Item 1. BUSINESS
OVERVIEW
Pepco Holdings, Inc. (PHI or Pepco Holdings) is a public utility holding company that, through its operating subsidiaries, is engaged primarily in two principal business operations:
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electricity and natural gas delivery (Power Delivery), and
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competitive energy generation, marketing and supply (Competitive Energy).
PHI was incorporated in Delaware in 2001, for the purpose of effecting the acquisition of Conectiv by Potomac Electric Power Company (Pepco). The acquisition was completed on August 1, 2002, at which time Pepco and Conectiv became wholly owned subsidiaries of PHI. Conectiv was formed in 1998 to be the holding company for Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) in connection with the combination of DPL and ACE. As a result, DPL and ACE are wholly owned subsidiaries of Conectiv. The following chart shows, in simplified form, the corporate structure of PHI and its principal subsidiaries.
On February 8, 2006, the Public Utility Holding Company Act of 1935 (PUHCA 1935) was repealed and the Public Utility Holding Company Act of 2005 (PUHCA 2005) went into effect. As a result, PHI has ceased to be regulated by the Securities and Exchange Commission (SEC) as a public utility holding company and is now subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC). As permitted under FERC regulations promulgated under PUHCA 2005, PHI will give notice to FERC that it will continue, until further notice, to operate pursuant to the authority granted in the financing order issued by the SEC under PUHCA 1935, which has an authorization period ending June 30, 2008, relating to the issuance of securities and guarantees, other financing transactions and the operation of the money pool. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - PUHCA Restrictions" for additional information.
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PHI Service Company, a subsidiary service company of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries. These services are provided pursuant to a service agreement among PHI, PHI Service Company, and the participating operating subsidiaries which was filed with, and approved by, the SEC under PUHCA 1935. The expenses of the service company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methodologies set forth in the service agreement. PHI expects to continue operating under the service agreement and is evaluating whether to seek FERC approval of the cost allocation methodologies in the service agreement under PUHCA 2005.
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. This segment information includes a revision of PHI's segments for 2003 to reflect that, as of January 1, 2004, the formerly separate segments of Pepco Power Delivery and Conectiv Power Delivery were combined to form one operating segment. Each of Pepco, DPL and ACE has one operating segment.
Investor Information
Each of PHI, Pepco, DPL and ACE is a reporting company under the Securities Exchange Act of 1934, as amended (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 SEC. These reports may be found at http://www.pepcoholdings.com/investors.
The following is a description of each of PHI's two principal areas of operation.
Power Delivery
The largest component of PHI's business is Power Delivery, which consists of the transmission and distribution of electricity and the distribution of natural gas. In 2005, 2004 and 2003, respectively, PHI's Power Delivery operations produced 58%, 61% and 55% of PHI's consolidated operating revenues (including intercompany transactions) and 74%, 70% and 82% of PHI's consolidated operating income (including income from intercompany transactions).
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 regulated 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 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.
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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
PHI and its subsidiaries refer to this supply service in each of the jurisdictions 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 120,000 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 as such are part of an interstate power transmission grid over which electricity is transmitted throughout the eastern United States. 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 Interconnection, LLC (PJM) provides transmission planning functions and acts as the independent system operator that coordinates the movement of electricity in 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. FERC has designated PJM as the sole provider of transmission service in the PJM region. Any entity that wishes to have electricity delivered at any point in the PJM 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 PJM and PJM directs and controls the operation of these transmission facilities. In return for the use of their transmission facilities, PJM pays the transmission owners fees approved by FERC.
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 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
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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 substantially all of their generation assets, either by 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, except for the limited generation activities of ACE described in the "ACE" section, herein.
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 greater in the summer months associated with cooling and demand for electricity and natural gas is generally greater 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 less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Regulation
The retail operations of PHI's utility subsidiaries, including the rates they are permitted to charge customers for the delivery of electricity and natural gas, are subject to regulation by governmental agencies in the jurisdictions in which they provide utility service. Pepco's electricity delivery operations are regulated in Maryland by the Maryland Public Service Commission (MPSC) and in Washington, D.C. by the District of Columbia Public Service Commission (DCPSC). DPL's electricity delivery operations are regulated in Maryland by the MPSC, in Virginia by the Virginia State Corporation Commission (VSCC) and in Delaware by the Delaware Public Service Commission (DPSC). DPL's natural gas distribution operations in Delaware are regulated by the DPSC. ACE's electric delivery operations are regulated in New Jersey by the New Jersey Board of Public Utilities (NJBPU). The wholesale and transmission operations for both electricity and natural gas of each of PHI's utility subsidiaries are regulated by FERC.
Pepco
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 was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949. Pepco's service territory covers approximately 640 square miles and has a population of approximately 2 million. As of December 31, 2005, Pepco delivered electricity to approximately 747,000 customers, as compared to 737,000 customers as of December 31, 2004. Pepco delivered a total of approximately 27,594,000 megawatt hours of electricity in 2005, compared to approximately 26,902,000 megawatt hours in 2004. In 2005, approximately 30% was delivered to residential customers, 51% to commercial customers, and 19% to United States and District of Columbia government customers.
Under a settlement approved by the MPSC in April 2003, Pepco is required to provide SOS to residential and small commercial customers through May 2008 and to medium-sized
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commercial customers through May 2006, and was required to provide SOS to large commercial customers through May 2005. Pepco also has an obligation to provide service at hourly priced rates to the largest customers through May 2006. In accordance with the settlement, 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 MPSC. Pepco is entitled to recover from its SOS customers the cost of the SOS supply plus an average margin of approximately $.002 per kilowatt hour (calculated at the time of the announcement of the contracts, based on total sales to residential and small and large commercial Maryland SOS customers over the twelve months ended December 31, 2003). 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 both SOS customers and customers in Maryland who have selected another energy supplier. These delivery rates are capped through December 31, 2006 pursuant to the MPSC order issued in connection with the Pepco acquisition of Conectiv, but are subject to adjustment if FERC transmission rates increase by more than 10%.
Under an order issued by the DCPSC in March 2004, as amended by a DCPSC order issued in July 2004, Pepco is obligated to provide SOS for small commercial and residential customers through May 31, 2011 and for large commercial customers through May 31, 2007. 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 approximately $.00248 per kilowatt hour (calculated at the time of the announcement of the contracts, based on total sales to residential and small and large commercial District of Columbia SOS customers over the twelve months ended December 31, 2003). 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 both SOS customers and customers in the District of Columbia who have selected another energy supplier. Delivery rates in the District of Columbia generally are capped through July 2007, but are subject to adjustment if FERC transmission rates increase by more than 10%, except that for residential low-income customers, rates generally are capped through July 2009.
For the twelve months ended December 31, 2005, 62% of Pepco's Maryland sales (measured by megawatt hours) were to SOS customers, as compared to 71% in 2004 and 42% of its District of Columbia sales were to SOS customers, as compared to 68% in 2004.
DPL
DPL is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and Virginia and provides natural gas distribution service in northern Delaware. In Delaware, service is provided in three counties, Kent, New Castle, and Sussex; in Maryland, service is provided in ten counties, Caroline, Cecil, Dorchester, Harford, Kent, Queen Anne's, Somerset, Talbot, Wicomico, and Worchester; and in Virginia, service is provided to two counties, Accomack and Northampton. DPL was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979. DPL's electricity distribution service territory covers approximately 6,000 square miles and has a population of approximately 1.28 million. DPL's
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natural gas distribution service territory covers approximately 275 square miles and has a population of approximately 523,000. As of December 31, 2005, DPL delivered electricity to approximately 510,000 customers and delivered natural gas to approximately 120,000 customers, as compared to 501,000 electricity customers and 118,000 natural gas customers as of December 31, 2004.
In 2005, DPL delivered a total of approximately 14,101,000 megawatt hours of electricity to its customers, as compared to a total of approximately 13,902,000 megawatt hours in 2004. In 2005, approximately 40% of DPL's retail electricity deliveries were to residential customers, 38% were to commercial customers and 22% were to industrial customers. In 2005, DPL delivered approximately 20,700,000 Mcf (one thousand cubic feet) of natural gas to retail customers in its Delaware service territory, as compared to approximately 21,600,000 Mcf in 2004. In 2005, approximately 41% of DPL's retail gas deliveries were sales to residential customers, 27% were sales to commercial customers, 5% were sales to industrial customers, and 27% were sales to customers receiving a transportation-only service.
Under a settlement approved by the DPSC, DPL is required to provide POLR service to customers in Delaware through April 2006. DPL is paid for supplying POLR service to customers in Delaware at fixed rates established in the settlement. DPL obtains all of the energy needed to fulfill its POLR obligations in Delaware under a supply agreement with its affiliate Conectiv Energy, which terminates in April 2006. DPL does not make any profit or incur any loss on the supply component of the POLR supply that it delivers to its Delaware customers. DPL is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both POLR customers and customers who have selected another energy supplier. These delivery rates generally are frozen through April 2006, except that DPL is allowed to file for a one-time transmission rate change during this period. On March 22, 2005, the DPSC issued an order approving DPL as the SOS provider after May 1, 2006, when DPL's current fixed rate POLR obligation ends. DPL will retain the SOS obligation for an indefinite period until changed by the DPSC, and will purchase the power supply required to satisfy its SOS obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure. On October 11, 2005, the DPSC approved a settlement agreement, under which DPL will provide SOS to all customer classes, with no specified termination date for SOS. Two categories of SOS will exist: (i) a fixed price SOS available to all but the largest customers; and (ii) an Hourly Priced Service (HPS) for the largest customers. DPL will purchase the power supply required to satisfy its fixed-price SOS obligation from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure. Power to supply the HPS customers will be acquired on next-day and other short-term PJM markets. In addition to the costs of capacity, energy, transmission, and ancillary services associated with the fixed-price SOS and HPS, DPL's initial rates will include a component referred to as the 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 a billing system to be used for billing HPS customers.
Under a settlement approved by the MPSC in April 2003, DPL is required to provide SOS to residential and small commercial customers through May 2008 and to medium-sized commercial customers through May 2006. In accordance with the settlement, DPL purchases the power supply required to satisfy its market rate SOS obligation from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved and supervised by the MPSC. DPL is entitled to recover from its SOS customers the costs of the SOS supply plus
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an average margin of $.002 per kilowatt hour (calculated at the time of the announcement of the contracts, based on total sales to residential and small and large commercial Maryland SOS customers over the twelve months ended December 31, 2003). 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 both SOS customers and customers in Maryland who have selected another energy supplier. These delivery rates generally are capped through December 2006, subject to adjustment if FERC transmission rates increase by more than 10%.
Under amendments to the Virginia Electric Utility Restructuring Act implemented in March 2004, DPL is obligated to offer Default Service to customers in Virginia for an indefinite period until relieved of that obligation by the VSCC. DPL currently obtains all of the energy and capacity needed to fulfill its Default Service obligations in Virginia under a supply agreement with Conectiv Energy that commenced on January 1, 2005 and expires in May 2006 (the 2005 Supply Agreement). DPL entered into the 2005 Supply Agreement after conducting a competitive bid procedure in which Conectiv Energy was the lowest bidder.
In October 2004, DPL filed an application with the VSCC for approval to increase the rates that DPL charges its Default Service customers to allow it to recover its costs for power under the 2005 Supply Agreement plus an administrative charge and a margin. A VSCC order issued in November 2004 allowed DPL to put interim rates into effect on January 1, 2005, subject to refund if the VSCC subsequently determined the rates are excessive. The interim rates reflected an increase of 1.0247 cents per kilowatt hour (Kwh) to the fuel rate, which provides for recovery of the entire amount being paid by DPL to Conectiv Energy, but did not include an administrative charge or margin, pending further consideration of this issue. In January 2005, the VSCC ruled that the administrative charge and margin are base rate items not recoverable through a fuel clause. On March 25, 2005, the VSCC approved a settlement resolving all other issues and making the interim rates final.
DPL is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both Default Service customers and customers in Virginia who have selected another energy supplier. These delivery rates generally are frozen until December 31, 2010, except that DPL can propose two changes in delivery rates - one prior to July 1, 2007 and another between July 1, 2007 and December 31, 2010.
In Maryland, DPL sales to SOS customers represented 77% of total sales (measured by megawatt hours) for the twelve months ended December 31, 2005, as compared to 80% in 2004. In Delaware, DPL sales to POLR customers represented 90% of total sales (measured by megawatt hours) for the twelve months ended December 31, 2005, as compared to 89% in 2004. In Virginia, DPL sales to Default Supply customers represented 100% of total sales (measured by megawatt hours) in both 2005 and 2004.
DPL also provides regulated natural gas supply and distribution service to customers in its Delaware natural gas service territory. Large and medium volume commercial and industrial natural gas customers may purchase natural gas either from DPL or from other suppliers. DPL uses its natural gas distribution facilities to transport gas for customers that choose to purchase natural gas from other suppliers. These customers pay DPL distribution service rates approved by the DPSC. DPL purchases natural gas supplies for resale to its sales 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, 2005, DPL supplied 72.8% of the
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natural gas that it delivered, compared to 71.8% in 2004.
ACE
ACE is primarily engaged in the transmission and distribution of electricity in a service territory consisting of Gloucester, Camden, Burlington, Ocean, Atlantic, Cape May, Cumberland and Salem counties in southern New Jersey. ACE was incorporated in New Jersey in 1924. ACE's service territory covers approximately 2,700 square miles and has a population of approximately 998,000. As of December 31, 2005, ACE delivered electricity to approximately 532,000 customers in its service territory, as compared to approximately 524,000 customers as of December 31, 2004. ACE delivered a total of approximately 10,080,000 megawatt hours of electricity in 2005 compared to approximately 9,874,000 megawatt hours in 2004. In 2005, approximately 44% was delivered to residential customers, 43% was delivered to commercial customers and 13% was delivered to industrial customers.
In accordance with a process mandated by the NJBPU, electric customers in New Jersey who do not choose another supplier receive BGS from their electric distribution company. Each of New Jersey's electric distribution companies, including ACE, jointly procure the supply to meet their BGS obligations from competitive suppliers selected through two concurrent auctions authorized by the NJBPU for New Jersey's total BGS requirement each February. 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 two prior years. ACE's BGS-FP load is approximately 2,050 megawatts, which represents approximately 87% 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 real-time market prices for a term of 12 months. ACE's BGS-CIEP load is approximately 300 megawatts, which represents approximately 13% of ACE's BGS load. This total load is auctioned off each year for a one-year term.
As of December 31, 2005, Conectiv Energy served four 100 megawatt blocks of BGS load in the ACE territory.
ACE is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both BGS customers and customers in its service territory who have selected another energy supplier. ACE is also paid tariff rates established by the NJBPU that compensate it for the cost of obtaining the BGS from competitive suppliers. ACE does not make any profit or incur any loss on the supply component of the BGS it provides to customers.
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ACE is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both BGS customers and customers in its service territory who have selected another energy supplier. ACE is also paid tariff rates established by the NJBPU that compensate it for the cost of obtaining the BGS from competitive suppliers. ACE does not make any profit or incur any loss on the supply component of the BGS it provides to customers.
ACE sales to New Jersey BGS customers represented 78% of total sales (measured by megawatt hours) for the twelve months ended December 31, 2005 and 2004.
In addition to its electricity transmission and distribution operations, as of December 31, 2005, ACE owned the B.L. England electric generating facility (with a generating capacity of 447 megawatts) and a 2.47% undivided interest in the Keystone electric generating facility and a 3.83% undivided interest in the Conemaugh electric generating facility. The combined generating capacity of these facilities is 555 megawatts. See Item 2 -- "Properties." ACE also has contracts with non-utility generators under which ACE purchased 3.8 million megawatt hours of power in 2005. ACE sells the electricity produced by the generating facilities and purchased under the non-utility generator contracts in the wholesale market administered by PJM. During 2005, ACE's generation and wholesale electricity sales operations produced approximately 30% of ACE's operating revenue.
On November 15, 2005, ACE entered into an agreement to sell its undivided interests in the Keystone and Conemaugh generating facilities to Duquesne Light Holdings Inc. for $173.1 million. The sale, subject to approval by the NJBPU, as well as other regulatory agencies and certain other legal conditions, is expected to be completed mid-year 2006. In December 2005, ACE filed testimony with the NJBPU in estimating that its net gains on the sale of the generating stations will be approximately $126.9 million; however, the net gains ultimately realized will be dependent upon the timing of the closing of the sale, transaction costs and other factors. The net gains will be an offset to stranded costs.
ACE is continuing its efforts to sell the B.L. England generating facility. On January 24, 2006, PHI, Conectiv and ACE entered into an administrative consent order (ACO) with the New Jersey Department of Environmental Protection (NJDEP) and the Attorney General of New Jersey, which provides that ACE will permanently cease operation of the B.L. England generating facility by December 15, 2007 if it does not sell the facility before then. The shut-down is contingent upon the receipt by ACE of necessary approvals from applicable regulatory authorities and permits to construct certain electric transmission facilities in southern New Jersey. See "Environmental Matters -- Air Quality Regulation."
In 2001, ACE established Atlantic City Electric Transition Funding L.L.C. (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.
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Competitive Energy
PHI's Competitive Energy business provides non-regulated generation, marketing and supply of electricity and natural gas, and related energy management services, in the mid-Atlantic region. In 2005, 2004 and 2003, respectively, PHI's Competitive Energy operations produced 51%, 50% and 55% of PHI's consolidated operating revenues. In 2005 and 2004, respectively, PHI's Competitive Energy operations produced 16% and 19% of PHI's consolidated operating income. In 2003, PHI's Competitive Energy operations incurred an operating loss equal to 20% of PHI's consolidated operating income. PHI's Competitive Energy operations are conducted through subsidiaries of Conectiv Energy and Pepco Energy Services.
Conectiv Energy
Conectiv Energy provides wholesale electric power, capacity, and ancillary services in the wholesale markets administered by PJM and also supplies electricity to other wholesale market participants under long and short-term bilateral contracts. Among its bilateral contracts are the power supply agreements under which Conectiv Energy sells to DPL electricity required by DPL to fulfill its Default Electricity Supply obligations for customers in Delaware and Virginia and for a portion of its Maryland customers. Conectiv Energy also supplies electric power to satisfy a portion of ACE's Default Electric Supply load, as well as Default Electric Supply load to other mid-Atlantic utilities. 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 from purchases in the wholesale market administered by PJM.
Conectiv Energy's generation asset strategy focuses on mid-merit plants with operating flexibility and multi-fuel capability that 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, 2005, Conectiv Energy owned and operated mid-merit plants with a combined 2,713 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." Conectiv Energy also owns three uninstalled combustion turbines with a book value of $57.0 million. Conectiv Energy will determine whether to install these turbines as part of an existing or new generating facility or sell the turbines to a third party based upon market demand and transmission system needs and requirements.
Conectiv Energy also sells natural gas and fuel oil to very large end-users and to wholesale market participants under bilateral agreements. Conectiv Energy obtains the natural gas and fuel oil required to meet its supply obligations through market purchases for next day delivery and under long- and short-term bilateral contracts with other market participants.
Conectiv Energy actively engages in commodity risk management activities to reduce its financial exposure to changes in the value of its assets and obligations due to commodity price fluctuations. A portion of these risk management activities are conducted using instruments classified as derivatives, such as forward contracts, futures, swaps, and exchange-traded and over-the-counter options. Conectiv Energy also manages commodity risk with contracts that are not classified as derivatives. Conectiv Energy has two primary risk management objectives: to
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manage the spread between the cost of fuel used to operate its electric generation plants and the revenue received from the sale of the power produced by those plants; and to manage the cost of its contracts relating to Default Electricity Supply in order 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 market activities in an effort to profit from short-term geographical price differentials in electricity prices among markets.
Conectiv Energy's goal is to hedge economically a targeted portion of both the expected power output of its generation facilities and the expected costs of fuel used to operate those facilities. The hedge goals are approved by PHI's Corporate Risk Management Committee and may change from time to time based on market conditions, and the actual level of coverage may vary from the target depending on the extent to which the company is successful in implementing its hedging strategies. In July 2003, Conectiv Energy entered into an agreement with an international investment banking firm consisting of a series of energy contracts designed to hedge more effectively approximately 50% of Conectiv Energy's generation output and approximately 50% of its supply obligations, with the intention of providing Conectiv Energy with a more predictable earnings stream during the term of the agreement. The agreement will expire in May 2006. For additional discussion of Conectiv Energy's hedging activities, see Item 7A "Quantitative and Qualitative Disclosures About Market Risk."
Pepco Energy Services
Pepco Energy Services sells retail electricity and natural gas primarily to commercial, industrial and governmental customers primarily in the mid-Atlantic region. Pepco Energy Services also provides integrated energy management services to commercial, industrial and governmental customers, including energy-efficiency contracting, development and construction of "green power" facilities, central plant and other equipment operation and maintenance, and fuel management. Subsidiaries of Pepco Energy Services provide high voltage construction and maintenance services to utilities and other customers throughout the United States and low voltage electric and telecommunication construction and maintenance services in the Washington, D.C. area.
Pepco Energy Services owns peak-load electricity generation plants with approximately 800 megawatts of peak-load capacity, the output of which is sold in the wholesale market administered by PJM. See Item 2 "Properties."
Pepco Energy Services actively engages in commodity risk management activities to reduce the financial exposure to changes in the value of its supply contracts and sales commitments due to commodity price and volume fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives, such as forward contracts, futures, swaps, and exchange-traded and over-the-counter options. Pepco Energy Services' primary risk management objective is to manage the spread between its retail electric and natural gas sales commitments and the cost of supply used to service those commitments in order to secure favorable margins. Because of the age and design of Pepco Energy Services' power plants, these facilities have a high variable cost of operation and Pepco Energy Services generally does not hedge the output of these plants. For additional discussion of Pepco Energy Services' hedging activities, see Item 7A "Quantitative and Qualitative Disclosures About Market Risk."
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Competition
The unregulated energy generation, supply and marketing businesses 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 greater in the summer months associated with cooling and demand for electricity and natural gas generally is greater 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 produced less revenue when weather conditions are milder than normal. Such weather conditions can also negatively impact income from these operations. Energy management services generally are not seasonal.
Other Business Operations
Over the last several years, PHI has discontinued its investments in non-energy related businesses, including the sale of its aircraft investments and the sale of its 50% interest in Starpower Communications LLC (Starpower). Through its subsidiary, Potomac Capital Investment Corporation (PCI), PHI continues to maintain a portfolio of cross-border energy sale-leaseback transactions, with a book value at December 31, 2005 of approximately $1.3 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 and Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors." This activity constitutes a separate operating segment for financial reporting purposes which is designated "Other Non-Regulated."
EMPLOYEES
At December 31, 2005, PHI had 5,481 employees, including 1,526 employed by Pepco, 898 employed by DPL, 632 employed by ACE and 1,709 employed by PHI Service Company. The balance was employed by PHI's competitive energy and other non-regulated businesses. Approximately 2,950 employees (including 1,145 employed by Pepco, 730 employed by DPL, 457 employed by ACE, 349 employed by PHI Service Company, and the balance employed by PHI's Competitive Energy businesses) are covered by collective bargaining agreements with various locals of the International Brotherhood of Electrical Workers.
ENVIRONMENTAL MATTERS
PHI, through its subsidiaries, is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition,
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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 currently estimates that capital expenditures for environmental control facilities by its subsidiaries will be $4.2 million in 2006 and $20.2 million in 2007. However, the actual costs of environmental compliance may be materially different from these estimates 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.
Air Quality Regulation
The generation facilities and operations of PHI's subsidiaries are subject to federal, state and local laws and regulations, including the federal Clean Air Act (CAA), that limit emissions of air pollutants, require permits for operation of facilities and impose recordkeeping and reporting requirements.
Among other things, the CAA regulates total sulfur dioxide (SO2) emissions from affected generation units and allocates "allowances." The generation 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, 22 eastern and mid-western states and the District of Columbia regulate nitrogen oxide (NOx) emissions from generation units and allocate NOx allowances. Most of the generation units operated by PHI subsidiaries are subject to NOx emission limits and are required to hold, either through allocations or purchases, NOx allowances as necessary to achieve compliance.
The NJDEP administers CAA programs in New Jersey as well as air quality requirements imposed by New Jersey laws and regulations. In February 2000, the U.S. Environmental Protection Agency (EPA) and NJDEP requested information from ACE regarding the operation of coal-fired boilers at ACE's B.L. England facility and Conectiv Energy's (formerly ACE's) Deepwater facility to determine whether they were in compliance with the New Source Review (NSR), Prevention of Significant Deterioration (PSD) and non-attainment NSR requirements of the CAA. Generally, these regulations require that operators of major sources of certain air pollutants obtain permits, install pollution control technology and obtain offsets in some circumstances when those sources undergo a "major modification," as defined in the regulations
In 2003, EPA published a final rule clarifying the types of activities that qualify as "routine maintenance, repair and replacement" rather than "major modifications" and are therefore excluded from NSR requirements. A number of states, industrial entities, and environmental groups have challenged the rule and the U.S. Court of Appeals for the District of Columbia Circuit has stayed the rule's applicability.
On January 24, 2006, PHI, Conectiv and ACE entered into an ACO with NJDEP and the Attorney General of New Jersey. This ACO is the definitive agreement contemplated by the April 26, 2004 preliminary settlement agreement among the parties. The ACO resolves New Jersey's claim for alleged violations of the CAA and the NJDEP's concerns regarding ACE's compliance with NSR requirements and the New Jersey Air Pollution Control Act (APCA) with respect to the B.L. England generating facility and various other environmental issues
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relating to ACE and Conectiv Energy facilities in New Jersey. Among other things, the ACO provides that:
·
Contingent upon the receipt of necessary approvals for the construction of substation and transmission facilities to compensate for the shut down of B.L. England, ACE will permanently cease operation of the B.L. England generating facility by December 15, 2007 if ACE does not sell the facility. In the event that ACE is unable to shut down the B.L. England facility by December 15, 2007 through no fault of its own, (i) ACE may operate B.L. England Unit 1 after December 15, 2007 for certain limited purposes and/or for electric system reliability during the summer months in the years 2008 to 2012, and (ii) B.L. England Unit 1 and 2 would be required to comply with stringent emissions limits by December 15, 2012 and May 1, 2010, respectively. If ACE fails to meet those 2010 and 2012 deadlines for reducing emissions, ACE would be required to pay up to $10 million in civil penalties.
·
If B.L. England is shut down by December 15, 2007, ACE will surrender to NJDEP certain SO2 and NOx allowances allocated to B.L. England Units 1 and 2, contingent upon approval by the NJBPU recognizing cost impacts of the surrender.
·
In the event that ACE is unable to shut down B.L. England Units 1 and 2 by December 15, 2007 through no fault of its own, ACE will surrender NOx and SO2 allowances not needed to satisfy the operational needs of B.L. England Units 1 and 2, contingent upon approval by the NJBPU recognizing cost impacts of the surrender.
·
To resolve any possible civil liability (and without admitting liability) for violations of APCA and the PSD provisions of the CAA, ACE paid a $750,000 civil penalty to NJDEP in June 2004 and will undertake environmental projects that are beneficial to the state of New Jersey and approved by the NJDEP or donate property valued at $2 million.
·
To resolve any possible civil liability (and without admitting liability) for natural resource damages resulting from groundwater contamination at ACE's B.L. England facility and Conectiv Energy's Deepwater facility and ACE's operations center near Pleasantville, New Jersey, ACE and Conectiv Energy paid NJDEP $674,162 and will remediate the groundwater contamination at all three sites
·
The ACO allows the sale of the B.L. England facility through the B.L. England auction process to a third party that is not committing to repower or otherwise meet the ACO's emissions limits, subject to a 45-day right of first refusal in favor of NJDEP for purchase of B.L. England on terms and conditions no less favorable to ACE than those offered by a third party. In the event that ACE enters into a third-party agreement through the B.L. England auction process with an entity that commits to repower B.L. England or otherwise meet the ACO's emission limits, NJDEP does not have a right of first refusal.
·
If ACE does not sell B.L. England and the facility is shut down by December 15, 2007, ACE will give NJDEP or a charitable conservancy six months to negotiate an agreement to purchase B.L. England. If no agreement is reached, ACE may seek bids for B.L. England from third parties, subject to a 45-day right of first refusal in favor of NJDEP for purchase of B.L. England on terms and conditions no less favorable to ACE than those offered by a third party.
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The ACO does not resolve any federal claims for alleged violations at the B.L. England generating station or any federal or state claims regarding alleged violations at Conectiv Energy's Deepwater generating station or any other facilities. PHI does not believe that any of its subsidiaries has any liability with respect thereto, but cannot predict the consequences of the federal and state inquiries.
On May 4, 2002, ACE and Conectiv Energy entered into an ACO with NJDEP to address the inability of ACE and Conectiv Energy to procure Discrete Emission Reduction (DER) credits to comply fully with New Jersey's NOx Reasonably Available Control Technology requirements, as well as NJDEP's contention that ACE had failed to comply with DER credit use restrictions from 1996 to 2001. The ACO (i) eliminated requirements for ACE and Conectiv Energy to purchase DER credits for certain generation units through May 1, 2005, (ii) provided for installation of new controls on certain Conectiv Energy electric generating units at an estimated cost of $10.7 million, (iii) imposed a $1 million penalty, (iv) required the contribution of $1 million to promote, develop and enhance an urban air shed reforestation project, and (v) imposed operating hour limits at Conectiv Energy's Deepwater generating facility Unit No. 4. In August 2005, NJDEP terminated the ACO based on its determination that ACE and Conectiv Energy had achieved compliance with all of the terms of the ACO.
EPA finalized its Clean Air Mercury Rule (CAMR) on May 18, 2005. CAMR establishes mercury emissions standards for new or modified sources and caps state-wide emissions of mercury beginning in 2010. States may implement CAMR by adopting EPA's trading program for coal-fired utility boilers or through regulations that at a minimum achieve the reductions that will be achieved through EPA's program. These regulations may require installation of pollution control devices and/or fuel modifications for generating units owned by ACE, Conectiv Energy and Pepco Energy Services. As discussed below, New Jersey facilities will be required to satisfy state mercury emissions standards that are more stringent than CAMR. Closely related to CAMR is EPA's Clean Air Interstate Rule (CAIR), released on March 10, 2005, which imposes additional reductions of SO2 and Nox emissions from electric generating units in 28 Eastern states and the District of Columbia with implementation commencing in 2009. CAIR caps state-wide emissions of SO2 and Nox in two stages beginning in 2009 (Nox) and 2010 (SO2). As with CAMR, states may implement CAIR by adopting EPA's trading program or through regulations that at a minimum achieve the reductions that will be achieved through implementation of EPA's program. These regulations may require installation of pollution control devices and/or fuel modifications for generating units owned by ACE, Conectiv Energy and Pepco Energy Services.
In a March 14, 2005 rulemaking, EPA removed coal- and oil-fired units from the list of source categories requiring Maximum Achievable Control Technology for hazardous air pollutants 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 Conectiv Energy's Edge Moor Unit 5 and ACE's B.L. England Unit 3.
In December 2004, NJDEP published final rules regulating mercury emissions from power plants and industrial facilities in New Jersey that impose standards that are significantly stricter than EPA's federal CAMR for coal-fired plants. In lieu of meeting these standards for all New Jersey coal-fired units by December 15, 2007, NJDEP's final mercury rules allow an owner or operator to enter into an enforceable agreement to comply with the mercury limits for 50% of a company's total coal-fired capacity by the December 15, 2007 deadline and to comply with the mercury standards, as well as with stringent standards regulating emissions of Nox, SO2 and
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particulate matter, for the remaining 50% of its units by December 2012. Alternatively, if an owner or operator enters into an enforceable agreement with NJDEP by December 15, 2007 to shut down coal unit(s) by December 15, 2012, then the mercury limitations would not be applicable to that particular unit. Contingent upon receipt of necessary approvals from the NJBPU, PJM, North American Reliability Counsel, FERC and other regulatory authorities and the receipt of permits to construct certain transmission facilities in southern New Jersey, if ACE does not sell the B.L. England facility, ACE plans to shut down the facility by December 15, 2007. In this event, no significant capital improvements will be needed at B.L. England to comply with NJDEP's final mercury emission rules or CAMR. Conectiv Energy is investigating what, if any, capital or operational improvements are needed at the Deepwater generating facility in order to comply with NJDEP's final mercury regulations and CAMR and at Edge Moor to comply with CAMR. At this time, Conectiv Energy anticipates that activated carbon injection will be needed at Deepwater to meet these regulations at a cost of approximately $300,000.
In September 2005, NJDEP adopted regulations regarding the further control of Nox emissions from combustion sources. These regulations significantly reduce the Nox limit on B.L. England's diesel generators beginning in 2007.
In November 2005, NJDEP finalized regulations that classify carbon dioxide (CO2) as an air contaminant and enable NJDEP potentially to regulate CO2 emissions from power plants and other sources. Through its rulemaking and other public announcements, NJDEP has indicated that it will take action to limit or reduce emissions of CO2 from electric utilities in New Jersey in the near future. New Jersey is one of seven states, including Delaware, Connecticut, Maine, New Hampshire, Vermont and New York, that has agreed to participate in the Regional Greenhouse Gas Initiative (RGGI), which is expected to cap and eventually reduce emissions of CO2 from power plants within the participating states.
