rules of the Securities and Exchange Commission that permit DPL to provide only management’s report in this Form 10-K.
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 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, 2008 and December 31, 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008 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. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 12 to the financial statements, the Company changed its manner of accounting and reporting for uncertain tax positions in 2007.
PricewaterhouseCoopers LLP
Washington, DC
March 2,
DPL
The accompanying Notes are an integral part of these Financial Statements.
DPL
The accompanying Notes are an integral part of these Financial Statements.
DPL
The accompanying Notes are an integral part of these Financial Statements.
DPL
The accompanying Notes are an integral part of these Financial Statements.
DPL
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 Virginia (until the sale of its Virginia assets on January 2, 2008), and provides gas distribution service in northern Delaware. Additionally, DPL supplies electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier. The regulatory term for this service varies by jurisdiction as follows:
Delaware
Standard Offer Service (SOS)
Maryland
SOS
Virginia
Default Service (prior to January 2, 2008)
In this Form 10-K, DPL also refers to these supply services generally as Default Electricity Supply. 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 the Eastern Shore of Virginia. For a discussion of the sales of the Virginia assets, see Note (14), “Commitment and Contingencies - Regulatory and Other Matters - Sale of Virginia Retail Electric Distribution and Wholesale Transmission Assets.”
Impact of the Current Capital and Credit Market Disruptions
The recent disruptions in the capital and credit markets have had an impact on DPL’s business. While these conditions have required DPL to make certain adjustments in its financial management activities, DPL believes that it currently has sufficient liquidity to fund its operations and meet its financial obligations. These market conditions, should they continue, however, could have a negative effect on DPL’s financial condition, results of operations and cash flows.
Liquidity Requirements
DPL depends on access to the capital and credit markets to meet its liquidity and capital requirements. To meet its liquidity requirements, DPL historically has relied on the issuance of commercial paper and short-term notes and on bank lines of credit to supplement internally generated cash from operations. DPL’s primary credit source is PHI’s $1.5 billion syndicated credit facility, under which DPL can borrow funds, obtain letters of credit and support the issuance of commercial paper in an amount up to $500 million (subject to the limitation that the total utilization by DPL and PHI’s other utility subsidiaries cannot exceed $625 million). This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total commitment.
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Due to the recent capital and credit market disruptions, the market for commercial paper was severely restricted for most companies. As a result, DPL has not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that it typically has required for cash management purposes. After giving effect to outstanding letters of credit and commercial paper, PHI’s utility subsidiaries have an aggregate of $843 million in combined cash and borrowing capacity under the credit facility at December 31, 2008. During the months of January and February 2009, the average daily amount of the combined cash and borrowing capacity of PHI’s utility subsidiaries was $831 million and ranged from a low of $673 million to a high of $1 billion.
To address the challenges posed by the current capital and credit market environment and to ensure that it will continue to have sufficient access to cash to meet its liquidity needs, DPL has identified a number of cash and liquidity conservation measures, including opportunities to defer capital expenditures due to lower than anticipated growth. Several measures to reduce expenditures have been taken. Additional measures could be undertaken if conditions warrant.
Due to the financial market conditions, which have caused uncertainty of short-term funding, DPL issued $250 million in long-term debt securities in November, with the proceeds used to refund short-term debt incurred to finance utility construction and operations on a temporary basis and incurred to fund the temporary repurchase of tax-exempt auction rate securities.
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 recent stock market declines have caused a decrease in the market value of benefit plan assets in 2008. DPL expects to contribute approximately $10 million to the pension plan in 2009.
(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
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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 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.
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 $52 million and $50 million as of December 31, 2008 and 2007, 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 power 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. 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 de minimis.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in DPL’s gross revenues were $15 million, $13 million and $14 million for the years ended December 31, 2008, 2007 and 2006, 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 Statement of Financial Accounting Standards (SFAS) No. 71 until recovered. At December 31, 2008, there was a net deferred
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derivative payable of $56 million, offset by a $56 million regulatory asset. At December 31, 2007, there was a net deferred derivative payable of $13 million, offset by a $13 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 assets’ carrying amount exceeds their fair value including costs to sell.
Income Taxes
DPL, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL based upon the taxable income or loss amounts, determined on a separate return basis.
In 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). FIN 48 clarifies the criteria for recognition of tax benefits in accordance with Statement of SFAS No. 109, “Accounting for Income Taxes,” and prescribes a financial statement recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Specifically, it clarifies that an entity’s tax benefits must be “more likely than not” of being sustained prior to recording the related tax benefit in the financial statements. If the position drops below the “more likely than not” standard, the benefit can no longer be recognized. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.
On May 2, 2007, the FASB issued FASB Staff Position (FSP) FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48” (FIN 48-1), which provides 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 of FIN 48-1 with its adoption of FIN 48 on January 1, 2007.
The financial statements include current and deferred income taxes. Current income taxes represent the amounts 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 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
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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 discussion.
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 unrecognized tax benefits, and tax-related penalties in income tax expense.
Investment tax credits from utility plant purchased in prior years are reported on the Balance Sheets as Investment tax credits. These investment tax credits are being amortized to income over the useful lives of the related utility plant.
Consolidation of Variable Interest Entities
In accordance with the provisions of FIN 46R entitled “Consolidation of Variable Interest Entities,” DPL consolidates those variable interest entities where DPL has been determined to be primary beneficiary. FIN 46R addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests.
DPL Onshore Wind Transactions
In 2008, DPL entered into three onshore wind power purchase arrangements (PPAs) for energy and renewable energy credits (RECs) to help serve 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 all three agreements, and payments under the agreements are expected to start in 2009 at the earliest.
DPL has exclusive rights to the energy and RECs in amounts up to a total between 120 and 150 megawatts under the PPAs. The lengths of the contracts range between 15 and 20 years. DPL is only obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed. Recent disruptions in the capital and credit markets could result in delays in the start dates for these PPAs. If the PPAs are not initiated by the specified dates, DPL has the right to terminate the PPAs. DPL’s maximum exposure to loss under the PPAs is the extent to which the market prices for energy and RECs fall below the contractual purchase price.
DPL concluded that two of the PPAs were leases in accordance with the guidance in Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease” (EITF 01-8), but that DPL did not own the assets under the lease during construction in accordance with EITF Issue No. 97-10, “The Effect of Lessee Involvement in Asset Construction.” DPL concluded that it is not the primary beneficiary under the third PPA because it will only receive 50 percent of the output from the facility and it will not absorb a majority of the risks or rewards as compared to the debt and equity investors in the facility. DPL concluded that consolidation is not required for any of these PPAs under FIN 46(R).
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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.
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
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. 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 the new information is known.
Inventories
Included in inventories are:
- generation, 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 fuel expense 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 as of July 1, 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. 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 PHI’s stock price causing its market capitalization to fall below its book value; an adverse regulatory action; or an impairment of long-lived assets. DPL performed its annual impairment test on July 1, 2008, and an interim impairment test at December 31, 2008, and no impairment was recorded as described in Note (6), “Goodwill.”
Regulatory Assets and Regulatory Liabilities
Certain aspects of DPL’s utility businesses 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 (VSCC). The transmission and wholesale sale of electricity by DPL is 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, the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 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, then the regulatory asset will be eliminated through a charge to earnings.
As part of the new electric service distribution base rates for DPL approved by the MPSC, effective in June 2007, the MPSC approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to which the BSA applies, DPL recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA thus decouples 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 positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a negative Revenue Decoupling Adjustment is recorded as a regulatory liability. The net Revenue Decoupling Adjustment at December 31, 2008 is a regulatory asset and is included in the “Other” line item on the table of regulatory asset balances in Note (7), “Regulatory Assets and Regulatory Liabilities.”
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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 under the provisions of SFAS No. 144. 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 Retirement Obligations” 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 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 rate for each of 2008, 2007 and 2006 for DPL’s transmission and distribution system property was approximately 3%.
Capitalized Interest and Allowance for Funds Used During Construction
In accordance with the provisions of SFAS No. 71, 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 Earnings.
DPL recorded AFUDC for borrowed funds of $1 million for each of the years ended December 31, 2008, 2007, and 2006.
DPL recorded amounts for the equity component of AFUDC of $1 million, zero and $1 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Leasing Activities
DPL’s lease transactions can include plant, office space, equipment, software and vehicles. In accordance with SFAS No. 13, “Accounting for Leases” (SFAS No. 13), 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 the increases 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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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. Costs associated with the redemption of debt are also deferred and amortized over the lives of the new issues.
Asset Removal Costs
In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” asset removal costs are recorded as regulatory liabilities. At December 31, 2008 and 2007, $234 million is reflected as a regulatory liability 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.
The PHI Retirement Plan is accounted for in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” as amended by SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS No. 158), and its other postretirement benefits in accordance with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” as amended by SFAS No. 158. Pepco Holdings’ financial statement disclosures were prepared in accordance with SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” as amended by SFAS No. 158.
DPL participates in benefit plans sponsored by Pepco Holdings and as such, the provisions of SFAS No. 158 do not have an impact on its financial condition and cash flows.
Dividend Restrictions
In addition to its future financial performance, the ability of DPL to pay dividends is subject to limits imposed by: (i) state corporate and regulatory laws, which impose limitations on the funds that can be used to pay dividends and, in the case of regulatory laws, may require the prior approval of DPL’s utility regulatory commissions before dividends can be paid 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 $95 million and $118 million of restricted retained earnings at December 31, 2008 and 2007, respectively.
Reclassifications and Adjustments
Certain prior year amounts have been reclassified in order to conform to current year presentation.
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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, which were not considered material either individually or in the aggregate, 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
Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS No. 157)
SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. Under SFAS No. 157, 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 in the most advantageous market using the best available information. The provisions of SFAS No. 157 were effective for financial statements beginning January 1, 2008 for DPL.
In February 2008, the FASB issued FSP 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” (FSP 157-1), that removed fair value measurement for the recognition and measurement of lease transactions from the scope of SFAS No. 157. The effective date of FSP 157-1 was for financial statement periods beginning January 1, 2008 for DPL.
Also in February 2008, the FASB issued FSP 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2), which deferred the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually), until financial statement reporting periods beginning January 1, 2009 for DPL.
DPL applied the guidance of FSP 157-1 and FSP 157-2 with its adoption of SFAS No. 157. The adoption of SFAS No. 157 on January 1, 2008 did not result in a transition adjustment to beginning retained earnings and did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows. SFAS No. 157 also required new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value. This additional disclosure is provided in Note (13), “Fair Value Disclosures.” DPL is currently evaluating the impact of FSP 157-2 and does not anticipate that the application of FSP 157-2 to its other non-financial assets and non-financial liabilities will materially affect its overall financial condition, results of operations, or cash flows.
In September 2008, the Securities and Exchange Commission and FASB issued guidance on fair value measurements, which was clarifies in October 2008 by the FASB in FSP 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active.”
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This guidance clarifies the application of SFAS No. 157 to assets in an inactive market and illustrates how to determine the fair value of a financial asset in an inactive market. The guidance was effective beginning with the September 30, 2008 reporting period for DPL, and has not had a material impact on DPL’s results.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities-including an Amendment of FASB Statement No. 115” (SFAS No. 159)
SFAS No. 159 permits entities to elect to measure eligible financial instruments at fair value. SFAS No. 159 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. On January 1, 2008, DPL elected not to apply the fair value option for its eligible financial assets and liabilities.
FASB Staff Position (FSP) FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1)
FSP FIN 39-1 amended certain portions of FIN 39. The FSP replaces the terms “conditional contracts” and “exchange contracts” in FIN 39 with the term “derivative instruments” as defined in SFAS Statement No. 133 “Accounting for Derivative Instrument and Hedging Activities” (SFAS No. 133). The FSP also amends FIN 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivables, or the obligation to return cash collateral or payables, arising from the same master netting arrangement as the derivative instruments. FSP FIN 39-1 applied to financial statements beginning January 1, 2008 for DPL.
DPL retrospectively adopted the provisions of FSP FIN 39-1 and elected to offset the net 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 effect of retrospective application of FSP FIN 39-1 was not material at December 31, 2007 and, as such, no amounts were reclassified.
SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162)
In May 2008, the FASB issued SFAS No. 162, which identifies the sources of accounting principles and the hierarchy for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. Moving the GAAP hierarchy into the accounting literature directs the responsibility for applying the hierarchy to the reporting entity, rather than just to the auditors.
SFAS No. 162 was effective for DPL as of November 15, 2008 and did not result in a change in accounting for DPL. Therefore, the provisions of SFAS No. 162 did not have a material impact on DPL’s overall financial condition, results of operations, cash flows and disclosure.
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FSP FAS 133-1 and FIN 45-4, “Disclosure About Credit Derivatives and Certain Guarantees” (FSP FAS 133-1 and FIN 45-4)
In September 2008, the FASB issued FSP FAS 133-1 and FIN 45-4, which requires enhanced disclosures by entities that provide credit protection through credit derivatives (including embedded credit derivatives) within the scope of SFAS No. 133, and guarantees within the scope of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”
For credit derivatives, FSP FAS 133-1 and FIN 45-4 requires disclosure of the nature and fair value of the credit derivative, the approximate term, the reasons for entering the derivative, the events requiring performance, and the current status of the payment/performance risk. It also requires disclosures of the maximum potential amount of future payments without any reduction for possible recoveries under collateral provisions, recourse provisions, or liquidation proceeds. DPL has not provided credit protection to others through the credit derivatives within the scope of SFAS No. 133.
