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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electricity and natural gas delivery (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 (the Exchange Act):
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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 (Conectiv Energy) and Pepco Energy Services, Inc. (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 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 the service company are charged to PHI and the participating operating subsidiaries in accordance with costing methodologies set forth in the service agreement.
For financial information relating to PHI’s segments, see Note (3), “Segment Information,” to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K. Each of Pepco, DPL and ACE has one operating segment.
Investor Information
Each of PHI, Pepco, DPL and ACE files reports under the Exchange Act. 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. A minor portion of the Power Delivery business consists of the supply and distribution of natural gas. In 2007, 2006 and 2005, respectively, PHI’s Power Delivery operations produced 56%, 61%, and 58% of PHI’s consolidated operating revenues (including revenue from intercompany transactions) and 66%, 67%, and 74% 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 and Natural Gas and Default Electricity Supply
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 local regulatory agency. 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
Provider of Last Resort service - before May 1,
Standard Offer Service (SOS) - on and after May 1,
District of Columbia SOS
Maryland
SOS
New Jersey
Basic Generation Service (BGS)
Virginia
Default Service
In this Form 10-K, these supply service obligations 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 sole provider of transmission service in the PJM RTO region, which today 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 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, as the tariff administrator, collects transmission service revenue from transmission service customers and distributes the revenue to the transmission owners. PJM also oversees the planning process for the enhancement and expansion of transmission capability on a regional basis within the PJM RTO region. PJM approval is required for transmission upgrades and enhancements undertaken by member utilities.
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
The Power Delivery business is seasonal and weather patterns can have a material impact on operating performance. In the region served by PHI, 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. Historically, the Power Delivery operations of each of PHI’s utility subsidiaries have generated higher revenues and income when temperatures are colder than normal in the winter and warmer than normal in the summer, and conversely revenues and income typically are lower when the temperature is warmer than normal in the winter and cooler than normal in the summer. 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 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 for other reasons as a factor having an impact on reported revenue and income.
Regulation
The retail operations of PHI’s utility subsidiaries, including the rates they are permitted to charge customers for the delivery of electricity and, in the case of DPL, 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 operations on January 2, 2008, were regulated in Virginia by the Virginia State Corporation Commission.
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DPL’s natural gas distribution operations in Delaware are regulated by the DPSC.
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ACE’s electricity delivery operations are regulated by the New Jersey Board of Public Utilities (NJBPU).
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The transmission and wholesale sale of electricity by each of PHI’s utility subsidiaries are regulated by FERC.
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The interstate transportation and wholesale sale of natural gas by DPL are regulated by FERC.
Pepco
Pepco is engaged in the transmission, distribution and default supply of electricity in Washington, D.C. and major portions of Prince George’s and Montgomery Counties 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, 2007, Pepco delivered electricity to 760,000 customers (of which 241,800 were located in the District of Columbia and 518,200 were located in Maryland), as compared to 753,000 customers as of December 31, 2006 (of which 240,960 were located in the District of Columbia and 512,040 were located in Maryland).
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. In 2006, Pepco delivered a total of 26,488,000 megawatt hours of electricity, of which 29% was delivered to residential customers, 51% to commercial customers, and 20% to United States and District of Columbia government customers.
Pepco has been providing SOS in Maryland since July 2004. Pursuant to 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 2009. Pepco also has an ongoing obligation to provide SOS service at hourly priced rates to the largest customers. 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 is entitled to recover from its SOS customers the cost of the SOS supply plus an average margin of $.001667 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 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 for small commercial and residential customers through May 2011 and for large commercial
customers through May 2009. 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 $.00241 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, 2007, 51% of Pepco’s Maryland sales (measured by megawatt hours) were to SOS customers, as compared to 60% in 2006, and 35% of its District of Columbia sales were to SOS customers in 2007, as compared to 57% in 2006.
DPL
DPL is engaged in the transmission, distribution and default supply of electricity in Delaware and portions of Maryland and Virginia (until the sale of its Virginia operations on January 2, 2008). 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 Service Territory,” DPL, on January 2, 2008, completed the sale of substantially all of its Virginia electric service operations.
DPL’s electricity distribution service territory covers approximately 6,000 square miles and has a population of approximately 1.3 million. As of December 31, 2007, DPL delivered electricity to 519,000 customers (of which 298,000 were located in Delaware, 198,000 were located in Maryland, and 23,000 were located in Virginia), as compared to 513,000 electricity customers as of December 31, 2006 (of which 295,000 were located in Delaware, 196,000 were located in Maryland, and 22,000 were located in Virginia).
In 2007, DPL delivered a total of 13,680,000 megawatt hours of electricity to its customers, of which 39% was delivered to residential customers, 40% to commercial customers and 21% to industrial customers. In 2006, DPL delivered a total of 13,477,000 megawatt hours of electricity, of which 38% was delivered to residential customers, 40% to commercial customers and 22% to industrial customers.
DPL has been providing SOS in Delaware since May 2006. Pursuant to orders issued by the DPSC, DPL will continue to be obligated to provide fixed-price SOS to residential, small
commercial and industrial customers through May 2009 and to medium, large and general service customers through May 2008. 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 Hourly Priced Service (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 $2.75 million, plus estimated incremental expenses, a cash working capital allowance, and recovery with a return over five years of the capitalized costs of the billing system used for billing HPS customers. DPL is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to all electricity customers in its Delaware service territory regardless of whether the customer receives SOS or purchases electricity from another energy supplier.
In Delaware, DPL sales to SOS customers represented 54% of total sales (measured by megawatt hours) for the year ended December 31, 2007, as compared to 69% in 2006.
DPL has been providing 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 2009. DPL purchases the power supply required to satisfy its market rate 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 $.001667 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 sales to SOS customers represented 67% of total sales (measured by megawatt hours) for the year ended December 31, 2007, as compared to 75% in 2006.
DPL provided Default Service in Virginia from March 2004 until the sale of its Virginia retail electric business 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 sales to Default Service customers represented 94% of total sales (measured by megawatt hours) for the years ended December 31, 2007 and 2006.
Sale of Virginia Service Territory
On January 2, 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price of
approximately $45.2 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5.4 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 are purchasing (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date. These sales resulted in an immaterial financial gain to DPL that will be recorded during the first quarter of 2008.
Natural Gas Distribution
DPL provides regulated natural gas supply and distribution service to customers in a service territory consisting of a major portion of New Castle County in Delaware. This service territory covers approximately 275 square miles and has a population of approximately 500,000. Large volume commercial, institutional, 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. 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, 2007, DPL supplied 67% of the natural gas that it delivered, compared to 66% in 2006.
As of December 31, 2007, DPL distributed natural gas to 122,000 customers, as compared to 121,000 customers as of December 31, 2006. In 2007, DPL distributed 20,700,000 Mcf (thousand cubic feet) of natural gas to customers in its Delaware service territory, of which 38% were sales to residential customers, 25% to commercial customers, 4% to industrial customers, and 33% to customers receiving a transportation-only service. In 2006, DPL delivered 18,300,000 Mcf of natural gas, of which 36% were sales to residential customers, 25% were sales to commercial customers, 4% were to industrial customers, and 35% were sales to customers receiving a transportation-only service.
ACE
ACE is primarily engaged in the transmission, distribution and default supply of electricity in a service territory consisting of Gloucester, Camden, Burlington, Ocean, Atlantic, Cape May, Cumberland and Salem counties in southern New Jersey. ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.0 million. As of December 31, 2007, ACE delivered electricity to 544,000 customers in its service territory, as compared to 539,000 customers as of December 31, 2006. 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. In 2006, ACE delivered a total of 9,931,000 megawatt hours of electricity to its customers, of which 43% was delivered to residential customers, 44% to commercial customers, and 13% 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 2,270 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 16 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 sales to BGS customers represented 80% of total sales (measured by megawatt hours) for the year ended December 31, 2007 and 78% of total sales (measured by megawatt hours) for the year ended December 31, 2006.
On February 8, 2007, ACE completed the sale of its 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 (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, 2006 and 2005. ACE’s sale of its interests in the Keystone and Conemaugh generating facilities in September 2006 is also reflected as discontinued operations on ACE’s consolidated statements of earnings for the years ended December 31, 2006 and 2005.
ACE has several contracts with non-utility generators (NUGs) under which ACE purchased 3.8 million megawatt hours of power in 2007. 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
PHI’s Competitive Energy business is engaged in the generation of electricity and the non-regulated marketing and supply of electricity and natural gas, and related energy management services, primarily in the mid-Atlantic region. In 2007, 2006 and 2005 PHI’s Competitive Energy operations produced 48%, 43%, and 48%, respectively, of PHI’s consolidated operating revenues. In 2007, 2006 and 2005 PHI’s Competitive Energy operations produced 26%, 20%, and 16%, respectively, of PHI’s consolidated operating income. PHI’s Competitive Energy operations are conducted by Conectiv Energy and Pepco Energy Services which are separate operating segments for financial reporting purposes.
Conectiv Energy
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 also supplies electric power to Pepco, DPL and ACE to satisfy a portion of their Default Electricity Supply load, as well as default electricity supply load shares of other utilities within PJM RTO and the ISONE wholesale markets. PHI refers to these activities as Merchant Generation & Load Service. Other than its default electricity supply sales, Conectiv Energy does not participate in the retail competitive power supply market. Conectiv Energy obtains the electricity required to meet its power supply obligations from its own generating plants, under bilateral contracts entered into with other wholesale market participants and through purchases in the wholesale market.
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, 2007, Conectiv Energy owned and operated mid-merit plants with a combined 2,725 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.” In addition to the generation plants it owns, Conectiv Energy controls another nominal 480 megawatts of capacity through tolling agreements.
On December 14, 2007, Conectiv Energy announced a decision to construct a 545 MW natural gas and oil-fired combined-cycle electricity generation plant to be located in Peach Bottom Township, Pennsylvania. 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 1, 2011 through May 31, 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.
Conectiv Energy also sells natural gas and fuel oil to very large end-users and to wholesale market participants under bilateral agreements and 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 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.
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 and known minimum cash flows, and lock in favorable prices and margins when they become available. To a lesser extent, Conectiv Energy also engages in energy marketing activities. 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 prior to October 31, 2006, provided operating services under an agreement with an unaffiliated generating plant. PHI collectively refers to these energy marketing activities, including its commodity risk management activities, as “other energy commodity” activities and identifies this activity separately from the proprietary trading activity that was discontinued in 2003.
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 the CRMC 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.”
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. and the Chicago, Illinois area. As of December 31, 2007, Pepco Energy Services’ estimated retail electricity backlog was 31.8 million MWh for
delivery through 2013, an increase of 2% over December 31, 2006. Pepco Energy Services also sells natural gas to customers primarily located in the mid-Atlantic region.
Pepco Energy Services also provides energy savings performance contracting services principally to federal, state and local government customers, and owns and operates district energy systems in Atlantic City, New Jersey and Wilmington, Delaware and sells steam and chilled water to customers in those cities. Pepco Energy Services also designs, constructs, and operates combined heat and power and central energy plants.
In addition, Pepco Energy Services provides high voltage construction and maintenance services to utilities throughout the United States and low voltage electric and telecommunication construction and maintenance services to utilities and other commercial customers and streetlight asset management services to municipalities in the Washington, D.C. area.
During 2006, Pepco Energy Services sold five businesses that served primarily commercial and industrial customers by providing heating, ventilation, air conditioning, electrical testing and maintenance, and building automation services. Net assets sold were approximately $20.7 million.
Pepco Energy Services also 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 MW. See Item 2 “Properties.” 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 MW. 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 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.
PJM Capacity Markets
One of the sources of revenue of the Competitive Energy Business is the sale of capacity by Conectiv Energy and Pepco Energy Services associated with their respective generating facilities. The wholesale market for capacity 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 obligation. This capacity can be obtained through the ownership of generation facilities, the entry into bilateral contracts or the purchase of capacity credits in the auctions administered by PJM. All of the generating facilities owned by PHI’s 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 four auctions, each covering capacity to be supplied over consecutive 12-month periods beginning June 1, 2007. Each of these auctions has yielded higher prices for capacity than in the period preceding implementation of RPM. 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 1, 2011 through May 31, 2012, will take place in May 2008.
In addition to participating in the PJM auctions, PHI’s 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 primarily located 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 of services offered to customers and quality of service.
Seasonality
Like the Power Delivery business, 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. Energy management services generally are not seasonal.
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, 2007 of approximately $1.4 billion. For additional information concerning these cross-border lease transactions, see Note (12), “Commitments and Contingencies,” to the consolidated financial statements of PHI included in Item 8 “Financial Statements and Supplementary Data”
and Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” This activity constitutes a separate operating segment for financial reporting purposes, which is designated “Other Non-Regulated.”
EMPLOYEES
At December 31, 2007, PHI had 5,131 employees, including 1,365 employed by Pepco, 916 employed by DPL, 507 employed by ACE and 1,805 employed by PHI Service Company. The balance were employed by PHI’s Competitive Energy and other non-regulated businesses. Approximately 2,666 employees (including 1,060 employed by Pepco, 741 employed by DPL, 363 employed by ACE, 344 employed by PHI Service Company, and 158 employed by Conectiv Energy) 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 by its subsidiaries are $51.3 million in 2008 and $43.9 million in 2009. 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 and regulations.
The projected capital expenditures for 2008 and 2009 include $38 million and $19.2 million, respectively, of expenditures to comply with multipollutant regulations adopted by the Delaware Department of Natural Resources and Environmental Control (DNREC). Conectiv Energy has appealed these regulations, as described below. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources and Liquidity -- Capital Requirements -- Compliance with Delaware Multipollutant Regulations”. The $57.2 million in expected expenditures in 2008 and 2009 for compliance with the multipollutant regulations is only a portion of the total capital expenditures of $79 million, which PHI currently estimates will be necessary for multipollutant regulation compliance over the long term.
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
Among other things, 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 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 purchased in the open market as necessary to achieve compliance with these regulations.
In 2005, the U.S. Environmental Protection Agency (EPA) issued its Clean Air Interstate Rule (CAIR), which imposes additional 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 2010 for SO2. States may implement CAIR by adopting EPA’s trading program or through regulations that at a minimum achieve the 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. These regulations may require installation of pollution control devices and/or fuel modifications for generating units owned by Conectiv Energy and Pepco Energy Services.
The states in which PHI subsidiaries own and operate generating units have adopted, or are in the process of adopting, regulations to implement CAIR which will require, beginning in 2009, the surrender of a NOx annual allowance for each ton of NOx emitted during the year and, beginning in 2010, will require the surrender of more than one SO2 allowance for each ton of SO2 emitted. To implement CAIR, the New Jersey Department of Environmental Protection (NJDEP) in June 2007 adopted a new NOx trading program that will replace the existing NOx trading program in 2009. This new trading program will allocate NOx annual and NOx ozone season allowances to Conectiv Energy’s Carll’s Corner, Cedar, Middle, Mickleton, Cumberland and Sherman generating units, and will operate in a manner similar to NJDEP’s existing 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 is expected to promulgate CAIR regulations in 2008 that will be applicable to Conectiv Energy’s Bethlehem generating units and the generating units being constructed in Peach Bottom Township, Pennsylvania, known as the Delta Project. Virginia will implement CAIR by participating in EPA’s cap and trade program and Conectiv Energy’s Tasley peaking unit will be subject to CAIR requirements. Conectiv Energy’s Maryland generating units are smaller 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 will be subject to CAIR requirements. However, it is not yet certain whether the District will adopt a state implementation plan or whether the District will rely on the federal
program. Pepco Energy Services’ Buzzard Point generating units and its landfill gas generating units will not be subject to CAIR.
Conectiv Energy and Pepco Energy Services units will use NOx annual, NOx ozone season and SO2 allowances allocated or purchased in the open market as necessary 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 operation of the affected generating units.
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 initiated a monitoring program at the Deepwater generating facility, its only coal-fired generating plant in New Jersey, in order to show compliance with NJDEP’s mercury regulations.
On November 15, 2006, DNREC adopted 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 multipollutant regulations establish stringent short-term emission limits for emissions of NOx, SO2 and mercury, and for Edge Moor’s residual oil-fired generating unit, impose more stringent sulfur in fuel limits and establish stringent short-term emission limits for NOx emissions. The regulations also cap annual 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. Compliance with the regulations will require the installation of new pollution control equipment and/or the enhancement of existing equipment, and may require the imposition of restrictions on the operation of those units. Conectiv Energy submitted a compliance plan for its facilities to DNREC in June 2007. Conectiv Energy estimates that it will cost up to $80 million to install the control equipment necessary to comply with the regulations. These estimated costs do not include increased costs associated with operating control equipment. In December 2006, Conectiv Energy filed a complaint with the Delaware Superior Court seeking review of DNREC’s adoption of the regulations. The appeal is pending.
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). Under RGGI, each of the participating states has committed to the adoption of legislation or regulations designed to stabilize and eventually reduce emissions of carbon dioxide CO2 emissions, including the implementation of a regional CO2 budget and allowance trading program to regulate emissions from fossil fuel-fired power plants. The regulations implementing this program are expected to require fossil fuel-fired electric generating units commencing in 2009 to hold CO2 allowances equivalent to their historic baseline CO2 emissions and to reduce CO2 emissions incrementally beginning in 2015 to achieve an overall 10% reduction from baseline by 2019. Each state is permitted to adopt its own regulations and can develop its own allowance allocation/auction mechanisms. Until Delaware, Maryland and New Jersey adopt regulations, PHI will not be in a position to determine whether the allowances allocated to the generating facilities operated by its subsidiaries will be sufficient to cover the CO2 emissions from those facilities, the financial impact of acquiring allowances through auction, or the potential financial and operational consequences of the regulations.
In February 2007, the New Jersey Governor signed an Executive Order which requires New Jersey to reduce its greenhouse gas emissions to 1990 levels by 2020, and 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 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 greenhouse gas emissions monitoring and reporting program to evaluate progress toward the 2020 and 2050 greenhouse gas limits. In January 2008, New Jersey enacted legislation requiring the NJDEP to develop regulations for a trading program for CO2 allowances to be created under RGGI. Regulatory actions in Delaware and Maryland implementing CO2 regulations are expected in 2008.
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. All of the steam generating facilities operated by PHI’s subsidiaries have NPDES permits authorizing their pollutant discharges which are 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. EPA has not yet initiated the additional rulemaking. Petitions for review of the Riverkeeper II decision have been filed with the U.S. Supreme Court by various interested parties. The Supreme Court has not yet determined whether it will hear the appeal. The capital expenditures, if any, that may be needed as a consequence of these regulations will not be known until these proceedings are concluded and until 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. Timely filing of the application for renewal administratively extended the existing permit. The previous NJPDES permit for Deepwater required 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 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, Conectiv Energy asked NJDEP to modify or stay a cooling water intake structure design upgrade requirement in Deepwater’s NJPDES permit, and NJDEP agreed to stay that permit requirement.
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. EPA has not yet issued the revised draft permit. 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.
On November 5, 2007, NJDEP adopted amendments to its regulations under the Flood Hazard Area Control Act (FHACA) to minimize damage to life and property from flooding caused by development in flood plains. The amended regulations impose a new regulatory program to mitigate flooding and related environmental impacts from a broad range of construction and development activities, including electric utility transmission and distribution construction that was previously unregulated under the FHACA and that is otherwise regulated under a number of other state and federal programs. ACE is evaluating whether to appeal the adoption of these regulations to the Appellate Division of the Superior Court of New Jersey. PHI cannot predict at this time the costs of complying with the FHACA regulations due, among other things, to the possibility that NJDEP will issue exemptions from the new regulations.
In September 2007, NJDEP proposed amendments to the agency’s regulations under the Freshwater Wetlands Protection Act (FWPA). PHI believes that these proposed amendments may hinder development of electric transmission and distribution systems by increasing the regulatory obstacles necessary to site public service infrastructure. On December 31, 2007, ACE filed comments concerning the proposed amendments, urging NJDEP not to change the manner in which the FWPA regulations presently apply to utility lines, poles, and other utility property. An accurate estimate of PHI’s compliance costs is not feasible until the regulations are adopted.
In 2002, EPA amended its oil pollution prevention regulations to require facilities, that because of their location could reasonably be expected to discharge oil in quantities that may be harmful to the environment, to amend and implement Spill Prevention, Control, and Countermeasure (SPCC) Plans and Facility Response Plans (FRPs) by February 2003. Since 2002, EPA has provided a number of extensions to the compliance deadline. As a result of those extensions, PHI facilities subject to the regulations must now comply with these regulatory requirements by July 1, 2009. PHI has undertaken an analysis of its facilities to identify equipment/sites for which physical modifications are necessary to reduce the risk of a release of oil and comply with EPA’s SPCC and FRP regulations. Physical modification of facilities through the construction of containment structures or replacement of oil-filled equipment with non-oil-filled equipment is scheduled from 2008 through 2010 with an anticipated cost of approximately $56 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 at certain contaminated sites. See Note (12), Commitments and Contingencies -- Legal Proceedings -- Environmental Litigation” to the consolidated financial statements of PHI included in Item 8. In addition, DPL and ACE have undertaken efforts to remediate currently or formerly owned facilities found to be contaminated, including two former manufactured gas plant sites and other owned property. See Note (12), Commitments and Contingencies -- Legal Proceedings -- Environmental Litigation” to the consolidated financial statements of PHI included in Item 8 and Item 7 “Management’s
Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources and Liquidity -- Capital Requirements -- Environmental Remediation Obligations.”
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.
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 “PHI -- 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 is seasonal and weather patterns can have a material impact on their 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 has generated less revenue and income when temperatures are warmer than normal in the winter and cooler than normal in the summer. 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 by the 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 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 Competitive Energy businesses’ energy management services generally are 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 up to two times the capacity payment price which the generation facility receives. Furthermore, if the company owning the facilities is unable to perform its contractual obligations for any of these reasons, that company, and correspondingly PHI, may incur penalties or damages.
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 sole provider of transmission service in the PJM RTO region, which today 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 statutes, 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 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 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 the 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 upon 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 upon 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 PHI’s Competitive Energy businesses.
Research and development activities are ongoing to improve alternative technologies to produce electricity, including fuel cells, 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 PHI’s 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 PHI’s Competitive Energy businesses. Changes in technology also could alter the channels through which retail electric customers buy electricity, 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 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 PHI’s 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.
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 PHI’s 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 cross-border energy sale-leaseback transactions, which as of December 31, 2007, had a book value of approximately $1.4 billion and from which PHI currently derives approximately $60 million per year in tax benefits in the form of interest and depreciation deductions. On February 11, 2005, the Treasury Department and IRS issued a notice informing taxpayers that the IRS intends to challenge the tax benefits claimed by taxpayers with respect to certain of these transactions.
As part of the normal PHI tax audit for 2001 and 2002, the IRS disallowed the tax benefits claimed by PHI with respect to these leases for those years. The tax benefits claimed by PHI with respect to these leases from 2001 through December 31, 2007 were approximately $347 million. PHI has filed a protest against the IRS adjustments and the unresolved audit has been forwarded to the IRS Appeals Office. If the IRS prevails, PHI would be subject to
additional taxes, along with interest and possibly penalties on the additional taxes, which could have a material adverse effect on PHI’s results of operations and cash flows. 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” for additional information.
Changes in tax law could have a material adverse effect on the tax benefits that PHI realizes from the portfolio of cross-border energy sale-leaseback transactions entered into by one of its subsidiaries.
In recent years, efforts have been made by members of the U.S. Senate to pass legislation that would have the effect of deferring the deduction of losses associated with leveraged lease transactions involving tax-indifferent parties for taxable years beginning after the year of enactment regardless of when the transaction was entered into. These proposals, which would affect transactions such as those included in PCI’s portfolio of cross-border energy leases, would effectively defer the deduction of losses associated with such leveraged lease transactions until the taxable year in which the taxpayer recognized taxable income from the lease, which is typically toward the end of the lease term. To date, no such legislation has been enacted; however, there are continuing efforts by members of the U.S. Senate to add legislation to various Senate bills directed to the deferral or other curtailment of the tax benefits realized from such transactions. Enactment of legislation of this nature could result in a material delay of the income tax benefits that PHI would receive in connection with PCI’s portfolio of cross-border energy leases. Furthermore, if legislation of this type were enacted, under the Financial Accounting Standards Board Staff Position on Financial Accounting Standard 13-2, PHI would be required to adjust the book value of the leases and record a charge to earnings equal to the repricing impact of the deferred deductions which could result in a material adverse effect on PHI’s financial condition, results of operations and cash flows.
IRS Revenue Ruling 2005-53 on Mixed Service Costs could require PHI to incur additional tax and interest payments in connection with the IRS audit of this issue for the tax years 2001 through 2004 (IRS Revenue Ruling 2005-53).
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 future tax periods beginning in 2005. Based on the proposed regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believes will be acceptable to the IRS.
At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which is 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 has filed a protest against the IRS adjustments and the issue is among the unresolved audit matters relating to the 2001 and 2002 audits pending before the Appeals Office.
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. However, if the IRS is successful in requiring Pepco, DPL and ACE to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management’s estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006.
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 each rely on access to both short-term money markets and longer-term capital markets as a source of liquidity and to satisfy their capital requirements not satisfied by the cash flow from their operations. Capital market disruptions, or a downgrade in credit ratings, would increase the cost of borrowing or could adversely affect the ability to access one or more financial markets. In addition, a reduction in PHI’s credit ratings could require PHI or its subsidiaries to post additional collateral in connection with some of the Competitive Energy businesses’ wholesale marketing and financing activities. Disruptions to the capital markets could include, but are not limited to:
·
recession or an economic slowdown;
·
the bankruptcy of one or more energy companies;
·
significant increases in the prices for oil or other fuel;
·
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.
Future defined benefit plan funding obligations are affected by assumptions regarding the valuation of PHI’s benefit obligations and the performance of plan assets; actual experience which varies from the assumptions could result in an obligation of PHI, Pepco, DPL or ACE to make significant unplanned cash contributions to the Retirement Plan.
PHI follows the guidance of SFAS No. 87, “Employers’ Accounting for Pensions” in accounting for pension benefits under its non-contributory defined benefit plan (the PHI Retirement Plan). In addition, on December 31, 2006, PHI 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. In accordance with these accounting standards, PHI makes assumptions regarding the valuation of benefit obligations and the performance of plan assets. Changes in assumptions, such as the use of a different discount rate or expected return on plan assets, affect the calculation of projected benefit obligations (PBO), accumulated benefit obligation (ABO), reported pension liability, regulated assets, or accumulated other comprehensive income on PHI’s consolidated balance sheet and on the balance sheets of Pepco, DPL and ACE, and reported annual net periodic pension benefit cost on PHI’s consolidated statement of earnings and on the statements of earnings of Pepco, DPL and ACE.
Use of alternative assumptions could also impact the expected future cash funding requirements of PHI, Pepco, DPL and ACE for the PHI Retirement Plan if the plan did not meet the minimum funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA).
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 and distinct 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 are indirect wholly owned subsidiaries of PHI, PHI can exercise substantial control over their dividend policies and businesses and operations. (Pepco, DPL and ACE only)
All of the members of each of Pepco’s, DPL’s and ACE’s board of directors, as well as many of 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, 2007.
a
All holdings of Conectiv Energy are owned by its various subsidiaries.
b
These facilities are owned by a subsidiary of Pepco Energy Services. In 2007, a 16 MW combustion turbine at Buzzard Point was deactivated.
c
This facility is owned by Fauquier Landfill Gas, LLC, of which Pepco Energy Services holds a 75% membership interest.
d
This facility is owned by Eastern Landfill Gas, LLC, of which Pepco Energy Services holds a 75% membership interest.
The preceding table sets forth the 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, 2007 consisted of approximately 3,600 transmission circuit miles of overhead lines, 160 transmission circuit miles of underground cables, 22,740 distribution circuit miles of overhead lines, and 19,030 distribution circuit miles of underground cables, primarily in their respective service territories. On January 2, 2008, DPL completed the sale of substantially all of its electric business in Virginia, which included approximately 94.5 transmission circuit miles of overhead lines, .3 transmission circuit miles of underground cables, 534 distribution circuit miles of overhead lines and 291 distribution circuit miles of underground cables. See “Business - Power Delivery - DPL” in Item 1 of this Form 10-K. 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 3.045 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 225,000 Mcf per day. DPL also owns approximately 111 pipeline miles of natural gas transmission mains, 1,777 pipeline miles of natural gas distribution mains, and 1,292 natural gas pipeline miles of service lines. The natural gas transmission mains include 7.2 miles of pipeline of which DPL owns 10%, which is used for natural gas operations, and of which Conectiv Energy owns 90%, which is used 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 (7) “Debt” to the consolidated financial statements of PHI included in Item 8.
Item 3.
Item 3. LEGAL PROCEEDINGS
Pepco Holdings
Other than ordinary routine litigation incidental to its and its subsidiaries’ business, PHI is not a party to, and its and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (12), “Commitments and Contingencies--Legal Proceedings,” to the consolidated financial statements of PHI included in Item 8.
Pepco
Other than ordinary routine 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 (10), “Commitments and Contingencies--Legal Proceedings,” to the financial statements of Pepco included in Item 8.
DPL
Other than ordinary routine 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
(11), “Commitments and Contingencies--Legal Proceedings,” to the financial statements of DPL included in Item 8.
ACE
Other than ordinary routine 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 (11), “Commitments and Contingencies--Legal Proceedings,” to the financial statements of ACE included in Item 8.
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” for information regarding restrictions on the ability of PHI and its subsidiaries to pay dividends.
At December 31, 2007, there were approximately 64,126 holders of record of Pepco Holdings common stock.
Dividends
On January 24, 2008, the Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2008, to shareholders of record March 10, 2008.
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.
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.
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.
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 $33.4 million ($20.0 million after-tax) from settlement of Mirant bankruptcy claims. See “Management’s Discussion and Analysis -- Financial Condition and Results of Operations -- Capital Resources and Liquidity -- Cash Flow Activity -- Proceeds from Settlement of Mirant Bankruptcy Claims.”
(b)
Includes $19.5 million ($17.7 million net of fees) benefit related to Maryland income tax settlement.
(c)
Includes $18.9 million of impairment losses ($13.7 million after-tax) related to certain energy services business assets.
(d)
Includes $12.3 million gain ($7.9 million after-tax) on the sale of Conectiv Energy’s equity interest in a joint venture which owns a wood burning cogeneration facility.
(e)
Includes $68.1 million ($40.7 million after-tax) gain from sale of non-utility land owned by Pepco at Buzzard Point.
(f)
Includes $70.5 million ($42.2 million after-tax) gain (net of customer sharing) from settlement of Mirant bankruptcy claims. See “Management’s Discussion and Analysis -- Financial Condition and Results of Operations -- Capital Resources and Liquidity -- Cash Flow Activity -- Proceeds from Settlement of Mirant Bankruptcy Claims.”
(g)
Includes $13.3 million ($8.9 million after-tax) related to PCI’s liquidation of a financial investment that was written off in 2001.
(h)
Includes $10.9 million in income tax expense related to the mixed service cost issue under IRS Revenue Ruling 2005-53.
(i)
Includes a $19.7 million charge related to an IRS settlement. Also includes $13.2 million tax benefit related to issuance of a local jurisdiction’s final consolidated tax return regulations.
(j)
Includes a charge of $50.1 million ($29.5 million after-tax) related to a CT contract cancellation. Also includes a gain of $68.8 million ($44.7 million after-tax) on the sale of the Edison Place office building.
(k)
Includes the unfavorable impact of $44.3 million ($26.6 million after-tax) resulting from trading losses prior to the cessation of proprietary trading.
(l)
Includes an impairment charge of $102.6 million ($66.7 million after-tax) related to prior investment in Starpower Communications, L.L.C.
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:
THIS PAGE LEFT INTENTIONALLY BLANK.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
PEPCO HOLDINGS, INC.
GENERAL OVERVIEW
In 2007, 2006 and 2005, respectively, PHI’s Power Delivery operations produced 56%, 61%, and 58% of PHI’s consolidated operating revenues (including revenues from intercompany transactions) and 66%, 67%, and 74% 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 electric power, which for 2007, 2006, and 2005, was responsible for 94%, 95%, and 94%, respectively, of Power Delivery’s operating revenues. The distribution of natural gas contributed 6%, 5% and 6% of Power Delivery’s operating revenues in 2007, 2006 and 2005, respectively. Power Delivery represents one operating segment for financial reporting purposes.
The Power Delivery business is conducted by PHI’s three utility subsidiaries: Pepco, DPL and 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 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
Provider of Last Resort service (POLR) - before May 1, 2006
Standard Offer Service (SOS) - on and after May 1, 2006
District of Columbia
SOS
Maryland
SOS
New Jersey
Basic Generation Service (BGS)
Virginia Default Service
In this Form 10-K, these supply service obligations are referred to generally as Default Electricity Supply.
Pepco, DPL and ACE are also responsible for the transmission of wholesale electricity into and across their service territories. The rates each company is permitted to charge for the wholesale transmission of electricity are regulated by the Federal Energy Regulatory Commission (FERC). Transmission rates are updated annually based on a FERC-approved formula methodology.
The profitability of the Power Delivery business depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge.
Power Delivery’s operating results are 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.
Effective June 16, 2007, the Maryland Public Service Commission (MPSC) approved new electric service distribution base rates for Pepco and DPL (the 2007 Maryland Rate Order). The MPSC also approved a bill stabilization adjustment mechanism (BSA) for retail customers. See “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. This change in the reporting of distribution revenue has the effect of eliminating changes in 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 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 business provides 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) and Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), each of which is treated as a separate operating segment for financial reporting purposes. For the years ended December 31, 2007, 2006 and 2005, the operating revenues of the Competitive Energy business (including revenue from intercompany transactions) were equal to 48%, 43%, and 48%, respectively, of PHI’s consolidated operating revenues, and the operating income of the Competitive Energy business (including operating income from intercompany transactions) was 26%, 20%, and 16% of PHI’s consolidated operating income for the years ended December 31, 2007, 2006 and 2005, respectively. For the years ended December 31, 2007, 2006 and 2005, amounts equal to 10%, 13%, and 15% respectively, of the operating revenues of the Competitive Energy business were attributable to electric energy and capacity, and natural gas sold to the Power Delivery segment.
·
Conectiv Energy 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 default electricity supply load shares of other utilities within PJM RTO and ISONE wholesale markets. PHI refers to these activities as Merchant Generation & Load Service. Conectiv Energy obtains the electricity required to meet its Merchant Generation & Load Service power supply obligations from its own generation plants, bilateral contract purchases from other wholesale market participants, and purchases in the wholesale market. Conectiv Energy also sells natural gas and fuel oil to very large end-users and to wholesale market participants under bilateral agreements. PHI refers to these sales operations as Energy Marketing.
·
Pepco Energy Services provides retail energy supply and energy services primarily to commercial, industrial, and governmental customers. Pepco Energy
Services sells electricity and natural gas to customers primarily in the mid-Atlantic region. Pepco Energy Services provides energy-savings performance contracting services, owns and operates two district energy systems, and designs, constructs and operates combined heat and power and central energy plants. Pepco Energy Services provides high voltage construction and maintenance services to customers throughout the U.S. and low voltage electric construction and maintenance services and streetlight asset management services in the Washington, D.C. area and owns and operates electric generating plants in Washington, D.C.
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. 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 business, like the Power Delivery business, is 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, 2007 of approximately $1.4 billion. This activity constitutes a fourth operating segment, which is designated as “Other Non-Regulated,” for financial reporting purposes. For a discussion of PHI’s cross-border leasing transactions, see “Regulatory and Other Matters -- Federal Income Tax Treatment of Cross-Border Leases” in this Management’s Discussion and Analysis.
BUSINESS STRATEGY
PHI’s business strategy is to remain a 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 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 in PJM RTO.
·
Pursuing technologies and practices that promote energy efficiency, energy conservation and the reduction of green house gas emissions.
In furtherance of this business strategy, PHI may from time to time examine a variety of transactions involving its existing businesses, including the entry into joint ventures or the disposition of one or more businesses, as well as possible acquisitions. PHI also may reassess or refine the components of its business strategy as it deems necessary or appropriate in response to
a wide variety of factors, including the requirements of its businesses, competitive conditions and regulatory requirements.
EARNINGS OVERVIEW
Year Ended December 31, 2007 Compared to the Year Ended December 31,
PHI’s net income for the year ended December 31, 2007 was $334.2 million, or $1.72 per share, compared to $248.3 million, or $1.30 per share, for the year ended December 31, 2006.
Net income for the year ended December 31, 2007, included the credits set forth below, which are presented net of federal and state income taxes and are in millions of dollars. The operating segment that recognized the credits is also indicated.
·
Power Delivery
Mirant bankruptcy damage claims settlement
$ 20.0
Maryland income tax settlement, net of fees
$ 17.7
Net income for year ended December 31, 2006, included the credits (charges) set forth below, which are presented net of federal and state income taxes and are in millions of dollars. The operating segment that recognized the credits (charges) is also indicated.
Excluding the items listed above for the years ended December 31, net income would have been $296.5 million, or $1.53 per share, in 2007 and $254.1 million, or $1.33 per share, in 2006.
PHI’s net income for the years ended December 31, 2007 and 2006, by operating segment, is set forth in the table below (in millions of dollars):
Discussion of Operating Segment Net Income Variances:
Power Delivery’s $40.5 million increase in earnings is primarily due to the following:
·
$20.0 million increase due to the recovery of operating expenses and certain other costs associated with the Mirant Corporation (Mirant) bankruptcy damage claims settlement.
·
$17.7 million increase due to the settlement of a Maryland income tax refund claim relating to the divestiture of Pepco generation assets in 2000, net of $1.8 million (after-tax) in professional fees.
·
$24.2 million increase due to the impact of the Maryland distribution base rate increases that became effective June 16, 2007 for Pepco and DPL.
·
$27.5 million increase primarily due to higher distribution sales (favorable impact of weather compared to 2006).
·
$28.4 million decrease due to higher operating and maintenance costs (primarily electric system maintenance, various construction project write-offs related to customer requested work, employee-related costs, regulatory costs and increased bad debts expense). This variance does not include the $1.8 million (after-tax) in professional fees associated with the Maryland income tax refund settlement.
·
$13.7 million decrease primarily due to favorable income tax audit adjustments in 2006.
·
$5.8 million decrease due to lower Default Electricity Supply margins primarily as a result of customers electing to purchase electricity from competitive suppliers and the impact of the Virginia Default Electricity Supply rate cap.
Conectiv Energy’s $25.9 million increase in earnings is primarily due to the following:
·
$40.8 million increase in Merchant Generation & Load Service primarily due to: (i) an increase of approximately $45.3 million due to higher generation output resulting from the favorable impact of weather and improved availability at the Hay Road and Deepwater generating stations and improved spark spreads, and (ii) an increase of approximately $15.3 million due to higher capacity prices due to the implementation of the PJM Reliability Pricing Model; partially offset by (iii) a decrease of approximately $19.8 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 (see discussion under Conectiv Energy Gross Margin below).
·
$7.9 million decrease due to the gain on disposition of assets associated with a co-generation facility in 2006.