As RGGI signatories, it is anticipated that both New Jersey and Delaware will adopt implementing CO2 regulations in 2006. These regulations are expected to require New Jersey and Delaware fossil fuel-fired electric generating units to hold CO2 allowances equivalent to its historic baseline CO2 emissions commencing in 2009 and to incrementally reduce CO2 emissions beginning in 2015 to achieve a 10% reduction baseline by 2019. Because each state has freedom to adopt its own regulations and can develop its own allowance allocation mechanisms, PHI cannot predict, at this time, if any allowance allocations by these two states will fall below its future predicted emissions of CO2, and what the regulations' potential economic impact may be.
On January 6, 2006, the Delaware Department of Natural Resources and Environmental Control (DNREC) informed Conectiv Energy of DNREC's intent to develop a new regulation to "facilitate the reduction of air emissions from Delaware's coal and residual oil fired power plants." This "multipollutant" regulation will further control SO2, Nox, and mercury from the Edge Moor generation facility, independent of the federal CAIR and CAMR regulations. According to DNREC's Start Action Notice, the regulation will help to attain the ambient air quality standards for ozone and fine particulate matter, address local scale fine particulate and mercury problems attributable to coal and oil fired electric generating stations, satisfy the federal CAIR and CAMR rules, improve visibility and satisfy Delaware's regional haze obligations. Conectiv Energy will participate as a stakeholder in the regulation's development, which is expected to occur during the fall of 2006.
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Water Quality Regulation
Section 402(a) of the federal Water Pollution Control Act, also known as the Clean Water Act (CWA), establishes the basic legal structure for regulating the discharge of pollutants from point sources to surface waters of the United States. Among other things, CWA Section 402(a) 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 the EPA or by a state agency under a federally authorized state program. All of the steam generation facilities operated by PHI's subsidiaries have NPDES permits authorizing their pollutant discharges, which are subject to periodic renewal.
In July 2004, the 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. These regulations may require changes to cooling water intake structures at facilities operated by ACE, Conectiv Energy and Pepco Energy Services. However, the capital expenditures the regulations may require at each facility, if any, will not be known until each facility completes various studies in accordance with schedules established consistent with the regulations and related permit requirements. Based on these studies, the applicable permitting authority will specify any changes to cooling water intake structures that are required in a facility's NPDES renewal permit.
The 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 generation 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 technology and operational studies were evaluated and are being discussed with DNREC. Expenditures to comply with EPA's CWA Section 316(b) performance-based standards are dependent upon DNREC's input. PHI cannot predict the extent of these expenditures until DNREC provides a direction or comments on PHI's proposed strategy.
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. The NJPDES renewal permit for Conectiv Energy's Deepwater generating facility, effective through September 30, 2007, requires several studies to determine whether or not Deepwater's cooling water intake structures satisfy applicable requirements for protection of the environment. The studies required by Deepwater's NJPDES permit are consistent with requirements under EPA's regulations implementing CWA Section 316(b). NJDEP will consider the results of these studies, as well as other related information submitted in accordance with EPA's CWA Section 316(b) regulations, in connection with the facility's NJPDES permit renewal application, which will be filed in 2007.
The renewal NJPDES permit for the B.L. England generating facility was issued by NJDEP in February 2005. Under the terms of the permit, ACE is required to submit all federally required studies and complete construction of all facilities necessary to satisfy the EPA's new
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cooling water intake structure regulations in accordance with a schedule established by the NJDEP that takes into account ACE's agreement to shut down the B.L. England facility by December 15, 2007, subject to receipt of all regulatory approvals.
Pepco and a subsidiary of Pepco Energy Services discharge water from a steam generation 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 the EPA 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. The EPA has not 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.
Hazardous Substance Regulation
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), authorizes the 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 the EPA or a state environmental agency as a potentially responsible party (PRP) at certain contaminated sites. See Item 3 "Legal Proceedings -- Environmental Litigation." 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 Item 3 "Legal Proceedings -- Environmental Litigation" 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
Pepco Holdings
See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Risk Factors."
Pepco
See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Risk Factors."
DPL
See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Risk Factors."
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ACE
See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Risk Factors."
Item 1B.
Item 1B. UNRESOLVED STAFF COMMENTS
Pepco Holdings
None.
Pepco
Not applicable.
DPL
Not applicable.
ACE
Not applicable.
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Item 2.
Item 2. PROPERTIES
Generation Facilities
The following table identifies the electric generation facilities owned by PHI's subsidiaries at December 31, 2005.
All holdings of Conectiv Energy are owned by its various subsidiaries.
ACE holds a 3.83% undivided interest as a tenant in common. During the fourth quarter of 2005, ACE entered into an agreement to sell its interest in this generation asset. The sale is expected to be completed by the third quarter of 2006.
ACE holds a 2.47% undivided interest as a tenant in common. During the fourth quarter of 2005, ACE entered into an agreement to sell its interest in this generation asset. The sale is expected to be completed by the third quarter of 2006.
On January 24, 2006, ACE entered into an ACO with the NJDEP agreeing to shut down and permanently cease operations at the B.L. England generating facility by December 15, 2007.
Effective June 2005, the capacity of Hay Road units 1-4 was increased to 545,000 kw.
Owned by a subsidiary of Pepco Energy Services.
This facility is owned by Fauquier Landfill Gas, LLC, of which Pepco Energy Services holds a 75% membership.
This facility is owned by Rolling Hills Landfill Gas, LLC, of which Pepco Energy Services holds an 82% membership.
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The preceding table sets forth the summer electric generating capacity of the electric generating plants owned by Pepco Holdings' subsidiaries. Although, due to thermoelectric factors, 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.
ACE's generation facilities are subject to the lien of the mortgage under which its First Mortgage Bonds are issued.
Transmission and Distribution Systems
On a combined basis, the electric transmission and distribution systems owned by Pepco, DPL and ACE at December 31, 2005 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. Pepco also operates a distribution system control center in Maryland. The computer equipment and systems contained in the 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 45,000 Mcf per day. DPL owns eight natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total sendout capacity of 225,000 Mcf per day. DPL also owns approximately 111 pipeline miles of gas transmission mains, 1,755 pipeline miles of gas distribution mains, and 1,281 gas pipeline miles of service lines. The gas transmission mains include 7.2 miles of pipeline of which DPL owns 10%, which is used for gas operations, and of which Conectiv Energy owns 90%, which is used for delivery of gas to electric generation facilities.
Substantially all of the transmission and distribution property, plant and equipment owned by each of Pepco, DPL and ACE are 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
The legal proceedings for Pepco Holdings consist solely of those of its subsidiaries, as described below.
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
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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, 2005, there are approximately 265 cases still pending against Pepco in the State Courts of Maryland; of those approximately 265 remaining asbestos cases, approximately 85 cases were filed after December 19, 2000, and have been tendered to Mirant Corporation for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement. Mirant's Plan of Reorganization, as approved by the Bankruptcy Court in connection with the Mirant bankruptcy, does not alter Mirant's indemnification obligations. However, litigation relating to Mirant's efforts to reject its contract obligations under the Asset Purchase and Sale Agreement is continuing. In the event Mirant's efforts to reject obligations under the Asset Purchase and Sale Agreement, including the indemnity obligations, were to be successful, Mirant would be relieved of these indemnity obligations and Pepco would have a pre-petition claim for the value of the damages incurred.
While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) exceeds $400 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 and PHI's financial position, results of operations or cash flows.
ENVIRONMENTAL LITIGATION
PHI, through its subsidiaries, is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. PHI's subsidiaries may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of the operating utilities, environmental clean-up costs incurred by Pepco, DPL and ACE would be included by each company in its respective cost of service for ratemaking purposes.
In July 2004, DPL entered into an 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 the 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 has completed and submitted the FS to MDE. The costs for completing the RI/FS for this site were approximately $150,000. The costs of cleanup resulting from the
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RI/FS will not be determinable until MDE identifies the appropriate remedy.
In the early 1970s, both Pepco and DPL sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In December 1987, Pepco and DPL were notified by EPA that they, along with a number of other utilities and non-utilities, were PRPs in connection with the PCB contamination at the site.
In 1994, an RI/FS including a number of possible remedies was submitted to the EPA. In 1997, the EPA issued a Record of Decision that set forth a selected remedial action plan with estimated implementation costs of approximately $17 million. In 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs directing them to conduct the design and actions called for in its decision. In May 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In October 2003, the bankruptcy court confirmed a reorganization plan that incorporates the terms of a settlement among the two debtor owner/operator entities, the United States and a group of utility PRPs including Pepco (the Utility PRPs). Under the bankruptcy settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site (the Bankruptcy Settlement).
On September 2, 2005 the United States lodged with the U.S. District Court for the Eastern District of Pennsylvania global consent decrees for the Metal Bank/Cottman Avenue site, entered into on August 23, 2005 involving the Utility PRPs, the U.S. Department of Justice, EPA, The City of Philadelphia and two owner/operators of the site. Under the terms of the settlement, the two owner/operators will make payments totaling $5.55 million to the U.S. and totaling $4.05 million to the Utility PRPs. The Utility PRPs will perform the remedy at the site and will be able to draw on the $13.25 million from the Bankruptcy Settlement to accomplish the remediation (the Bankruptcy Funds). The Utility PRPs will contribute funds to the extent remediation costs exceed the Bankruptcy Funds available. The Utility PRPs also will be liable for EPA costs associated with overseeing the monitoring and operation of the site remedy after the remedy construction is certified to be complete and also the cost of performing the "5 year" review of site conditions required by CERCLA. Any Bankruptcy Funds not spent on the remedy may be used to cover the Utility PRPs' liabilities for future costs. No parties are released from potential liability for damages to natural resources. The global settlement agreement is subject to approval by the court.
As of December 31, 2005, Pepco had accrued $1.7 million to meet its liability for a remedy at the Metal Bank/Cottman Avenue site. While final costs to Pepco of the settlement have not been determined, Pepco believes that its liability at this site will not have a material adverse effect on its financial position, results of operations or cash flows.
In 1999, DPL entered into a de minimis settlement with EPA and paid approximately $107,000 to resolve its liability for cleanup costs at the Metal Bank/Cottman Avenue site. The de minimis settlement did not resolve DPL's responsibility for natural resource damages, if any, at the site. DPL believes that any liability for natural resource damages at this site will not have a material adverse effect on its financial position, results of operations or cash flows.
In June 1992, EPA identified ACE as a PRP at the Bridgeport Rental and Oil Services Superfund site in Logan Township, New Jersey. In September 1996, ACE along with other PRPs signed a consent decree with EPA and NJDEP to address remediation of the site. ACE's liability is limited to .232 percent of the aggregate remediation liability and thus far ACE has made contributions of approximately $105,000. Based on information currently available, ACE
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anticipates that it may be required to contribute approximately an additional $52,000. ACE believes that its liability at this site will not have a material adverse effect on its financial position, results of operations or cash flows.
In November 1991, 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 completed and the NJDEP conditionally approved the report submitted by the parties on the implementation of the remedy in January 2003. In March 2004, NJDEP approved a Ground Water Sampling and Analysis Plan. Positive results of groundwater monitoring events have resulted in a reduced level of groundwater monitoring. In March 2003, EPA demanded from the PRP group reimbursement for EPA's past costs at the site, totaling $168,789. The PRP group objected to the demand for certain costs, but agreed to reimburse EPA approximately $19,000. Based on information currently available, ACE anticipates that its share of additional cost associated with this site will be approximately $626,000. 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.
On January 24, 2006, PHI, Conectiv and ACE entered into an ACO with NJDEP and the Attorney General of New Jersey. This ACO is the definitive agreement contemplated by the April 26, 2004 preliminary settlement agreement among the parties. The ACO resolves the NJDEP's concerns regarding ACE's compliance with NSR requirements with respect to the B.L. England generating facility and various other environmental issues relating to ACE and Conectiv Energy facilities in New Jersey. See Item 1 "Business -- Environmental Matters -- Air Quality Regulation."
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Pepco Holdings, Inc.
None.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
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Part II
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 common stock as reported by the New York Stock Exchange during each quarter in the last two fiscal years.
See 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
PEPCO HOLDINGS, INC.
RESTATEMENT
Pepco Holdings restated its previously reported consolidated financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct the accounting for certain deferred compensation arrangements. The restatement includes the correction of other errors for the same periods, primarily relating to unbilled revenue, taxes, and various accrual accounts, which were considered by management to be immaterial. These other errors would not themselves have required a restatement absent the restatement to correct the accounting for deferred compensation arrangements. This restatement was required solely because the cumulative impact of the correction, if recorded in the fourth quarter of 2005, would have been material to that period's reported net income. See Note 15 "Restatement" for further discussion.
GENERAL OVERVIEW
Pepco Holdings, Inc. (PHI or Pepco Holdings) is a public utility holding company that, through its operating subsidiaries, is engaged primarily in two principal business operations:
·
electricity and natural gas delivery (Power Delivery), and
·
competitive energy generation, marketing and supply (Competitive Energy).
The Power Delivery business is the largest component of PHI's business. For each of the years ended December 31, 2005, 2004, and 2003, the operating revenues of the Power Delivery business (including intercompany amounts) were equal to 58%, 61%, and 55%, respectively, of PHI's consolidated operating revenues, and the operating income of the Power Delivery business (including income from intercompany transactions) was equal to 74%, 70%, and 82% of PHI's consolidated operating income, respectively. The Power Delivery business consists primarily of the transmission, distribution and default supply of electric power, which was responsible for 94%, 95%, and 95% of Power Delivery's operating revenues for the years ended December 31, 2005, 2004, and 2003, respectively, and the distribution of natural gas, which contributed 6%, 5%, and 5% of Power Delivery's operating revenues over the same periods, respectively. Power Delivery represents one operating segment for financial reporting purposes.
The Power Delivery business is conducted by three regulated utility subsidiaries: Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE). Each of these companies is a regulated public utility in the jurisdictions that comprise its service territory. Each company is responsible for the distribution 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 commissions. Each company also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service varies by jurisdiction as follows:
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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
PHI and its subsidiaries refer to this supply service in each of the jurisdictions 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).
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 revenue and income are seasonal, and weather patterns may have a material impact on operating results.
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, 2005, 2004, and 2003, the operating revenues of the Competitive Energy business (including intercompany amounts) were equal to 51%, 50%, and 55%, respectively, of PHI's consolidated operating revenues, and the operating income of the Competitive Energy business (including operating income from intercompany transactions) was 16% and 19% of PHI's consolidated operating income for the years ended December 31, 2005 and 2004, respectively. In 2003, PHI's Competitive Energy operations incurred an operating loss equal to 20% of PHI's consolidated operating income. For the years ended December 31, 2005, 2004 and 2003, amounts equal to 14%, 16% and 16%, 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.
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·
Conectiv Energy provides wholesale electric power, capacity and ancillary services in the wholesale markets administered by PJM Interconnection, LLC (PJM) and also supplies electricity to other wholesale market participants under long- and short-term bilateral contracts. PHI refers to these wholesale supply operations as Merchant Generation. Conectiv Energy has a power supply agreement under which it provides DPL with all of the electric power needed for distribution to its Default Electricity Supply customers in Delaware and Virginia. Conectiv Energy also supplies electric power to satisfy a portion of ACE's Default Electricity Supply load and DPL's Maryland Default Electricity Supply load, as well as Default Electricity Supply load shares of other mid-Atlantic utilities. PHI refers to the supply of energy by Conectiv Energy to utilities to fulfill their Default Electricity Supply obligations as Full Requirements Load Service. Conectiv Energy obtains the electricity required to meet its Merchant Generation and Full Requirements Load Service power supply obligations from its own generation plants, under bilateral contract purchases from other wholesale market participants and from purchases in the PJM 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 Other Power, Oil & Gas Marketing.
·
Pepco Energy Services sells retail electricity and natural gas and provides integrated energy management services, primarily in the mid-Atlantic region, and its subsidiaries own and operate generation plants located in PJM. Pepco Energy Services also provides high voltage construction and maintenance services to utilities and other customers throughout the United States and low voltage electric and telecommunication construction and maintenance services primarily in the Washington, D.C. area.
Conectiv Energy's primary objective is to maximize the value of its generation fleet by leveraging its operational and fuel flexibilities. Pepco Energy's primary objective is to capture retail energy supply and service opportunities primarily 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 to operate the Conectiv Energy plants, and the cost of purchased energy necessary to meet its power supply obligations.
In order to lower its financial exposure related to commodity price fluctuations, Conectiv Energy entered into an agreement consisting of a series of energy contracts with an international investment banking firm. This agreement is designed to hedge approximately 50% of Conectiv Energy's generation output and approximately 50% of its supply obligations, with the intention of providing Conectiv Energy with a more predictable earnings stream during the term of the agreement. This agreement consists of two major components: (i) a fixed price energy supply hedge that will be used to reduce Conectiv Energy's financial exposure under its current Default Electricity Supply commitment to DPL which extends through April 2006 and (ii) a generation off-take agreement under which Conectiv Energy will receive a fixed monthly payment from the counterparty, and the counterparty will receive the profit realized from the sale of approximately 50% of the electricity generated by Conectiv Energy's plants (excluding the Edge Moor facility).
Conectiv Energy has taken steps to hedge its generation output and supply obligations after May 2006 by entering into various new standard product supply agreements, full requirement supply contracts, bilateral energy and capacity sales agreements and various fuel and power supply transactions to hedge the related fuel and power requirements.
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The Competitive Energy business, like the Power Delivery business, is seasonal, and therefore weather patterns can have a material impact on operating results.
Over the last several years, PHI has discontinued its investments in non-energy related businesses, and has sold its aircraft investments and its 50% interest in Starpower Communications LLC (Starpower). Through its subsidiary, Potomac Capital Investment Corporation (PCI), PHI continues to maintain a portfolio of cross-border energy sale-leaseback transactions with a book value at December 31, 2005 of approximately $1.3 billion. This activity constitutes a fourth operating segment, which is designated as "Other Non-Regulated," for financial reporting purposes.
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. This strategy has three primary components:
·
Achieving growing earnings 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 growth through competitive energy businesses that focus primarily on serving the competitive wholesale and retail markets in PJM.
·
Strengthening PHI's credit profile through continued debt reduction efforts.
EARNINGS OVERVIEW
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
PHI's net income for the year ended December 31, 2005 was $371.2 million compared to $260.6 million for the year ended December 31, 2004.
Net income for 2005 included the (charges) and/or credits set forth below (which are presented net of tax and in millions of dollars). The segment that recognized the (charge) or credit is also indicated.
·
Power Delivery
- Favorable impact of the ACE base rate case settlement as follows:
Ordinary loss from write-offs for disallowance of regulatory assets, net of reserve
$ (3.9)
Extraordinary gain from reversal of restructuring reserves
9.0
Aggregate impact
$ 5.1
- Gain on sale of non-utility land, Buzzard Point
$ 40.7
- Increase in income tax expense for the interest accrued on the potential impact of the IRS mixed service cost issue
$(10.9)
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- Gain on Settlement of Pepco TPA Claim and Pepco asbestos claim against Mirant
$ 42.2
·
Conectiv Energy
- Impairment charge to reduce the value of an investment in a jointly owned generation project
$ (2.6)
·
Other Non-Regulated
- Gain related to the final liquidation of a financial investment that was written off in 2001
$ 8.9
Net income for 2004 included the (charges) and/or credits set forth below (which are presented net of tax and in millions of dollars). Where attributable to a single segment, the segment that recognized the (charge) or credit is also indicated.
·
Tax benefits related to issuance of a local jurisdiction's final consolidated tax return regulations, which were retroactive to 2001 (applies to all segments)
$ 13.2
·
Power Delivery
- Gain on disposition of distribution assets associated with Vineland condemnation settlement
$ 8.6
- Severance costs accruals
$ (6.7)
·
Conectiv Energy
- Gain on disposition of assets associated with Vineland co-generation facility
$ 6.6
- Charge associated with the early pay-off of the Bethlehem mid-merit facility debt
$ (7.7)
·
Other Non-Regulated
- Impairment charge used to reduce the book value of the Starpower investment
$ (7.3)
- Charge resulting from a tax settlement with the IRS related to PCI's non-lease financial assets
$(19.7)
Excluding the items listed above, net income would have been $287.8 million in 2005 and $273.6 million in 2004.
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PHI's net income for the year ended December 31, 2005 compared to the year ended December 31, 2004 is set forth in the table below:
Discussion of Segment Net Income Variances (the net income variance amounts are reflected net of tax):
Power Delivery's higher earnings of $75.0 million are primarily due to the following: (i) $42.2 million of increased earnings related to the settlement of the TPA and asbestos claims with Mirant, (ii) $32.1 million of increased earnings related to the gain on sale of assets primarily Buzzard Point non-utility land ($40.7 million), partially offset by the gain on disposition of distribution assets associated with Vineland condemnation settlement ($8.6 million), (iii) $16.7 million of increased earnings related to higher sales (14.7% Cooling Degree Day increase as compared to 2004), (iv) $5.1 million increase attributable to the ACE base rate case settlement, and (v) $14.1 million of increased earnings primarily associated with lower interest expense, other taxes and other net; partially offset by (vi) $5.2 million revenue reduction due to a change in the estimation of unbilled revenue, (vii) $5.9 million decrease due to lower Default Electricity Supply margins primarily due to increased customer migration, partially offset by the implementation of the competitive bid process (change from TPA calculation method), (viii) $7.5 million increase in operation and maintenance expense, primarily employee related costs, system maintenance, software write-off, outside legal fees associated with the Mirant bankruptcy proceedings and transmission matters; partially offset by a reduction in the uncollectible account reserve to reflect the amount expected to be collected on Pepco's Pre-Petition Claims with Mirant, and a decrease in PJM administrative office expenses, and (ix) $16.0 million for increased tax expense (primarily mixed service costs and 2004 tax adjustments).
Conectiv Energy's lower earnings of $12.1 million are primarily due to the following: (i) a $19.3 million decrease due to lower Full Requirements Load Service earnings as a result of higher power costs to meet load obligations, (ii) higher earnings of $6.6 million in 2004 as the result of the gain on disposition associated with Vineland co-generation facility, (iii) a one-time gain of $5.2 million on a group of coal contracts in 2004, and (iv) a $2.6 million impairment charge to reduce the value of an investment in an energy project, partially offset by (v) $9.2 million increase in Merchant Generation earnings, due primarily to higher output and increased spark spreads, (vi) a $3.9 million increase related to Other Power, Oil & Gas Marketing Services (which consists of all Conectiv Energy activities not included in Merchant Generation or Full Requirements Load Service), (vii) a $6.6 million decrease in interest expense primarily due to the early pay-off of the Bethlehem mid-merit facility debt in 2004, and (viii) higher earnings of $2.9 million from lower depreciation expense due to a change in the estimated useful life of
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generation assets.
Pepco Energy Services' higher earnings of $12.8 million are primarily due to the following: (i) $9.2 million increased earnings from its retail commodity business resulting from increased commercial and industrial load acquisition, (ii) $3.6 million increase related to higher generation from its Benning and Buzzard Point power plants, and (iii) $2.9 million increased earnings primarily from energy service activities, partially offset by (iv) $1.5 million decrease related to the 2004 tax benefit related to issuance of a local jurisdiction's final consolidated tax return regulations and (v) a $1.4 million decrease in interest expense.
Other Non-Regulated higher earnings of $22.3 million are primarily due to the following: (i) $19.7 million increase due to a 2004 charge resulting from a tax settlement with the IRS related to PCI's non-lease financial assets, (ii) $8.9 million increase from a gain on the final liquidation of a financial investment that was written off in a prior year, (iii) $7.3 million increase related to an impairment charge to reduce the value of the Starpower investment recorded in 2004, and (iv) $4.8 million gain on the sale of PCI's Solar Electric Generation Stations (SEGS) investment in 2005, partially offset by (v) $8.8 million decrease due to the 2004 tax benefit related to issuance of a local jurisdiction's final consolidated tax return regulations, (vi) $4.8 million due to the gain on sale of aircraft investments in 2004, and (vii) $4.5 million decrease in financing/investment earnings related to 2004 activity.
Corporate and Other higher earnings of $12.6 million are primarily due to a reduction in net interest expense.
CONSOLIDATED RESULTS OF OPERATIONS
The accompanying results of operations discussion is for the year ended December 31, 2005, compared to the year ended December 31, 2004. All amounts in the tables (except sales and customers) are in millions.
Year Ended December 31, 2005 Compared to the Year Ended December 31, 2004
Operating Revenue
A detail of the components of PHI's consolidated operating revenues is as follows:
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Power Delivery Business
The following table categorizes Power Delivery's operating revenue by type of revenue.
Regulated Transmission and Distribution (T&D) Electric Revenue consists of revenue from the transmission and the delivery of electricity to PHI's customers within its service territories at regulated rates.
Default Supply Revenue is the revenue received for Default Electricity Supply. The costs related to the supply of electricity are included in Fuel and Purchased Energy and Other Services Cost of Sales.
Other Electric Revenue consists of utility-related work and services performed on behalf of customers, including other utilities.
Regulated Gas Revenue consists of revenues for on-system natural gas sales and the transportation of natural gas for customers within PHI's service territories at regulated rates.
Other Gas Revenue consists of off-system natural gas sales and the release of excess system capacity.
Electric Operating Revenue
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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 Revenue increased by $51.9 million primarily due to the following: (i) $19.3 million due to customer growth, the result of a 1.5% customer increase in 2005, (ii) $17.6 million increase as a result of a 14.7% increase in Cooling Degree Days in 2005, (iii) $1.9 million (including $3.3 million in tax pass-throughs) increase due to net adjustments for estimated unbilled revenues recorded in the second and fourth quarters of 2005, reflecting a modification in the estimation process, primarily reflecting higher estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers) and (iv) $21.7 million increase in tax pass-throughs, principally a county surcharge (offset in Other Taxes) offset by (v) $8.6 million other sales and rate variances.
Default Electricity Supply
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Default Supply Revenue increased $238.3 million primarily due to the following: (i) $251.9 million due to higher retail energy rates, the result of market-based SOS competitive bid procedures implemented in Maryland in June 2005 and the District of Columbia in February 2005, (ii) $142.2 million increase in wholesale energy revenues resulting from sales of generated and purchased energy into PJM due to higher market prices in 2005, (iii) $44.8 million due to weather (14.7% increase in Cooling Degree Days), (iv) $48.2 million increase due to customer growth, and (v) $8.1 million due to other sales and rate variances, offset by (vi) $245.0 million decrease due primarily to higher commercial customer migration, and (vii) $11.9 million decrease due to net adjustments for estimated unbilled revenues recorded in the second and fourth quarters of 2005, primarily reflecting higher estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers).
Other Electric Revenue increased $2.1 million to $69.9 million from $67.8 million in 2004 primarily due to mutual assistance work related to storm damage in 2005 (offset in Other Operations and Maintenance expense).
Gas Operating Revenue
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Power Delivery'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 $29.0 million primarily due to a $30.6 million increase in the Gas Cost Rate (GCR) effective November 2004 and 2005, due to higher natural gas commodity costs.
Other Gas Revenue increased by $3.9 million to $62.8 million from $58.9 in 2004 primarily due to increased capacity release revenues compared to the same period last year.
Competitive Energy Businesses
Conectiv Energy
The following table divides Conectiv Energy's operating revenues among its major business activities.
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Merchant Generation includes sales of electric power, capacity and ancillary services from its power plants into PJM, tolling arrangements, hedges of generation power and capacity, and fuel-switching activities where the lowest cost fuel is utilized and the more expensive fuel is sold. Excess generation capacity is used to manage risk associated with Full Requirements Load Service.
Full Requirements Load Service includes service provided to affiliated and non-affiliated companies to satisfy Default Energy Supply obligations, other full requirements electric power sales contracts, and related hedges.
Other Power, Oil and Gas Marketing Services consist of all other Conectiv Energy activities not included above. These activities include primarily wholesale gas marketing, oil marketing, a large operating services agreement with an unaffiliated power plant, and the activities of the real-time power desk, which engages in arbitrage between power pools.
Total Conectiv Energy Operating Revenue includes $801.8 million and $820.3 million of affiliate transactions for 2005 and 2004, respectively.
The impact of revenue changes with respect to the Conectiv Energy component of the Competitive Energy business are encompassed within the discussion below under the heading "Conectiv Energy Gross Margin."
Pepco Energy Services
The following table presents Pepco Energy Services' operating revenues.
The increase in Pepco Energy Services' operating revenue of $320.9 million is primarily due to (i) an increase of $228.1 million due to commercial and industrial retail load acquisition by Pepco Energy Services in 2005 at higher prices than in 2004, (ii) an increase of $39.3 million due to higher generation from its Benning and Buzzard Point power plants in 2005 due to warmer weather conditions, and (iii) an increase of $49.5 million due to higher energy services activities in 2005 resulting from contracts signed with customers under which Pepco Energy Services provides services for energy efficiency and high voltage installation projects. As of December 31, 2005, Pepco Energy Services had 2,004 megawatts of commercial and industrial load, as compared to 1,553 megawatts of commercial and industrial load at the end of 2004. In 2005, Pepco Energy Services' power plants generated 237,624 megawatt hours of electricity as compared to 45,836 in 2004.
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:
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Power Delivery Business
Power Delivery's Fuel and Purchased Energy costs increased by $196.3 million primarily due to (i) $326.7 million increase for higher average energy costs resulting from Default Electricity Supply contracts implemented in 2005, (ii) $65.6 million increase due to customer growth, (iii) $33.1 million increase for gas commodity purchases, (iv) $25.8 million increase in other sales and rate variances, offset by (v) $254.9 million decrease due to higher customer migration. This expense is primarily offset in Default Supply Revenue.
Competitive Energy Business
Conectiv Energy
The following table divides Conectiv Energy's Fuel and Purchased Energy and Other Services Cost of Sales among its major business activities.
The totals presented include $217.7 million and $245.4 million of affiliate transactions for 2005 and 2004, respectively.
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 discussion below under the heading "Conectiv Energy Gross Margin."
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Conectiv Energy Gross Margin
Management believes that gross margin (Revenue less Fuel and Purchased Energy and Other Services Cost of Sales) is a better comparative measurement of the primary activities of Conectiv Energy than Revenue and Fuel and Purchased Energy by themselves. Gross margin is a more stable comparative measurement and it is used extensively by management in internal reporting. The following is a summary of gross margins by activity type (Millions of dollars):
Warmer weather during the summer months of 2005 and continued PJM load growth resulted in increased demand for power and higher prices for power, causing higher Merchant Generation output and an increase in the gross margin. The higher gross margin from the sale of generation output was partially offset by negative hedge results.
The 2005 decrease in the Lower Full Requirements Load Service gross margin resulted from higher fuel and energy prices during 2005. Full Requirements Load Service is hedged by both contract purchases with third parties and by the output of the generation plants operated by Conectiv Energy.
Other Power, Oil and Gas Marketing margins decreased because of a one-time gain of $8.7 million on a group of coal contracts in 2004. This was partially offset by higher margin sales for oil marketing ($5.6 million) and gas marketing ($2.0 million) during the fourth quarter of 2005.
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Pepco Energy Services
The following table presents Pepco Energy Services' Fuel and Purchased Energy and Other Services cost of sales.
The increase in Pepco Energy Services' fuel and purchased energy and other services cost of sales of $293.1 million resulted from (i) higher volumes of electricity purchased at higher prices in 2005 to serve commercial and industrial retail customers, (ii) higher fuel and operating costs for the Benning and Buzzard Point power plants in 2005 due to higher electric generation that resulted from warmer weather in 2005, and (iii) higher energy services activities in 2005 resulting from contracts signed with customers under which Pepco Energy Services provides services for energy efficiency and high voltage installation projects.
Other Operation and Maintenance
A detail of PHI's other operation and maintenance expense is as follows:
PHI's other operation and maintenance increased by $19.1 million to $815.7 million for the year ended 2005 from $796.6 million for the year ended 2004 primarily due to the following: (i) a $10.3 million increase in employee related costs, (ii) 9.0 million increase in corporate services allocation, (iii) $3.9 million increase due to the write-off of software, (iv) $3.2 million increase due to mutual assistance work related to storm damage in 2005 (offset in Other Electric Revenues), and (v) $2.1 million increase in maintenance expenses, partially offset by (vi) $4.9 million reduction in the uncollectible account reserve to reflect the amount expected to be collected on Pepco's Pre-Petition Claims with Mirant and (vii) a $5.5 million decrease in PJM administrative expenses.
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Depreciation and Amortization
PHI's depreciation and amortization expenses decreased by $17.9 million to $422.6 million in 2005 from $440.5 million in 2004. The decrease is primarily due to a $7.6 million decrease from a change in depreciation technique resulting from a 2005 final rate order from the NJBPU and a $4.8 million decrease due to a change in the estimated useful lives of Conectiv Energy's generation assets.
Other Taxes
Other taxes increased by $30.8 million to $342.2 million in 2005 from $311.4 million in 2004 due to higher pass-throughs, mainly as the result of a county surcharge rate increase (primarily offset in Regulated T&D Electric Revenue).