For guarantees, FSP FAS 133-1 and FIN 45-4 requires disclosure on the current status of the payment/performance risk and whether the current status is based on external credit ratings or current internal groupings used to manage risk. If internal groupings are used, then information is required about how the groupings are determined and used for managing risk.
The new disclosures are required starting with financial statement reporting periods ending December 31, 2008 for DPL. Comparative disclosures are only required for periods ending after initial adoption. The new guarantee disclosures did not have a material impact on DPL.
FSP FAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities” (FSP FAS 140-4 and FIN 46(R)-8)
In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8 to expand the disclosures under the original pronouncements. The disclosure requirements in SFAS No. 140 for transfers of financial assets are to include disclosure of (i) a transferor’s continuing involvement in transferred financial assets, and (ii) how a transfer of financial assets to a special-purpose entity affects an entity’s financial position, financial performance, and cash flows. The principal objectives of the disclosure requirements in Interpretation 46(R) are to outline (i) significant judgments in determining whether an entity should consolidate a variable interest entity (VIE), (ii) the nature of any restrictions on consolidated assets, (iii) the risks associated with the involvement in the VIE, and (iv) how the involvement with the VIE affects an entity’s financial position, financial performance, and cash flows.
FSP FAS 140-4 and FIN 46(R)-8 is effective for DPL’s December 31, 2008 financial statements. This FSP has no material impact to DPL’s overall financial condition, results of operations, or cash flows as it relates to SFAS No. 140. DPL’s FIN 46(R) disclosures are provided in Note (2), “Significant Accounting Policies - Consolidation of Variable Interest Entities.”
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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
SFAS No. 141(R), “Business Combinations-a Replacement of FASB Statement No. 141” (SFAS No. 141 (R))
SFAS No. 141(R) replaces FASB Statement No. 141, “Business Combinations,” and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141 (R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require 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.
In January 2009, the FASB proposed FSP FAS 141(R)-a “Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP FAS 141(R)-a), to clarify the accounting on the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The FSP FAS 141(R)-a requires that assets acquired and liabilities assumed in a business combination that arise from contingences be measured at fair value in accordance with SFAS No. 157 if the acquisition date can be reasonably determined. If not, then the asset or liability would be measured at the amount in accordance with SFAS 5, “Accounting for Contingencies,” and FIN 14, “Reasonable Estimate of the Amount of Loss.”
SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-a applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009 for DPL. DPL has evaluated the impact of SFAS No. 141(R) and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, or cash flows.
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an Amendment of ARB No. 51” (SFAS No. 160)
SFAS No. 160 establishes 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. It clarifies that a minority interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.
SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity, and presented separately on the face of the consolidated statement of income, (ii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.
SFAS No. 160 is effective prospectively for financial statement reporting periods beginning January 1, 2009 for DPL, except for the presentation and disclosure requirements. The presentation and disclosure requirements apply retrospectively for all periods presented.
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DPL has evaluated the impact of SFAS No. 160 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, cash flows or disclosure.
SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an Amendment of FASB Statement No. 133” (SFAS No. 161)
In March 2008, the FASB issued SFAS No. 161, which changes the disclosure requirements for derivative instruments and hedging activities. Entities will be required to provide qualitative disclosures about derivatives objectives and strategies, fair value amounts of gains and losses on derivative instruments which before were optional, disclosure about credit-risk-related contingent features in derivative agreements, and information on the potential effect on an entity’s liquidity from using derivatives.
SFAS No. 161 requires that the gross fair value of derivative instruments and gross gains and losses be quantitatively disclosed in a tabular format to provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. The FASB provides an option for hedged items to be presented in a tabular or non-tabular format.
SFAS No. 161 is effective for financial statement reporting periods beginning January 1, 2009 for DPL. SFAS No. 161 encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. DPL is currently evaluating the impact SFAS No. 161 may have on its March 31, 2009 quarterly disclosures.
EITF Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third Party Credit Enhancement” (EITF 08-5)
In September 2008, the FASB issued EITF 08-5 to provide guidelines for the determination of the unit of accounting for a liability issued with an inseparable third-party credit enhancement when it is measured or disclosed at fair value on a recurring basis. EITF 08-5 applies to entities that incur liabilities with inseparable third-party credit enhancements or guarantees that are recognized or disclosed at fair value. This would include guaranteed debt obligations, 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 is 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.
EITF 08-5 is effective on a prospective basis in reporting periods on and after January 1, 2009 for DPL. The effect of initial application shall be included in the change in fair value in the period of adoption. DPL is currently evaluating the impact on its accounting and disclosures.
EITF Issue No. 08-6, “Equity Method Investment Accounting Consideration” (EITF 08-6)
In November 2008, the FASB issued EITF 08-6 to address 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 an equity method investee’s
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issuance of shares should be accounted for. The EITF concludes that initial carrying value of an equity method investment can be determined using the accumulation model in SFAS 141(R), “Business Combination (revised 2007),” and other-than-temporary impairments should be recognized in accordance with paragraph 19(h) of Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”
This EITF is effective for DPL beginning January 1, 2009. DPL is currently evaluating the impact on its accounting and disclosures.
FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP FAS 132(R)-1)
In December 2008, the FASB issued FSP FAS 132(R)-1 to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The required disclosures under this FSP would expand current disclosures under SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits-an amendment of FASB Statements No. 87, 88, and 106,” to be in line with SFAS No. 157 required disclosures.
The disclosures are to provide users an understanding of the investment allocation decisions made, factors used in the investment policies and strategies, plan assets by major investment types, inputs and valuation techniques used to measure fair value of plan assets, significant concentration of risk within the plan, and the effects of fair value measurement using significant unobservable inputs (Level 3 as defined in SFAS No. 157) on changes in plan assets for the period.
The new disclosures are required starting with financial statement reporting periods ending December 31, 2009 for DPL and earlier application is permitted. Comparative disclosures under this provision are not required for earlier periods presented. DPL is currently evaluating the impact on its disclosures.
(5) SEGMENT INFORMATION
In accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” DPL has one segment, its regulated utility business.
(6) GOODWILL
DPL’s July 1, 2008 annual impairment test indicated that its goodwill was not impaired. DPL performed an interim impairment test at December 31, 2008, as the market capitalization of PHI for a significant period in the fourth quarter of 2008 was lower than its book value. The December 31, 2008 impairment test indicated that the goodwill balance was not impaired under either of the discounted cash flow models.
To estimate the fair value of DPL’s business, DPL reviewed 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 estimate of terminal value is based on a constant, annual cash flow growth rate that is consistent with DPL’s plan, and the other estimate of terminal value is
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based on a multiple of earnings before interest, taxes, depreciation, and amortization that management believes is consistent with relevant market multiples for comparable utilities. Each model uses a cost of capital appropriate for a regulated utility as the discount rate for the estimated cash flows associated with the reporting unit. Neither valuation model evidenced impairment of goodwill. PHI has consistently used this valuation model to estimate the fair value of DPL’s business since the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142).
The estimation of fair value is dependent on a number of factors, including but not limited to future growth assumptions, operating and capital expenditure requirements, and capital costs, and changes in these factors could materially impact the results of impairment testing. The estimated cash flows were sourced from DPL’s forecast, and they incorporate current plans for capital expenditures and regulatory ratemaking cases. Assumptions and methodologies used in the models were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures. The discount rate employed reflected DPL’s estimated cost of capital. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of DPL’s business include utility sector market performance, sustained poor economic conditions, the results of rate-making proceedings, higher operating and capital expenditure requirements, a significant increase in the cost of capital and other factors.
With the current volatile general market conditions and the disruptions in the credit and capital markets, DPL will continue to closely monitor whether there is goodwill impairment.
(7) REGULATORY ASSETS AND REGULATORY LIABILITIES
The components of DPL’s regulatory asset balances at December 31, 2008 and 2007 are as follows:
The components of DPL’s regulatory liability balances at December 31, 2008 and 2007 are as follows:
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A description for each category of regulatory assets and regulatory liabilities follows:
Deferred Energy Supply Costs: The regulatory asset primarily represents deferred 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 primarily represents deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred in Delaware. The Default Electricity Supply deferrals do 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 provide deferred income taxes. As the temporary differences between the financial statement and tax basis of assets reverse, the deferred recoverable balances are reversed. There is no return 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 received on these deferrals.
Phase In Credits: Represents 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 to occur over a 17-month period beginning January 2008. The Delaware deferral will be 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 and ending in 2008. There is no return on these deferrals.
COPCO Acquisition Adjustment: On July 19, 2007, the Maryland PSC 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 has been transferred to a regulatory asset. It will earn a 12.95% return and will be amortized from August 2007 through August 2018.
Other: Includes losses associated with DPL’s natural gas hedging activity which earns a return and under-recovery of administration costs associated with Maryland and Delaware SOS that do not receive a return.
Deferred Income Taxes Due to Customers: Represents the portion of deferred income tax liabilities applicable to DPL’s utility operations that has not been reflected in current customer rates, for which future payment to customers is probable. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return 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.
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Other: Includes over-recovery of procurement and administration costs associated with Maryland and Delaware SOS. There is no return 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 $107 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, 2008 are $9 million in 2009, $17 million in 2010, $5 million in 2011, $5 million in 2012, $5 million in 2013, and $99 million after 2013.
Rental expense for operating leases, including the Merrill Creek Reservoir lease, was $9 million, $10 million and $11 million for the years ended December 31, 2008, 2007 and 2006, respectively.
(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 to A&N Electric Cooperative for a purchase price of approximately $49 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative for a purchase price of approximately $5 million, after closing adjustments.
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(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 2008, 2007, and 2006, DPL was responsible for $3 million, $4 million and $1 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings. In 2008 and 2007, DPL made no contributions to the PHI Retirement Plan, and $9 million and $8 million, respectively to other postretirement benefit plans. At December 31, 2008 and 2007, DPL’s prepaid pension expense of $184 million and $178 million, and other postretirement benefit obligation of $4 million and $5 million, included in Other Deferred Credits, effectively represent assets and benefit obligations resulting from DPL’s participation in the Pepco Holdings benefit plan. DPL expects to contribute approximately $10 million to the pension plan in 2009.
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(11) DEBT
LONG-TERM DEBT
Long-term debt outstanding as of December 31, 2008 and 2007 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)
The bonds were subject to mandatory tender on August 1, 2008.
(d)
The insured auction rate tax-exempt bonds were repurchased by DPL at par due to the disruption in the credit markets. The bonds are considered extinguished for accounting purposes; however, DPL intends to remarket or reissue the bonds to the public in 2009.
The outstanding First Mortgage Bonds issued by DPL are subject to a lien on substantially all of DPL’s property, plant and equipment.
Maturities of long-term debt and sinking fund requirements during the next five years are as follows: zero in 2009, $31 million in 2010, $35 million in 2011, zero in 2012, $250 million in 2013, and $371 million thereafter.
DPL’s long-term debt is subject to certain covenants. DPL is in compliance with all requirements.
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SHORT-TERM DEBT
DPL, a regulated utility, 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, 2008 and 2007 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 a $500 million credit facility, described below under the heading “Credit Facility,” shared with PHI’s other utility subsidiaries, Potomac Electric Power Company (Pepco) and Atlantic City Electric Company (ACE).
DPL had no commercial paper outstanding at December 31, 2008 and $24 million of commercial paper outstanding at December 31, 2007. The weighted average interest rates for commercial paper issued during 2008 and 2007 were 3.88% and 5.35%, respectively. The weighted average maturity for commercial paper issued during 2008 and 2007 was five days and four days, respectively.
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. 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 VRDB as a source of long-term financing. During 2008, $9 million of VRDB’s were tendered to the company. If market conditions are favorable, DPL intends to remarket these bonds during 2009. The VRDB outstanding in 2008 mature as follows: 2017 ($26 million), 2024 ($24 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDB was 3.24% during 2008 and 3.87% during 2007. Of the $96 million in VRDB’s, $72 million of DPL’s obligations are secured by first mortgage bonds, which provide collateral to the investors in the event of a default by DPL.
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Bank Loan
In March 2008, DPL obtained a $150 million unsecured term loan that matures in July 2009. Interest on the loan is calculated at a variable rate.
Credit Facility
PHI, Pepco, DPL and ACE maintain a credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under this primary 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. All indebtedness incurred under the facility is unsecured.
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 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.
As a result of severe liquidity constraints in the credit, commercial paper and capital markets during October 2008, DPL borrowed under the $1.5 billion credit facility. Typically, DPL issues commercial paper if required to meet its short-term working capital requirements. Given the lack of liquidity in the commercial paper markets, DPL borrowed under the credit facility to maintain sufficient cash on hand to meet daily short-term operating needs. In October 2008, DPL borrowed $150 million. At December 31, 2008, DPL did not have any borrowings under the facility.
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(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 as part of Pepco’s acquisition of Conectiv on August 1, 2002. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.
The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.
Provision for Income Taxes
Reconciliation of Income Tax Rate
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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 “Deferred tax adjustments” in the reconciliation provided above. In addition, during 2008 DPL recorded after-tax net interest income of $3 million under FIN 48 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.