·
$6.4 million decrease due to higher plant maintenance costs.
Pepco Energy Services’ $17.8 million increase in earnings is primarily due to the following:
·
$12.4 million increase due to higher impairment losses on certain energy services business assets in 2006.
·
$2.1 million increase from its retail energy supply businesses resulting from $11.6 million increase from its retail electric business due to higher installed capacity prices, higher volumes and more favorable congestion costs in 2007; partially offset by higher gains of $8.4 million on sale of excess electricity supply in 2006, and a $1.1 million decrease from its retail natural gas business due to higher cost of supply in 2007 (see discussion under Pepco Energy Services below).
Other Non-Regulated’s $4.4 million decrease in earnings is primarily due to tax adjustments in 2006 that related to periods prior to the acquisition of Conectiv by Pepco and Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48 (FIN 48) impact in 2007; partially offset by lower interest expense in 2007.
Corporate and Other’s $6.1 million increase in earnings is primarily due to prior year tax audit adjustments (tax benefits recorded by other segments and eliminated in consolidation through Corporate and Other); partially offset by higher interest expense in 2007.
CONSOLIDATED RESULTS OF OPERATIONS
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:
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 transmission and 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.
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 release of excess system capacity.
Electric Operating Revenue
Other Regulated T&D Electric Revenue consists primarily of (i) transmission service revenue received by PHI’s utility subsidiaries from PJM as transmission owners, (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 Order 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).
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, strip 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 $98.6 million primarily due to the following: (i) $43.0 million increase in sales due to higher weather-related sales (a 17% increase in Cooling Degree Days and a 12% increase in Heating Degree Days), (ii) $28.8 million increase 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), (iii) $20.3 million increase due to a 2007 Maryland Rate Order that became effective in June 2007, which includes a positive $4.9 million Revenue Decoupling Adjustment, (iv) $12.1 million increase due to higher pass-through revenue primarily resulting from tax rate increases in the District of Columbia (offset primarily in Other Taxes), (v) $5.2 million increase due to customer growth of 1% in 2007, partially offset by (vi) $10.0 million decrease due to a change in Delaware rate structure effective May 1, 2006, which shifted revenue from Regulated T&D Electric Revenue to Default Supply Revenue, and (vii) $4.0 million decrease 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 under non-utility generating contracts between ACE and unaffiliated third parties (NUGs) in the PJM RTO market.
Default Supply Revenue, which is partially offset in Fuel and Purchased Energy and Other Services Cost of Sales, decreased by $15.0 million primarily due to the following: (i) $345.5 million decrease primarily due to commercial and industrial customers electing to purchase an increased amount of electricity from competitive suppliers, (ii) $94.8 million decrease due to differences in consumption among the various customer rate classes, (iii) $46.3 million decrease 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, (iv) $4.1 million decrease due to a DPL adjustment to reclassify market-priced supply revenue from Regulated T&D Electric Revenue in 2006, partially offset by (v) $379.1 million increase due to annual increases in market-based Default Electricity Supply rates, (vi) $86.6 million increase due to higher weather-related sales (a 17% increase in Cooling Degree Days and a 12% increase in Heating Degree Days), and (vii) $10.0 million increase 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 $5.9 million to $64.2 million in 2007 from $58.3 million in 2006 primarily due to increases in revenue related to pole rentals and late payment fees.
Gas Operating Revenue
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, strip malls, stand alone construction and tourism.
·
Industrial activity in the region includes automotive, chemical and pharmaceutical.
Regulated Gas Revenue increased by $6.5 million primarily due to (i) $11.7 million increase due to colder weather (a 15% increase in Heating Degree Days), (ii) $5.7 million increase due to base rate increases effective in November 2006 and April 2007, (iii) $4.8 million
increase due to differences in consumption among the various customer rate classes, (iv) $2.7 million increase due to customer growth of 1% in 2007, partially offset by (v) $18.4 million decrease due to Gas Cost Rate (GCR) 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 $29.4 million to $80.0 million in 2007 from $50.6 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
The impact of Operating Revenue changes and Fuel and Purchased Energy and Other Services Cost of Sales changes with respect to the Conectiv Energy component of the Competitive Energy business are encompassed within the discussion that follows.
Operating Revenues of the Conectiv Energy segment are derived primarily from the sale of electricity. The primary components of its costs of sales are fuel and purchased power. 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. For this reason, 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) and 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 prior to October 31, 2006, operating services under an agreement with an unaffiliated generating plant. Beginning in 2007, power origination activities, which primarily represent the fixed margin component of structured power transactions such as default electricity supply contracts, have been classified into Energy Marketing from Merchant Generation & Load Service. The 2006 activity has been reclassified for comparative purposes accordingly. Power origination contributed $18.8 million and $18.7 million of gross margin for the years ended December 31, 2007 and 2006, respectively.
Includes $441.5 million and $471.1 million of affiliate transactions for 2007 and 2006, respectively. The 2006 amount has been reclassified to exclude $193.1 million of intra-affiliate transactions that were reported gross in 2006 at the segment level.
Includes $6.7 million and $4.6 million of affiliate transactions for 2007 and 2006, respectively. The 2006 amount has been reclassified to exclude $193.1 million of intra-affiliate transactions that were reported gross in 2006 at the segment level. Also, excludes depreciation and amortization expense of $37.7 million and $36.3 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.
Merchant Generation & Load Service gross margin increased $69.1 million primarily due to:
·
An increase of approximately $76.5 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 $25.9 million due to higher capacity prices due to the implementation of the PJM Reliability Pricing Model.
·
A decrease of $33.4 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 $5.5 million primarily due to:
·
A decrease of $5.2 million due to lower margins in oil marketing.
·
A decrease of $4.0 million due to lower margins in natural gas marketing.
·
An increase of $2.7 million for adjustments related to an unaffiliated generation operating services agreement that expired in 2006.
Pepco Energy Services
Pepco Energy Services’ operating revenue increased $640.2 million, which corresponds with the increase in Fuel and Purchased Energy and Other Services Costs of Sales, to $2,309.1 million in 2007 from $1,668.9 million in 2006 primarily due to (i) increase of $646.0 million due to higher volumes of retail electric load served at higher prices in 2007 driven by customer acquisitions , (ii) increase of $27.4 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, partially offset by (iii) decrease of $32.3 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 $14.4 million to $76.2 million in 2007 from $90.6 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 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 $56.1 million primarily due to: (i) $445.2 million increase in average energy costs, the result of new annual Default Electricity Supply contracts, (ii) $93.0 million increase due to an increase in weather-related sales, (iii) $28.8 million increase for energy and capacity purchased under the Panda PPA (offset in T&D Electric Revenue), partially offset by (iv) $472.2 million decrease primarily due to commercial and industrial customers electing to purchase an increased amount of electricity from competitive suppliers, and (v) $36.4 million decrease in the Default Electricity Supply deferral balance. Fuel and Purchased Energy expense is primarily offset in Default Supply Revenue, Regulated Gas Revenue or 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 $630.6 million primarily due to (i) an increase of $635.7 million due to higher volumes of purchased electricity at higher prices in 2007 to serve increased retail customer load (ii) an increase of $39.9 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, partially offset by (iii) a decrease of $44.6 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 $27.4 million; however, excluding the favorable variance of $34.2 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 $61.6 million. The $61.6 million increase was primarily due to (i) $15.7 million increase in employee-related costs, (ii) $10.6 million increase in preventative maintenance and system operation costs, (iii) $6.8 million increase in customer service operation expenses, (iv) $4.4 million increase in costs associated with Default Electricity Supply (primarily deferred and recoverable), (v) $3.5 million increase in regulatory expenses, (vi) $3.5 million increase in accounting service expenses, (vii) $3.4 million increase due to various construction project write-offs related to customer requested work, (viii) $3.1 million increase in Demand Side Management program costs (offset in Deferred Electric Service Costs), and (ix) $2.8 million increase due to higher bad debt expenses.
Other Operation and Maintenance expense for Conectiv Energy increased by $10.9 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 $6.0 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 $6.6 million due to increased employee-related costs.
Depreciation and Amortization
Depreciation and Amortization expenses decreased by $47.3 million to $365.9 million in 2007 from $413.2 million in 2006. The decrease is primarily due to (i) $31.1 million decrease in ACE’s regulatory asset amortization resulting primarily from the 2006 sale of ACE’s interests in Keystone and Conemaugh, and (ii) $19.1 million decrease in depreciation due to a change in depreciation rates in accordance with the 2007 Maryland Rate Order.
Other Taxes
Other Taxes increased by $14.1 million to $357.1 million in 2007 from $343.0 million in 2006. The increase was primarily due to increased 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 $46.0 million to $68.1 million in 2007 from $22.1 million in 2006. The increase is primarily due to (i) $37.5 million net over-recovery associated with non-utility generation contracts between ACE and unaffiliated third parties, (ii) $11.7 million net over-recovery associated with BGS energy costs, partially offset by (iii) $3.2 million net under-recovery associated with Demand Side Management program costs.
Impairment Losses
During 2007, Pepco Holdings recorded pre-tax impairment losses of $2.0 million ($1.3 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 $18.9 million ($13.7 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 of $33.4 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.”
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 3.3% 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 $19.5 million with a corresponding decrease to the effective tax rate of 3.7%.
The following results of operations discussion compares the year ended December 31, 2006, to the year ended December 31, 2005. 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 T&D Electric Revenue includes revenue from the transmission and 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.
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 release of excess system capacity.
Electric Operating Revenue
Other Regulated T&D Electric Revenue consists primarily of (i) transmission service revenue received by PHI’s utility subsidiaries from PJM as transmission owners, and (ii) revenue from the resale of energy and capacity under power purchase agreements between Pepco and unaffiliated third parties in the PJM market.
Regulated T&D Revenue decreased by $90.0 million primarily due to the following: (i) $51.2 million decrease in sales due to weather, the result of a 16% decrease in Heating Degree Days and 12% decrease in Cooling Degree Days in 2006, (ii) $18.5 million decrease due to a change in Delaware rate structure effective May 1, 2006, which shifted revenue from Regulated T&D Electric Revenue to Default Supply Revenue, (iii) $17.1 million decrease in network transmission revenues due to lower rates approved by FERC in June 2006, (iv) $7.0 million decrease due to a Delaware base rate reduction effective May 1, 2006, primarily offset by (v) $12.9 million increase in sales due to a 0.9% increase in the number of customers.
Default Electricity Supply
Other Default Supply Revenue consists primarily of revenue from the resale of energy and capacity under non-utility generating contracts between ACE and unaffiliated third parties (NUGs) in the PJM market.
Default Supply Revenue, which is partially offset in Fuel and Purchased Energy and Other Services Cost of Sales, increased $518.9 million, representing an 18.8% increase despite a 5% decrease in GWh sales. This increase was primarily due to the following: (i) an increase of $709.3 million attributable to higher retail electricity rates, primarily resulting from market based rates beginning in Delaware on May 1, 2006 and annual increases in Default Electricity Supply rates during the year in the District of Columbia, Maryland, New Jersey, and Virginia, primarily offset by (ii) $142.1 million decrease in wholesale energy revenues from sales of generated and purchased energy in PJM due to lower market prices in the third quarter of 2006 and the sale by ACE of its interests in the Keystone and Conemaugh generating plants, effective September 1, 2006, and (iii) $93.1 million decrease in sales due to milder weather (a 16% decrease in Heating Degree Days and a 12% decrease in Cooling Degree Days in 2006).
Other Electric Revenue
Other Electric Revenue decreased $6.9 million to $58.3 million in 2006 from $65.2 million in 2005 primarily due to a decrease in customer requested work.
Gas Operating Revenue
Regulated Gas Revenue increased by $6.1 million primarily due to (i) $33.2 million increase primarily due to GCR increase effective November 1, 2005, as a result of higher natural gas commodity costs (primarily offset in Fuel and Purchased Energy and Other Services Costs of Sales expense), offset by (ii) $22.3 million decrease in sales due to milder weather (a 17% decrease in Heating Degree Days in 2006), and (iii) $4.8 million decrease primarily due to differences in consumption among various customer rate classes.
Other Gas Revenue
Other Gas Revenue decreased by $12.2 million to $50.6 million in 2006 from $62.8 million in 2005 primarily due to lower off-system sales (partially offset in Gas Purchased expense).
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 following discussion of gross margin.
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. For this reason, PHI from a managerial standpoint focuses on gross margin as a measure of performance.
Conectiv Energy Gross Margin
Beginning in 2007, power origination activities, which primarily represent the fixed margin component of structured power transactions such as default electricity supply contracts, were classified into Energy Marketing from Merchant Generation & Load Service. Accordingly, the 2006 and 2005 activity has been reclassified for comparative purposes. Power origination contributed $18.7 million and $7.5 million of gross margin for 2006 and 2005, respectively.
Includes $471.1 million and $591.3 million of affiliate transactions for 2006 and 2005, respectively. The 2006 and 2005 amounts have been reclassified to exclude $193.1 million and $210.5 million, respectively, of intra-affiliate transactions that were reported gross in 2006 and 2005 at the segment level.
Includes $4.6 million and $7.2 million of affiliate transactions for 2006 and 2005, respectively. The 2006 and 2005 amounts have been reclassified to exclude $193.1 million and $210.5 million, respectively, of affiliate transactions that were reported gross in 2006 and 2005 at the segment level. Also, excludes depreciation and amortization expense of $36.3 million and $40.4 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 amounts in 2006 and 2005 for 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.
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.
Merchant Generation & Load Service gross margin decreased $29.2 million primarily due to:
·
A decrease of $110.9 million due a 26% decline in output from Conectiv Energy’s generating plants primarily because of milder weather in 2006, coupled with lower spark spreads, lower contribution from sales of ancillary services and fuel switching activities, and an unplanned summer outage at the Hay Road generating facility.
·
An increase of $73.2 million on fuel and power hedge contracts.
·
An increase of $10.1 million due to a mark-to-market gain on a supply contract.
Energy Marketing gross margin increased $25.2 million primarily due to:
·
An increase of $11.2 million in power origination due to new higher margin contracts.
·
An increase of $9.2 million due to improved inventory management in the oil marketing business.
·
An increase of $7.7 million in the gas marketing business from gains on storage, transportation, and supply contracts.
·
A decrease of $3.3 million due to the expiration and associated termination costs of a contract to provide operating services for an unaffiliated generation station which expired on October 31, 2006.
Pepco Energy Services
Pepco Energy Services’ operating revenue increased $181.4 million primarily due to (i) an increase of $265.6 million due to higher retail electricity customer load in 2006 and (ii) an increase of $44.3 million due to higher energy services project revenue in 2006 resulting from increased construction activity partially offset by lower revenue related to the sale of five businesses in 2006; partially offset by (iii) a decrease of $93.8 million due to lower natural gas volumes in 2006 as a result of fewer customers served and milder weather, (iv) a decrease of $29.0 million due to reduced electricity generation by the Benning and Buzzard power plants in 2006 due to milder weather and higher fuel oil prices, and (v) a decrease of $5.7 million in mass market products and services revenue, a business Pepco Energy Services exited in 2005. As of December 31, 2006, Pepco Energy Services had 3,544 megawatts of commercial and industrial load, as compared to 2,034 megawatts of commercial and industrial load at the end of 2005. In 2006, Pepco Energy Services’ power plants generated 89,578 megawatt hours of electricity as compared to 237,624 in 2005.
Other Non-Regulated
Other Non-Regulated revenue increased $6.1 million to $90.6 million in 2006 from $84.5 million in 2005. Operating revenues consist of lease earnings recognized under Statement of Financial Accounting Standards (SFAS) No. 13 and changes to the carrying value of the other miscellaneous investments.
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 $583.1 million primarily due to: (i) $736.8 million increase in average energy costs, resulting from higher costs of Default Electricity Supply contracts that went into effect primarily in June 2006 and 2005, offset by (ii) $155.5 million decrease primarily due to differences in consumption among the various customer rate classes (impact due to such factors as weather, migration, etc). This expense is primarily offset in 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 $173.6 million due to (i) a $246.5 million increase in purchases of electricity in 2006 to serve higher retail customer load and (ii) an increase of $37.2 million in costs due to higher energy services projects in 2006 as a result of increased construction activity; partially offset by (iii) a decrease of $87.6 million for purchases of natural gas due to lower volumes sold in 2006 as the result of fewer customers served and milder weather, (iv) a $17.6 million decrease in electricity generation costs in 2006 due to reduced electricity generation by the Benning and Buzzard power plants as a result of milder weather and higher fuel oil prices, (v) a $4.9 million decrease in mass market products and services costs, a business Pepco Energy Services exited in 2005, and (vi) decreased costs due to the sale of five companies in 2006.
Other Operation and Maintenance
A detail of PHI’s other operation and maintenance expense is as follows:
The higher operation and maintenance expenses of the Conectiv Energy segment were primarily due to planned and unplanned facility outages. The impact of this increase was substantially offset by lower corporate expenses related to the amortization of non-compete agreements and other administrative and general expenses.
Depreciation and Amortization
Depreciation and amortization expenses decreased by $14.1 million to $413.2 million in 2006, from $427.3 million in 2005. The decrease is primarily due to (i) $5.4 million change in depreciation technique resulting from the ACE distribution base rate case settlement in 2005 that depreciates assets over their whole life versus their remaining life, (ii) $4.1 million reduction of ACE regulatory debits, and (iii) $3 million reduction due to completion of amortization related to software, offset by net increases to plant in-service (additions less retirements) of about $5.4 million.
Deferred Electric Service Costs
Deferred Electric Service Costs decreased by $98.1 million to $22.1 million in 2006 from $120.2 million in 2005. The $98.1 million decrease was attributable to (i) $92.4 million net under-recovery associated with New Jersey BGS, NUGs, market transition charges and other restructuring items and (ii) $5.7 million in regulatory disallowances (net of amounts previously reserved) in connection with the ACE distribution base rate case settlement in 2005.
Impairment Losses
For the year ended December 31, 2006, Pepco Holdings recorded pre-tax impairment losses of $18.9 million ($13.7 million after-tax) related to certain energy services business assets owned by Pepco Energy Services. The impairments were recorded as a result of the execution of contracts to sell certain assets and due to the lower than expected production and related estimated cash flows from other assets. The fair value of the assets under contract for sale was determined based on the sales contract price; while the fair value of the other assets was determined by estimating future expected production and cash flows.
Gain on Sale of Assets
Pepco Holdings recorded a Gain on Sale of Assets of $.8 million for the year ended December 31, 2006, compared to $86.8 million for the year ended December 31, 2005. The $86.8 million gain in 2005 primarily consisted of: (i) a $68.1 million gain from the sale of non-utility land owned by Pepco located at Buzzard Point in the District of Columbia, and (ii) a $13.3 million gain recorded by PCI from proceeds related to the final liquidation of a financial investment that was written off in 2001.
Effect of Settlement of Mirant Bankruptcy Claims
The Effect of Settlement of Mirant Bankruptcy Claims of $70.5 million in 2005 represents a settlement (net of customer sharing) with Mirant of the allowed, pre-petition general unsecured claim related to a transition power agreement (TPA) by Pepco in the Mirant bankruptcy in the amount of $105 million (the TPA Claim) ($70 million gain) and a Pepco asbestos claim against the Mirant bankruptcy estate ($.5 million gain). See “Capital Resources and Liquidity -- Cash Flow Activity -- Proceeds from Settlement of Mirant Bankruptcy Claims.”
Other Income (Expenses)
Other Expenses (which are net of other income) decreased by $3.1 million to $282.4 million for the year ended December 31, 2006 from $285.5 million for the same period in 2005. The decrease primarily resulted from an increase in income from equity fund valuations at PCI of $7.3 million and $2.3 in lower impairment charges during 2006 compared to 2005, partially offset by a $6.6 million gain in 2005 related to the sale of an investment.
Income Tax Expense
PHI’s effective tax rates for the years ended December 31, 2006 and 2005 were 39.3% and 41.2%, respectively. The 1.9% decrease in the effective tax rate in 2006 was primarily the result of changes in estimates related to prior year tax liabilities, which reduced the effective tax rate by 2.3%.
CAPITAL RESOURCES AND LIQUIDITY
This section discusses Pepco Holdings’ working capital, cash flow activity, capital requirements and other uses and sources of capital.
Working Capital
At December 31, 2007, Pepco Holdings’ current assets on a consolidated basis totaled $2.0 billion and its current liabilities totaled $2.0 billion. At December 31, 2006, Pepco Holdings’ current assets on a consolidated basis totaled $2.0 billion and its current liabilities totaled $2.5 billion. The working capital deficit at the end of 2006 was primarily due to $500 million of current long-term debt due to mature in August 2007. During 2007, PHI refinanced $450 million of the maturing debt with new long-term debt.
At December 31, 2007, Pepco Holdings’ cash and cash equivalents and its current restricted cash (cash that is available to be used only for designated purposes) totaled $69.6 million. At December 31, 2006, Pepco Holdings’ cash and cash equivalents and its current restricted cash, totaled $60.8 million. See “Capital Requirements -- Contractual Arrangements with Credit Rating Triggers or Margining Rights” 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.
Cash Flow Activity
PHI’s cash flows for 2007, 2006, and 2005 are summarized below.
Operating Activities
Cash flows from operating activities are summarized below for 2007, 2006, and 2005.
Net cash from operating activities in 2007 was $592.4 million higher than in 2006. In addition to net income, the factors that primarily contributed to the increase were: (i) a decrease of $202.9 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 “Regulatory and Other Matters - IRS Mixed Service Cost Issue” below) and (ii) the change in cash collateral requirements detailed below associated with Competitive Energy activities.
Changes in cash collateral include the following:
·
The balance of cash collateral posted by PHI (net of cash collateral held by PHI) decreased $61.7 million from December 31, 2006 to December 31, 2007 (an increase in cash).
·
The balance of cash collateral posted by PHI (net of cash collateral held by PHI) increased $259.9 million from December 31, 2005 to December 31, 2006 (a decrease in cash).
Cash flows from operating activities in 2007 also were affected by the Mirant bankruptcy settlement. See “Proceeds from Settlement of Mirant Bankruptcy Claims” below. During the third quarter of 2007, Pepco Holdings received $413.9 million in net settlement proceeds, of which $398.9 million was designated as operating cash flows and $15.0 million was designated as investing cash flows. See “Investing Activities” below. These funds were used to purchase money market funds, which are considered cash equivalents, and have been accounted for as restricted cash based on management’s intent only to use such funds, and any interest earned thereon, to pay for the future above-market capacity and energy purchase costs under the Panda PPA. This restricted cash has been classified as a non-current asset to be consistent with the classification of the corresponding non-current regulatory liability, and any changes in the balance of this restricted cash, including interest receipts, have been considered operating cash flows.
Net cash from operating activities in 2006 was $784.3 million lower than in 2005. In addition to the decrease in net income, the factors contributing to the decrease in cash flow from operating activities included: (i) an increase of $194.5 million in taxes paid in 2006, including a tax payment of $121 million made in February 2006 in connection with an unresolved tax matter (see “Regulatory and Other Matters -- IRS Mixed Service Cost Issue” below), (ii) a decrease in the change in regulatory assets and liabilities of $107.9 million due primarily to the 2005 over-
recoveries associated with New Jersey BGS, NUGs, market transition charges and other restructuring items, and (iii) the change in collateral requirements associated with the activities of Competitive Energy described above.
Investing Activities
Cash flows used by investing activities during 2007, 2006, and 2005 are summarized below.
Net cash used by investing activities in 2007 was $352.5 million higher than in 2006 primarily due to: (i) a $148.8 million increase in capital expenditures, $107.0 million of which relates to Power Delivery, and (ii) a decrease of $170.3 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 property in 2006 consisted primarily of $177.0 million from the sale of ACE’s interest in the Keystone and Conemaugh generating facilities and $13.1 million from the sale of Conectiv Energy’s equity interest in a joint venture which owns a wood burning cogeneration facility. Proceeds from the sale of property in 2007 consisted primarily of $9.0 million received from the sale of the B.L. England generating facility. Cash flows from investing activities in 2007 also include $15.0 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.
Net cash used by investing activities in 2006 were $104.8 million lower than in 2005. The decrease is primarily due to the net proceeds of $177.0 million received in 2006 from the sale of ACE’s interest in the Keystone and Conemaugh generating facilities, compared to the $73.7 million in proceeds received in 2005 from the sale of the Buzzard Point land.
Financing Activities
Cash flows used by financing activities during 2007, 2006 and 2005 are summarized below.
Net cash used by financing activities in 2007 was $160.9 million higher than in 2006. Net cash used by financing activities in 2006 was $514.8 million lower than in 2005.
Changes in Outstanding Common Stock
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 $175.5 million. The net proceeds are being used for general corporate purposes. The balance of the change in 2007 common stock is primarily attributable to the issuance of performance based shares under the long-term incentive plan.
Under the DRP, PHI issued 979,155 shares of common stock in 2007, 1,232,569 shares of common stock in 2006, and 1,228,505 shares of common stock in 2005.
Common Stock Dividends
Common stock dividend payments were $202.6 million in 2007, $198.3 million in 2006, and $188.9 million in 2005. The increase in common dividends paid in 2007 was due primarily to an issuance of the additional shares under the DRP. The increase in common dividends paid in 2006 was due to the issuance of the additional shares under the DRP and a quarterly dividend increase from 25 cents per share to 26 cents per share beginning in the first quarter of 2006.
Changes in Outstanding Preferred Stock
Preferred stock redemptions in 2007 consisted of DPL’s redemption in January 2007, at prices ranging from 103% to 105% of par, of the following securities, representing all of DPL’s outstanding preferred stock, at an aggregate cost of $18.9 million:
·
19,809 shares of 4.00% Series, 1943 Redeemable Serial Preferred Stock,
·
39,866 shares of 3.70% Series, 1947 Redeemable Serial Preferred Stock,
·
28,460 shares of 4.28% Series, 1949 Redeemable Serial Preferred Stock,
·
19,571 shares of 4.56% Series, 1952 Redeemable Serial Preferred Stock,
·
25,404 shares of 4.20% Series, 1955 Redeemable Serial Preferred Stock, and
·
48,588 shares of 5.00% Series, 1956 Redeemable Serial Preferred Stock.
Preferred stock redemptions in 2006 consisted of Pepco’s redemption in March 2006 of the following securities at an aggregate cost of $21.5 million:
·
216,846 shares of $2.44 Series, 1957 Serial Preferred Stock,
·
99,789 shares of $2.46 Series, 1958 Serial Preferred Stock, and
·
112,709 shares of $2.28 Series, 1965 Serial Preferred Stock.
Preferred stock redemptions in 2005 consisted of:
·
Pepco’s redemption in October 2005 of the following securities at an aggregate cost of $5.5 million:
o
22,795 shares of $2.44 Series 1957 Serial Preferred Stock,
o
74,103 shares of $2.46 Series 1958 Serial Preferred Stock, and
o
13,148 shares of $2.28 Series 1965 Serial Preferred Stock.
·
ACE’s redemption in August 2005 of 160 shares of 4.35% Serial Preferred Stock at a cost of $.02 million, and
·
DPL’s redemption in December 2005 of all of the 35,000 shares of 6.75% Serial Preferred Stock outstanding at a cost of $3.5 million.
Changes in Outstanding Long-Term Debt
Cash flows from the issuance and redemption of long-term debt in 2007 were attributable primarily to the following transactions, which encompass $700.0 million of the $703.9 million in long-term debt issued in 2007 and all of the $854.9 million in long-term debt redeemed in 2007:
·
In January 2007, Pepco retired at maturity $35 million of 7.64% medium-term notes and also retired at maturity $175 million of 6.25% first mortgage bonds using the proceeds of commercial paper. In November 2007, Pepco issued $250 million of 6.5% first mortgage bonds.
·
In February 2007, DPL retired at maturity $11.5 million of medium-term notes with a weighted average interest rate of 7.08%. In the second quarter of 2007, DPL retired at maturity $50 million of 8.125% medium-term notes and $3.2 million of 6.95% first mortgage bonds.
·
In the second quarter of 2007, ACE retired at maturity $15 million of 7.52% medium-term notes and $1 million of 7.15% medium-term notes.
·
For the year ended December 31, 2007, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $21.4 million on Series 2002-1 Bonds, Class A-1 and $8.5 million on Series 2003-1, Class A-1 with a weighted average interest rate of 2.89%.
·
In February 2007, PCI retired at maturity $34.3 million of 7.62% medium-term notes.
·
In April 2007, PHI issued $200 million of 6.0% notes due 2019 in a private placement. The proceeds were used to redeem $200 million of 5.5% notes due August 15, 2007 at a price of 100.0377% of par. In June 2007, PHI issued $250 million of 6.125% notes due 2017 in a public offering and used the proceeds along with short-term debt to redeem $300 million of its 5.5% notes in August 2007.
Cash flows from the issuance and redemption of long-term debt in 2006 were attributable primarily to the following transactions, which encompass all of the $514.5 million of long-term debt issued in 2006 and $576.4 million of the $578.0 million of the long-term debt redeemed in 2006:
·
In May 2006, Pepco used the proceeds from a bond refinancing to redeem an aggregate of $109.5 million of three series of first mortgage bonds. The series were combined into one series of $109.5 million due 2022.
·
In December 2006, Pepco retired at maturity $50 million of variable rate notes.
·
In June 2006, DPL redeemed $2.9 million of 6.95% first mortgage bonds due 2008.
·
In October 2006, DPL retired at maturity $20 million of medium-term notes.
·
In December 2006, DPL issued $100 million of 5.22% unsecured notes due 2016. The proceeds were used to redeem DPL’s commercial paper outstanding.
·
In the first quarter of 2006, PHI retired at maturity $300 million of its 3.75% unsecured notes with proceeds from the issuance of commercial paper.
·
In December 2006, PHI issued $200 million of 5.9% unsecured notes due 2016. The net proceeds, plus additional funds, were used to repay a $250 million bank loan entered into in August 2006.
·
In January 2006, ACE retired at maturity $65 million of medium-term notes.
·
In March 2006, ACE issued $105 million of Senior Notes due 2036. The proceeds were used to pay down short-term debt incurred earlier in the quarter to repay medium-term notes at maturity.
·
For the year ended December 31, 2006, ACE Funding made principal payments of $20.7 million on Series 2002-1 Bonds, Class A-1 and $8.3 million on Series 2003-1, Class A-1 with a weighted average interest rate of 2.89%.
Cash flows from the issuance and redemption of long-term debt in 2005 were attributable primarily to the following transactions, which encompass $525 million of the $532 million of long-term debt issued in 2005 and $727.7 million of the $755.8 million of long-term debt redeemed in 2005:
·
In 2005, Pepco Holdings issued $250 million of floating rate unsecured notes due 2010. The net proceeds, plus additional funds, were used to repay commercial paper issued to fund the $300 million redemptions of Conectiv debt.
·
In September 2005, Pepco used the proceeds from the June 2005 issuance of $175 million in senior secured notes to fund the retirement of $100 million in first mortgage bonds at maturity as well as the redemption of $75 million in first mortgage bonds prior to maturity.
·
In 2005, DPL issued $100 million of unsecured notes due 2015. The net proceeds were used to redeem $102.7 million of higher rate securities.
·
In December 2005, Pepco paid down $50 million of its $100 million bank loan due December 2006.
·
In 2005, ACE retired at maturity $40 million of medium-term notes.
·
In 2005, PCI redeemed $60 million of medium-term notes.
PHI’s long-term debt is subject to certain covenants. PHI and its subsidiaries are in compliance with all requirements.
Changes in Short-Term Debt
In 2007, PHI redeemed a total of $36.0 million in short-term debt with cash from operations.
In 2006, Pepco and DPL issued short-term debt of $67.1 million and $91.1 million, respectively, in order to cover capital expenditures and tax obligations throughout the year.
In 2005, ACE and PHI redeemed a total of $161.3 million in short-term debt with cash from operations.
Sales of ACE Generating Facilities
On September 1, 2006, ACE completed the sale of its interest in the Keystone and Conemaugh generating facilities for $175.4 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 $9.0 million. No gain or loss was realized on these sales.
Sale of Interest in Cogeneration Joint Venture
During the first quarter of 2006, Conectiv Energy recognized a $12.3 million pre-tax gain ($7.9 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
In 2000, Pepco sold substantially all of its electricity generating assets to Mirant. 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 asset sale, Pepco entered into the TPAs. Under a settlement to avoid the rejection by Mirant of its obligations under the TPAs in the bankruptcy proceeding, the terms of the TPAs were modified to increase the purchase price of the energy and capacity supplied by Mirant and Pepco received the TPA Claim. In December 2005, Pepco sold the TPA Claim, plus the right to receive accrued interest thereon, to an unaffiliated third party for $112.5 million. In addition, Pepco received proceeds of $.5 million in settlement of an asbestos claim against the Mirant bankruptcy estate. After customer sharing, Pepco recorded a pre-tax gain of $70.5 million from the settlement of these claims.
In connection with the asset sale, Pepco and Mirant also entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco is obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco is obligated to pay to Panda. As part of the further settlement of Pepco’s claims against Mirant arising from the Mirant 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 is obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $413.9 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. These funds are being accounted for as restricted cash based on management’s intent to use such funds, and any interest earned thereon, for the sole purpose of paying for the future above-market capacity and energy purchase costs under the Panda PPA. Correspondingly, a regulatory liability has been established in the same amount to help offset the future above-market capacity and energy purchase costs. This restricted cash has been classified as a non-current asset to be consistent with the classification of the non-current regulatory liability, and any changes in the balance of this restricted cash, including interest on the invested funds, are being accounted for as operating cash flows.
As of December 31, 2007, the balance of the restricted cash account was $417.3 million. Based on a reexamination of the costs of the Panda PPA in light of current and projected wholesale market conditions conducted in the fourth quarter of 2007, Pepco determined that, principally due to increases in wholesale capacity prices, the present value above-market cost of
the Panda PPA over the term of the agreement are expected to be significantly less than the current amount of the restricted cash account balance. Accordingly, on February 22, 2008, Pepco filed applications with the DCPSC and the MPSC requesting orders directing Pepco to maintain $320 million in the restricted cash account and to use that cash, and any future earnings on the cash, for the sole purpose of paying the future above-market cost of the Panda PPA (or, in the alternative, to fund a transfer or assignment of the remaining obligations under the Panda PPA to a third party). Pepco also requested that the order provide that any cash remaining in the account at the conclusion of the Panda PPA be refunded to customers and that any shortfall be recovered from customers. Pepco further proposed that the excess proceeds remaining from the settlement (approximately $94.6 million, representing the amount by which the regulatory liability of $414.6 million at December 31, 2007 exceeded $320 million) be shared approximately equally with its customers in accordance with the procedures previously approved by each commission for the sharing of the proceeds received by Pepco from the sale to Mirant of its generating assets. The regulatory liability of $414.6 million at December 31, 2007 differs from the restricted cash amount of $417.3 million on that date, in part, because the regulatory liability has been reduced for the portion of the December 2007 Panda charges in excess of market that had not yet been paid from the restricted cash account. The amount of the restricted cash balance that Pepco is permitted to retain will be recorded as earnings upon approval of the sharing arrangement by the respective commissions. At this time, Pepco cannot predict the outcome of these proceedings.
In settlement of other damages claims against Mirant, Pepco in 2007 also received a settlement payment in the amount of $70.0 million. Of this amount (i) $33.4 million was recorded as a reduction in operating expenses, (ii) $21.0 million was recorded as a reduction in a net pre-petition receivable claim from Mirant, (iii) $15.0 million was recorded as a reduction in the capitalized costs of certain property, plant and equipment and (iv) $.6 million was recorded as a liability to reimburse a third party for certain legal costs associated with the settlement.
Sale of Buzzard Point Property
In August 2005, Pepco sold for $75 million excess non-utility land located at Buzzard Point in the District of Columbia. The sale resulted in a pre-tax gain of $68.1 million which was recorded as a reduction of Operating Expenses in the Consolidated Statements of Earnings.
Financial Investment Liquidation
In October 2005, PCI received $13.3 million in cash and recorded an after-tax gain of $8.9 million related to the liquidation of a financial investment that was written-off in 2001.
Capital Requirements
Capital Expenditures
Pepco Holdings’ total capital expenditures for the year ended December 31, 2007 totaled $623.4 million of which $272.2 million related to Pepco (excluding $15 million of reimbursements related to the settlement of the Mirant bankruptcy claims), $132.6 million related to DPL and $149.4 million related to ACE. The remainder of $69.2 million was primarily related to Conectiv Energy and Pepco Energy Services. 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 Pepco, DPL, ACE, Conectiv Energy and Pepco Energy Services for the five-year period 2008 through 2012.
Pepco Holdings expects to fund these expenditures through internally generated cash and external financing.
Distribution, Transmission and Gas Delivery
The projected capital expenditures 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, Pepco, DPL and ACE each announced an initiative that it refers 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 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, Pepco and DPL intend to install “smart meters” for all customers in the District of Columbia, Maryland and
Delaware, 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. The projected costs for PHI’s utility subsidiaries for the years 2008 through 2012 are included in the table above.
MAPP Project
On October 17, 2007, PHI received the approval of the PJM Board of Managers to build a new 230-mile, 500-kilovolt interstate transmission line as part of PJM’s Regional Transmission Expansion Plan to address the reliability objectives of the PJM RTO system. The transmission line, which is referred to as the MAPP Project, will be located in northern Virginia, Maryland, the Delmarva Peninsula, and New Jersey. The preliminarily estimated cost of the MAPP Project is approximately $1 billion. Construction is expected to occur in sections over a six-year period with completion targeted by 2013. PHI also plans to add significant 230-kilovolt support lines in Maryland and New Jersey to connect with the new 500-kilovolt line at an approximate cost of $200 million. PJM continues to evaluate the 230-kilovolt support lines. Only the projected construction costs associated with the 500-kilovolt transmission line for the years 2008 through 2012 are included in the table above.
Delta Project
On December 14, 2007, Conectiv Energy announced a decision to construct a 545 MW 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, with projected expenditures of $62 million in 2008, $195 million in 2009, $136 million in 2010, and $14 million in 2011, and are included in Conectiv Energy’s projected capital expenditures shown in the table above. The total expenditures include $63 million in development costs and three combustion turbines currently held in inventory by Conectiv Energy. The plant is expected to become operational by June 2011.
Cumberland Project
In 2007, Conectiv Energy began construction of a new combustion turbine power plant in Millville, New Jersey. The total construction expenditures for this project are expected to be $75 million (of which $24 million was expended in 2007), with projected expenditures of $46 million in 2008 and $5 million in 2009. These future expenditures are included in Conectiv Energy’s projected capital expenditures shown in the table above.
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 $79 million. The compliance plan filed by Conectiv Energy contemplates capital expenditures of $38 million of capital in 2008 and $19 million of capital 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 2007, PHI’s Board of Directors declared quarterly dividends of 26 cents per share of common stock payable on March 30, 2007, June 29, 2007, September 28, 2007 and December 31, 2007.
On January 24, 2008, the Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2008, to shareholders of record March 10, 2008.