Deferred Electric Service Costs
Deferred Electric Service Costs, which relates only to ACE, increased by $83.9 million to $120.2 million in 2005, from $36.3 million in 2004. At December 31, 2005, DESC represents the net expense or over-recovery associated with New Jersey NUGs, market transition change (MTC) and other restructuring items. The $83.9 million increase represents (i) $77.1 million net over-recovery associated with New Jersey BGS, NUGS, market transition charges and other restructuring items, and (ii) $4.5 million in regulatory disallowances (net of amounts previously reserved) associated with the April 2005 NJBPU settlement agreement. ACE's rates for the recovery of those costs are reset annually and the rates will vary from year to year. At December 31, 2005, ACE's balance sheet included as a regulatory liability an over-recovery of $40.9 million with respect to these items, which is net of a $47.3 million reserve for items disallowed by the NJBPU in a ruling that is under appeal.
Gain on Sales of Assets
Pepco Holdings recorded a Gain on Sales of Assets of $86.8 million for the year ended December 31, 2005, compared to $30.0 million for the year ended December 31, 2004. The $86.8 million gain in 2005 primarily consists of: (i) a $68.1 million gain from the 2005 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. The $30.0 million gain in 2004 consists of: (i) a $14.7 million gain from the 2004 condemnation settlement with the City of Vineland relating to the transfer of ACE's distribution assets and customer accounts to the city, (ii) a $6.6 million gain from the 2004 sale of land, and (iii) an $8.3 million gain on the 2004 sale of aircraft investments by PCI.
Gain on Settlement of Claims with Mirant
The Gain on Settlement of Claims with Mirant of $70.5 million represents a settlement (net of customer sharing) with Mirant in the fourth quarter of 2005, of the Pepco TPA Claim ($70 million gain) and a Pepco asbestos claim against the Mirant bankruptcy estate ($.5 million gain).
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Other Income (Expenses)
Other expenses (which are net of other income) decreased by $55.9 million to $285.5 million in 2005 from $341.4 million in 2004, primarily due to the following: (i) a decrease in net interest expense of $35.7 million, which primarily resulted from a $23.6 million decrease due to less debt outstanding during the 2005 period and a decrease of $12.8 million of interest expense that was recorded by Conectiv Energy in 2004 related to costs associated with the prepayment of debt related to the Bethlehem mid-merit facility, (ii) an $11.2 million impairment charge on the Starpower investment that was recorded during 2004, (iii) income of $7.9 million received by PCI in 2005 from the sale and liquidation of energy investments, and (iv) income of $3.9 million in 2005 from cash distributions from a joint-owned co-generation facility, partially offset by (v) an impairment charge of $4.1 million in 2005 related to a Conectiv Energy investment in a jointly owned generation project, and (vi) a pre-tax gain of $11.2 million on a distribution from a co-generation joint-venture that was recognized by Conectiv Energy during the second quarter of 2004.
Income Tax Expense
Pepco Holdings' effective tax rate for the year ended December 31, 2005 was 41% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit), the flow-through of certain book/tax depreciation differences, and changes in estimates related to tax liabilities of prior tax years subject to audit, partially offset by the flow-through of Deferred Investment Tax Credits and tax benefits related to certain leveraged leases.
Pepco Holdings' effective tax rate for the year ended December 31, 2004 was 39% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit), the flow-through of certain book/tax depreciation differences, and the settlement with the IRS on certain non-lease financial assets, partially offset by the flow-through of Deferred Investment Tax Credits and tax benefits related to certain leveraged leases.
Extraordinary Items
On April 19, 2005, ACE, the staff of the New Jersey Board of Public Utilities (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.
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The accompanying results of operations discussion is for the year ended December 31, 2004, compared to the year ended December 31, 2003. 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:
Change
Power Delivery
$4,377.7
$4,015.7
$362.0
Conectiv Energy
2,409.8
2,857.5
(447.7)
Pepco Energy Services
1,166.6
1,126.2
40.4
Other Non-Regulated
87.9
100.1
(12.2)
Corporate and Other
(818.9)
(830.8)
11.9
Total Operating Revenue
$7,223.1
$7,268.7
$(45.6)
Power Delivery Business
The following table categorizes Power Delivery's operating revenue by type of revenue.
Change
Regulated T&D Electric Revenue
$1,566.6
$1,521.0
$45.6
Default Supply Revenue
2,514.7
2,206.1
308.6
Other Electric Revenue
67.8
97.6
(29.8)
Total Electric Operating Revenue
4,149.1
3,824.7
324.4
Regulated Gas Revenue
169.7
150.2
19.5
Other Gas Revenue
58.9
40.8
18.1
Total Gas Operating Revenue
228.6
191.0
37.6
Total Power Delivery Operating Revenue
$4,377.7
$4,015.7
$362.0
Electric Operating Revenue
Regulated T&D Electric Revenue
Change
Residential
$ 597.7
$ 576.2
$21.5
Commercial
692.3
674.7
17.6
Industrial
37.4
41.0
(3.6)
Other (Includes PJM)
239.2
229.1
10.1
Total Regulated T&D Electric Revenue
$1,566.6
$1,521.0
$45.6
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Regulated T&D Electric Sales (Gwh)
Change
Residential
17,759
17,147
Commercial
28,448
27,648
Industrial
4,471
4,874
(403)
Total Regulated T&D Electric Sales
50,678
49,669
1,009
Regulated T&D Electric Customers (000s)
Change
Residential
1,567
1,547
Commercial
Industrial
-
Total Regulated T&D Electric Customers
1,762
1,740
Regulated T&D Electric Sales, as measured on a Gwh basis, increased by 2% in 2004, driven by residential and commercial customer classes. Regulated T&D Revenue increased by $45.6 million primarily due to the following: (i) $14.4 million increase due to growth and average customer usage, (ii) $4.8 million increase due to higher average effective rates, (iii) $9.1 million due to weather, and (iv) $39.9 million increase in tax pass-throughs, principally a county surcharge (offset in Other Taxes expense). These increases were offset by (v) $20.5 million decrease primarily related to PJM network transmission revenue and the impact of customer choice, and (vi) $2.1 million related to a Delaware competitive transition charge that ended in 2003. Cooling Degree Days increased by 11.0% and heating degree days decreased by 6.3% for the year ended December 31, 2004 as compared to the same period in 2003.
Default Electricity Supply
Default Supply Revenue
Change
Residential
$ 993.6
$ 875.2
$118.4
Commercial
1,060.9
946.4
114.5
Industrial
140.7
156.1
(15.4)
Other (Includes PJM)
319.5
228.4
91.1
Total Default Supply Revenue
$2,514.7
$2,206.1
$308.6
Default Electricity Supply Sales (Gwh)
Change
Residential
16,775
16,048
Commercial
19,203
18,134
1,069
Industrial
2,292
2,882
(590)
Other
Total Default Electricity Supply Sales
38,496
37,158
1,338
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Default Electricity Supply Customers (000s)
Change
Residential
1,509
1,460
Commercial
Industrial
-
Other
Total Default Electricity Supply Customers
1,691
1,638
Default Supply Revenue increased $308.6 million primarily due to the following: (i) $109.2 million as the result of higher retail energy rates, the result of effective rate increases in Delaware beginning October 2003 and in Maryland beginning in June and July 2004, (ii) $92.3 million primarily due to a reduction in customer migration in D.C., (iii) $83.1 million increase in wholesale energy prices as the result of higher market prices in 2004, and (iv) $24.4 million increase in average customer usage.
Other Electric Revenue decreased $29.8 million primarily due to a $43.0 million decrease that resulted from the expiration on December 31, 2003 of a contract to supply electricity to Delaware Municipal Electric Corporation (DMEC). This decrease was partially offset by a $14.0 million increase in customer requested work (related costs in Operations and Maintenance expense).
Gas Operating Revenue
Regulated Gas Revenue
Change
Residential
$ 100.2
$ 88.8
$11.4
Commercial
56.7
47.7
9.0
Industrial
8.3
9.2
(.9)
Transportation and Other
4.5
4.5
-
Total Regulated Gas Revenue
$169.7
$150.2
$19.5
Regulated Gas Sales (Bcf)
Change
Residential
8.7
9.0
(.3)
Commercial
5.5
5.5
-
Industrial
1.2
1.6
(.4)
Transportation and Other
6.2
6.8
(.6)
Total Regulated Gas Sales
21.6
22.9
(1.3)
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Regulated Gas Customers (000s)
Change
Residential
Commercial
-
Industrial
-
-
-
Transportation and Other
-
-
-
Total Regulated Gas Customers
Regulated Gas Revenue increased $19.5 million principally due to the following: (i) $21.0 million increase in the Gas Cost Rate due to higher natural gas commodity costs, effective November 1, 2003, (ii) $8.2 million increase in Gas Base Rates due to higher operating expenses and cost of capital, effective December 9, 2003, and (iii) $2.0 million true up adjustment to unbilled revenues in 2003. These increases were partially offset by (iv) $9.4 million decrease due to 2003 being significantly colder than normal, and (v) $2.9 million reduction related to lower industrial sales. Heating degree days decreased 7.1% for the year ended December 31, 2004 as compared to the same period in 2003.
Other Gas Revenue increased $18.1 million largely related to an increase in off-system sales revenues of $17.3 million. The gas sold off-system was made available by warmer winter weather and reduced customer demand.
Competitive Energy Businesses
Conectiv Energy
The following table divides Conectiv Energy's operating revenues among its major business activities.
Change
Merchant Generation
$ 684.5
$ 540.2
$ 144.3
Full Requirements Load Service
960.2
1,630.3
(670.1)
Other Power, Oil and Gas Marketing Services
765.1
687.0
78.1
Total Conectiv Energy Operating Revenue
$2,409.8
$2,857.5
$(447.7)
The totals presented include $820.3 million and $822.1 million of affiliate transactions for 2004 and 2003, respectively.
The impact of revenue changes with respect to the Conectiv Energy component of the Competitive Energy business are encompassed within the discussion below under the heading "Conectiv Energy Gross Margin."
Pepco Energy Services
The following table presents Pepco Energy Services' operating revenues.
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The increase in Pepco Energy Services' operating revenue of $40.4 million resulted from higher volumes of electricity sold to customers in 2004 at more favorable prices than in 2003, partially offset by a decrease in natural gas revenues.
Operating Expenses
Fuel and Purchased Energy and Other Services Cost of Sales
A detail of PHI's consolidated Fuel and Purchased Energy and Other Services Cost of Sales is as follows:
Change
Power Delivery
$2,524.2
$2,295.4
$228.8
Conectiv Energy
2,130.9
2,696.1
(565.2)
Pepco Energy Services
1,064.4
1,033.1
31.3
Corporate and Other
(823.3)
(820.8)
(2.5)
Total
$4,896.2
$5,203.8
$(307.6)
Power Delivery Business
Power Delivery's Fuel and Purchased Energy costs increased by $228.8 million primarily due to the following: (i) a $212.9 million increase related to higher average energy costs, the result of new Default Supply rates for Maryland beginning in June and July 2004 and for New Jersey beginning in June 2004, and less customer migration primarily in D.C., (ii) $45.1 million higher costs due to the increased cost of electricity supply under the Amended Settlement Agreement and Release with Mirant, effective October 2003, and (iii) a $30.2 million increase for gas commodity purchases, partially offset by (iv) $43.0 million related to the DMEC 2003 contract expiration, and (v) a $14.5 million reserve recorded in September 2003 to reflect a potential exposure related to a pre-petition receivable from Mirant for which Pepco filed a creditor's claim in the bankruptcy proceedings.
Competitive Energy Businesses
Conectiv Energy
The following table categorizes Conectiv Energy's Fuel and Purchased Energy and Other Services Cost of Sales into major profit centers.
Change
Merchant Generation
$ 444.3
$ 356.5
$ 87.8
Full Requirements Load Service
933.1
1,591.9
(658.8)
Other Power, Oil & Gas Marketing Services
753.5
747.7
5.8
Total Conectiv Energy Fuel and Purchased
Energy and Other Services Cost of Sales
$2,130.9
$2,696.1
$(565.2)
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Totals presented include $245.4 million and $161.1 million of affiliate transactions for 2004 and 2003, respectively.
The impact of Fuel and Purchased Energy and Other Services Cost of Sales changes for Conectiv Energy's component of the Competitive Energy business is detailed within the discussion below under the heading "Conectiv Energy Gross Margin."
Conectiv Energy Gross Margin
Management believes that gross margin is a better comparative measurement of the primary activities of Conectiv Energy than Revenue and Fuel and Purchased Energy by themselves. Gross margin is a more stable comparative measurement and it is used extensively by management in internal reporting. The following is a summary of gross margins by activity type (Millions of dollars):
The higher Generation gross margin in 2004 was due to the addition of new more efficient combined cycle generation at Bethlehem (which lowered fuel cost and increased Mwhs sold), unit flexibility (which increased margin by providing quick standard controls over unit running time), increased fuel switching (which generated fuel savings) and nuclear unit outages during the 4th quarter of 2004 (which increased output and price for power in eastern PJM). The higher margins were partially offset by cooler than normal summer weather which resulted in lower unit output in 2004. Conectiv Energy's power plants achieved a substantial portion of the increase ($18.9 million) during the month of December 2004 due to unplanned nuclear outages in the region.
The lower Full Requirements Load Service gross margin resulted from the termination of various full requirements load contracts and related power hedges in 2003 which contained
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favorable margins. This was partially offset by higher POLR rates in 2004 and lower cost of sales.
Other Power, Oil and Gas Marketing margins increased primarily because 2003 results included proprietary trading losses totaling $44 million. In addition, 2004 contained a substantial coal contract gain.
Pepco Energy Services
The following table presents Pepco Energy Services' Fuel and Purchased Energy and Other Services cost of sales.
The increase in Pepco Energy Services' fuel and purchased energy and other services cost of sales of $31.3 million resulted from higher volumes of electricity purchased in 2004 to serve customers, partially offset by a decrease in volumes of natural gas purchased in 2004 to serve customers.
Other Operation and Maintenance
PHI's other operation and maintenance increased by $25.2 million to $796.6 million in 2004 from $771.4 million in 2003 primarily due to (i) $12.1 million of customer requested work (offset in Other Electric Revenue), (ii) $10.6 million higher electric system operation and maintenance costs, (iii) $9.4 million in Sarbanes-Oxley external compliance costs, and (iv) $12.8 million in severance costs, partially offset by (v) $10.6 million incremental storm costs primarily related to Hurricane Isabel in September 2003.
Depreciation and Amortization
PHI's depreciation and amortization expenses increased by $18.4 million to $440.5 million in 2004 from $422.1 million in 2003 primarily due to a $17.0 million increase attributable to the Power Delivery business resulting from (i) a $12.8 million increase for amortization of New Jersey bondable transition property as a result of additional transitional bonds issued in December 2003, (ii) $3.8 million for the amortization of the New Jersey deferred service costs balance which began in August 2003, and (iii) a $2.4 million increase for amortization of a regulatory tax asset related to New Jersey stranded costs. Additionally, depreciation expense attributable to the Competitive Energy business increased by $5.9 million from 2003 due to a full year of depreciation expense during 2004 at Conectiv Energy's Bethlehem facility.
Other Taxes
Other taxes increased by $39.2 million to $311.4 million in 2004 from $272.2 million in 2003. This increase primarily resulted from a $30.1 million increase attributable to the Power Delivery business due to higher county surcharge pass-throughs of $33.9 million and $3.6 million higher gross receipts/delivery taxes (offset in Regulated T&D Electric Revenue).
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Deferred Electric Service Costs
Deferred Electric Service Costs (DESC), which relates only to ACE, increased by $43.3 million to $36.3 million in 2004 from a $7.0 million operating expense credit in 2003. At December 31, 2004, DESC represents the net expense or over-recovery associated with New Jersey NUGs, MTC and other restructuring items. A key driver of the $43.3 million change was $27.5 million for the New Jersey deferral disallowance from 2003. ACE's rates for the recovery of these costs are reset annually and the rates will vary from year to year. On ACE's balance sheet, regulatory assets include an under-recovery of $97.4 million as of December 31, 2004. This amount is net of a $46.1 million write-off on previously disallowed items under appeal.
Impairment Losses
The impairment losses recorded by PHI in 2003 consist of an impairment charge of $53.3 million from the cancellation of a CT contract and an $11.0 million aircraft investments impairment.
Gain on Sales of Assets
During 2004, PHI recorded $30.0 million in pre-tax gains on the sale of assets compared to a $68.8 million pre-tax gain in 2003. The 2004 pre-tax gains primarily consist of (i) a $14.7 million pre-tax gain from the condemnation settlement with the City of Vineland relating to the ACE transfer of distribution assets and customer accounts, (ii) an $8.3 million pre-tax gain on the sale of aircraft investments by PCI, and (iii) a $6.6 million pre-tax gain on the sale of land. The $68.8 million pre-tax gain in 2003 represents the gain on the sale of PHI's office building which was owned by PCI.
Other Income (Expenses)
Other expenses (which are net of other income) decreased $91.9 million to $341.4 million in 2004 from $433.3 million in 2003. The decrease was primarily due to a pre-tax impairment charge of $102.6 million related to PHI's investment in Starpower in 2003, compared to a pre-tax impairment charge of $11.2 million related to Starpower that was recorded in 2004.
Preferred Stock Dividend Requirements of Subsidiaries
Preferred Stock Dividend Requirements decreased by $11.1 million to $2.8 million in 2004 from $13.9 million in 2003. Of this decrease, $6.9 million was attributable to SFAS No. 150, which requires that dividends on Mandatorily Redeemable Serial Preferred Stock declared subsequent to July 1, 2003 be recorded as interest expense. An additional $4.6 million of the decrease resulted from lower dividends in 2004 due to the redemption of the Trust Originated Preferred Securities in 2003.
Income Tax Expense
Pepco Holdings' effective tax rate for 2004 was 39% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit), the flow-through of certain book/tax depreciation differences, and the settlement with the IRS on certain non-lease financial assets (which is the primary reason for the higher effective tax rate as compared to 2003), partially offset by the flow-through of Deferred Investment Tax Credits and tax benefits related to certain leveraged leases, and the benefit associated with the retroactive
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adjustment for the issuance of final consolidated tax return regulations by a taxing authority.
Pepco Holdings' effective tax rate for 2003 was 37% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) and the flow-through of certain book/tax depreciation differences, partially offset by the flow-through of Deferred Investment Tax Credits and tax benefits related to certain leveraged leases.
Extraordinary Item
In July 2003, the NJBPU approved the recovery of $149.5 million of stranded costs related to ACE's B.L. England generating facility. As a result of the order, ACE reversed $10.0 million of accruals for the possible disallowances related to these stranded costs. The credit to income of $5.9 million is classified as an extraordinary gain in the financial statements, since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.
CAPITAL RESOURCES AND LIQUIDITY
This section discusses Pepco Holdings' capital structure, cash flow activity, capital spending plans and other uses and sources of capital for 2005 and 2004.
Capital Structure
The components of Pepco Holdings' capital structure are shown below as of December 31, 2005 and 2004 in accordance with GAAP. The table also shows the following adjustments to components of the capital structure made for the reasons discussed in the footnotes to the table: (i) the exclusion from debt of the Transition Bonds issued by ACE Funding, and (ii) the treatment of the Variable Rate Demand Bonds (VRDBs) issued by certain of PHI's subsidiaries as long-term, rather than short-term, debt obligations (Millions of dollars):
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(a)
Consists of Serial Preferred Stock and Redeemable Serial Preferred Stock issued by subsidiaries of PHI.
(b)
In accordance with GAAP, the VRDBs are included in short-term debt on the Balance Sheet of PHI because they are payable on demand by the holder. However, under the terms of the VRDBs, when demand is made for payment by the holder (specifically, when the VRDBs are submitted for purchase by the holder), the VRDBs are remarketed by a remarketing agent on a best efforts basis and the remarketing resets the interest rate at market rates. Due to the creditworthiness of the issuers, PHI expects that any VRDBs submitted for purchase will be successfully remarketed. Because of these characteristics of the VRDBs, PHI, from a debt management standpoint, views the VRDBs (which have nominal maturity dates ranging from 2009 to 2031) as Long-Term Debt and, accordingly, the adjustment reduces Short-Term Debt and increases Long-Term Debt by an amount equal to the principal amount of the VRDBs.
(c)
Adjusted to exclude Transition Bonds issued by ACE Funding. Because repayment of the Transition Bonds is funded solely by charges collected from ACE's customers and is not a general obligation of ACE or PHI, PHI excludes the Transition Bonds from capitalization from a debt management standpoint.
(d)
Adjusted to exclude the current maturities of Transition Bonds issued by ACE Funding.
In 2003, PHI established a goal of reducing its total debt and preferred stock outstanding by $1 billion by the end of 2007 to improve PHI's interest coverage ratios and to achieve a ratio of consolidated equity to total capitalization (excluding Transition Bonds issued by ACE Funding) in the mid-40% range. Because the net proceeds of $278 million from a public offering of PHI common stock in 2004 was not contemplated in the original $1 billion debt reduction plan, PHI raised its debt reduction goal to $1.3 billion by 2007.
PHI expects to meet its debt reduction goal through a combination of internally generated cash, equity issuances through the Shareholder Dividend Reinvestment Plan (DRP), and asset dispositions. (See "Risk Factors" for a description of factors that could cause PHI to not meet this goal.)
The total debt and preferred stock reduction achieved through year end 2005 is $1.14 billion.
Set forth below is a summary of the equity and long-term debt financing activity during 2005 for Pepco Holdings and its subsidiaries.
Pepco Holdings issued 1,228,505 shares of common stock under the DRP and various benefit plans. The proceeds from the issuances were added to PHI's general funds.
Pepco Holdings issued $250 million of floating rate unsecured notes due 2010. The net proceeds of $248.5 million were used to repay commercial paper issued to fund the redemptions of Conectiv debt.
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Pepco issued $175 million of 5.40% senior secured notes due 2035. The net proceeds of $172.8 million, plus additional funds, were used to pay at maturity and redeem higher interest rate securities of $175 million.
DPL issued $100 million of unsecured notes due in 2015. The net proceeds of $98.9 million, plus additional funds, were used to redeem higher interest rate securities of $100 million.
Proceeds from Sale of Claims with Mirant
In December 2005, Pepco received proceeds of $112.9 million for the sale of the Pepco TPA Claim and the Pepco asbestos claim against the Mirant bankruptcy estate. After customer sharing, Pepco recorded a pre-tax gain of $70.5 million related to the settlement of these claims.
Sale of Buzzard Point Property
In August 2005, Pepco sold for $75 million in cash 384,051 square feet of excess non-utility land owned by Pepco 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.
Working Capital
At December 31, 2005, Pepco Holdings' current assets on a consolidated basis totaled $2.2 billion and its current liabilities totaled $2.4 billion. At December 31, 2004, Pepco Holdings' current assets totaled $1.7 billion and its current liabilities totaled $1.9 billion.
PHI's working capital deficit results in large part from the fact that, in the normal course of business, PHI's utility subsidiaries acquire energy supplies for their customers before the supplies are delivered to, metered and billed to customers. Short-term financing is used to meet liquidity needs. Short-term financing is also used, at times, to fund temporary redemptions of long-term debt, until long-term replacement financings are completed.
At December 31, 2005, Pepco Holdings' cash and cash equivalents and its restricted cash, totaled $144.5 million, of which $112.8 million was net cash collateral held by subsidiaries of PHI engaged in Competitive Energy and Default Electricity Supply activities (none of which was held as restricted cash). At December 31, 2004, Pepco Holdings' cash and cash equivalents and its restricted cash totaled $71.5 million, of which $21 million was net cash collateral held by subsidiaries of PHI engaged in Competitive Energy and Default Electricity Supply activities (of which $7.6 million was held as restricted cash). See "Capital Requirements -- Contractual Arrangements with Credit Rating Triggers or Margining Rights" for additional information.
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A detail of PHI's short-term debt balance and its current maturities of long-term debt and project funding balance follows:
Cash Flow Activity
PHI's cash flows for 2005, 2004, and 2003 are summarized below.
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Operating Activities
Cash flows from operating activities are summarized below for 2005, 2004, and 2003.
Net cash provided by operating activities increased by $271.2 million in 2005 as compared to 2004. A $110.6 million increase in net income in 2005 as compared to 2004 is a result of improved operating results at PHI's regulated utilities. Other increases in operating activities include the following: (i) Pepco's receipt of $112.9 million in proceeds in December 2005 for the sale of the Pepco TPA Claim and the Pepco asbestos claim against the Mirant bankruptcy estate, (ii) a decrease of approximately $29 million in interest paid on debt obligations in 2005 as compared to 2004 due to a decrease in outstanding debt, (iii) an increase in power broker payables in 2005 as a result of higher electricity prices, and (iv) an increase from $21 million to $112.8 million in the cash collateral held in connection with Competitive Energy activities.
Cash flows from operating activities increased by $53.3 million to $715.7 million in 2004 from $662.4 million in 2003. The $53.3 million increase was largely the result of improved operating results at PHI's Regulated utilities. Regulated T&D Electric experienced 2% growth in Gwh sales in 2004, and Regulated T&D Revenue increased by $45.6 million primarily due to customer growth and increased average usage, higher average effective rates, and favorable warmer weather.
The Power Delivery business produced over 80% of consolidated cash from operations in 2005, 2004 and 2003.
Investing Activities
The most significant items included in cash flows related to investing activities during 2005, 2004, and 2003 are summarized below.
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Net cash used by investing activities decreased by $83.4 million in 2005 compared to 2004. The decrease is primarily due to a $50.3 million decrease in capital expenditures, net proceeds of $73.7 million received from the sale of non-utility land in 2005, and proceeds of $33.8 million received by PCI from the sale of an energy investment and from the final liquidation of a financial investment that was written off in 2001.
In 2004, capital expenditures decreased $80.8 million to $517.4 million from $598.2 million in 2003. The decrease was primarily due to lower construction expenditures for Conectiv Energy, offset by an increase in Power Delivery capital requirements to upgrade electric transmission and distribution systems.
In 2004, PHI sold its 50% interest in Starpower for $29 million in cash. Additionally in 2004, PCI continued to liquefy its marketable securities portfolio and PHI received proceeds from the sale of aircraft and land.
In 2003, PCI liquidated its marketable securities portfolio. Additionally, in 2003, PHI received cash proceeds of $147.7 million from the sale by PCI of an office building known as Edison Place (which serves as headquarters for PHI and Pepco).
Financing Activities
Net cash used by financing activities increased by $201.9 million in 2005 as compared to 2004.
Common stock dividend payments were $188.9 million in 2005, $176.0 million in 2004 and $170.7 million in 2003. The increase in common dividends paid in 2005 and 2004 was due to the issuance of 14,950,000 shares of common stock in September 2004 and issuances of 1,228,505 and 1,471,936 shares in 2005 and 2004, respectively, of common stock under the DRP.
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Preferred stock redemptions in 2005 totaled $9.0 million and included the following: (i) in October 2005, Pepco redeemed 22,795 shares of its $2.44 Series 1957 Serial Preferred Stock at $1.1 million, 74,103 shares of its $2.46 Series 1958 Serial Preferred Stock at $3.7 million, and 13,148 shares of its $2.28 Series 1965 Serial Preferred Stock at $.7 million, (ii) in August 2005, ACE redeemed 160 shares of its 4.35% Serial Preferred Stock at $.02 million, and (iii) in December 2005, DPL redeemed all of the 35,000 shares of its 6.75% Serial Preferred Stock outstanding at $3.5 million.
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 redemption of $300 million 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 to redeem $100 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.
Described above are $525 million of the $532 million total 2005 long-term debt issuances and $725 million of the $755.8 million total 2005 long-term debt redemptions.
As a result of the 2004 common stock issuance, Pepco Holdings received $278.5 million of proceeds, net of issuance costs of $10.3 million. The proceeds in combination with short-term debt were used to prepay in its entirety the $335 million Conectiv Bethlehem term loan.
In 2004, Pepco redeemed all of the 900,000 shares of $3.40 series mandatorily redeemable preferred stock then outstanding for $45 million, and 165,902 shares of $2.28 series preferred stock for $8.3 million.
In 2004, Pepco Holdings redeemed $200 million of variable rate notes at maturity.
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In 2004, Pepco issued $275 million of secured senior notes with maturities of 10 and 30 years, the net proceeds of which were used to redeem higher interest rate securities of $210 million and to repay short-term debt. Pepco borrowed $100 million under a bank loan due in 2006, and proceeds were used to redeem mandatorily redeemable preferred stock and repay short-term debt. DPL issued $100 million of unsecured notes that mature in 2014, the net proceeds of which were used to redeem trust preferred securities and repay short-term debt. ACE issued $54.7 million of insured auction rate tax-exempt securities and $120 million of secured senior notes which mature in 2029 and 2034, respectively; the net proceeds of $173.2 million were used to redeem higher interest rate securities. Conectiv redeemed $50 million of Medium-Term Notes, and PCI redeemed $86 million of Medium-Term Notes in 2004. In 2004, redemptions of mandatorily redeemable trust preferred securities included $70 million for DPL and $25 million for ACE.
Described above are $649.7 million of the $650.4 million total 2004 long-term debt issuances and $1,149.2 million of the $1,214.7 million total 2004 long-term debt redemptions.
In 2003, Pepco Holdings issued $700 million of unsecured long-term debt with maturities ranging from 1 year to 7 years, the net proceeds of which were used to repay short-term debt. Pepco issued $200 million of secured senior notes, and proceeds were used to refinance $125 million trust preferred securities and repay short-term debt. Pepco redeemed $50 million of First Mortgage Bonds at maturity, $140 million of First Mortgage Bonds, and $15 million of Medium-Term Notes during 2003. DPL issued $33.2 million of tax-exempt bonds having maturities ranging from 5 to 35 years, the net proceeds of which were used to refinance higher interest debt of $33 million. DPL also redeemed $85 million of First Mortgage Bonds at maturity and $32 million of higher interest rate securities. ACE redeemed $40 million of First Mortgage Bonds and $30 million Medium-Term Notes at maturity, and redeemed $58 million of higher interest rate securities. ACE Funding issued $152 million of Transition Bonds with maturities ranging from 8 to 17 years, the net proceeds of which were used to recover the stranded costs associated with an ACE generation asset and transaction costs. PCI redeemed $141 million of Medium-Term Notes in 2003. Conectiv redeemed $50 million of Medium-Term Notes. Also, in 2003, redemptions of mandatorily redeemable trust preferred securities included $125 million for Pepco, and $70 million for ACE.
Described above are $1,085.2 million of the $1,136.9 million total 2003 long-term debt issuances and $647 million of the $692.2 million total 2003 long-term debt redemptions.
Subsequent Financing
On February 9, 2006, certain institutional buyers tentatively agreed to purchase in a private placement $105 million of ACE's senior notes having an interest rate of 5.80% and a term of 30 years. The execution of a definitive purchase agreement and closing is expected on or about March 15, 2006. The proceeds from the notes would be used to repay outstanding commercial paper issued by ACE to fund the payment at maturity of $105 million in principal amount of various issues of medium-term notes.
On March 1, 2006, Pepco redeemed all outstanding shares of its Serial Preferred Stock of each series, at 102% of par, for an aggregate redemption amount of $21.9 million.
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Capital Requirements
Construction Expenditures
Pepco Holdings' construction expenditures for the year ended December 31, 2005 totaled $467.1 million of which $432.1 million was related to the Power Delivery businesses and the remainder related to Conectiv Energy and Pepco Energy Services.
For the five-year period 2006 through 2010, approximate construction expenditures are projected as follows:
These amounts include estimated costs for environmental compliance by PHI's subsidiaries. See Item 1 "Business -- Environmental Matters." Pepco Holdings expects to fund these expenditures through internally generated cash from the Power Delivery businesses.
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. PHI's Board of Directors declared quarterly dividends of 25 cents per share of common stock payable on March 31, 2005, June 30, 2005, September 30, 2005 and December 31, 2005.
On January 26, 2006, Pepco Holdings declared a dividend on common stock of 26 cents per share payable March 31, 2006, to shareholders of record March 10, 2006.
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 the charters of Pepco, DPL and ACE, which impose restrictions on the payment of common stock dividends for the benefit of preferred stockholders.
Pepco's articles of incorporation and DPL's certificate and articles of incorporation each contain provisions restricting the amount of dividends that can be paid on common stock when preferred stock is outstanding if the applicable company's capitalization ratio is less than 25%. For this purpose, the capitalization ratio is equal to (i) common stock capital plus surplus, divided by (ii) total capital (including long-term debt) plus surplus. In addition, DPL's certificate
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and articles of incorporation and ACE's certificate of incorporation each provide that, if preferred stock is outstanding, no dividends may be paid on common stock if, after payment, the applicable company's common stock capital plus surplus would be less than the involuntary liquidation value of the outstanding preferred stock. Pepco has 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 Retirement Plan) that covers substantially all employees of Pepco, DPL and ACE and certain employees of other Pepco Holdings' subsidiaries.
As of the 2005 valuation, the Retirement Plan satisfied the minimum funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA) without requiring any additional funding. However, PHI's funding policy with regard to the Retirement Plan is to maintain a funding level in excess of 100% of its accumulated benefit obligation (ABO). In 2005 and 2004, PHI made discretionary tax-deductible cash contributions to the Retirement Plan in accordance with its funding policy as described below.