FIN 48, “Accounting for Uncertainty in Income Taxes”
As disclosed in Note (2), “Significant Accounting Policies,” DPL adopted FIN 48 effective January 1, 2007. Upon adoption, DPL recorded the cumulative effect of the change in accounting principle of $100 thousand as an increase in retained earnings. Also upon adoption, DPL had $43 million of unrecognized tax benefits and $10 million of related accrued interest.
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, in accordance with FIN 48, 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, 2008, 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, 2008 and 2007, DPL recognized $5 million of interest income before tax ($3 million after-tax) and $2 million of interest expense before tax ($1 million after-tax), respectively, as a component of tax expense. As of December 31, 2008 and 2007, DPL had $3 million and $6 million, respectively, of accrued interest payable related to effectively settled and uncertain tax positions.
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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 and the obligation becomes certain. See Note (14), “Commitments and Contingencies,” for additional information.
Tax Years Open to Examination
DPL, as in 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 noted above.
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 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, 2008 and 2007.
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 normalized over the remaining service lives of the related assets.
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Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below. These amounts relate to the Power Delivery business and are recoverable through rates.
(13) FAIR VALUE DISCLOSURES
Effective January 1, 2008, DPL adopted SFAS No. 157, as discussed earlier in Note (3), which established a framework for measuring fair value and expands disclosures about fair value measurements.
As defined in SFAS No. 157, 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. SFAS No. 157 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 defined by SFAS No. 157 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.
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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. Some of the options do not expire until December 2011. All of the options are part of the natural gas hedging program approved by the Delaware Public Service Commission.
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 table sets 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, 2008. As required by SFAS No. 157, 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.
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A reconciliation of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (level 3) is shown below (in millions of dollars):
The estimated fair values of DPL’s non-derivative financial instruments at December 31, 2008 and 2007 are shown below.
The fair values of the Long-term debt, which includes First Mortgage Bonds, Amortizing 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 for issues with no market price available, were based on discounted cash flows using current rates for similar issues with similar terms and remaining maturities.
(14) COMMITMENTS AND CONTINGENCIES
Rate Proceedings
In the most recent electric service distribution base rate cases filed by DPL in Maryland, and in a natural gas distribution case filed by DPL in Delaware, DPL proposed the adoption of a BSA for retail customers. As more fully discussed below, the implementation of a BSA has been approved for electric service in Maryland. A method of revenue decoupling similar to a BSA,
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referred to as a modified fixed variable rate design (MFVRD), has been adopted in Delaware, which will be implemented in the context of DPL’s next Delaware base rate case. Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount. The BSA increases rates if actual distribution revenues fall below the level approved by the applicable commission 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” revenue from unit sales consumption and ties the growth in 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 utility 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 delivery revenues. The MVFRD adopted in Delaware relies primarily upon 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 believes that the MFRVD can serve as an appropriate revenue decoupling mechanism.
Delaware
On August 29, 2008, DPL submitted its 2008 Gas Cost Rate (GCR) filing to the DPSC, requesting a 14.8% increase in the level of GCR. On September 16, 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.
On January 26, 2009, DPL submitted to the DPSC an interim GCR filing, requesting a 6.6% decrease in the level of GCR. On February 5, 2009, the DPSC issued an initial order approving the requested decrease, to become effective on March 1, 2009, subject to refund pending final DPSC approval after evidentiary hearings.
Maryland
In July 2007, the MPSC issued an order in DPL’s electric service distribution rate case, which included approval of a BSA. The order approved an annual increase in distribution rates of approximately $15 million (including a decrease in annual depreciation expense of approximately $1 million). The approved distribution rate reflects a return on equity (ROE) of 10%. The rate increases were effective as of June 16, 2007, and remained in effect for an initial period until July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of an audit of DPL’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required. On July 18, 2008, the MPSC issued an order covering the Phase II proceedings, denying any further adjustment to DPL’s rates, thus making permanent the rate increases approved in the July 2007 order. The MPSC also issued an order on August 4, 2008, further explaining its July 18 order.
DPL has filed a general notice of appeal of the MPSC July 2007 and the July 18 and August 4, 2008 orders. The appeal challenges the MPSC’s failure to implement permanent rates in accordance with Maryland law, and seek judicial review of the MPSC’s denial of DPL’s rights
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to recover an increased share of the PHI Service Company costs and the costs of performing a MPSC-mandated management audit. The case currently is pending before the Circuit Court for Baltimore City. Under the procedural schedule set by the court, DPL will file a consolidated brief on or before March 9, 2009, specifying the basis for its requested relief.
Federal Energy Regulatory Commission
On August 18, 2008, DPL submitted an application with FERC for incentive rate treatments in connection with PHI’s 230-mile, 500-kilovolt Mid-Atlantic Power Pathway transmission project. The application requested that FERC include DPL’s Construction Work in Progress in its transmission rate base, an ROE adder of 150 basis points (for a total ROE of 12.8%) and the recovery of prudently incurred costs in the event the project is abandoned or terminated for reasons beyond DPL’s control. On October 31, 2008, FERC issued an order approving the application.
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 to A&N Electric Cooperative (A&N) for a purchase price of approximately $49 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5 million, after closing adjustments. Each of A&N and ODEC assumed certain post-closing liabilities and unknown pre-closing liabilities related to the respective assets they purchased (including, in the A&N transaction, most environmental liabilities). A&N delayed final payment of approximately $3 million, which was due on June 2, 2008, due to a dispute in the final true-up amounts. On October 21, 2008, DPL and A&N entered into a Settlement Agreement pursuant to which A&N paid $3 million to DPL, and an additional $1 million was distributed to DPL pursuant to an escrow agreement.
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.
Metal Bank/Cottman Avenue Site. In the early 1970s, DPL sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In 1987, DPL was notified by the United States Environmental Protection Agency (EPA) that it, along with a number of other utilities and non-utilities, was a potentially responsible party in connection with the PCB contamination at the site. In 1999, DPL entered into a de minimis settlement with EPA and paid less than a million dollars to resolve its liability
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for cleanup costs at the Metal Bank/Cottman Avenue site. The de minimis settlement did not resolve DPL’s responsibility for natural resource damages, if any, at the site. DPL believes that any liability for natural resource damages at this site will not have a material adverse effect on its financial position, results of operations or cash flows.
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 DPL to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions generated incremental tax cash flow benefits of approximately $62 million for DPL, primarily attributable to DPL’s 2001 tax returns.
In 2005, the Treasury Department issued proposed regulations that, if adopted in their current form, would require DPL to change its method of accounting with respect to capitalizable construction costs for income tax purposes for tax periods beginning in 2005. Based on those proposed regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believed would be acceptable to the IRS.
At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which was intended to limit the ability of certain taxpayers to utilize the method of accounting for income tax purposes they utilized on their tax returns for 2004 and prior years with respect to capitalizable construction costs. In line with this Revenue Ruling, the IRS revenue agent’s report for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that DPL had claimed on those returns by requiring it to capitalize and depreciate certain expenses rather than treat such expenses as current deductions. PHI’s protest of the IRS adjustments is among the unresolved audit matters relating to the 2001 and 2002 audits pending before the U.S. Office of Appeals of the Internal Revenue Service (IRS).
In February 2006, PHI paid approximately $121 million of taxes to cover the amount of additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, adopted on its 2005 tax return. In June 2008, PHI received from the IRS an offer of settlement pertaining to DPL for the tax years 2001 through 2004. DPL is substantially in agreement with this proposed settlement. Based on the terms of the proposal, DPL expects the final settlement amount to be less than the $121 million previously deposited.
On the basis of the tentative settlement, DPL updated its estimated liability related to mixed service costs and, as a result, recorded in the quarter ended June 30, 2008, a net reduction in its liability for unrecognized tax benefits of $1 million and recognized after-tax interest income of $2 million.
Contractual Obligations
As of December 31, 2008, DPL’s contractual obligations under non-derivative fuel and power purchase contracts were $482 million in 2009, $412 million in 2010 to 2011, $47 million in 2012 to 2013, and $136 million in 2014 and thereafter.
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(15) RELATED PARTY TRANSACTIONS
PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost 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, 2008, 2007 and 2006 were $111 million, $108 million, and $101 million, respectively.
In addition to the PHI Service Company charges described above, DPL’s financial statements include the following related party transactions in its Statements of Earnings:
(a) Included in fuel and purchased energy expense.
(b) Included in electric revenue.
(c) Included in gas revenue.
(d) Included in gas purchased expense.
As of December 31, 2008 and 2007, DPL had the following balances on its balance sheets due (to)/from related parties:
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(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 $3 million of after-tax net interest income on uncertain tax positions primarily related to casualty losses.
(b)
Includes $2 million of after-tax interest income related to the tentative settlement of the IRS mixed service cost issue.
(c)
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.
(d)
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.
(e)
Includes a charge of $1 million in the third quarter and $2 million in the fourth quarter related to additional analysis of deferred tax balances completed in 2007.
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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. Because of 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, 2008 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 its internal control over financial reporting was effective as of December 31, 2008.
This Annual Report on Form 10-K does not include an attestation report of ACE’s registered public accounting firm, PricewaterhouseCoopers LLP, regarding internal control over financial reporting. Management’s report was not subject to attestation by PricewaterhouseCoopers LLP pursuant to temporary rules of the Securities and Exchange Commission that permit ACE to provide only management’s report in this Form 10-K.
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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 present fairly, in all material respects, the financial position of Atlantic City Electric Company (a wholly owned subsidiary of Pepco Holdings, Inc.) and its subsidiaries at December 31, 2008 and December 31, 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 11 to the consolidated financial statements, the Company changed its manner of accounting and reporting for uncertain tax positions in 2007.
PricewaterhouseCoopers LLP
Washington, DC
March 2,
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The accompanying Notes are an integral part of these Consolidated Financial Statements.
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The accompanying Notes are an integral part of these Consolidated Financial Statements.
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The accompanying Notes are an integral part of these Consolidated Financial Statements.
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The accompanying Notes are an integral part of these Consolidated Financial Statements.
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The accompanying Notes are an integral part of these Consolidated Financial Statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ATLANTIC CITY ELECTRIC COMPANY
(1) ORGANIZATION
Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. In addition, 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). ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).
In addition to its electricity transmission and distribution operations, during 2006 ACE owned a 2.47% undivided interest in the Keystone electric generating facility, a 3.83% undivided interest in the Conemaugh electric generating facility (with a combined generating capacity of 108 megawatts), and also owned the B.L. England electric generating facility (with a generating capacity of 447 megawatts). On September 1, 2006, ACE sold its interests in the Keystone and Conemaugh generating facilities and on February 8, 2007, ACE completed the sale of the B.L. England generating facility.
Impact of the Current Capital and Credit Market Disruptions
The recent disruptions in the capital and credit markets have had an impact on ACE’s business. While these conditions have required ACE to make certain adjustments in its financial management activities, ACE believes that it currently has sufficient liquidity to fund its operations and meet its financial obligations. These market conditions, should they continue, however, could have a negative effect on ACE’s financial condition, results of operations and cash flows.
Liquidity Requirements
ACE depends on access to the capital and credit markets to meet its liquidity and capital requirements. To meet its liquidity requirements, ACE historically has relied on the issuance of commercial paper and short-term notes and on bank lines of credit to supplement internally generated cash from operations. ACE’s primary credit source is PHI’s $1.5 billion syndicated credit facility, under which ACE can borrow funds, obtain letters of credit and support the issuance of commercial paper in an amount up to $500 million (subject to the limitation that the total utilization by ACE and PHI’s other utility subsidiaries cannot exceed $625 million). This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total commitment.
Due to the recent capital and credit market disruptions, the market for commercial paper was severely restricted for most companies. As a result, ACE has not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that it typically has required for cash management purposes. After giving effect to outstanding letters of credit and commercial paper, PHI’s utility subsidiaries have an aggregate of $843 million in combined cash and borrowing capacity under the credit facility at December 31, 2008. During the months of January and February 2009, the average daily amount of the combined cash and borrowing
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capacity of PHI’s utility subsidiaries was $831 million and ranged from a low of $673 million to a high of $1 billion.
To address the challenges posed by the current capital and credit market environment and to ensure that it will continue to have sufficient access to cash to meet its liquidity needs, ACE has identified a number of cash and liquidity conservation measures, including opportunities to defer capital expenditures due to lower than anticipated growth. Several measures to reduce expenditures have been taken. Additional measures could be undertaken if conditions warrant.
Due to the financial market conditions, which have caused uncertainty of short-term funding, ACE issued $250 million in long-term debt securities in November. The proceeds were used to refund short-term debt incurred to finance utility construction and operations on a temporary basis and incurred to fund the temporary repurchase of tax-exempt auction rate securities.
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 recent stock market declines have caused a decrease in the market value of benefit plan assets in 2008. ACE expects to contribute approximately $60 million to the pension plan in 2009.
(2) SIGNIFICANT ACCOUNTING POLICIES
Consolidation Policy
The accompanying consolidated financial statements include the accounts of ACE and its wholly owned subsidiaries. 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.
In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R, entitled “Consolidation of Variable Interest Entities” (FIN 46R), ACE consolidates those variable interest entities where ACE has been determined to be primary beneficiary. FIN 46R addresses conditions when an entity should be consolidated based upon variable interests rather than voting interests. For additional information, see the FIN 46R discussion later in this Note.
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
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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 $45 million and $38 million as of December 31, 2008 and December 31, 2007, 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 power 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.
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 de minimis.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in ACE’s gross revenues were $22 million, $23 million and $22 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Long-Lived Asset Impairment Evaluation
ACE evaluates certain long-lived assets to be held and used (for example, 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 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.