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 2007 valuation, the PHI Retirement Plan satisfied the minimum funding requirements of the Employment 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). In 2007 and 2006, no contributions were made to the PHI Retirement Plan.
In 2007, the ABO for the PHI Retirement Plan decreased from 2006, due to an increase in the discount rate used to value the ABO obligation, which more than offset the accrual of an additional year of service for participants. The PHI Retirement Plan assets achieved returns in 2007 above the 8.25% level assumed in the valuation. As a result of the combination of these factors, no contribution was made to the PHI Retirement Plan, because the funding level at year end 2007 was in excess of 100% of the ABO. In 2006, as a result of similar factors, PHI made no contribution to the PHI Retirement Plan. Assuming no changes to the current pension plan assumptions, PHI projects no funding will be required under ERISA in 2008; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its assets in excess of ABO for the PHI Retirement Plan. Legislative changes, in the form of the Pension Protection Act of 2006, impact the funding requirements for pension plans beginning in 2008. The Pension Protection Act alters the manner in which liabilities and asset values are determined
for the purpose of calculating required pension contributions. Based on preliminary actuarial projections and assuming no changes to current pension plan assumptions, PHI believes it is unlikely that there will be a required contribution in 2008.
Contractual Obligations and Commercial Commitments
Summary information about Pepco Holdings’ consolidated contractual obligations and commercial commitments at December 31, 2007, is as follows:
(a)
Estimates relating to the future funding of PHI’s pension and other postretirement benefit plans are not included in this table. For additional information, see Item 8, Note (6) Pension and Other Postretirement Benefits -- “Cash Flows.”
(b)
Includes transition bonds issued by ACE Funding.
(c)
Excludes contractual obligations entered into by ACE to purchase electricity to satisfy its BGS load.
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 which are entered into in the normal course of business to facilitate commercial transactions with third parties as discussed below.
As of December 31, 2007, 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. These commitments and obligations, in millions of dollars, were as follows:
(a)
Pepco Holdings has contractual commitments ensuring the 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, 2007, obligations under the guarantees were approximately $5.7 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:
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Pepco Holdings has guaranteed a subsidiary building lease of $2.3 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.
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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, 2007, the guarantees cover the remaining $1.4 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.
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)
PHI does not engage in proprietary trading activities.
(b)
Includes all SFAS No. 133 hedge activity and non-proprietary trading activities marked-to-market through earnings.
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, 2007 and are subject to change as a result of changes in these factors:
(a)
Indicated maturity is based on contract settlement or delivery date(s).
(b)
Includes all SFAS No. 133 hedge activity and non-proprietary trading activities marked-to-market through Accumulated Other Comprehensive Income or on the Statements of earnings, as required.
(c)
Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
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, 2007, PHI estimates that if a one level downgrade in the credit rating of PHI and each of its relevant subsidiaries were to occur, the additional aggregate cash collateral or letters of credit amount required would be $339.0 million. PHI believes that it and its utility subsidiaries maintain adequate short-term funding sources in the event the additional collateral or letters of credit are required. See “Sources of Capital -- Short-Term Funding Sources.”
Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with Competitive Energy and Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the applicable arrangements. Pursuant to these margining rights, the affected PHI subsidiary may receive, or be required to post, collateral due to energy price movements. As of December 31,
2007, Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities provided net cash collateral in the amount of $91.2 million in connection with these activities.
Environmental Remediation Obligations
PHI’s accrued liabilities as of December 31, 2007 include approximately $18.4 million, of which $5.7 million is expected to be incurred in 2008, for potential environmental cleanup and other costs related to sites at which an operating subsidiary is a potentially responsible party (PRP), 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.” The most significant environmental remediation obligations as of December 31, 2007, were:
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$4.7 million, of which $1.2 million is expected to be incurred in 2008, 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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$4.9 million in environmental remediation costs, of which $1.3 million is expected to be incurred in 2008, payable by Conectiv Energy associated with the Deepwater generating facility.
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$3.8 million for environmental remediation costs related to former manufactured gas plant (MGP) 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 2008.
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$1.7 million in connection with Pepco’s liability for a remedy at the Metal Bank/Cottman Avenue site.
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$1.4 million, of which approximately $260,000 is expected to be incurred in 2008, 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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$735,000, of which approximately $65,000 is expected to be incurred in 2008, payable by Pepco for long-term monitoring associated with a pipeline oil release that occurred in 2000.
Sources of Capital
Pepco Holdings’ sources to meet its long-term funding needs, such as capital expenditures, dividends, and new investments, and its short-term funding needs, such as working capital and the temporary funding of long-term funding needs, include internally generated funds, securities issuances and bank financing under new or existing facilities. PHI’s ability to generate funds from its operations and to access capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and
tightening credit may affect efficient access to certain of PHI’s potential funding sources. See Item 1A. “Risk Factors” 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, DPL, and ACE have ongoing commercial paper programs of up to $500 million, up to $275 million, and up to $250 million, respectively. The commercial paper can be issued with maturities of up to 270 days.
PHI, Pepco, DPL and ACE maintain a credit facility which supports the issuance of commercial paper and is available to provide for short-term liquidity needs.
The aggregate borrowing limit under the 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 based on the prevailing prime rate or 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 made by the borrower at the time the credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower’s business,
property, and results of operations or financial condition subsequent to the entry into the credit agreement is not a condition to the availability of credit under the facility. Among the covenants to which each of the companies is subject are (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 certain trust preferred securities and deferrable interest subordinated debt from the definition of total indebtedness (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the credit agreement. The credit agreement does not include any rating triggers.
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 both debt and equity securities by the principal subsidiaries of PHI 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 District of Columbia Public Service Commission (DCPSC) and MPSC. DPL’s long-term financing activities are subject to authorization by MPSC and the Delaware Public Service 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 New Jersey Board of Public Utilities (NJBPU). Each utility, through periodic filings with the state public service commission(s) having jurisdiction over its financing activities, typically maintains 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. 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 approval would be required for the issuance of securities by those companies.
To the extent FERC approval is required for the issuance of securities by PHI and its subsidiaries, the companies, in accordance with regulations adopted by FERC, are relying on
authority granted in a financing order issued by the Securities and Exchange Commission prior to the repeal of Public Utility Holding Company Act 1935 (the Financing Order), which extends through June 30, 2008. Prior to June 30, 2008, PHI’s utility subsidiaries will file for new financing authority for the issuance of securities for which FERC approval is required.
Money Pool
Under the Financing Order, Pepco Holdings is authorized to operate a system money pool. 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. After expiration of the Financing Order, PHI and its subsidiaries expect to engage in intra-system cash management programs such as the money pool under a blanket authorization adopted by FERC.
REGULATORY AND OTHER MATTERS
Proceeds from Settlement of Mirant Bankruptcy Claims
In 2000, Pepco sold substantially all of its electricity generating assets to Mirant. 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 asset sale, Pepco entered into the TPAs. Under a settlement to avoid the rejection by Mirant of its obligations under the TPAs in the bankruptcy proceeding, the terms of the TPAs were modified to increase the purchase price of the energy and capacity supplied by Mirant and Pepco received the TPA Claim. In December 2005, Pepco sold the TPA Claim, plus the right to receive accrued interest thereon, to an unaffiliated third party for $112.5 million. In addition, Pepco received proceeds of $.5 million in settlement of an asbestos claim against the Mirant bankruptcy estate. After customer sharing, Pepco recorded a pre-tax gain of $70.5 million from the settlement of these claims.
In connection with the asset sale, Pepco and Mirant also entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco is obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco is obligated to pay to Panda. As part of the further settlement of Pepco’s claims against Mirant arising from the Mirant 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 is obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $413.9 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. These funds are being accounted for as restricted cash based on management’s intent to use such funds, and any interest
earned thereon, for the sole purpose of paying for the future above-market capacity and energy purchase costs under the Panda PPA. Correspondingly, a regulatory liability has been established in the same amount to help offset the future above-market capacity and energy purchase costs. This restricted cash has been classified as a non-current asset to be consistent with the classification of the non-current regulatory liability, and any changes in the balance of this restricted cash, including interest on the invested funds, are being accounted for as operating cash flows.
As of December 31, 2007, the balance of the restricted cash account was $417.3 million. Based on a reexamination of the costs of the Panda PPA in light of current and projected wholesale market conditions conducted in the fourth quarter of 2007, Pepco determined that, principally due to increases in wholesale capacity prices, the present value above-market cost of the Panda PPA over the term of the agreement is expected to be significantly less than the current amount of the restricted cash account balance. Accordingly, on February 22, 2008, Pepco filed applications with the DCPSC and the MPSC requesting orders directing Pepco to maintain $320 million in the restricted cash account and to use that cash, and any future earnings on the cash, for the sole purpose of paying the future above-market cost of the Panda PPA (or, in the alternative, to fund a transfer or assignment of the remaining obligations under the Panda PPA to a third party). Pepco also requested that the order provide that any cash remaining in the account at the conclusion of the Panda PPA be refunded to customers and that any shortfall be recovered from customers. Pepco further proposed that the excess proceeds remaining from the settlement (approximately $94.6 million, representing the amount by which the regulatory liability of $414.6 million at December 31, 2007 exceeded $320 million) be shared approximately equally with its customers in accordance with the procedures previously approved by each commission for the sharing of the proceeds received by Pepco from the sale to Mirant of its generating assets. The regulatory liability of $414.6 million at December 31, 2007 differs from the restricted cash amount of $417.3 million on that date, in part, because the regulatory liability has been reduced for the portion of the December 2007 Panda charges in excess of market that had not yet been paid from the restricted cash account. The amount of the restricted cash balance that Pepco is permitted to retain will be recorded as earnings upon approval of the sharing arrangement by the respective commissions. At this time, Pepco cannot predict the outcome of these proceedings.
In settlement of other damages claims against Mirant, Pepco in 2007 also received a settlement payment in the amount of $70.0 million. Of this amount (i) $33.4 million was recorded as a reduction in operating expenses, (ii) $21.0 million was recorded as a reduction in a net pre-petition receivable claim from Mirant, (iii) $15.0 million was recorded as a reduction in the capitalized costs of certain property, plant and equipment and (iv) $.6 million was recorded as a liability to reimburse a third party for certain legal costs associated with the settlement.
Rate Proceedings
In electric service distribution base rate cases filed by Pepco in the District of Columbia and Maryland, and by DPL in Maryland, and pending in 2007, Pepco and DPL proposed the adoption of a BSA for retail customers. 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 will increase rates if actual distribution revenues fall below the level approved by the applicable commission and will decrease rates if actual distribution revenues are above the approved level. The result will be that, over time, the utility would collect 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 the regulated utilities to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and delivery revenues. The status of the BSA proposals in each of the jurisdictions is described below in discussion of the respective base rate proceedings.
Delaware
On September 4, 2007, DPL submitted its 2007 GCR filing to the DPSC. The GCR permits DPL to recover its gas procurement costs through customer rates. On September 18, 2007, the DPSC issued an initial order approving a 5.7% decrease in the level of the GCR, which became effective November 1, 2007, subject to refund and 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. The application to the DCPSC requested an annual increase of approximately $46.2 million or an overall increase of 13.5%, reflecting a proposed return on equity (ROE) of 10.75%. In the alternative, the application requested an annual increase of $50.5 million or an overall increase of 14.8%, reflecting an ROE of 11.00%, if the BSA were not approved. Subsequently, Pepco reduced its annual revenue increase request to $43.4 million (including a proposed BSA) and $47.9 million (if the BSA were not approved).
On January 30, 2008, the DCPSC approved a revenue requirement increase of approximately $28.3 million, based on an authorized return on rate base of 7.96%, including a 10% ROE. The rate increase is effective February 20, 2008. The DCPSC, while finding the BSA to be an appropriate ratemaking concept, cited potential statutory problems in the DCPSC’s ability to implement the BSA. The DCPSC stated that it intends to issue an order to establish a Phase II proceeding to consider these implementation issues.
Maryland
On July 19, 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 annual increase in distribution rates of approximately $14.9 million (including a decrease in annual depreciation expense of approximately $.9 million). The Pepco order approved an annual increase in distribution rates of approximately $10.6 million (including a decrease in annual depreciation expense of approximately $30.7 million). In each case, the approved distribution rate reflects an ROE of 10.0%. The orders each provided that the rate increases are effective as of June 16, 2007, and will remain in effect for an initial period of nine months from the date of the order (or until April 19, 2008). These rates are subject to a Phase II proceeding in which the MPSC will consider 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 is required. Hearings for the Phase II proceeding are scheduled for mid-March 2008.
New Jersey
On June 1, 2007, ACE filed with the NJBPU an application for permission to decrease the Non Utility Generation Charge (NGC) and increase components of its Societal Benefits Charge (SBC) to be collected from customers for the period October 1, 2007 through September 30, 2008. The proposed changes are designed to effect a true-up of the actual and estimated costs and revenues collected through the current NGC and SBC rates through September 30, 2007 and, in the case of the SBC, forecasted costs and revenues for the period October 1, 2007 through September 30, 2008.
As of December 31, 2007, the NGC, which is intended primarily to recover the above-market component of payments made by ACE under non-utility generation contracts and stranded costs associated with those commitments, had an over-recovery balance of $224.3 million. The filing proposed that the estimated NGC balance as of September 30, 2007 in the amount of $216.2 million, including interest, be amortized and returned to ACE customers over a four-year period, beginning October 1, 2007.
As of December 31, 2007, the SBC, which is intended to allow ACE to recover certain costs involved with various NJBPU-mandated social programs, had an under-recovery of approximately $20.9 million, primarily due to increased costs associated with funding the New Jersey Clean Energy Program. In addition, ACE has requested an increase to the SBC to reflect the funding levels approved by the NJBPU of $20.4 million for the period October 1, 2007 through September 30, 2008, bringing to $40 million the total recovery requested for the period October 1, 2007 to September 30, 2008 (based upon actual data through August 2007).
The net impact of the proposed adjustments to the NGC and the SBC, including associated changes in sales and use tax, is an overall rate decrease of approximately $129.9 million for the period October 1, 2007 through September 30, 2008 (based upon actual data through August 2007). The proposed adjustments and the corresponding changes in customer rates are subject to the approval of the NJBPU. If approved and implemented, ACE anticipates that the revised rates will remain in effect until September 30, 2008, subject to an annual true-up and change each year thereafter. The proposed adjustments and the corresponding changes in customer rates remain under review by the NJBPU and have not yet been implemented.
ACE Restructuring Deferral Proceeding
Pursuant to orders issued by the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA), beginning August 1, 1999, ACE was obligated to provide BGS to retail electricity customers in its service territory who did not elect to purchase electricity from a competitive supplier. For the period August 1, 1999 through July 31, 2003, ACE’s aggregate costs that it was allowed to recover from customers exceeded its aggregate revenues from supplying BGS. These under-recovered costs were partially offset by a $59.3 million deferred energy cost liability existing as of July 31, 1999 (LEAC Liability) related to ACE’s Levelized Energy Adjustment Clause and ACE’s Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance of under-recovered costs.
In August 2002, ACE filed a petition with the NJBPU for the recovery of approximately $176.4 million in actual and projected deferred costs relating to the provision of BGS and other restructuring related costs incurred by ACE over the four-year period August 1, 1999 through July 31, 2003, net of the $59.3 million offset for the LEAC Liability. The petition also requested that ACE’s rates be reset as of August 1, 2003 so that there would be no under-recovery of costs embedded in the rates on or after that date. The increase sought represented an overall 8.4% annual increase in electric rates.
In July 2004, the NJBPU issued a final order in the restructuring deferral proceeding confirming a July 2003 summary order, which (i) permitted ACE to begin collecting a portion of the deferred costs and reset rates to recover on-going costs incurred as a result of EDECA, (ii) approved the recovery of $125 million of the deferred balance over a ten-year amortization period beginning August 1, 2003, (iii) transferred to ACE’s then pending base rate case for further consideration approximately $25.4 million of the deferred balance (the base rate case ended in a settlement approved by the NJBPU in May 2005, the result of which is that any net rate impact from the deferral account recoveries and credits in future years will depend in part on whether rates associated with other deferred accounts considered in the case continue to generate over-collections relative to costs), and (iv) estimated the overall deferral balance as of July 31, 2003 at $195.0 million, of which $44.6 million was disallowed recovery by ACE. Although ACE believes the record does not justify the level of disallowance imposed by the NJBPU in the final order, the $44.6 million of disallowed incurred costs were reserved during the years 1999 through 2003 (primarily 2003) through charges to earnings, primarily in the operating expense line item “deferred electric service costs,” with a corresponding reduction in the regulatory asset balance sheet account. In 2005, an additional $1.2 million in interest on the disallowed amount was identified and reserved by ACE. In August 2004, ACE filed a notice of appeal with respect to the July 2004 final order with the Appellate Division of the Superior Court of New Jersey (the Appellate Division), which hears appeals of the decisions of New Jersey administrative agencies, including the NJBPU. On August 9, 2007, the Appellate Division, citing deference to the factual and policy findings of the NJBPU, affirmed the NJBPU’s decision in its entirety, rejecting challenges from ACE and the Division of Rate Counsel. On September 10, 2007, ACE filed an application for certification to the New Jersey Supreme Court. On January 15, 2008, the New Jersey Supreme Court denied ACE’s application for certification. Because the full amount at issue in this proceeding was previously reserved by ACE, there will be no further financial statement impact to ACE.
Divestiture Cases
District of Columbia
Final briefs on Pepco’s District of Columbia divestiture proceeds sharing application were filed with the DCPSC in July 2002 following an evidentiary hearing in June 2002. That application was filed to implement a provision of Pepco’s DCPSC-approved divestiture settlement that provided for a sharing of any net proceeds from the sale of Pepco’s generation-related assets. One of the principal issues in the case 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, 2007, the District of Columbia allocated portions
of EDIT and ADITC associated with the divested generating assets were approximately $6.5 million and $5.8 million, respectively.
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 ($5.8 million as of December 31, 2007), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($4.0 million as of December 31, 2007) 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 2003, the IRS issued a notice of proposed rulemaking (NOPR), which would allow for the sharing of EDIT and ADITC related to divested assets with utility customers on a prospective basis and at the election of the taxpayer on a retroactive basis. In December 2005 a revised NOPR was issued which, among other things, withdrew the March 2003 NOPR and eliminated the taxpayer’s ability to elect to apply the regulation retroactively. Comments on the revised NOPR were filed in March 2006, and a public hearing was held in April 2006. Pepco filed a letter with the DCPSC in January 2006, in which it has reiterated that the DCPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations. 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 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, 2007, the Maryland allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $9.1 million and $10.4 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 (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 ($9.1 million as of December 31, 2007), 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 ($10.4 million as of December 31, 2007), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($7.2 million as of December 31, 2007), 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. Pepco filed a letter with the MPSC in January 2006, in which it has reiterated that the MPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations.
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 and Pepco does not believe that it will do so until action is taken by the IRS as described above. 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 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.
New Jersey
In connection with the divestiture by ACE of its nuclear generating assets, the NJBPU in July 2000 preliminarily determined that the amount of stranded costs associated with the divested assets that ACE could recover from ratepayers should be reduced by approximately $94.8 million, consisting of $54.1 million of accumulated deferred federal income taxes (ADFIT) associated with accelerated depreciation on the divested nuclear assets, and $40.7 million of current tax loss from selling the assets at a price below the tax basis.
The $54.1 million in deferred taxes associated with the divested assets’ accelerated depreciation, however, is subject to the normalization rules. Due to uncertainty under federal tax law regarding whether the sharing of federal income tax benefits associated with the divested assets, including ADFIT related to accelerated depreciation, with ACE’s customers would violate the normalization rules, ACE submitted a request to the IRS for a Private Letter Ruling
(PLR) to clarify the applicable law. The NJBPU delayed its final determination of the amount of recoverable stranded costs until after the receipt of the PLR.
On May 25, 2006, the IRS issued the PLR in which it stated that returning to ratepayers any of the unamortized ADFIT attributable to accelerated depreciation on the divested assets after the sale of the assets by means of a reduction of the amount of recoverable stranded costs would violate the normalization rules.
On June 9, 2006, ACE submitted a letter to the NJBPU, requesting that the NJBPU conduct proceedings to finalize the determination of the stranded costs associated with the sale of ACE’s nuclear assets in accordance with the PLR. In the absence of an NJBPU action regarding ACE’s request, on June 22, 2007, ACE filed a motion requesting that the NJBPU issue an order finalizing the determination of such stranded costs in accordance with the PLR. On October 24, 2007, the NJBPU approved a stipulation resolving the ADFIT issue and issued a clarifying order, which concludes that the $94.8 million in stranded cost reduction, including the $54.1 million in ADFIT, does not violate the IRS normalization rules. In explaining this result, the NJBPU stated that (i) its earlier orders determining ACE’s recoverable stranded costs “net of tax” did not cause ADFIT associated with certain divested nuclear assets to reduce stranded costs otherwise recoverable from ACE’s ratepayers, and (ii) because the Market Transition Charge-Tax component of the stranded cost recovery was intended by the NJBPU to gross-up “net of tax” stranded costs, thereby ensuring and establishing that the ADFIT balance was not flowed through to ratepayers, the normalization rules were not violated.
Default Electricity Supply Proceedings
Virginia
In June 2007, the Virginia State Corporation Commission (VSCC) denied DPL’s request for an increase in its rates for Default Service for the period July 1, 2007 to May 31, 2008. DPL appealed in both state and federal courts. Those appeals have been dismissed in light of the closing of the sale of DPL's Virginia electric operations as described below under the heading “DPL Sale of Virginia Operations.”
ACE Sale of B.L. England Generating Facility
On February 8, 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, for which it received proceeds of approximately $9 million. At the time of the sale, RC Cape May and ACE agreed to submit to arbitration the issue of whether RC Cape May, under the terms of the purchase agreement, must pay to ACE an additional $3.1 million as part of the purchase price. On February 26, 2008, the arbitrators issued a decision awarding $3.1 million to ACE, plus interest, attorneys’ fees and costs, for a total award of approximately $4.2 million.
On July 18, 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement. 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. In
addition, RC Cape May has asserted a claim for indemnification from ACE in the amount of $25 million if the TSA is held not to be enforceable against Citgo. While ACE believes that it has defenses to the indemnification under the terms of the purchase agreement, 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 sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. ACE anticipates that approximately $9 million to $10 million of additional regulatory assets related to B.L. England may, subject to NJBPU approval, be eligible for recovery as stranded costs. Approximately $47 million in emission allowance credits associated with B. L. England were monetized for the benefit of ACE’s ratepayers pursuant to the NJBPU order approving the sale. Net proceeds from the sale of the plant and monetization of the emission allowance credits, estimated to be $32.2 million as of December 31, 2007, will be credited to ACE’s ratepayers in accordance with the requirements of EDECA and NJBPU orders. The appropriate mechanism for crediting the net proceeds from the sale of the plant and the monetized emission allowance credits to ratepayers is being determined in a proceeding that is currently pending before the NJBPU.
DPL Sale of Virginia Operations
On January 2, 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price of approximately $45.2 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5.4 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 are purchasing (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date. These sales are expected to result in an immaterial financial gain to DPL that will be recorded in the first quarter of 2008.
Pepco Energy Services Deactivation of Power Plants
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 MW. 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 MW. 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 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. Prior to deactivation of the plants, Pepco Energy Services may incur deficiency charges imposed by PJM at a rate up to two times the capacity payment price that the plants receive. Deactivation is not expected to have a material impact on PHI’s financial condition, results of operations or cash flows.
General Litigation
During 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.” Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepco’s property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings are not entirely clear, it appears that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant.
Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of December 31, 2007, 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 current 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.
On September 19, 2007, the Delaware District Court issued an order granting summary judgment in favor of the PHI Parties. On October 12, 2007, the plaintiffs filed an appeal of the decision to the U.S. Court of Appeals for the Third Circuit.
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.
Cambridge, Maryland Site. In July 2004, DPL entered into an administrative consent order (ACO) with the Maryland Department of the Environment (MDE) to perform a Remedial Investigation/Feasibility Study (RI/FS) to further identify the extent of soil, sediment and ground and surface water contamination related to former MGP operations at a Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The MDE has approved the RI and DPL submitted a final FS to MDE on February 15, 2007. No further MDE action is required with respect to the final FS. The costs of cleanup (as determined by the RI/FS and subsequent negotiations with MDE) are anticipated to be approximately $3.8 million. The remedial action to be taken by DPL will include dredging activities within Cambridge Creek, which are expected to commence in March 2008, and soil excavation on DPL’s and adjacent property as early as August 2008. The final cleanup costs will include protective measures to control contaminant migration during the dredging activities and improvements to the existing shoreline.
Delilah Road Landfill Site. In November 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 other PRPs, signed an ACO 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 U.S. Environmental Protection Agency’s (EPA’s) costs 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) and in October 2007, EPA and the PRP group entered into a tolling agreement to permit the parties sufficient time to execute a final settlement agreement. This settlement agreement 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. 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.
Frontier Chemical Site. On June 29, 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 the 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.
Carolina Transformer Site. In August 2006, EPA notified each of DPL and Pepco that they have been identified as entities that sent PCB-laden oil to be disposed at the Carolina Transformer site in Fayetteville, North Carolina. The EPA notification stated that, on this basis, DPL and Pepco may be PRPs. In December 2007, DPL and Pepco agreed to enter into a settlement agreement with EPA and the PRP group at the Carolina Transformer site. Under the terms of the settlement, (i) Pepco and DPL each will pay $162,000 to EPA to resolve any liability that it might have at the site, (ii) EPA covenants not to sue or bring administrative action against DPL and Pepco for response costs at the site, (iii) other PRP group members release all rights for cost recovery or contribution claims they may have against DPL and Pepco, and (iv) DPL and Pepco release all rights for cost recovery or contribution claims that they may have against other parties settling with EPA. The consent decree is expected to be filed with the U.S. District Court in North Carolina in the second quarter of 2008.
Deepwater Generating Station. On December 27, 2005, NJDEP issued a Title V Operating Permit for Conectiv Energy’s Deepwater Generating Station. The permit includes new limits on unit heat input. In order to comply with these new operational limits, Conectiv Energy restricted the output of the Deepwater Generating Station’s Unit 1 and Unit 6. In 2006 and the first half of 2007, these restrictions resulted in operating losses of approximately $10,000
per operating day on Unit 6, primarily because of lost revenues due to reduced output, and to a lesser degree because of lost revenues related to capacity requirements of PJM. Since June 1, 2007, Deepwater Unit 6 can operate within the heat input limits set forth in the Title V Operating Permit without restricting output, because of technical improvements that partially corrected the inherent bias in the continuous emissions monitoring system that had caused recorded heat input to be higher than actual heat input. In order to comply with the heat input limit at Deepwater Unit 1, Conectiv Energy continues to restrict Unit 1 output, resulting in operating losses of approximately $500,000 in the second half of 2007 and projected operating losses in 2008 of approximately $500,000, due to penalties and lost revenues related to PJM capacity requirements. Beyond 2008, while penalties due to PJM capacity requirements are not expected, further operating losses due to lost revenues related to PJM capacity requirements may continue to be incurred. The operating losses due to reduced output on Unit 1 have been, and are expected to continue to be, insignificant. Conectiv Energy is challenging these heat input restrictions and other provisions of the Title V Operating Permit for Deepwater Generating Station in the New Jersey Office of Administrative Law (OAL). On October 2, 2007, the OAL issued a decision granting summary decision in favor of Conectiv Energy, finding that hourly heat input shall not be used as a condition or limit for Conectiv Energy’s electric generating operations. On October 26, 2007, the NJDEP Commissioner denied NJDEP’s request for interlocutory review of the OAL order and determined that the Commissioner would review the October 2, 2007 order upon completion of the proceeding on Conectiv Energy’s other challenges to the Deepwater Title V permit. A hearing on the remaining challenged Title V permit provisions is scheduled for mid-April 2008.
On April 3, 2007, NJDEP issued an Administrative Order and Notice of Civil Administrative Penalty Assessment (the First Order) alleging that at Conectiv Energy's Deepwater Generating Station, the maximum gross heat input to Unit 1 exceeded the maximum allowable heat input in calendar year 2005 and the maximum gross heat input to Unit 6 exceeded the maximum allowable heat input in calendar years 2005 and 2006. The order required the cessation of operation of Units 1 and 6 above the alleged permitted heat input levels, assessed a penalty of approximately $1.1 million and requested that Conectiv Energy provide additional information about heat input to Units 1 and 6. Conectiv Energy provided NJDEP Units 1 and 6 calendar year 2004 heat input data on May 9, 2007, and calendar years 1995 to 2003 heat input data on July 10, 2007. On May 23, 2007, NJDEP issued a second Administrative Order and Notice of Civil Administrative Penalty Assessment (the Second Order) alleging that the maximum gross heat input to Units 1 and 6 exceeded the maximum allowable heat input in calendar year 2004. The Second Order required the cessation of operation of Units 1 and 6 above the alleged permitted heat input levels and assessed a penalty of $811,600. Conectiv Energy has requested a contested case hearing challenging the issuance of the First Order and the Second Order and moved for a stay of the orders pending resolution of the Title V Operating Permit contested case described above. On November 29, 2007, the OAL issued orders placing the First Order and the Second Order on the inactive list for six months. Until the OAL decision discussed above is final, it will not have an impact on these currently inactive enforcement cases.
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, which was 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 exchange under IRC Section 1031. In July 2006, Conectiv filed a protest of this disallowance to the IRS Office of Appeals.
PHI believes that its tax position related to this transaction is proper based on applicable statutes, regulations and case law and is contesting the disallowance. However, there is no absolute assurance that Conectiv’s position will prevail. If the IRS prevails, Conectiv would be subject to additional income taxes, interest and possible penalties. However, a portion of the denied benefit would be offset by additional tax depreciation. PHI has accrued approximately $4.9 million related to this matter.
As of December 31, 2007, if the IRS were to fully prevail, the potential cash impact on PHI would be current income tax and interest payments of approximately $31.2 million and the earnings impact would be approximately $9.8 million in after-tax interest.
Federal Tax Treatment of Cross-Border Leases
PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which, as of December 31, 2007, had a book value of approximately $1.4 billion, and from which PHI currently derives approximately $60 million per year in tax benefits in the form of interest and depreciation deductions.
In 2005, the Treasury Department and IRS issued Notice 2005-13 informing taxpayers that the IRS intends to challenge on various grounds the purported tax benefits claimed by taxpayers entering into certain sale-leaseback transactions with tax-indifferent parties (i.e., municipalities, tax-exempt and governmental entities), including those entered into on or prior to March 12, 2004 (the Notice). All of PCI’s cross-border energy leases are with tax indifferent parties and were entered into prior to 2004. Also in 2005, the IRS published a Coordinated Issue Paper concerning the resolution of audit issues related to such transactions. PCI’s cross-border energy leases are similar to those sale-leaseback transactions described in the Notice and the Coordinated Issue Paper.
PCI’s leases have been under examination by the IRS as part of the normal PHI tax audit. In 2006, the IRS issued its final RAR for its audit of PHI’s 2001 and 2002 income tax returns. In the RAR, the IRS disallowed the tax benefits claimed by PHI with respect to these leases for those years. The tax benefits claimed by PHI with respect to these leases from 2001 through December 31, 2007 were approximately $347 million. PHI has filed a protest against the IRS adjustments and the unresolved audit has been forwarded to the U.S. Office of Appeals. The ultimate outcome of this issue is uncertain; however, if the IRS prevails, PHI would be subject to additional taxes, along with interest and possibly penalties on the additional taxes, which could have a material adverse effect on PHI’s financial condition, results of operations, and cash flows. PHI believes that its tax position related to these transactions was appropriate based on
applicable statutes, regulations and case law, and intends to contest the adjustments proposed by the IRS; however, there is no assurance that PHI’s position will prevail.
In 2006, the FASB issued FASB Staff Position (FSP) on Financial Accounting Standards (FAS) 13-2, which amends SFAS No. 13 effective for fiscal years beginning after December 15, 2006. This amendment requires a lease to be repriced and the book value adjusted when there is a change or probable change in the timing of tax benefits of the lease, regardless of whether the change results in a deferral or permanent loss of tax benefits. Accordingly, a material change in the timing of cash flows under PHI’s cross-border leases as the result of a settlement with the IRS would require an adjustment to the book value of the leases and a charge to earnings equal to the repricing impact of the disallowed deductions which could result in a material adverse effect on PHI’s financial condition, results of operations, and cash flows. PHI believes its tax position was appropriate and at this time does not believe there is a probable change in the timing of its tax benefits that would require repricing the leases and a charge to earnings.
On December 14, 2007 the U.S. Senate passed its version of the Farm, Nutrition, and Bioenergy Act of 2007 (H.R. 2419), which contains a provision that would apply passive loss limitation rules to leases with foreign tax indifferent parties effective for taxable years beginning after December 31, 2006, even if the leases were entered into on or prior to March 12, 2004. The U.S. House of Representatives version of this proposed legislation which it passed on July 27, 2007 does not contain any provision that would modify the current treatment of leases with tax indifferent parties. Enactment into law of a bill that is similar to that passed by the U.S. Senate in its current form could result in a material delay of the income tax benefits that PHI would receive in connection with its cross-border energy leases. Furthermore, if legislation of this type were to be enacted, under FSP FAS 13-2, PHI would be required to adjust the book value of the leases and record a charge to earnings equal to the repricing impact of the deferred deductions which could result in a material adverse effect on PHI’s financial condition, results of operations and cash-flows. The U.S. House of Representatives and the U.S. Senate are expected to hold a conference in the near future to reconcile the differences in the two bills to determine the final legislation.
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 released 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 believes will be acceptable to the IRS.
At the same time as the new proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which is intended to limit the ability of certain taxpayers to utilize the method of accounting for income tax purposes for 2004 and prior years with respect to capitalizable construction costs. In line with this Revenue Ruling, the IRS RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco, DPL and ACE had claimed on those returns 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 Appeals Office.
In February 2006, PHI paid approximately $121 million of taxes to cover the amount of additional taxes 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, has adopted on its 2005 tax return. However, if the IRS is successful in requiring Pepco, DPL and ACE to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management’s estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006. It is reasonably possible that PHI’s unrecognized tax benefits related to this issue will significantly decrease in the next 12 months as a result of a settlement with the IRS.
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 to its financial condition or results of operations under different conditions or using different assumptions. Pepco Holdings has discussed the development, selection and disclosure of each of these policies with the Audit Committee of the Board of Directors.
Goodwill Impairment Evaluation
Pepco Holdings believes that the estimates involved in its goodwill impairment evaluation process represent “Critical Accounting Estimates” because (i) they may be susceptible to change from period to period because management is required to make assumptions and judgments about the discounting of future cash flows, 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 and the net loss related to an impairment charge could be material.
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. Substantially all of Pepco Holdings’ goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and was allocated to Pepco Holdings’ Power Delivery segment. In order to estimate the fair value of its Power Delivery segment, Pepco Holdings discounts the estimated future cash flows associated with the segment using a discounted cash flow model with a single interest rate that is commensurate with the risk involved with such an investment. The estimation of fair value is dependent on a number of
factors, including but not limited to interest rates, future growth assumptions, operating and capital expenditure requirements and other factors, changes in which could materially impact the results of impairment testing. Pepco Holdings’ July 1, 2007 goodwill impairment testing indicated that its goodwill balance was not impaired. A hypothetical decrease in the Power Delivery segment’s forecasted cash flows of 10 percent would not have resulted in an impairment charge.
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, which is discussed above.
For a discussion of PHI’s impairment losses during 2007, refer to the “Impairment Losses” section in the accompanying Consolidated Results of Operations discussion.
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), “Summary of Significant Accounting Policies - Accounting for Derivatives” to the consolidated financial statements of PHI included in Item 8 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
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, an internal model is used to interpolate broker quality price information. 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, the reported pension and other postretirement benefit liability on the balance sheet, and the reported annual net periodic pension and other postretirement benefit cost on the income statement. In terms of quantifying the anticipated impact of a change in assumptions, Pepco Holdings estimates that a .25% change in the discount rate used to value the benefit obligations could result in a $5 million impact on its consolidated balance sheets and statements of earnings. Additionally, Pepco Holdings estimates that a .25% change in the expected return on plan assets could result in a $4 million impact on the consolidated balance sheets and statements of earnings and a .25% change in the assumed healthcare cost trend rate could result in a $.5 million impact on its consolidated balance sheets and statements of earnings. Pepco Holdings’ management consults with its actuaries and investment consultants when selecting its plan assumptions.
Pepco Holdings follows the guidance of SFAS No. 87, “Employers’ Accounting for Pensions,” SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” and 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), when accounting for these benefits. Under these accounting standards, assumptions are made regarding the valuation of benefit obligations and the performance of plan assets. In accordance with these standards, the impact of changes in these 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. Plan assets are stated at their market value as of the measurement date, which is December 31.
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 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 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 (2) “Summary of Significant Accounting Policies -- Newly Adopted Accounting Standards and Recently Issued Accounting Policies, 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:
·
Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;
·
Changes in and compliance with environmental and safety laws and policies;
·
Weather conditions;
·
Population growth rates and demographic patterns;
·
Competition for retail and wholesale customers;
·
General economic conditions, including potential negative impacts resulting from an economic downturn;
·
Growth in demand, sales and capacity to fulfill demand;
·
Changes in tax rates or policies or in rates of inflation;
·
Changes in accounting standards or practices;
·
Changes in project costs;
·
Unanticipated changes in operating expenses and capital expenditures;
·
The ability to obtain funding in the capital markets on favorable terms;
·
Rules and regulations imposed by federal and/or state regulatory commissions, PJM and other regional transmission organizations (New York Independent System Operator, ISONE), the North American Electric Reliability Council and other applicable electric reliability organizations;
·
Legal and administrative proceedings (whether civil or criminal) and settlements that affect PHI’s business and profitability;
·
Pace of entry into new markets;
·
Volatility in market demand and prices for energy, capacity and fuel;
·
Interest rate fluctuations and credit market concerns; 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 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 our 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, 2007, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to Washington, D.C. customers.
Effective June 16, 2007, the Maryland Public Service Commission (MPSC) approved new electric service distribution base rates for Pepco (the 2007 Maryland Rate Order). The MPSC also 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 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 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.
RESULTS OF OPERATIONS
The following results of operations discussion compares the year ended December 31, 2007 to the year ended December 31, 2006. 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 transmission and the delivery of electricity, including the delivery of Default Electricity Supply, to Pepco’s customers within its service territory at regulated rates.
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 expense.
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 received by Pepco from PJM Interconnection, LLC (PJM) as a transmission owner, (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 (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 $73.8 million primarily due to the following: (i) $28.8 million increase 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), (ii) $26.1 million increase due to higher weather-related sales (a 21% increase in Cooling Degree Days and a 10% increase in Heating Degree Days), (iii) $12.1 million increase due to higher pass-through revenue primarily resulting from tax rate increases in the District of Columbia (offset primarily in Other Taxes), (iv) $11.5 million increase due to a 2007 Maryland Rate Order that became effective in June 2007, which includes a positive $3.3 million Revenue Decoupling Adjustment.