In 2005, the ABO for the Retirement Plan increased over 2004, due to the accrual of an additional year of service for participants and a decrease in the discount rate used to value the ABO obligation. The change in the discount rate reflected the continued decline in long-term interest rates in 2005. The Retirement Plan assets achieved returns in 2005 below the 8.50% level assumed in the valuation. As a result of the combination of these factors, in December 2005 PHI contributed $60 million (all of which was funded by ACE) to the Retirement Plan. The contribution was made to ensure that under reasonable assumptions, the funding level at year end would be in excess of 100% of the ABO. In 2004, PHI contributed a total of $10 million (all of which was funded by Pepco) to the Retirement Plan. Assuming no changes to the current pension plan assumptions, PHI projects no funding will be required under ERISA in 2006; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its assets in excess of ABO for the Retirement Plan.
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Contractual Obligations And Commercial Commitments
Summary information about Pepco Holdings' consolidated contractual obligations and commercial commitments at December 31, 2005, is as follows:
(a)
Excludes the PPA Related Obligations that are part of the back-to-back agreement that was entered into with Mirant (See "Relationship with Mirant Corporation" for additional information) and excludes ACE's BGS load supply.
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, 2005, 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 fair value of these commitments and obligations was not required to be recorded in Pepco Holdings' Consolidated Balance Sheets; however, certain energy marketing obligations of Conectiv Energy were recorded. The commitments and obligations, in millions of dollars, were as follows:
1.
Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties related to routine energy sales and procurement obligations, including requirements under BGS contracts entered into with ACE.
2.
Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value related to certain equipment and fleet vehicles held through lease agreements. As of December 31, 2005, obligations under the guarantees were approximately $7.1 million. Assets leased under agreements subject to
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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.
3.
Other guarantees consist of:
·
Pepco Holdings has guaranteed payment of a bond issued by a subsidiary of $14.9 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.
·
Pepco Holdings has guaranteed a subsidiary building lease of $3.4 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, 2005, the guarantees cover the remaining $2.4 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.
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Energy Contract Net Asset Activity
The following table provides detail on changes in net asset or liability position of the Competitive Energy business with respect to energy commodity contracts from one period to the next:
Notes:
(1)
Includes all contracts held for proprietary trading since the discontinuation of that activity in 2003.
(2)
Includes all SFAS No. 133 hedge activity and non-proprietary trading activities marked-to-market through earnings.
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The following table provides the source of fair value information (exchange-traded, provided by other external sources, or modeled internally) used to determine the carrying amount of the Competitive Energy business' total mark-to-market energy contract net assets. The table also provides the maturity, by year, of the Competitive Energy business' mark-to-market energy contract net assets, which indicates when the amounts will settle and either generate cash for, or require payment of cash by, PHI.
PHI uses its best estimates to determine the fair value of the commodity and derivative contracts that its Competitive Energy business hold and sell. The fair values in each category presented below reflect forward prices and volatility factors as of December 31, 2005 and are subject to change as a result of changes in these factors:
Notes:
(1)
Includes all SFAS No. 133 hedge activity and non-proprietary trading activities marked-to-market through AOCI or on the Statement of Earnings, as required.
(2)
Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(3)
The modeled hedge position is a power swap for 50% of the POLR obligation in the DPL territory. The model is used to approximate the forward load quantities. Pricing is derived from the broker market.
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Contractual Arrangements with Credit Rating Triggers or Margining Rights
Under certain contractual arrangements entered into by PHI's subsidiaries in connection with competitive energy 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 one or more levels. 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. As of December 31, 2005, a one-level downgrade in the credit rating of PHI and all of its affected subsidiaries would have required PHI and such subsidiaries to provide aggregate cash collateral or letters of credit of up to approximately $181 million. An additional approximately $328 million of aggregate cash collateral or letters of credit would have been required in the event of subsequent downgrades to below investment grade. 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 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, 2005, Pepco Holdings' subsidiaries engaged in competitive energy activities and default supply activities were in receipt of (a net holder of) cash collateral in the amount of $112.8 million in connection with their competitive energy activities.
Environmental Remediation Obligations
PHI's accrued liabilities as of December 31, 2005 include approximately $22.3 million, of which $5.6 million is expected to be incurred in 2006, for potential cleanup and other costs related to sites at which an operating subsidiary is a 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 principal environmental remediation obligations as of December 31, 2005, were:
·
$6.8 million, of which $1.0 million is expected to be incurred in 2006, payable by DPL in accordance with a consent agreement reached with DNREC during 2001, 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. That plant was sold on June 22, 2001.
·
ACE's entry into a sale agreement in 2000 (which was subsequently terminated) for the B.L. England and Deepwater generating facilities (ACE transferred the Deepwater generating facility to Conectiv Energy on February 29, 2004) triggered the applicability of the New Jersey Industrial Site Recovery Act requiring remediation at these facilities. When the prospective purchaser of these generating facilities terminated the agreement of sale in accordance with the agreement's termination provisions, ACE decided to continue the environmental investigation process at these facilities. ACE and Conectiv Energy are continuing the investigation with oversight from NJDEP. ACE anticipates
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that it will incur approximately $2.2 million in environmental remediation costs, of which $860,000 is expected to be incurred in 2006, associated with the B.L. England generating facility. Conectiv Energy anticipates that it will incur approximately $6.0 million in environmental remediation costs, of which $690,000 is expected to be incurred in 2006, associated with the Deepwater generating facility.
·
As a result of a December 7, 2003 oil spill at the B.L. England generating facility, $811,000 was accrued in December 2003 for estimated clean up, remediation, restoration, and potential NJDEP natural resources damage assessments. As of December 31, 2005, ACE has spent $611,000 for clean up, remediation, and restoration. The remaining liability of $200,000 is anticipated to cover future restoration efforts to be monitored for three years ending in May 2007. The NJDEP natural resource damage assessments, if any, have not been determined at this time.
·
DPL expects to incur costs of approximately $2.6 million in connection with a site located in Wilmington, Delaware, to remediate residual material from the historical operation of a manufactured gas plant. Approximately $2.0 million is expected to be incurred in 2006.
·
Pepco expects to incur approximately $1.3 million for long-term monitoring in connection with a pipeline oil release, of which $140,000 is expected to be incurred in 2006.
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. See "Risk Factors" for a 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 $700 million. Pepco, DPL, and ACE have ongoing commercial paper programs of up to $300 million, up to $275 million, and up to $250 million, respectively. The commercial paper can be issued with maturities up to 270 days from the date of issue. The commercial paper programs of PHI, Pepco, DPL, and ACE are backed by a $1.2 billion credit facility.
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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.
PUHCA Restrictions
Because Pepco Holdings is a public utility holding company that was registered under the Public Utility Holding Company Act of 1935 (PUHCA 1935), it was required to obtain Securities and Exchange Commission (SEC) approval to issue securities. PUHCA 1935 also prohibited Pepco Holdings from borrowing from its subsidiaries. Under an SEC Financing Order dated June 30, 2005 (the Financing Order), Pepco Holdings is authorized to issue equity, preferred securities and debt securities in an aggregate amount not to exceed $6 billion through an authorization period ending June 30, 2008, subject to a ceiling on the effective cost of these funds. Pepco Holdings is also authorized to enter into guarantees to third parties or otherwise provide credit support with respect to obligations of its subsidiaries of up to $3.5 billion. Of this amount, only $1.75 billion may be on behalf of subsidiaries engaged in energy marketing activities. As permitted under FERC regulations promulgated under the newly effective Public Utility Holding Company Act of 2005 (PUHCA 2005), Pepco Holdings will give notice to FERC that it will continue to operate pursuant to the authority granted in the Financing Order until further notice.
Under the Financing Order, Pepco Holdings is limited to issuing no more than an aggregate of 20 million shares of common stock under the DRP and employee benefit plans during the period ending June 30, 2008.
The Financing Order requires that, in order to issue debt or equity securities, including commercial paper, Pepco Holdings must maintain a ratio of common stock equity to total capitalization (consisting of common stock, preferred stock, if any, long-term debt and short-term debt for this purpose) of at least 30 percent. At December 31, 2005, Pepco Holdings' common equity ratio for purposes of the Financing Order was 40.1 percent. The Financing Order also requires that all rated securities issued by Pepco Holdings be rated "investment grade" by at least one nationally recognized rating agency. Accordingly, if Pepco Holdings' common equity ratio were less than 30 percent or if no nationally recognized rating agency rated a security investment grade, Pepco Holdings could not issue the security without first obtaining an amendment to the Financing Order from FERC.
If an amendment to the Financing Order or other FERC authority pursuant to the Federal Power Act or FERC regulations is required to enable Pepco Holdings or any of its subsidiaries to effect a financing, there is no certainty that such an amendment or authority could be obtained nor certainty as to the timing of FERC action.
The foregoing financing limitations also generally apply to Pepco, DPL, ACE and certain other Pepco Holdings' subsidiaries.
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Money Pool
Under the Financing Order, Pepco Holdings has received SEC authorization under PUHCA 1935, which will continue until June 30, 2008 under PUHCA 2005, to establish the Pepco Holdings 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 the PHI 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. Consequently, Pepco Holdings' external borrowing requirements fluctuate based on the amount of funds required to be deposited in the money pool.
REGULATORY AND OTHER MATTERS
Relationship with Mirant Corporation
In 2000, Pepco sold substantially all of its electricity generation assets to Mirant Corporation, formerly Southern Energy, Inc. As part of the Asset Purchase and Sale Agreement, Pepco entered into several ongoing contractual arrangements with Mirant Corporation and certain of its subsidiaries. In July 2003, Mirant Corporation and most of its subsidiaries filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas (the Bankruptcy Court). On December 9, 2005, the Bankruptcy Court approved Mirant's Plan of Reorganization (the Reorganization Plan) and the Mirant business emerged from bankruptcy on January 3, 2006 (the Bankruptcy Emergence Date), in the form of a new corporation of the same name (together with its predecessors, Mirant). However, as discussed below, the Reorganization Plan did not resolve all of the outstanding matters between Pepco and Mirant relating to the Mirant bankruptcy and the litigation between Pepco and Mirant over these matters is ongoing.
Depending on the outcome of ongoing litigation, the Mirant bankruptcy could have a material adverse effect on the results of operations and cash flows of Pepco Holdings and Pepco. However, management believes that Pepco Holdings and Pepco currently have sufficient cash, cash flow and borrowing capacity under their credit facilities and in the capital markets to be able to satisfy any additional cash requirements that may arise due to the Mirant bankruptcy. Accordingly, management does not anticipate that the Mirant bankruptcy will impair the ability of either Pepco Holdings or Pepco to fulfill its contractual obligations or to fund projected capital expenditures. On this basis, management currently does not believe that the Mirant bankruptcy will have a material adverse effect on the financial condition of either company.
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Transition Power Agreements
As part of the Asset Purchase and Sale Agreement, Pepco and Mirant entered into Transition Power Agreements for Maryland and the District of Columbia, respectively (collectively, the TPAs). Under the TPAs, Mirant was obligated to supply Pepco with all of the capacity and energy needed to fulfill Pepco's SOS obligations during the rate cap periods in each jurisdiction immediately following deregulation, which in Maryland extended through June 2004 and in the District of Columbia extended until January 22, 2005.
To avoid the potential rejection of the TPAs by Mirant in the bankruptcy proceeding, Pepco and Mirant in October 2003 entered into an Amended Settlement Agreement and Release (the Settlement Agreement) pursuant to which the terms of the TPAs were modified to increase the purchase price of the capacity and energy supplied by Mirant. In exchange, the Settlement Agreement provided Pepco with an allowed, pre-petition general unsecured claim against Mirant Corporation in the amount of $105 million (the Pepco TPA Claim).
On December 22, 2005, Pepco completed the sale of the Pepco TPA Claim, plus the right to receive accrued interest thereon, to Deutsche Bank for a cash payment of $112.4 million. Additionally, Pepco received $0.5 million in proceeds from Mirant in settlement of an asbestos claim against the Mirant bankruptcy estate. Pepco Holdings and Pepco recognized a total gain of $70.5 million (pre-tax) related to the settlement of these claims. Based on the regulatory settlements entered into in connection with deregulation in Maryland and the District of Columbia, Pepco is obligated to share with its customers the profits it realizes from the provision of SOS during the rate cap periods. The proceeds of the sale of the Pepco TPA Claim will be included in the calculations of the amounts required to be shared with customers in both jurisdictions. Based on the applicable sharing formulas in the respective jurisdictions, Pepco anticipates that customers will receive (through billing credits) approximately $42.3 million of the proceeds over a 12-month period beginning in March 2006 (subject to DCPSC and MPSC approvals).
Power Purchase Agreements
Under agreements with FirstEnergy Corp., formerly Ohio Edison (FirstEnergy), and Allegheny Energy, Inc., both entered into in 1987, Pepco was obligated to purchase 450 megawatts of capacity and energy from FirstEnergy annually through December 2005 (the FirstEnergy PPA). Under the Panda PPA, entered into in 1991, Pepco is obligated to purchase 230 megawatts of capacity and energy from Panda annually through 2021. At the time of the sale of Pepco's generation assets to Mirant, the purchase price of the energy and capacity under the PPAs was, and since that time has continued to be, substantially in excess of the market price. As a part of the Asset Purchase and Sale Agreement, Pepco entered into a "back-to-back" arrangement with Mirant. Under this arrangement, Mirant (i) was obligated, through December 2005, to purchase from Pepco the capacity and energy that Pepco was obligated to purchase under the FirstEnergy PPA at a price equal to Pepco's purchase price from FirstEnergy, and (ii) is obligated through 2021 to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the Panda PPA at a price equal to Pepco's purchase price from Panda (the PPA-Related Obligations). Mirant currently is making these required payments.
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Pepco Pre-Petition Claims
At the time the Reorganization Plan was approved by the Bankruptcy Court, Pepco had pending pre-petition claims against Mirant totaling approximately $28.5 million (the Pre-Petition Claims), consisting of (i) approximately $26 million in payments due to Pepco in respect of the PPA-Related Obligations and (ii) approximately $2.5 million that Pepco has paid to Panda in settlement of certain billing disputes under the Panda PPA that related to periods after the sale of Pepco's generation assets to Mirant and prior to Mirant's bankruptcy filing, for which Pepco believes Mirant is obligated to reimburse it under the terms of the Asset Purchase and Sale Agreement. In the bankruptcy proceeding, Mirant filed an objection to the Pre-Petition Claims. The Pre-Petition Claims were not resolved in the Reorganization Plan and are the subject of ongoing litigation between Pepco and Mirant. To the extent Pepco is successful in its efforts to recover the Pre-Petition Claims, it would receive under the terms of the Reorganization Plan a number of shares of common stock of the new corporation created pursuant to the Reorganization Plan (the New Mirant Common Stock) equal to (i) the amount of the allowed claim (ii) divided by the market price of the New Mirant Common Stock on the Bankruptcy Emergence Date. Because the number of shares is based on the market price of the New Mirant Common Stock on the Bankruptcy Emergence Date, Pepco would receive the benefit, and bear the risk, of any change in the market price of the stock between the Bankruptcy Emergence Date and the date the stock is issued to Pepco.
As of December 31, 2005, Pepco maintained a receivable in the amount of $28.5 million, representing the Pre-Petition Claims, which was offset by a reserve of $14.5 million established by an expense recorded in 2003 to reflect the uncertainty as to whether the entire amount of the Pre-Petition Claims is recoverable. As of December 31, 2005, this reserve was reduced to $9.6 million to reflect the fact that there was no longer an objection to $15 million of Pepco's claim.
Mirant's Efforts to Reject the PPA-Related Obligations and Disgorgement Claims
In August 2003, Mirant filed with the Bankruptcy Court a motion seeking authorization to reject the PPA-Related Obligations (the First Motion to Reject). Upon motions filed with the U.S. District Court for the Northern District of Texas (the District Court) by Pepco and FERC, the District Court in October 2003 withdrew jurisdiction over this matter from the Bankruptcy Court. In December 2003, the District Court denied Mirant's motion to reject the PPA-Related Obligations on jurisdictional grounds. Mirant appealed the District Court's decision to the U.S. Court of Appeals for the Fifth Circuit (the Court of Appeals). In August 2004, the Court of Appeals remanded the case to the District Court holding that the District Court had jurisdiction to rule on the merits of Mirant's rejection motion, suggesting that in doing so the court apply a "more rigorous standard" than the business judgment rule usually applied by bankruptcy courts in ruling on rejection motions.
In December 2004, the District Court issued an order again denying Mirant's motion to reject the PPA-Related Obligations. The District Court found that the PPA-Related Obligations are not severable from the Asset Purchase and Sale Agreement and that the Asset Purchase and Sale Agreement cannot be rejected in part, as Mirant was seeking to do. Mirant has appealed the District Court's order to the Court of Appeals.
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In January 2005, Mirant filed in the Bankruptcy Court a motion seeking to reject certain of its ongoing obligations under the Asset Purchase and Sale Agreement, including the PPA-Related Obligations (the Second Motion to Reject). In March 2005, the District Court entered orders granting Pepco's motion to withdraw jurisdiction over these rejection proceedings from the Bankruptcy Court and ordering Mirant to continue to perform the PPA-Related Obligations (the March 2005 Orders). Mirant has appealed the March 2005 Orders to the Court of Appeals.
In March 2005, Pepco, FERC, the Office of People's Counsel of the District of Columbia (the District of Columbia OPC), the MPSC and the Office of People's Counsel of Maryland (Maryland OPC) filed in the District Court oppositions to the Second Motion to Reject. In August 2005, the District Court issued an order informally staying this matter, pending a decision by the Court of Appeals on the March 2005 Orders.
On February 9, 2006, oral arguments on Mirant's appeals of the District Court's order relating to the First Motion to Reject and the March 2005 Orders were held before the Court of Appeals; an opinion has not yet been issued.
On December 1, 2005, Mirant filed with the Bankruptcy Court a motion seeking to reject the executory parts of the Asset Purchase and Sale Agreement and its obligations under all other related agreements with Pepco, with the exception of Mirant's obligations relating to operation of the electric generating stations owned by Pepco Energy Services (the Third Motion to Reject). The Third Motion to Reject also seeks disgorgement of payments made by Mirant to Pepco in respect of the PPA-Related Obligations after filing of its bankruptcy petition in July 2003 to the extent the payments exceed the market value of the capacity and energy purchased. On December 21, 2005, Pepco filed an opposition to the Third Motion to Reject in the Bankruptcy Court.
On December 1, 2005, Mirant, in an attempt to "recharacterize" the PPA-Related Obligations, filed a complaint with the Bankruptcy Court seeking (i) a declaratory judgment that the payments due under the PPA-Related Obligations to Pepco are pre-petition debt obligations; and (ii) an order entitling Mirant to recover all payments that it made to Pepco on account of these pre-petition obligations after the petition date to the extent permitted under bankruptcy law (i.e., disgorgement).
On December 15, 2005, Pepco filed a motion with the District Court to withdraw jurisdiction over both of the December 1 filings from the Bankruptcy Court. The motion to withdraw and Mirant's underlying complaint have both been stayed pending a decision of the Court of Appeals in the appeals described above.
Each of the theories advanced by Mirant to recover funds paid to Pepco relating to the PPA-Related Obligations as a practical matter seeks reimbursement for the above-market cost of the capacity and energy purchased from Pepco over a period beginning, at the earliest, from the date on which Mirant filed its bankruptcy petition and ending on the date of rejection or the date through which disgorgement is approved. Under these theories, Pepco's financial exposure is the amount paid by Mirant to Pepco in respect of the PPA-Related Obligations during the relevant period, less the amount realized by Mirant from the resale of the purchased energy and capacity. On this basis, Pepco estimates that if Mirant ultimately is successful in rejecting the PPA-Related Obligations or on its alternative claims to recover payments made to Pepco related to the PPA-Related Obligations, Pepco's maximum reimbursement obligation would be
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approximately $263 million as of March 1, 2006.
If Mirant were ultimately successful in its effort to reject its obligations relating to the Panda PPA, Pepco also would lose the benefit on a going-forward basis of the offsetting transaction that negates the financial risk to Pepco of the Panda PPA. Accordingly, if Pepco were required to purchase capacity and energy from Panda commencing as of March 1, 2006, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 17.1 cents), and resold the capacity and energy at market rates projected, given the characteristics of the Panda PPA, to be approximately 11.0 cents per kilowatt hour, Pepco estimates that it would incur losses of approximately $24 million for the remainder of 2006, approximately $30 million in 2007, and approximately $27 million to $38 million annually thereafter through the 2021 contract termination date. These estimates are based in part on current market prices and forward price estimates for energy and capacity, and do not include financing costs, all of which could be subject to significant fluctuation.
Pepco is continuing to exercise all available legal remedies to vigorously oppose Mirant's efforts to reject or recharacterize the PPA-Related Obligations under the Asset Purchase and Sale Agreement in order to protect the interests of its customers and shareholders. While Pepco believes that it has substantial legal bases to oppose these efforts by Mirant, the ultimate legal outcome is uncertain. However, if Pepco is required to repay to Mirant any amounts received from Mirant in respect of the PPA-Related Obligations, Pepco believes it will be entitled to file a claim against the Mirant bankruptcy estate in an amount equal to the amount repaid. Likewise, if Mirant is successful in its efforts to reject its future obligations relating to the Panda PPA, Pepco will have a claim against Mirant in an amount corresponding to the increased costs that it would incur. In either case, Pepco anticipates that Mirant will contest the claim. To the extent Pepco is successful in its efforts to recover on these claims, it would receive, as in the case of the Pre-Petition Claims, a number of shares of New Mirant Common Stock that is calculated using the market price of the New Mirant Common Stock on the Bankruptcy Emergence Date and accordingly would receive the benefit, and bear the risk, of any change in the market price of the stock between the Bankruptcy Emergence Date and the date the stock is issued to Pepco.
Regulatory Recovery of Mirant Bankruptcy Losses
If Mirant were ultimately successful in rejecting the PPA-Related Obligations or on its alternative claims to recover payments made to Pepco related to the PPA-Related Obligations and Pepco's corresponding claims against the Mirant bankruptcy estate are not recovered in full, Pepco would seek authority from the MPSC and the DCPSC to recover its additional costs. Pepco is committed to working with its regulatory authorities to achieve a result that is appropriate for its shareholders and customers. Under the provisions of the settlement agreements approved by the MPSC and the DCPSC in the deregulation proceedings in which Pepco agreed to divest its generation assets under certain conditions, the PPAs were to become assets of Pepco's distribution business if they could not be sold. Pepco believes that these provisions would allow the stranded costs of the PPAs that are not recovered from the Mirant bankruptcy estate to be recovered from Pepco's customers through its distribution rates. If Pepco's interpretation of the settlement agreements is confirmed, Pepco expects to be able to establish the amount of its anticipated recovery from customers as a regulatory asset. However, there is no assurance that Pepco's interpretation of the settlement agreements would be confirmed by the respective public service commissions.
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Pepco's Notice of Administrative Claims
On January 24, 2006, Pepco filed Notice of Administrative Claims in the Bankruptcy Court seeking to recover: (i) costs in excess of $70 million associated with the transmission upgrades necessitated by shut-down of the Potomac River Power Station; and (ii) costs in excess of $8 million due to Mirant's unjustified post-petition delay in executing the certificates needed to permit Pepco to refinance certain tax exempt pollution control bonds. Mirant is expected to oppose both of these claims, which must be approved by the Bankruptcy Court. There is no assurance that Pepco will be able to recover the amounts claimed.
Mirant's Fraudulent Transfer Claim
In July 2005, Mirant filed a complaint in the Bankruptcy Court against Pepco alleging that Mirant's $2.65 billion purchase of Pepco's generating assets in June 2000 constituted a fraudulent transfer for which it seeks compensatory and punitive damages. Mirant alleges in the complaint that the value of Pepco's generation assets was "not fair consideration or fair or reasonably equivalent value for the consideration paid to Pepco" and that the purchase of the assets rendered Mirant insolvent, or, alternatively, that Pepco and Southern Energy, Inc. (as predecessor to Mirant) intended that Mirant would incur debts beyond its ability to pay them.
Pepco believes this claim has no merit and is vigorously contesting the claim, which has been withdrawn to the District Court. On December 5, 2005, the District Court entered a stay pending a decision of the Court of Appeals in the appeals described above.
The SMECO Agreement
As a term of the Asset Purchase and Sale Agreement, Pepco assigned to Mirant a facility and capacity agreement with Southern Maryland Electric Cooperative (SMECO) under which Pepco was obligated to purchase the capacity of an 84-megawatt combustion turbine installed and owned by SMECO at a former Pepco generating facility (the SMECO Agreement). The SMECO Agreement expires in 2015 and contemplates a monthly payment to SMECO of approximately $.5 million. Pepco is responsible to SMECO for the performance of the SMECO Agreement if Mirant fails to perform its obligations thereunder. At this time, Mirant continues to make post-petition payments due to SMECO.
On March 15, 2004, Mirant filed a complaint with the Bankruptcy Court seeking a declaratory judgment that the SMECO Agreement is an unexpired lease of non-residential real property rather than an executory contract and that if Mirant were to successfully reject the agreement, any claim against the bankruptcy estate for damages made by SMECO (or by Pepco as subrogee) would be subject to the provisions of the Bankruptcy Code that limit the recovery of rejection damages by lessors.
On November 22, 2005, the Bankruptcy Court issued an order granting summary judgment in favor of Mirant, finding that the SMECO Agreement is an unexpired lease of nonresidential real property. On the basis of this ruling, any claim by SMECO (or by Pepco as subrogee) for damages arising from a successful rejection are limited to the greater of (i) the amount of future rental payments due over one year, or (ii) 15% of the future rental payments due over the remaining term of the lease, not to exceed three years.
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On December 1, 2005, Mirant filed both a motion with the Bankruptcy Court seeking to reject the SMECO Agreement and a complaint against Pepco and SMECO seeking to recover payments made to SMECO after the entry of the Bankruptcy Court's November 22, 2005 order holding that the SMECO Agreement is a lease of real property. On December 15, 2005, Pepco filed a motion with the District Court to withdraw jurisdiction of this matter from the Bankruptcy Court. The motion to withdraw and Mirant's underlying motion and complaint have been stayed pending a decision of the Court of Appeals in the appeals described above.
If the SMECO Agreement is successfully rejected by Mirant, Pepco will become responsible for the performance of the SMECO Agreement. In addition, if the SMECO Agreement is ultimately determined to be an unexpired lease of nonresidential real property, Pepco's claim for recovery against the Mirant bankruptcy estate would be limited as described above. Pepco estimates that its rejection claim, assuming the SMECO Agreement is determined to be an unexpired lease of nonresidential real property, would be approximately $8 million, and that the amount it would be obligated to pay over the remaining nine years of the SMECO Agreement is approximately $44.3 million. While that amount would be offset by the sale of capacity, under current projections, the market value of the capacity is de minimis.
Rate Proceedings
Delaware
On October 3, 2005, DPL submitted its 2005 gas cost rate (GCR) filing to the DPSC, which permits DPL to recover gas procurement costs through customer rates. In its filing, DPL seeks to increase its GCR by approximately 38% in anticipation of increasing natural gas commodity costs. The proposed rate became effective November 1, 2005, subject to refund pending final Delaware Public Service Commission (DPSC) approval after evidentiary hearings. A public input hearing was held on January 19, 2006. DPSC staff and the Division of the Public Advocate filed testimony on February 20, 2006.
As authorized by the April 16, 2002 settlement agreement in Delaware relating to the acquisition of Conectiv by Pepco (the Delaware Merger Settlement Agreement), on May 4, 2005, DPL filed with the DPSC a proposed increase of approximately $6.2 million in electric transmission service revenues, or about 1.1% of total Delaware retail electric revenues. This revenue increase covers the Delaware retail portion of the increase in the "Delmarva zonal" transmission rates on file with FERC under the PJM Open Access Transmission Tariff (OATT) and other transition of PJM charges. This level of revenue increase will decrease to the extent that competitive suppliers provide the supply portion and its associated transmission service to retail customers. In that circumstance, PJM would charge the competitive retail supplier the PJM OATT rate for transmission service into the Delmarva zone and DPL's charges to the retail customer would exclude as a "shopping credit" an amount equal to the SOS supply charge and the transmission and ancillary charges that would otherwise be charged by DPL to the retail customer. DPL began collecting this rate change for service rendered on and after June 3, 2005, subject to refund pending final approval by the DPSC.
On September 1, 2005, DPL filed with the DPSC its first comprehensive base rate case in ten years. This application was filed as a result of increasing costs and is consistent with a provision in the Delaware Merger Settlement Agreement requiring DPL to file a base rate case by September 1, 2005 and permitting DPL to apply for an increase in rates to be effective no earlier
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than May 1, 2006. In the application, DPL sought approval of an annual increase of approximately $5.1 million in its electric rates, with an increase of approximately $1.6 million to its electric distribution base rates after proposing to assign approximately $3.5 million in costs to the supply component of rates to be collected as part of the SOS. Of the approximately $1.6 million in net increases to its electric distribution base rates, DPL proposed that approximately $1.2 million be recovered through changes in delivery charges and that the remaining approximately $0.4 million be recovered through changes in premise collection and reconnect fees. The full proposed revenue increase is approximately 0.9% of total annual electric utility revenues, while the proposed net increase to distribution rates is 0.2% of total annual electric utility revenues. DPL's distribution revenue requirement is based on a proposed return on common equity of 11%. DPL also has proposed revised depreciation rates and a number of tariff modifications.
On September 20, 2005, the DPSC issued an order approving DPL's request that the rate increase go into effect on May 1, 2006; subject to refund and pending evidentiary hearings. The order also suspends effectiveness of various proposed tariff rule changes until the case is concluded. The discovery process commenced on October 21, 2005. In its direct testimony, DPSC staff has proposed a variety of adjustments to rate base, operating expenses including depreciation and rate of return with an overall recommendation of a distribution base rate revenue decrease of $14.3 million. The DPSC staff's testimony also addresses issues such as rate design, allocation of any rate decrease and positions regarding the DPL's proposals on certain non-rate tariff modifications. The Delaware Division of Public Advocate has proposed many of the same adjustments and others with an overall recommendation of a distribution base rate revenue decrease of $18.9 million. DPL filed rebuttal testimony on January 17, 2006, which supports a distribution base rate revenue increase of $2 million. On January 30, 2006, the DPSC staff requested the Hearing Examiner approve a modification of the procedural schedule in the case to allow for inclusion of testimony regarding recalculation of DPSC staff's proposed depreciation rates to allow for a separate amortization of the cost of removal reserve. DPL objected to this modification of the procedural schedule. The Hearing Examiner issued a letter ruling on February 1, 2006, which denied DPSC staff's request for a modified procedural schedule. On February 2, 2006, DPSC staff filed an emergency motion requesting the DPSC to permit consideration of the issue by the Hearing Examiner in this docket. On February 6, 2006, the DPSC ruled to allow the issue in the case. A revised procedural schedule was established by the Hearing Examiner on February 10, 2006. On February 15, 2006, DPL filed an interlocutory appeal of the Hearing Examiner's ruling on the procedural schedule with the DPSC. On February 28, 2006, the DPSC upheld the Hearing Examiner's ruling and procedural schedule set on February 10, 2006. DPSC staff filed testimony related to this issue on February 17, 2006. DPSC staff's revised depreciation proposal reduces their recommended proposed rate decrease to $18.9 million, plus the amortization of the cost of removal of $58.4 million, which DPSC staff has recommended be returned to customers through either a 5-, 7- or 10-year amortization. DPL continues to oppose the inclusion of this issue in the case for substantive and procedural grounds. Evidentiary hearings were held in early February. Hearings on the separate issue related to the depreciation of the cost of removal are scheduled to be held March 20, 2006. Briefs are due on March 31, 2006 and DPSC deliberation is scheduled to occur on April 25, 2006. DPL cannot predict the outcome of this proceeding.
District of Columbia and Maryland
On February 27, 2006, Pepco filed for the period February 8, 2002 through February 7, 2004 and for the period February 8, 2004 through February 7, 2005, an update to the District of
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Columbia Generation Procurement Credit (GPC), which provides for sharing of the profit from SOS sales; and on February 24, 2006, Pepco filed an update for the period July1, 2003 through June 30, 2004 to the Maryland GPC. The updates to the GPC in both the District of Columbia and Maryland take into account the proceeds from the sale of the $105 million claim against the Mirant bankruptcy estate related to the TPA Settlement on December 13, 2005 for $112.4 million. The filings also incorporate true-ups to previous disbursements in the GPC for both states. In the filings, Pepco requests that $24.3 million be credited to District of Columbia customers and $17.7 million be credited to Maryland customers during the twelve-month-period beginning April 2006.