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For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the assets’ carrying amount exceeds their 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.
In 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). FIN 48 clarifies the criteria for recognition of tax benefits in accordance with Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes,” and prescribes a financial statement recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Specifically, it clarifies that an entity’s tax benefits must be “more likely than not” of being sustained prior to recording the related tax benefit in the financial statements. If the position drops below the “more likely than not” standard, the benefit can no longer be recognized. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.
On May 2, 2007, the FASB issued FASB Staff Position (FSP) FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48” (FIN 48-1), which provides 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 of FIN 48-1 with its adoption of FIN 48 on January 1, 2007.
The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amounts of tax expected to be reported on ACE’s state income tax returns and the amount of federal income tax allocated from PHI.
Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement 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 discussion.
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 unrecognized tax benefits, and tax-related penalties in income tax expense.
Investment tax credits from utility plant purchased in prior years are reported on the Consolidated Balance Sheets as Investment tax credits. These investment tax credits are being amortized to income over the useful lives of the related utility plant.
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Discontinued Operations
Discontinued operations are identified and accounted for in accordance with the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” For information regarding ACE’s discontinued operations refer to Note (16), “Discontinued Operations” herein.
FIN 46R, “Consolidation of Variable Interest Entities”
ACE has power purchase agreements (PPAs) with a number of entities, including three contracts between unaffiliated non-utility generators (NUGs) and ACE. Due to a variable element in the pricing structure of the NUGs, ACE potentially assumes the variability in the operations of the plants related to these PPAs and, therefore, has a variable interest in the entities. In accordance with the provisions of FIN 46R (revised December 2003), entitled “Consolidation of Variable Interest Entities,” and FSP FIN 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R),” ACE continued, during the fourth quarter of 2008, to conduct exhaustive efforts to obtain information from these entities, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R 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 application of FIN 46R 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, 2008, 2007 and 2006, were approximately $349 million, $327 million and $324 million, respectively, of which approximately $305 million, $292 million and $288 million, respectively, related to power purchases under the NUGs. ACE does not have exposure to loss under the NUGs because cost recovery will be achieved from its 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).
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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 Earnings. 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 allowances 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 the new information is known.
Inventories
Included in inventories are generation, 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 utility businesses are subject to regulation by the New Jersey Board of Public Utilities (NJBPU). The transmission and wholesale sale of electricity by ACE is regulated by the Federal Energy Regulatory Commission (FERC).
Based on the regulatory framework in which it has operated, ACE has historically applied, and in connection with its transmission and distribution business continues to apply, the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 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, then 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 under the provisions of SFAS No. 144. 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
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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 rate for each of 2008, 2007 and 2006 for ACE’s transmission and distribution system property was 3%.
Capitalized Interest and Allowance for Funds Used During Construction
In accordance with the provisions of SFAS No. 71, 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 Earnings.
ACE recorded AFUDC for borrowed funds of $2 million, $2 million and $1 million for the years ended December 31, 2008, 2007 and 2006, respectively.
ACE recorded amounts for the equity component of AFUDC of $1 million for each of the years ended December 31, 2008, 2007 and 2006.
Leasing Activities
ACE’s lease transactions can include plant, office space, equipment, software and vehicles. In accordance with SFAS No. 13, “Accounting for Leases” (SFAS No. 13), 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 the increases 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. Costs associated with the redemption of debt are also deferred and amortized over the lives of the new issues.
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 SFAS No. 87, “Employers’ Accounting for Pensions,” as amended by SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS No. 158), and its other postretirement benefits in accordance with SFAS
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No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” as amended by SFAS No. 158. Pepco Holdings’ financial statement disclosures were prepared in accordance with SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” as amended by SFAS No. 158.
ACE participates in benefit plans sponsored by Pepco Holdings and as such, the provisions of SFAS No. 158 do not have an impact on its financial condition and cash flows.
Dividend Restrictions
In addition to its future financial performance, the ability of ACE to pay dividends is subject to limits imposed by: (i) state corporate and regulatory laws, which impose limitations on the funds that can be used to pay dividends and, in the case of regulatory laws, may require the prior approval of ACE’s utility regulatory commission before dividends can be paid; (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 dividends. ACE had approximately $89 million and $88 million of restricted retained earnings at December 31, 2008 and 2007, respectively.
Reclassifications and Adjustments
Certain prior year amounts have been reclassified in order to conform to current year presentation.
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, which was not considered material, resulted in an increase in Other Operation and Maintenance expenses of $1 million for the year ended December 31, 2008, all of which related to prior periods.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS No. 157)
SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. Under SFAS No. 157, 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 in the most advantageous market using the best available information. The provisions of SFAS No. 157 were effective for financial statements beginning January 1, 2008 for ACE.
In February 2008, the FASB issued FSP 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” (FSP
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157-1), that removed fair value measurement for the recognition and measurement of lease transactions from the scope of SFAS No. 157. The effective date of FSP 157-1 was for financial statement periods beginning January 1, 2008 for ACE.
Also in February 2008, the FASB issued FSP 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2), which deferred the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually), until financial statement reporting periods beginning January 1, 2009 for ACE.
ACE applied the guidance of FSP 157-1 and FSP 157-2 with its adoption of SFAS No. 157. The adoption of SFAS No. 157 on January 1, 2008 did not result in a transition adjustment to beginning retained earnings and did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows. SFAS No. 157 also required new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value. This additional disclosure is provided in Note (13), “Fair Value Disclosures.” ACE is currently evaluating the impact of FSP 157-2 and does not anticipate that the application of FSP 157-2 to its other non-financial assets and non-financial liabilities will materially affect its overall financial condition, results of operations, or cash flows.
In September 2008, the Securities and Exchange Commission and FASB issued guidance on fair value measurements, which was clarifies in October 2008 by the FASB in FSP 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active.” This guidance clarifies the application of SFAS No. 157 to assets in an inactive market and illustrates how to determine the fair value of a financial asset in an inactive market. The guidance was effective beginning with the September 30, 2008 reporting period for ACE, and has not had a material impact on ACE’s results.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities-including an Amendment of FASB Statement No. 115” (SFAS No. 159)
SFAS No. 159 permits entities to elect to measure eligible financial instruments at fair value. SFAS No. 159 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. On January 1, 2008, ACE elected not to apply the fair value option for its eligible financial assets and liabilities.
SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162)
In May 2008, the FASB issued SFAS No. 162, which identifies the sources of accounting principles and the hierarchy for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. Moving the GAAP hierarchy into the accounting literature directs the responsibility for applying the hierarchy to the reporting entity, rather than just to the auditors.
SFAS No. 162 was effective for ACE as of November 15, 2008 and did not result in a change in accounting for ACE. Therefore, the provisions of SFAS No. 162 did not have a material impact on ACE’s overall financial condition, results of operations, cash flows and disclosure.
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FSP FAS 133-1 and FIN 45-4, “Disclosure About Credit Derivatives and Certain Guarantees” (FSP FAS 133-1 and FIN 45-4)
In September 2008, the FASB issued FSP FAS 133-1 and FIN 45-4, which requires enhanced disclosures by entities that provide credit protection through credit derivatives (including embedded credit derivatives) within the scope of SFAS No. 133, and guarantees within the scope of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”
For credit derivatives, FSP FAS 133-1 and FIN 45-4 requires disclosure of the nature and fair value of the credit derivative, the approximate term, the reasons for entering the derivative, the events requiring performance, and the current status of the payment/performance risk. It also requires disclosures of the maximum potential amount of future payments without any reduction for possible recoveries under collateral provisions, recourse provisions, or liquidation proceeds. ACE has not provided credit protection to others through the credit derivatives within the scope of SFAS No. 133.
For guarantees, FSP FAS 133-1 and FIN 45-4 requires disclosure on the current status of the payment/performance risk and whether the current status is based on external credit ratings or current internal groupings used to manage risk. If internal groupings are used, then information is required about how the groupings are determined and used for managing risk.
The new disclosures are required starting with financial statement reporting periods ending December 31, 2008 for ACE. Comparative disclosures are only required for periods ending after initial adoption. The new guarantee disclosures did not have a material impact on ACE.
FSP FAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities” (FSP FAS 140-4 and FIN 46(R)-8)
In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8 to expand the disclosures under the original pronouncements. The disclosure requirements in SFAS No. 140 for transfers of financial assets are to include disclosure of (i) a transferor’s continuing involvement in transferred financial assets, and (ii) how a transfer of financial assets to a special-purpose entity affects an entity’s financial position, financial performance, and cash flows. The principal objectives of the disclosure requirements in Interpretation 46(R) are to outline (i) significant judgments in determining whether an entity should consolidate a variable interest entity (VIE), (ii) the nature of any restrictions on consolidated assets, (iii) the risks associated with the involvement in the VIE, and (iv) how the involvement with the VIE affects an entity’s financial position, financial performance, and cash flows.
FSP FAS 140-4 and FIN 46(R)-8 is effective for ACE’s December 31, 2008 financial statements. This FSP has no material impact to ACE’s overall financial condition, results of operations, or cash flows as it relates to SFAS No. 140. ACE’s FIN 46(R) disclosures are provided in Note (2), “Significant Accounting Policies - FIN 46R, Consolidation of Variable Interest Entities.”
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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
SFAS No. 141(R), “Business Combinations-a Replacement of FASB Statement No. 141” (SFAS No. 141 (R))
SFAS No. 141(R) replaces FASB Statement No. 141, “Business Combinations,” and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141 (R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require 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.
In January 2009, the FASB proposed FSP FAS 141(R)-a “Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP FAS 141(R)-a), to clarify the accounting on the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The FSP FAS 141(R)-a requires that assets acquired and liabilities assumed in a business combination that arise from contingences be measured at fair value in accordance with SFAS No. 157 if the acquisition date can be reasonably determined. If not, then the asset or liability would be measured at the amount in accordance with SFAS 5, “Accounting for Contingencies,” and FIN 14, “Reasonable Estimate of the Amount of Loss.”
SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-a applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009 for ACE. ACE has evaluated the impact of SFAS No. 141(R) and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, or cash flows.
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an Amendment of ARB No. 51” (SFAS No. 160)
SFAS No. 160 establishes 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. It clarifies that a minority interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.
SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity, and presented separately on the face of the consolidated statement of income, (ii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.
SFAS No. 160 is effective prospectively for financial statement reporting periods beginning January 1, 2009 for ACE, except for the presentation and disclosure requirements. The presentation and disclosure requirements apply retrospectively for all periods presented.
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ACE has evaluated the impact of SFAS No. 160 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, cash flows or disclosure.
EITF Issue No. 08-6, “Equity Method Investment Accounting Consideration” (EITF 08-6)
In November 2008, the FASB issued EITF 08-6 to address 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 an equity method investee’s issuance of shares should be accounted for. The EITF concludes that initial carrying value of an equity method investment can be determined using the accumulation model in SFAS 141(R), “Business Combination (revised 2007),” and other-than-temporary impairments should be recognized in accordance with paragraph 19(h) of Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”
This EITF is effective for ACE beginning January 1, 2009. ACE is currently evaluating the impact on its accounting and disclosures.
FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP FAS 132(R)-1)
In December 2008, the FASB issued FSP FAS 132(R)-1 to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The required disclosures under this FSP would expand current disclosures under SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits-an amendment of FASB Statements No. 87, 88, and 106,” to be in line with SFAS No. 157 required disclosures.
The disclosures are to provide users an understanding of the investment allocation decisions made, factors used in the investment policies and strategies, plan assets by major investment types, inputs and valuation techniques used to measure fair value of plan assets, significant concentration of risk within the plan, and the effects of fair value measurement using significant unobservable inputs (Level 3 as defined by SFAS No. 157) on changes in plan assets for the period.
The new disclosures are required starting with financial statement reporting periods ending December 31, 2009 for ACE and earlier application is permitted. Comparative disclosures under this provision are not required for earlier periods presented. ACE is currently evaluating the impact on its disclosures.
(5) SEGMENT INFORMATION
In accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” ACE has one segment, its regulated utility business.
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(6) REGULATORY ASSETS AND REGULATORY LIABILITIES
The components of ACE’s regulatory asset balances at December 31, 2008 and 2007 are as follows:
The components of ACE’s regulatory liability balances at December 31, 2008 and 2007 are as follows:
A description for each category of regulatory assets and regulatory liabilities follows:
Securitized Stranded Costs: Represents stranded costs associated with a non-utility generator contract termination payment and the discontinuance of the application of SFAS No. 71 for ACE’s electricity generation business. 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 received on these deferrals with the exception of taxes.
Deferred Income Taxes: Represents a receivable from our customers for tax benefits ACE has previously flowed through before the company was ordered to provide deferred income taxes. As the temporary differences between the financial statement and tax basis of assets reverse, the deferred recoverable balances are reversed. There is no return 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 received on these deferrals.
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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 on this deferral.
Unrecovered Purchased Power Contract Costs: Represents deferred costs related to purchase power contracts at ACE, which are being recovered from July 1994 through May 2014 and which earn a return.
Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years and generally do not receive a return.
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 on these deferrals.
Deferred Energy Supply Costs: The regulatory liability primarily represents deferred costs associated with a net over-recovery by ACE connected with the provision of Default Electricity Supply costs and other restructuring related costs incurred by ACE. A return is generally received 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 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 on ACE’s Consolidated Balance Sheets 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 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 are being 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 is no return on these deferrals.