Default Electricity Supply
Default Supply Revenue, which is partially offset in Fuel and Purchased Energy, decreased by $90.3 million primarily due to the following: (i) $279.8 million decrease primarily due to commercial customers electing to purchase an increased amount of electricity from competitive suppliers, (ii) $54.4 million decrease due to differences in consumption among the various customer rate classes, partially offset by (iii) $194.9 million increase due to annual increases in market-based Default Electricity Supply rates, and (iv) $48.0 million increase due to higher weather-related sales, (a 21% increase in Cooling Degree Days and a 10 % increase in Heating Degree Days).
The following table shows percentages of Pepco’s total sales by jurisdiction that are derived from customers receiving Default Electricity Supply in that jurisdiction from Pepco.
Operating Expenses
Fuel and Purchased Energy
Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, decreased by $53.9 million to $1,245.8 million in 2007 from $1,299.7 in 2006. The decrease is primarily due to the following: (i) $316.1 million decrease primarily due to commercial customers electing to purchase an increased amount of electricity from competitive suppliers, (ii) $28.3 million decrease in the Default Electricity Supply deferral balance, partially offset by (iii) $211.6 million increase in average energy costs, the result of new annual Default Electricity Supply contracts, (iv) $49.1 million increase due to higher weather-related sales, and (v) $28.8 million increase for energy and capacity purchased under the Panda PPA (offset in Regulated T&D Electric Revenue). Fuel and Purchased Energy expense is primarily offset in Default Supply Revenue.
Other Operation and Maintenance
Other Operation and Maintenance increased by $22.7 million to $300.0 million in 2007 from $277.3 million in 2006. The increase was primarily due to the following: (i) $7.0 million increase in preventative maintenance and system operation costs, (ii) $6.9 million increase in employee-related costs, (iii) $3.9 million increase in regulatory expenses, (iv) $3.4 million increase due to construction project write-offs related to customer requested work, and (v) $2.0 million increase due to higher bad debt expenses.
Depreciation and Amortization
Depreciation and Amortization expenses decreased by $14.8 million to $151.4 million in 2007 from $166.2 million in 2006, 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 of $33.4 million in operating expenses and certain other costs as damages in the Mirant bankruptcy settlement.
Other Taxes
Other Taxes increased $16.4 million to $289.5 million in 2007 from $273.1 million in 2006 primarily due to increased pass-throughs resulting from tax rate increases in the District of Columbia (partially offset in Regulated T&D Electric Revenue).
Income Tax Expense
Pepco’s effective tax rates for the years ended December 31, 2007 and 2006 were 33.2% and 40.2%, respectively. The 7.0% 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, Pepco’s 2007 income tax expense was reduced by $19.5 million with a corresponding decrease to the effective tax rate of 10.4%. This decrease in the effective tax rate was partially offset by 2007 deferred tax basis adjustments and reduced book versus tax depreciation and amortization differences, which increased the year over year effective tax rate by 2.4% and 0.9%, respectively.
Capital Requirements
Capital Expenditures
Pepco’s total capital expenditures for the twelve months ended December 31, 2007, totaled $272.2 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 2008 through 2012:
Pepco expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.
Distribution, Transmission and Gas Delivery
The projected capital expenditures 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, PHI announced an initiative in Pepco’s service territory 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 the District of Columbia and Maryland. Pepco has made filings with the District of Columbia Public Service Commission and the MPSC for approval of certain aspects of these programs.
MAPP Project
On October 17, 2007, Pepco Holdings received the approval of the PJM Board of Managers to build a new 230-mile, 500-kilovolt interstate transmission line as part of PJM’s Regional Transmission Expansion Plan to address the reliability objectives of the PJM RTO system. The transmission line, which is referred to as the MAPP Project, will be located in northern Virginia, Maryland, the Delmarva Peninsula, and New Jersey. The preliminarily estimated cost of the 500-kilovolt MAPP Project is approximately $1 billion. Pepco’s portion of the preliminary estimated cost of the 500-kilovolt transmission line is approximately $119 million. Construction is expected to occur in sections over a six-year period with completion targeted by 2013.
Proceeds from Settlement of Mirant Bankruptcy Claims
In 2000, Pepco sold substantially all of its electricity generating assets to Mirant Corporation (Mirant). 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 asset sale, Pepco entered into transition power agreements with Mirant pursuant to which Mirant agreed to supply all of the energy and capacity needed by Pepco to fulfill its SOS obligations in Maryland and in the District of Columbia (the TPAs). Under a settlement to avoid the rejection by Mirant of its obligations under the TPAs in the bankruptcy proceeding, the terms of the TPAs were modified to increase the purchase price of the energy and capacity supplied by Mirant and Pepco received an allowed, pre-petition general unsecured claim in the bankruptcy in the amount of $105 million (the TPA Claim). In December 2005, Pepco sold the TPA Claim, plus the right to receive accrued interest thereon, to an unaffiliated third party for $112.5 million. In addition, Pepco received proceeds of $.5 million in settlement of an asbestos claim against the Mirant bankruptcy estate. After customer sharing, Pepco recorded a pre-tax gain of $70.5 million from the settlement of these claims.
In connection with the asset sale, Pepco and Mirant also entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco is obligated to purchase annually through 2021 from Panda-Brandywine LLP (Panda) under a power purchase agreement (the Panda PPA) at the purchase price Pepco is
obligated to pay to Panda. As part of the further settlement of Pepco’s claims against Mirant arising from the Mirant 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 is obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $413.9 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. These funds are being accounted for as restricted cash based on management’s intent to use such funds, and any interest earned thereon, for the sole purpose of paying for the future above-market capacity and energy purchase costs under the Panda PPA. Correspondingly, a regulatory liability has been established in the same amount to help offset the future above-market capacity and energy purchase costs. This restricted cash has been classified as a non-current asset to be consistent with the classification of the non-current regulatory liability, and any changes in the balance of this restricted cash, including interest on the invested funds, are being accounted for as operating cash flows.
As of December 31, 2007, the balance of the restricted cash account was $417.3 million. Based on a reexamination of the costs of the Panda PPA in light of current and projected wholesale market conditions conducted in the fourth quarter of 2007, Pepco determined that, principally due to increases in wholesale capacity prices, the present value above-market cost of the Panda PPA over the term of the agreement is expected to be significantly less than the current amount of the restricted cash account balance. Accordingly, on February 22, 2008, Pepco filed applications with the DCPSC and the MPSC requesting orders directing Pepco to maintain $320 million in the restricted cash account and to use that cash, and any future earnings on the cash, for the sole purpose of paying the future above-market cost of the Panda PPA (or, in the alternative, to fund a transfer or assignment of the remaining obligations under the Panda PPA to a third party). Pepco also requested that the order provide that any cash remaining in the account at the conclusion of the Panda PPA be refunded to customers and that any shortfall be recovered from customers. Pepco further proposed that the excess proceeds remaining from the settlement (approximately $94.6 million, representing the amount by which the regulatory liability of $414.6 million at December 31, 2007 exceeded $320 million) be shared with its customers in accordance with the procedures previously approved by each commission for the sharing of the proceeds received by Pepco from the sale to Mirant of its generating assets. The regulatory liability of $414.6 million at December 31, 2007 differs from the restricted cash amount of $417.3 million on that date, in part, because the regulatory liability has been reduced for the portion of the December 2007 Panda charges in excess of market that had not yet been paid from the restricted cash account. The amount of the restricted cash balance that Pepco is permitted to retain will be recorded as earnings upon approval of the sharing arrangement by the respective commissions. At this time, Pepco cannot predict the outcome of these proceedings.
In settlement of other damages claims against Mirant, Pepco in 2007 also received a settlement payment in the amount of $70.0 million. Of this amount (i) $33.4 million was recorded as a reduction in operating expenses, (ii) $21.0 million was recorded as a reduction in a net pre-petition receivable claim from Mirant, (iii) $15.0 million was recorded as a reduction in the capitalized costs of certain property, plant and equipment and (iv) $.6 million was recorded as a liability to reimburse a third party for certain legal costs associated with the settlement.
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 or Pepco’s industry’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;
·
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 project costs;
·
Unanticipated changes in operating expenses and capital expenditures;
·
The ability to obtain funding in the capital markets on favorable terms;
·
Restrictions 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 affect Pepco’s business and profitability;
·
Volatility in market demand and prices for energy, capacity and fuel;
·
Interest rate fluctuations and credit market concerns; 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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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 and Virginia (until the sale of its Virginia operations on January 2, 2008). 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 Default Service in Virginia (until the sale of its Virginia operations on January 2, 2008), as Standard Offer Service in Maryland and in Delaware on and after May 1, 2006, and as Provider of Last Resort (POLR) service in Delaware before May 1, 2006. DPL’s electricity distribution service territory covers approximately 6,000 square miles and has a population of approximately 1.3 million. As of December 31, 2007, approximately 65% of delivered electricity sales were to Delaware customers, approximately 32% were to Maryland customers, and approximately 3% were to Virginia customers. DPL also provides natural gas distribution service in northern Delaware. DPL’s natural gas distribution service territory covers approximately 275 square miles and has a population of approximately .5 million.
On January 2, 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price of approximately $45.2 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5.4 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 are purchasing (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date. These sales resulted in an immaterial financial gain to DPL that will be recorded during the first quarter of 2008.
Effective June 16, 2007, the Maryland Public Service Commission (MPSC) approved new electric service distribution base rates for DPL (the 2007 Maryland Rate Order). The MPSC also 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 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 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). 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.
RESULTS OF OPERATIONS
The following results of operations discussion compares the year ended December 31, 2007 to the year ended December 31, 2006. 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 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 transmission and the delivery of electricity, including the delivery of Default Electricity Supply, to DPL’s customers within its service territory at regulated rates.
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 expense.
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 received by DPL from PJM Interconnection, LLC (PJM) as a transmission owner, 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 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).
Regulated T&D Electric Revenue increased by $4.0 million primarily due to the following: (i) $11.0 million increase due to higher weather-related sales (a 15% increase in Heating Degree Days and a 13% increase in Cooling Degree Days), (ii) $8.8 million increase due to a 2007 Maryland Rate Order that became effective in June 2007, which includes a positive $1.6 million Revenue Decoupling Adjustment, partially offset by (iii) $10.0 million decrease due to a change in Delaware rate structure effective May 1, 2006, which shifted revenue from Regulated T&D Electric Revenue to Default Supply Revenue, and (iv) $4.0 million decrease due to a Delaware base rate reduction in May 2006.
Default Electricity Supply
Default Supply Revenue, which is partially offset in Fuel and Purchased Energy, increased by $33.9 million primarily due to the following: (i) $116.0 million increase due to annual increases in market-based Default Electricity Supply rates, (ii) $27.0 million increase due to higher weather-related sales (a 15% increase in Heating Degree Days and a 13% increase in Cooling Degree Days), (iii) $10.0 million increase 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, partially offset by (iv) $68.0 million decrease primarily due to commercial and industrial customers electing to purchase an increased amount of electricity from competitive suppliers, and (v) $50.0 million decrease due to differences in consumption among the various customer rate classes.
The following table shows the percentages of DPL’s total sales by jurisdiction that are derived from customers receiving Default Electricity Supply in that jurisdiction from DPL.
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 for on-system natural gas delivered sales and the transportation of natural gas for customers. Other Gas Revenue includes off-system natural gas sales and the release of excess system capacity.
Regulated Gas
Regulated Gas Revenue increased by $6.5 million primarily due to (i) $11.7 million increase due to colder weather (a 15% increase in Heating Degree Days), (ii) $5.7 million increase due to base rate increases effective in November 2006 and April 2007, (iii) $4.8 million increase due to differences in consumption among the various customer rate classes, (iv) $2.7 million increase due to customer growth of 1% in 2007, partially offset by (v) $18.4 million decrease due to Gas Cost Rate decreases effective November 2006, April 2007 and November 2007 resulting from lower natural gas commodity costs (offset in Gas Purchased Expense).
Other Gas Revenue increased by $29.4 million to $80.0 million in 2007 from $50.6 million in 2006 primarily due to higher off-system sales (partially offset in Gas Purchased Expense). The gas sold off-system resulted from increased demand from unaffiliated third party electric generators during periods of low customer demand for natural gas.
Operating Expenses
Fuel and Purchased Energy
Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $21.8 million to $838.6 million in 2007 from $816.8 million in 2006. The increase is primarily due to (i) $143.8 million increase in average energy costs, the result of new annual Default Electricity Supply contracts, (ii) $27.1 million increase due to higher weather-related sales, partially offset by (iii) $130.1 million decrease primarily due to commercial and
industrial customers electing to purchase an increased amount of electricity from competitive suppliers, (iv) $10.8 million decrease in network transmission expenses primarily due to POLR service obligations ending April 1, 2006, and (v) $8.1 million decrease in the Default Electricity Supply deferral balance. Fuel and Purchased Energy expense is primarily offset by Default Supply Revenue.
Gas Purchased
Total Gas Purchased, which is primarily offset in Regulated Gas Revenue and Other Gas Revenue, increased by $21.9 million to $220.3 million in 2007 from $198.4 million in 2006. The increase is primarily due to (i) $26.4 million increase in off-system sales, partially offset by (ii) $4.6 million decrease from the settlement of financial hedges (entered into as part of DPL’s regulated natural gas hedge program).
Other Operation and Maintenance
Other Operation and Maintenance increased by $20.5 million to $205.4 million in 2007 from $184.9 million in 2006. The increase was primarily due to the following: (i) $4.3 million increase in costs associated with Default Electricity Supply (primarily deferred and recoverable), (ii) $4.2 million increase in preventative maintenance and system operation costs, (iii) $3.7 million increase in employee-related costs, (iv) $2.5 million increase in customer service operation expenses, (v) $1.2 million increase due to higher bad debt expenses, and (vi) $1.1 million increase in accounting service expenses.
Depreciation and Amortization
Depreciation and Amortization decreased by $2.3 million to $74.4 million in 2007 from $76.7 million in 2006. The decrease is primarily due to fully amortized software.
Other Income (Expense)
Other Expenses (which are net of Other Income) increased by $3.0 million to a net expense of $39.9 million in 2007 from a net expense of $36.9 million in 2006. The increase is primarily due to an increase in interest expense on inter-company borrowings.
Income Tax Expense
DPL’s effective tax rates for the years ended December 31, 2007 and 2006 were 45.3% and 43.0%, respectively. The 2.3% increase in the effective tax rate in 2007 was primarily the result of certain 2007 deferred tax basis adjustments which increased the 2007 effective tax rate by 3.9 %. This increase in the effective tax rate was partially offset by 2007 and 2006 changes in estimates related to prior year tax liabilities, which reduced the year over year effective tax rate by 2.0%.
Capital Requirements
Capital Expenditures
DPL’s total capital expenditures for the twelve months ended December 31, 2007, totaled $132.6 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.
The table below shows DPL’s projected capital expenditures for the five-year period 2008 through 2012:
DPL expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.
Distribution, Transmission and Gas Delivery
The projected capital expenditures 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, PHI announced an initiative in DPL’s service territory 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 and the MPSC for approval of certain aspects of these programs. DPL’s preliminarily estimated cost to implement these proposals, if approved by the applicable regulatory commissions, is summarized in the chart above for the five-year period from 2008 to 2012.
MAPP Project
On October 17, 2007, Pepco Holdings received the approval of the PJM Board of Managers to build a new 230-mile, 500-kilovolt interstate transmission line as part of PJM’s Regional Transmission Expansion Plan to address the reliability objectives of the PJM RTO system. The transmission line, which is referred to as the MAPP Project, will be located in northern Virginia, Maryland, the Delmarva Peninsula, and New Jersey. The preliminarily estimated cost of the 500-kilovolt MAPP Project is approximately $1 billion. DPL’s portion of the preliminary cost of the 500-kilovolt transmission line is approximately $904 million. Construction is expected to occur in sections over a six-year period with completion targeted by 2013.
PHI also plans to add significant 230-kilovolt support lines in Maryland and New Jersey to connect with the new 500-kilovolt line at an approximate cost of $200 million. PJM continues to evaluate the 230-kilovolt support lines. Accordingly, DPL’s projected construction costs associated with these support lines are not included in the table above.
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 or DPL’s industry’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;
·
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 project costs;
·
Unanticipated changes in operating expenses and capital expenditures;
·
The ability to obtain funding in the capital markets on favorable terms;
·
Restrictions 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 affect DPL’s business and profitability;
·
Volatility in market demand and prices for energy, capacity and fuel;
·
Interest rate fluctuations and credit market concerns; 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 anticipated 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 our 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
ATLANTIC CITY ELECTRIC COMPANY
GENERAL OVERVIEW
Atlantic City Electric Company (ACE) is engaged in the generation, 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 1.0 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
On February 8, 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 requires 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, 2006 and 2005. In September 2006, ACE sold its interests in the Keystone and Conemaugh generating facilities, which for the years ended December 31, 2006 and 2005, are also reflected as discontinued operations.
The following table summarizes information related to the discontinued operations for the years presented (millions of dollars):
RESULTS OF OPERATIONS
The following results of operations discussion compares the year ended December 31, 2007 to the year ended December 31, 2006. 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 consists of revenue from the transmission and the delivery of electricity, including the delivery of Default Electricity Supply, to ACE’s customers within its service territory at regulated rates.
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 expense. Also included in Default Supply Revenue is revenue from transition bond charges and other restructuring related revenues (see Deferred Electric Service Costs).
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 transmission service revenue received by ACE from PJM Interconnection, LLC (PJM) as a transmission owner.
Regulated T&D Electric Revenue increased by $20.9 million primarily due to the following: (i) $8.1 million increase in transmission service revenue primarily due to an increase in the Federal Energy Regulatory Commission formula rate in June 2007, (ii) $5.9 million increase due to higher weather-related sales (a 10% increase in Heating Degree Days and an 8% increase in Cooling Degree Days), (iii) $4.5 million increase due to differences in consumption among the various customer rate classes, and (iv) $2.4 million increase due to customer growth of 1.0% in 2007.
Default Electricity Supply
Other Default Supply Revenue consists primarily of revenue from the resale of energy and capacity under non-utility generating contracts between ACE and unaffiliated third parties (NUGs) in the PJM Regional Transmission Organization (PJM RTO) market.
Default Supply Revenue, which is partially offset in Fuel and Purchased Energy, increased by $145.4 million primarily due to the following: (i) $68.2 million increase due to annual increases in market-based Default Electricity Supply rates, (ii) $53.7 million increase in wholesale energy revenues due to the sale in PJM at higher market prices of electricity purchased from NUGs, and (iii) $11.6 million increase due to higher weather-related sales (a 10% increase in Heating Degree Days and an 8% increase in Cooling Degree Days).
For the years ended December 31, 2007 and 2006, ACE’s customers served energy by ACE represented 80% and 78%, respectively, of ACE’s total sales.
Operating Expenses
Fuel and Purchased Energy
Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $126.8 million to $1,051.0 million in 2007 from $924.2 in 2006. The increase is primarily due to the following: (i) $89.8 million increase due to new annual BGS supply contracts, and (ii) $16.8 million increase due to higher weather-related sales. Fuel and Purchased Energy expense is primarily offset in Default Supply Revenue.
Other Operation and Maintenance
Other Operation and Maintenance increased by $17.1 million to $164.8 million in 2007 from $147.7 million in 2006. The increase was primarily due to the following: (i) $5.2 million increase in employee-related costs, (ii) $3.1 million increase in Demand Side Management program costs (offset in Deferred Electric Service costs), (iii) $2.8 million increase in customer service operation expenses, (iv) $1.5 million increase in accounting service expenses, and (v) $.7 million increase in regulatory expenses.
Depreciation and Amortization
Depreciation and Amortization expenses decreased by $31.1 million to $80.2 million in 2007 from $111.3 million in 2006. The decrease is primarily due to lower amortization of regulatory assets resulting from the 2006 sale of ACE’s interests in Keystone and Conemaugh.
Deferred Electric Service Costs
Deferred Electric Service Costs increased by $51.0 million to an expense of $66.0 million in 2007 from an expense of $15.0 million in 2006. The increase was primarily due to (i) $37.5 million net over-recovery associated with non-utility generating contracts between ACE and unaffiliated third parties, (ii) $11.7 million net over-recovery associated with BGS energy costs,
partially offset by (iii) $3.2 million net under-recovery associated with Demand Side Management program costs.
Income Tax Expense
ACE’s effective tax rates for the years ended December 31, 2007 and 2006 were 40.5% and 35.4%, respectively. The 5.1% increase in the effective tax rate in 2007 was primarily the result of 2007 and 2006 changes in estimates related to prior year tax liabilities, which increased the year over year effective tax rate by 4.8%.
Capital Requirements
Capital Expenditures
ACE’s total capital expenditures for the twelve months ended December 31, 2007, totaled $149.4 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 2008 through 2012:
ACE expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.
Distribution, Transmission and Gas Delivery
The projected capital expenditures 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, PHI announced an initiative in ACE’s service territory 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.
MAPP Project
On October 17, 2007, Pepco Holdings received the approval of the PJM Board of Managers to build a new 230-mile, 500-kilovolt interstate transmission line as part of PJM’s Regional Transmission Expansion Plan to address the reliability objectives of the PJM RTO system. The transmission line, which is referred to as the MAPP Project, will be located in northern Virginia, Maryland, the Delmarva Peninsula, and New Jersey. The preliminarily estimated cost of the 500-kilovolt MAPP Project is approximately $1 billion. ACE’s portion of the preliminary estimated cost of the 500-kilovolt transmission line is approximately $27 million. Construction is expected to occur in sections over a six-year period with completion targeted by 2013.
PHI also plans to add significant 230-kilovolt support lines in Maryland and New Jersey to connect with the new 500-kilovolt line at an approximate cost of $200 million. PJM continues to evaluate the 230-kilovolt support lines. Accordingly, ACE’s projected construction costs associated with these support lines are not included in the table above.
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 or ACE’s industry’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 project costs;
·
Unanticipated changes in operating expenses and capital expenditures;
·
The ability to obtain funding in the capital markets on favorable terms;
·
Restrictions 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 affect ACE’s business and profitability;
·
Volatility in market demand and prices for energy, capacity and fuel;
·
Interest rate fluctuations and credit market concerns; 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 anticipated 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 our 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.
Pepco Holdings, Inc.
Commodity Price Risk
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 and known minimum cash flows, and lock in favorable prices and margins when they become available. To a lesser extent, Conectiv Energy also engages in energy marketing activities. 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 prior to October 31, 2006, provided operating services under an agreement with an unaffiliated generating plant. PHI collectively refers to these energy marketing activities, including its commodity risk management activities, as “other energy commodity” activities and identifies this activity separately from the discontinued proprietary trading activity that was discontinued in 2003.
The Corporate Risk Management Committee has the responsibility for establishing corporate compliance requirements for the Competitive Energy businesses’ energy market participation. PHI collectively refers to these energy market activities, including its commodity risk management activities, as “other energy commodity” activities. PHI does not engage in proprietary trading activities. PHI uses a value-at-risk (VaR) model to assess the market risk of its Competitive Energy businesses’ energy commodity activities. PHI also uses other measures to limit and monitor risk in its energy commodity activities, including limits on the nominal size of positions and periodic loss limits. VaR represents the potential mark-to-market loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level. PHI estimates VaR using a delta-normal variance / covariance model with a 95 percent, one-tailed confidence level and assuming a one-day holding period. Since VaR is an estimate, it is not necessarily indicative of actual results that may occur.
(a)
This column represents all energy derivative contracts, normal purchase and sales contracts, modeled generation output and fuel requirements and modeled customer load obligations for PHI’s other energy commodity activities.
For additional information about PHI’s derivative activities refer to Note (2), “Accounting for Derivatives” and Note 13, “Use of Derivatives in Energy and Interest Rate Hedging Activities” of the Consolidated Financial Statements of Pepco Holdings included 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.
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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, 2007 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, 2007.
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.
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, 2007 and December 31, 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 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, 2007, 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 Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. 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 8 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
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
February 29, 2008
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 principal business operations:
·
electricity and natural gas delivery (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 (the Exchange Act):
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 (Conectiv Energy) and Pepco Energy Services, Inc. (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 the 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, which consists of the transmission, distribution and default supply of electricity and the delivery and supply of natural gas.
PHI’s Power Delivery business is conducted by its three regulated utility subsidiaries: Pepco, DPL and ACE. Each subsidiary is a regulated public utility in the jurisdictions that comprise its service territory. Pepco, DPL and ACE each owns and operates a network of wires, substations and other equipment that are classified either as transmission or distribution facilities.
Transmission facilities are high-voltage systems that carry wholesale electricity into, or across, the utility’s service territory. Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utility’s service territory. Together the three companies constitute a single segment for financial reporting purposes.
Each company is responsible for the delivery of electricity and, in the case of DPL, natural gas in its service territory, for which it is paid tariff rates established by the 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
Provider of Last Resort service - before May 1, 2006
Standard Offer Service (SOS) - on and after May 1,
District of Columbia SOS
Maryland
SOS
New Jersey
Basic Generation Service (BGS)
Virginia
Default Service
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 subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services). Conectiv Energy and Pepco Energy Services are separate operating segments for financial reporting purposes.
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, 2007 of approximately $1.4 billion. This activity constitutes a fourth operating segment, which is designated as “Other Non-Regulated” for financial reporting purposes. For a discussion of PHI’s cross-border leasing transactions, see “Regulatory and Other Matters -- Federal Tax Treatment of Cross-Border Leases,” in Note (12), “Commitments and Contingencies.”
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Consolidation Policy
The accompanying consolidated financial statements include the accounts of Pepco Holdings and its wholly owned subsidiaries. All material intercompany balances and transactions between subsidiaries have been eliminated. Pepco Holdings uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies in which it
holds a 20% to 50% voting interest and cannot exercise control over the operations and policies of the investment. Undivided interests in several jointly owned electric plants previously held by PHI, and certain transmission and other facilities currently held, are consolidated in proportion to PHI’s percentage interest in the facility.
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. 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 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 estimates used by Pepco Holdings include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in goodwill and asset impairment evaluations, fair value calculations (based on estimated market pricing) associated with derivative instruments, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, and income tax provisions and reserves. Additionally, 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 that are probable and reasonably estimable.
Changes in Accounting Estimates
During 2007, as a result of depreciation studies presented as part of Pepco's and DPL’s Maryland rate cases, the MPSC approved new lower depreciation rates for Maryland distribution assets owned by Pepco and DPL. This resulted in lower depreciation expense of approximately $19.1 million for the last six months of 2007.
During 2005, Pepco recorded the impact of an increase in estimated unbilled revenue (electricity and gas delivered to the customer but not yet billed), primarily reflecting a change in Pepco’s unbilled revenue estimation process. This modification in accounting estimate increased net earnings for the year ended December 31, 2005 by approximately $2.2 million.
During 2005, DPL and ACE each recorded the impact of reductions in estimated unbilled revenue, primarily reflecting an increase in the estimated amount of power line losses (electricity lost in the process of its transmission and distribution to customers). These changes in accounting estimates reduced net earnings for the year ended December 31, 2005 by approximately $7.4 million, of which $1.0 million was attributable to DPL and $6.4 million was attributable to ACE.
During 2005, Conectiv Energy increased the estimated useful lives of its generation assets which resulted in lower depreciation expense of approximately $5.3 million.
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 $169.8 million and $172.2 million as of December 31, 2007 and 2006, 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, the impact of which could be material.
The 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. 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.
Regulation of Power Delivery Operations
The Power Delivery operations of Pepco are regulated by the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC).
The Power Delivery operations of DPL are regulated by the Delaware Public Service Commission (DPSC) and the MPSC and, until the sale of its Virginia operations on January 2, 2008, was 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 each of 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 must 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 June 16, 2007, the MPSC approved for both companies a bill stabilization adjustment mechanism (BSA) for retail customers. See Note 12 “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, 2007 is a regulatory asset and is included in the “Other” line item on the table of regulatory asset balances listed below.
The components of Pepco Holdings’ regulatory asset balances at December 31, 2007 and 2006 are as follows:
The components of Pepco Holdings’ regulatory liability balances at December 31, 2007 and 2006 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.
Recoverable 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.
Deferred Energy Supply Costs: The regulatory liability balances of $240.9 million and $164.9 million for the years ended December 31, 2007 and 2006, respectively, primarily represent deferred costs related to a net over-recovery by ACE connected with the provision of BGS and other restructuring related costs incurred by ACE. The regulatory asset balances of $1.7 million and $6.9 million for the years ended December 31, 2007 and 2006, respectively, represent deferred fuel costs for DPL’s gas business, which are recovered annually.
Deferred Recoverable 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 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 and DPL. The ACE amortization period began in July 1994 and will end in May 2014 and earns a return. The DPL amortization period ended in October 2007 and earned 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 to occur over an 18-month period beginning June 2007. The Maryland deferral will be recovered from participating customers at a rate per kilowatt-hour based on energy usage during the recovery period.
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.
Federal and New Jersey Tax Benefits, Related to Securitized Stranded Costs: Securitized stranded costs include a portion of stranded costs attributable to the future tax benefit expected to be realized when the higher tax basis of generating plants divested by ACE is deducted for New Jersey state income tax purposes as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE’s regulated electricity delivery customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service issues its final regulations with respect to normalization of these federal excess deferred taxes.
Asset Removal Costs: Represents Pepco’s and DPL’s asset retirement obligations associated with removal costs accrued using public service commission approved depreciation techniques for transmission, distribution, and general utility property.
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.
Asset Retirement Obligation: During the first quarter of 2006, ACE recorded an asset retirement obligation of $60 million for B.L. England plant demolition and environmental remediation costs; the obligation was to be amortized over a two-year period. The cumulative amortization of $33.0 million at December 31, 2006, was recorded as a regulatory asset -- “Asset Retirement Cost.” As discussed in Note (12) “Commitments and Contingencies -- ACE Sale of Generating Assets,” in the first quarter of 2007, ACE completed the sale of the B.L. England generating facility and the asset retirement obligation and asset retirement cost were reversed.
Gain from Sale of B.L. England: In the first quarter of 2007, ACE completed the sale of the B.L. England generating facility. Net proceeds from the sale of the plant and monetization of the emission allowance credits will be credited to ACE’s ratepayers in accordance with the requirements of the New Jersey Electric Discount and Energy Competition Act (EDECA) and NJBPU orders.
Settlement Proceeds - Mirant Bankruptcy Claims: Represents the $413.9 million of net proceeds received by Pepco from settlement of a Mirant Corporation (Mirant) claim, plus interest earned, which will be used to pay for future above-market capacity and energy purchases under a power purchase agreement entered into with Panda-Brandywine L.P. (Panda) over the remaining life of the agreement, which extends through 2021 (the Panda PPA).
Gain from Sale of Keystone and Conemaugh: In the third quarter of 2006, ACE completed the sale of its interests in the Keystone and Conemaugh generating facilities for $175.4 million (after giving effect to post-closing adjustments). The total gain recognized on this sale, net of adjustments, came to $131.4 million. Approximately $81.3 million of the net gain from the sale offset the remaining regulatory asset balance, which ACE has been recovering in rates, and $49.8 million of the net gain is being returned to ratepayers over a 33-month period as a credit on their bills, which began during the October 2006 billing period. The balance to be repaid to customers is $30.7 million as of December 31, 2007.
Other: Includes miscellaneous regulatory liabilities such as the over-recovery of procurement, transmission and administrative costs associated with Maryland, Delaware and District of Columbia SOS.
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.
Changes in the fair value of derivatives designated as fair value hedges result in a change in the value of the asset, liability, or firm commitment being hedged. Changes in fair value of the asset, liability, or firm commitment, and the hedging instrument, are recorded in the Consolidated Statements of Earnings.
Certain commodity forwards are not required to be recorded on a mark-to-market basis of accounting under SFAS No. 133. These contracts are designated as “normal purchases and sales” as permitted by 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, normal sales as operating revenue, and normal purchases as fuel and purchased energy expenses.
PHI uses option contracts to mitigate certain risks. These options are normally marked-to-market through current earnings because of the difficulty in qualifying options for hedge accounting treatment. Market prices, when available, are used to value options. If market prices are not available, the market value of the options is estimated using Black-Scholes closed form models. Option contracts typically make up only a small portion of PHI’s total derivatives portfolio.
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. 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.
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. When a hedging gain or loss is realized, it is presented on a net basis in the same category as the underlying item being hedged. Normal purchase and sale transactions are presented gross on the Consolidated Statements of Earnings as they are realized. The unrealized assets and liabilities that offset unrealized derivative gains and losses are presented gross on the Consolidated Balance Sheets except where contractual netting agreements are in place.
Emission Allowances
Emission allowances for sulfur dioxide and nitrous oxide are allocated to generation owners by the U.S. Environmental Protection Agency (EPA) based on federal programs designed to regulate the emissions from power plants. EPA allotments have no cost basis to the generation owners. Depending on the run-time of a generating unit in a given year, and other pollution controls it may have, the unit may need additional allowances above its allocation or it may have excess allowances. Allowances are traded among companies in an over-the-counter market, which allows companies to purchase additional allowances to avoid incurring penalties for noncompliance with applicable emissions standards or to sell excess allowances.
Pepco Holdings accounts for emission allowances as inventory in the balance sheet line item “Fuel, materials and supplies - at average cost.” Allowances from EPA allocations are added to current inventory each year at a zero basis. Additional purchased allowances are recorded at cost. 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, 2007 and 2006, the book value of emission allowances was $8.4 million and $11.7 million, respectively. Pepco Holdings has established a committee to monitor compliance with emissions regulations and ensure its power plants have the required number of allowances.
Goodwill and Goodwill Impairment
Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. Substantially all of Pepco Holdings’ goodwill was generated by Pepco’s August 2002 acquisition of Conectiv and was recorded at the PHI level. 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. The July 1, 2007 test indicated that none of Pepco Holdings’ goodwill balance was impaired.
A roll forward of PHI’s goodwill balance follows (millions of dollars):
Long-Lived Assets Impairment
Pepco Holdings 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 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 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.
During 2007, Pepco Holdings recorded pre-tax impairment losses of $2.0 million ($1.3 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 $18.9 million ($13.7 million after-tax) related to certain energy services business assets owned by Pepco Energy Services. The impairments were recorded as a result of the execution of contracts to sell certain assets, and due to the lower than expected production and related estimated cash flows from other assets. The fair value of the assets under contracts for sale was determined based on the sales contract price; while the fair value of the other assets was determined by estimating future expected production and cash flows.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, money market funds, and commercial paper with original maturities of three months or less.
Restricted Cash and Cash Equivalents
The restricted cash included in Current Assets and the restricted cash and 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 solely to fund the future above-market capacity and energy purchase costs under the Panda PPA. The classification as current or non-current conforms to the classification of the related liabilities.
Prepaid Expenses and Other
The prepaid expenses and other balance primarily consists of prepayments and the current portion of deferred income tax assets.
Accounts Receivable and Allowance for Uncollectible Accounts
Pepco Holdings’ subsidiaries’ accounts receivable balances primarily consist 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). PHI uses the allowance method to account for uncollectible accounts receivable.
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
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 $7.0 million, $2.8 million, and $3.3 million for the years ended December 31, 2007, 2006 and 2005, respectively.
Pepco Holdings recorded amounts for the equity component of AFUDC of $4.4 million, $3.8 million and $4.7 million for the years ended December 31, 2007, 2006, and 2005, respectively.
Leasing Activities
Income from investments in direct financing leases and leveraged lease transactions, in which PCI 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. For direct financing leases, unearned income is amortized to income over the lease term at a constant rate of return on the net investment. 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. 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. Each quarter, PHI reviews the carrying value of each lease, which includes a review of the underlying lease financial assumptions, the timing and collectibility of cash flows, and the credit quality (including, if available, credit ratings) of the lessee. Changes to the underlying assumptions, if any, would be accounted for in accordance with SFAS No. 13 and reflected in the carrying value of the lease effective for the quarter within which they occur.
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 (6), Pensions and Other Postretirement Benefits, for additional information.
Severance Costs
In 2004, the Power Delivery business reduced its work force through a combination of retirements and targeted reductions. This reduction plan met the criteria for the accounting treatment provided under SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” and SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” as applicable. A roll forward of PHI’s severance accrual balance is as follows (millions of dollars):
Based on the employees that accepted the severance packages, substantially all of the severance liability was paid by December 31, 2007. Employees had the option of taking severance payments in a lump sum or over a period of time.
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 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 depreciation rates for the years ended December 31, 2007, 2006, and 2005.
(a)
Rate reflects the Consolidated Balance Sheet classification of ACE’s generation assets as “assets held for sale” in 2006 and therefore no depreciation expense was recorded.
In accordance with FASB Staff Position (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.
Asset Retirement Obligations
In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” and FIN 47, asset removal costs are recorded as regulatory liabilities. At December 31, 2007, $331.8 million of accrued asset removal costs ($234.2 million for DPL and $97.6 million for Pepco) and at December 31, 2006, $322.2 million of accrued asset removal costs ($229.5 million for DPL and $92.7 million for Pepco) are reflected as regulatory liabilities in the accompanying Consolidated Balance Sheets. Public service commission-approved depreciation rates for ACE do not contain components for the recovery of removal cost; therefore, the recording of asset retirement obligations for ACE associated with accruals for removal cost is not required. Additionally, in 2005 Pepco Holdings recorded conditional asset retirement obligations of approximately $1.5 million. Accretion for 2007 and 2006, which relates to the regulated Power Delivery segment, has been recorded as a regulatory asset.
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. In applying the modified prospective transition method, Pepco Holdings has not restated prior interim and annual financial results and therefore these prior periods do not reflect the revised recognition of share-based compensation cost as required by SFAS No. 123R.
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.
Prior to the adoption of SFAS No. 123R, Pepco Holdings accounted for its share-based employee compensation under the intrinsic value method of expense recognition and measurement prescribed by Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees, and related Interpretations” (APB No. 25). Under this method, compensation expense was recognized for restricted stock awards but not for stock options granted since the exercise price was equal to the grant-date market price of the stock.
The issuance of SFAS No. 123, “Accounting for Stock-Based Compensation,” in 1995 as amended by SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure,” permitted continued application of APB No. 25, but required tabular presentation of pro-forma stock-based employee compensation cost, net income, and basic and diluted earnings per share as if the fair-value based method of expense recognition and measurement prescribed by SFAS No. 123 had been applied to all options. This information for the year ended December 31, 2005 is as follows:
Pepco Holdings estimates the fair value of each stock option award on the date of grant using the Black-Scholes-Merton option pricing model. This model uses assumptions related to expected option term, expected volatility, expected dividend yield and risk-free interest rate. Pepco Holdings uses historical data to estimate option exercise and employee termination within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding.
No stock options were granted in 2005, 2006 or 2007.
No modifications were made to outstanding stock options prior to the adoption of SFAS No. 123R, and no changes in valuation methodology or assumptions in estimating the fair value of stock options 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.
As of January 1, 2007, there are no outstanding options that were not fully vested. Consequently, no compensation cost related to the vesting of options was recorded in 2007.