Federal Energy Regulatory Commission
On January 31, 2005, Pepco, DPL, and ACE filed at FERC to reset their rates for network transmission service using a formula methodology. The companies also sought a 12.4% return on common equity and a 50-basis-point return on equity adder that FERC had made available to transmission utilities who had joined Regional Transmission Organizations and thus turned over control of their assets to an independent entity. FERC issued an order on May 31, 2005, approving the rates to go into effect June 1, 2005, subject to refund, hearings, and further orders. The new rates reflect a decrease of 7.7% in Pepco's transmission rate, and increases of 6.5% and 3.3% in DPL's and ACE's transmission rates, respectively. The companies continue in settlement discussions under the supervision of a FERC administrative law judge and cannot predict the ultimate outcome of this proceeding.
Restructuring Deferral
Pursuant to orders issued by the NJBPU under 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 choose a competitive energy 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) that was 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 and was in addition to the base rate increase discussed above. ACE's recovery of the deferred costs is subject to review and approval by the NJBPU in accordance with EDECA.
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
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further consideration approximately $25.4 million of the deferred balance, and (iv) estimated the overall deferral balance as of July 31, 2003 at $195 million, of which $44.6 million was disallowed recovery by ACE. ACE believes the record does not justify the level of disallowance imposed by the NJBPU in the final order. In August 2004, ACE filed with the Appellate Division of the Superior Court of New Jersey, which hears appeals of New Jersey administrative agencies, including the NJBPU, a Notice of Appeal with respect to the July 2004 final order. ACE's initial brief was filed on August 17, 2005. Cross-appellant briefs on behalf of the Division of the New Jersey Ratepayer Advocate and Cogentrix Energy Inc., the co-owner of two cogeneration power plants with contracts to sell ACE approximately 397 megawatts of electricity, were filed on October 3, 2005. The NJBPU Staff filed briefs on December 12, 2005. ACE filed its reply briefs on January 30, 2006.
Divestiture Cases
District of Columbia
Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed 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 and its implementing regulations. As of December 31, 2005, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generation 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 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, 2005), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($5.3 million as of December 31, 2005) 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 are due by March 21, 2006, and a public hearing will be held on April 5, 2006. Pepco filed a letter with the DCPSC on January 12, 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 will be terminated without the
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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, results of operations or cash flows. It is uncertain when the DCPSC will issue a decision regarding Pepco's divestiture proceeds sharing application.
Maryland
Pepco filed its divestiture proceeds plan application in Maryland 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, 2005, the MPSC allocated portions of EDIT and ADITC associated with the divested generation 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, 2005), 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, 2005), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($9.5 million as of December 31, 2005), 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 on January 12, 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 will be terminated without the issuance of any regulations.
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Pepco has appealed the Hearing Examiner's decision as it relates to the treatment of EDIT and ADITC and corporate reorganization costs to the MPSC. Consistent with Pepco's position in the District of Columbia, Pepco has argued that the only prudent course of action is for the MPSC to await the issuance of final regulations relating to the tax issues or a termination by the IRS of its regulation project without the issuance of any regulations, and then allow the parties to file supplemental briefs on the tax issues. Pepco believes that its calculation of the Maryland customers' share of divestiture proceeds is correct. 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 and make additional gain-sharing payments related 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, results of operations or cash flows.
Default Electricity Supply Proceedings
District of Columbia
Under an order issued by the DCPSC in March 2004, as amended by a DCPSC order issued in July 2004, Pepco is obligated to provide SOS for small commercial and residential customers through May 31, 2011 and for large commercial customers through May 31, 2007. In August 2004, the DCPSC issued an order adopting administrative charges for residential, small and large commercial District of Columbia SOS customers that are intended to allow Pepco to recover the administrative costs incurred to provide the SOS supply. The approved administrative charges include an average margin for Pepco of approximately $.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial District of Columbia SOS customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of SOS customers from each customer class and the load taken by such customers over the time period. The administrative charges went into effect for Pepco's SOS sales on February 8, 2005.
The TPA with Mirant under which Pepco obtained the fixed-rate SOS supply ended on January 22, 2005, while the new SOS supply contracts with the winning bidders in the competitive procurement process began on February 1, 2005. Pepco procured power separately on the market for next-day deliveries to cover the period from January 23 through January 31, 2005, before the new SOS contracts began. Consequently, Pepco had to pay the difference between the procurement cost of power on the market for next-day deliveries and the current SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new SOS rates did not go into effect until February 8, 2005, Pepco had to pay the difference between the procurement cost of power under the new SOS contracts and the SOS rates charged to customers for the period from February 1 to February 7, 2005. The total amount of the difference is estimated to be approximately $8.7 million. This difference, however, was included in the calculation of the GPC for the District of Columbia for the period February 8, 2004 through February 7, 2005, which was filed on July 12, 2005 with the DCPSC. The GPC provides for a sharing between Pepco's customers and shareholders, on an annual basis, of any margins, but not losses, that Pepco earned providing SOS in the District of Columbia during the four-year period from February 8, 2001 through February 7, 2005. At the
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time of the filing, based on the rates paid to Mirant by Pepco under the TPA Settlement, there was no customer sharing. On December 22, 2005 Pepco received $112.4 million in proceeds from the sale of the Pepco TPA Claim against the Mirant bankruptcy estate. A portion of this recovery related to the period February 8, 2004 through February 7, 2005 covered in the July 12 DCPSC filing. As a consequence, on February 27, 2006, Pepco filed with the DCPSC an updated calculation of the customer sharing for this period, which also takes into account the losses incurred during the January 22, 2005 through February 7, 2005 period. The updated filing shows that both residential and commercial customers will receive customer sharing that totals $17.5 million. Without the inclusion of the $8.7 million loss from the January 22, 2005 through February 7, 2005 period, the amount shared with customers would have been approximately $22.7 million, or $5.2 million greater, so that the net effect of the loss on the SOS sales during this period is approximately $3.5 million.
On February 3, 2006, Pepco announced proposed rates for its District of Columbia SOS customers to take effect on June 1, 2006. The new rate will raise the average monthly bill for residential customers by approximately 12%. The proposed rates must be approved by the DCPSC.
Delaware
Under a settlement approved by the DPSC, DPL is required to provide POLR to customers in Delaware through April 2006. DPL is paid for POLR to customers in Delaware at fixed rates established in the settlement. DPL obtains all of the energy needed to fulfill its POLR obligations in Delaware under a supply agreement with its affiliate Conectiv Energy, which terminates in May 2006. DPL does not make any profit or incur any loss on the supply component of the POLR supply that it delivers to its Delaware customers. DPL is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both POLR customers and customers who have selected another energy supplier. These delivery rates generally are frozen through April 2006, except that DPL is allowed to file for a one-time transmission rate change during this period. On March 22, 2005, the DPSC issued an order approving DPL as the SOS provider after May 1, 2006, when DPL's current fixed rate POLR obligation ends. DPL will retain the SOS obligation for an indefinite period until changed by the DPSC, and will purchase the power supply required to satisfy its SOS obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure.
On October 11, 2005, the DPSC approved a settlement agreement, under which DPL will provide SOS to all customer classes, with no specified termination date for SOS. Two categories of SOS will exist: (i) a fixed price SOS available to all but the largest customers; and (ii) an Hourly Priced Service (HPS) for the largest customers. DPL will purchase the power supply required to satisfy its fixed-price SOS obligation from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure. Power to supply the HPS customers will be acquired on next-day and other short-term PJM markets. In addition to the costs of capacity, energy, transmission, and ancillary services associated with the fixed-price SOS and HPS, DPL's initial rates will include a component referred to as the 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 a billing system to be used for billing HPS customers.
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Bids for fixed-priced SOS supply for the May 1, 2006 through May 31, 2007 period were accepted and approved by the DPSC in December 2005 and January 2006. The new SOS rates are scheduled to be effective May 1, 2006.
On February 7, 2006, the Governor of Delaware issued an Executive Order directing the DPSC and other state agencies to examine ways to mitigate the electric rate increases that are expected in May 2006 as a result of rising energy prices. The Executive Order directed the DPSC to examine the feasibility of: (1) deferring or phasing-in the increases; (2) requiring DPL to build generation or enter into long-term supply contracts to meet all, or a portion of, the SOS supply requirements under a traditional regulatory paradigm; (3) directing DPL to conduct integrated resource planning to ensure fuel diversity and least-cost supply alternatives; and (4) requiring DPL to implement demand-side management, conservation and energy efficient programs.
In response to the Executive Order and to help facilitate discussion on several key issues facing the State of Delaware, particularly the issue of rising energy prices, DPL presented a proposed plan to the DPSC on February 28, 2006. A key feature of DPL's proposed plan is a phase-in of rate increases to assist DPL's residential and small commercial customers with the impact of rising energy prices. The proposed phase-in of the rate increase would be in three steps, with one third of the increase to be phased in on May 1, 2006, another one-third on January 1, 2007 and the remainder on June 1, 2007. The phase-in would create a deferral balance of approximately $60 million dollars that would accrue interest and would be recovered through a surcharge imposed for a 24-month period beginning June 1, 2007. DPL believes that this proposal offers a fair and reasonable solution to the concerns identified in the Executive Order.
The Delaware Governor's Cabinet Committee on Energy filed its report with the Governor on March 8, 2006. The report outlines a proposal that recommends: (1) a phase-in of the SOS increase; (2) long-term steps to ensure more stabilized prices and supply; (3) aggregation of the state of Delaware's power needs; and (4) reduction of Delaware's dependence on traditional energy sources through conservation, energy efficiency, and innovation.
DPL intends to file with the DPSC, on or about March 15, 2006, an implementation plan with proposed tariffs based on its proposed phase-in plan as described above. DPL also anticipates that others may advance other legislative or regulatory proposals to address the concerns expressed in the Executive Order. Accordingly, the nature and impact of any changes precipitated by the Executive Order are uncertain and DPL cannot predict at this time whether this phase-in proposal will be implemented.
Maryland
Because of rising energy prices and the resultant expected increases in Pepco's and DPL's rates, on March 3, 2006 the MPSC issued an order initiating an investigation to consider a residential rate stabilization plan for Pepco and DPL. This investigation is driven by the unprecedented national and international events. The MPSC directed the MPSC staff, Pepco and DPL to file comments addressing whether or not the rate stabilization plan that the MPSC adopted for Baltimore Gas & Electric Company in a March 6, 2006 order also should be used for Pepco and DPL. Comments are to be filed by March 16, 2006.
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On March 7, 2006, Pepco and DPL each announced the results of competitive bids to supply electricity to its Maryland SOS customers for one year beginning June 1, 2006. The proposed new rates must be approved formally by the MPSC. Due to significant increases in the cost of fuels used to generate electricity, the average monthly electric bill will increase by about 38.5% and 35% for Pepco's and DPL's Maryland residential customers, respectively.
Virginia
Under amendments to the Virginia Electric Utility Restructuring Act implemented in March 2004, DPL is obligated to offer Default Service to customers in Virginia for an indefinite period until relieved of that obligation by the VSCC. DPL currently obtains all of the energy and capacity needed to fulfill its Default Service obligations in Virginia under a supply agreement with Conectiv Energy that commenced on January 1, 2005 and expires in May 2006 (the 2005 Supply Agreement). A prior agreement, also with Conectiv Energy, terminated effective December 31, 2004. DPL entered into the 2005 Supply Agreement after conducting a competitive bid procedure in which Conectiv Energy was the lowest bidder.
In October 2004, DPL filed an application with the VSCC for approval to increase the rates that DPL charges its Default Service customers to allow it to recover its costs for power under the 2005 Supply Agreement plus an administrative charge and a margin. A VSCC order issued in November 2004 allowed DPL to put interim rates into effect on January 1, 2005, subject to refund if the VSCC subsequently determined the rate is excessive. The interim rates reflected an increase of 1.0247 cents per Kwh to the fuel rate, which provide for recovery of the entire amount being paid by DPL to Conectiv Energy, but did not include an administrative charge or margin, pending further consideration of this issue. In January 2005, the VSCC ruled that the administrative charge and margin are base rate items not recoverable through a fuel clause. In March 2005, the VSCC approved a settlement resolving all other issues and making the interim rates final.
On March 10, 2006, DPL filed a rate increase with the VSCC to reflect proposed rates for its Virginia Default Service customers to take effect on June 1, 2006. The new rates will raise the average monthly bill for residential customers by approximately 43%. The proposed rates must be approved by the VSCC.
New Jersey
On October 12, 2005, the NJBPU, following the evaluation of proposals submitted by ACE and the other three electric distribution companies located in New Jersey, issued an order reaffirming the current BGS auction process for the annual period from June 1, 2006 through May 2007. The NJBPU order maintains the current size and make up of the Commercial and Industrial Energy Pricing class (CIEP) and approved the electric distribution companies' recommended approach for the CIEP auction product, but deferred a decision on the level of the retail margin funds.
Proposed Shut Down of B.L. England Generating Facility
In April 2004, pursuant to a NJBPU order, ACE filed a report with the NJBPU recommending that ACE's B.L. England generating facility, a 447 megawatt plant, be shut down. The report stated that, while operation of the B.L. England generating facility was necessary at the time of the report to satisfy reliability standards, those reliability standards could also be satisfied in
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other ways. The report concluded that, based on B.L. England's current and projected operating costs resulting from compliance with more restrictive environmental requirements, the most cost-effective way in which to meet reliability standards is to shut down the B.L. England generating facility and construct additional transmission enhancements in southern New Jersey.
In December 2004, ACE filed a petition with the NJBPU requesting that the NJBPU establish a proceeding that will consist of a Phase I and Phase II and that the procedural process for the Phase I proceeding require intervention and participation by all persons interested in the prudence of the decision to shut down B.L. England generating facility and the categories of stranded costs associated with shutting down and dismantling the facility and remediation of the site. ACE contemplates that Phase II of this proceeding, which would be initiated by an ACE filing in 2008 or 2009, would establish the actual level of prudently incurred stranded costs to be recovered from customers in rates. The NJBPU has not acted on this petition.
In a January 24, 2006 Administrative Consent Order (ACO) among PHI, Conectiv, ACE, the New Jersey Department of Environmental Protection (NJDEP) and the Attorney General of New Jersey, ACE agreed to shut down and permanently cease operations at the B.L. England generating facility by December 15, 2007 if ACE does not sell the plant. The shut-down of the B.L. England generating facility will be subject to necessary approvals from the relevant agencies and the outcomes of the auction process, discussed under "ACE Auction of Generating Assets," below.
ACE Auction of Generation Assets
In May 2005, ACE announced that it would again auction its electric generation assets, consisting of its B.L. England generating facility and its ownership interests in the Keystone and Conemaugh generating stations. On November 15, 2005, ACE announced an agreement to sell its interests in the Keystone and Conemaugh generating stations to Duquesne Light Holdings Inc. for $173.1 million. The sale, subject to approval by the NJBPU as well as other regulatory agencies and certain other legal conditions, is expected to be completed mid-year 2006.
Based on the expressed need of the potential B.L. England bidders for the details of the ACO relating to the shut down of the plant that was being negotiated between ACE and the NJDEP, ACE elected to delay the final bid due date for B.L. England until such time as a final ACO was complete and available to bidders. With the January 24, 2006 execution of the ACO by all parties, ACE is proceeding with the auction process. Indicative bids were received on February 16, 2006 and final bids are scheduled to be submitted on or about April 19, 2006.
Under the terms of sale, any successful bid for B.L. England must include assumption of all environmental liabilities associated with the plant in accordance with the auction standards previously issued by the NJBPU.
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Any sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. If B.L. England is sold, ACE anticipates that, subject to regulatory approval in Phase II of the proceeding described above, approximately $9.1 million of additional assets may be eligible for recovery as stranded costs. The net gains on the sale of the Keystone and Conemaugh generating stations will be an offset to stranded costs associated with the shutdown of B. L. England or will be offset through other ratemaking adjustments. Testimony filed by ACE with the NJBPU in December 2005 estimated net gains of approximately $126.9 million; however, the net gains ultimately realized will be dependent upon the timing of the closing of the sale of Keystone and Conemaugh generating stations, transaction costs and other factors.
Federal Tax Treatment of Cross-Border Leases
PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which, as of December 31, 2005, had a book value of approximately $1.3 billion, and from which PHI currently derives approximately $55 million per year in tax benefits in the form of interest and depreciation deductions.
On February 11, 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. In addition, on June 29, 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. On May 4, 2005, the IRS issued a Notice of Proposed Adjustment to PHI that challenges the tax benefits realized from interest and depreciation deductions claimed by PHI with respect to these leases for the tax years 2001 and 2002. The tax benefits claimed by PHI with respect to these leases from 2001 through December 31, 2005 were approximately $230 million. 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 proper based on applicable statutes, regulations and case law, and intends to contest the final adjustments proposed by the IRS; however, there is no assurance that PHI's position will prevail.
On November 18, 2005 the U.S. Senate passed The Tax Relief Act of 2005 (S.2020) which would apply passive loss limitation rules to leases with foreign tax indifferent parties effective for taxable years beginning after December 31, 2005, even if the leases were entered into on or prior to March 12, 2004. On December 8, 2005 the U.S. House of Representatives passed the Tax Relief Extension Reconciliation Act of 2005 (H.R. 4297), which does not contain any provision which would modify the current treatment of leases with tax indifferent parties. Enactment into law of a bill that is similar to S.2020 in its current form could result in a material delay of the income tax benefits that PCI would receive in connection with its cross-border energy leases and thereby adversely affect PHI's financial condition and cash flows. The U.S. House of Representatives and the U.S. Senate are expected to hold a conference in the near
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future to reconcile the differences in the two bills to determine the final legislation.
Under SFAS No. 13, as currently interpreted, a settlement with the IRS or a change in tax law that results in a deferral of tax benefits that does not change the total estimated net income from a lease does not require an adjustment to the book value of the lease. However, if the IRS were to disallow, rather than require the deferral of, certain tax deductions related to PHI's leases, 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 disallowed deductions. Such a charge to earnings, if required, is likely to have a material adverse effect on PHI's financial condition, results of operations, and cash flows for the period in which the charge is recorded.
In July 2005, the FASB released a Proposed Staff Position paper that would amend SFAS No. 13 and require a lease to be repriced and the book value adjusted when there is a change or probable change in the timing of tax benefits. Under this proposal, a material change in the timing of cash flows under PHI's cross-border leases as the result of a settlement with the IRS or a change in tax law also would require an adjustment to the book value. If adopted in its proposed form, the application of this guidance could result in a material adverse effect on PHI's financial condition, results of operations, and cash flows, even if a resolution with the IRS or a change in tax law is limited to a deferral of the tax benefits realized by PCI from its leases.
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, which allow the companies to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions have 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. On August 2, 2005, the IRS issued Revenue Ruling 2005-53 (the Revenue Ruling) that will limit the ability of the companies to utilize this method of accounting for income tax purposes on their tax returns for 2004 and prior years. PHI intends to contest any IRS adjustment to its prior year income tax returns based on the Revenue Ruling. However, if the IRS is successful in applying this Revenue Ruling, Pepco, DPL, and ACE would be required to capitalize and depreciate a portion of the construction costs previously deducted and repay the associated income tax benefits, along with interest thereon. During 2005, PHI recorded a $10.9 million increase in income tax expense consisting of $6.0 million for Pepco, $2.9 million for DPL, and $2.0 million for ACE, to account for the accrued interest that would be paid on the portion of tax benefits that PHI estimates would be deferred to future years if the construction costs previously deducted are required to be capitalized and depreciated.
On the same day as the Revenue Ruling was issued, the Treasury Department released 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 all future tax periods beginning in 2005. Under these regulations, Pepco, DPL, and ACE will have to capitalize and depreciate a portion of the construction costs that they have previously deducted and include the impact of this adjustment in taxable income over a two-year period beginning with tax year 2005. PHI is continuing to work with the industry to determine an alternative method of accounting for capitalizable construction costs acceptable to the IRS to replace the method disallowed by the proposed regulations.
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In February 2006, PHI paid approximately $121 million of taxes to cover the amount of taxes management estimates will be payable once a new final method of tax accounting is adopted on its 2005 tax return, due to the proposed regulations. Although the increase in taxable income will be spread over the 2005 and 2006 tax return periods, the cash payments would have all occurred in 2006 with the filing of the 2005 tax return and the ongoing 2006 estimated tax payments. This $121 million tax payment was accelerated to eliminate the need to accrue additional federal interest expense for the potential IRS adjustment related to the previous tax accounting method PHI used during the 2001-2004 tax years.
CRITICAL ACCOUNTING POLICIES
General
The SEC has defined a company's most critical accounting policies as the ones that are most important to the portrayal of its financial condition and results of operations, and which require the company to make its most difficult and subjective judgments, often as a result of the need to make estimates of matters that are inherently uncertain. Critical estimates represent those estimates and assumptions that may be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and that have a material impact on financial condition or operating performance.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America, such as Statement of Position 94-6, "Disclosure of Certain Significant Risks and Uncertainties," requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes.
Examples of significant estimates used by Pepco Holdings include the assessment of contingencies and the need/amount for reserves of future receipts from Mirant (see "Relationship with Mirant Corporation"), 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, and the judgment involved with assessing the probability of recovery of regulatory assets. Additionally, PHI is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of our business. Pepco Holdings records an estimated liability for these proceedings and claims based upon the probable and reasonably estimable criteria contained in SFAS No. 5, "Accounting for Contingencies." 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.
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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.
The provisions of SFAS No. 142, "Goodwill and Other Intangible Assets," require the evaluation of goodwill for impairment at least annually and more frequently if events and circumstances indicate that the asset might be impaired. SFAS No. 142 indicates that if the fair value of a reporting unit is less than its carrying value, including goodwill, an impairment charge may be necessary. The goodwill generated in the transaction by which Pepco acquired Conectiv in 2002 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 tested its goodwill for impairment as of July 1, 2005. This testing concluded that Pepco Holdings' 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. The process of determining fair value is done consistent with the process described in assessing the fair value of goodwill, which is discussed above.
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Derivative Instruments
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 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," and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," 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
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than immediately recognized in the statement 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.
New Accounting Standards
SFAS No. 154
In May 2005, the FASB issued Statement No. 154, "Accounting Changes and Error Corrections (SFAS No. 154), a replacement of APB Opinion No. 20 and FASB Statement No. 3." SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. The reporting of a correction of an error by restating previously issued financial statements is also addressed by SFAS No. 154. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 (the year ended December 31, 2006 for Pepco Holdings). Early adoption is permitted.
SFAS No. 155
In February 2006, the FASB issued Statement No. 155, "Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140" (SFAS No. 155). This Statement amends FASB Statements No. 133, "Accounting for Derivative Instruments and Hedging Activities", and No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." This Statement resolves issues addressed in Statement 133 Implementation Issue No. D1, "Application of Statement 133 to Beneficial Interests in
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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. Pepco Holdings is in the process of evaluating the impact of SFAS No. 155 but does not anticipate that its implementation will have a material impact on Pepco Holdings overall financial condition, results of operations, or cash flows.
SAB 107 and SFAS No. 123R
In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (SAB 107) which provides implementation guidance on the interaction between FASB Statement No. 123 (revised 2004), "Share-Based Payment" (SFAS No. 123R), and certain SEC rules and regulations, as well as guidance on the valuation of share-based payment arrangements for public companies.
In April 2005, the SEC adopted a rule delaying the effective date of SFAS No. 123R for public companies. Under the rule, most registrants must comply with SFAS No. 123R beginning with the first interim or annual reporting period of their first fiscal year beginning after June 15, 2005 (the year ended December 31, 2006 for Pepco Holdings).
In November 2005, the FASB published FASB Staff Position (FSP) FAS 123R-3, "Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards" (FSP FAS 123R-3), which provides guidance regarding an alternative transition election for accounting for the tax effects of share-based payments. FSP FAS 123R-3 was effective upon issuance.
In February 2006, the FASB published FASB Staff Position FAS 123(R)-4, "Classification of Options and Similar Instruments Issued as Employee Compensation that Allow for Cash Settlement upon the Occurrence of a Contingent Event" (FSP FAS 123(R)-4), which incorporate the concept of when cash settlement features of options and similar instruments meet the condition outlined in SAFS No. 123R. FSP FAS 123(R)-4 is effective upon initial adoption of SFAS No.123R or the first reporting period after its issuance, if SFAS No. 123R has been adopted.
Pepco Holdings is in the process of completing its evaluation of the impact of SFAS No. 123R, FSP FAS 123(R)-3, and FSP FAS 123(R)-4, and does not anticipate that their implementation or SAB 107 will have a material effect on Pepco Holdings' overall financial condition, results of operations or cash flows.
FIN 47
Pepco Holdings adopted FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47), on December 31, 2005. A conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity applies even though uncertainty exists about the time and/or method of settlement. FIN 47 requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation, when incurred, if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of the conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists.
In adopting FIN 47, Pepco Holdings identified that it has asset retirement obligations to (1) remove retired underground storage tanks located in multiple locations, (2) cap and monitor an
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ash disposal site, (3) remove asbestos at one generating station and (4) remove thermal equipment installed under contract with a Delaware court house at the termination of the contract. As a result of these obligations, during 2005 Pepco Holdings recorded both a conditional asset retirement obligation of $1.5 million and a de minimis transition liability. Accretion expense for 2005 which relates to the Power Delivery segment has been recorded as a regulatory asset.
EITF 04-13
In September 2005, the FASB ratified EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" (EITF 04-13), which addresses circumstances under which two or more exchange transactions involving inventory with the same counterparty should be viewed as a single exchange transaction for the purposes of evaluating the effect of APB Opinion 29. EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006 (April 1, 2006 for Pepco Holdings). EITF 04-13 would not affect Pepco Holdings' net income, overall financial condition, or cash flows, but rather could result in certain revenues and costs, including wholesale revenues and purchased power expenses, being presented on a net basis. Pepco Holdings is in the process of evaluating the impact of EITF 04-13 on its Consolidated Statements of Earnings presentation of purchases and sales.
RISK FACTORS
The businesses of PHI and its subsidiaries 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 PHI and its subsidiaries, including, depending on the circumstances, their financial condition, results of operations and cash flows.
PHI and its subsidiaries are subject to substantial governmental regulation. If PHI or any of its subsidiaries receives unfavorable regulatory treatment, PHI's business could be negatively affected.
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 public service commissions 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 gas). In addition, the rates that the companies can charge for electricity transmission are 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 its subsidiaries have
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obtained or sought renewal of the material permits, approvals and certificates necessary for their existing operations and that their businesses are conducted in accordance with applicable laws; however, PHI is unable 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 PHI's subsidiaries to incur additional expenses or to change the way they conduct their operations.
PHI's business could be adversely affected by the Mirant bankruptcy.
In 2000, Pepco sold substantially all of its electricity generation assets to Mirant. As part of the sale, Pepco entered into several ongoing contractual arrangements with Mirant and certain of its subsidiaries. On July 14, 2003, Mirant and most of its subsidiaries filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas. Depending on the outcome of the proceedings related to the bankruptcy, the Mirant bankruptcy could adversely affect PHI's business. See "Relationship with Mirant Corporation" for additional information.
Pepco may be required to make additional divestiture proceeds gain-sharing payments to customers in the District of Columbia and Maryland.
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 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 "Regulatory and Other Matters" for additional information.
The operating results of PHI's Power Delivery and Competitive Energy businesses fluctuate on a seasonal basis and can be adversely affected by changes in weather.
PHI's Power Delivery and Competitive Energy businesses are seasonal and weather patterns can have a material impact on their operating performance. Demand for electricity is generally greater in the summer months associated with cooling and demand for electricity and gas is generally greater 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 produced less revenues when weather conditions are milder than normal. Such weather conditions can also negatively impact income from these operations. Energy management services generally are not seasonal.
The facilities of PHI's subsidiaries may not operate as planned or may require significant maintenance expenditures, which could decrease their revenues or increase their expenses.
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Operation of generation, transmission and distribution 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. Furthermore, if PHI's operating subsidiaries are unable to perform their contractual obligations for any of these reasons, they may incur penalties or damages.
The transmission facilities of PHI's Power Delivery business are interconnected with the facilities of other transmission facility owners whose actions could have a negative impact on the operations of PHI's subsidiaries.
The 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 operators to coordinate the operation of portions of the interstate transmission grid. Each of Pepco, DPL and ACE is a member of PJM, which is the regional transmission operator that coordinates the movement of electricity in 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 and the other regional transmission operators 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 and the other regional transmission operators 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 its and PHI's business.
The cost of compliance with environmental laws is significant and new environmental laws may increase the expenses of PHI and its subsidiaries.
The operations of PHI's subsidiaries, both regulated and unregulated, 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 require PHI's subsidiaries to make capital expenditures and to incur other expenditures to, among other things, meet emissions standards, conduct site remediation and perform environmental monitoring. PHI's subsidiaries also may be required to pay significant remediation costs with respect to third party sites. If PHI's subsidiaries fail to comply with applicable environmental laws and regulations, even if caused by factors beyond their 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.
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In addition, PHI's subsidiaries incur costs 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 PHI's subsidiaries fail to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.
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. PHI's current compliance strategy 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 of PHI.
Implementation of PHI's 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 PHI's business, operations, and financial condition.
PHI's Competitive Energy businesses are highly competitive.
The unregulated energy generation, supply and marketing businesses 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 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's Competitive Energy businesses depend upon electric transmission facilities, natural gas pipelines, and 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 transmission, natural gas pipelines, or 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 PHI's Power Delivery and 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
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advances in technology could reduce demand for electricity supply and distribution, which could adversely affect PHI's Power Delivery and Competitive Energy businesses. Changes in technology also could alter the channels through which retail electric customers buy electricity, which could adversely affect PHI's Power Delivery business.
PHI's risk management procedures may not prevent losses in the operation of its Competitive Energy businesses.
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.
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 carry a unique set of risks in their 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. 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 spot 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 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 generation facilities, Pepco Energy Services generally does not enter into wholesale contracts to lock in the forward value of its plants. To the extent
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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.
Acts of terrorism could adversely affect PHI's businesses.
The threat of, or actual acts of, terrorism may affect the operations of PHI and its subsidiaries in unpredictable ways and may cause changes in the insurance markets, force PHI and its subsidiaries to increase security measures and cause disruptions of fuel supplies and markets. If any of PHI's 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, its operations could be adversely affected. Instability in the financial markets as a result of terrorism also could affect the ability of PHI and its subsidiaries to raise needed capital.
The insurance coverage of PHI and its subsidiaries may not be sufficient to cover all casualty losses that they might incur.
PHI and its subsidiaries 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.
PHI and its subsidiaries 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 PHI's Power Delivery and 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.
PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which as of December 31, 2005, had a book value of approximately $1.3 billion and from which PHI currently derives approximately $55 million per year in tax benefits in the form of interest and depreciation deductions. All of PCI's cross-border energy leases are with tax indifferent parties and were entered into prior to 2004. 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. In addition, on June 29, 2005, the IRS published a Coordinated Issue Paper concerning the resolution of audit issues related to such transactions.
PCI's leases have been under examination by the IRS as part of the normal PHI tax audit. On May 4, 2005, the IRS issued a Notice of Proposed Adjustment to PHI that challenges the tax benefits realized from interest and depreciation deductions claimed by PHI with respect to these leases for the tax years 2001 and 2002. The tax benefits claimed by PHI with respect to these leases from 2001 through December 31, 2005 were approximately $230 million. The ultimate
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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 results of operations and cash flows.
In addition, a disallowance, rather than a deferral, of tax benefits to be realized by PHI from these leases will require PHI to adjust the book value of its leases and record a charge to earnings equal to the repricing impact of the disallowed deductions. Such a change would likely have a material adverse effect on PHI's results of operations for the period in which the charge is recorded.
See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory and Other Matters" for additional information.
Pending tax legislation could result in a loss of future tax benefits from cross-border energy sale and lease-back transactions entered into by a PHI subsidiary.
On November 18, 2005, the U.S. Senate passed The Tax Relief Act of 2005 (S.2020) which would apply passive loss limitation rules to leases with foreign tax indifferent parties effective for taxable years beginning after December 31, 2005, even if the leases were entered into on or prior to March 12, 2004. On December 8, 2005, the U.S. House of Representatives passed the Tax Relief Extension Reconciliation Act of 2005 (H.R. 4297), which does not contain any provision which would modify the current treatment of leases with tax indifferent parties. Enactment into law of a bill that is similar to S.2020 in its current form could result in a material delay of the income tax benefits that PCI would receive in connection with its cross-border energy leases and thereby adversely affect PHI's cash flow. 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.
In July 2005, the FASB released a Proposed Staff Position paper that would amend SFAS No. 13 and require a lease to be repriced and the book value adjusted when there is a change or probable change in the timing of tax benefits. Adoption of this Proposed Staff Position Paper and enactment of a bill that is similar to S.2020 could result in a material adverse effect on PHI's results of operations and cash flows.
See "Regulatory and Other Matters" for additional information.
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, which allow the companies to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions have 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. On August 2, 2005, the IRS issued Revenue Ruling 2005-53 (the Revenue Ruling) that will limit the ability of the companies to utilize this method of accounting for income tax purposes on their tax returns for 2004 and prior years. PHI intends to contest any IRS adjustment to its prior year income tax returns based on the Revenue Ruling. However, if the
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IRS is successful in applying this Revenue Ruling, Pepco, DPL, and ACE would be required to capitalize and depreciate a portion of the construction costs previously deducted and repay the associated income tax benefits, along with interest thereon. During 2005, PHI recorded a $10.9 million increase in income tax expense, consisting of $6.0 million for Pepco, $2.9 million for DPL, and $2.0 million for ACE, to account for the accrued interest that would be paid on the portion of tax benefits that PHI estimates would be deferred to future years if the construction costs previously deducted are required to be capitalized and depreciated.