(7) LEASING ACTIVITIES
ACE leases certain types of property and equipment for use in its operations. Rental expense for operating leases was $9 million, $10 million and $12 million for the years ended December 31, 2008, 2007 and 2006, respectively.
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Total future minimum operating lease payments for ACE as of December 31, 2008 are $4 million in 2009, $9 million in 2010, $1 million in 2011, $1 million in 2012, $1 million in 2013, and $21 million after 2013.
(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 Sheet includes its proportionate share of assets and liabilities related to jointly owned plant. ACE has ownership interests in transmission facilities, and other facilities in which various parties have ownership interests. ACE’s proportionate share of operating and maintenance expenses of the jointly owned plant is included in the corresponding expenses in ACE’s Consolidated Statements of Earnings. ACE is responsible for providing its share of financing for the jointly owned facilities. Information with respect to ACE’s share of jointly owned plant as of December 31, 2008 is shown below.
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Asset Sales
As discussed in Note (16), “Discontinued Operations,” in the third quarter of 2006, ACE completed the sale of its interests in the Keystone and Conemaugh generating facilities for approximately $175 million (after giving effect to post-closing adjustments). In the first quarter of 2007, ACE completed the sale of the B.L. England generating facility for a price of $9 million. In February 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 2008, 2007, and 2006, ACE was responsible for $12 million, $11 million and $14 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings. In 2008 and 2007, ACE made no contributions to the PHI Retirement Plan, and $7 million and $7 million, respectively to other postretirement benefit plans. At December 31, 2008 and 2007, ACE’s prepaid pension expense of $6 million and $8 million, and other postretirement benefit obligation of $41 million and $38 million, effectively represent assets and benefit obligations resulting from ACE’s participation in the Pepco Holdings benefit plan. ACE expects to contribute approximately $60 million to the pension plan in 2009.
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(10) DEBT
LONG-TERM DEBT
Long-term debt outstanding as of December 31, 2008 and 2007 is presented below.
(a)
Represents a series of First Mortgage Bonds issued by ACE 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 First Mortgage Bonds issued by ACE as collateral for an outstanding series of senior notes as described in footnote (a) above 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.
(c)
The insured auction rate tax-exempt bonds were repurchased by ACE at par due to the disruption in the credit markets. The bonds are considered extinguished for accounting purposes; however, ACE intends to remarket or reissue the bonds to the public in 2009.
The outstanding First Mortgage Bonds issued by ACE are subject to a lien on substantially all of ACE’s property, plant and equipment.
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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, 2008, that will mature in each of 2009 through 2013 and thereafter is as follows: $32 million in 2009, $35 million in 2010, $35 million in 2011, $37 million in 2012, $108 million in 2013, and $798 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, 2008 and 2007 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 a $500 million credit facility, described below under the heading “Credit Facility,” shared with PHI’s other utility subsidiaries, Potomac Electric Power Company (Pepco) and Delmarva Power & Light Company (DPL).
ACE had no commercial paper outstanding at December 31, 2008 and $29 million of commercial paper outstanding at December 31, 2007. The weighted average interest rates for commercial paper issued during 2008 and 2007 were 3.12 % and 5.45%, respectively. The weighted average maturity for commercial paper issued during 2008 and 2007 was four days and three days, respectively.
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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. ACE expects the bonds submitted for purchase will continue to 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 VRDB as a source of long-term financing. During 2008, in accordance with their terms, $22 million of VRDB were tendered to the bond trustee under a Standby Bond Purchase Agreement (SBPA) that was created at the time of issuance to provide liquidity for the bondholders. If market conditions are favorable, ACE intends to remarket these bonds during 2009. The VRDB outstanding in 2008 mature as follows: 2014 ($18 million) and 2017 ($5 million). The weighted average interest rate for VRDB was 3.29 % and 3.59% during 2008 and 2007, respectively.
Credit Facility
PHI, Pepco, DPL and ACE maintain a credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under this primary 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. All indebtedness incurred under the facility is unsecured.
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 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
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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.
As a result of severe liquidity constraints in the credit, commercial paper and capital markets during September 2008, ACE borrowed $135 million under the $1.5 billion credit facility. Typically, ACE issues commercial paper if required to meet its short-term working capital requirements. Given the lack of liquidity in the commercial paper markets, ACE borrowed under the credit facility to maintain sufficient cash on hand to meet daily short-term operating needs. At December 31, 2008, ACE had no borrowings under the facility.
(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 as part of Pepco’s acquisition of Conectiv on August 1, 2002. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.
The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred income tax liabilities (assets) are shown below.
Provision for Consolidated Income Taxes
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Reconciliation of Consolidated Income Tax Rate
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 FIN 48 (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 FIN 48 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.
FIN 48, “Accounting for Uncertainty in Income Taxes”
As disclosed in Note (2), “Significant Accounting Policies,” ACE adopted FIN 48 effective January 1, 2007. Upon adoption, ACE recorded an immaterial adjustment to retained earnings representing the cumulative effect of the change in accounting principle. Also upon adoption, ACE had $28 million of unrecognized tax benefits and $3 million of related accrued interest.
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
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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, in accordance with FIN 48, 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, 2008, 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, 2008 and 2007, ACE recognized $24 million of interest income before tax ($14 million after-tax) and $2 million of interest income before tax ($1 million after-tax), respectively, as a component of income tax expense. As of December 31, 2008 and 2007, ACE had $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 and the obligation becomes certain. See Note (14), “Commitments and Contingencies,” herein for additional information.
Tax Years Open to Examination
ACE, as an indirect subsidiary of PHI, is included on PHI’s consolidated federal tax return. ACE’s federal income tax liabilities for all years through 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 noted above.
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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 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, 2008 and 2007.
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 normalized over the remaining service lives of the related assets.
Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below. These amounts relate to the Power Delivery business and are recoverable through rates.
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(12) PREFERRED STOCK
The preferred stock amounts outstanding as of December 31, 2008 and 2007 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. In addition, ACE has authority to issue up to 2 million shares of No Par Preferred Stock and 3 million shares of Preference Stock without par value.
(13) FAIR VALUE DISCLOSURES
Effective January 1, 2008, ACE adopted SFAS No. 157, as discussed earlier in Note (3), which established a framework for measuring fair value and expands disclosures about fair value measurements.
As defined in SFAS No. 157, 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. SFAS No. 157 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 defined by SFAS No. 157 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
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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.
The following table sets 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, 2008. As required by SFAS No. 157, 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.
The estimated fair values of ACE’s financial instruments at December 31, 2008 and 2007 are shown below.
The methods and assumptions below were used to estimate, at December 31, 2008 and 2007, the fair value of each class of financial instruments shown above for which it is practicable to estimate a value.
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The fair values of the Long-term Debt, which includes First Mortgage Bonds, Medium-Term Notes, and Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on current market prices, or for issues with no market price available, were based on discounted cash flows using current rates for similar issues with similar terms and remaining maturities.
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
Rate Proceedings
On August 18, 2008, ACE submitted an application with FERC for incentive rate treatments in connection with PHI’s 230-mile, 500-kilovolt Mid-Atlantic Power Pathway transmission project. The application requested that FERC include ACE’s Construction Work in Progress in its transmission rate base, an ROE adder of 150 basis points (for a total ROE of 12.8%) and the recovery of prudently incurred costs in the event the project is abandoned or terminated for reasons beyond ACE’s control. On October 31, 2008, FERC issued an order approving the application.
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. RC Cape May has commenced an arbitration proceeding against Citgo seeking a determination that the TSA remains in effect and has notified ACE of the proceeding. The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo. While ACE believes that it has defenses to the indemnification claim, should the arbitrator rule that the TSA has terminated, the outcome of this matter is uncertain. ACE notified RC Cape May of its intent to participate in the pending arbitration. The arbitration hearings were conducted in November 2008. A decision is expected late in the second quarter of 2009, after the filing of post-hearing memoranda in the first quarter of 2009.
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,
ACE
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 United States 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. 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. 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 filed a proof of claim in the Lenox bankruptcy case in February 2009. 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.
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. ACE believes that its responsibility at the site will not have a material adverse effect on its financial position, results of operations or cash flows.
Franklin Slag Pile Superfund Site. On November 26, 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile Superfund 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 the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under
ACE
CERCLA. The EPA’s letter also states that to date its 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, such 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 such claims made by the EPA. At this time ACE cannot predict how EPA will proceed or what portion, if any, of the Franklin Slag Pile Site response costs EPA would seek to recover from ACE.
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, which took effect November 5, 2007, 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 and that is otherwise regulated under a number of other state and federal programs. ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey on November 3, 2008. See Item I “Business - Environmental Matters- Air Quality Regulation - Sulfur Dioxide, Nitrogen Oxide, Mercury and Nickel Emissions.”
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 ACE to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions generated incremental tax cash flow benefits of approximately $49 million for ACE, primarily attributable to ACE’s 2001 tax returns.
In 2005, the Treasury Department issued proposed regulations that, if adopted in their current form, would require ACE to change its method of accounting with respect to capitalizable construction costs for income tax purposes for tax periods beginning in 2005. Based on those proposed regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believed would be acceptable to the Internal Revenue Service (IRS).
At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which was intended to limit the ability of certain taxpayers to utilize the method of accounting for income tax purposes they utilized on their tax returns for 2004 and prior years with respect to capitalizable construction costs. In line with this Revenue Ruling, the IRS revenue agent’s report for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that ACE had claimed on those returns by requiring it to capitalize and depreciate certain expenses rather than treat such expenses as current deductions. PHI’s protest of the IRS adjustments is among the unresolved audit matters relating to the 2001 and 2002 audits pending before the Appeals Office of the IRS.
ACE
In February 2006, PHI paid approximately $121 million of taxes to cover the amount of additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, adopted on its 2005 tax return. In June 2008, PHI received from the IRS an offer of settlement pertaining to ACE for the tax years 2001 through 2004. ACE is substantially in agreement with this proposed settlement. Based on the terms of the proposal, ACE expects the final settlement amount to be less than the $121 million previously deposited.
On the basis of the tentative settlement, ACE updated its estimated liability related to mixed service costs and, as a result, recorded in the quarter ended June 30, 2008, a net reduction in its liability for unrecognized tax benefits of $2 million and recognized after-tax interest income of $2 million.
Contractual Obligations
As of December 31, 2008, ACE’s contractual obligations under non-derivative fuel and power purchase contracts were $275 million in 2009, $ 500 million in 2010 to 2011, $461 million in 2012 to 2013, and $2,196 million in 2014 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, 2008, 2007 and 2006 were $88 million, $81 million and $79 million, respectively.
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 Earnings:
(a)
Included in fuel and purchased energy expense.
(b)
Included in other operation and maintenance expense.
ACE
As of December 31, 2008 and 2007, ACE had the following balances due (to)/from related parties:
(16) DISCONTINUED OPERATIONS
As discussed in Note (14), “Commitments and Contingencies,” herein, in February 2007, ACE completed the sale of the B.L. England generating facility. B.L. England comprised a significant component of ACE’s generation operations and its sale required discontinued operations presentation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets,” on ACE’s Consolidated Statements of Earnings for the years ended December 31, 2007 and 2006. In September 2006, ACE sold its interests in the Keystone and Conemaugh generating facilities, which for the year ended December 31, 2006 is also reflected as discontinued operations.
The following table summarizes information related to the discontinued operations presentation (millions of dollars):
Operating Revenue
$ -
$10
$114
Income Before Income Tax Expense
$ -
$ -
$ 4
Net Income
$ -
$ -
$ 2
ACE
(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, differences between summer and winter rates, and the scheduled downtime and maintenance of electric generating units. Therefore, comparisons by quarter within a year are not meaningful.
(a)
Includes $4 million of after-tax net interest income on uncertain tax positions primarily related to casualty losses.
(b)
Includes $2 million of after-tax interest income related to the tentative settlement of the IRS mixed service cost issue.
(c)
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).
(d)
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.
(e)
Includes adjustment related to timing of recognition of certain operating expenses which were overstated by $5 million in the fourth quarter and understated by $1 million and $4 million in the second and third quarters, respectively.
THIS PAGE LEFT INTENTIONALLY BLANK.
Item 9.
Item 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None for all registrants.
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, 2008, 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 Item 8 of this Form 10-K.
Attestation Report of the Registered Public Accounting Firm
See “Report of Independent Registered Public Accounting Firm” in Item 8 of this Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2008, 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.
Item 9A(T). CONTROLS AND PROCEDURES
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, 2008, 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 Item 8 of this Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2008, 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, 2008, 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 Item 8 of this Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2008, 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, 2008, 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 Item 8 of this Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2008, 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 appearing in PHI’s definitive proxy statement for the 2009 Annual Meeting, which is expected to be filed with the SEC on or about March 26, 2009, is incorporated herein by reference:
·
The information appearing under the heading “Nominees for Election as Directors.”
·
The information appearing under the heading “Security Ownership of Certain Beneficial Owners and Management - Section 16(a) Beneficial Ownership Reporting Compliance.”
·
The information appearing under the heading “Where do I find the Company’s Corporate Business Policies, Corporate Governance Guidelines and Committee Charters?” concerning PHI’s Corporate Business Policies.
·
The information appearing under the heading “Board Committees - Audit Committee,” regarding the membership and function of the Audit Committee and the financial expertise of its members.