Cash received from stock options exercised under all share-based payment arrangements for the years ended December 31, 2007, 2006 and 2005, was $13.4 million, $15.9 million, and $3.7 million, respectively. The actual tax benefit realized from these option exercises totaled $1.2 million, $.9 million, and $.3 million, respectively, for the years ended December 31, 2007, 2006 and 2005.
Pepco Holdings’ current policy is to issue new shares to satisfy stock option exercises and the vesting of restricted stock awards.
Accumulated Other Comprehensive (Loss) Earnings
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)
Represents an adjustment for nonqualified pension plan minimum liability and the impact of initially applying SFAS No. 158.
(b)
Represents amortization of gains and losses for prior service costs.
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.
Financial Investment Liquidation
In October 2005, PCI received $13.3 million in cash related to the liquidation of a preferred stock investment that was written-off in 2001 and recorded an after-tax gain of $8.9 million.
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). 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 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. 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. For additional information, see the preceding discussion under “Regulation of Power Delivery Operations.”
Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.
PHI 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 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.
FIN 46R, “Consolidation of Variable Interest Entities”
Subsidiaries of Pepco Holdings have power purchase agreements (PPAs) with a number of entities, including three NUGs and ACE and the Panda PPA. Due to a variable element in the pricing structure of the NUGs and the Panda PPA, Pepco and ACE, respectively, potentially assume the variability in the operations of the plants related to these PPAs and therefore have a variable interest in the counterparties to these PPAs. In accordance with the provisions of FIN 46R, Pepco Holdings continued, during 2007, to conduct exhaustive efforts to obtain information from these four entities, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R to determine whether these four 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 counterparties to the NUGs and the Panda PPA for the years ended December 31, 2007, 2006, and 2005, were approximately $412 million, $403 million, and $419 million, respectively, of which approximately $378 million, $367 million, and $381 million, respectively, related to power purchases under the NUGs and the Panda PPA. Pepco Holdings does not have loss exposure under the NUGs because cost recovery will be achieved from ACE’s customers through regulated rates. In addition, there is no loss exposure on the Panda PPA as recovery will be achieved through the PJM Interconnection LLC (PJM) and funds received from the Mirant bankruptcy settlement.
Sale of Interest in Cogeneration Joint Venture
During the first quarter of 2006, Conectiv Energy recognized a $12.3 million pre-tax gain ($7.9 million after-tax) on the sale of its equity interest in a joint venture which owns a wood burning cogeneration facility.
Other Non-Current Assets
The other assets balance principally consists of real estate under development, equity and other investments, unrealized derivative assets, and deferred compensation trust assets.
Other Current Liabilities
The other current liability balance principally consists of customer deposits, accrued vacation liability, current unrealized derivative liabilities, and other miscellaneous liabilities. For 2006, this balance included $70 million paid to Pepco by Mirant in settlement of claims resulting from the Mirant bankruptcy.
Other Deferred Credits
The other deferred credits balance principally consists of non-current unrealized derivative liabilities and miscellaneous deferred liabilities.
Preferred Stock
As of December 31, 2007 and 2006, 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, 2007 and 2006.
Reclassifications
Certain prior year amounts have been reclassified in order to conform to current year presentation.
Newly Adopted Accounting Standards
FSP FTB 85-4-1, “Accounting for Life Settlement Contracts by Third-Party Investors”
In March 2006, the FASB issued FSP FASB Technical Bulletin (FTB) 85-4-1, “Accounting for Life Settlement Contracts by Third-Party Investors” (FSP FTB 85-4-1). This FSP provides initial and subsequent measurement guidance and financial statement presentation and disclosure guidance for investments by third-party investors in life settlement contracts. FSP FTB 85-4-1 also amends certain provisions of FTB No. 85-4, “Accounting for Purchases of Life Insurance,” and SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The guidance in FSP FTB 85-4-1 applies prospectively for all new life settlement contracts and is effective for fiscal years beginning after June 15, 2006 (year ended December 31, 2007 for Pepco Holdings). Implementation of FSP FTB 85-4-1 did not have a material impact on Pepco Holdings’ overall financial condition, results of operations, or cash flows.
SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140”
In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140” (SFAS No. 155). SFAS No. 155 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities,” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 155 resolves issues addressed in SFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006 (year ended December 31, 2007 for Pepco Holdings). Implementation of SFAS No. 155 did not have a material impact on Pepco Holdings’ overall financial condition, results of operations, or cash flows.
SFAS No. 156, “Accounting for Servicing of Financial Assets, an amendment of FASB Statement No. 140”
In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets” (SFAS No. 156), an amendment of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” with respect to the accounting for separately recognized servicing assets and servicing liabilities. SFAS No. 156 requires an entity to recognize a servicing asset or servicing liability upon undertaking an obligation to service a financial asset via certain servicing contracts, and for all separately recognized servicing assets and servicing liabilities to be initially measured at fair value, if practicable. Subsequent measurement is permitted using either the amortization method or the fair value measurement method for each class of separately recognized servicing assets and servicing liabilities.
SFAS No. 156 is effective as of the beginning of an entity’s first fiscal year that begins after September 15, 2006 (year ended December 31, 2007 for Pepco Holdings). Application is to be applied prospectively to all transactions following adoption of SFAS No. 156. Implementation of SFAS No. 156 did not have a material impact on Pepco Holdings’ overall financial condition, results of operations, or cash flows.
EITF Issue No. 06-3, “Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions”
On June 28, 2006, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 06-3, “Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions” (EITF 06-3). EITF 06-3 provides guidance on an entity’s disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity’s activities over a period of time are not within the scope of EITF 06-3. Pepco Holdings implemented EITF 06-3 during the first quarter of 2007. Taxes included in Pepco Holdings gross revenues were $318.3 million, $259.9 million and $266.1 million for the years ended December 31, 2007, 2006 and 2005, respectively.
FSP FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction”
On July 13, 2006, the FASB issued FSP Financial Accounting Standards (FAS) 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction” (FSP FAS 13-2). FSP FAS 13-2, which amends SFAS No. 13, “Accounting for Leases,” addresses how a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction affects the accounting by a lessor for that lease.
FSP FAS 13-2 is effective for the first fiscal year beginning after December 15, 2006 (year ended December 31, 2007 for Pepco Holdings). A material change in the timing of cash flows under Pepco Holdings’ cross-border leases as the result of a settlement with the Internal Revenue Service or a change in tax law would require an adjustment to the book value of the leases and a charge to earnings equal to the repricing impact of the disallowed deductions which could result in a material adverse effect on Pepco Holdings’ overall financial condition, results of operations, and cash flows. For a further discussion, see “Federal Tax Treatment of Cross-Border Leases” in Note (12), “Commitments and Contingencies.”
FSP AUG AIR-1, “Accounting for Planned Major Maintenance Activities”
On September 8, 2006, the FASB issued FSP AUG AIR-1, which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods for all industries. FSP AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006 (year ended December 31, 2007 for Pepco Holdings). Implementation of FSP AUG AIR-1 did not have a material impact on Pepco Holdings’ overall financial condition, results of operations, or cash flows.
EITF Issue No. 06-5, “Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance”
On September 20, 2006, the FASB ratified EITF Issue No. 06-5, “Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance” (EITF 06-5) which provides guidance on whether an entity should consider the contractual ability to surrender all of the individual-life policies (or certificates under a group life policy) together when determining the amount that could be realized in accordance with FTB 85-4, and whether a guarantee of the additional value associated with the group life policy affects that determination. EITF 06-5 provides that a policyholder should (i) determine the amount that could be realized under the insurance contract assuming the surrender of an individual-life by individual-life policy (or certificate by certificate in a group policy) and (ii) not discount the cash surrender value component of the amount that could be realized when contractual restrictions on the ability to surrender a policy exist unless contractual limitations prescribe that the cash surrender value component of the amount that could be realized is a fixed amount, in which case the amount that could be realized should be discounted in accordance with Accounting Principles Board of the American Institute of Certified Public Accountants Opinion 21. EITF 06-5 is effective for fiscal years beginning after December 15, 2006 (year ended December 31, 2007 for Pepco Holdings).
Implementation of EITF 06-5 did not have a material impact on Pepco Holdings’ overall financial condition, results of operations, cash flows, or footnote disclosure requirements.
FASB Staff Position No. EITF 00-19-2, “Accounting for Registration Payment Arrangements”
On December 21, 2006, the FASB issued FSP No. EITF 00-19-2, “Accounting for Registration Payment Arrangements” (FSP EITF 00-19-2), which addresses an issuer’s accounting for registration payment arrangements and specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with SFAS No. 5, “Accounting for Contingencies.” FSP EITF 00-19-2 is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of its issuance. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of FSP EITF 00-19-2, this guidance is effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years (year ended December 31, 2007 for Pepco Holdings). Pepco Holdings implemented FSP EITF 00-19-2 during the first quarter of 2007. The implementation did not have a material impact on its overall financial condition, results of operations, or cash flows.
Recently Issued Accounting Standards, Not Yet Adopted
SFAS No. 157, "Fair Value Measurements"
In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of this Statement will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the disclosures about fair value measurements.
The provisions of SFAS No. 157, as issued, are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (January 1, 2008 for Pepco Holdings). On February 6, 2008, the FASB decided to issue final Staff Positions that will (i) defer 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) and (ii) remove certain leasing transactions from the scope of SFAS No. 157. The final Staff Positions will defer the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of the final Staff Positions. Pepco Holdings has evaluated the impact of SFAS No. 157 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, cash flows, or footnote disclosure requirements.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115”
On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115” (SFAS No. 159) which permits entities to elect to measure eligible financial instruments at fair value. The objective of SFAS No. 159 is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of SFAS No. 159 will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the disclosures about fair value measurements.
SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.
SFAS No. 159 applies to the beginning of a reporting entity’s first fiscal year that begins after November 15, 2007 (January 1, 2008 for Pepco Holdings), with early adoption permitted for an entity that has also elected to apply the provisions of SFAS No. 157, Fair Value Measurements. An entity is prohibited from retrospectively applying SFAS No. 159, unless it chooses early adoption. SFAS No. 159 also applies to eligible items existing at November 15, 2007 (or early adoption date). Pepco Holdings has evaluated the impact of SFAS No. 159 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, cash flows, or footnote disclosure requirements.
FSP FIN 39-1, “Amendment of FASB Interpretation No. 39”
On April 30, 2007, the FASB issued FSP FIN 39-1, “Amendment of FASB Interpretation No. 39” to amend certain portions of Interpretation 39. The FSP replaces the terms “conditional contracts” and “exchange contracts” in Interpretation 39 with the term “derivative instruments” as defined in Statement 133. The FSP also amends Interpretation 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivable, or the obligation to return cash collateral or payable, arising from the same master netting arrangement as the derivative instruments. FSP FIN 39-1 applies to fiscal years beginning after November 15, 2007 (year ending December 31, 2008 for Pepco Holdings), with early adoption permitted. Pepco Holdings has evaluated the impact of FSP FIN 39-1 and has determined that it does not have a material impact on its overall financial condition, results of operations, cash flows, or footnote disclosure requirements.
EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards”
On June 27, 2007, the FASB ratified EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11) which 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 nonvested equity shares, nonvested 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 (i.e. the “APIC pool”).
EITF Issue No. 06-11 also provides that, when the estimated amount of forfeitures increases or actual forfeitures exceeds estimates, the amount of tax benefits previously recognized in APIC should be reclassified into the income statement; however, the amount reclassified is limited to the APIC pool balance on the reclassification date.
EITF Issue No. 06-11 applies prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning after December 15, 2007, and interim periods within those fiscal years (year ending December 31, 2008 for Pepco Holdings). Early application is permitted as of the beginning of a fiscal year for which interim or annual financial statements have not yet been issued. Retrospective application to previously issued financial statements is prohibited. Entities must disclose the nature of any change in their accounting policy for income tax benefits of dividends on share-based payment awards resulting from the adoption of this guidance. Pepco Holdings has evaluated the impact of EITF Issue No. 06-11 and has determined that it does not have a material impact on its overall financial condition, results of operations, cash flows, or footnote disclosure requirements.
SFAS No. 141(R), “Business Combinations - a replacement of FASB Statement No. 141”
On December 4, 2007, the FASB issued SFAS No. 141(R), “Business Combinations - a replacement of FASB Statement No. 141” (SFAS No. 141(R)) which replaces FASB Statement No. 141, “Business Combinations.” This Statement retains the fundamental requirements in Statement 141 that the acquisition method of accounting (which Statement 141 called the purchase method) be used for all business combinations and for an acquirer to be identified for each business combination.
SFAS No. 141(R) applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree). It does not apply to (i) the formation of a joint venture, (ii) the acquisition of an asset or a group of assets that does not constitute a business, (iii) a combination between entities or businesses under common control and (iv) a combination between not-for-profit organizations or the acquisition of a for-profit business by a not-for-profit organization.
SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for Pepco Holdings). An entity may not apply it before that date.
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51”
On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (SFAS No. 160) which amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.
A noncontrolling interest, sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. The objective of SFAS No. 160 is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards that require (i) the ownership interests 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, (ii) the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income, (iii) changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently. A parent’s ownership interest in a subsidiary changes if the parent purchases additional ownership interests in its subsidiary or if the parent sells some of its ownership interests in its subsidiary. It also changes if the subsidiary reacquires some of its ownership interests or the subsidiary issues additional ownership interests. All of those transactions are economically similar, and this Statement requires that they be accounted for similarly, as equity transactions, (iv) when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary be initially measured at fair value. The gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any noncontrolling equity investment rather than the carrying amount of that retained investment and (v) entities provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.
SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary.
SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009, for Pepco Holdings). Earlier adoption is prohibited. SFAS No. 160 shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. Pepco Holdings is currently evaluating the impact SFAS No. 160 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.
(3) 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, 2007 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Prior to 2007, intrasegment revenues and expenses were not eliminated at the segment level for purposes of presenting segment financial results but rather were eliminated for PHI’s consolidated results through the “Corp. & Other” column. Beginning in 2007, intrasegment revenues and expenses are eliminated at the segment level. Segment results for the years ended December 31, 2006 and 2005 have been reclassified to conform to the current presentation. Segment financial information for the years ended December 31, 2007, 2006, and 2005, 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. Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance. Included in Corp. & Other are intercompany amounts of $(469.0) million for Operating Revenue, $(464.2) million for Operating Expense, $(92.8) million for Interest Income, $(90.4) million for Interest Expense, and $(2.5) 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 $431.4 million for the year ended December 31, 2007.
(c)
Includes depreciation and amortization of $365.9 million, consisting of $306.0 million for Power Delivery, $37.7 million for Conectiv Energy, $12.1 million for Pepco Energy Services, $1.8 million for Other Non-Regulated and $8.3 million for Corp. & Other.
(d)
Includes $33.4 million ($20.0 million, after-tax) from settlement of Mirant bankruptcy claims.
(e)
Includes $19.5 million benefit ($17.7 million net of fees) related to Maryland income tax settlement.
(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. Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance. Included in Corp. & Other are intercompany amounts of $(481.3) million for Operating Revenue, $(475.1) million for Operating Expense, $(90.0) million for Interest Income, $(87.6) million for Interest Expense, and $(2.5) million for Preferred Stock Dividends.
(b)
Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $460.5 million for the year ended December 31, 2006.
(c)
Includes depreciation and amortization of $413.2 million, consisting of $354.3 million for Power Delivery, $36.3 million for Conectiv Energy, $11.8 million for Pepco Energy Services, $1.8 million for Other Non-Regulated and $9.0 million for Corp. & Other.
(d)
Includes $12.3 million gain ($7.9 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 $18.9 million of impairment losses ($13.7 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 $6.3 million increase in net income ($2.5 million for Power Delivery and $5.4 million for Other Non-Regulated, partially offset by an unfavorable $1.6 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 $9.1 million ($3.1 million related to Power Delivery and $6.0 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 $2.6 million was recorded that resulted from changes in estimates related to prior year tax liabilities subject to audit ($4.1 million for Power Delivery, partially offset by an unfavorable $1.5 million for Corp. & Other).
(g)
Due to the reclassification referred to in the introductory paragraph, the Conectiv Energy segment does not include $193.1 million of intrasegment operating revenue and operating expense and $27.7 million of intrasegment interest income and interest expense. Accordingly, the Corp. & Other column does not include an elimination for these amounts.
(h)
Due to the reclassification referred to in the introductory paragraph, the Other Non-Regulated segment does not include $163.1 million of intrasegment interest income and interest expense. Accordingly, the Corp. & Other column does not include an elimination for these amounts.
(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. Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance. Included in Corp. & Other are intercompany amounts of $(605.2) million for Operating Revenue, $(599.7) million for Operating Expense, $(81.3) million for Interest Income, $(79.1) million for Interest Expense, and $(2.5) million for Preferred Stock Dividends.
(b)
Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $565.3 million for the year ended December 31, 2005.
(c)
Includes $10.9 million in income tax expense related to Internal Revenue Service (IRS) Revenue Ruling 2005-53. Also refer to Note (12) Commitments and Contingencies for a discussion of the IRS mixed service cost issue.
(d)
Relates to ACE’s electric distribution rate case settlement that was accounted for in the first quarter of 2005. This resulted in ACE’s reversal of $9.0 million in after-tax accruals related to certain deferred costs that are now deemed recoverable. This amount is classified as extraordinary since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.
(e)
Includes $70.5 million ($42.2 million after-tax) gain (net of customer sharing) from the settlement of the Pepco TPA Claim and the Pepco asbestos claims against the Mirant bankruptcy estate. Also includes $68.1 million gain ($40.7 million after-tax) from the sale of non-utility land owned by Pepco at Buzzard Point.
(f)
Includes $13.3 million gain ($8.9 million after-tax) related to PCI’s liquidation of a financial investment that was written off in 2001.
(g)
Includes depreciation and amortization of $427.3 million, consisting of $361.4 million for Power Delivery, $40.4 million for Conectiv Energy, $14.5 million for Pepco Energy Services, $1.7 million for Other Non-Regulated and $9.3 million for Corp. & Other.
(h)
Due to the reclassification referred to in the introductory paragraph, the Conectiv Energy segment does not include $210.5 million of intrasegment operating revenue and operating expense and $28.9 million of intrasegment interest income and interest expense. Accordingly, the Corp. & Other column does not include an elimination for these amounts.
(i)
Due to the reclassification referred to in the introductory paragraph, the Other Non-Regulated segment does not include $107.4 million of intrasegment interest income and interest expense. Accordingly, the Corp. & Other column does not include an elimination for these amounts.
(4) LEASING ACTIVITIES
Finance Leases
As of December 31, 2007 and 2006, Pepco Holdings had equity investments in energy leveraged leases of $1,384.4 million and $1,321.8 million, respectively, consisting of electric power plants and natural gas transmission and distribution networks located outside of the
United States. As of December 31, 2007, $708.4 million of equity is attributable to facilities located in Austria, $490.5 million in The Netherlands and $185.5 million in Australia.
The components of the net investment in finance leases at December 31, 2007 and 2006 are summarized below (millions of dollars):
Income recognized from leveraged leases (included in “Other Operating Revenue”) was comprised of the following for the years ended December 31:
Scheduled lease payments from leveraged leases are net of non-recourse debt. Minimum lease payments receivable from PCI’s finance leases for each of the years 2008 through 2012 and thereafter are zero for 2008 and 2009, $16.0 million for 2010, zero for 2011 and 2012, and $1,368.4 million thereafter. For a discussion of the federal tax treatment of cross-border leases, see Note (12) “Commitments and Contingencies.”
Lease Commitments
Pepco leases its consolidated control center, 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 $7.6 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, 2007 and 2006, in millions of dollars, are comprised of the following:
The approximate annual commitments under all capital leases are $15.4 million for 2008, $15.2 million for 2009, 2010, 2011 and 2012, and $106.7 million thereafter.
Rental expense for operating leases was $50.6 million, $50.8 million, and $53.3 million for the years ended December 31, 2007, 2006, and 2005, respectively.
Total future minimum operating lease payments for Pepco Holdings as of December 31, 2007 include $38.1 million in 2008, $33.7 million in 2009, $28.7 million in 2010, $25.6 million in 2011, $24.0 million in 2012 and $361.9 million after 2012.
(5) 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
As discussed in Note (2), Summary of Significant Accounting Policies, in the third quarter of 2006, ACE completed the sale of its interest in the Keystone and Conemaugh generating facilities for approximately $175.4 million (after giving effect to post-closing adjustments) and in the first quarter of 2007, ACE completed the sale of the B.L. England generating facility for a price of $9.0 million.
In the third quarter of 2005, Pepco sold for $75 million in cash 384,051 square feet of excess non-utility land located at Buzzard Point in the District of Columbia. The sale resulted in a pre-tax gain of $68.1 million, which was recorded as a reduction of Operating Expenses in the Consolidated Statements of Earnings.
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 have ownership interests. PHI’s 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, 2007 is shown below.
(6) 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. Certain 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
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 Legislation.” SFAS No.158 does not change how pension and other postretirement benefits 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) “Summary of Significant Accounting Policies -- Pension and Other Postretirement Benefit Plans” for additional information.
All amounts in the following tables are in millions of dollars.
The following table provides the amounts recognized in PHI’s Consolidated Balance Sheets as of December 31, 2007 in compliance with SFAS No. 158:
Amounts included in accumulated other comprehensive income (pre-tax) and regulatory assets at December 31, 2007 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 2007 combined pension and other postretirement net periodic benefit cost of $63.8 million includes $22.3 million for Pepco, $4.3 million for DPL and $11.0 million for ACE. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.
The 2006 combined pension and other postretirement net periodic benefit cost of $67.5 million includes $32.1 million for Pepco, $.7 million for DPL and $14.3 million for ACE. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.
The 2005 combined pension and other postretirement net periodic benefit cost of $59.7 million includes $28.9 million for Pepco, $(2.0) million for DPL and $16.9 million for ACE. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.
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
$ 2.1
$ (2.1)
Increase (decrease) on postretirement benefit obligation
$31.8
$(31.6)
The following weighted average assumptions were used to determine the net periodic benefit cost for the years ended December 31:
A cash flow matched bond portfolio approach to developing a discount rate is used to value SFAS No. 87 and SFAS No. 106 liabilities. The hypothetical portfolio includes high quality instruments with maturities that mirror the benefit obligations.
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 and fixed income investments, and when viewed over a long-term horizon, are expected to yield a return on assets of 8.250%.
Plan Assets
The PHI Retirement Plan weighted average asset allocations at December 31, 2007, and 2006, by asset category are as follows:
Pepco Holdings’ Other Postretirement plan weighted average asset allocations at December 31, 2007, and 2006, 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 and provide 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 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.
No Pepco Holdings common stock is included in pension or postretirement program assets.
Cash Flows
Contributions - PHI Retirement Plan
Pepco Holdings’ funding policy with regard to the PHI Retirement Plan is to maintain a funding level in excess of 100% with respect to its accumulated benefit obligation (ABO). The PHI Retirement Plan currently meets the minimum funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA) without any additional funding. In 2007 and 2006, PHI made no contributions to the plan. At December 31, 2007, PHI’s Plan assets were $1,631.4 and the ABO was $1,538.0 million. At December 31, 2006, PHI’s Plan assets were $1,633.7 million and the ABO was $1,575.2 million. Assuming no changes to the current pension plan assumptions, PHI projects no funding will be required under ERISA in 2008; however, PHI may elect to make a discretionary tax-deductible contribution, to maintain its plan assets in excess of its ABO.
Contributions - Other Postretirement Benefits
In 2007 and 2006, Pepco contributed $10.3 million and $6.0 million, respectively, DPL contributed $8.0 million and $6.8 million, respectively, and ACE contributed $6.8 million and $6.6 million, respectively, to the plans. In 2007 and 2006, contributions of $13.2 million and $13.5 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 2008.
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, 2007 are as follows (millions of dollars):
Medicare Prescription Drug Improvement and Modernization Act of 2003
On December 8, 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Medicare Act) became effective. The Medicare Act introduced a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefits plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Pepco Holdings sponsors post-retirement health care plans that provide prescription drug benefits that PHI plan actuaries have determined are actuarially equivalent to Medicare Part D. At December 31, 2007, the estimated reduction in accumulated postretirement
benefit obligation is $30.4 million. In 2007 and 2006, Pepco Holdings received $1.9 million and $1.6 million, respectively, in Federal Medicare prescription drug subsidies.
Pepco Holdings Retirement Savings Plan
Pepco Holdings has a defined contribution employee benefit plan (the 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 $11.0 million, $11.0 million, and $10.4 million for the years ended December 31, 2007, 2006, and 2005, respectively.
(7) 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 or tax-exempt bonds issued by the same company. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or tax-exempt bonds are identical to the terms of the collateral First Mortgage Bonds by which it is secured. Payments of principal and interest on a series of senior notes or 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 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 August 1, 2008.
(d)
The bonds are subject to mandatory tender on July 1, 2010.
(e)
The bonds are subject to mandatory tender on May 1, 2011.
NOTE: Schedule is continued on next page.
(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.
The outstanding First Mortgage Bonds issued by each of Pepco, DPL and ACE are secured by 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, 2007, are $323.8 million in 2008, $82.2 million in 2009, $531.9 million in 2010, $69.9 million in 2011, $787.3 million in 2012, and $3,143.3 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, 2007 and 2006, Pepco Energy Services had outstanding total long-term project funding (including current maturities) of $29.3 million and $25.7 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, 2007, are $8.4 million in 2008, $2.1 million in 2009, $2.0 million in 2010, $1.7 million in 2011, $1.6 million in 2012, and $13.5 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, 2007 and 2006 is as follows.
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, $275 million, and $250 million, respectively. The commercial paper programs of PHI, Pepco, DPL and ACE are backed by a $1.5 billion credit facility, which is described under the heading “Credit Facility” below.
Pepco Holdings, Pepco, DPL and ACE had zero, $84.0 million, $24.0 million and $29.1 million of commercial paper outstanding at December 31, 2007, respectively. The weighted average interest rate for Pepco Holdings, Pepco, DPL and ACE commercial paper issued during 2007 was 5.58%, 5.27%, 5.35% and 5.45% respectively. The weighted average maturity for Pepco Holdings, Pepco, DPL and ACE was two, four, four, and three days respectively for all commercial paper issued during 2007.
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, 2007 mature in 2008 to 2009 ($5.8 million), 2014 to 2017 ($48.6 million), 2024 ($33.3 million) and 2028 to 2031 ($64 million). The weighted average interest rate for VRDB was 3.79% during 2007 and 3.55% during 2006.
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 the 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 based on the prevailing prime rate or 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 made by the borrower at the time the credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower’s business, property, and results of operations or financial condition subsequent to the entry into the credit agreement is not a condition to the availability of credit under the facility. Among the covenants to which each of the companies is subject are (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 certain trust preferred securities and deferrable interest subordinated debt from the definition of total indebtedness (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the credit agreement. The agreement does not include any rating triggers.
(8) 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 Expense
FIN 48, “Accounting for Uncertainty in Income Taxes”
As disclosed in Note 2, “Summary of 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 $7.4 million as a decrease in retained earnings. Also upon adoption, PHI had $186.9 million of unrecognized tax benefits and $24.3 million of related accrued interest.
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
As of December 31, 2007, PHI had $26.4 million of accrued interest related to 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, 2007, included $11.2 million that, if recognized, would lower the effective tax rate.
Interest and Penalties
PHI recognizes interest and penalties relating to its unrecognized tax benefits as an element of tax expense. For the year ended December 31, 2007, PHI recognized $2.1 million of interest expense and penalties, net, as a component of tax expense.
Possible Changes to Unrecognized Benefits
Total unrecognized tax benefits that may change over the next twelve months include the matter of Mixed Service Costs. See discussion in Note 12, “Commitments and Contingencies -- IRS Mixed Service Cost Issue.”
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.
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 $6.3 million increase in net income ($2.5 million for Power Delivery and $5.4 million for Other Non-Regulated, partially offset by an unfavorable $1.6 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 $9.1 million ($3.1 million
related to Power Delivery and $6.0 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 $2.6 million was recorded that resulted from changes in estimates related to prior year tax liabilities subject to audit ($4.1 million for Power Delivery, partially offset by an unfavorable $1.5 million for Corp. & Other).
Non Financial Lease Asset
The IRS, as part of its normal audit of PCI’s income tax returns, questioned whether PCI is entitled to certain ongoing tax deductions being taken by PCI as a result of the adoption by PCI of a carry-over tax basis for a non-lease financial asset acquired in 1998 by a subsidiary of PCI. On December 14, 2004, PCI and the IRS agreed to a Notice of Proposed Adjustment settling this and certain other tax matters. This settlement resulted in a cash payment in February 2006 for additional taxes and interest of approximately $22.8 million associated with the examination of PCI’s 2001-2002 tax returns and an anticipated refund of taxes and interest of approximately $7.1 million when the examination of PCI’s 2003 return is completed. In addition, in the fourth quarter of 2004, PCI took a tax charge to earnings of approximately $19.7 million for financial reporting purposes related to this matter. The charge consisted of approximately $16.3 million to reflect the reversal of tax benefits recognized by PCI prior to September 30, 2004, and approximately $3.4 million of interest on the additional taxes. During 2006 and 2005, PCI recorded tax charges to earnings of approximately $.1 million and $.9 million, respectively, for interest on the additional taxes.
Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below. The total amounts below include $348.2 million, $332.9 million, and $333.4 million, for the years ended December 31, 2007, 2006, and 2005, respectively, related to the Power Delivery Business, which are recoverable through rates.
(9) MINORITY INTEREST
The outstanding preferred stock issued by subsidiaries of PHI as of December 31, 2007 and 2006 consisted of the following. The shares of each of these series are redeemable solely at the option of the issuer.
(a)
On January 18, 2007, DPL redeemed all of the outstanding shares of its preferred stock, with an aggregate par value of $18.9 million, at prices ranging from 103% to 105% of par.
(10)
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 Board as a participant in the LTIP. Under the LTIP, awards to officers and key employees may be in the form of restricted stock, options, performance units, stock appreciation rights, and dividend equivalents. Up to 10,100,000 shares of common stock initially were available 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, 2007, 2006, and 2005 is $4.3 million, $5.8 million, and $4.4 million, respectively. For the years ended December 31, 2007, 2006, and 2005, $1.9 million, $.1 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, 2007, 2006 and 2005.
PHI recognizes compensation expense related to Performance Restricted Stock Awards based on the fair value of the awards at date of grant. PHI estimates the fair value of market condition awards using a Monte Carlo simulation model, in a risk-neutral framework, based on the following assumptions:
Prior to acquisition of Conectiv by Pepco, each company had a long-term incentive plan under which stock options were granted. At the time of the acquisition, certain Conectiv options vested and were canceled in exchange for a cash payment. Certain other Conectiv options were exchanged on a 1 for 1.28205 basis for Pepco Holdings stock options under the LTIP: 590,198 Conectiv stock options were converted into 756,660 Pepco Holdings stock options. The Conectiv stock options were originally granted on January 1, 1998, January 1, 1999, July 1, 1999, October 18, 2000, and January 1, 2002, in each case with an exercise price equal to the market price (fair value) of the Conectiv stock on the date of the grant. The exercise prices of these options, after adjustment to give effect to the conversion ratio of Conectiv stock for Pepco Holdings stock, are $17.81, $18.91, $19.30, $13.08 and $19.03, respectively. All of the Pepco Holdings options received in exchange for the Conectiv options are exercisable.
At the time of the acquisition of Conectiv by Pepco, outstanding Pepco options were exchanged on a one-for-one basis for Pepco Holdings stock options granted under the LTIP. The options were originally granted under Pepco’s long-term incentive plan in May 1998, May 1999, January 2000, May 2000, January 2001, May 2001, January 2002, and May 2002. The exercise prices of the options are $24.3125, $29.78125, $22.4375, $23.15625, $24.59, $21.825, $22.57 and $22.685, respectively, which represent the market prices (fair values) of the Pepco common stock on its original grant dates. All the options granted are exercisable.
Stock option activity for the three years ended December 31 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.
The aggregate intrinsic value of stock options outstanding and exercisable at December 31, 2007, 2006, and 2005 was $3.8 million, $4.1 million, and $.1 million, respectively.
The total intrinsic value of stock options exercised during the years ended December 31, 2007, 2006, and 2005 was $3.0 million, $2.2 million, and $.8 million, respectively. For the years ended December 31, 2007, 2006, and 2005, $1.2 million, $.9 million, and $.3 million, respectively, in tax benefits were recognized in relation to stock-based compensation costs of stock options.
As of December 31, 2007, an analysis of options outstanding by exercise prices is as follows:
Prior to the adoption of SFAS No. 123R on January 1, 2006, Pepco Holdings recognized compensation costs for the LTIP based on the accounting prescribed by APB No. 25, “Accounting for Stock Issued to Employees.” There were no stock-based employee compensation costs charged to expense in 2007, 2006 and 2005 with respect to stock options granted under the LTIP.
There were no options granted in 2007, 2006, or 2005.
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 2007, 2006 and 2005 under Pepco Holdings’ Performance Restricted Stock Program for performance periods 2007-2009, 2006-2008, and 2005-2007 were 190,657, 218,108, and 247,400, 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 95,314 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 $25.54 for the 2007-2009 award, $23.28 for the 2006-2008 award, and $26.92 for the 2005-2007 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 418,426 awards earned with respect to the 2004-2006 share award opportunity.
The maximum number of share award opportunities granted under the Merger Integration Success Program during 2002 was 241,075. The fair value per share on grant date was $19.735. Of those shares, 96,427 were restricted and vested over three years: 20% vested in 2003, 30% vested in 2004, and 50% vested in 2005. The remaining 144,648 shares were performance-based award opportunities that could have been earned based on the extent to which operating
efficiencies and expense reduction goals were attained through December 31, 2003 and 2004, respectively. Although the goals were met in 2003, it was determined that 63,943 shares, including shares reallocated from participants who did not meet performance goals as well as shares reflecting accrued dividends for the period August 1, 2002 to December 31, 2003, granted to certain executives, would not vest until 2005, and then only if the cost reduction goals were maintained and Pepco Holdings’ financial performance were satisfactory. A total of 9,277 shares of common stock vested under this program on December 31, 2003 for other eligible employees. On March 11, 2005, 70,315 shares, including reinvested dividends, vested for the performance period ending on December 31, 2004. A total of 44,644 shares, including reinvested dividends, vested on March 7, 2006, for the original performance period ended December 31, 2003, that was extended to December 31, 2005.
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.
On August 1, 2002, the date of the acquisition of Conectiv by Pepco, in accordance with the terms of the merger agreement, 80,602 shares of Conectiv performance accelerated restricted stock (PARS) were converted to 103,336 shares of Pepco Holdings restricted stock. The PARS were originally granted on January 1, 2002 at a fair market price of $24.40. All of the converted restricted stock has time-based vesting over periods ranging from 5 to 7 years from the original grant date. As of December 31, 2007, 96,026 converted shares have vested and 7,310 shares remain unvested.
In June 2003, the President and Chief Executive Officer of PHI received a retention award in the form of 14,822 shares of restricted stock. The shares vested on June 1, 2006.
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 to three years.
The 2007 activity for non-vested share opportunities is summarized below. The information presented in the table is for Pepco Holdings, including Conectiv PARS converted to Pepco Holdings restricted stock.
The total fair value of restricted stock awards vested during the years ended December 31, 2007, 2006, and 2005 was $10.1 million, $2.0 million, and $2.7 million, respectively.
As of December 31, 2007, there was approximately $5.4 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 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 $1.8 billion at December 31, 2007 and $1.9 billion at December 31, 2006. PHI had no restricted retained earnings or restricted net income at December 31, 2007 and 2006.
For the years ended December 31, 2007, 2006, and 2005, 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 earn dividends as well as appreciation equal to the amount of increase in fair value of the phantom shares. The ultimate payout is in cash. The amount deferred and invested in phantom Pepco Holdings shares in the years ended December 31, 2007, 2006 and 2005 was $.2 million, $.1 million and $.1 million, respectively.
Compensation recognized in respect of dividends and increase in fair value in the years ended December 31, 2007, 2006 and 2005 was $.3 million, $.3 million and $.1 million, respectively. The balance of deferred compensation invested in phantom Pepco Holdings’ shares at December 31, 2007 and 2006 was $2.2 million and $1.8 million.
Calculations of Earnings per Share of Common Stock
Reconciliations of the numerator and denominator for basic and diluted earnings per share of common stock calculations are shown below.
(a)
Approximately zero, .6 million, and 1.4 million for the years ended December 31, 2007, 2006 and 2005, respectively, related to options to purchase common stock with exercise prices between $22.44 and $29.78 per share, have been excluded from the calculation of diluted EPS as they are considered to be anti-dilutive.
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 979,155, 1,232,569, and 1,228,505 original issue shares sold under the DRP in 2007, 2006 and 2005, respectively.
Pepco Holdings Common Stock Reserved and Unissued
The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2007:
(a)
No further awards will be made under this plan.
(b)
Effective January 30, 2006, Pepco Holdings established the Pepco Holdings, Inc. 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.
(11) FAIR VALUES OF FINANCIAL INSTRUMENTS
The estimated fair values of Pepco Holdings’ financial instruments at December 31, 2007 and 2006 are shown below.
The methods and assumptions described below were used to estimate, at December 31, 2007 and 2006, the fair value of each class of financial instruments shown above for which it is practicable to estimate a value.
The fair values of derivative instruments were derived based on quoted market prices where available or, for instruments that are not traded on an exchange, based on information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. For some custom and complex instruments, an internal model is used to interpolate available price information.
Long-Term Debt includes recourse and non-recourse debt issued by PCI. The fair values of this PCI debt, including amounts due within one year, were based on current rates offered to similar companies 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 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.
(12) 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. 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 asset sale, Pepco entered into transition power agreements with Mirant pursuant to which Mirant agreed to supply all of the energy and capacity needed by Pepco to fulfill its SOS obligations in Maryland and in the District of Columbia (the TPAs). Under a settlement to avoid the rejection by Mirant of its obligations under the TPAs in the bankruptcy proceeding, the terms of the TPAs were modified to increase the purchase price of the energy and capacity supplied by Mirant and Pepco received an allowed, pre-petition general unsecured claim in the bankruptcy in the amount of $105 million (the TPA Claim). In December 2005, Pepco sold the TPA Claim, plus the right to receive accrued interest thereon, to an unaffiliated third party for $112.5 million. In addition, Pepco received proceeds of $.5 million in settlement of an asbestos claim against the Mirant bankruptcy estate. After customer sharing, Pepco recorded a pre-tax gain of $70.5 million from the settlement of these claims.
In connection with the asset sale, Pepco and Mirant also entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco is obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco is obligated to pay to Panda. As part of the further settlement of Pepco’s claims against Mirant arising from the Mirant 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 is obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $413.9 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. These funds are being accounted for as restricted cash based on management’s intent to use such funds, and any interest earned thereon, for the sole purpose of paying for the future above-market capacity and energy purchase costs under the Panda PPA. Correspondingly, a regulatory liability has been established in the same amount to help offset the future above-market capacity and energy
purchase costs. This restricted cash has been classified as a non-current asset to be consistent with the classification of the non-current regulatory liability, and any changes in the balance of this restricted cash, including interest on the invested funds, are being accounted for as operating cash flows.