On the same day as the Revenue Ruling was issued, the Treasury Department released 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 all future tax periods beginning in 2005. Under these regulations, Pepco, DPL, and ACE will have to capitalize and depreciate a portion of the construction costs that they have previously deducted, and include the impact of this adjustment in taxable income over a two year period beginning with tax year 2005. PHI is working with the industry to identify an alternative method of accounting for capitalizable construction costs acceptable to the IRS to replace the method disallowed by the proposed regulations.
In February 2006, PHI paid approximately $121 million of taxes to cover the amount of taxes management estimates will be payable once a new final method of tax accounting is adopted on its 2005 tax return, due to the proposed regulations. Although the increase in taxable income will be spread over the 2005 and 2006 tax return periods, the cash payments would have all occurred in 2006 with the filing of the 2005 tax return and the ongoing 2006 estimated tax payments. This $121 million tax payment was accelerated to eliminate the need to accrue additional Federal interest expense for the potential IRS adjustment related to the previous tax accounting method PHI used during the 2001-2004 tax years.
PHI believes that the $121 million tax payment is a reasonable estimate, based on current information, of the additional taxes that will be due once a new method of tax accounting is adopted. For the 2001 through 2004 period currently under audit by the IRS, there is a risk that the IRS could successfully challenge the tax accounting method utilized in 2001 through 2004, and assert additional taxes above the $121 million payment. If the IRS were to be successful in this contention, PHI would be responsible for the additional taxes above the $121 million amount, as well as interest on the additional taxes.
PHI and its subsidiaries are dependent on their ability to successfully access capital markets. An inability to access capital may adversely affect their business.
PHI and its subsidiaries 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 of PHI or its subsidiaries, could increase the cost of borrowing or could adversely affect their 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 its wholesale marketing and financing activities. Disruptions to the capital markets could include, but are not limited to:
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recession or an economic slowdown;
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the bankruptcy of one or more energy companies;
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significant increases in the prices for oil or other fuel;
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a terrorist attack or threatened attacks; or
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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 the financing costs of PHI and its subsidiaries or could adversely affect their ability to access one or more financial markets.
PHI's future defined benefit plan funding obligations are affected by its assumptions regarding the valuation of its benefit obligations and the performance of plan assets; actual experience which varies from the assumptions could result in an obligation of PHI to make significant unplanned cash contributions to the plan.
PHI follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions," in accounting for pension benefits under the Retirement Plan, a non-contributory defined benefit plan. 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, accumulated benefit obligation (ABO), reported pension liability on PHI's balance sheet, and reported annual net periodic pension benefit cost on PHI's statement of earnings.
Furthermore, if actual pension plan experience is different from that which is expected, the ABO could be greater than the fair value of pension plan assets. If this were to occur, PHI could be required to recognize an additional minimum liability as prescribed by SFAS No. 87. The liability would be recorded as a reduction to common equity through a charge to Other Comprehensive Income (OCI), and would not affect net income for the year. The charge to OCI would be restored through common equity in future periods when the fair value of plan assets exceeded the accumulated benefit obligation. PHI's funding policy is to make cash contributions to the pension plan sufficient for plan assets to exceed the ABO, and avoid the recognition of an additional minimum liability.
Use of alternative assumptions could also impact the expected future cash funding requirements for the pension plan if PHI's defined benefit plan did not meet the minimum funding requirements of 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 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
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to make any funds available for such payment. Because the claims of the creditors and preferred stockholders of PHI's subsidiaries 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 preferred stock to receive dividend payments.
Energy companies are subject to adverse publicity, which may render PHI and its subsidiaries 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 recent 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 and PHI's organizational documents may discourage an acquisition of PHI.
The Delaware General Corporation Law and PHI's organizational documents both contain provisions that could impede the removal of PHI's directors and discourage a third party from making a proposal to acquire PHI. 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. PHI has a staggered board of directors that is divided into three classes of equal size, with one class elected each year for a term of three years. At the 2005 Annual Meeting, the shareholders approved an amendment to PHI's Certificate of Incorporation that will eliminate the staggered board over a two-year period. As a result, beginning with the 2007 Annual Meeting, all of the directors will be elected for one-year terms.
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 and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding Pepco Holdings' intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as "may," "will," "should," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "potential" or "continue" or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause PHI's actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.
The forward-looking statements contained herein are qualified in their entirety by reference to the following important factors, which are difficult to predict, contain uncertainties, are beyond Pepco Holdings' control and may cause actual results to differ materially from those contained in forward-looking statements:
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Prevailing governmental policies and regulatory actions affecting the energy industry, including with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;
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Changes in and compliance with environmental and safety laws and policies;
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Weather conditions;
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Population growth rates and demographic patterns;
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Competition for retail and wholesale customers;
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General economic conditions, including potential negative impacts resulting from an economic downturn;
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Growth in demand, sales and capacity to fulfill demand;
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Changes in tax rates or policies or in rates of inflation;
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Potential changes in accounting standards or practices;
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Changes in project costs;
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Unanticipated changes in operating expenses and capital expenditures;
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The ability to obtain funding in the capital markets on favorable terms;
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Restrictions imposed by Federal and/or state regulatory commissions;
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Legal and administrative proceedings (whether civil or criminal) and settlements that influence PHI's business and profitability;
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Pace of entry into new markets;
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Volatility in market demand and prices for energy, capacity and fuel;
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Interest rate fluctuations and credit market concerns; and
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Effects of geopolitical events, including the threat of domestic terrorism.
Any forward-looking statements speak only as to the date of this Annual Report and Pepco Holdings undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for Pepco Holdings to predict all of such factors, nor can Pepco Holdings assess the impact of any such factor on its 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
RESTATEMENT
Pepco restated its previously reported financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct the accounting for certain deferred compensation arrangements. The restatement includes the correction of other errors for the same periods, primarily relating to unbilled revenue, taxes, and various accrual accounts, which were considered by management to be immaterial. These other errors would not themselves have required a restatement absent the restatement to correct the accounting for deferred compensation arrangements. This restatement was required solely because the cumulative impact of the correction, if recorded in the fourth quarter of 2005, would have been material to that period's reported net income. See Note 13 "Restatement" for further discussion.
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 (SOS) in both the District of Columbia and Maryland. Pepco's service territory covers approximately 640 square miles and has a population of approximately 2 million. As of December 31, 2005, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to Washington, D.C. customers.
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 FERC under PUHCA 2005.
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RESULTS OF OPERATIONS
The accompanying results of operations discussion is for the year ended December 31, 2005 compared to the year ended December 31, 2004. 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.
Operating Revenue
The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D (Transmission and Distribution) 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 the revenue Pepco receives for delivery of electricity to its customers for which service Pepco is paid regulated rates. Default Supply Revenue is the revenue received from Default Electricity Supply. The costs related to the supply of electricity 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, rents, late payments, and collection fees.
Regulated T&D Electric
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Regulated T&D Electric Revenue increased by $35.2 million primarily due to the following: (i) $21.7 million increase in tax pass-throughs, offset in Other Taxes, (ii) $10.2 million due to customer growth, the result of a 1.4% customer increase in 2005, (iii) $7.1 million increase in estimated unbilled revenue recorded in the fourth quarter of 2005, primarily reflecting a modification in the estimation process (includes $3.3 million in tax pass-throughs), and (iv) $6.8 million increase due to weather, the result of a 10% increase in Cooling Degree Days in 2005, offset by $10.6 million due to other sales and rate variances.
Default Electricity Supply
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Default Supply Revenue increased by $5.3 million primarily due to: (i) $195.8 million higher retail energy rates, the result of market based SOS beginning in Maryland in July 2004 and in the District of Columbia in February 2005 (partially offset in Fuel and Purchased Energy expense), (ii) $23.9 million due to customer growth, (iii) $9.1 million increase due to weather, and (iv) $5.5 million increase due to other sales and rate variances, partially offset by (v) $227.8 million decrease resulting from higher commercial customer migration, and (vi) $1.2 million decrease in estimated unbilled revenue recorded in the fourth quarter of 2005, primarily reflecting modifications in the estimation process. Default Supply Revenue is partially offset in Fuel and Purchased Power expense.
For the twelve months ended December 31, 2005, Pepco's Maryland customers served by an alternate supplier represented 38% of Pepco's total Maryland sales, and Pepco's District of Columbia customers served by an alternate supplier represented 58% of Pepco's total District of Columbia sales. For the twelve months ended December 31, 2004, Pepco's Maryland customers served by an alternate supplier represented 29% of Pepco's total Maryland sales, and Pepco's District of Columbia customers served by an alternate supplier represented 32% of Pepco's total District of Columbia sales.
Operating Expenses
Fuel and Purchased Energy
Fuel and Purchased Energy increased by $15.5 million to $913.7 million in 2005, from $898.2 million in 2004. The increase is primarily due to: (i) $209.3 million increase in higher average energy costs, the result of new SOS supply contracts in 2005 and (ii) $33.1 million increase due to customer growth and (iii) $3.9 million increase in other sales and rate variances, partially offset by (iv) $230.8 million decrease due to higher commercial customer migration. This expense is primarily offset in Default Supply Revenue.
Other Operation and Maintenance
Other Operation and Maintenance expenses increased by $7.1 million to $280.3 million in 2005, from $273.2 million in 2004. The increase was primarily due to the following: (i) $8.9 million increase in employee related costs, (ii) $3.9 million due to the write-off of software and (iii) $2.0 million in emergency restoration and maintenance expenses, partially offset by (iv) $5.5 million decrease in PJM administrative expenses due to market based SOS in 2005 and (v) $4.9 million reduction in the uncollectible account reserve to reflect the amount expected to be collected on Pepco's Pre-Petition Claims with Mirant.
Depreciation and Amortization
Depreciation and Amortization expenses decreased by $4.5 million to $161.8 million in 2005, from $166.3 million in 2004. The decrease is primarily due to $5.7 million lower amortization of non-regulated assets that have been fully amortized.
Other Taxes
Other Taxes increased by $27.1 million to $276.1 million in 2005, from $249.0 million in 2004. The increase was primarily due to higher pass-throughs, mainly as the result of a county surcharge rate increase (partially offset in Regulated T&D Electric Revenue).
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Gain on Settlement of Claims with Mirant
The Gain on Settlement of Claims with Mirant of $70.5 million represents a settlement (net of customer sharing) with Mirant in the fourth quarter of 2005 related to the TPA between Pepco and Mirant ($70 million gain) and a Pepco asbestos claim against the Mirant bankruptcy estate ($.5 million gain).
Gain on Sales of Assets
Gain on Sales of Assets increased $65.5 million to $72.4 million in 2005, from $6.9 million in 2004. This increase is primarily due to a $68.1 million gain from the sale of non-utility land located at Buzzard Point in the third quarter of 2005.
Other Income (Expenses)
Other Expenses decreased by $10.2 million to a net expense of $63.7 million in 2005, from a net expense of $73.9 million in 2004. This decrease was primarily due to: (i) $3.9 million increase in interest and dividend income, (ii) $2.8 million increase in other income due to higher gross up percentages applied to contributions in aid of construction (offset in Income Tax expense) and (iii) $2.2 million gain from the sale of stock in 2005.
Income Tax Expense
Pepco's effective tax rate for the year ended December 31, 2005 was 44% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit), the flow-through of certain book tax depreciation differences, and changes in estimates related to tax liabilities of prior tax years subject to audit (which, in addition to the mixed service cost issued under IRS Ruling 2005-53, were the reasons for the higher effective tax rate as compared to 2004), partially offset by the flow-through of tax credits.
Pepco's effective tax rate for the year ended December 31, 2004 was 37% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences, partially offset by the flow-through of tax credits and changes in estimates related to tax liabilities of prior tax years subject to audit (which was the primary reason for the lower effective tax rate as compared to 2003).
RISK FACTORS
The business of Pepco is 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 Pepco, including, depending on the circumstances, their results of operations and financial condition.
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Pepco is a public utility that is subject to substantial governmental regulation. If Pepco receives unfavorable regulatory treatment, Pepco's business could be negatively affected.
Pepco's utility business is subject to regulation by various federal, state and local regulatory agencies that significantly affects its operations. Pepco's operations are regulated in Maryland by the MPSC and in Washington, D.C. by the DCPSC with respect to, among other things, the rates it can charge retail customers for the supply and distribution of electricity. In addition, the rates that Pepco can charge for electricity transmission are regulated by FERC. Pepco 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 Pepco to recover its costs of service and earn a reasonable rate of return, Pepco's profitability is affected by the rates it is able to charge. In addition, if the costs incurred by Pepco in operating its transmission and distribution facilities exceed the allowed amounts for costs included in the approved rates, Pepco's financial results will be adversely affected.
Pepco also is required to have numerous permits, approvals and certificates from governmental agencies that regulate its business. Pepco believes that 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, Pepco is unable 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 Pepco to incur additional expenses or to change the way it conducts its operations.
Pepco's business could be adversely affected by the Mirant bankruptcy.
In 2000, Pepco sold substantially all of its electricity generation assets to Mirant. As part of the sale, Pepco entered into several ongoing contractual arrangements with Mirant and certain of its subsidiaries. On July 14, 2003, Mirant and most of its subsidiaries filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas. Depending on the outcome of the proceedings related to bankruptcy, the Mirant bankruptcy could adversely affect Pepco's business. See "Relationship with Mirant Corporation" for additional information.
Pepco may be required to make additional divestiture proceeds gain-sharing payments to customers in the District of Columbia and Maryland.
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 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 "Regulatory and Other Matters" for additional information.
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The operating results of Pepco fluctuate on a seasonal basis and can be adversely affected by changes in weather.
Pepco's electric utility business is seasonal and weather patterns can have a material impact on its operating performance. Demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating as compared to other times of the year. Accordingly, Pepco historically has generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Pepco's facilities may not operate as planned or may require significant maintenance expenditures, which could decrease its revenues or increase its expenses.
Operation of transmission and distribution 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 transmission and distribution delivery systems. Operation of 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. Furthermore, if Pepco is unable to perform its contractual obligations for any of these reasons, it may incur penalties or damages.
Pepco's transmission facilities are interconnected with the facilities of other transmission facility owners whose actions could have a negative impact on Pepco's operations.
The transmission facilities of Pepco 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 operators to coordinate the operation of portions of the interstate transmission grid. Pepco is a member of PJM, which is the regional transmission operator that coordinates the movement of electricity in 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 operates its transmission facilities under the direction and control of PJM. PJM and the other regional transmission operators 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 and the other regional transmission operators may not always be adequate to prevent problems at other utilities from causing service interruptions in the transmission facilities of Pepco. If Pepco were to suffer such a service interruption, it could have a negative impact on its business.
The cost of compliance with environmental laws is significant and new environmental laws may increase Pepco's expenses.
Pepco's operations 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 require
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Pepco to make capital expenditures and to incur other expenditures to, among other things, conduct site remediation and perform environmental monitoring. Pepco also may be required to pay significant remediation costs with respect to third party sites. If Pepco 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, Pepco incurs costs 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 Pepco fails to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.
New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on Pepco's operations or require it to incur significant additional costs. Pepco's current compliance strategy may not successfully address the relevant standards and interpretations of the future.
Changes in technology may adversely affect Pepco's business.
Increased conservation efforts and advances in technology could reduce demand for electricity supply and distribution, which could adversely affect Pepco's business. In addition, changes in technology also could alter the channels through which retail electric customers buy electricity, which could adversely affect Pepco's business.
Acts of terrorism could adversely affect Pepco's business.
The threat of, or actual acts of, terrorism may affect Pepco's operations in unpredictable ways and may cause changes in the insurance markets, force Pepco to increase security measures and cause disruptions of power markets. If any of Pepco's transmission or distribution facilities were to be a direct target, or an indirect casualty, of an act of terrorism, its operations could be adversely affected. Instability in the financial markets as a result of terrorism also could affect the ability of Pepco to raise needed capital.
Pepco's insurance coverage may not be sufficient to cover all casualty losses that it might incur.
Pepco currently has insurance coverage for its facilities and operations in amounts and with deductibles that it considers 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.
Pepco 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 Pepco.
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Pepco is dependent on its ability to successfully access capital markets. An inability to access capital may adversely affect its business.
Pepco relies on access to both short-term money markets and longer-term capital markets as a source of liquidity and to satisfy its capital requirements not satisfied by the cash flow from its operations. Capital market disruptions, or a downgrade in Pepco's credit ratings, could increase the cost of borrowing or could adversely affect its ability to access one or more financial markets. 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, Pepco'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 the financing costs of PHI and its subsidiaries or could adversely affect their ability to access one or more financial markets.
Pepco's future defined benefit plan funding obligations are affected by its assumptions regarding the valuation of its benefit obligations and the performance of plan assets; actual experience which varies from the assumptions could result in an obligation of Pepco to make significant unplanned cash contributions to the plan.
Pepco follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions" in accounting for pension benefits under the Retirement Plan, a non-contributory defined benefit plan. In accordance with these accounting standards, Pepco 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, accumulated benefit obligations (ABO), reported pension liability on Pepco's balance sheet, and reported annual net periodic pension benefit cost on Pepco's statement of earnings.
Furthermore, if actual pension plan experience is different from that which is expected, the ABO could be greater than the fair value of pension plan assets. If this were to occur, Pepco could be required to recognize an additional minimum liability as prescribed by SFAS No. 87. The liability would be recorded as a reduction to common equity through a charge to Other Comprehensive Income (OCI), and would not affect net income for the year. The charge to OCI would be restored through common equity in future periods when the fair value of plan assets exceeded the ABO. Pepco's funding policy is to make cash contributions to the pension plan sufficient for plan assets to exceed the ABO, and avoid the recognition of an additional minimum liability.
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Use of alternative assumptions could also impact the expected future cash funding requirements for the pension plan if Pepco's defined benefit plan did not meet the minimum funding requirements of ERISA.
Energy companies are subject to adverse publicity, which may render Pepco 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 recent 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 Pepco in a favorable light and may cause Pepco to be susceptible to adverse outcomes with respect to decisions by such bodies.
Because Pepco is a wholly owned subsidiary of PHI, PHI can exercise substantial control over its dividend policy and business and operations.
All of the members of Pepco's board of directors, as well as many of Pepco's executive officers, are officers of PHI. Among other decisions, Pepco'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 Pepco's outstanding debt instruments, Pepco's board of directors will base its decisions concerning the amount and timing of dividends, and other business decisions, on Pepco's earnings, cash flow and capital structure, but may also take into account the business plans and financial requirements of PHI and its other subsidiaries.
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:
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·
Prevailing governmental policies and regulatory actions affecting the energy industry, including with respect to 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;
·
Legal and administrative proceedings (whether civil or criminal) and settlements that influence Pepco's business and profitability;
·
Volatility in market demand and prices for energy, capacity and fuel;
·
Interest rate fluctuations and credit market concerns; and
·
Effects of geopolitical events, including the threat of domestic terrorism.
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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
RESTATEMENT
Our parent company, Pepco Holdings, restated its previously reported consolidated financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct the accounting for certain deferred compensation arrangements. The restatement includes the correction of other errors for the same periods, primarily relating to unbilled revenue, taxes, and various accrual accounts, which were considered by management to be immaterial. These other errors would not themselves have required a restatement absent the restatement to correct the accounting for deferred compensation arrangements. The restatement of Pepco Holdings consolidated financial statements was required solely because the cumulative impact of the correction, if recorded in the fourth quarter of 2005, would have been material to that period's reported net income. The restatement to correct the accounting for the deferred compensation arrangements had no impact on DPL; however, DPL restated its previously reported financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to reflect the correction of other errors. The correction of these other errors, primarily relating to unbilled revenue, taxes, and various accrual accounts, was considered by management to be immaterial. See Note 13 "Restatement" for further discussion.
GENERAL OVERVIEW
Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and Virginia. 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, as Standard Offer Service (SOS) in Maryland and in Delaware on and after May 1, 2006, and as Provider of Last Resort 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 1.28 million. As of December 31, 2005, approximately 65% of delivered electricity sales were to Delaware customers, approximately 31% were to Maryland customers, and approximately 4% 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 523,000.
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 FERC under PUHCA 2005.
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RESULTS OF OPERATIONS
The accompanying results of operations discussion is for the year ended December 31, 2005 compared to the year ended December 31, 2004. 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.
Electric Operating Revenue
The table above shows the amount of Electric Operating Revenue earned that is subject to price regulation (Regulated T&D (Transmission and Distribution) 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 DPL receives for delivery of electricity to its customers, for which DPL is paid regulated rates. Default Supply Revenue is the revenue received from Default Electricity Supply. The costs related to the supply of electricity 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, rents, late payments, and collection fees.
Regulated T&D Electric
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Regulated T&D Electric Revenue increased by $13.0 million due primarily to: (i) $5.4 million increase due to other sales and rate variances, (ii) $4.8 million due to customer growth, the result of a 1.8% customer increase in 2005, and (iii) $4.0 million increase due to weather, primarily the result of a 16.7% increase in Cooling Degree Days in 2005, offset by (iv) $1.2 million reduction in estimated unbilled revenue recorded in the second quarter of 2005, primarily reflecting higher estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers).
Default Electricity Supply
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Default Supply Revenue increased $48.0 million due primarily to the following: (i) $39.3 million higher retail energy rates, primarily resulting from new market based Maryland SOS effective June 2005, (ii) $14.5 million increase due to customer growth, (iii) $13.4 million increase due to favorable weather, offset by (iv) $9.0 million decrease due to customer migration, (v) $7.4 million decrease due to other sales and rate variances, and (vi) $2.8 million reduction in estimated unbilled revenue primarily reflecting higher estimated power line losses recorded in the second quarter of 2005. Default Supply Revenue is partially offset in Fuel and Purchased Power expense.
For the twelve months ended December 31, 2005, DPL's Delaware customers served by an alternate supplier represented 10% of DPL's total Delaware sales and DPL's Maryland customers served by an alternate supplier represented 23% of DPL's total Maryland sales. For the twelve months ended December 31, 2004, DPL's Delaware customers served by an alternate supplier represented 11% of DPL's total Delaware sales and DPL's Maryland customers served by an alternate supplier represented 19% of DPL's total Maryland sales.
Other Electric Revenue
Other Electric Revenue increased by $3.9 million to $23.5 million in 2005 from $19.6 million in 2004 primarily due to mutual assistance work related to storm damage in 2005 (primarily offset in Other Operation and Maintenance expense).
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
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Regulated Gas Revenue increased by $29.0 million primarily due to a $30.6 million increase in the Gas Cost Rate (GCR) effective November 2004 and 2005, due to higher natural gas commodity costs (primarily offset in Gas Purchased expense).
Other Gas Revenue
Other Gas Revenue increased by $3.9 to $62.8 million in 2005 from $58.9 million in 2004 primarily due to increased capacity release revenues.
Operating Expenses
Fuel and Purchased Energy
Fuel and Purchased Energy increased by $42.4 million to $698.0 million in 2005 from $655.6 million in 2004. The increase is primarily due to: (i) $33.0 million increase in higher average energy costs, the result of new Maryland SOS supply contracts in June 2005 and (ii) $10.9 million increase due to customer growth and (iii) $6.6 million increase in other sales and rate variances, partially offset by (iv) $8.1 million decrease due to higher customer migration. This expense is primarily offset in Default Supply Revenue.
Gas Purchased
Total Gas Purchased increased by $33.1 million to $196.8 million in 2005 from $163.7 million in 2004. This increase was primarily due to: (i) $30.3 million increase due to higher wholesale commodity costs partially offset by storage injections, (ii) $10.0 million increase in deferred fuel costs, partially offset by (iii) $7.2 million decrease from the settlement of financial hedges (entered into as part of DPL's regulated natural gas hedge program). This expense is primarily offset in Regulated Gas Revenues.
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Other Operation and Maintenance
Other Operation and Maintenance expenses increased by $3.1 million to $180.1 million in 2005 from $177.0 million in 2004. This increase was primarily due to a $3.5 million increase for mutual assistance work related to 2005 storm damage (primarily offset in Other Electric Revenues).
Depreciation and Amortization
Depreciation and Amortization expenses increased by $1.8 million to $75.7 million in 2005 from $73.9 million in 2004, primarily due to utility property additions.
Gain on Sale of Assets
Gain on Sale of Assets represents a $3.6 million gain on sale of land in 2005.
Income Tax Expense
DPL's effective tax rate for the year ended December 31, 2005 was 43% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit), changes in estimates related to tax liabilities of prior tax years subject to audit (primarily due to the mixed service cost issue under IRS Rule 2005-53), and the flow-through of certain book tax depreciation differences partially offset by the flow-through of deferred investment tax credits.
DPL's effective tax rate for the year ended December 31, 2004 was 43% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit), changes in estimates related to tax liabilities of prior tax years subject to audit, and the flow-through of certain book tax depreciation differences partially offset by the flow-through of deferred investment tax credits.
RISK FACTORS
The business of DPL is 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 DPL, including, depending on the circumstances, its results of operations and financial condition.
DPL is a public utility that is subject to substantial governmental regulation. If DPL receives unfavorable regulatory treatment, DPL's business could be negatively affected.
DPL's utility business is subject to regulation by various federal, state and local regulatory agencies that significantly affects its operations. DPL's operations are regulated in Maryland by the MPSC, in Delaware by the DPSC and in Virginia by the VSCC with respect to, among other things, the rates it can charge retail customers for the supply and distribution of electricity and gas. In addition, the rates that DPL can charge for electricity transmission are regulated by FERC. DPL 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 DPL to recover its costs of service and earn a reasonable rate of return, DPL's profitability is affected by the rates it is able to charge. In addition, if the costs incurred by DPL in operating its transmission and distribution facilities exceed the allowed amounts for costs
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included in the approved rates, DPL's financial results will be adversely affected.
DPL also is required to have numerous permits, approvals and certificates from governmental agencies that regulate its business. DPL believes that 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, DPL is unable 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 DPL to incur additional expenses or to change the way it conducts its operations.
The operating results of DPL fluctuate on a seasonal basis and can be adversely affected by changes in weather.
DPL's utility businesses are seasonal and weather patterns can have a material impact on its operating performance. Demand for electricity is generally greater in the summer months associated with cooling and demand for electricity and gas is generally greater in the winter months associated with heating as compared to other times of the year. Accordingly, DPL historically has generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
DPL's facilities may not operate as planned or may require significant maintenance expenditures, which could decrease its revenues or increase its expenses.
Operation of transmission and distribution 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 transmission and distribution delivery systems. Operation of 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. Furthermore, if DPL is unable to perform its contractual obligations for any of these reasons, it may incur penalties or damages.
DPL's transmission facilities are interconnected with the facilities of other transmission facility owners whose actions could have a negative impact on DPL's operations.
The electricity transmission facilities of DPL 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 operators to coordinate the operation of portions of the interstate transmission grid. DPL is a member of PJM, which is the regional transmission operator that coordinates the movement of electricity in 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. DPL operates its transmission facilities under the direction and control of PJM. PJM and the other regional transmission operators 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 and the other regional transmission operators may not always be
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adequate to prevent problems at other utilities from causing service interruptions in the transmission facilities of DPL. If DPL were to suffer such a service interruption, it could have a negative impact on its business.
The cost of compliance with environmental laws is significant and new environmental laws may increase DPL's expenses.
DPL's operations 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 require DPL to make capital expenditures and to incur other expenditures to, among other things, conduct site remediation and perform environmental monitoring. DPL also may be required to pay significant remediation costs with respect to third party sites. If DPL 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, DPL incurs costs 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 DPL fails to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.
New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on DPL's operations or require it to incur significant additional costs. DPL's current compliance strategy may not successfully address the relevant standards and interpretations of the future.
Changes in technology may adversely affect DPL's electricity and gas delivery businesses.
Increased conservation efforts and advances in technology could reduce demand for electricity and gas supply and distribution, which could adversely affect DPL's business. In addition, changes in technology also could alter the channels through which retail electric customers buy electricity, which could adversely affect DPL's business.
Acts of terrorism could adversely affect DPL's business.
The threat of or actual acts of terrorism may affect DPL's operations in unpredictable ways and may cause changes in the insurance markets, force DPL to increase security measures and cause disruptions of power markets. If any of DPL's fuel storage, transmission or distribution facilities were to be a direct target, or an indirect casualty, of an act of terrorism, its operations could be adversely affected. Instability in the financial markets as a result of terrorism also could affect the ability of DPL to raise needed capital.
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DPL's insurance coverage may not be sufficient to cover all casualty losses that it might incur.
DPL currently has insurance coverage for its facilities and operations in amounts and with deductibles that it considers 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.
DPL 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 DPL.
DPL is dependent on its ability to successfully access capital markets. An inability to access capital may adversely affect its business.
DPL relies on access to both short-term money markets and longer-term capital markets as a source of liquidity and to satisfy its capital requirements not satisfied by the cash flow from its operations. Capital market disruptions, or a downgrade in DPL's credit ratings, would increase the cost of borrowing or could adversely affect its ability to access one or more financial markets. 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.
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In accordance with the requirements of the Sarbanes-Oxley Act of 2002, and the SEC rules thereunder, DPL'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 the financing costs of PHI and its subsidiaries or could adversely affect their ability to access one or more financial markets.
DPL's future defined benefit plan funding obligations are affected by its assumptions regarding the valuation of its benefit obligations and the performance of plan assets; actual experience which varies from the assumptions could result in an obligation of DPL to make significant unplanned cash contributions to the plan.
DPL follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions" in accounting for pension benefits under the Retirement Plan, a non-contributory defined benefit plan. In accordance with these accounting standards, DPL 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, accumulated benefit obligations (ABO), reported pension liability on DPL's balance sheet, and reported annual net periodic pension benefit cost on DPL's statement of earnings.
Furthermore, if actual pension plan experience is different from that which is expected, the ABO could be greater than the fair value of pension plan assets. If this were to occur, DPL could be required to recognize an additional minimum liability as prescribed by SFAS No. 87. The liability would be recorded as a reduction to common equity through a charge to Other Comprehensive Income (OCI), and would not affect net income for the year. The charge to OCI would be restored through common equity in future periods when the fair value of plan assets exceeded the ABO. DPL's funding policy is to make cash contributions to the pension plan sufficient for plan assets to exceed the ABO, and avoid the recognition of an additional minimum liability.
Use of alternative assumptions could also impact the expected future cash funding requirements for the pension plan if DPL's defined benefit plan did not meet the minimum funding requirements of ERISA.
Energy companies are subject to adverse publicity, which may render DPL 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 recent natural disasters and weather related incidents. Adverse publicity of this nature may render legislatures, regulatory authorities, and tribunals less likely to view energy companies such as DPL in a favorable light and may cause DPL to be susceptible to adverse outcomes with respect to decisions by such bodies.
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Because DPL is an indirect, wholly owned subsidiary of PHI, PHI can exercise substantial control over its dividend policy and business and operations.
All of the members of DPL's board of directors, as well as many of DPL's executive officers, are officers of PHI. Among other decisions, DPL'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 DPL's outstanding debt instruments, DPL's board of directors will base its decisions concerning the amount and timing of dividends, and other business decisions, on DPL's earnings, cash flow and capital structure, but may also take into account the business plans and financial requirements of PHI and its other subsidiaries.
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 with respect to 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;
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·
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;
·
Legal and administrative proceedings (whether civil or criminal) and settlements that influence DPL's business and profitability;
·
Volatility in market demand and prices for energy, capacity and fuel;
·
Interest rate fluctuations and credit 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
RESTATEMENT
Our parent company, Pepco Holdings, restated its previously reported consolidated financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct the accounting for certain deferred compensation arrangements. The restatement includes the correction of other errors for the same periods, primarily relating to unbilled revenue, taxes, and various accrual accounts, which were considered by management to be immaterial. These other errors would not themselves have required a restatement absent the restatement to correct the accounting for deferred compensation arrangements. The restatement of Pepco Holdings consolidated financial statements was required solely because the cumulative impact of the correction, if recorded in the fourth quarter of 2005, would have been material to that period's reported net income. The restatement to correct the accounting for the deferred compensation arrangements had no impact on ACE; however, ACE restated its previously reported consolidated financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to reflect the correction of other errors. The correction of these other errors, primarily relating to taxes and various accrual accounts, was considered by management to be immaterial. See Note 14 "Restatement" for further discussion.
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 998,000.
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 FERC under PUHCA 2005.
RESULTS OF OPERATIONS
The accompanying results of operations discussion is for the year ended December 31, 2005 compared to the year ended December 31, 2004. 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.
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Operating Revenue
The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D (Transmission and Distribution) 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 the revenue ACE receives for delivery of electricity to its customers for which service ACE is paid regulated rates. Default Supply Revenue is the revenue received by ACE for providing Default Electricity Supply. The costs related to the supply of electricity are included in Fuel and Purchased Energy expense. Also included in Default Supply Revenue is revenue from non-utility generators (NUGS), transition bond charges, market transition charges (MTC) 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, rents, late payments, and collection fees.