Executive Officers of PHI
The names of the executive officers of PHI and their ages and the positions they held as of March 1, 2009, are set forth in the following table. Their business experience during the past five years is set forth in the footnotes to the table.
PEPCO HOLDINGS
Name
Age
Office and
Length of Service
Dennis R. Wraase
Chairman of the Board
5/04 - Present (1)
William T. Torgerson
Vice Chairman - 6/03 - Present and Chief Legal Officer
3/08 - Present (2)
Joseph M. Rigby
President - 3/08 - Present and Chief Executive Officer
3/09 - Present (3)
David M. Velazquez
Executive Vice President
3/09 - Present (4)
Paul H. Barry
Senior Vice President and Chief Financial Officer
9/07 - Present (5)
Kirk J. Emge
Senior Vice President and General Counsel
3/08 - Present (6)
Anthony J. Kamerick
Senior Vice President and Chief Regulatory Officer
3/09 - Present (7)
Beverly L. Perry
Senior Vice President
10/02 - Present
Ronald K. Clark
Vice President and Controller
8/05 - Present (8)
Gary J. Morsches
President and Chief Executive Officer, Conectiv Energy Holding Company
3/09 - Present (9)
John U. Huffman
President - 6/06 - Present and Chief Executive Officer, Pepco Energy Services, Inc. - 3/09 - Present (10)
(1)
Mr. Wraase was Chief Executive Officer of PHI from May 2004 until February 28, 2009, President of PHI from August 2002 until March 2008 and Chief Operating Officer of PHI from August 2002 until June 2003. Mr. Wraase was Chairman of Pepco from May 2004 until February 28, 2009 and was Chief Executive Officer from August 2002 until October 2005. From May 2004 to February 28, 2009, he was also Chairman of DPL and ACE.
(2)
Mr. Torgerson was General Counsel of PHI from August 2002 until March 2008.
(3)
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.
(4)
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.
(5)
Mr. Barry was Senior Vice President and Chief Development Officer of Duke Energy Corporation from September 2006 to August 2007. From November 2005 to September 2006, he was Group Executive and President of Duke Energy Americas, a division of Duke Energy Corporation. From June 2002 to November 2005, he was a Vice President of Duke Energy Corporation. Duke Energy is an energy company not affiliated with PHI.
(6)
Mr. Emge was Vice President, Legal Services 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.
(7)
Mr. Kamerick was Vice President and Treasurer of PHI from August 2002 until February 28, 2009.
(8)
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.
(9)
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.
(10)
Since June 2003, Mr. Huffman has been employed by Pepco Energy Services in the following capacities: (a) Chief Operating Officer from April 2006 to February 28, 2009, (b) Senior Vice President, February 2005 to March 2006 and (c) Vice President from June 2003 to February 2005.
The PHI executive officers are elected annually and serve until their respective successors have been elected and qualified or their 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 appearing in PHI’s definitive proxy statement for the 2009 Annual Meeting, which is expected to be filed with the SEC on or about March 26, 2009, is incorporated herein by reference:
·
The information appearing under the heading “2008 Director Compensation.”
·
The information appearing under the heading “Compensation Discussion and Analysis.”
·
The information appearing under the heading “Executive Compensation.”
·
The information appearing 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 appearing under the heading “Security Ownership of Certain Beneficial Owners and Management” in PHI’s definitive proxy statement for the 2009 Annual Meeting, which is expected to be filed with the SEC on or about March 26, 2009, is incorporated herein by reference.
The following table provides information as of December 31, 2008, with respect to the shares of PHI’s common stock that may be issued under PHI’s existing equity compensation plans.
(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, 2008, options to purchase an aggregate of 374,904 shares of PHI common stock, having a weighted average exercise price of $22.2647, 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 appearing under the heading “Board Review of Transactions With Related Parties” in PHI’s definitive proxy statement for the 2009 Annual Meeting, which is expected to be filed with the SEC on or about March 26, 2009, 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, Inc., 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 2008 and 2007 fiscal years, reviews of the financial statements included in the 2008 and 2007 Forms 10-Q of Pepco Holdings and its subsidiary reporting companies, reviews of public filings, comfort letters and other attest services were $7,780,994 and $6,143,733, respectively. The amount for 2007 includes $69,325 for the 2007 audit that was billed after the 2007 amount was disclosed in Pepco Holding’s proxy statement for the 2008 Annual Meeting.
Audit-Related Fees
No fees were billed by PricewaterhouseCoopers LLP for audit-related services for the 2008 or 2007 fiscal years.
Tax Fees
The aggregate fees billed by PricewaterhouseCoopers LLP for tax services rendered for the 2008 and 2007 fiscal years were $284,678 and $126,810 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 2008 and
fiscal years were $4,500 and $41,740, 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 is attached as Annex A to Pepco Holdings’ definitive proxy statement for the 2009 Annual Meeting of Shareholders to be filed with the SEC on or about March 26, 2009, and is incorporated herein by reference.
Part IV
Item 15.
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents List
1. FINANCIAL STATEMENTS
The financial statements filed as part of this report consist of the financial statements of each registrant set forth in Item 8, “Financial Statements and Supplementary Data” of this Form 10-K.
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 Item 8, “Financial Statements and Supplementary Data” of this Form 10-K.
Schedule I, Condensed Financial Information of Parent Company is submitted below.
The accompanying Notes are an integral part of these financial statements.
The accompanying Notes are an integral part of these financial statements.
The accompanying Notes are an integral part of these financial statements.
NOTES TO FINANCIAL INFORMATION
These condensed financial statements represent the financial information for Pepco Holdings, Inc. (Parent Company).
For information concerning PHI’s long-term debt obligations, see Note (11), “Debt” to the consolidated financial statements of Pepco Holdings included in Item 8 of this Form 10-K.
For information concerning PHI’s material contingencies and guarantees, see Note (16), “Commitments and Contingencies” to the consolidated financial statements of Pepco Holdings included in Item 8 of this Form 10-K.
The Parent Company’s majority owned subsidiaries are recorded using the equity method of accounting.
Schedule II (Valuation and Qualifying Accounts) for each registrant is submitted below:
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.
(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.
Exhibit
No.
Registrant(s)
Description of Exhibit
Reference
3.1
PHI
Restated Certificate of Incorporation (filed in Delaware 6/2/2005)
Exh. 3.1 to PHI’s Form 10-K, 3/13/06.
3.2
Pepco
Restated Articles of Incorporation and Articles of Restatement (as filed in the District of Columbia)
Exh. 3.1 to Pepco’s Form 10-Q, 5/5/06.
3.3
DPL
Articles of Restatement of Certificate and Articles of Incorporation (filed in Delaware and Virginia 02/22/07)
Exh. 3.3 to DPL’s Form 10-K, 3/1/07.
3.4
ACE
Restated Certificate of Incorporation (filed in New Jersey 8/09/02)
Exh. B.8.1 to PHI’s Amendment No. 1 to Form U5B, 2/13/03.
3.5
PHI
Bylaws
Exh. 3 to PHI’s Form 8-K, 5/3/07.
3.6
Pepco
By-Laws
Exh. 3.1 to Pepco’s Form 10-Q, 5/5/06.
3.7
DPL
Bylaws
Exh. 3.2.1 to DPL’s Form 10-Q 5/9/05.
3.8
ACE
Bylaws
Exh. 3.2.2 to ACE’s Form 10-Q 5/9/05.
4.1
PHI
Pepco
Mortgage and Deed of Trust dated July 1, 1936, of Pepco to The Bank of New York Mellon as successor trustee, securing First Mortgage Bonds of Pepco, and Supplemental Indenture dated July 1, 1936
Exh. B-4 to First Amendment, 6/19/36, to Pepco’s Registration Statement No. 2-2232.
Supplemental Indentures, to the aforesaid Mortgage and Deed of Trust, dated -
December 10, 1939
Exh. B to Pepco’s Form 8-K, 1/3/40.
July 15, 1942
Exh. B-1 to Amendment No. 2, 8/24/42, and B-3 to Post-Effective Amendment, 8/31/42, to Pepco’s Registration Statement No. 2-5032.
October 15, 1947
Exh. A to Pepco’s Form 8-K, 12/8/47.
December 31, 1948
Exh. A-2 to Pepco’s Form 10-K, 4/13/49.
December 31, 1949
Exh. (a)-1 to Pepco’s Form 8-K, 2/8/50.
February 15, 1951
Exh. (a) to Pepco’s Form 8-K, 3/9/51.
February 16, 1953
Exh. (a)-1 to Pepco’s Form 8-K, 3/5/53.
March 15, 1954 and March 15, 1955
Exh. 4-B to Pepco’s Registration Statement No. 2-11627, 5/2/55.
March 15, 1956
Exh. C to Pepco’s Form 10-K, 4/4/56.
April 1, 1957
Exh. 4-B to Pepco’s Registration Statement No. 2-13884, 2/5/58.
May 1, 1958
Exh. 2-B to Pepco’s Registration Statement No. 2-14518, 11/10/58.
May 1, 1959
Exh. 4-B to Amendment No. 1, 5/13/59, to Pepco’s Registration Statement No. 2-15027.
May 2, 1960
Exh. 2-B to Pepco’s Registration Statement No. 2-17286, 11/9/60.
April 3, 1961
Exh. A-1 to Pepco’s Form 10-K, 4/24/61.
May 1, 1962
Exh. 2-B to Pepco’s Registration Statement No. 2-21037, 1/25/63.
May 1, 1963
Exh. 4-B to Pepco’s Registration Statement No. 2-21961, 12/19/63.
April 23, 1964
Exh. 2-B to Pepco’s Registration Statement No. 2-22344, 4/24/64.
May 3, 1965
Exh. 2-B to Pepco’s Registration Statement No. 2-24655, 3/16/66.
June 1, 1966
Exh. 1 to Pepco’s Form 10-K, 4/11/67.
April 28, 1967
Exh. 2-B to Post-Effective Amendment No. 1 to Pepco’s Registration Statement No. 2-26356, 5/3/67.
July 3, 1967
Exh. 2-B to Pepco’s Registration Statement No. 2-28080, 1/25/68.
May 1, 1968
Exh. 2-B to Pepco’s Registration Statement No. 2-31896, 2/28/69.
June 16, 1969
Exh. 2-B to Pepco’s Registration Statement No. 2-36094, 1/27/70.
May 15, 1970
Exh. 2-B to Pepco’s Registration Statement No. 2-38038, 7/27/70.
September 1, 1971
Exh. 2-C to Pepco’s Registration Statement No. 2-45591, 9/1/72.
June 17, 1981
Exh. 2 to Amendment No. 1 to Pepco’s Form 8-A, 6/18/81.
November 1, 1985
Exh. 2B to Pepco’s Form 8-A, 11/1/85.
September 16, 1987
Exh. 4-B to Pepco’s Registration Statement No. 33-18229, 10/30/87.
May 1, 1989
Exh. 4-C to Pepco’s Registration Statement No. 33-29382, 6/16/89.
May 21, 1991
Exh. 4 to Pepco’s Form 10-K, 3/27/92.
May 7, 1992
Exh. 4 to Pepco’s Form 10-K, 3/26/93.
September 1, 1992
Exh. 4 to Pepco’s Form 10-K, 3/26/93.
November 1, 1992
Exh. 4 to Pepco’s Form 10-K, 3/26/93.
July 1, 1993
Exh. 4.4 to Pepco’s Registration Statement No. 33-49973, 8/11/93.
February 10, 1994
Exh. 4 to Pepco’s Form 10-K, 3/25/94.
February 11, 1994
Exh. 4 to Pepco’s Form 10-K, 3/25/94.
March 10, 1995
Exh. 4.3 to Pepco’s Registration Statement No. 33-61379, 7/28/95.
October 2, 1997
Exh. 4 to Pepco’s Form 10-K, 3/26/98.
November 17, 2003
Exhibit 4.1 to Pepco’s Form 10-K, 3/11/04.
March 16, 2004
Exh. 4.3 to Pepco’s Form 8-K, 3/23/04.
May 24, 2005
Exh. 4.2 to Pepco’s Form 8-K, 5/26/05.
April 1, 2006
Exh. 4.1 to Pepco’s Form 8-K, 4/17/06.
November 13,
Exh. 4.2 to Pepco’s Form 8-K, 11/15/07.
March 24, 2008
Exh. 4.1 to Pepco’s Form 8-K, 3/28/08.
December 3, 2008
Exh. 4.2 to Pepco’s Form 8-K, 12/8/08.
4.2
PHI
Pepco
Indenture, dated as of July 28, 1989, between Pepco and The Bank of New York Mellon, Trustee, with respect to Pepco’s Medium-Term Note Program
Exh. 4 to Pepco’s Form 8-K, 6/21/90.
4.3
PHI
Pepco
Senior Note Indenture dated November 17, 2003 between Pepco and The Bank of New York Mellon
Exh. 4.2 to Pepco’s Form 8-K, 11/21/03.
Supplemental Indenture, to the aforesaid Senior Note Indenture, dated March 3,
Filed herewith.
4.4
PHI
DPL
Mortgage and Deed of Trust of Delaware Power & Light Company to The Bank of New York Mellon (ultimate successor to the New York Trust Company), as trustee, dated as of October 1, 1943 and copies of the First through Sixty-Eighth Supplemental Indentures thereto
Exh. 4-A to DPL’s Registration Statement No. 33-1763, 11/27/85.