As of December 31, 2007, the balance of the restricted cash account was $417.3 million. Based on a reexamination of the costs of the Panda PPA in light of current and projected wholesale market conditions conducted in the fourth quarter of 2007, Pepco determined that, principally due to increases in wholesale capacity prices, the present value above-market cost of the Panda PPA over the term of the agreement is expected to be significantly less than the current amount of the restricted cash account balance. Accordingly, on February 22, 2008, Pepco filed applications with the DCPSC and the MPSC requesting orders directing Pepco to maintain $320 million in the restricted cash account and to use that cash, and any future earnings on the cash, for the sole purpose of paying the future above-market cost of the Panda PPA (or, in the alternative, to fund a transfer or assignment of the remaining obligations under the Panda PPA to a third party). Pepco also requested that the order provide that any cash remaining in the account at the conclusion of the Panda PPA be refunded to customers and that any shortfall be recovered from customers. Pepco further proposed that the excess proceeds remaining from the settlement (approximately $94.6 million, representing the amount by which the regulatory liability of $414.6 million at December 31, 2007 exceeded $320 million) be shared approximately equally with its customers in accordance with the procedures previously approved by each commission for the sharing of the proceeds received by Pepco from the sale to Mirant of its generating assets. The regulatory liability of $414.6 million at December 31, 2007 differs from the restricted cash amount of $417.3 million on that date, in part, because the regulatory liability has been reduced for the portion of the December 2007 Panda charges in excess of market that had not yet been paid from the restricted cash account. The amount of the restricted cash balance that Pepco is permitted to retain will be recorded as earnings upon approval of the sharing arrangement by the respective commissions. At this time, Pepco cannot predict the outcome of these proceedings.
In settlement of other damages claims against Mirant, Pepco in 2007 also received a settlement payment in the amount of $70.0 million. Of this amount (i) $33.4 million was recorded as a reduction in operating expenses, (ii) $21.0 million was recorded as a reduction in a net pre-petition receivable claim from Mirant, (iii) $15.0 million was recorded as a reduction in the capitalized costs of certain property, plant and equipment and (iv) $.6 million was recorded as a liability to reimburse a third party for certain legal costs associated with the settlement.
Rate Proceedings
In electric service distribution base rate cases filed by Pepco in the District of Columbia and Maryland, and by DPL in Maryland, and pending in 2007, Pepco and DPL proposed the adoption of a BSA for retail customers. 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 will increase rates if actual distribution revenues fall below the level approved by the applicable commission and will decrease rates if actual distribution revenues are above the approved level. The result will be that, over time, the utility would collect 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 the regulated utilities to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and delivery revenues. The status of the BSA proposals in each of the jurisdictions is described below in discussion of the respective base rate proceedings.
Delaware
On September 4, 2007, DPL submitted its 2007 Gas Cost Rate (GCR) filing to the DPSC. The GCR permits DPL to recover its gas procurement costs through customer rates. On September 18, 2007, the DPSC issued an initial order approving a 5.7% decrease in the level of the GCR, which became effective November 1, 2007, subject to refund and 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. The application to the DCPSC requested an annual increase of approximately $46.2 million or an overall increase of 13.5%, reflecting a proposed return on equity (ROE) of 10.75%. In the alternative, the application requested an annual increase of $50.5 million or an overall increase of 14.8%, reflecting an ROE of 11.00%, if the BSA were not approved. Subsequently, Pepco reduced its annual revenue increase request to $43.4 million (including a proposed BSA) and $47.9 million (if the BSA were not approved).
On January 30, 2008, the DCPSC approved a revenue requirement increase of approximately $28.3 million, based on an authorized return on rate base of 7.96%, including a 10% ROE. The rate increase is effective February 20, 2008. The DCPSC, while finding the BSA to be an appropriate ratemaking concept, cited potential statutory problems in the DCPSC’s ability to implement the BSA. The DCPSC stated that it intends to issue an order to establish a Phase II proceeding to consider these implementation issues.
Maryland
On July 19, 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 annual increase in distribution rates of approximately $14.9 million (including a decrease in annual depreciation expense of approximately $.9 million). The Pepco order approved an annual increase in distribution rates of approximately $10.6 million (including a decrease in annual depreciation expense of approximately $30.7 million). In each case, the approved distribution rate reflects an ROE of 10.0%. The orders each provided that the rate increases are effective as of June 16, 2007, and will remain in effect for an initial period of nine months from the date of the order (or until April 19, 2008). These rates are subject to a Phase II proceeding in which the MPSC will consider 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 is required. Hearings for the Phase II proceeding are scheduled for mid-March 2008.
New Jersey
On June 1, 2007, ACE filed with the NJBPU an application for permission to decrease the Non Utility Generation Charge (NGC) and increase components of its Societal Benefits Charge (SBC) to be collected from customers for the period October 1, 2007 through September 30, 2008. The proposed changes are designed to effect a true-up of the actual and estimated costs and revenues collected through the current NGC and SBC rates through September 30, 2007 and, in the case of the SBC, forecasted costs and revenues for the period October 1, 2007 through September 30, 2008.
As of December 31, 2007, the NGC, which is intended primarily to recover the above-market component of payments made by ACE under non-utility generation contracts and stranded costs associated with those commitments, had an over-recovery balance of $224.3 million. The filing proposed that the estimated NGC balance as of September 30, 2007 in the amount of $216.2 million, including interest, be amortized and returned to ACE customers over a four-year period, beginning October 1, 2007.
As of December 31, 2007, the SBC, which is intended to allow ACE to recover certain costs involved with various NJBPU-mandated social programs, had an under-recovery of approximately $20.9 million, primarily due to increased costs associated with funding the New Jersey Clean Energy Program. In addition, ACE has requested an increase to the SBC to reflect the funding levels approved by the NJBPU of $20.4 million for the period October 1, 2007 through September 30, 2008, bringing to $40 million the total recovery requested for the period October 1, 2007 to September 30, 2008 (based upon actual data through August 2007).
The net impact of the proposed adjustments to the NGC and the SBC, including associated changes in sales and use tax, is an overall rate decrease of approximately $129.9 million for the period October 1, 2007 through September 30, 2008 (based upon actual data through August 2007). The proposed adjustments and the corresponding changes in customer rates are subject to the approval of the NJBPU. If approved and implemented, ACE anticipates that the revised rates will remain in effect until September 30, 2008, subject to an annual true-up and change each year thereafter. The proposed adjustments and the corresponding changes in customer rates remain under review by the NJBPU and have not yet been implemented.
ACE Restructuring Deferral Proceeding
Pursuant to orders issued by the NJBPU under EDECA, beginning August 1, 1999, ACE was obligated to provide BGS to retail electricity customers in its service territory who did not elect to purchase electricity from a competitive supplier. For the period August 1, 1999 through July 31, 2003, ACE’s aggregate costs that it was allowed to recover from customers exceeded its aggregate revenues from supplying BGS. These under-recovered costs were partially offset by a $59.3 million deferred energy cost liability existing as of July 31, 1999 (LEAC Liability) related to ACE’s Levelized Energy Adjustment Clause and ACE’s Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance of under-recovered costs.
In August 2002, ACE filed a petition with the NJBPU for the recovery of approximately $176.4 million in actual and projected deferred costs relating to the provision of BGS and other
restructuring related costs incurred by ACE over the four-year period August 1, 1999 through July 31, 2003, net of the $59.3 million offset for the LEAC Liability. The petition also requested that ACE’s rates be reset as of August 1, 2003 so that there would be no under-recovery of costs embedded in the rates on or after that date. The increase sought represented an overall 8.4% annual increase in electric rates.
In July 2004, the NJBPU issued a final order in the restructuring deferral proceeding confirming a July 2003 summary order, which (i) permitted ACE to begin collecting a portion of the deferred costs and reset rates to recover on-going costs incurred as a result of EDECA, (ii) approved the recovery of $125 million of the deferred balance over a ten-year amortization period beginning August 1, 2003, (iii) transferred to ACE’s then pending base rate case for further consideration approximately $25.4 million of the deferred balance (the base rate case ended in a settlement approved by the NJBPU in May 2005, the result of which is that any net rate impact from the deferral account recoveries and credits in future years will depend in part on whether rates associated with other deferred accounts considered in the case continue to generate over-collections relative to costs), and (iv) estimated the overall deferral balance as of July 31, 2003 at $195.0 million, of which $44.6 million was disallowed recovery by ACE. Although ACE believes the record does not justify the level of disallowance imposed by the NJBPU in the final order, the $44.6 million of disallowed incurred costs were reserved during the years 1999 through 2003 (primarily 2003) through charges to earnings, primarily in the operating expense line item “deferred electric service costs,” with a corresponding reduction in the regulatory asset balance sheet account. In 2005, an additional $1.2 million in interest on the disallowed amount was identified and reserved by ACE. In August 2004, ACE filed a notice of appeal with respect to the July 2004 final order with the Appellate Division of the Superior Court of New Jersey (the Appellate Division), which hears appeals of the decisions of New Jersey administrative agencies, including the NJBPU. On August 9, 2007, the Appellate Division, citing deference to the factual and policy findings of the NJBPU, affirmed the NJBPU’s decision in its entirety, rejecting challenges from ACE and the Division of Rate Counsel. On September 10, 2007, ACE filed an application for certification to the New Jersey Supreme Court. On January 15, 2008, the New Jersey Supreme Court denied ACE’s application for certification. Because the full amount at issue in this proceeding was previously reserved by ACE, there will be no further financial statement impact to ACE.
Divestiture Cases
District of Columbia
Final briefs on Pepco’s District of Columbia divestiture proceeds sharing application were filed with the DCPSC in July 2002 following an evidentiary hearing in June 2002. That application was filed to implement a provision of Pepco’s DCPSC-approved divestiture settlement that provided for a sharing of any net proceeds from the sale of Pepco’s generation-related assets. One of the principal issues in the case 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, 2007, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6.5 million and $5.8 million, respectively.
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 ($5.8 million as of December 31, 2007), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance $4.0 million as of December 31, 2007) 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 2003, the IRS issued a notice of proposed rulemaking (NOPR), which would allow for the sharing of EDIT and ADITC related to divested assets with utility customers on a prospective basis and at the election of the taxpayer on a retroactive basis. In December 2005 a revised NOPR was issued which, among other things, withdrew the March 2003 NOPR and eliminated the taxpayer’s ability to elect to apply the regulation retroactively. Comments on the revised NOPR were filed in March 2006, and a public hearing was held in April 2006. Pepco filed a letter with the DCPSC in January 2006, in which it has reiterated that the DCPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations. 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 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, 2007, the Maryland allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $9.1 million and $10.4 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 (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 ($9.1 million as of December 31, 2007), 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 ($10.4 million as of December 31, 2007), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($7.2 million as of December 31, 2007), 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. Pepco filed a letter with the MPSC in January 2006, in which it has reiterated that the MPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations.
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 and Pepco does not believe that it will do so until action is taken by the IRS as described above. 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 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.
New Jersey
In connection with the divestiture by ACE of its nuclear generating assets, the NJBPU in July 2000 preliminarily determined that the amount of stranded costs associated with the divested assets that ACE could recover from ratepayers should be reduced by approximately $94.8 million, consisting of $54.1 million of accumulated deferred federal income taxes (ADFIT) associated with accelerated depreciation on the divested nuclear assets, and $40.7 million of current tax loss from selling the assets at a price below the tax basis.
The $54.1 million in deferred taxes associated with the divested assets’ accelerated depreciation, however, is subject to the normalization rules. Due to uncertainty under federal tax law regarding whether the sharing of federal income tax benefits associated with the divested assets, including ADFIT related to accelerated depreciation, with ACE’s customers would violate the normalization rules, ACE submitted a request to the IRS for a Private Letter Ruling (PLR) to clarify the applicable law. The NJBPU delayed its final determination of the amount of recoverable stranded costs until after the receipt of the PLR.
On May 25, 2006, the IRS issued the PLR in which it stated that returning to ratepayers any of the unamortized ADFIT attributable to accelerated depreciation on the divested assets after the sale of the assets by means of a reduction of the amount of recoverable stranded costs would violate the normalization rules.
On June 9, 2006, ACE submitted a letter to the NJBPU, requesting that the NJBPU conduct proceedings to finalize the determination of the stranded costs associated with the sale of ACE’s nuclear assets in accordance with the PLR. In the absence of an NJBPU action regarding ACE’s request, on June 22, 2007, ACE filed a motion requesting that the NJBPU issue an order finalizing the determination of such stranded costs in accordance with the PLR. On October 24, 2007, the NJBPU approved a stipulation resolving the ADFIT issue and issued a clarifying order, which concludes that the $94.8 million in stranded cost reduction, including the $54.1 million in ADFIT, does not violate the IRS normalization rules. In explaining this result, the NJBPU stated that (i) its earlier orders determining ACE’s recoverable stranded costs “net of tax” did not cause ADFIT associated with certain divested nuclear assets to reduce stranded costs otherwise recoverable from ACE’s ratepayers, and (ii) because the Market Transition Charge-Tax component of the stranded cost recovery was intended by the NJBPU to gross-up “net of tax” stranded costs, thereby ensuring and establishing that the ADFIT balance was not flowed through to ratepayers, the normalization rules were not violated.
Default Electricity Supply Proceedings
Virginia
In June 2007, the Virginia State Corporation Commission (VSCC) denied DPL’s request for an increase in its rates for Default Service for the period July 1, 2007 to May 31, 2008. DPL appealed in both state and federal courts. Those appeals have been dismissed in light of the closing of the sale of DPL's Virginia electric operations as described below under the heading “DPL Sale of Virginia Operations.”
ACE Sale of B.L. England Generating Facility
On February 8, 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, for which it received proceeds of approximately $9 million. At the time of the sale, RC Cape May and ACE agreed to submit to arbitration the issue of whether RC Cape May, under the terms of the purchase agreement, must pay to ACE an additional $3.1 million as part of the purchase price. On February 26, 2008, the arbitrators issued a decision awarding $3.1 million to ACE, plus interest, attorneys’ fees and costs, for a total award of approximately $4.2 million.
On July 18, 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement. 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. In addition, RC Cape May has asserted a claim for indemnification from ACE in the amount of $25 million if the TSA is held not to be enforceable against Citgo. While ACE believes that it
has defenses to the indemnification under the terms of the purchase agreement, 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 sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. ACE anticipates that approximately $9 million to $10 million of additional regulatory assets related to B.L. England may, subject to NJBPU approval, be eligible for recovery as stranded costs. Approximately $47 million in emission allowance credits associated with B. L. England were monetized for the benefit of ACE’s ratepayers pursuant to the NJBPU order approving the sale. Net proceeds from the sale of the plant and monetization of the emission allowance credits, estimated to be $36.1 million as of December 31, 2007, will be credited to ACE’s ratepayers in accordance with the requirements of EDECA and NJBPU orders. The appropriate mechanism for crediting the net proceeds from the sale of the plant and the monetized emission allowance credits to ratepayers is being determined in a proceeding that is currently pending before the NJBPU.
DPL Sale of Virginia Operations
On January 2, 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price of approximately $45.2 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5.4 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 are purchasing (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date. These sales are expected to result in an immaterial financial gain to DPL that will be recorded in the first quarter of 2008.
Pepco Energy Services Deactivation of Power Plants
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 MW. 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 MW. 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 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. Prior to deactivation of the plants, Pepco Energy Services may incur deficiency charges imposed by PJM at a rate up to two times the capacity payment price that the plants receive. Deactivation is not expected to have a material impact on PHI’s financial condition, results of operations or cash flows.
General Litigation
During 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.” Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepco’s property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings are not entirely clear, it appears that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant.
Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of December 31, 2007, 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 Corporation 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 current 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.
On September 19, 2007, the Delaware District Court issued an order granting summary judgment in favor of the PHI Parties. On October 12, 2007, the plaintiffs filed an appeal of the decision to the U.S. Court of Appeals for the Third Circuit.
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.
Cambridge, Maryland Site. In July 2004, DPL entered into an administrative consent order (ACO) with the Maryland Department of the Environment (MDE) to perform a Remedial Investigation/Feasibility Study (RI/FS) to further identify the extent of soil, sediment and ground and surface water contamination related to former manufactured gas plant (MGP) operations at a Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The MDE has approved the RI and DPL submitted a final FS to MDE on February 15, 2007. No further MDE action is required with respect to the final FS. The costs of cleanup (as determined by the RI/FS and subsequent negotiations with MDE) are anticipated to be approximately $3.8 million. The remedial action to be taken by DPL will include dredging activities within Cambridge Creek, which are expected to commence in March 2008, and soil excavation on DPL’s and adjacent property as early as August 2008. The final cleanup costs will include protective measures to control contaminant migration during the dredging activities and improvements to the existing shoreline.
Delilah Road Landfill Site. In November 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 other PRPs, signed an ACO 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 EPA’s costs 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) and in October 2007, EPA and the PRP group entered into a tolling agreement to permit the parties sufficient time to execute a final settlement agreement. This settlement agreement 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. 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.
Frontier Chemical Site. On June 29, 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 the 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.
Carolina Transformer Site. In August 2006, EPA notified each of DPL and Pepco that they have been identified as entities that sent PCB-laden oil to be disposed at the Carolina Transformer site in Fayetteville, North Carolina. The EPA notification stated that, on this basis, DPL and Pepco may be PRPs. In December 2007, DPL and Pepco agreed to enter into a settlement agreement with EPA and the PRP group at the Carolina Transformer site. Under the terms of the settlement, (i) Pepco and DPL each will pay $162,000 to EPA to resolve any liability that it might have at the site, (ii) EPA covenants not to sue or bring administrative action against DPL and Pepco for response costs at the site, (iii) other PRP group members release all rights for cost recovery or contribution claims they may have against DPL and Pepco, and (iv) DPL and Pepco release all rights for cost recovery or contribution claims that they may have against other parties settling with EPA. The consent decree is expected to be filed with the U.S. District Court in North Carolina in the second quarter of 2008.
Deepwater Generating Station. On December 27, 2005, NJDEP issued a Title V Operating Permit for Conectiv Energy’s Deepwater Generating Station. The permit includes new limits on unit heat input. In order to comply with these new operational limits, Conectiv Energy restricted the output of the Deepwater Generating Station’s Unit 1 and Unit 6. In 2006 and the first half of 2007, these restrictions resulted in operating losses of approximately $10,000
per operating day on Unit 6, primarily because of lost revenues due to reduced output, and to a lesser degree because of lost revenues related to capacity requirements of PJM. Since June 1, 2007, Deepwater Unit 6 can operate within the heat input limits set forth in the Title V Operating Permit without restricting output, because of technical improvements that partially corrected the inherent bias in the continuous emissions monitoring system that had caused recorded heat input to be higher than actual heat input. In order to comply with the heat input limit at Deepwater Unit 1, Conectiv Energy continues to restrict Unit 1 output, resulting in operating losses of approximately $500,000 in the second half of 2007 and projected operating losses in 2008 of approximately $500,000, due to penalties and lost revenues related to PJM capacity requirements. Beyond 2008, while penalties due to PJM capacity requirements are not expected, further operating losses due to lost revenues related to PJM capacity requirements may continue to be incurred. The operating losses due to reduced output on Unit 1 have been, and are expected to continue to be, insignificant. Conectiv Energy is challenging these heat input restrictions and other provisions of the Title V Operating Permit for Deepwater Generating Station in the New Jersey Office of Administrative Law (OAL). On October 2, 2007, the OAL issued a decision granting summary decision in favor of Conectiv Energy, finding that hourly heat input shall not be used as a condition or limit for Conectiv Energy’s electric generating operations. On October 26, 2007, the NJDEP Commissioner denied NJDEP’s request for interlocutory review of the OAL order and determined that the Commissioner would review the October 2, 2007 order upon completion of the proceeding on Conectiv Energy’s other challenges to the Deepwater Title V permit. A hearing on the remaining challenged Title V permit provisions is scheduled for mid-April 2008.
On April 3, 2007, NJDEP issued an Administrative Order and Notice of Civil Administrative Penalty Assessment (the First Order) alleging that at Conectiv Energy's Deepwater Generating Station, the maximum gross heat input to Unit 1 exceeded the maximum allowable heat input in calendar year 2005 and the maximum gross heat input to Unit 6 exceeded the maximum allowable heat input in calendar years 2005 and 2006. The order required the cessation of operation of Units 1 and 6 above the alleged permitted heat input levels, assessed a penalty of approximately $1.1 million and requested that Conectiv Energy provide additional information about heat input to Units 1 and 6. Conectiv Energy provided NJDEP Units 1 and 6 calendar year 2004 heat input data on May 9, 2007, and calendar years 1995 to 2003 heat input data on July 10, 2007. On May 23, 2007, NJDEP issued a second Administrative Order and Notice of Civil Administrative Penalty Assessment (the Second Order) alleging that the maximum gross heat input to Units 1 and 6 exceeded the maximum allowable heat input in calendar year 2004. The Second Order required the cessation of operation of Units 1 and 6 above the alleged permitted heat input levels and assessed a penalty of $811,600. Conectiv Energy has requested a contested case hearing challenging the issuance of the First Order and the Second Order and moved for a stay of the orders pending resolution of the Title V Operating Permit contested case described above. On November 29, 2007, the OAL issued orders placing the First Order and the Second Order on the inactive list for six months. Until the OAL decision discussed above is final, it will not have an impact on these currently inactive enforcement cases.
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, which was 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 exchange under IRC Section 1031. In July 2006, Conectiv filed a protest of this disallowance to the IRS Office of Appeals.
PHI believes that its tax position related to this transaction is proper based on applicable statutes, regulations and case law and is contesting the disallowance. However, there is no absolute assurance that Conectiv’s position will prevail. If the IRS prevails, Conectiv would be subject to additional income taxes, interest and possible penalties. However, a portion of the denied benefit would be offset by additional tax depreciation. PHI has accrued approximately $4.9 million related to this matter.
As of December 31, 2007, if the IRS were to fully prevail, the potential cash impact on PHI would be current income tax and interest payments of approximately $31.2 million and the earnings impact would be approximately $9.8 million in after-tax interest.
Federal Tax Treatment of Cross-Border Leases
PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which, as of December 31, 2007, had a book value of approximately $1.4 billion, and from which PHI currently derives approximately $60 million per year in tax benefits in the form of interest and depreciation deductions.
In 2005, the Treasury Department and IRS issued Notice 2005-13 informing taxpayers that the IRS intends to challenge on various grounds the purported tax benefits claimed by taxpayers entering into certain sale-leaseback transactions with tax-indifferent parties (i.e., municipalities, tax-exempt and governmental entities), including those entered into on or prior to March 12, 2004 (the Notice). All of PCI’s cross-border energy leases are with tax indifferent parties and were entered into prior to 2004. Also in 2005, the IRS published a Coordinated Issue Paper concerning the resolution of audit issues related to such transactions. PCI’s cross-border energy leases are similar to those sale-leaseback transactions described in the Notice and the Coordinated Issue Paper.
PCI’s leases have been under examination by the IRS as part of the normal PHI tax audit. In June 2006, the IRS issued its final RAR for its audit of PHI’s 2001 and 2002 income tax returns. In the RAR, the IRS disallowed the tax benefits claimed by PHI with respect to these leases for those years. The tax benefits claimed by PHI with respect to these leases from 2001 through December 31, 2007 were approximately $347 million. PHI has filed a protest against the IRS adjustments and the unresolved audit has been forwarded to the U.S. Office of Appeals. The ultimate outcome of this issue is uncertain; however, if the IRS prevails, PHI would be subject to additional taxes, along with interest and possibly penalties on the additional taxes, which could have a material adverse effect on PHI’s financial condition, results of operations, and cash flows. PHI believes that its tax position related to these transactions was appropriate
based on applicable statutes, regulations and case law, and intends to contest the adjustments proposed by the IRS; however, there is no assurance that PHI’s position will prevail.
In 2006, the FASB issued FSP FAS 13-2, which amends SFAS No. 13 effective for fiscal years beginning after December 15, 2006. This amendment requires a lease to be repriced and the book value adjusted when there is a change or probable change in the timing of tax benefits of the lease regardless of whether the change results in a deferral or permanent loss of tax benefits. Accordingly, a material change in the timing of cash flows under PHI’s cross-border leases as the result of a settlement with the IRS would require an adjustment to the book value of the leases and a charge to earnings equal to the repricing impact of the disallowed deductions which could result in a material adverse effect on PHI’s financial condition, results of operations, and cash flows. PHI believes its tax position was appropriate and at this time does not believe there is a probable change in the timing of its tax benefits that would require repricing the leases and a charge to earnings.
On December 14, 2007 the U.S. Senate passed its version of the Farm, Nutrition, and Bioenergy Act of 2007 (H.R. 2419) which contains a provision that would apply passive loss limitation rules to leases with foreign tax indifferent parties effective for taxable years beginning after December 31, 2006, even if the leases were entered into on or prior to March 12, 2004. The U.S. House of Representatives version of this proposed legislation which it passed on July 27, 2007 does not contain any provision that would modify the current treatment of leases with tax indifferent parties. Enactment into law of a bill that is similar to that passed by the U.S. Senate in its current form could result in a material delay of the income tax benefits that PHI would receive in connection with its cross-border energy leases. Furthermore, if legislation of this type were to be enacted, under FSP FAS 13-2, PHI would be required to adjust the book value of the leases and record a charge to earnings equal to the repricing impact of the deferred deductions which could result in a material adverse effect on PHI’s financial condition, results of operations and cash-flows. The U.S. House of Representatives and the U.S. Senate are expected to hold a conference in the near future to reconcile the differences in the two bills to determine the final legislation.
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 the proposed regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believes will be acceptable to the IRS.
At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which is 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 RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco, DPL and ACE had claimed on those returns 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 Appeals Office.
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. However, if the IRS is successful in requiring Pepco, DPL and ACE to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management’s estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006. It is reasonably possible that PHI’s unrecognized tax benefits related to this issue will significantly decrease in the next 12 months as a result of a settlement with the IRS.
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 which are entered into in the normal course of business to facilitate commercial transactions with third parties as discussed below.
As of December 31, 2007, 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 ensuring the 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, 2007, obligations under the guarantees were approximately $5.7 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 $2.3 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. As of December 31, 2007, the guarantees cover the remaining $1.4 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.
Dividends
On January 24, 2008, the Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2008, to shareholders of record March 10, 2008.
Contractual Obligations
As of December 31, 2007, Pepco Holdings’ contractual obligations under non-derivative fuel and purchase power contracts, excluding the BGS supplier load commitments, were $3,176.7 million in 2008, $2,756.8 million in 2009 to 2010, $752.7 million in 2011 to 2012, and $3,119.9 million in 2013 and thereafter.
(13)
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 (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 and known minimum cash flows, and lock in favorable prices and margins when they become available. To a lesser extent, Conectiv Energy also engages in energy marketing activities. 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 prior to October 31, 2006, provided operating services under an agreement with an unaffiliated generating plant. PHI collectively refers to these energy marketing activities, including its commodity risk management activities, as “other energy commodity” activities and identifies this activity separately from the discontinued proprietary trading activity that was discontinued in 2003.
Conectiv Energy assesses risk on a total portfolio basis and by component (e.g. generation output, generation fuel, load supply, etc.). Portfolio risk combines the generation
fleet, load obligations, miscellaneous commodity sales and hedges. Derivatives designated as cash flow and fair value hedges (Accounting Hedges) are matched against each component using the product or products that most closely represent the underlying hedged item. The total portfolio is risk managed based on its megawatt position by month. If the total portfolio becomes too long or too short for a period as determined in accordance with Conectiv Energy’s policies, steps are taken to reduce or increase hedges. Portfolio-level hedging includes the use of Accounting Hedges, derivatives that are being marked-to-market through earnings, and other physical commodity purchases and sales.
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. Its options contracts are marked-to-market through current earnings. Its 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.
Policies and practices designed to minimize credit risk exposure to wholesale energy counterparties include, among other things, formal credit policies, regular assessment of counterparty creditworthiness and the establishment of a credit limit for each counterparty, monitoring procedures that include stress testing, the use of standard agreements which allow for the netting of positive and negative exposures associated with a single counterparty and collateral requirements under certain circumstances, and the establishment of reserves for credit losses.
PHI and its subsidiaries also use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt incurred in connection with the operation of their businesses. In June 2002, PHI entered into several treasury lock transactions in anticipation of the issuance of several series of fixed rate debt commencing in July 2002. There remained a loss balance of $28.8 million in Accumulated Other Comprehensive Income (AOCI) at December 31, 2007 related to this transaction. The portion expected to be reclassified to earnings during the next 12 months is $3.3 million. In addition, interest rate swaps have been executed in support of PCI’s medium-term note program.
PCI has entered into interest rate swap agreements for the purpose of managing its overall borrowing rate and managing its interest rate exposure associated with debt it has issued. PCI’s outstanding fixed rate debt issued under its Medium-Term Note program was swapped into variable rate debt in a transaction entered into in December 2001, which matures in December 2008. All of PCI’s hedges on variable rate debt issued under its Medium-Term Note program matured during 2005.
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, 2007. Under SFAS No. 133, cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to AOCI. The data in the table indicates the magnitude of the effective cash flow hedges by hedge type (i.e., other 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 Loss as of December 31, 2007, includes a $(7.5) million balance related to minimum pension liability. This balance is not included in this table as there is not a cash flow hedge associated with it.
The following table shows, in millions of dollars, the pre-tax gain (loss) recognized in earnings for cash flow hedge ineffectiveness for the years ended December 31, 2007, 2006, and 2005, and where they were reported in the Consolidated Statements of Earnings during the period.
In connection with their other energy commodity activities, the Competitive Energy businesses designate certain derivatives as fair value hedges. The net pre-tax gains/(losses) recognized during the twelve months ended December 31, 2007, 2006 and 2005 included in the Consolidated Statements of Earnings for fair value hedges and the associated hedged items are shown in the following table (in millions of dollars).
(Loss)/Gain on Derivative Instruments
$ (9.5)
$ .2
$-
Gain/(Loss) on Hedged Items
$ 9.7
$(.2)
$-
For the years ended 2007 and 2006, losses of $1.8 million and $.3 million, respectively, were reclassified from other comprehensive income (OCI) to earnings because the forecasted hedged transactions were deemed to be no longer probable.
In connection with their other energy commodity activities, the Competitive Energy businesses hold certain derivatives that do not qualify as hedges. Under SFAS No. 133, these derivatives are marked-to-market 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, in millions of dollars, for the years ended December 31, 2007, 2006, and 2005.
Proprietary Trading (a)
$ -
$ -
$ .1
Other Energy Commodity (b)
8.7
64.7
37.8
Total
$ 8.7
$64.7
$37.9
(a)
PHI discontinued its proprietary trading activity in 2003.
(b)
Includes $.5 million, $.3 million and zero in effective fair value hedge gains for the years ended December 31, 2007, 2006 and 2005, respectively.
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 firm customers’ exposure to increases in the market price of gas. DPL also manages commodity risk with capacity contracts that do not meet the definition of derivatives. The primary goal of these activities is to reduce the exposure of its regulated retail gas customers to natural gas price spikes. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses on the natural gas hedging activity, are fully recoverable through the gas cost rate clause included in DPL’s gas tariff rates approved by the DPSC and are deferred under SFAS No. 71 until recovered. At December 31, 2007, DPL had a net deferred derivative payable of $13.1 million, offset by a $13.1 million regulatory asset. At December 31, 2006, DPL had a net deferred derivative payable of $27.3 million, offset by a $28.5 million regulatory asset.
(14) EXTRAORDINARY ITEM
On April 19, 2005, ACE, the staff of the NJBPU, the New Jersey Ratepayer Advocate, and active intervenor parties agreed on a settlement in ACE’s electric distribution rate case. As a result of this settlement, ACE reversed $15.2 million in accruals related to certain deferred costs that are now deemed recoverable. The after-tax credit to income of $9.0 million is classified as an extraordinary gain in the 2005 financial statements since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.
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, 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 adjustment related to timing of recognition of certain operating revenues which were overstated by $0.5 million and $1.9 million in the second and third quarters, respectively, and understated by $2.4 million in the fourth quarter.
(b)
Includes adjustment related to timing of recognition of certain operating expenses which were overstated by $4.8 million in the fourth quarter and understated by $1.2 million and $3.6 million in the second and third quarters, respectively.
(c)
Includes $33.4 million benefit ($20.0 million after-tax) from settlement of Mirant bankruptcy claims.
(d)
Includes $19.5 million benefit ($17.7 million net of fees) related to Maryland income tax refund.
(e)
Includes $12.3 million gain ($7.9 million after-tax) on the sale of its equity interest in a joint venture which owns a wood burning cogeneration facility.
(f)
Includes $18.9 million of impairment losses ($13.7 million after-tax) related to certain energy services business assets.
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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, 2007 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, 2007.
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.
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, 2007 and December 31, 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007 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 8 to the financial statements, the Company changed its manner of accounting and reporting for uncertain tax positions in 2007.
PricewaterhouseCoopers LLP
Washington, DC
February 29, 2008
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 and Montgomery Counties in suburban Maryland. Pepco provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier, in both the District of Columbia and Maryland. Default Electricity Supply is known as Standard Offer Service (SOS) in both the District of Columbia and Maryland. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI).
(2) SUMMARY OF 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 estimates used by Pepco 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 that are probable and reasonably estimable.
Adjustment to Pepco’s Previously Recorded Delivery Taxes
In 2006, Pepco recorded an adjustment to correct previously recorded District of Columbia delivery tax amounts. This adjustment reduced Pepco’s earnings for the twelve months ended December 31, 2006 by $2.9 million.
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 $18.8 million for the last six months of 2007.
During 2005, Pepco recorded the impact of an increase in estimated unbilled revenue (electricity delivered to the customer but not yet billed), primarily reflecting a change in Pepco’s
unbilled revenue estimation process. This modification in accounting estimate increased net earnings for the year ended December 31, 2005 by approximately $2.2 million.
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 $81.9 million and $82.0 million as of December 31, 2007 and 2006, 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, the impact of which could be material.
The 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.
Regulation of Power Delivery Operations
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 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 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. Should existing facts or circumstances change in the future to indicate that a regulatory asset is not probable of recovery, the regulatory asset will be charged to earnings.
As part of the new electric service distribution base rates for Pepco approved by the MPSC, effective June 16, 2007, the MPSC approved a bill stabilization adjustment mechanism (BSA) for retail customers. See Note 10 “Commitments and Contingencies - Regulatory and Other Matters - Rate Proceedings.” 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, 2007 is a regulatory asset and is included in the “Other” line item on the table of regulatory asset balances listed below.
The components of Pepco’s regulatory asset balances at December 31, 2007 and 2006 are as follows:
The components of Pepco’s regulatory liability balances at December 31, 2007 and 2006 are as follows:
A description of the regulatory assets and regulatory liabilities is as follows:
Deferred Recoverable 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 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 residential and small commercial customers to mitigate the immediate impact of significant rate increases due to energy costs in 2006. The deferral period for Maryland was June 1, 2006 to June 1, 2007, with the recovery to occur over an 18-month period beginning June 2007. The Maryland deferral will be recovered from participating customers at a rate per kilowatt-hour based on energy usage during the recovery period.
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.
Asset Removal Costs: Represents Pepco’s asset retirement obligation associated with removal costs accrued using public service commission approved depreciation techniques for transmission, distribution, and general utility property.
Settlement proceeds - Mirant Bankruptcy Claims: Represents the $413.9 million of net proceeds received by Pepco from settlement of a Mirant Corporation (Mirant) claim, plus interest earned, which will be used to pay for future above-market capacity and energy purchases under a power purchase agreement entered into with Panda-Brandywine L.P. (Panda) over the remaining life of the agreement, which extends through 2021 (the Panda PPA).
Other: Includes miscellaneous regulatory liabilities such as the over-recovery of procurement, transmission and administrative costs associated with Maryland and District of Columbia SOS.
Asset Retirement Obligations
In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” and Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, asset removal costs are recorded as regulatory liabilities. At December 31, 2007 and 2006, $97.6 million and $92.7 million, respectively, are reflected as regulatory liabilities in the accompanying Balance Sheets. Additionally, in 2005, Pepco recorded immaterial conditional asset retirement obligations for underground storage tanks. Accretion for these asset retirement obligations has been recorded as a regulatory asset.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, money market funds, and commercial paper 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. Deposits in the money pool were zero and $.4 million at December 31, 2007 and 2006, respectively.
Restricted Cash and Cash Equivalents
The restricted cash that is included in Current Assets and the restricted cash and cash equivalents that is 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 solely to
fund the future above-market capacity and energy purchase costs under the Panda PPA. 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 balances primarily consist 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 uses the allowance method to account for uncollectible accounts receivable.
Investment in Trust
Represents assets held in a trust for the benefit of participants in the Pepco Owned Life Insurance plan.
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 $4.7 million, $1.5 million, and $1.6 million for the years ended December 31, 2007, 2006, and 2005, respectively.
Pepco recorded amounts for the equity component of AFUDC of $3.3 million for the year ended December 31, 2007 and $2.6 million for the years ended December 31, 2006, and 2005, respectively.
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.
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.
Severance Costs
In 2004, PHI’s Power Delivery business reduced its work force through a combination of retirements and targeted reductions. This plan met the criteria for the accounting treatment provided under SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” and SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” as applicable. A roll forward of Pepco’s severance accrual balance is as follows (Millions of dollars).
All of the severance liability was paid by December 31, 2007. Employees had the option of taking severance payments in a lump sum or over a period of time.
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.
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.
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 2007, 2006, and 2005 for Pepco’s transmission and distribution system property were approximately 3.0%, 3.5%, and 3.4%, respectively.
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 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 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. For additional information, see the discussion under “Regulation of Power Delivery Operations” above.
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 the Panda PPA, Pepco potentially assumes the variability in the operations of the plants related to this PPA and therefore has a variable interest in the entity. In accordance with the provisions of FIN 46R (revised December 2003), entitled “Consolidation of Variable Interest Entities,” (FIN 46R), Pepco continued, during the year ended December 31, 2007, to conduct exhaustive efforts to obtain information from this entity, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R to determine whether the entity was a variable interest entity or if Pepco was the primary beneficiary. As a result, Pepco 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.
Power purchases related to the Panda PPA for the years ended December 31, 2007, 2006 and 2005, were approximately $85 million, $79 million and $91 million, respectively.
Other Non-Current Assets
The other assets balance principally consists of deferred compensation trust assets and unamortized debt expense.
Other Current Liabilities
The other current liability balance principally consists of customer deposits, accrued vacation liability, and other miscellaneous liabilities. For 2006, this balance included $70 million paid to Pepco by Mirant in settlement of claims resulting from the Mirant bankruptcy.
Other Deferred Credits
The other deferred credits balance principally consists of miscellaneous deferred liabilities.
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 $75.0 million and $11.7 million of restricted retained earnings at December 31, 2007 and 2006, respectively.
Reclassifications
Certain prior year amounts have been reclassified in order to conform to current year presentation.