Regulated T&D Electric
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Regulated T&D Electric Revenue increased by $3.6 million primarily due to the following: (i) $6.8 million increase due to weather, the result of a 28% increase in Cooling Degree Days in 2005, (ii) $4.3 million due to customer growth, the result of a 1.5% customer increase in 2005, offset by (iii) $4.0 million reduction in estimated unbilled revenue recorded in the second quarter of 2005, primarily reflecting higher estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers) and (iv) $3.5 million decrease due to other sales and rate variances.
Default Electricity Supply
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Default Supply Revenue is primarily subject to deferral accounting, with differences in revenues and expenses deferred to the balance sheet for subsequent recovery under the New Jersey restructuring deferral. The $185.0 million increase in Default Supply Revenue primarily resulted from the following: (i) $142.2 million increase in wholesale energy revenues from sales of generated and purchased energy into PJM (included in Other) due to higher market prices in 2005, (ii) $22.3 million increase due to weather, primarily in the third quarter of 2005, (iii) $16.8 million increase due to higher retail energy rates resulting from the new market based New Jersey BGS effective October 2005, (iv) $10.3 million due to other sales and rate variances, and (v) $9.8 million increase due to customer growth, offset by (vi) $8.5 million decrease resulting from customer migration (load) and (vii) $7.9 million decrease due to a reduction in estimated unbilled revenue recorded in the second quarter of 2005, primarily reflecting higher estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). Default Supply Revenue is partially offset in Fuel and Purchased Power expense.
ACE's New Jersey customers served by an alternate supplier represented 22% of ACE's total load for the twelve months ended December 31, 2005 and 2004.
Operating Expenses
Fuel and Purchased Energy and Other Services Costs of Sales
Fuel and Purchased Energy increased by $105.3 million to $912.0 million in 2005, from $806.7 million in 2004. The increase is primarily due to: (i) $84.5 million increase in higher average energy costs, the result of New Jersey BGS supply contracts in June 2005 and (ii) $21.6 million increase due to customer growth and (iii) $15.2 million increase in other sales and rate variances, partially offset by (iv) $16.0 million decrease due to higher customer migration. This expense is primarily offset in Default Supply Revenue.
Depreciation and Amortization
Depreciation and Amortization expenses decreased by $8.9 million to $123.9 million in 2005, from $132.8 million in 2004. The decrease is primarily due to a $7.6 million decrease from a change in depreciation technique resulting from a 2005 final rate order from the NJBPU.
Other Taxes
Other Taxes increased by $2.2 million to $22.9 million in 2005, from $20.7 million in 2004. The increase is primarily due to a $2.5 million true-up for the Transitional Electricity Facilities Adjustment (TEFA), which decreased Other Taxes expense in 2004.
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Deferred Electric Service Costs
Deferred Electric Service Costs increased by $83.9 million to $120.2 million in 2005, from $36.3 million in 2004. The $83.9 million increase represents (i) $77.1 million net over-recovery associated with New Jersey BGS, NUGS, market transition charges and other restructuring items and (ii) $4.5 million in regulatory disallowances (net of amounts previously reserved) associated with the April 2005 NJBPU settlement agreement. At December 31, 2005, ACE's balance sheet included as a regulatory liability an over-recovery of $40.9 million with respect to these items, which is net of a $47.3 million reserve for items disallowed by the NJBPU in a ruling that is under appeal.
Gain on Sale of Assets
Gain on Sale of Assets represents a $14.7 million gain from the 2004 condemnation settlement with the City of Vineland, New Jersey relating to the transfer of ACE's distribution assets and customer accounts to the city.
Other Income (Expenses)
Other expenses decreased by $3.2 million to a net expense of $50.7 million in 2005, from a net expense of $53.9 million in 2004. The decrease is primarily due to (i) lower interest expense resulting from maturities of debt in March, July and August of 2005 and (ii) an increase in interest income due to higher interest rates in 2005.
Income Tax Expenses
ACE's effective tax rate before extraordinary item for the year ended December 31, 2005 was 44% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit), the flow-through of certain book tax depreciation differences and changes in estimates related to tax liabilities of prior tax years subject to audit (primarily due to the mixed service cost issue under IRS Rule 2005-43), partially offset by the flow-through of deferred investment tax credits.
ACE's effective tax rate for the year ended December 31, 2004 was 41% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences, partially offset by the flow-through of deferred investment tax credits.
Extraordinary Item
On April 19, 2005, ACE, the staff of the New Jersey Board of Public Utilities (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.
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RISK FACTORS
The business of ACE is subject to numerous risks and uncertainties, including the events or conditions identified below. The occurrence of one or more these events or conditions could have an adverse effect on the business of ACE, including, depending on the circumstances, its results of operations and financial condition.
ACE is a public utility that is subject to substantial governmental regulation. If ACE receives unfavorable regulatory treatment, ACE's business could be negatively affected.
ACE's utility business is subject to regulation by various federal, state and local regulatory agencies that significantly affects its operations. ACE's operations are regulated in New Jersey by the NJBPU with respect to, among other things, the rates it can charge retail customers for the supply and distribution of electricity. In addition, the rates that ACE can charge for electricity transmission are regulated by FERC. ACE 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 ACE to recover its costs of service and earn a reasonable rate of return, ACE's profitability is affected by the rates it is able to charge. In addition, if the costs incurred by ACE in operating its transmission and distribution facilities exceed the allowed amounts for costs included in the approved rates, ACE's financial results will be adversely affected.
ACE also is required to have numerous permits, approvals and certificates from governmental agencies that regulate its business. ACE believes that 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, ACE is unable 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 ACE to incur additional expenses or to change the way it conducts its operations.
The operating results of ACE fluctuate on a seasonal basis and can be adversely affected by changes in weather.
ACE's electric utility business is seasonal and weather patterns can have a material impact on its operating performance. Demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating as compared to other times of the year. Accordingly, ACE historically has generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
ACE's facilities may not operate as planned or may require significant maintenance expenditures, which could decrease its revenues or increase its expenses.
Operation of generation, transmission and distribution 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,
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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. Furthermore, if ACE is unable to perform its contractual obligations for any of these reasons, it may incur penalties or damages.
ACE's transmission facilities are interconnected with the facilities of other transmission facility owners whose actions could have a negative impact on ACE's operations.
The transmission facilities of 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 operators to coordinate the operation of portions of the interstate transmission grid. ACE is a member of PJM, which is the regional transmission operator that coordinates the movement of electricity in 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. ACE operates its transmission facilities under the direction and control of PJM. PJM and the other regional transmission operators 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 and the other regional transmission operators may not always be adequate to prevent problems at other utilities from causing service interruptions in the transmission facilities of ACE. If ACE were to suffer such a service interruption, it could have a negative impact on its business.
The cost of compliance with environmental laws is significant and new environmental laws may increase ACE's expenses.
ACE's operations 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 require ACE to make capital expenditures and to incur other expenditures to, among other things, meet emissions standards, conduct site remediation and perform environmental monitoring. ACE also may be required to pay significant remediation costs with respect to third party sites. If ACE 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, ACE incurs costs 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 ACE fails to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.
New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on ACE's operations or require it to incur
significant additional costs. ACE's current compliance strategy may not successfully address the relevant standards and interpretations of the future.
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Changes in technology may adversely affect ACE's electricity delivery businesses.
Increased conservation efforts and advances in technology could reduce demand for electricity supply and distribution, which could adversely affect ACE's business. In addition, changes in technology also could alter the channels through which retail electric customers buy electricity, which could adversely affect ACE's business.
Acts of terrorism could adversely affect ACE's business.
The threat of, or actual acts of, terrorism may affect ACE's operations in unpredictable ways and may cause changes in the insurance markets, force ACE to increase security measures and cause disruptions of power markets. If any of ACE's fuel storage, generation, transmission or distribution facilities were to be a direct target or an indirect casualty of an act of terrorism, its operations could be adversely affected. Instability in the financial markets as a result of terrorism also could affect the ability of ACE to raise needed capital.
ACE's insurance coverage may not be sufficient to cover all casualty losses that it might incur.
ACE currently has insurance coverage for its facilities and operations in amounts and with deductibles that it considers 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.
ACE 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 ACE.
ACE is dependent on its ability to successfully access capital markets. An inability to access capital may adversely affect its business.
ACE relies on access to both short-term money markets and longer-term capital markets as a source of liquidity and to satisfy its capital requirements not satisfied by the cash flow from its operations. Capital market disruptions, or a downgrade in ACE's credit ratings, would increase the cost of borrowing or could adversely affect its ability to access one or more financial markets. 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.
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In accordance with the requirements of the Sarbanes-Oxley Act of 2002 and the SEC rules thereunder, ACE'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 the financing costs of PHI and its subsidiaries or could adversely affect their ability to access one or more financial markets.
ACE's future defined benefit plan funding obligations are affected by its assumptions regarding the valuation of its benefit obligations and the performance of plan assets; actual experience which varies from the assumptions could result in an obligation of ACE to make significant unplanned cash contributions to the plan.
ACE follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions" in accounting for pension benefits under the Retirement Plan, a non-contributory defined benefit plan. In accordance with these accounting standards, ACE 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, accumulated benefit obligations (ABO), reported pension benefit obligation on ACE's Consolidated Balance Sheet, and reported annual net periodic pension benefit cost on ACE's Consolidated Statement of Earnings.
Furthermore, if actual pension plan experience is different from that which is expected, the ABO could be greater than the fair value of pension plan assets. If this were to occur, ACE could be required to recognize an additional minimum liability as prescribed by SFAS No. 87. The liability would be recorded as a reduction to common equity through a charge to Other Comprehensive Income (OCI), and would not affect net income for the year. The charge to OCI would be restored through common equity in future periods when the fair value of plan assets exceeded the ABO. ACE's funding policy is to make cash contributions to the pension plan sufficient for plan assets to exceed the ABO, and avoid the recognition of an additional minimum liability.
Use of alternative assumptions could also impact the expected future cash funding requirements for the pension plan if ACE's defined benefit plan did not meet the minimum funding requirements of ERISA.
Energy companies are subject to adverse publicity, which may render ACE 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 recent 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 ACE in a favorable light and may cause ACE to be susceptible to adverse outcomes with respect to decisions by such bodies.
Because ACE is an indirect, wholly owned subsidiary of PHI, PHI can exercise substantial control over its dividend policy and business and operations.
All of the members of ACE's board of directors, as well as many of ACE's executive officers, are officers of PHI. Among other decisions, ACE's board is responsible for decisions regarding
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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 ACE's outstanding debt instruments, ACE's board of directors will base its decisions concerning the amount and timing of dividends, and other business decisions, on ACE's earnings, cash flow and capital structure, but may also take into account the business plans and financial requirements of PHI and its other subsidiaries.
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 with respect to 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;
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·
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;
·
Legal and administrative proceedings (whether civil or criminal) and settlements that influence ACE's business and profitability;
·
Volatility in market demand and prices for energy, capacity and fuel;
·
Interest rate fluctuations and credit 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
GENERAL INFORMATION
As of March 2003, Conectiv Energy ceased all proprietary trading activities, which generally consist of the entry into contracts to take a view of market direction, capture market price change, and put capital at risk. PHI's competitive energy segments are no longer engaged in proprietary trading; however, the market exposure under certain contracts entered into prior to cessation of proprietary trading activities was not eliminated due to the illiquid market environment to execute such elimination. Some of these contracts remained in place through December 2005.
The competitive energy segments actively engage in commodity risk management activities to reduce their financial exposure to changes in the value of their assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives under SFAS 133. In addition, the competitive energy segments also manage commodity risk with contracts that are not classified as derivatives. The competitive energy segments' primary risk management objectives are to manage the spread between the cost of fuel used to operate their electric generation plants and the revenue received from the sale of the power produced by those plants and manage the spread between retail sales commitments and the cost of supply used to service those commitments in order to ensure stable and known minimum cash flows and fix favorable prices and margins when they become available. To a lesser extent, Conectiv Energy also engages in market activities in an effort to profit from short-term geographical price differentials in electricity prices among markets. PHI collectively refers to these energy market activities, including its commodity risk management activities, as "other energy commodity" activities and identifies this activity separately from that of the discontinued proprietary trading activity.
PHI's risk management policies place oversight at the senior management level through the Corporate Risk Management Committee which has the responsibility for establishing corporate compliance requirements for the competitive energy segments' energy market participation. PHI uses a value-at-risk (VaR) model to assess the market risk of its competitive energy segments' other energy commodity activities and its remaining proprietary trading contracts. PHI also uses other measures to limit and monitor risk in its 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-gamma 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.
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Notes:
(1)
Includes all remaining proprietary trading contracts entered into prior to cessation of this activity prior to March 2003.
(2)
This column represents all energy derivative contracts, normal purchase and sales contracts, modeled generation output and fuel requirements and modeled customer load obligations for both the discontinued proprietary trading activity and the ongoing other energy commodity activities.
(3)
As VaR calculations are shown in a standard delta or delta/gamma closed form 95% 1-day holding period 1-tail normal distribution form, traditional statistical and financial methods can be employed to reconcile prior Form 10-K and Form 10-Q VaRs to the above approach. In this case, 5-day VaRs divided by the square root of 5 equal 1-day VaRs; and 99% 1-tail VaRs divided by 2.326 times 1.645 equal 95% 1-tail VaRs. Note that these methods of conversion are not valid for converting from 5-day or less holding periods to over 1-month holding periods and should not be applied to "non-standard closed form" VaR calculations in any case.
For additional quantitative and qualitative information on the fair value of energy contracts see Note (13) "Use of Derivatives in Energy and Interest Rate Hedging Activities" to 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.
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* 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, 2005 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, 2005.
Management's assessment of the effectiveness of its internal controls over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which is included herein.
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Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
of Pepco Holdings, Inc.:
We have completed integrated audits of Pepco Holdings, Inc.'s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedules
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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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 of financial statements 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 disclosed in Note 15 to the consolidated financial statements, the Company restated its financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003.
Internal control over financial reporting
Also, in our opinion, management's assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our
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audit of internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
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, D.C.
March 13, 2006
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PEPCO HOLDINGS, INC.
(1) ORGANIZATION
Pepco Holdings, Inc. (Pepco Holdings or PHI) is a diversified energy company that, through its operating subsidiaries, is engaged in two principal business operations:
·
electricity and natural gas delivery (Power Delivery), and
·
competitive energy generation, marketing and supply (Competitive Energy).
PHI was incorporated in Delaware in February 2001, for the purpose of effecting the acquisition of Conectiv by Potomac Electric Power Company (Pepco). The acquisition was completed on August 1, 2002, at which time Pepco and Conectiv became wholly owned subsidiaries of PHI. Conectiv was formed in 1998 to be the holding company for Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) in connection with a merger between DPL and ACE. As a result, DPL and ACE are wholly owned subsidiaries of Conectiv.
On February 8, 2006, the Public Utility Holding Company Act of 1935 (PUHCA 1935) was repealed and the Public Utility Holding Company Act of 2005 (PUHCA 2005) went into effect. As a result, PHI has ceased to be regulated by the Securities and Exchange Commission (SEC) as a public utility holding company and is now subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC). As permitted under FERC regulations promulgated under PUHCA 2005, PHI will give notice to FERC that it will continue, until further notice, to operate pursuant to the authority granted in the financing order issued by the SEC under PUHCA 1935, which has an authorization period ending June 30, 2008, relating to the issuance of securities and guarantees, other financing transactions and the operation of the money pool.
PHI Service Company, a subsidiary service company of PHI, provides a variety of support services, including legal, accounting, tax, financial reporting, treasury, purchasing and information technology services to Pepco Holdings and its operating subsidiaries. These services are provided pursuant to a service agreement among PHI, PHI Service Company, and the participating operating subsidiaries that was filed with, and approved by, the SEC under PUHCA 1935. 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. PHI expects to continue operating under 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 and distribution of electricity and the distribution 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. 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
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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
PHI and its subsidiaries refer to this supply service in each of the jurisdictions generally as Default Electricity Supply.
The rates each company is permitted to charge for the wholesale transmission of electricity are regulated by FERC.
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.
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
Over the last several years, PHI has discontinued its investments in non-energy related businesses, including the sale of its aircraft investments and the sale of its 50% interest in Starpower Communications LLC (Starpower). Through its subsidiary, Potomac Capital Investment Corporation (PCI), PHI continues to maintain a portfolio of cross-border energy sale-leaseback transactions, with a book value at December 31, 2005 of approximately $1.3 billion. This activity constitutes a fourth operating segment, which is designated as "Other Non-Regulated" for financial reporting purposes.
(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 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. Under the equity method, Pepco Holdings records its interest in the entity as an investment in the accompanying Consolidated Balance Sheets, and its percentage share of the
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entity's earnings are recorded in the accompanying Consolidated Statements of Earnings. Additionally, the proportionate interests in jointly owned electric plants are consolidated.
In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 46R (revised December 2003), entitled "Consolidation of Variable Interest Entities," Pepco Holdings deconsolidated several entities that had previously been consolidated and consolidated several small entities that had not previously been consolidated. FIN 46R addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. For additional information regarding the impact of implementing FIN 46R, 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, such as compliance with Statement of Position 94-6, "Disclosure of Certain Significant Risks and Uncertainties," 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. Examples of 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, and judgment involved with assessing the probability of recovery of regulatory assets. 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 based upon the probable and reasonably estimable criteria contained in SFAS No. 5 "Accounting for Contingencies." 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.
Changes in Accounting Estimates
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.
Also, 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 that resulted in lower depreciation expense of approximately $5.3 million.
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Revenue Recognition
Regulated Revenue
The Power Delivery businesses recognize revenues from the supply and delivery of electricity and gas upon delivery to the customer, including amounts for services rendered but not yet billed (unbilled revenue). Pepco Holdings recorded amounts for unbilled revenue of $198.2 million and $227.4 million as of December 31, 2005 and 2004, respectively. These amounts are included in the "accounts receivable" line item in the accompanying Consolidated Balance Sheets. 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. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix and estimated power line losses, 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 by the respective companies 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 revenues for the supply and delivery of electricity and gas upon delivery to the customer, including amounts for services rendered, but not yet billed. Conectiv Energy recognizes revenue when delivery is complete. 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 SFAS No. 133. Pepco Energy Services recognizes revenue for its wholesale and retail commodity business upon delivery to customers. Revenues for Pepco Energy Services' energy efficiency construction business are recognized using the percentage-of-completion method of revenue recognition 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. Revenues from the other non-regulated business lines are 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 of revenue recognition.
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), the MPSC, and the Virginia State Corporation Commission (VSCC).
The power delivery operations of ACE are regulated by the New Jersey Board of Public Utilities (NJBPU).
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The wholesale power transmission operations of 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.
The components of Pepco Holdings' regulatory asset balances at December 31, 2005 and 2004, are as follows:
The components of Pepco Holdings' regulatory liability balances at December 31, 2005 and 2004, 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 (NUG) contract termination payment 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 of Transition Bonds by Atlantic City Electric Transition Funding LLC (ACE Funding). A customer surcharge is collected by ACE to fund principal and
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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 Energy Supply Costs: The regulatory asset balances primarily represent deferred costs related to the provision of BGS and other restructuring related costs incurred by ACE as well as deferred fuel costs for DPL's gas business. All deferrals receive a return, with ACE deferrals recovered over the next 8 years and DPL's deferred fuel costs recovered annually. The regulatory liability balance at December 31, 2005 relates to ACE and reflects net over recovery associated with New Jersey BGS, NUGS, Market transition charges, and other restructuring items.
Deferred Recoverable Income Taxes: Represents deferred income tax assets recognized from the normalization of flow-through items as a result of amounts previously provided to customers. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return on these deferrals.
Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period. A return is received on these deferrals.
Unrecovered Purchased Power Contract Costs: Represents deferred costs related to purchase power contracts at ACE and DPL. The ACE amortization period began in July 1994 and will end in May 2014. The DPL amortization period began in February 1996 and will end in October 2007. Both earn 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.
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.
Regulatory Liability for Federal and New Jersey Tax Benefit: 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.
Generation Procurement Credit (GPC) and Customer Sharing Commitment: Pepco's
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settlement agreements related to its December 2000 generation divestiture, approved by both the DCPSC and MPSC, required the sharing between customers and shareholders of any profits earned during the four-year transition period from February 8, 2001 through February 7, 2005 in each jurisdiction. The GPC represents the customers' share of profits that Pepco has realized on the procurement and resale of Standard Offer Service electricity supply to customers in Maryland and the District of Columbia that has not yet been distributed to customers. Pepco is currently distributing the customers' share of profits monthly to customers in a billing credit. The GPC increased by $42.3 million in December 2005 due to the settlement of the Pepco TPA claim against the Mirant bankruptcy estate.
Accrued Asset Removal Costs: Represents Pepco's and DPL's asset retirement obligations associated with removal costs accrued using public service commission-approved depreciation rates for transmission, distribution, and general utility property. In accordance with the SEC interpretation of SFAS 143, accruals for removal costs were classified as a regulatory liability.
Excess Depreciation Reserve: The excess depreciation reserve was recorded as part of a 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 will be amortized over 8.25 years, beginning June 2005.
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. The CRMC sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements.
PHI accounts for its derivative activities in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by subsequent pronouncements. SFAS No. 133 requires derivative instruments to be measured at fair value. Derivatives are recorded on the Consolidated Balance Sheet as other assets or other liabilities with offsetting gains and losses flowing through earnings unless they are designated as cash flow hedges. Derivatives can be accounted for in four ways under SFAS No. 133: (i) marked-to-market through current earnings, (ii) cash flow hedge accounting, (iii) fair value hedge accounting, and (iv) normal purchase and sales accounting.
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. Derivatives that were used for Conectiv Energy's discontinued proprietary trading activities were marked-to-market through earnings.
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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 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 other hedging 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 as provided under the guidance of 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 risk. These options are normally marked-to-market through current earnings because of the difficulty in qualifying options for hedge accounting treatment. Option premiums are deferred as prepaid expenses or other liabilities until the exercise period of the option is realized. 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, an internal model is 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 on 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 sales 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.
Conectiv Energy engages in commodity hedging activities to minimize the risk of market fluctuations associated with the purchase and sale of energy commodities (natural gas, petroleum, coal and electricity). The majority of these hedges relate to the procurement of fuel for its power plants, fixing the cash flows from the plant output, and securing power for electric
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load service. Conectiv Energy's hedging activities are conducted using derivative instruments, including forward contracts, swaps and futures, designated as cash flow hedges which are designed to reduce the variability in future cash flows. Conectiv Energy's commodity hedging objectives, in accordance with its risk management policy, are primarily the assurance of stable and known cash flows and the fixing of favorable prices and margins when they become available.
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. 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, steps are taken to reduce or increase hedges. Portfolio-level hedging includes the use of accounting hedges (derivatives designated as cash flow hedges), derivatives that are being marked-to-market through earnings, and other physical commodity purchases and sales.
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 fuel adjustment clause approved by the DPSC and are deferred under SFAS No. 71 until recovered. At December 31, 2005, DPL's Balance Sheet included a deferred derivative receivable of $21.6 million, offset by a $21.6 million regulatory liability.
Pepco Energy Services purchases electric and natural gas futures, swaps and forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for delivery to customers in future months. Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of forecasted transactions. Its forward contracts are accounted for under standard accrual accounting as these contracts meet the requirements for normal purchase and sale accounting under SFAS No. 133.
Conectiv Bethlehem, LLC (CBI), a subsidiary of Conectiv Energy, entered into an interest rate swap agreement for the purpose of managing its overall borrowing rate and limiting its interest rate risk associated with debt it incurred. CBI hedged 75% of the interest rate payments for its variable rate debt. CBI formally designated its interest rate swap agreement as a cash flow hedge. CBI repaid all of its external debt and settled its interest rate swap agreement ($6.8 million gain) in September 2004.
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. Approximately 72.9% of PCI's fixed rate debt for its Medium Term Note program has been swapped into variable rate debt. All of PCI's hedges on variable rate debt expired when the variable rate debt incurred under its Medium-Term Note program matured during 2005.
Emission Allowances
Emission allowances for Sulfur Dioxide (SO2) and Nitrous Oxide (NOX) are allocated to
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generation owners by the Environmental Protection Agency (EPA) based on Federal programs designed to regulate the emissions from power plants. The 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. 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 zero-basis allowances. Pepco Holdings has a committee established to monitor compliance with emissions regulations and whether its power plants have the required number of allowances.
Accounting for Goodwill
Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. The accounting for goodwill is governed by SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." Pepco Holdings' goodwill balance that was generated from Pepco's acquisition of Conectiv has been allocated to the Power Delivery business. SFAS No. 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting and broadens the criteria for recording intangible assets apart from goodwill. SFAS No. 142 requires that purchased goodwill and certain indefinite-lived intangibles no longer be amortized, but instead be tested for impairment at least annually. Substantially all of Pepco Holdings' goodwill was generated by the acquisition of Conectiv by Pepco in 2002.
A roll forward of PHI's goodwill balance follows (Millions of dollars):
Balance, December 31, 2003
$1,432.3
Less: Adjustment to pre-merger tax reserve
(1.8)
Balance December 31, 2004
$1,430.5
Add: Adjustment to pre-merger tax reserve
.8
Balance, December 31, 2005
$1,431.3
Goodwill Impairment Evaluation
The provisions of SFAS No. 142 require the evaluation of goodwill for impairment at least annually or more frequently if events and circumstances indicate that the asset might be impaired. Examples of such events and circumstances include an adverse action or assessment by a regulator, a significant adverse change in legal factors or in the business climate, and unanticipated competition. SFAS No. 142 indicates that if the fair value of a reporting unit is less than its carrying value, including goodwill, an impairment charge may be necessary. During 2005, Pepco Holdings tested its goodwill for impairment as of July 1, 2005. This test indicated that none of Pepco Holdings' goodwill balance was impaired.
Long-Lived Assets Impairment Evaluation
Pepco Holdings is required to evaluate certain long-lived assets (for example, generating property and equipment and real estate) to determine if they are impaired when certain
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conditions exist. SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," governs the accounting treatment for impairments of long-lived assets and indicates that companies are required to test long-lived assets for recoverability 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.
For long-lived assets that are expected to be held and used, SFAS No. 144 requires that an impairment loss be recognized only if the carrying amount of an asset is not recoverable and exceeds its fair value. For long-lived assets that can be classified as assets to be disposed of by sale under SFAS No. 144, an impairment loss will be recognized to the extent their carrying amount exceeds their fair value including costs to sell.
During 2003, PHI recorded an impairment charge of $53.3 million from the cancellation of a combustion turbine purchase contract and an impairment charge of $11.0 million related to aircraft investments held for lease by PCI.
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
Restricted cash represents cash either held as collateral or pledged as collateral that is restricted from use for general corporate purposes.
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. 34, "Capitalization of Interest Cost," the cost of financing the construction of Pepco Holdings' non-regulated subsidiaries' electric generating plants is capitalized. Other non-utility construction projects also include financing costs in accordance with SFAS No. 34. In accordance with the provisions of SFAS No. 71, utilities can capitalize Allowance for Funds Used During Construction (AFUDC) as part of the cost of plant and equipment. AFUDC recognizes that utility construction is financed partially by debt and partially by equity.
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Pepco Holdings recorded AFUDC for borrowed funds of $3.3 million, $2.8 million, and $3.0 million for the years ended December 31, 2005, 2004, and 2003, respectively. These amounts are recorded as a reduction of "interest expense" in the accompanying Consolidated Statements of Earnings.
Pepco Holdings recorded amounts for the equity component of AFUDC of $4.7 million, $4.1 million and $4.6 million for the years ended December 31, 2005, 2004 and 2003, respectively. The amounts are included in the "other income" caption of the accompanying Consolidated Statements of Earnings.
Leasing Activities
Pepco Holdings accounts for leases entered into by its subsidiaries in accordance with the provisions of SFAS No. 13, "Accounting for Leases." 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.
Amortization of Debt Issuance and Reacquisition Costs
Expenses incurred in connection with the issuance of long-term debt, including premiums and discounts associated with such debt, are deferred and amortized over the lives of the respective debt issues. Costs associated with the reacquisition of debt for PHI's regulated operations are also deferred and amortized over the lives of the new issues.
Pension and Other Postretirement Benefit Plans
Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings' subsidiaries (Retirement Plan). 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.
Pepco Holdings accounts for the Retirement Plan 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." PHI's financial statement disclosures are prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits," as revised.
Severance Costs
In 2004, PHI's 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
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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. Additionally, during 2002, Pepco Holdings' management approved initiatives by Pepco and Conectiv to streamline their operating structures by reducing the number of employees at each company. These initiatives met the criteria for the accounting treatment provided under EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." A roll forward of PHI's severance accrual balance is as follows (Millions of dollars):
Balance, December 31, 2003
$ 7.9
Accrued during 2004
11.7
Payments during 2004
(12.5)
Balance, December 31, 2004
7.1
Accrued during 2005
5.0
Payments during 2005
(9.6)
Balance, December 31, 2005
$ 2.5
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. 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. For additional information regarding the treatment of asset removal 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 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 system-wide composite depreciation rates for 2005, 2004 and 2003 for Pepco's transmission and distribution system property were approximately 3.4%, 3.5% and 3.5%, respectively. The system-wide composite depreciation rates for 2005, 2004 and 2003 for DPL's transmission and distribution system property was approximately 3.1%. The system-wide composite depreciation rates for 2005, 2004 and 2003 for ACE's generation, transmission and distribution system property were 3.1%, 3.3% and 3.2%, respectively.
Asset Retirement Obligations
Pepco Holdings adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," on January 1, 2003 and FIN 47 as of December 31, 2005. This statement and related interpretation establish the accounting and reporting standards for measuring and recording asset retirement obligations. Based on the implementation of SFAS No. 143, $244.2 million of accrued asset removal costs ($179.2 million for DPL and $65.0 million for Pepco) at December 31, 2005, and $254.1 million of accrued asset removal costs ($176.9 million for DPL and $77.2 million for Pepco) at December 31, 2004, are reflected as regulatory liabilities in the accompanying
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Consolidated Balance Sheets. 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 expense for 2005, which relates to the regulated Power Delivery segment, has been recorded as a regulatory asset.
Stock-Based Compensation
Pepco Holdings accounts for its stock-based employee compensation under the intrinsic value method of expense recognition and measurement prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees, and related Interpretations" (APB No. 25). As required by SFAS No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," a tabular presentation of the 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 follows:
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Accumulated Other Comprehensive Loss
A detail of the components of Pepco Holdings' Accumulated Other Comprehensive Loss is as follows. For additional information, see the Consolidated Statements of Comprehensive Earnings.
A detail of the income tax expense (benefit) allocated to the components of Pepco Holdings' Other Comprehensive Earnings (Loss) for each year is as follows.
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 SEC pursuant to regulations under PUHCA 1935 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, with the exception of the tax benefits applicable to non-acquisition debt expenses of PHI. Such tax benefits are allocated only to subsidiaries with taxable income.
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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 taxes are discussed below.
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 Sheet. 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.
Investment tax credits from utility plants purchased in prior years are reported on the Consolidated Balance Sheet as "Investment tax credits." These investment tax credits are being amortized to income over the useful lives of the related utility plant.
FIN 46R
Subsidiaries of Pepco Holdings have power purchase agreements (PPAs) with a number of entities, including three ACE Non-Utility Generation contracts (ACE NUGs) and an agreement of Pepco (Panda PPA) with Panda-Brandywine, L.P. (Panda). Due to a variable element in the pricing structure of the ACE NUGs and the Panda PPA, the Pepco Holdings' subsidiaries 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. As required by FIN 46R, Pepco Holdings continued, during 2005, 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 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 has not been able to obtain such information.
Net purchase activities with the counterparties to the ACE NUGs and the Panda PPA for the years ended December 31, 2005, 2004, and 2003, were approximately $419 million, $341 million, and $326 million, respectively, of which approximately $381 million, $312 million, and $299 million, respectively, related to power purchases under the ACE NUGs and the Panda PPA. Pepco Holdings' exposure to loss under the agreement with Panda entered into in 1991, pursuant to which Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021, is discussed in Note (12), Commitments and Contingencies, under "Relationship with Mirant Corporation." Pepco Holdings does not have loss exposure under the ACE NUGs because cost recovery will be achieved from ACE's customers through regulated rates.
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.
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Other Current Liabilities
The other current liability balance principally consists of customer deposits, accrued vacation liability, current unrealized derivative liabilities, and the current portion of deferred income taxes.
Other Deferred Credits
The other deferred credits balance principally consists of non-current unrealized derivative liabilities and miscellaneous deferred liabilities.
New Accounting Standards
SFAS No. 154
In May 2005, the FASB issued Statement No. 154, "Accounting Changes and Error Corrections (SFAS No. 154), a replacement of APB Opinion No. 20 and FASB Statement No. 3." SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. The reporting of a correction of an error by restating previously issued financial statements is also addressed by SFAS No. 154. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 (the year ended December 31, 2006 for Pepco Holdings). Early adoption is permitted.