Sixty-Ninth Supplemental Indenture
Exh. 4-B to DPL’s Registration Statement No. 33-39756, 4/03/91.
Seventieth through Seventy-Fourth Supplemental Indentures
Exhs. 4-B to DPL’s Registration Statement No. 33-24955, 10/13/88.
Seventy-Fifth through Seventy-Seventh Supplemental Indentures
Exhs. 4-D, 4-E & 4-F to DPL’s Registration Statement No. 33-39756, 4/03/91.
Seventy-Eighth and Seventy-Ninth Supplemental Indentures
Exhs. 4-E & 4-F to DPL’s Registration Statement No. 33-46892, 4/1/92.
Eightieth Supplemental Indenture
Exh. 4 to DPL’s Registration Statement No. 33-49750, 7/17/92.
Eighty-First Supplemental Indenture
Exh. 4-G to DPL’s Registration Statement No. 33-57652, 1/29/93.
Eighty-Second Supplemental Indenture
Exh. 4-H to DPL’s Registration Statement No. 33-63582, 5/28/93.
Eighty-Third Supplemental Indenture
Exh. 99 to DPL’s Registration Statement No. 33-50453, 10/1/93.
Eighty-Fourth through Eighty-Eighth Supplemental Indentures
Exhs. 4-J, 4-K, 4-L, 4-M & 4-N to DPL’s Registration Statement No. 33-53855, 1/30/95.
Eighty-Ninth and Ninetieth Supplemental Indentures
Exhs. 4-K & 4-L to DPL’s Registration Statement No. 333-00505, 1/29/96.
Ninety-Fifth Supplemental Indenture
Exh. 4-K to DPL’s Post Effective Amendment No. 1 to Registration Statement No. 333-145691-02, 11/18/08
4.5
PHI
DPL
Indenture between DPL and The Bank of New York Mellon Trust Company, N.A. (ultimate successor to Manufacturers Hanover Trust Company), as trustee, dated as of November 1, 1988
Exh. No. 4-G to DPL’s Registration Statement No. 33-46892, 4/1/92.
4.6
PHI
ACE
Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic City Electric Company and The Bank of New York Mellon (formerly Irving Trust Company), as trustee
Exh. 2(a) to ACE’s Registration Statement No. 2-66280, 12/21/79.
Supplemental Indentures, to the aforesaid Mortgage and Deed of Trust, dated as of -
June 1, 1949
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
July 1, 1950
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
November 1, 1950
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
March 1, 1952
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
January 1, 1953
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
March 1, 1954
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
March 1, 1955
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
January 1, 1957
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
April 1, 1958
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
April 1, 1959
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
March 1, 1961
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
July 1, 1962
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
March 1, 1963
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
February 1, 1966
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
April 1, 1970
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
September 1, 1970
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
May 1, 1971
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
April 1, 1972
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
June 1, 1973
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
January 1, 1975
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
May 1, 1975
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
December 1, 1976
Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
January 1, 1980
Exh. 4(e) to ACE’s Form 10-K, 3/25/81.
May 1, 1981
Exh. 4(a) to ACE’s Form 10-Q, 8/10/81.
November 1, 1983
Exh. 4(d) to ACE’s Form 10-K, 3/30/84.
April 15, 1984
Exh. 4(a) to ACE’s Form 10-Q, 5/14/84.
July 15, 1984
Exh. 4(a) to ACE’s Form 10-Q, 8/13/84.
October 1, 1985
Exh. 4 to ACE’s Form 10-Q, 11/12/85.
May 1, 1986
Exh. 4 to ACE’s Form 10-Q, 5/12/86.
July 15, 1987
Exh. 4(d) to ACE’s Form 10-K, 3/28/88.
October 1, 1989
Exh. 4(a) to ACE’s Form 10-Q for quarter ended 9/30/89.
March 1, 1991
Exh. 4(d)(1) to ACE’s Form 10-K, 3/28/91.
May 1, 1992
Exh. 4(b) to ACE’s Registration Statement 33-49279, 1/6/93.
January 1, 1993
Exh. 4.05(hh) to ACE’s Registration Statement 333-108861, 9/17/03
August 1, 1993
Exh. 4(a) to ACE’s Form 10-Q, 11/12/93.
September 1, 1993
Exh. 4(b) to ACE’s Form 10-Q, 11/12/93.
November 1, 1993
Exh. 4(c)(1) to ACE’s Form 10-K, 3/29/94.
June 1, 1994
Exh. 4(a) to ACE’s Form 10-Q, 8/14/94.
October 1, 1994
Exh. 4(a) to ACE’s Form 10-Q, 11/14/94.
November 1, 1994
Exh. 4(c)(1) to ACE’s Form 10-K, 3/21/95.
March 1, 1997
Exh. 4(b) to ACE’s Form 8-K, 3/24/97.
April 1, 2004
Exh. 4.3 to ACE’s Form 8-K, 4/6/04.
August 10, 2004
Exh. 4 to PHI’s Form 10-Q, 11/8/04.
March 8, 2006
Exh. 4 to ACE’s Form 8-K, 3/17/06.
November 6, 2008
Exh. 4.2 to ACE’s Form 8-K, 11/10/08.
4.7
PHI
ACE
Indenture dated as of March 1, 1997 between Atlantic City Electric Company and The Bank of New York Mellon, as trustee
Exh. 4(e) to ACE’s Form 8-K, 3/24/97.
4.8
PHI
ACE
Senior Note Indenture, dated as of April 1, 2004, with The Bank of New York Mellon, as trustee
Exh. 4.2 to ACE’s Form 8-K, 4/6/04.
4.9
PHI
ACE
Indenture dated as of December 19, 2002 between Atlantic City Electric Transition Funding LLC (ACE Funding) and The Bank of New York Mellon, as trustee
Exh. 4.1 to ACE Funding’s Form 8-K, 12/23/02.
4.10
PHI
ACE
2002-1 Series Supplement dated as of December 19, 2002 between ACE Funding and The Bank of New York Mellon, as trustee
Exh. 4.2 to ACE Funding’s Form 8-K, 12/23/02.
4.11
PHI
ACE
2003-1 Series Supplement dated as of December 23, 2003 between ACE Funding and The Bank of New York Mellon, as trustee
Exh. 4.2 to ACE Funding’s Form 8-K, 12/23/03.
4.12
PHI
Indenture between PHI and The Bank of New York Mellon, as trustee dated September 6,
Exh. 4.03 to PHI’s Registration Statement No. 333-100478, 10/10/02.
10.1
PHI
Employment Agreement of Dennis R. Wraase dated July 26, 2007*
Exh. 10.3 to PHI’s Form 10-Q, 8/6/07.
10.2
PHI
Employment Agreement of William T. Torgerson dated August 1, 2002*
Exh. 10.3 to PHI’s Form 10-Q, 8/9/02.
10.3
PHI
Employment Agreement of Paul H. Barry dated August 7, 2007*
Exh. 10 to PHI’s Form 8-K, 8/13/07.
10.4
PHI
Employment Agreement of Joseph M. Rigby dated August 1, 2008*
Exh. 10.1 to PHI’s Form 8-K, 7/30/08.
10.5
PHI
Pepco Holdings, Inc. Long-Term Incentive Plan*
Filed herewith.
10.6
PHI
Pepco Holdings, Inc. Executive and Director Deferred Compensation Plan*
Filed herewith.
10.7
PHI
Pepco
Potomac Electric Power Company Director and Executive Deferred Compensation Plan*
Exh. 10.22 to PHI’s Form 10-K, 3/28/03.
10.8
PHI
Pepco
Potomac Electric Power Company Long-Term Incentive Plan*
Exh. 4 to Pepco’s Form S-8, 6/12/98.
10.9
PHI
Conectiv Incentive Compensation Plan*
Exh. 99(e) to Conectiv’s Registration Statement No. 333-18843, 12/26/96.
10.10
PHI
Conectiv Supplemental Executive Retirement Plan*
Filed herewith.
10.11
ACE
Bondable Transition Property Sale Agreement between ACE Funding and ACE dated as of December 19, 2002
Exh. 10.1 to ACE Funding’s Form 8-K, 12/23/02.
10.12
ACE
Bondable Transition Property Servicing Agreement between ACE Funding and ACE dated as of December 19, 2002
Exh. 10.2 to ACE Funding’s Form 8-K, 12/23/02.
10.13
PHI
Conectiv Deferred Compensation Plan*
Exh. 10.1 to PHI’s Form 10-Q, 8/6/04.
10.14
PHI
Form of Employee Nonqualified Stock Option Agreement*
Exh. 10.2 to PHI’s Form 10-Q, 11/8/04.
10.15
PHI
Form of Director Nonqualified Stock Option Agreement*
Exh. 10.3 to PHI’s Form 10-Q, 11/8/04.
10.16
PHI
Form of Election Regarding Payment of Director Retainer/Fees*
Exh. 10.4 to PHI’s Form 10-Q, 11/8/04.
10.17
PHI
Form of Executive and Director Deferred Compensation Plan Executive Deferral Agreement*
Exh. 10.5 to PHI’s Form 10-Q, 11/8/04.
10.18
PHI
Form of Executive Incentive Compensation Plan Participation Agreement*
Exh. 10.6 to PHI’s Form 10-Q, 11/8/04.
10.19
PHI
Form of Restricted Stock Agreement*
Exh. 10.7 to PHI’s Form 10-Q, 11/8/04.
10.20
PHI
Form of Election with Respect to Stock Tax Withholding*
Exh. 10.8 to PHI’s Form 10-Q, 11/8/04.
10.21
PHI
Non-Management Directors Compensation Plan*
Filed herewith.
10.22
PHI
Annual Executive Incentive Compensation Plan dated as of February 9, 2009*
Filed herewith.
10.23
PHI
Non-Management Director Compensation Arrangements*
Exh. 10-24 to PHI’s Form 10-K, 2/29/08.
10.24
PHI
Form of Election regarding Non-Management Directors Compensation Plan*
Exh. 10.57 to PHI’s Form 10-K, 3/16/05.
10.25
PHI
Pepco
Change-in-Control Severance Plan for Certain Executive Employees*
Filed herewith.
10.26
PHI
Pepco
PHI Named Executive Officer 2007 Compensation Determinations*
Exh. 10.32 to PHI’s Form 10-K, 2/29/08.
10.27
PHI
Pepco
DPL
ACE
Amended and Restated Credit Agreement, dated as of May 2, 2007, between PHI, Pepco, DPL and ACE, the lenders party thereto, Wachovia Bank, National Association, as administrative agent and swingline lender, Citicorp USA, Inc., as syndication agent, The Royal Bank of Scotland, plc, The Bank of Nova Scotia and JPMorgan Chase Bank, N.A., as documentation agents, and Wachovia Capital Markets, LLC and Citigroup Global Markets Inc., as joint lead arrangers and joint book runners
Exh. 10 to PHI’s Form 10-Q, 5/7/07.
10.28
PHI
Pepco Holdings, Inc. Combined Executive Retirement Plan*
Filed herewith.
10.29
PHI
PHI Named Executive Officer 2008 Compensation Determinations*
Exh. 10.33 to PHI’s Form 10-K, 2/29/08.
10.30
PHI
PHI Named Executive Officer 2009 Compensation Determinations*
Filed herewith.
10.31
DPL
Transmission Purchase and Sale Agreement By and Between Delmarva Power & Light Company and Old Dominion Electric Cooperative dated as of June 13,
Exh. 10.1 to DPL’s Form 10-Q, 8/6/07.
10.32
DPL
Purchase And Sale Agreement By and Between Delmarva Power & Light Company and A&N Electric Cooperative dated as of June 13, 2007
Exh. 10.2 to DPL’s Form 10-Q, 8/6/07.
10.33
DPL
PHI
Loan Agreement, dated as of March 20, 2008, between DPL and The Bank of Nova Scotia
Exh. 10.1 to DPL’s Form 8-K, 3/24/08.
10.34
Pepco
PHI
Loan Agreement, dated as of May 1, 2008, between Pepco and Wachovia Bank, National Association
Exh. 10.1 to Pepco’s Form 8-K, 5/6/08.
10.35
PHI
Amendment to Employment Agreement of Dennis R. Wraase effective August 1, 2008*
Exh. 10.2 to PHI’s Form 8-K, 7/30/08.
10.36
PHI
Amendment to Employment Agreement of William T. Torgerson effective August 1, 2008*
Filed herewith.
10.37
PHI
Credit Agreement, dated November 7, 2008, by and among Bank of America, N.A., Banc of America Securities, KeyBank National Association, JPMorgan Chase Bank, N.A., SunTrust Bank, The Bank of Nova Scotia, Morgan Stanley Bank, Credit Suisse, Cayman Islands Branch and Wachovia Bank, National Association
Filed herewith.
PHI
Statements Re: Computation of Earnings Per Common Share
**
12.1
PHI
Statements Re: Computation of Ratios
Filed herewith.
12.2
Pepco
Statements Re: Computation of Ratios
Filed herewith.
12.3
DPL
Statements Re: Computation of Ratios
Filed herewith.
12.4
ACE
Statements Re: Computation of Ratios
Filed herewith.
PHI
Subsidiaries of the Registrant
Filed herewith.
23.1
PHI
Consent of Independent Registered Public Accounting Firm
Filed herewith.
23.2
Pepco
Consent of Independent Registered Public Accounting Firm
Filed herewith.