Newly Adopted Accounting Standards
FSP FTB 85-4-1, “Accounting for Life Settlement Contracts by Third-Party Investors”
In March 2006, the FASB issued FSP FASB Technical Bulletin (FTB) 85-4-1, “Accounting for Life Settlement Contracts by Third-Party Investors” (FSP FTB 85-4-1). This FSP provides initial and subsequent measurement guidance and financial statement presentation and disclosure guidance for investments by third-party investors in life settlement contracts. FSP FTB 85-4-1 also amends certain provisions of FTB No. 85-4, “Accounting for Purchases of Life Insurance,” and SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The guidance in FSP FTB 85-4-1 applies prospectively for all new life settlement contracts and is effective for fiscal years beginning after June 15, 2006 (year ended December 31, 2007 for Pepco). Implementation of FSP FTB 85-4-1 did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.
EITF Issue No. 06-3, “Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions”
On June 28, 2006, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 06-3, “Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions” (EITF 06-3). EITF 06-3 provides guidance on an entity’s disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity’s activities over a period of time are not within the scope of EITF 06-3. Pepco implemented EITF 06-3 during the first quarter of 2007. Taxes included in Pepco’s gross revenues were $243.1 million, $223.4 million and $229.4 million for the twelve months ended December 31, 2007, 2006 and 2005, respectively.
FSP AUG AIR-1, “Accounting for Planned Major Maintenance Activities”
On September 8, 2006, the FASB issued FSP American Institute of Certified Public Accountants Industry Audit Guide, Audits of Airlines--”Accounting for Planned Major Maintenance Activities” (FSP AUG AIR-1), which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods for all industries. FSP AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006 (year ended December 31, 2007 for Pepco). Implementation of FSP AUG AIR-1 did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.
EITF Issue No. 06-5, “Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance”
On September 20, 2006, the FASB ratified EITF Issue No. 06-5, “Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance” (EITF 06-5) which provides guidance on whether an entity should consider the contractual ability to surrender all of the individual-life policies (or certificates under a group life policy) together when determining the amount that could be realized in accordance with FTB 85-4, and whether a guarantee of the additional value associated with the group life policy affects that determination. EITF 06-5 provides that a policyholder should (i) determine the amount that could be realized under the insurance contract assuming the surrender of an individual-life by individual-life policy (or certificate by certificate in a group policy) and (ii) not discount the cash surrender value component of the amount that could be realized when contractual restrictions on the ability to surrender a policy exist unless contractual limitations prescribe that the cash surrender value component of the amount that could be realized is a fixed amount, in which case the amount that could be realized should be discounted in accordance with Accounting Principles Board of the American Institute of Certified Public Accountants Opinion 21. EITF 06-5 is effective for fiscal years beginning after December 15, 2006 (year ended December 31, 2007 for Pepco). Implementation of EITF 06-5 did not have a material impact on Pepco’s overall financial condition, results of operations, cash flows, or footnote disclosure requirements.
Recently Issued Accounting Standards, Not Yet Adopted
SFAS No. 157, “Fair Value Measurements”
In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of this Statement will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the disclosures about fair value measurements.
The provisions of SFAS No. 157, as issued, are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (January 1, 2008 for Pepco). On February 6, 2008, the FASB decided to issue final Staff Positions that will (i) defer 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) and (ii) remove certain leasing transactions from the scope of SFAS No. 157. The final Staff Positions will defer the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of the final Staff Positions. Pepco has evaluated the impact of SFAS No. 157 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, cash flows, or footnote disclosure requirements.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115”
On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115” (SFAS No. 159) which permits entities to elect to measure eligible financial instruments at fair value. The objective of SFAS No. 159 is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of SFAS No. 159 will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the disclosures about fair value measurements.
SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.
SFAS No. 159 applies to the beginning of a reporting entity’s first fiscal year that begins after November 15, 2007 (January 1, 2008 for Pepco), with early adoption permitted for an entity that has also elected to apply the provisions of SFAS No. 157, Fair Value Measurements. An entity is prohibited from retrospectively applying SFAS No. 159, unless it chooses early adoption. SFAS No. 159 also applies to eligible items existing at November 15, 2007 (or early adoption date). Pepco has evaluated the impact of SFAS No. 159 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, cash flows, or footnote disclosure requirements.
SFAS No. 141(R), “Business Combinations - a replacement of FASB Statement No. 141”
On December 4, 2007, the FASB issued SFAS No. 141(R), “Business Combinations - a replacement of FASB Statement No. 141” (SFAS No. 141(R)) which replaces FASB Statement No. 141, “Business Combinations.” This Statement retains the fundamental requirements in Statement 141 that the acquisition method of accounting (which Statement 141 called the purchase method) be used for all business combinations and for an acquirer to be identified for each business combination.
SFAS No. 141(R) applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree). It does not apply to (i) the formation of a joint venture, (ii) the acquisition of an asset or a group of assets that does not constitute a business, (iii) a combination between entities or businesses under common control and (iv) a combination between not-for-profit organizations or the acquisition of a for-profit business by a not-for-profit organization.
SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for Pepco). An entity may not apply it before that date.
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51”
On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (SFAS No. 160) which amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.
A noncontrolling interest, sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. The objective of SFAS No. 160 is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards that require (i) the ownership interests 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, (ii) the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income, (iii) changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently. A parent’s ownership interest in a subsidiary changes if the parent purchases additional ownership interests in its subsidiary or if the parent sells some of its ownership interests in its subsidiary. It also changes if the subsidiary reacquires some of its ownership interests or the subsidiary issues additional ownership interests. All of those transactions are economically similar, and this Statement requires that they be accounted for similarly, as equity transactions, (iv) when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary be initially measured at fair value. The gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any noncontrolling equity investment rather than the carrying amount of that retained investment and (v) entities provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.
SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary.
SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009, for Pepco). Earlier adoption is prohibited. SFAS No. 160 shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. Pepco is currently evaluating the impact SFAS No. 160 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.
(3) 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.
(4) LEASING ACTIVITIES
Lease Commitments
Pepco leases its consolidated control center, 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 $7.6 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, 2007 and 2006 are comprised of the following:
The approximate annual commitments under capital leases are $15.4 million for 2008, $15.2 million for 2009, 2010, 2011 and 2012, and $106.7 million thereafter.
Rental expense for operating leases was $3.7 million, $3.6 million and $2.5 million for the years ended December 31, 2007, 2006 and 2005, respectively.
Total future minimum operating lease payments for Pepco as of December 31, 2007 include $3.1 million in 2008, $2.6 million in 2009, $1.9 million in 2010, $1.5 million in 2011, $1.3 million in 2012 and $7.9 million after 2012.
(5) 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.
Asset Sales
In August 2005, Pepco sold for $75 million in cash 384,051 square feet of excess non-utility land located at Buzzard Point in the District of Columbia. The sale resulted in a pre-tax gain of $68.1 million, which was recorded as a reduction of Operating Expenses in the Statements of Earnings.
(6) PENSIONS AND OTHER POSTRETIREMENT BENEFITS
Pepco accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. For 2007, 2006, and 2005, Pepco’s allocated share of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings was approximately $22.3 million, $32.1 million, and $28.9 million, respectively. In 2007 and 2006, Pepco made no contributions to the PHI Retirement Plan, and $10.3 million and $6.0 million, respectively to other postretirement benefit plans. At December 31, 2007 and 2006, Pepco’s prepaid pension expense of $152.0 million and $160.1 million, and other postretirement benefit obligation of $57.4 million and $69.3 million, effectively represent assets and benefit obligations resulting from Pepco’s participation in the Pepco Holdings benefit plan.
(7) 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 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 tax-exempt bonds are identical to the terms of the collateral First Mortgage Bonds by which it is secured. Payments of principal and interest on a series of senior notes or 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 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.
The outstanding First Mortgage Bonds are secured by a lien on substantially all of Pepco’s property, plant and equipment.
The aggregate principal amount of long-term debt outstanding at December 31, 2007, that will mature in each of 2008 through 2012 and thereafter is as follows: $128.0 million in 2008, $50.0 million in 2009, $16.0 million in 2010, zero in 2011 and 2012, and $1,047.8 million thereafter.
Pepco’s long-term debt is subject to certain covenants. Pepco is in compliance with all requirements.
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, 2007 and 2006 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 Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE).
Pepco had $84.0 million of commercial paper outstanding at December 31, 2007 and $67.1 million of commercial paper outstanding at December 31, 2006. The weighted average interest rate for commercial paper issued during 2007 was 5.27% and 5.25% in 2006. The weighted average maturity for commercial paper issued during 2007 was four days and during 2006 was five days.
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 the 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 based on the prevailing prime rate or 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 made by the borrower at the time the credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower’s business, property, and results of operations or financial condition subsequent to the entry into the credit agreement is not a condition to the availability of credit under the facility. Among the covenants to which each of the companies is subject are (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 certain trust preferred securities and deferrable interest subordinated debt from the definition of total indebtedness (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the credit agreement. The agreement does not include any rating triggers.
(8) 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.
Provision for Income Taxes
Reconciliation of Income Tax Expense
During 2007, Pepco completed an analysis of its deferred tax accounts as of December 31, 2006. As a result of this analysis, Pepco recorded a $3.2 million charge to income tax expense which is included in "Deferred tax basis adjustment" in the reconciliation provided above.
FIN 48, “Accounting for Uncertainty in Income Taxes”
As disclosed in Note 2, “Summary of 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 $1.9 million as a decrease in retained earnings. Also upon adoption, Pepco had $95.1 million of unrecognized tax benefits and $6.9 million of related accrued interest.
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
As of December 31, 2007, Pepco had $7.4 million of accrued interest related to 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, 2007, 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 unrecognized tax benefits as an element of tax expense. For the year ended December 31, 2007, Pepco recognized $.5 million of interest income and penalties, net, as a component of tax expense.
Possible Changes to Unrecognized Benefits
Total unrecognized tax benefits that may change over the next twelve months include the matter of Mixed Service Costs. See discussion in Note 10, “Commitments and Contingencies -- IRS Mixed Service Cost Issue.”
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, 2007 and 2006.
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.
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.
(9) FAIR VALUES OF FINANCIAL INSTRUMENTS
The estimated fair values of Pepco’s financial instruments at December 31, 2007 and 2006 are shown below.
The methods and assumptions described below were used to estimate, at December 31, 2007 and 2006, the fair value of each class of financial instrument shown above for which it is practicable to estimate a value.
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.
The carrying amounts of all other financial instruments in Pepco’s accompanying financial statements approximate fair value.
(10) 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. 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 asset sale, Pepco entered into transition power agreements with Mirant pursuant to which Mirant agreed to supply all of the energy and capacity needed by Pepco to fulfill its SOS obligations in Maryland and in the District of Columbia (the TPAs). Under a settlement to avoid the rejection by Mirant of its obligations under the TPAs in the bankruptcy proceeding, the terms of the TPAs were modified to increase the purchase price of the energy and capacity supplied by Mirant and Pepco received an allowed, pre-petition general unsecured claim in the bankruptcy in the amount of $105 million (the TPA Claim). In December 2005, Pepco sold the TPA Claim, plus the right to receive accrued interest thereon, to an unaffiliated third party for $112.5 million. In addition, Pepco received proceeds of $.5 million in settlement of an asbestos claim against the Mirant bankruptcy estate. After customer sharing, Pepco recorded a pre-tax gain of $70.5 million from the settlement of these claims.
In connection with the asset sale, Pepco and Mirant also entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco is obligated to purchase annually through 2021 from Panda under the
Panda PPA at the purchase price Pepco is obligated to pay to Panda. As part of the further settlement of Pepco’s claims against Mirant arising from the Mirant 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 is obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $413.9 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. These funds are being accounted for as restricted cash based on management’s intent to use such funds, and any interest earned thereon, for the sole purpose of paying for the future above-market capacity and energy purchase costs under the Panda PPA. Correspondingly, a regulatory liability has been established in the same amount to help offset the future above-market capacity and energy purchase costs. This restricted cash has been classified as a non-current asset to be consistent with the classification of the non-current regulatory liability, and any changes in the balance of this restricted cash, including interest on the invested funds, are being accounted for as operating cash flows.
As of December 31, 2007, the balance of the restricted cash account was $417.3 million. Based on a reexamination of the costs of the Panda PPA in light of current and projected wholesale market conditions conducted in the fourth quarter of 2007, Pepco determined that, principally due to increases in wholesale capacity prices, the present value above-market cost of the Panda PPA over the term of the agreement is expected to be significantly less than the current amount of the restricted cash account balance. Accordingly, on February 22, 2008, Pepco filed applications with the DCPSC and the MPSC requesting orders directing Pepco to maintain $320 million in the restricted cash account and to use that cash, and any future earnings on the cash, for the sole purpose of paying the future above-market cost of the Panda PPA (or, in the alternative, to fund a transfer or assignment of the remaining obligations under the Panda PPA to a third party). Pepco also requested that the order provide that any cash remaining in the account at the conclusion of the Panda PPA be refunded to customers and that any shortfall be recovered from customers. Pepco further proposed that the excess proceeds remaining from the settlement (approximately $94.6 million, representing the amount by which the regulatory liability of $414.6 million at December 31, 2007 exceeded $320 million) be shared approximately equally with its customers in accordance with the procedures previously approved by each commission for the sharing of the proceeds received by Pepco from the sale to Mirant of its generating assets. The regulatory liability of $414.6 million at December 31, 2007 differs from the restricted cash amount of $417.3 million on that date, in part, because the regulatory liability has been reduced for the portion of the December 2007 Panda charges in excess of market that had not yet been paid from the restricted cash account. The amount of the restricted cash balance that Pepco is permitted to retain will be recorded as earnings upon approval of the sharing arrangement by the respective commissions. At this time, Pepco cannot predict the outcome of these proceedings.
In settlement of other damages claims against Mirant, Pepco in 2007 also received a settlement payment in the amount of $70.0 million. Of this amount (i) $33.4 million was recorded as a reduction in operating expenses, (ii) $21.0 million was recorded as a reduction in a net pre-petition receivable claim from Mirant, (iii) $15.0 million was recorded as a reduction in the capitalized costs of certain property, plant and equipment and (iv) $.6 million was recorded as a liability to reimburse a third party for certain legal costs associated with the settlement.
Rate Proceedings
In electric service distribution base rate cases filed by Pepco in the District of Columbia and Maryland, and pending in 2007, Pepco proposed the adoption of a BSA for retail customers. 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 will increase rates if actual distribution revenues fall below the level approved by the applicable commission and will decrease rates if actual distribution revenues are above the approved level. The result will be that, over time, Pepco would collect 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 Pepco to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and delivery revenues. The status of the BSA proposals in each of the jurisdictions is described below in discussion of the respective base rate proceedings.
District of Columbia
In December 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. The application to the DCPSC requested an annual increase of approximately $46.2 million or an overall increase of 13.5%, reflecting a proposed return on equity (ROE) of 10.75%. In the alternative, the application requested an annual increase of $50.5 million or an overall increase of 14.8%, reflecting an ROE of 11.00%, if the BSA were not approved. Subsequently, Pepco reduced its annual revenue increase request to $43.4 million (including a proposed BSA) and $47.9 million (if the BSA were not approved).
On January 30, 2008, the DCPSC approved a revenue requirement increase of approximately $28.3 million, based on an authorized return on rate base of 7.96%, including a 10% ROE. The rate increase is effective February 20, 2008. The DCPSC, while finding the BSA to be an appropriate ratemaking concept, cited potential statutory problems in the DCPSC’s ability to implement the BSA. The DCPSC stated that it intends to issue an order to establish a Phase II proceeding to consider these implementation issues.
Maryland
On July 19, 2007, the MPSC issued an order in the electric service distribution rate case filed by Pepco, which included approval of a BSA. The order approved an annual increase in distribution rates of approximately $10.6 million (including a decrease in annual depreciation expense of approximately $30.7 million). The approved distribution rate reflects an ROE of 10.0%. The orders provided that the rate increases are effective as of June 16, 2007, and will remain in effect for an initial period of nine months from the date of the order (or until April 19, 2008). These rates are subject to a Phase II proceeding in which the MPSC will consider 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 is required. Hearings for the Phase II proceeding are scheduled for mid-March 2008.
Divestiture Cases
District of Columbia
Final briefs on Pepco’s District of Columbia divestiture proceeds sharing application were filed with the DCPSC in July 2002 following an evidentiary hearing in June 2002. That application was filed to implement a provision of Pepco’s DCPSC-approved divestiture settlement that provided for a sharing of any net proceeds from the sale of Pepco’s generation-related assets. One of the principal issues in the case 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, 2007, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6.5 million and $5.8 million, respectively.
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 ($5.8 million as of December 31, 2007), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($4.0 million as of December 31, 2007) 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 2003, the IRS issued a notice of proposed rulemaking (NOPR), which would allow for the sharing of EDIT and ADITC related to divested assets with utility customers on a prospective basis and at the election of the taxpayer on a retroactive basis. In December 2005 a revised NOPR was issued which, among other things, withdrew the March 2003 NOPR and eliminated the taxpayer’s ability to elect to apply the regulation retroactively. Comments on the revised NOPR were filed in March 2006, and a public hearing was held in April 2006. Pepco filed a letter with the DCPSC in January 2006, in which it has reiterated that the DCPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations. 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 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, 2007, the Maryland allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $9.1 million and $10.4 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 (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 ($9.1 million as of December 31, 2007), 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 ($10.4 million as of December 31, 2007), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($7.2 million as of December 31, 2007), 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. Pepco filed a letter with the MPSC in January 2006, in which it has reiterated that the MPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations.
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 and Pepco does not believe that it will do so until action is taken by the IRS as described above. 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 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.
General Litigation
During 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.” Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepco’s property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings are not entirely clear, it appears that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant.
Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of December 31, 2007, 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 current 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.
Carolina Transformer Site. In August 2006, the U.S. Environmental Protection Agency (EPA) notified Pepco that it had been identified as an entity that sent PCB-laden oil to be disposed at the Carolina Transformer site in Fayetteville, North Carolina. The EPA notification stated that, on this basis, Pepco may be a potentially responsible party (PRP). In December
2007, Pepco agreed to enter into a settlement agreement with EPA and the PRP group at the Carolina Transformer site. Under the terms of the settlement, (i) Pepco will pay $162,000 to EPA to resolve any liability that it might have at the site, (ii) EPA covenants not to sue or bring administrative action Pepco for response costs at the site, (iii) other PRP group members release all rights for cost recovery or contribution claims they may have against Pepco, and (iv) Pepco releases all rights for cost recovery or contribution claims that it may have against other parties settling with EPA. The consent decree is expected to be filed with the U.S. District Court in North Carolina in the second quarter of 2008.
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, primarily attributable to its 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 the proposed regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believes will be acceptable to the IRS.
At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which is 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 Appeals Office.
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. However, if the IRS is successful in requiring Pepco to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management’s estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006. It is reasonably possible that PHI’s unrecognized tax benefits related to this issue will significantly decrease in the next 12 months as a result of a settlement with the IRS.
Contractual Obligations
As of December 31, 2007, Pepco’s contractual obligations under non-derivative fuel and power purchase contracts were $973.3 million in 2008, $733.8 million in 2009 to 2010, $125.6 million in 2011 to 2012, and $430.4 in 2013 and thereafter.
(11) 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, 2007, 2006 and 2005 were approximately $128.6 million, $114.4 million, and $114.6 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, 2007, 2006 and 2005 were approximately $25.7 million, $15.3 million and $11.6 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.
(b)
Included in other operation and maintenance.
As of December 31, 2007 and 2006, 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.
(12) 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 $33.4 million benefit ($20.0 million after-tax) from settlement of Mirant bankruptcy claims.
(b)
Includes $19.5 million benefit ($17.7 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 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, 2007 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, 2007.
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.
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, 2007 and December 31, 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007 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 8 to the financial statements, the Company changed its manner of accounting and reporting for uncertain tax positions in 2007.
PricewaterhouseCoopers LLP
Washington, DC
February 29, 2008
The accompanying Notes are an integral part of these Financial Statements.
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 operations 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
Provider of Last Resort service - before May 1, 2006
Standard Offer Service (SOS) - on and after May 1,
Maryland
SOS
Virginia
Default Service
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). On January 2, 2008, DPL, in two separate transactions, sold its Virginia electric distribution and default supply operations and substantially all of its Virginia transmission assets, in each case located on the eastern shore of Virginia, for an aggregate sale price of price of approximately $44.6 million, subject to closing adjustments. As a result of the transaction, DPL no longer has any service territory in the state of Virginia and has ceased to be regulated by the Virginia State Corporation Commission.
(2) SUMMARY OF 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 estimates used by DPL include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, fair value calculations (based on estimated market pricing) associated with derivative instruments, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings
and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims that are probable and 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. This resulted in lower depreciation expense of approximately $.3 million for the last six months of 2007.
During 2005, DPL recorded the impact of reductions in estimated unbilled revenue, primarily reflecting an increase in the estimated amount of power line losses (electricity lost in the process of its transmission and distribution to customers). This change in accounting estimate reduced net earnings for the year ended December 31, 2005 by approximately $1.0 million.
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 $49.8 million and $58.4 million as of December 31, 2007 and 2006, 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, the impact of which could be material. Revenues from other services are recognized when services are performed or products are delivered.
Revenues from non-regulated electricity and gas sales are included in “Electric” revenues and “Natural Gas” revenues, respectively. The 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.
Regulation of Power Delivery Operations
Certain aspects of DPL’s utility businesses are subject to regulation by the Delaware Public Service Commission (DPSC) and the MPSC, and, until the sale of its Virginia operations on January 2, 2008, was regulated by the Virginia State Corporation Commission (VSCC). The transmission and wholesale sale of electricity by DPL is regulated by FERC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC.
Based on the regulatory framework in which it has operated, DPL has historically applied, and in connection with its transmission and distribution business continues to apply, the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 (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. Should existing facts or circumstances change in the future to indicate that a regulatory asset is not probable of recovery, then the regulatory asset must be charged to earnings.
As part of the new electric service distribution base rates for DPL approved by the MPSC, effective June 16, 2007, the MPSC approved a bill stabilization adjustment mechanism (BSA) for retail customers. See Note 11 “Commitments and Contingencies - Regulatory and Other Matters - Rate Proceedings.” 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, 2007 is a regulatory asset and is included in the “Other” line item on the table of regulatory asset balances listed below.
The components of DPL’s regulatory asset balances at December 31, 2007 and 2006 are as follows:
The components of DPL’s regulatory liability balances at December 31, 2007 and 2006 are as follows:
A description for each category of regulatory assets and regulatory liabilities follows:
Deferred Energy Supply Costs: Primarily represents 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.
Deferred Recoverable 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 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 at DPL, which were recovered from February 1996 through October 2007 and earned a return.
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 to occur over an 18-month period beginning June 2007. The Maryland deferral will be recovered from participating customers at a rate per kilowatt-hour based on energy usage during the recovery period.
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, $40.5 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 and under-recovery of procurement, transmission and administration costs associated with Maryland and Delaware SOS.
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.
Asset Removal Costs: Represents DPL’s asset retirement obligation associated with removal costs accrued using public service commission approved depreciation techniques for transmission, distribution and general utility property.
Other: Includes over-recovery of procurement, transmission and administration costs associated with Maryland and Delaware SOS.
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 taxes recoverable in the future and is included in “regulatory assets” on the Balance Sheets. For additional information, see the discussion under “Regulation of Power Delivery Operations,” above.
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.
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 firm 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 DPSC, and are deferred under SFAS No. 71 until recovered. At December 31, 2007, there was a net deferred derivative payable of $13.1 million, offset by a $13.1 million regulatory asset. At December 31, 2006, there was a net deferred derivative payable of $27.3 million, offset by a $28.5 million regulatory asset.
Accounts Receivable and Allowance for Uncollectible Accounts
DPL’s accounts receivable balances primarily consist 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 uses the allowance method to account for uncollectible accounts receivable.
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 $.5 million, $.6 million, and $.9 million for the years ended December 31, 2007, 2006, and 2005, respectively.
DPL recorded amounts for the equity component of AFUDC of zero, $.6 million, and $.5 million for the years ended December 31, 2007, 2006 and 2005, respectively.
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.
Goodwill and Goodwill Impairment
Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. DPL’s goodwill balances at December 31, 2007 and 2006 of $8.0 million and $48.5 million, respectively, are primarily related to DPL’s acquisition of Conowingo Power Company in 1995. In addition, on July 19, 2007, the Maryland PSC issued an order which provided for the recovery of a portion of DPL’s goodwill through February 2018. As a
result of this order, $40.5 million in DPL goodwill has been transferred to a regulatory asset which will be amortized over that same period. 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 a reporting unit below its carrying amount.
The July 1, 2007 test indicated that none of DPL’s goodwill balance was impaired.
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.
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.
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 rates for 2007, 2006 and 2005 for DPL’s transmission and distribution system property were approximately 2.9%, 3.0%, and 3.1%, respectively.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, money market funds, and commercial paper 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
Restricted cash represents cash either held as collateral or pledged as collateral, and is restricted from use for general corporate purposes.
Asset Retirement Obligations
In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” and Financial Accounting Standards Board Interpretation No. 47, asset removal costs are recorded as regulatory liabilities. At December 31, 2007 and 2006, $234.2 million and $229.5 million, respectively, are reflected as regulatory liabilities in the accompanying Balance Sheets. Additionally, in 2005, DPL recorded immaterial conditional asset retirement obligations for underground storage tanks. Accretion for these asset retirement obligations has been recorded as a regulatory asset.
Other Non-Current Assets
The other assets balance principally consists of deferred compensation trust assets and unamortized debt expense.
Other Current Liabilities
The other current liabilities balance principally consists of customer deposits and accrued vacation liability.
Other Deferred Credits
The other deferred credits balance principally consists of miscellaneous deferred liabilities.
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 $117.6 million and $113.3 million of restricted retained earnings at December 31, 2007 and 2006, respectively.
Newly Adopted Accounting Standards
EITF Issue No. 06-3, “Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions”
On June 28, 2006, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 06-3, “Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions” (EITF 06-3). EITF 06-3 provides guidance on an entity’s disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity’s activities over a period of time are not within the scope of EITF 06-3. DPL implemented EITF 06-3 during the first quarter of 2007. Taxes included in DPL’s gross revenues were $13.3 million, $14.2 million and $14.1 million for the twelve months ended December 31, 2007, 2006 and 2005, respectively.
FSP AUG AIR-1, “Accounting for Planned Major Maintenance Activities”
On September 8, 2006, the FASB issued FSP American Institute of Certified Public Accountants Industry Audit Guide, Audits of Airlines--”Accounting for Planned Major Maintenance Activities” (FSP AUG AIR-1), which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods for all industries. FSP AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006 (year ended December 31, 2007 for DPL). Implementation of FSP AUG AIR-1 did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.
Recently Issued Accounting Standards, Not Yet Adopted
SFAS No. 157, “Fair Value Measurements”
In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of this Statement
will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the disclosures about fair value measurements.
The provisions of SFAS No. 157, as issued, are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (January 1, 2008 for DPL). On February 6, 2008, the FASB decided to issue final Staff Positions that will (i) defer 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) and (ii) remove certain leasing transactions from the scope of SFAS No. 157. The final Staff Positions will defer the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of the final Staff Positions. DPL has evaluated the impact of SFAS No. 157 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, cash flows, or footnote disclosure requirements.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115”
On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115” (SFAS No. 159) which permits entities to elect to measure eligible financial instruments at fair value. The objective of SFAS No. 159 is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of SFAS No. 159 will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the disclosures about fair value measurements.
SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.
SFAS No. 159 applies to the beginning of a reporting entity’s first fiscal year that begins after November 15, 2007 (January 1, 2008 for DPL), with early adoption permitted for an entity that has also elected to apply the provisions of SFAS No. 157, Fair Value Measurements. An entity is prohibited from retrospectively applying SFAS No. 159, unless it chooses early adoption. SFAS No. 159 also applies to eligible items existing at November 15, 2007 (or early adoption date). DPL has evaluated the impact of SFAS No. 159 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, cash flows, or footnote disclosure requirements.
SFAS No. 141(R), “Business Combinations - a replacement of FASB Statement No. 141”
On December 4, 2007, the FASB issued SFAS No. 141(R), “Business Combinations - a replacement of FASB Statement No. 141” (SFAS No. 141(R)) which replaces FASB Statement No. 141, “Business Combinations.” This Statement retains the fundamental requirements in Statement 141 that the acquisition method of accounting (which Statement 141 called the purchase method) be used for all business combinations and for an acquirer to be identified for each business combination.
SFAS No. 141(R) applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree). It does not apply to (i) the formation of a joint venture, (ii) the acquisition of an asset or a group of assets that does not constitute a business, (iii) a combination between entities or businesses under common control and (iv) a combination between not-for-profit organizations or the acquisition of a for-profit business by a not-for-profit organization.
SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for DPL). An entity may not apply it before that date.
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51”
On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (SFAS No. 160) which amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.
A noncontrolling interest, sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. The objective of SFAS No. 160 is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards that require (i) the ownership interests 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, (ii) the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income, (iii) changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently. A parent’s ownership interest in a subsidiary changes if the parent purchases additional ownership interests in its subsidiary or if the parent sells some of its ownership interests in its subsidiary. It also changes if the subsidiary reacquires some of its ownership interests or the subsidiary issues additional ownership interests. All of those transactions are economically similar, and this Statement requires that they be accounted for similarly, as equity transactions, (iv) when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary be initially measured at fair value. The gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any noncontrolling equity investment rather than the carrying amount of that retained investment and
(v) entities provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.
SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary.
SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009, for DPL). Earlier adoption is prohibited. SFAS No. 160 shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. DPL is currently evaluating the impact SFAS No. 160 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.
(3) 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.
(4) 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 $111.1 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, 2007 include $9.9 million in 2008, $9.4 million in 2009, $9.0 million in 2010, $8.4 million in 2011, $7.7 million in 2012 and $126.0 million after 2012.
Rental expense for operating leases, including the Merrill Creek Reservoir lease, was $10.3 million, $11.1 million and $11.7 million for the years ended December 31, 2007, 2006 and 2005, respectively.
(5) 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.
(6) PENSIONS AND OTHER POSTRETIREMENT BENEFITS
DPL accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. For 2007, 2006, and 2005, DPL’s allocated share of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings was approximately $4.3 million, $.7 million, and $(2.0) million, respectively. In 2007 and 2006, DPL made no contributions to the PHI Retirement Plan, and $8.0 million and $6.8 million, respectively to other postretirement benefit plans. At December 31, 2007 and 2006, DPL’s prepaid pension expense of $178.1 million and $171.8 million, and other postretirement benefit obligation of $4.5 million and $3.3 million, included in Other Deferred Credits, effectively represent assets and benefit obligations resulting from DPL’s participation in the Pepco Holdings benefit plan.
(7) DEBT
LONG-TERM DEBT
Long-term debt outstanding as of December 31, 2007 and 2006 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 are subject to mandatory tender on August 1, 2008.
The outstanding First Mortgage Bonds issued by DPL are secured by 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: $22.6 million in 2008, zero in 2009, $31.2 million in 2010, $34.5 million in 2011, zero in 2012, and $464.4 million thereafter.
DPL’s long-term debt is subject to certain covenants. DPL is in compliance with all requirements.
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, 2007 and 2006 is as follows.
Commercial Paper
DPL maintains an ongoing commercial paper program of up to $275 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 Potomac Electric Power Company (Pepco) and Atlantic City Electric Company (ACE).
DPL had $24.0 million of commercial paper outstanding at December 31, 2007 and $91.1 million of commercial paper outstanding at December 31, 2006. The weighted average interest rates for commercial paper issued during 2007 and 2006 were 5.35% and 5.30%, respectively. The weighted average maturity for commercial paper issued during 2007 and 2006 was four days and seven 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. The VRDB outstanding in 2007 and 2006 mature as follows: 2017 ($26.0 million), 2024 ($33.3 million), 2028 ($15.5 million), and 2029 ($30.0 million). The weighted average interest rate for VRDB was 3.87% during 2007 and 3.64% during 2006. Of the $104.8 in VRDB, $71.5 is collateralized with first mortgage bonds.
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 the 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 based on the prevailing prime rate or 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 made by the borrower at the time the credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower’s business, property, and results of operations or financial condition subsequent to the entry into the credit agreement is not a condition to the availability of credit under the facility. Among the covenants to which each of the companies is subject are (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 certain trust preferred securities and deferrable interest subordinated debt from the definition of total indebtedness (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the credit agreement. The agreement does not include any rating triggers.
(8) 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 Expense
FIN 48, “Accounting for Uncertainty in Income Taxes”
As disclosed in Note 2, “Summary of 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 $.1 million as an increase in retained earnings. Also upon adoption, DPL had $43.2 million of unrecognized tax benefits and $9.8 million of related accrued interest.
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
As of December 31, 2007, DPL had $7.6 million of accrued interest related to 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, 2007, 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 unrecognized tax benefits as an element of tax expense. For the year ended December 31, 2007, DPL recognized $1.3 million of interest expense and no penalties, net, as a component of tax expense.
Possible Changes to Unrecognized Benefits
Total unrecognized tax benefits that may change over the next twelve months include the matter of Mixed Service Costs. See discussion in Note 11, “Commitments and Contingencies -- IRS Mixed Service Cost Issue.”
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, 2007 and 2006.
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.
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.
(9) PREFERRED STOCK
The preferred stock amounts outstanding as of December 31, 2007 and 2006 are as follows:
(a)
On January 18, 2007, DPL redeemed all of the outstanding shares of its Redeemable Serial Preferred Stock, at prices ranging from 103% to 105% of par, in an aggregate amount of approximately $18.9 million.
(10) FAIR VALUES OF FINANCIAL INSTRUMENTS
The estimated fair values of DPL’s financial instruments at December 31, 2007 and 2006 are shown below.
The methods and assumptions below were used to estimate, at December 31, 2007 and 2006, the fair value of each class of financial instruments shown above for which it is practicable to estimate a value.
The fair values of derivative instruments were derived based on quoted market prices.
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.
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.
The carrying amounts of all other financial instruments in DPL’s accompanying financial statements approximate fair value.
(11) COMMITMENTS AND CONTINGENCIES
Rate Proceedings
Delaware
On September 4, 2007, DPL submitted its 2007 Gas Cost Rate (GCR) filing to the DPSC. The GCR permits DPL to recover its gas procurement costs through customer rates. On September 18, 2007, the DPSC issued an initial order approving a 5.7% decrease in the level of the GCR, which became effective November 1, 2007, subject to refund and pending final DPSC approval after evidentiary hearings.
Maryland
In electric service distribution base rate cases it filed in Maryland, and pending in 2007, DPL proposed the adoption of a BSA for retail customers. 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 will increase rates if actual distribution revenues fall below the level approved by the MPSC and will decrease rates if actual distribution revenues are above the approved level. The result will be that, over time, DPL would collect 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.
On July 19, 2007, the MPSC issued an order in the electric service distribution rate case filed by DPL, which included approval of a BSA. The order approved an annual increase in distribution rates of approximately $14.9 million (including a decrease in annual depreciation expense of approximately $.9 million). The approved distribution rate reflects an ROE of 10.0%. The order provided that the rate increases are effective as of June 16, 2007, and will remain in effect for an initial period of nine months from the date of the order (or until April 19, 2008). These rates are subject to a Phase II proceeding in which the MPSC will consider 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 is required. Hearings for the Phase II proceeding are scheduled for mid-March 2008.
Default Electricity Supply Proceedings
Virginia
In June 2007, the Virginia State Corporation Commission (VSCC) denied DPL’s request for an increase in its rates for Default Service for the period July 1, 2007 to May 31, 2008. DPL appealed in both state and federal courts. Those appeals have been dismissed in light of the closing of the sale of DPL's Virginia electric operations as described below under the heading “DPL Sale of Virginia Operations.”
DPL Sale of Virginia Operations
On January 2, 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price of approximately $45.2 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5.4 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 are purchasing (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date. These sales are expected to result in an immaterial financial gain to DPL that will be recorded in the first quarter of 2008.
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.
Cambridge, Maryland Site. In July 2004, DPL entered into an administrative consent order with the Maryland Department of the Environment (MDE) to perform a Remedial Investigation/Feasibility Study (RI/FS) to further identify the extent of soil, sediment and ground and surface water contamination related to former manufactured gas plant (MGP) operations at a Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The MDE has approved the RI and DPL submitted a final FS to MDE on February 15, 2007. No further MDE action is required with respect to the final FS. The costs of cleanup (as determined by the RI/FS and subsequent negotiations with MDE) are anticipated to be approximately $3.8 million. The remedial action to be taken by DPL will include dredging activities within Cambridge Creek, which are expected to commence in March 2008, and soil excavation on DPL’s and adjacent property as early as August 2008. The final cleanup costs will include protective measures to control contaminant migration during the dredging activities and improvements to the existing shoreline.
Carolina Transformer Site. In August 2006, the U.S. Environmental Protection Agency (EPA) notified DPL that it had been identified as an entity that sent PCB-laden oil to be disposed at the Carolina Transformer site in Fayetteville, North Carolina. The EPA notification stated that, on this basis, DPL may be a potentially responsible party (PRP). In December 2007, DPL agreed to enter into a settlement agreement with EPA and the PRP group at the Carolina Transformer site. Under the terms of the settlement, (i) DPL will pay $162,000 to EPA to resolve any liability that it might have at the site, (ii) EPA covenants not to sue or bring administrative action against DPL for response costs at the site, (iii) other PRP group members
release all rights for cost recovery or contribution claims they may have against DPL, and (iv) DPL releases all rights for cost recovery or contribution claims that they may have against other parties settling with EPA. The consent decree is expected to be filed with the U.S. District Court in North Carolina in the second quarter of 2008.
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, primarily attributable to its 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 the proposed regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believes will 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 is 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 Appeals Office.
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. However, if the IRS is successful in requiring DPL to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management’s estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006. It is reasonably possible that PHI’s unrecognized tax benefits related to this issue will significantly decrease in the next 12 months as a result of a settlement with the IRS.
Contractual Obligations
As of December 31, 2007, DPL’s contractual obligations under non-derivative fuel and power purchase contracts were $628.4 million in 2008, $478.5 million in 2009 to 2010, $43.9 million in 2011 to 2012, and zero in 2013 and thereafter.
(12) 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, 2007, 2006 and 2005 were $107.6 million, $100.5 million, and $98.4 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.
(b) Included in electric revenue.
(c) Included in gas revenue.
(d) Included in gas purchased.
As of December 31, 2007 and 2006, DPL had the following balances on its balance sheets due (to)/from related parties:
(13) 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 charge to income tax expense of $1.2 million and $2.0 million, respectively, related to analysis of deferred tax accounts.
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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, 2007 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, 2007.
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.
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, 2007 and December 31, 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 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 8 to the consolidated financial statements, the Company changed its manner of accounting and reporting for uncertain tax positions in 2007.
PricewaterhouseCoopers LLP
Washington, DC
February 29, 2008
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. Additionally, 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.