23.3
DPL
Consent of Independent Registered Public Accounting Firm
Filed herewith.
23.4
ACE
Consent of Independent Registered Public Accounting Firm
Filed herewith.
31.1
PHI
Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
Filed herewith.
31.2
PHI
Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
Filed herewith.
31.3
Pepco
Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
Filed herewith.
31.4
Pepco
Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
Filed herewith.
31.5
DPL
Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
Filed herewith.
31.6
DPL
Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
Filed herewith.
31.7
ACE
Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
Filed herewith.
31.8
ACE
Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
Filed herewith.
* 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 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:
Exhibit No.
Registrant(s)
Description of Exhibit
32.1
PHI
Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.2
Pepco
Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.3
DPL
Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.4
ACE
Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
(b) Exhibits
Exhibit 12.1 Statements Re. Computation of Ratios
PEPCO HOLDINGS, INC.
(a)
Excludes income/losses on equity investments.
(b)
Concurrent with the adoption of FIN 48 in 2007, amount includes interest on uncertain tax positions.
Exhibit 12.2 Statements Re. Computation of Ratios
POTOMAC ELECTRIC POWER COMPANY
(a)
Concurrent with the adoption of FIN 48 in 2007, amount includes interest on uncertain tax positions.
Exhibit 12.3 Statements Re. Computation of Ratios
DELMARVA POWER & LIGHT COMPANY
(a)
Concurrent with the adoption of FIN 48 in 2007, amount includes interest on uncertain tax positions.
Exhibit 12.4 Statements Re. Computation of Ratios
ATLANTIC CITY ELECTRIC COMPANY
(a)
Concurrent with the adoption of FIN 48 in 2007, amount includes interest on uncertain tax positions.
Exhibit 21 Subsidiaries of the Registrants
Name of Company
Jurisdiction of
Incorporation or
Organization
Pepco Holdings, Inc.
DE
Potomac Electric Power Company
D.C. & VA
Gridco International LLC (Dissolved 10/8/2008)
DE
POM Holdings, Inc.
DE
Microcell Corporation
NC
Pepco Energy Services, Inc.
DE
Pepco Building Services Inc.
DE
W.A. Chester, L.L.C.
DE
W.A. Chester Corporation
DE
Chester Transmission Construction Canada, Inc.
Canada
Severn Construction Services, LLC
DE
Chesapeake HVAC, Inc. (f/k/a Unitemp, Inc.)
DE
Conectiv Thermal Systems, Inc.
DE
ATS Operating Services, Inc.
DE
Atlantic Jersey Thermal Systems, Inc.
DE
Thermal Energy Limited Partnership I
DE
Eastern Landfill Gas, LLC
DE
Blue Ridge Renewable Energy, LLC
DE
Distributed Generation Partners, LLC
DE
Rolling Hills Landfill Gas, LLC
DE
Potomac Power Resources, LLC
DE
Fauquier Landfill Gas, L.L.C.
DE
Pepco Energy Services - Suez Thermal, LLC (f/k/a Trigen-Pepco Energy Services, LLC)
DC
Pepco Government Services LLC
DE
Pepco Enterprises, Inc.
DE
Electro Ecology, Inc.
NY
Pepco Energy Cogeneration LLC
DE
Bethlehem Renewable Energy, LLC
DE
Potomac Capital Investment Corporation
DE
PCI Netherlands Corporation
NV
PCI Queensland LLC (f/k/a PCI Queensland Corporation)
NV
AMP Funding, LLC
DE
RAMP Investments, LLC
DE
PCI Air Management Partners, LLC
DE
PCI Ever, Inc.
DE
Friendly Skies, Inc.
Virgin Islands
PCI Air Management Corporation
NV
American Energy Corporation
DE
PCI-BT Investing, LLC
DE
Linpro Harmans Land LTD Partnership
MD
Potomac Nevada Corporation
NV
Potomac Delaware Leasing Corporation
DE
Potomac Equipment Leasing Corporation
NV
Potomac Leasing Associates, LP
DE
Potomac Nevada Leasing Corporation
NV
PCI Engine Trading, Ltd.
Bermuda
Potomac Capital Joint Leasing Corporation
DE
PCI Nevada Investments
DE
PCI Holdings, Inc.
DE
Aircraft International Management Company
DE
PCI-DB Ventures
DE
Potomac Nevada Investment, Inc.
NV
PCI Energy Corporation
DE
PHI Service Company
DE
Conectiv
DE
Delmarva Power & Light Company
DE & VA
Atlantic City Electric Company
NJ
Atlantic City Electric Transition Funding LLC
DE
Conectiv Properties and Investments, Inc.
DE
DCTC-Burney, Inc.
DE
Conectiv Solutions LLC
DE
ATE Investment, Inc.
DE
King Street Assurance Ltd. (Dissolved 1/22/08)
Bermuda
Enertech Capital Partners, LP
DE
Enertech Capital Partners II, LP
DE
Black Light Power, Inc.
DE
Millennium Account Services, LLC
DE
Conectiv Services, Inc.
DE
Atlantic Generation, Inc.
NJ
Vineland Limited, Inc.
DE
Vineland Cogeneration Limited Partnership
DE
Vineland General, Inc.
DE
Pedrick Gen., Inc.
NJ
Project Finance Fund III, LP
DE
Conectiv Communications, Inc.
DE
Atlantic Southern Properties, Inc.
NJ
Conectiv Energy Holding Company
DE
ACE REIT, Inc.
DE
Conectiv Atlantic Generation, LLC
DE
Conectiv Bethlehem LLC
DE
Conectiv Delmarva Generation, LLC
DE
Conectiv Pennsylvania Generation, LLC
DE
Conectiv Energy Supply, Inc.
DE
Conectiv North East, LLC
DE
Energy Systems North East, LLC
DE
Delta, LLC
DE
Conectiv Mid Merit, LLC
DE
Delaware Operating Services Company
DE
PHI Operating Services Company
DE
Tech Leaders II, LP
DE
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-145691 and 333-129429) and the Registration Statements on Form S-8 (Nos. 333-96675, 333-121823 and 333-131371) of Pepco Holdings, Inc. of our report dated March 2, 2009 for Pepco Holdings, Inc. relating to the financial statements, financial statement schedules and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Washington, DC
March 2,
Exhibit 23.2
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-145691-03) of Potomac Electric Power Company of our report dated March 2, 2009 relating to the financial statements and financial statement schedule of Potomac Electric Power Company, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Washington, DC
March 2,
Exhibit 23.3
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-145691-02) of Delmarva Power & Light Company of our report dated March 2, 2009 relating to the financial statements and financial statement schedule of Delmarva Power & Light Company, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Washington, DC
March 2,
Exhibit 23.4
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-145691-01) of Atlantic City Electric Company of our report dated March 2, 2009 relating to the financial statements and financial statement schedule of Atlantic City Electric Company, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Washington, DC
March 2,
Exhibit 31.1
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.
I have reviewed this report on Form 10-K of Pepco Holdings, Inc.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, 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;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: March 2, 2009
/s/ JOSEPH M. RIGBY
Joseph M. Rigby
President and
Chief Executive Officer
Exhibit 31.2
CERTIFICATION
I, Paul H. Barry, certify that:
1.
I have reviewed this report on Form 10-K of Pepco Holdings, Inc.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, 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;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: March 2, 2009
/s/ PAUL H. BARRY
Paul H. Barry
Senior Vice President and
Chief Financial Officer
Exhibit 31.3
CERTIFICATION
I, David M. Velazquez, certify that:
1.
I have reviewed this report on Form 10-K of Potomac Electric Power Company.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, 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;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: March 2, 2009
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Exhibit 31.4
CERTIFICATION
I, Paul H. Barry, certify that:
1.
I have reviewed this report on Form 10-K of Potomac Electric Power Company.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, 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;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: March 2, 2009
/s/ PAUL H. BARRY
Paul H. Barry
Senior Vice President and
Chief Financial Officer
Exhibit 31.5
CERTIFICATION
I, David M. Velazquez, certify that:
1.
I have reviewed this report on Form 10-K of Delmarva Power & Light Company.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, 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;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: March 2, 2009
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Exhibit 31.6
CERTIFICATION
I, Paul H. Barry, certify that:
1.
I have reviewed this report on Form 10-K of Delmarva Power & Light Company.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, 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;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: March 2, 2009
/s/ PAUL H. BARRY
Paul H. Barry
Senior Vice President and
Chief Financial Officer
Exhibit 31.7
CERTIFICATION
I, David M. Velazquez, certify that:
1.
I have reviewed this report on Form 10-K of Atlantic City Electric Company.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, 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;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: March 2, 2009
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Exhibit 31.8
CERTIFICATION
I, Paul H. Barry, certify that:
1.
I have reviewed this report on Form 10-K of Atlantic City Electric Company.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, 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;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: March 2, 2009
/s/ PAUL H. BARRY
Paul H. Barry
Chief Financial Officer
Exhibit 32.1
Certificate of Chief Executive Officer and Chief Financial Officer
of
Pepco Holdings, Inc.
(pursuant to 18 U.S.C. Section 1350)
I, Joseph M. Rigby, and I, Paul H. Barry, certify that, to the best of my knowledge, (i) the Report on Form 10-K of Pepco Holdings, Inc. for the year ended December 31, 2008, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Pepco Holdings, Inc.
March 2, 2009
/s/ JOSEPH M. RIGBY
Joseph M. Rigby
President and
Chief Executive Officer
March 2, 2009
/s/ PAUL H. BARRY
Paul H. Barry
Senior Vice President and
Chief Financial Officer
A signed original of this written statement required by Section 906 has been provided to Pepco Holdings, Inc. and will be retained by Pepco Holdings, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32.2
Certificate of Chief Executive Officer and Chief Financial Officer
of
Potomac Electric Power Company
(pursuant to 18 U.S.C. Section 1350)
I, David M. Velazquez, and I, Paul H. Barry, certify that, to the best of my knowledge, (i) the Report on Form 10-K of Potomac Electric Power Company for the year ended December 31, 2008, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Potomac Electric Power Company.
March 2, 2009
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
March 2, 2009
/s/ PAUL H. BARRY
Paul H. Barry
Senior Vice President and
Chief Financial Officer
A signed original of this written statement required by Section 906 has been provided to Potomac Electric Power Company and will be retained by Potomac Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32.3
Certificate of Chief Executive Officer and Chief Financial Officer
of
Delmarva Power & Light Company
(pursuant to 18 U.S.C. Section 1350)
I, David M. Velazquez, and I, Paul H. Barry, certify that, to the best of my knowledge, (i) the Report on Form 10-K of Delmarva Power & Light Company for the year ended December 31, 2008, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Delmarva Power & Light Company.
March 2, 2009
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
March 2, 2009
/s/ PAUL H. BARRY
Paul H. Barry
Senior Vice President and
Chief Financial Officer
A signed original of this written statement required by Section 906 has been provided to Delmarva Power & Light Company and will be retained by Delmarva Power & Light Company and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32.4
Certificate of Chief Executive Officer and Chief Financial Officer
of
Atlantic City Electric Company
(pursuant to 18 U.S.C. Section 1350)
I, David M. Velazquez, and I, Paul H. Barry, certify that, to the best of my knowledge, (i) the Report on Form 10-K of Atlantic City Electric Company for the year ended December 31, 2008, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Atlantic City Electric Company.
March 2, 2009
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
March 2, 2009
/s/ PAUL H. BARRY
Paul H. Barry
Chief Financial Officer
A signed original of this written statement required by Section 906 has been provided to Atlantic City Electric Company and will be retained by Atlantic City Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.
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.
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:
Signature
Title
Date
/s/ J. B. DUNN
Director, Pepco Holdings
March 2, 2009
Jack B. Dunn, IV
/s/ T. C. GOLDEN
Director, Pepco Holdings
March 2, 2009
Terence C. Golden
/s/ FRANK O. HEINTZ
Director, Pepco Holdings
March 2, 2009
Frank O. Heintz
/s/ BARBARA J. KRUMSIEK
Director, Pepco Holdings
March 2, 2009
Barbara J. Krumsiek
/s/ GEORGE F. MacCORMACK
Director, Pepco Holdings
March 2, 2009
George F. MacCormack
/s/ RICHARD B. McGLYNN
Director, Pepco Holdings
March 2, 2009
Richard B. McGlynn
/s/ LAWRENCE C. NUSSDORF
Director, Pepco Holdings
March 2, 2009
Lawrence C. Nussdorf
/s/ FRANK ROSS
Director, Pepco Holdings
March 2, 2009
Frank K. Ross
/s/ PAULINE A. SCHNEIDER
Director, Pepco Holdings
March 2, 2009
Pauline A. Schneider
/s/ LESTER P. SILVERMAN
Director, Pepco Holdings
March 2, 2009
Lester P. Silverman
/s/ WILLIAM T. TORGERSON
Director, Pepco Holdings
March 2, 2009
William T. Torgerson
/s/ D. R. WRAASE
Director, Pepco Holdings
March 2, 2009
Dennis R. Wraase
/s/ KIRK J. EMGE
Director, Pepco and DPL
March 2, 2009
Kirk J. Emge
/s/ WILLIAM GAUSMAN
Director, Pepco
March 2, 2009
William M. Gausman
/s/ MICHAEL J. SULLIVAN
Director, Pepco
March 2, 2009
Michael J. Sullivan
/s/ STANLEY A. WISNIEWSKI
Director, Pepco
March 2, 2009
Stanley A. Wisniewski