(2) SUMMARY OF 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 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 estimates used by ACE 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 that are probable and reasonably estimable.
Change in Accounting Estimates
During 2005, ACE recorded the impact of a reduction in estimated unbilled revenue, primarily reflecting an increase in the estimated amount of power line losses (electricity lost in the process of its transmission and distribution to customers). This change in accounting estimate reduced net earnings for the year ended December 31, 2005 by approximately $6.4 million.
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 $38.1 million and $31.8 million as of December 31, 2007 and December 31, 2006, 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, the impact of which could be material. Revenues from other services are recognized when services are performed or products are delivered.
The 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.
Regulation of Power Delivery Operations
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 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. Should existing facts or circumstances change in the future to indicate that a regulatory asset is not probable of recovery, then the regulatory asset must be charged to earnings.
The components of ACE’s regulatory asset balances at December 31, 2007 and 2006 are as follows:
The components of ACE’s regulatory liability balances at December 31, 2007 and 2006 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.
Deferred Recoverable 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 will be amortized to interest expense during the authorized rate recovery period. A return is received on these deferrals.
Deferred Other Postretirement Benefit Costs: Represents the non-cash portion of other postretirement benefit costs deferred by ACE during 1993 through 1997. This cost is being recovered over a 15-year period that began on January 1, 1998. There is no return 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.
Asset Retirement Cost: During the first quarter of 2006, ACE recorded an asset retirement obligation of $60 million for B.L. England plant demolition and environmental remediation costs; the amortization was to be amortized over a two-year period. The cumulative amortization of $33.0 million at December 31, 2006, was recorded as a regulatory asset -- “Asset Retirement Cost.” As discussed in Note (11) Commitments and Contingencies, in the first quarter of 2007, ACE completed the sale of the B.L. England generating facility, and the asset retirement obligation and asset retirement cost were reversed.
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.
Deferred Energy Supply Costs: The regulatory liability balances of $240.9 million and $164.9 million for the years ended December 31, 2007 and 2006, respectively, primarily represent deferred costs relating to a net over-recovery by ACE connected with the provision of BGS and other restructuring related costs incurred by ACE.
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.
Gain from Sale of Keystone and Conemaugh: In the third quarter of 2006, ACE completed the sale of its interests in the Keystone and Conemaugh generating facilities for $175.4 million (after giving effect to post-closing adjustments). The total gain recognized on this sale, net of adjustments, came to $131.4 million. Approximately $81.3 million of the net gain from the sale offset the remaining regulatory asset balance, which ACE has been recovering in rates, and $49.8 million of the net gain is being returned to ratepayers over a 33-month period as a credit on their bills, which began during the October 2006 billing period. The balance to be repaid to customers is $30.7 million as of December 31, 2007.
Gain from Sale of B.L. England: In the first quarter of 2007, ACE completed the sale of the B.L. England generating facility. Net proceeds from the sale of the plant and monetization of the emission allowance credits will be credited to ACE’s ratepayers in accordance with the requirements of the New Jersey Electric Discount and Energy Competition Act (EDECA) and NJBPU orders.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, money market funds, and commercial paper 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
Restricted cash represents cash either held as collateral or pledged as collateral, and is restricted from use for general corporate purposes.
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 $1.8 million, $.8 million and $.8 million for the years ended December 31, 2007, 2006 and 2005, respectively.
ACE recorded amounts for the equity component of AFUDC of $1.1 million, $.7 million and $1.6 million for the years ended December 31, 2007, 2006 and 2005, respectively.
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.
Emission Allowances
Emission allowances for sulfur dioxide (SO2) and nitrous oxide (NOx) are allocated to generation owners by the U.S. Environmental Protection Agency (EPA) based on federal programs designed to regulate the emissions from power plants. EPA allotments have no cost basis to the generation owners. Depending on the run-time of a generator in a given year, and other pollution controls it may have, the unit may need additional allowances above its allocation, or it may have excess allowances that it does not need. Allowances are traded among companies in an over-the-counter market, which allows companies to purchase additional allowances to avoid incurring penalties for noncompliance with applicable emissions standards or to sell excess allowances.
ACE accounts for emission allowances as inventory in the balance sheet line item “Fuel, materials and supplies - at average cost.” Allowances from EPA allocation are added to current inventory each year at a zero basis. Additional purchased allowances are recorded at cost. 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, 2007 and 2006, the book value of emission allowances was $.1 million and $.4 million, respectively. ACE has established a committee to ensure its plants are in compliance with emissions regulations and that its power plants have the required number of allowances on hand.
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 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. For additional information, see the discussion under “Regulation of Power Delivery Operations” above.
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.
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 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.
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.
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.
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 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 2007, 2006 and 2005 for ACE’s transmission and distribution system property were 2.9%, 2.9% and 3.1%, respectively, and for its generation system property were zero, .3%, and 2.4%, respectively.
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), the costs associated with planned major maintenance activities related to generation facilities are accounted for on an as incurred basis.
Accounts Receivable and Allowance for Uncollectible Accounts
ACE’s accounts receivable balances primarily consist of customer accounts receivable, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded). ACE uses the allowance method to account for uncollectible accounts receivable.
FIN 46R, “Consolidation of Variable Interest Entities”
ACE has power purchase agreements (PPAs) with a number of entities, including three contracts between ACE and unaffiliated non-utility generators (NUGs). 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, ACE continued, during 2007, 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 power purchase activities with the counterparties to the NUGs for the years ended December 31, 2007, 2006 and 2005, were approximately $327 million, $324 million and $327 million, respectively, of which $292 million, $288 million and $289 million, respectively, related to power purchases under the NUGs. ACE does not have exposure to loss under the PPA agreements since cost recovery will be achieved from its customers through regulated rates.
Prepaid Expenses and Other
The prepaid expenses and other balance primarily consists of prepayments and the current portion of deferred income tax assets.
Other Non-Current Assets
The other assets balance principally consists of deferred compensation trust assets and unamortized debt expense.
Other Current Liabilities
The other current liability balance principally consists of customer deposits, accrued vacation liability and other miscellaneous liabilities.
Other Deferred Credits
The other deferred credits balance principally consists of miscellaneous deferred liabilities.
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 $87.9 million and $97.9 million of restricted retained earnings at December 31, 2007 and 2006, respectively.
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 (13), “Discontinued Operations,” herein.
Newly Adopted Accounting Standards
EITF Issue No. 06-3, “Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions”
On June 28, 2006, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 06-3, “Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions” (EITF 06-3). EITF 06-3 provides guidance on an entity’s disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity’s activities over a period of time are not within the scope of EITF 06-3. ACE implemented EITF 06-3 during the first quarter of 2007. Taxes included in ACE’s gross revenues were $22.9 million, $22.3 million and $22.6 million for the twelve months ended December 31, 2007, 2006 and 2005, respectively.
FSP AUG AIR-1, “Accounting for Planned Major Maintenance Activities”
On September 8, 2006, the FASB issued FSP AUG AIR-1 which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods for all industries. FSP AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006 (year ended December 31, 2007 for ACE). Implementation of FSP AUG AIR-1 did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.
Recently Issued Accounting Standards, Not Yet Adopted
SFAS No. 157, “Fair Value Measurements”
In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of this Statement will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the disclosures about fair value measurements.
The provisions of SFAS No. 157, as issued, are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (January 1, 2008 for ACE). On February 6, 2008, the FASB decided to issue final Staff Positions that will (i) defer 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) and (ii) remove certain leasing transactions from the scope of SFAS No. 157. The final Staff Positions will defer the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of the final Staff Positions. ACE has evaluated the impact of SFAS No. 157 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, cash flows, or footnote disclosure requirements.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115”
On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115” (SFAS No. 159) which permits entities to elect to measure eligible financial instruments at fair value. The objective of SFAS No. 159 is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of SFAS No. 159 will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the disclosures about fair value measurements.
SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.
SFAS No. 159 applies to the beginning of a reporting entity’s first fiscal year that begins after November 15, 2007 (January 1, 2008 for ACE), with early adoption permitted for an entity that has also elected to apply the provisions of SFAS No. 157, Fair Value Measurements. An entity is prohibited from retrospectively applying SFAS No. 159, unless it chooses early adoption. SFAS No. 159 also applies to eligible items existing at November 15, 2007 (or early adoption date). ACE has evaluated the impact of SFAS No. 159 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, cash flows, or footnote disclosure requirements.
SFAS No. 141(R), “Business Combinations - a replacement of FASB Statement No. 141”
On December 4, 2007, the FASB issued SFAS No. 141(R), “Business Combinations - a replacement of FASB Statement No. 141” (SFAS No. 141(R)) which replaces FASB Statement No. 141, “Business Combinations.” This Statement retains the fundamental requirements in Statement 141 that the acquisition method of accounting (which Statement 141 called the purchase method) be used for all business combinations and for an acquirer to be identified for each business combination.
SFAS No. 141(R) applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree). It does not apply to (i) the formation of a joint venture, (ii) the acquisition of an asset or a group of assets that does not constitute a business, (iii) a combination between entities or businesses under common control and (iv) a combination between not-for-profit organizations or the acquisition of a for-profit business by a not-for-profit organization.
SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for ACE). An entity may not apply it before that date.
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51”
On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (SFAS No. 160) which amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.
A noncontrolling interest, sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. The objective of SFAS No. 160 is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards that require (i) the ownership interests 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, (ii) the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income, (iii) changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently. A parent’s ownership interest in a subsidiary changes if the parent purchases additional ownership interests in its subsidiary or if the parent sells some of its ownership interests in its subsidiary. It also changes if the subsidiary reacquires some of its ownership interests or the subsidiary issues additional ownership interests. All of those transactions are economically similar, and this Statement requires that they be accounted for similarly, as equity transactions, (iv) when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary be initially measured at fair value. The gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any noncontrolling equity investment rather than the carrying amount of that retained investment and (v) entities provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.
SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary.
SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009, for ACE). Earlier adoption is prohibited. SFAS No. 160 shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. ACE is currently evaluating the impact SFAS No. 160 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.
(3) 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.
(4) LEASING ACTIVITIES
ACE leases certain types of property and equipment for use in its operations. Rental expense for operating leases was $9.9 million, $9.6 million and $11.0 million for the years ended December 31, 2007, 2006 and 2005, respectively.
Total future minimum operating lease payments for ACE as of December 31, 2007 include $3.0 million in 2008, $2.7 million in 2009, $2.2 million in 2010, $1.7 million in 2011, $1.1 million in 2012 and $6.2 million after 2012.
(5) 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, 2007 is shown below.
Asset Sales
As discussed in Note (2), Summary of Significant Accounting Policies, in the third quarter of 2006, ACE completed the sale of its interests in the Keystone and Conemaugh generating facilities for approximately $175.4 million (after giving effect to post-closing adjustments) and in the first quarter of 2007, ACE completed the sale of the B.L. England generating facility for a price of $9.0 million.
(6) PENSIONS AND OTHER POSTRETIREMENT BENEFITS
ACE accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. For 2007, 2006, and 2005, ACE’s allocated share of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings was approximately $11.0 million, $14.3 million, and $16.9 million, respectively. In 2007 and 2006, ACE made no contributions to the PHI Retirement Plan, and $6.8 million and $6.6 million, respectively to other postretirement benefit plans. At December 31, 2007 and 2006, ACE’s prepaid pension expense of $8.5 million and $11.7 million, and other postretirement benefit obligation of $38.0 million and $27.1 million, effectively represent assets and benefit obligations resulting from ACE’s participation in the Pepco Holdings benefit plan.
(7) DEBT
LONG-TERM DEBT
Long-term debt outstanding as of December 31, 2007 and 2006 is presented below.
(a)
Represents a series of First Mortgage Bonds issued by ACE as collateral for an outstanding series of senior notes 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 tax-exempt bonds are identical to the terms of the collateral First Mortgage Bonds by which it is secured. Payments of principal and interest on a series of senior notes or 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 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.
The outstanding First Mortgage Bonds issued by ACE are secured by a lien on substantially all of ACE’s property, plant and equipment.
ACE Funding was established in 2001 solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable transition bond charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond charges collected from ACE’s customers are not available to creditors of ACE. The Transition Bonds are obligations of ACE Funding and are non-recourse to ACE.
The aggregate principal amount of long-term debt including Transition Bonds outstanding at December 31, 2007, that will mature in each of 2008 through 2012 and thereafter is as follows: $81 million in 2008, $32.2 million in 2009, $34.7 million in 2010, $35.4 million in 2011, $37.3 million in 2012, and $710.2 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, 2007 and 2006 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 Potomac Electric Power Company (Pepco) and Delmarva Power & Light Company (DPL).
ACE had $29.1 million of commercial paper outstanding at December 31, 2007 and $1.2 million of commercial paper outstanding at December 31, 2006. The weighted average interest rates for commercial paper issued during 2007 and 2006 were 5.45% and 4.79%, respectively.
The weighted average maturity for commercial paper issued during 2007 and 2006 was three days and four days.
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 VRDBs as a source of long-term financing. The VRDB outstanding in 2007 and 2006 mature as follows: 2014 ($18.2 million) and 2017 ($4.4 million). The weighted average interest rate for VRDB was 3.59% and 3.39% during 2007 and 2006, 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 the 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 based on the prevailing prime rate or 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 made by the borrower at the time the credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower’s business, property, and results of operations or financial condition subsequent to the entry into the credit agreement is not a condition to the availability of credit under the facility. Among the covenants to which each of the companies is subject are (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 certain trust preferred securities and deferrable interest subordinated debt from the definition of total indebtedness (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the credit agreement. The agreement does not include any rating triggers.
(8) 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
Reconciliation of Consolidated Income Tax Expense
FIN 48, “Accounting for Uncertainty in Income Taxes”
As disclosed in Note 2, “Summary of 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 $28.4 million of unrecognized tax benefits and $3.4 million of related accrued interest.
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
As of December 31, 2007, ACE had $2.5 million of accrued interest related to 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, 2007, included $3.6 million that, if recognized, would lower the effective tax rate.
Interest and Penalties
ACE recognizes interest and penalties relating to its unrecognized tax benefits as an element of tax expense. For the year ended December 31, 2007, ACE recognized $.9 million of interest income and penalties, net, as a component of tax expense.
Possible Changes to Unrecognized Benefits
Total unrecognized tax benefits that may change over the next twelve months include the matter of Mixed Service Costs. See discussion in Note 11, “Commitments and Contingencies -- IRS Mixed Service Cost Issue.”
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.
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, 2007 and 2006.
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.
(9) PREFERRED STOCK
The preferred stock amounts outstanding as of December 31, 2007 and 2006 are as follows:
(10) FAIR VALUES OF FINANCIAL INSTRUMENTS
The estimated fair values of ACE’s financial instruments at December 31, 2007 and 2006 are shown below.
The methods and assumptions below were used to estimate, at December 31, 2007 and 2006, the fair value of each class of financial instruments shown above for which it is practicable to estimate a value.
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.
The carrying amounts of all other financial instruments in ACE’s accompanying consolidated financial statements approximate fair value.
(11) COMMITMENTS AND CONTINGENCIES
Rate Proceedings
On June 1, 2007, ACE filed with the NJBPU an application for permission to decrease the Non Utility Generation Charge (NGC) and increase components of its Societal Benefits Charge (SBC) to be collected from customers for the period October 1, 2007 through September 30, 2008. The proposed changes are designed to effect a true-up of the actual and estimated costs and revenues collected through the current NGC and SBC rates through September 30, 2007 and, in the case of the SBC, forecasted costs and revenues for the period October 1, 2007 through September 30, 2008.
As of December 31, 2007, the NGC, which is intended primarily to recover the above-market component of payments made by ACE under non-utility generation contracts and stranded costs associated with those commitments, had an over-recovery balance of $224.3 million. The filing proposed that the estimated NGC balance as of September 30, 2007 in the amount of $216.2 million, including interest, be amortized and returned to ACE customers over a four-year period, beginning October 1, 2007.
As of December 31, 2007, the SBC, which is intended to allow ACE to recover certain costs involved with various NJBPU-mandated social programs, had an under-recovery of approximately $20.9 million, primarily due to increased costs associated with funding the New Jersey Clean Energy Program. In addition, ACE has requested an increase to the SBC to reflect the funding levels approved by the NJBPU of $20.4 million for the period October 1, 2007 through September 30, 2008, bringing to $40 million the total recovery requested for the period October 1, 2007 to September 30, 2008 (based upon actual data through August 2007).
The net impact of the proposed adjustments to the NGC and the SBC, including associated changes in sales and use tax, is an overall rate decrease of approximately $129.9 million for the period October 1, 2007 through September 30, 2008 (based upon actual data through August 2007). The proposed adjustments and the corresponding changes in customer rates are subject to the approval of the NJBPU. If approved and implemented, ACE anticipates that the revised rates will remain in effect until September 30, 2008, subject to an annual true-up and change each year thereafter. The proposed adjustments and the corresponding changes in customer rates remain under review by the NJBPU and have not yet been implemented.
ACE Restructuring Deferral Proceeding
Pursuant to orders issued by the NJBPU under EDECA, beginning August 1, 1999, ACE was obligated to provide BGS to retail electricity customers in its service territory who did not elect to purchase electricity from a competitive supplier. For the period August 1, 1999 through July 31, 2003, ACE’s aggregate costs that it was allowed to recover from customers exceeded its aggregate revenues from supplying BGS. These under-recovered costs were partially offset by a $59.3 million deferred energy cost liability existing as of July 31, 1999 (LEAC Liability) related to ACE’s Levelized Energy Adjustment Clause and ACE’s Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance of under-recovered costs.
In August 2002, ACE filed a petition with the NJBPU for the recovery of approximately $176.4 million in actual and projected deferred costs relating to the provision of BGS and other restructuring related costs incurred by ACE over the four-year period August 1, 1999 through July 31, 2003, net of the $59.3 million offset for the LEAC Liability. The petition also requested that ACE’s rates be reset as of August 1, 2003 so that there would be no under-recovery of costs embedded in the rates on or after that date. The increase sought represented an overall 8.4% annual increase in electric rates.
In July 2004, the NJBPU issued a final order in the restructuring deferral proceeding confirming a July 2003 summary order, which (i) permitted ACE to begin collecting a portion of the deferred costs and reset rates to recover on-going costs incurred as a result of EDECA, (ii) approved the recovery of $125 million of the deferred balance over a ten-year amortization period beginning August 1, 2003, (iii) transferred to ACE’s then pending base rate case for further consideration approximately $25.4 million of the deferred balance (the base rate case ended in a settlement approved by the NJBPU in May 2005, the result of which is that any net rate impact from the deferral account recoveries and credits in future years will depend in part on whether rates associated with other deferred accounts considered in the case continue to generate over-collections relative to costs), and (iv) estimated the overall deferral balance as of July 31, 2003 at $195.0 million, of which $44.6 million was disallowed recovery by ACE. Although ACE believes the record does not justify the level of disallowance imposed by the NJBPU in the final order, the $44.6 million of disallowed incurred costs were reserved during the years 1999 through 2003 (primarily 2003) through charges to earnings, primarily in the operating expense line item “deferred electric service costs,” with a corresponding reduction in the regulatory asset balance sheet account. In 2005, an additional $1.2 million in interest on the disallowed amount was identified and reserved by ACE. In August 2004, ACE filed a notice of appeal with respect to the July 2004 final order with the Appellate Division of the Superior Court of New Jersey (the Appellate Division), which hears appeals of the decisions of New Jersey administrative agencies, including the NJBPU. On August 9, 2007, the Appellate Division, citing deference to the factual and policy findings of the NJBPU, affirmed the NJBPU’s decision in its entirety, rejecting challenges from ACE and the Division of Rate Counsel. On September 10, 2007, ACE filed an application for certification to the New Jersey Supreme Court. On January 15, 2008, the New Jersey Supreme Court denied ACE’s application for certification. Because the full amount at issue in this proceeding was previously reserved by ACE, there will be no further financial statement impact to ACE.
Divestiture Case
In connection with the divestiture by ACE of its nuclear generating assets, the NJBPU in July 2000 preliminarily determined that the amount of stranded costs associated with the divested assets that ACE could recover from ratepayers should be reduced by approximately $94.8 million, consisting of $54.1 million of accumulated deferred federal income taxes (ADFIT) associated with accelerated depreciation on the divested nuclear assets, and $40.7 million of current tax loss from selling the assets at a price below the tax basis.
The $54.1 million in deferred taxes associated with the divested assets’ accelerated depreciation, however, is subject to the normalization rules. Due to uncertainty under federal tax law regarding whether the sharing of federal income tax benefits associated with the divested assets, including ADFIT related to accelerated depreciation, with ACE’s customers would violate the normalization rules, ACE submitted a request to the Internal Revenue Service (IRS) for a Private Letter Ruling (PLR) to clarify the applicable law. The NJBPU delayed its final determination of the amount of recoverable stranded costs until after the receipt of the PLR.
On May 25, 2006, the IRS issued the PLR in which it stated that returning to ratepayers any of the unamortized ADFIT attributable to accelerated depreciation on the divested assets after the sale of the assets by means of a reduction of the amount of recoverable stranded costs would violate the normalization rules.
On June 9, 2006, ACE submitted a letter to the NJBPU, requesting that the NJBPU conduct proceedings to finalize the determination of the stranded costs associated with the sale of ACE’s nuclear assets in accordance with the PLR. In the absence of an NJBPU action regarding ACE’s request, on June 22, 2007, ACE filed a motion requesting that the NJBPU issue an order finalizing the determination of such stranded costs in accordance with the PLR. On October 24, 2007, the NJBPU approved a stipulation resolving the ADFIT issue and issued a clarifying order, which concludes that the $94.8 million in stranded cost reduction, including the $54.1 million in ADFIT, does not violate the IRS normalization rules. In explaining this result, the NJBPU stated that (i) its earlier orders determining ACE’s recoverable stranded costs “net of tax” did not cause ADFIT associated with certain divested nuclear assets to reduce stranded costs otherwise recoverable from ACE’s ratepayers, and (ii) because the Market Transition Charge-Tax component of the stranded cost recovery was intended by the NJBPU to gross-up “net of tax” stranded costs, thereby ensuring and establishing that the ADFIT balance was not flowed through to ratepayers, the normalization rules were not violated.
ACE Sale of B.L. England Generating Facility
On February 8, 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, for which it received proceeds of approximately $9 million. At the time of the sale, RC Cape May and ACE agreed to submit to arbitration the issue of whether RC Cape May, under the terms of the purchase agreement, must pay to ACE an additional $3.1 million as part of the purchase price. On February 26, 2008, the arbitrators issued a decision awarding $3.1 million to ACE, plus interest, attorneys’ fees and costs, for a total award of approximately $4.2 million.
On July 18, 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement. 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. In addition, RC Cape May has asserted a claim for indemnification from ACE in the amount of $25 million if the TSA is held not to be enforceable against Citgo. While ACE believes that it has defenses to the indemnification under the terms of the purchase agreement, 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 sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. ACE anticipates that approximately $9 million to $10 million of additional regulatory assets related to B.L. England may, subject to NJBPU approval, be eligible for recovery as stranded costs. Approximately $47 million in emission allowance credits associated with B. L. England were monetized for the benefit of ACE’s ratepayers pursuant to the NJBPU order approving the sale. Net proceeds from the sale of the plant and monetization of the emission allowance credits, estimated to be $36.1 million as of December 31, 2007, will be credited to ACE’s ratepayers in accordance with the requirements of EDECA and NJBPU orders. The appropriate mechanism for crediting the net proceeds from the sale of the plant and the monetized emission allowance credits to ratepayers is being determined in a proceeding that is currently pending before the NJBPU.
Environmental Litigation
ACE is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. ACE may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. Although penalties assessed for violations of environmental laws and regulations are not recoverable from ACE’s customers, environmental clean-up costs incurred by ACE would be included in its cost of service for ratemaking purposes.
Delilah Road Landfill Site. In November 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 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 EPA’s costs 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) and in October 2007, EPA and the PRP group entered into a tolling agreement to permit the parties sufficient time to execute a final settlement agreement. This settlement agreement 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. 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.
Frontier Chemical Site. On June 29, 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 the 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.
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, primarily attributable to its 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 the proposed regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believes will be acceptable to the IRS.
At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which is 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.
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. However, if the IRS is successful in requiring ACE to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management’s estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006. It is reasonably possible that PHI’s unrecognized tax benefits related to this issue will significantly decrease in the next 12 months as a result of a settlement with the IRS.
Contractual Obligations
As of December 31, 2007, ACE’s contractual obligations under non-derivative fuel and power purchase contracts (excluding BGS supplier load commitments) were $281.7 million in 2008, $548.0 million in 2009 to 2010, $455.4 million in 2011 to 2012, and $2,656.6 million in 2013 and thereafter.
(12) 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, 2007, 2006 and 2005 were $81.2 million, $79.3 million and $82.2 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.
(b)
Included in other operation and maintenance.
As of December 31, 2007 and 2006, ACE had the following balances due (to)/from related parties:
(13) DISCONTINUED OPERATIONS
As discussed in Note (11), “Commitments and Contingencies,” herein, on February 8, 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, 2006 and 2005. In September 2006, ACE sold its interests in the Keystone and Conemaugh generating facilities, which for the years ended December 31, 2006 and 2005, are also reflected as “discontinued operations.”
The following table summarizes information related to the discontinued operations presentation (millions of dollars):
(14) EXTRAORDINARY ITEMS
On April 19, 2005, ACE, the staff of the NJBPU, the New Jersey Ratepayer Advocate, and active intervenor parties agreed on a settlement in ACE’s electric distribution rate case. As a result of this settlement, ACE reversed $15.2 million in accruals related to certain deferred costs that are now deemed recoverable. The after-tax credit to income of $9.0 million is classified as an extraordinary gain in the 2005 financial statements since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.
(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, 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 adjustment related to timing of recognition of certain operating expenses which were overstated by $4.8 million in the fourth quarter and understated by $1.2 million and $3.6 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, 2007, 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 Annual Report on Internal Control over Financial Reporting” in Part II, Item 8 of this Form 10-K.
Attestation Report of the Registered Public Accounting Firm
See “Report of Independent Registered Public Accounting Firm” in Part II, Item 8 of this Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2007, 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, 2007, 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 Annual Report on Internal Control over Financial Reporting” in Part II, Item 8 of this Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2007, 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 and 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, 2007, 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 Annual Report on Internal Control over Financial Reporting” in Part II, Item 8 of this Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2007, 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, 2007, 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 Annual Report on Internal Control over Financial Reporting” in Part II, Item 8 of this Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2007, 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.
Other than as set forth below, the information required by this Item 10 with regard to PHI is incorporated herein by reference to PHI’s definitive proxy statement for the 2008 Annual Meeting of Shareholders to be filed with the SEC on or about March 27, 2008 (excluding the information under the caption “Audit Committee Report”).
Executive Officers of PHI
The names of the executive officers of PHI and their ages and the positions they held as of February 22, 2008 are set forth in the following table. Their business experience during the past five years is set forth in the footnotes to the following table.
PEPCO HOLDINGS
Name
Age
Office and
Length of Service
Dennis R. Wraase
Chairman of the Board, President and Chief Executive Officer
5/04 - Present (1)
William T. Torgerson
Vice Chairman and General Counsel
6/03 - Present (2)
Joseph M. Rigby
Executive Vice President and Chief Operating Officer
9/07 - Present (3)
Paul H. Barry
Senior Vice President and Chief Financial Officer
9/07 - Present (4)
Beverly L. Perry
Senior Vice President
10/02 - Present
Ronald K. Clark
Vice President and Controller
8/05 - Present (5)
John U. Huffman
President - 6/06 - Present
and Chief Operating Officer, Pepco Energy Services, Inc. - 4/06 - Present (6)
David M. Velazquez
President - 6/06 - Present
and Chief Executive Officer, Conectiv Energy Holding Company - 1/07 - Present (7)
(1)
Mr. Wraase was President and Chief Operating Officer of PHI from August 2002 until June 2003. Mr. Wraase has been Chairman of Pepco since May 2004 and was Chief Executive Officer from August 2002 until October 2005. Since May 2004, he has also been Chairman of DPL and ACE.
(2)
Mr. Torgerson was Executive Vice President and General Counsel of PHI from August 2002 until June 2003.
(3)
Mr. Rigby was Senior Vice President of PHI from August 2002 until September 2007 and was 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.
(4)
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.
(5)
Mr. Clark has been employed by PHI since June 2005 and has also served as Vice President and Controller of Pepco and DPL and Controller of ACE since August 2005. From July 2004 until June 2005, he was Vice President, Financial Reporting and Policy for MCI, Inc., a telecommunications company not affiliated with PHI. From June 2002 until December 2003, Mr. Clark served as Vice President, Controller and Chief Accounting Officer of Allegheny Energy, Inc., an energy company not affiliated with PHI.
(6)
Since June 2003, Mr. Huffman has been employed by Pepco Energy Services in the following capacities: (a) Chief Operating Officer from April 2006 to June 2006, (b) Senior Vice President, February 2005 to March 2006 and (c) Vice President from June 2003 to February 2005. From June 2000 to May 2003, Mr. Huffman was President and Chief Executive Officer of ACN Energy, Inc, a retail electricity and natural gas provider which is not affiliated with PHI.
(7)
Mr. Velazquez served as 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.
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 information required by this Item 11 with regard to PHI is incorporated herein by reference to PHI’s definitive proxy statement for the 2008 Annual Meeting of Shareholders to be filed with the SEC on or about March 27, 2008 (excluding the information under the caption “Compensation 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.
Other than as set forth below, the information required by this Item 12 with regard to PHI is incorporated herein by reference to PHI’s definitive proxy statement for the 2008 Annual Meeting of Shareholders to be filed with the SEC on or about March 27, 2008.
The following table provides information as of December 31, 2007, 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, 2007, options to purchase an aggregate of 532,635 shares of PHI common stock, having a weighted average exercise price of $22.3443, were outstanding.
(c)
On January 1, 2005, the PHI Non-Management Directors Compensation Plan (the Directors Compensation Plan) became effective, pursuant to which 500,000 shares of PHI common stock became available for future issuance. Under the Directors Compensation 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 Directors Compensation 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 required by this Item 13 with regard to PHI is incorporated herein by reference to PHI’s definitive proxy statement for the 2008 Annual Meeting of Shareholders to be filed with the SEC on or about March 27, 2008.
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 ACCOUNTING 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 the Company and its subsidiary reporting companies for the 2007 and 2006 fiscal years, reviews of the financial statements included in the 2007 and 2006 Forms 10-Q of the Company and its subsidiary reporting companies, reviews of public filings, comfort letters and other attest services were $6,074,408 and $5,589,719, respectively. The amount for 2006 includes $74,592 for the 2006 audit that was billed after the 2006 amount was disclosed in Pepco Holdings’ proxy statement for the 2007 Annual Meeting.
Audit-Related Fees
The aggregate fees billed by PricewaterhouseCoopers LLP for audit-related services rendered for the 2007 and 2006 fiscal years were zero and $25,853, respectively. These services consisted of employee benefit plan audits. The amount for 2006 includes $6,117 for 2006 audit-related services that was billed after the 2006 amount was disclosed in Pepco Holdings’ proxy statement for the 2007 Annual Meeting.
Tax Fees
The aggregate fees billed by PricewaterhouseCoopers LLP for tax services rendered for the 2007 and 2006 fiscal years were $126,810 and $121,951 respectively. These services consisted of tax compliance, tax advice and tax planning. The amount for 2006 includes $35,791 for the 2006 tax-related services that was billed after the 2006 amount was disclosed in Pepco Holdings’ proxy statement for the 2007 Annual Meeting.
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 2007 and
fiscal years were $41,740 and $20,419, respectively, which represents 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 2008 Annual Meeting of Shareholders to be filed with the SEC on or about March 27, 2008.
Part IV
Item 15.
Item 15. EXHIBITS, 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.”
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,” herein.
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 (7) “Debt” to the consolidated financial statements of Pepco Holdings included in Item 8 of Part II.
For information concerning PHI’s material contingencies and guarantees, see Note (12) “Commitments and Contingencies” to the consolidated financial statements of Pepco Holdings included in Item 8.
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.
* Management contract or compensatory plan or arrangement.
** The information required by this Exhibit is set forth in Note (10) of the ”Notes to Consolidated Financial Statements” of the Financial Statements of Pepco Holdings included in Item 8 “Financial Statements and Supplementary Data.”
Regulation S-K Item 10(d) requires Registrants to identify the physical location, by SEC file number reference of all documents that are incorporated by reference and have been on file with the SEC for more than five years. The SEC file number references for Pepco Holdings, Inc., those of its subsidiaries that are registrants, Conectiv and ACE Funding are provided below:
Pepco Holdings, Inc. in file number 001-31403
Potomac Electric Power Company in file number 001-1072
Conectiv in file number 001-13895
Delmarva Power & Light Company in file number 001-1405
Atlantic City Electric Company in file number 001-3559
Atlantic City Electric Transition Funding LLC in file number 333-59558
Certain instruments defining the rights of the holders of long-term debt of PHI, Pepco, DPL and ACE (including medium-term notes, unsecured notes, senior notes and tax-exempt financing instruments) have not been filed as exhibits in accordance with Regulation S-K Item 601(b)(4)(iii) because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis. Each of PHI, Pepco, DPL or ACE agrees to furnish to the SEC upon request a copy of any such instruments omitted by it.
INDEX TO FURNISHED EXHIBITS
The documents listed below are being furnished herewith:
(b) Exhibits
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
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 February 29, 2008 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
February 29, 2008
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 February 29, 2008 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
February 29, 2008
Exhibit 23.3
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-145691-02) of Delmarva Power & Light Company of our report dated February 29, 2008 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
February 29, 2008
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 February 29, 2008 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
February 29, 2008
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: February 29, 2008
/s/ D. R. WRAASE
Dennis R. Wraase
Chairman of the Board, President
and Chief Executive Officer
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: February 29, 2008
/s/ P. H. BARRY
Paul H. Barry
Senior Vice President and
Chief Financial Officer
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: February 29, 2008
/s/ JOSEPH M. RIGBY
Joseph M. Rigby
President and Chief Executive Officer
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: February 29, 2008
/s/ P. H. BARRY
Paul H. Barry
Senior Vice President and
Chief Financial Officer
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: February 29, 2008
/s/ JOSEPH M. RIGBY
Joseph M. Rigby
President and Chief Executive Officer
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: February 29, 2008
/s/ P. H. BARRY
Paul H. Barry
Senior Vice President and
Chief Financial Officer
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: February 29, 2008
/s/ JOSEPH M. RIGBY
Joseph M. Rigby
President and Chief Executive Officer
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: February 29, 2008
/s/ P. 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, Dennis R. Wraase, 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, 2007, 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.
February 29, 2008
/s/ D. R. WRAASE
Dennis R. Wraase
President and Chief Executive Officer
February 29, 2008
/s/ P. 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, Joseph M. Rigby, 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, 2007, 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.
February 29, 2008
/s/ JOSEPH M. RIGBY
Joseph M. Rigby
President and Chief Executive Officer
February 29, 2008
/s/ P. 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, Joseph M. Rigby, 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, 2007, 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.
February 29, 2008
/s/ JOSEPH M. RIGBY
Joseph M. Rigby
President and Chief Executive Officer
February 29, 2008
/s/ P. 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, Joseph M. Rigby, 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, 2007, 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.
February 29, 2008
/s/ JOSEPH M. RIGBY
Joseph M. Rigby
President and Chief Executive Officer
February 29, 2008
/s/ P. 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.
February 29, 2008
PEPCO HOLDINGS, INC.
(Registrant)
By /s/ D. R. WRAASE
Dennis R. Wraase
Chairman of the Board,
President and Chief
Executive Officer
February 29, 2008
POTOMAC ELECTRIC POWER COMPANY (Pepco)
(Registrant)
By /s/ JOSEPH M. RIGBY
Joseph M. Rigby,
President and Chief
Executive Officer
February 29, 2008
DELMARVA POWER & LIGHT COMPANY (DPL)
(Registrant)
By /s/ JOSEPH M. RIGBY
Joseph M. Rigby,
President and Chief
Executive Officer
February 29, 2008
ATLANTIC CITY ELECTRIC COMPANY (ACE)
(Registrant)
By /s/ JOSEPH M. RIGBY
Joseph M. Rigby,
President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the above named registrants and in the capacities and on the dates indicated:
/s/ D. R. WRAASE
Dennis R. Wraase
Chairman of the Board, President and Chief Executive Officer of Pepco Holdings, Chairman of the Board of Pepco and Director of Pepco Holdings, Pepco, DPL and ACE
(Principal Executive Officer of Pepco Holdings)
February 29, 2008
/s/ JOSEPH M. RIGBY
Joseph M. Rigby
Director, President and Chief Executive Officer of Pepco and DPL and President and Chief Executive Officer of ACE
(Principal Executive Officer of Pepco, DPL and ACE)
February 29, 2008
/s/ P. H. BARRY
Paul H. Barry
Senior Vice President and Chief Financial Officer of Pepco Holdings, Pepco, and DPL, Chief Financial Officer of ACE and Director of Pepco and DPL
(Principal Financial Officer of Pepco Holdings, Pepco, DPL and ACE)
February 29, 2008
/s/ R. K. CLARK
Ronald K. Clark
Vice President and Controller of Pepco Holdings, Pepco and DPL and Controller of ACE
(Principal Accounting Officer of Pepco Holdings, Pepco, DPL and ACE)
February 29, 2008
Signature
Title
Date
/s/ J. B. DUNN
Jack B. Dunn, IV
Director, Pepco Holdings
February 29, 2008
/s/ T. C. GOLDEN
Terence C. Golden
Director, Pepco Holdings
February 29, 2008
/s/ FRANK O. HEINTZ
Frank O. Heintz
Director, Pepco Holdings
February 29, 2008
/s/ BARBARA J. KRUMSIEK
Barbara J. Krumsiek
Director, Pepco Holdings
February 29, 2008
/s/ GEORGE F. MacCORMACK
George F. MacCormack
Director, Pepco Holdings
February 29, 2008
/s/ RICHARD B. McGLYNN
Richard B. McGlynn
Director, Pepco Holdings
February 29, 2008
/s/ LAWRENCE C. NUSSDORF
Lawrence C. Nussdorf
Director, Pepco Holdings
February 29, 2008
/s/ FRANK ROSS
Frank K. Ross
Director, Pepco Holdings
February 29, 2008
/s/ PAULINE A. SCHNEIDER
Pauline A. Schneider
Director, Pepco Holdings
February 29, 2008
/s/ LESTER P. SILVERMAN
Lester P. Silverman
Director, Pepco Holdings
February 29, 2008
/s/ WILLIAM T. TORGERSON
William T. Torgerson
Director of Pepco Holdings, Pepco and DPL
February 29, 2008
/s/ WILLIAM M. GAUSMAN
William M. Gausman
Director of Pepco
February 29, 2008
/s/ MICHAEL J. SULLIVAN
Michael J. Sullivan
Director of Pepco
February 29, 2008
/s/ S. A. WISNIEWSKI
Stanley A. Wisniewski
Director of Pepco
February 29, 2008