SFAS No. 155
In February 2006, the FASB issued Statement No. 155, "Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140" (SFAS No. 155). This Statement amends FASB Statements No. 133, "Accounting for Derivative Instruments and Hedging Activities", and No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." This Statement resolves issues addressed in Statement 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. Pepco Holdings is in the process of evaluating the impact of SFAS No. 155 but does not anticipate that its implementation will have a material impact on Pepco Holdings overall financial condition, results of operations, or cash flows.
SAB 107 and SFAS No. 123R
In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (SAB 107) which provides implementation guidance on the interaction between FASB Statement No. 123 (revised 2004), "Share-Based Payment" (SFAS No. 123R), and certain SEC rules and regulations, as well as guidance on the valuation of share-based payment arrangements for public companies.
In April 2005, the SEC adopted a rule delaying the effective date of SFAS No. 123R for public companies. Under the rule, most registrants must comply with SFAS No. 123R beginning with the first interim or annual reporting period of their first fiscal year beginning after June 15, 2005 (the year ended December 31, 2006 for Pepco Holdings).
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In November 2005, the FASB published FASB Staff Position (FSP) FAS 123(R)-3, "Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards" (FSP FAS 123(R)-3, which provides guidance regarding an alternative transition election for accounting for the tax effects of share-based payments. FSP FAS 123(R)-3 was effective upon issuance.
In February 2006, the FASB published FASB Staff Position FAS 123(R)-4, "Classification of Options and Similar Instruments Issued as Employee Compensation that Allow for Cash Settlement upon the Occurrence of a Contingent Event" (FSP FAS 123(R)-4), which incorporate the concept of when cash settlement features of options and similar instruments meet the condition outlined in SAFS No. 123R. FSP FAS 123(R)-4 is effective upon initial adoption of SFAS No.123R or the first reporting period after its issuance if SFAS No. 123R has been adopted.
Pepco Holdings is in the process of completing its evaluation of the impact of SFAS No. 123R, FSP FAS 123(R)-3, and FSP FAS 123(R)-4, and does not anticipate that their implementation or SAB 107 will have a material effect on Pepco Holdings' overall financial condition, results of operations or cash flows.
EITF 04-13
In September 2005, the FASB ratified EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" (EITF 04-13), which addresses circumstances under which two or more exchange transactions involving inventory with the same counterparty should be viewed as a single exchange transaction for the purposes of evaluating the effect of APB Opinion 29. EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006 (April 1, 2006 for Pepco Holdings). EITF 04-13 would not affect Pepco Holdings' net income, overall financial condition, or cash flows, but rather could result in certain revenues and costs, including wholesale revenues and purchased power expenses, being presented on a net basis. Pepco Holdings is in the process of evaluating the impact of EITF 04-13 on its Consolidated Statements of Earnings presentation of purchases and sales.
(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, 2005 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Intercompany (intersegment) revenues and expenses are not eliminated at the segment level for purposes of presenting segment financial results. Elimination of these intercompany amounts is accomplished for PHI's consolidated results through the "Corporate and Other" column. Segment financial information for the years ended December 31, 2005, 2004, and 2003, is as follows.
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(4) LEASING ACTIVITIES
Financing lease balances were comprised of the following at December 31:
Pepco Holdings' $1,264.4 million equity investment in energy leveraged leases at December 31, 2005, consists of electric power plants and natural gas distribution networks located outside of the United States. Of this amount, $439.4 million of equity is attributable to facilities located in The Netherlands, $649.5 million in Austria and $175.5 million in Australia.
The components of the net investment in finance leases at December 31, 2005 and 2004 are summarized below (millions of dollars):
At December 31, 2005:
Leveraged Leases
Direct
Finance
Leases
Total
Finance
Leases
Scheduled lease payments, net of non-recourse debt
$2,315.4
$24.1
$2,339.5
Residual value
-
12.5
12.5
Less: Unearned and deferred income
(1,051.0)
(3.1)
(1,054.1)
Investment in finance leases held in trust
1,264.4
33.5
1,297.9
Less: Deferred taxes
(584.3)
(8.7)
(593.0)
Net Investment in Finance Leases Held in Trust
$ 680.1
$24.8
$ 704.9
At December 31, 2004:
Leveraged Leases
Direct
Finance
Leases
Total
Finance
Leases
Scheduled lease payments, net of non-recourse debt
$2,315.4
$26.4
$2,341.8
Residual value
-
12.5
12.5
Less: Unearned and deferred income
(1,132.3)
(3.3)
(1,135.6)
Investment in finance leases held in trust
1,183.1
35.6
1,218.7
Less: Deferred taxes
(494.6)
(8.1)
(502.7)
Net Investment in Finance Leases Held in Trust
$ 688.5
$27.5
$ 716.0
Income recognized from leveraged leases (included in "Other Operating Revenue") was comprised of the following for the years ended December 31:
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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 2006 through 2010 and thereafter are $30.7 million for 2006, $3.5 million for 2007, zero for 2008, zero for 2009, $32.1 million for 2010, and $1,231.6 million thereafter. For a discussion of the Federal tax treatment of cross-border leases, see to Note (12) "Commitments and Contingencies."
Lease Commitments
Pepco leases its consolidated control center, an integrated energy management center used by Pepco's power dispatchers to centrally control the operation of its transmission and distribution systems. The 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.
Rental expense for operating leases was $51.2 million, $46.2 million and $32.9 million for the years ended December 31, 2005, 2004, and 2003, respectively.
The approximate annual commitments under all operating leases are $38.3 million for 2006, $38.2 million for 2007, $39.0 million for 2008, 2009, and 2010, and $367.5 million thereafter.
Capital lease assets recorded within Property, Plant and Equipment at December 31, 2005 and 2004, in millions of dollars, are comprised of the following:
At December 31, 2005
Original
Cost
Accumulated
Amortization
Net Book
Value
Transmission
$ 76.0
$ 15.7
$ 60.3
Distribution
79.7
19.3
60.4
General
2.8
1.8
1.0
Total
$158.5
$36.8
$121.7
At December 31, 2004
Transmission
$ 76.0
$ 13.6
$ 62.4
Distribution
79.7
16.9
62.8
General
2.8
1.2
1.6
Total
$158.5
$31.7
$126.8
The approximate annual commitments under all capital leases are $15.8 million for 2006, $15.5 million for 2007, $15.4 million for 2008, $15.2 million for 2009 and 2010, and $137.1 million thereafter.
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(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.
Gain on Sale of Assets
In August 2005, Pepco sold for $75 million in cash 384,051 square feet of excess non-utility land owned by Pepco 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.
In 2004, PHI recorded pre-tax gains of $14.7 million from the condemnation settlement with the City of Vineland relating to the transfer of its distribution assets and customer accounts, $8.3 million on the sale of aircraft investments by PCI, and $6.6 million on the sale of land.
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 electric generating plants, 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, 2005 is shown below.
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As discussed in Note (12), Commitments and Contingencies, on November 15, 2005, ACE announced an agreement to sell its undivided interests in the Keystone and Conemaugh generating facilities to Duquesne Light Holdings Inc. for $173.1 million. The sale, subject to approval by the NJBPU, as well as other regulatory agencies and certain other legal conditions, is expected to be completed mid-year 2006.
(6) PENSIONS AND OTHER POSTRETIREMENT BENEFITS
Pension Benefits
Pepco Holdings sponsors a defined benefit Retirement Plan that 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.
Other Postretirement Benefits
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.
During 2004, PHI amended its postretirement health care plans for certain groups of eligible employees effective January 1, 2005 or January 1, 2006. The amendments included changes to coverage and retiree cost-sharing, and are reflected as a reduction in PHI's 2004 net periodic benefit cost and a reduction of $42 million in the projected benefit obligation at December 31, 2004.
Pepco Holdings uses a December 31 measurement date for its plans. Plan assets are stated at their market value as of the measurement date, December 31. All dollar amounts in the following tables are in millions of dollars.
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The following table provides a reconciliation of the projected benefit obligation, plan assets and funded status of the plans.
The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheet as of December 31:
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The accumulated benefit obligation for the Retirement Plan (the qualified defined benefit pension plan) was $1,556.2 million and $1,462.9 million at December 31, 2005, and 2004, respectively. The table below provides the projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the PHI nonqualified pension plan with an accumulated benefit obligation in excess of plan assets at December 31, 2005 and 2004.
In 2005 and 2004, PHI was required to recognize an additional minimum liability and an intangible asset related to its nonqualified pension plan as prescribed by SFAS No. 87. The liability was recorded as a reduction to shareholders' equity (other comprehensive income), and the equity will be restored to the balance sheet in future periods when the accrued benefit liability exceeds the accumulated benefit obligation at future measurement dates. The amount of reduction to shareholders' equity (net of income taxes) in 2005 was $7.3 million and in 2004 was $4.1 million. The recording of this reduction did not affect net income or cash flows in 2005 or 2004 or compliance with debt covenants.
The table below provides the components of net periodic benefit costs recognized for the years ended December 31.
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 2004 combined pension and other postretirement net periodic benefit cost of $57.6 million includes $24.1 million for Pepco, $1.0 million for DPL and $17.6 million for ACE. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.
The 2003 combined pension and other postretirement net periodic benefit cost of $77.5 million includes $33.7 million for Pepco, $7.1 million for DPL and $20.8 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:
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Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects (millions of dollars):
1-Percentage-
Point Increase
1-Percentage-
Point Decrease
Effect on total of service and interest cost
$ 1.8
$ (1.7)
Effect on postretirement benefit obligation
27.0
(25.1)
The following weighted average assumptions were used to determine the net periodic benefit cost for years ended December 31:
A cash flow matched bond portfolio approach to developing a discount rate is used to value FAS 87 and FAS 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 time horizon, are expected to yield a return on assets of 8.50%.
Plan Assets
Pepco Holdings' Retirement Plan weighted-average asset allocations at December 31, 2005, and 2004, by asset category are as follows:
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Pepco Holdings' other postretirement plan weighted-average asset allocations at December 31, 2005, and 2004, by asset category are as follows:
In developing an asset allocation policy for its 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 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.
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Cash Flows
Contributions - Retirement Plan
Pepco Holdings' funding policy with regard to the Retirement Plan is to maintain a funding level in excess of 100% with respect to its accumulated benefit obligation (ABO). PHI's Retirement Plan currently meets the minimum funding requirements of ERISA without any additional funding. In 2005 and 2004, PHI made discretionary tax-deductible cash contributions to the plan of $60.0 million and $10.0 million, respectively, in line with its funding policy. Assuming no changes to the current pension plan assumptions, PHI projects no funding will be required under ERISA in 2006; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its plan assets in excess of its ABO.
Contributions - Other Postretirement Benefits
In 2005, PHI combined its health and welfare plans and the existing IRC 501 (c) (9) Voluntary Employee Beneficiary Association (VEBA) trusts for Pepco, DPL and ACE to fund a portion of their estimated postretirement liabilities. Pepco funded the 2004 portion of its estimated liability for postretirement medical costs through the use of an Internal Revenue Code (IRC)401(h) account, within PHI's Retirement Plan. The trust was depleted in 2004 and a VEBA will be used for future funding. In 2005 and 2004, Pepco contributed $3.1 million and $4.7 million, respectively, DPL contributed $6.0 million and $9.5 million, respectively, and ACE contributed $7.0 million and $9.3 million, respectively, to the plans. Contributions of $6.4 million and $5.0 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 2006.
Expected Benefit Payments
Estimated future benefit payments to participants in PHI's qualified pension and postretirement welfare benefit plans, which reflect expected future service as appropriate, as of December 31, 2005 are in millions of dollars:
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(7) DEBT
LONG-TERM DEBT
The components of long-term debt are shown below.
NOTE: Schedule is continued on next page.
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The outstanding First Mortgage Bonds issued by each of Pepco, DPL and ACE are secured by a lien on substantially all of the issuing company's property, plant and equipment.
Atlantic City Electric Transition Funding L.L.C. (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 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.
The aggregate amounts of maturities for long-term debt and Transition Bonds outstanding at December 31, 2005, are $467.1 million in 2006, $854.8 million in 2007, $323.6 million in 2008, $82.2 million in 2009, $531.9 million in 2010, and $2,910.7 million thereafter.
Pepco Energy Services Notes, referred to as "Project Funding Secured by Customer Accounts Receivable" (Project Funding) represent funding for energy savings contracts performed by Pepco Energy Services. The aggregate amounts of maturities for the Project Funding debt outstanding at December 31, 2005, are $2.5 million in 2006, zero in 2007, $1.0 million in 2008, zero in 2009, $2.1 million in 2010, and $22.4 million thereafter, and includes the current portion of project funding that was provided in exchange for the sale of the customers' accounts receivable.
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, 2005 and 2004 is as follows.
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Commercial Paper
Pepco Holdings maintains an ongoing commercial paper program of up to $700 million. Pepco, DPL, and ACE have ongoing commercial paper programs of up to $300 million, $275 million, and $250 million, respectively. The commercial paper programs of PHI, Pepco, DPL and ACE are backed by a $1.2 billion credit facility, which is described under the heading "Credit Facility" below.
Pepco Holdings, Pepco, DPL and ACE had no commercial paper outstanding at December 31, 2005. The weighted average interest rate for commercial paper issued during 2005 was 3.02%. Interest rates for commercial paper issued during 2004 ranged from 1.05% to 2.63%. The weighted average maturity was two days for all commercial paper issued during 2005.
Floating Rate Note
In December 2004, Pepco Holdings issued a $50 million floating rate note that was paid at maturity in December 2005. The weighted average interest rate on this note was 3.61%.
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 in 2005 and 2004 mature in 2006 to 2009 ($10.5 million), 2014 to 2017 ($48.6 million), 2024 ($33.3 million) and 2028 to 2031 ($64.0 million). The weighted average interest rate for VRDB was 2.61% during 2005 and interest rates ranged from .82% to 2.47% in 2004.
Credit Facility
In May 2005, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $1.2 billion. This agreement replaces a $650 million five-year credit agreement that was entered into in July 2004 and a $550 million three-year credit agreement entered into in July 2003. Pepco Holdings' credit limit under this agreement is $700 million. The credit limit of each of Pepco, DPL and ACE is the lower of $300 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 under the agreement may not exceed $500 million. Under the terms of the credit agreement, the companies are entitled to request increases in the principal amount of available credit up to an aggregate increase of $300 million, with any such increase proportionately increasing the credit limit of each of the respective borrowers and the $300 million sublimits for each of Pepco, DPL and ACE. The interest rate payable by the respective companies on utilized funds is determined by a pricing schedule with rates corresponding to the credit rating of the borrower. Any indebtedness incurred under the credit agreement would be
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unsecured.
The credit agreement 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 contained in the credit agreement 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, (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 failure to satisfy any of the covenants or the occurrence of specified events that constitute an event of default could result in the acceleration of the repayment obligations of the borrower. The events of default include (i) the failure of any borrowing company or any of its significant subsidiaries to pay when due, or the acceleration of, certain indebtedness under other borrowing arrangements, (ii) certain bankruptcy events, judgments or decrees against any borrowing company or its significant subsidiaries, and (iii) a change in control (as defined in the credit agreement) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE. The agreement does not include any ratings triggers. There were no balances outstanding at December 31, 2005 and 2004.
(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 its subsidiaries included in its consolidated group pursuant to a written tax sharing agreement which was approved by the SEC pursuant to regulations under PUHCA 1935 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, with the exception of the tax benefits applicable to non-acquisition debt expenses of PHI. Such tax benefits are allocated only to subsidiaries with taxable income.
The provision for income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below.
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Provision for Income Taxes
Reconciliation of Consolidated Income Tax Expense
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Components of Consolidated Deferred Tax Liabilities (Assets)
The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to PHI's operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net and is recorded as a regulatory asset on the balance sheet.
The Tax Reform Act of 1986 repealed the Investment Tax Credit (ITC) for property placed in service after December 31, 1985, except for certain transition property. ITC previously earned on Pepco's, DPL's and ACE's property continues to be normalized over the remaining service lives of the related assets.
PHI files 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 1997, have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years.
Non Financial Lease Asset
The IRS, as part of its normal audit of PHI's income tax returns, has questioned whether PHI is entitled to certain ongoing tax deductions being taken by PHI as a result of the adoption by PHI of a carry-over tax basis for a non-lease financial asset acquired in 1998 by a subsidiary of PHI. On December 14, 2004, PHI and the IRS agreed to a Notice of Proposed Adjustment settling this and certain other tax matters. This settlement will result in a cash outlay during 2006 for additional taxes and interest of approximately $23.3 million associated with the examination of PHI's 2001-2002 tax returns and an anticipated refund of taxes and interest of approximately $7.1 million when the examination of PHI's 2003 return is completed. In addition, in the fourth quarter of 2004, PHI took a tax charge to earnings of approximately $19.7 million for financial reporting
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purposes related to this matter. The charge consisted of approximately $16.3 million to reflect the reversal of tax benefits recognized by PHI prior to September 30, 2004, and approximately $3.4 million of interest on the additional taxes. During 2005 PHI recorded a tax charge to earnings of approximately $.9 million for interest on the additional taxes.
Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below. The majority of these amounts relate to the Power Delivery businesses and are recoverable through rates.
(9) PREFERRED STOCK OF SUBSIDIARIES
Preferred stock amounts outstanding as of December 31, 2005 and 2004 are as follows:
(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 10,000,000 shares of common stock initially were available for issuance under the LTIP over a period of 10 years commencing August 1, 2002.
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 in May 1998, May 1999, January 2000, May 2000, January 2001, and May 2001 are exercisable. Seventy-five percent of the options granted on January 1, 2002 are exercisable and the remaining options became exercisable on January 1, 2006. Seventy-five percent of the options granted on May 1, 2002 are exercisable and the remaining options will become exercisable on May 1, 2006.
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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.
As of December 31, 2005, an analysis of options outstanding by exercise prices is as follows:
Range of
Exercise Prices
Number Outstanding
At December 31, 2005
Weighted Average
Exercise Price
Weighted Average
Remaining
Contractual Life
$13.08 to $19.30
498,309
18.8036
6.4
$21.83 to $29.78
1,365,941
23.4314
4.6
$13.08 to $29.78
1,864,250
22.1944
5.1
Pepco Holdings recognizes 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 2005, 2004 and 2003 with respect to stock options granted under the LTIP.
There were no options granted in 2005, 2004, or 2003.
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 2001 under Pepco's Performance Restricted Stock Program, a component of the LTIP, for performance periods 2002-2004 was 57,000. The target number of share award opportunities established in 2005, 2004 and 2003 under Pepco Holdings' Performance Restricted Stock Program for performance periods 2006-2008, 2005-2007 and 2004-2006 were 218,108, 247,400 and 292,100, respectively. The fair value per share on award date for the performance restricted stock was $22.235 for the 2006-2008 award, $21.060 for the 2005-2007 award, and $19.695 for the 2004-2006 award. Depending on the extent to which the performance criteria are satisfied, the executives are eligible to earn shares of common stock under the Performance Restricted Stock Program ranging from 0% to 200% of the target share award opportunities. No awards were earned with respect to the 2003-2005 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 have time-based vesting over three years: 20%
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vested in 2003, 30% vested in 2004, and 50% vested in 2005. The remaining 144,648 shares are performance-based award opportunities that may be 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 non-qualified 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.
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 will vest on June 1, 2006, if he is continuously employed by PHI through that date.
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 the charters of Pepco, DPL and ACE, which impose restrictions on payment of common stock dividends for the benefit of preferred stockholders.
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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.
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 1,228,505; 1,471,936; and 1,706,422 original issue shares sold under the DRP in 2005, 2004 and 2003, respectively.
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The following table presents Pepco Holdings' common stock reserved and unissued at December 31, 2005:
Name of Plan
Number of
Shares
DRP
4,946,124
Conectiv Incentive Compensation Plan
1,569,062
Potomac Electric Power Company Long-Term Incentive Plan
1,400,000
Pepco Holdings, Inc. Long-Term Incentive Plan
9,773,810
Pepco Holdings, Inc. Stock Compensation Plan for Directors (a)
-
Pepco Holdings, Inc. Non-Management Directors Compensation Plan
497,976
Potomac Electric Power Company Savings Plans consisting of
(i) the Retirement Savings Plan for Management Employees and (ii) the
Savings Plan for Bargaining Unit Employees (b),(c)
3,000,000
Conectiv Savings and Investment Plan (c)
20,000
Atlantic Electric 401(k) Savings and Investment Plan-B (c)
25,000
Total
21,231,972
(a)
Plan was terminated in 2005.
(b)
Effective January 1, 2005, the Savings Plan for Non-Bargaining Unit, Non-Exempt Employees was merged with and into the Savings Plan for Exempt Employees which was renamed the Retirement Savings Plan for Management Employees.
(c)
Effective January 13, 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 Retirement Savings Plan for Management Employees, (iii) the Conectiv Savings and Investment Plan, and (iv) the Atlantic City Electric 401(k) Savings and Investment Plan - B. As of January 20, 2006, there are 5,000,000 reserved and unissued shares under the Retirement Savings Plan (including the 3,045,000 shares previously reserved and unissued under the predecessor Plans.)
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(11) FAIR VALUES OF FINANCIAL INSTRUMENTS
The estimated fair values of Pepco Holdings' financial instruments at December 31, 2005 and 2004 are shown below.
The methods and assumptions described below were used to estimate, at December 31, 2005 and 2004, 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.
Long-Term Debt includes recourse and non-recourse debt issued by PCI. The fair values of this PCI debt, excluding 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, excluding 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 values of the Serial Preferred Stock and 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 Pepco Holdings' accompanying financial statements approximate fair value.
(12) COMMITMENTS AND CONTINGENCIES
REGULATORY AND OTHER MATTERS
Relationship with Mirant Corporation
In 2000, Pepco sold substantially all of its electricity generation assets to Mirant Corporation, formerly Southern Energy, Inc. As part of the Asset Purchase and Sale Agreement, Pepco entered into several ongoing contractual arrangements with Mirant Corporation and certain of its subsidiaries. In July 2003, Mirant Corporation and most of its subsidiaries filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S.
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Bankruptcy Court for the Northern District of Texas (the Bankruptcy Court). On December 9, 2005, the Bankruptcy Court approved Mirant's Plan of Reorganization (the Reorganization Plan) and the Mirant business emerged from bankruptcy on January 3, 2006 (the Bankruptcy Emergence Date), in the form of a new corporation of the same name (together with its predecessors, Mirant). However, as discussed below, the Reorganization Plan did not resolve all of the outstanding matters between Pepco and Mirant relating to the Mirant bankruptcy and the litigation between Pepco and Mirant over these matters is ongoing.
Depending on the outcome of ongoing litigation, the Mirant bankruptcy could have a material adverse effect on the results of operations and cash flows of Pepco Holdings and Pepco. However, management believes that Pepco Holdings and Pepco currently have sufficient cash, cash flow and borrowing capacity under their credit facilities and in the capital markets to be able to satisfy any additional cash requirements that may arise due to the Mirant bankruptcy. Accordingly, management does not anticipate that the Mirant bankruptcy will impair the ability of either Pepco Holdings or Pepco to fulfill its contractual obligations or to fund projected capital expenditures. On this basis, management currently does not believe that the Mirant bankruptcy will have a material adverse effect on the financial condition of either company.
Transition Power Agreements
As part of the Asset Purchase and Sale Agreement, Pepco and Mirant entered into Transition Power Agreements for Maryland and the District of Columbia, respectively (collectively, the TPAs). Under the TPAs, Mirant was obligated to supply Pepco with all of the capacity and energy needed to fulfill Pepco's SOS obligations during the rate cap periods in each jurisdiction immediately following deregulation, which in Maryland extended through June 2004 and in the District of Columbia extended until January 22, 2005.
To avoid the potential rejection of the TPAs by Mirant in the bankruptcy proceeding, Pepco and Mirant in October 2003 entered into an Amended Settlement Agreement and Release (the Settlement Agreement) pursuant to which the terms of the TPAs were modified to increase the purchase price of the capacity and energy supplied by Mirant. In exchange, the Settlement Agreement provided Pepco with an allowed, pre-petition general unsecured claim against Mirant Corporation in the amount of $105 million (the Pepco TPA Claim).
On December 22, 2005, Pepco completed the sale of the Pepco TPA Claim, plus the right to receive accrued interest thereon, to Deutsche Bank for a cash payment of $112.4 million. Additionally, Pepco received $0.5 million in proceeds from Mirant in settlement of an asbestos claim against the Mirant bankruptcy estate. Pepco Holdings and Pepco recognized a total gain of $70.5 million (pre-tax) related to the settlement of these claims. Based on the regulatory settlements entered into in connection with deregulation in Maryland and the District of Columbia, Pepco is obligated to share with its customers the profits it realizes from the provision of SOS during the rate cap periods. The proceeds of the sale of the Pepco TPA Claim will be included in the calculations of the amounts required to be shared with customers in both jurisdictions. Based on the applicable sharing formulas in the respective jurisdictions, Pepco anticipates that customers will receive (through billing credits) approximately $42.3 million of the proceeds over a 12-month period beginning in March 2006 (subject to DCPSC and MPSC approvals).
Power Purchase Agreements
Under agreements with FirstEnergy Corp., formerly Ohio Edison (FirstEnergy), and
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Allegheny Energy, Inc., both entered into in 1987, Pepco was obligated to purchase 450 megawatts of capacity and energy from FirstEnergy annually through December 2005 (the FirstEnergy PPA). Under the Panda PPA, entered into in 1991, Pepco is obligated to purchase 230 megawatts of capacity and energy from Panda annually through 2021. At the time of the sale of Pepco's generation assets to Mirant, the purchase price of the energy and capacity under the PPAs was, and since that time has continued to be, substantially in excess of the market price. As a part of the Asset Purchase and Sale Agreement, Pepco entered into a "back-to-back" arrangement with Mirant. Under this arrangement, Mirant (i) was obligated, through December 2005, to purchase from Pepco the capacity and energy that Pepco was obligated to purchase under the FirstEnergy PPA at a price equal to Pepco's purchase price from FirstEnergy, and (ii) is obligated through 2021 to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the Panda PPA at a price equal to Pepco's purchase price from Panda (the PPA-Related Obligations). Mirant currently is making these required payments.
Pepco Pre-Petition Claims
At the time the Reorganization Plan was approved by the Bankruptcy Court, Pepco had pending pre-petition claims against Mirant totaling approximately $28.5 million (the Pre-Petition Claims), consisting of (i) approximately $26 million in payments due to Pepco in respect of the PPA-Related Obligations and (ii) approximately $2.5 million that Pepco has paid to Panda in settlement of certain billing disputes under the Panda PPA that related to periods after the sale of Pepco's generation assets to Mirant and prior to Mirant's bankruptcy filing, for which Pepco believes Mirant is obligated to reimburse it under the terms of the Asset Purchase and Sale Agreement. In the bankruptcy proceeding, Mirant filed an objection to the Pre-Petition Claims. The Pre-Petition Claims were not resolved in the Reorganization Plan and are the subject of ongoing litigation between Pepco and Mirant. To the extent Pepco is successful in its efforts to recover the Pre-Petition Claims, it would receive under the terms of the Reorganization Plan a number of shares of common stock of the new corporation created pursuant to the Reorganization Plan (the New Mirant Common Stock) equal to (i) the amount of the allowed claim (ii) divided by the market price of the New Mirant Common Stock on the Bankruptcy Emergence Date. Because the number of shares is based on the market price of the New Mirant Common Stock on the Bankruptcy Emergence Date, Pepco would receive the benefit, and bear the risk, of any change in the market price of the stock between the Bankruptcy Emergence Date and the date the stock is issued to Pepco.
As of December 31, 2005, Pepco maintained a receivable in the amount of $28.5 million, representing the Pre-Petition Claims, which was offset by a reserve of $14.5 million established by an expense recorded in 2003 to reflect the uncertainty as to whether the entire amount of the Pre-Petition Claims is recoverable. As of December 31, 2005, this reserve was reduced to $9.6 million to reflect the fact that there was no longer an objection to $15 million of Pepco's claim.
Mirant's Efforts to Reject the PPA-Related Obligations and Disgorgement Claims
In August 2003, Mirant filed with the Bankruptcy Court a motion seeking authorization to reject the PPA-Related Obligations (the First Motion to Reject). Upon motions filed with the U.S. District Court for the Northern District of Texas (the District Court) by Pepco and FERC, the District Court in October 2003 withdrew jurisdiction over this matter from the Bankruptcy Court. In December 2003, the District Court denied Mirant's motion to reject the PPA-Related Obligations on jurisdictional grounds. Mirant appealed the District Court's decision to the U.S. Court of Appeals for the Fifth Circuit (the Court of Appeals). In August 2004, the Court of
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Appeals remanded the case to the District Court holding that the District Court had jurisdiction to rule on the merits of Mirant's rejection motion, suggesting that in doing so the court apply a "more rigorous standard" than the business judgment rule usually applied by bankruptcy courts in ruling on rejection motions.
In December 2004, the District Court issued an order again denying Mirant's motion to reject the PPA-Related Obligations. The District Court found that the PPA-Related Obligations are not severable from the Asset Purchase and Sale Agreement and that the Asset Purchase and Sale Agreement cannot be rejected in part, as Mirant was seeking to do. Mirant has appealed the District Court's order to the Court of Appeals.
In January 2005, Mirant filed in the Bankruptcy Court a motion seeking to reject certain of its ongoing obligations under the Asset Purchase and Sale Agreement, including the PPA-Related Obligations (the Second Motion to Reject). In March 2005, the District Court entered orders granting Pepco's motion to withdraw jurisdiction over these rejection proceedings from the Bankruptcy Court and ordering Mirant to continue to perform the PPA-Related Obligations (the March 2005 Orders). Mirant has appealed the March 2005 Orders to the Court of Appeals.
In March 2005, Pepco, FERC, the Office of People's Counsel of the District of Columbia (the District of Columbia OPC), the MPSC and the Office of People's Counsel of Maryland (Maryland OPC) filed in the District Court oppositions to the Second Motion to Reject. In August 2005, the District Court issued an order informally staying this matter, pending a decision by the Court of Appeals on the March 2005 Orders.
On February 9, 2006, oral arguments on Mirant's appeals of the District Court's order relating to the First Motion to Reject and the March 2005 Orders were held before the Court of Appeals; an opinion has not yet been issued.
On December 1, 2005, Mirant filed with the Bankruptcy Court a motion seeking to reject the executory parts of the Asset Purchase and Sale Agreement and its obligations under all other related agreements with Pepco, with the exception of Mirant's obligations relating to operation of the electric generating stations owned by Pepco Energy Services (the Third Motion to Reject). The Third Motion to Reject also seeks disgorgement of payments made by Mirant to Pepco in respect of the PPA-Related Obligations after filing of its bankruptcy petition in July 2003 to the extent the payments exceed the market value of the capacity and energy purchased. On December 21, 2005, Pepco filed an opposition to the Third Motion to Reject in the Bankruptcy Court.
On December 1, 2005, Mirant, in an attempt to "recharacterize" the PPA-Related Obligations, filed a complaint with the Bankruptcy Court seeking (i) a declaratory judgment that the payments due under the PPA-Related Obligations to Pepco are pre-petition debt obligations; and (ii) an order entitling Mirant to recover all payments that it made to Pepco on account of these pre-petition obligations after the petition date to the extent permitted under bankruptcy law (i.e., disgorgement).
On December 15, 2005, Pepco filed a motion with the District Court to withdraw jurisdiction over both of the December 1 filings from the Bankruptcy Court. The motion to withdraw and Mirant's underlying complaint have both been stayed pending a decision of the Court of Appeals in the appeals described above.
Each of the theories advanced by Mirant to recover funds paid to Pepco relating to the PPA-
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Related Obligations as a practical matter seeks reimbursement for the above-market cost of the capacity and energy purchased from Pepco over a period beginning, at the earliest, from the date on which Mirant filed its bankruptcy petition and ending on the date of rejection or the date through which disgorgement is approved. Under these theories, Pepco's financial exposure is the amount paid by Mirant to Pepco in respect of the PPA-Related Obligations during the relevant period, less the amount realized by Mirant from the resale of the purchased energy and capacity. On this basis, Pepco estimates that if Mirant ultimately is successful in rejecting the PPA-Related Obligations or on its alternative claims to recover payments made to Pepco related to the PPA-Related Obligations, Pepco's maximum reimbursement obligation would be approximately $263 million as of March 1, 2006.
If Mirant were ultimately successful in its effort to reject its obligations relating to the Panda PPA, Pepco also would lose the benefit on a going-forward basis of the offsetting transaction that negates the financial risk to Pepco of the Panda PPA. Accordingly, if Pepco were required to purchase capacity and energy from Panda commencing as of March 1, 2006, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 17.1 cents), and resold the capacity and energy at market rates projected, given the characteristics of the Panda PPA, to be approximately 11.0 cents per kilowatt hour, Pepco estimates that it would incur losses of approximately $24 million for the remainder of 2006, approximately $30 million in 2007, and approximately $27 million to $38 million annually thereafter through the 2021 contract termination date. These estimates are based in part on current market prices and forward price estimates for energy and capacity, and do not include financing costs, all of which could be subject to significant fluctuation.
Pepco is continuing to exercise all available legal remedies to vigorously oppose Mirant's efforts to reject or recharacterize the PPA-Related Obligations under the Asset Purchase and Sale Agreement in order to protect the interests of its customers and shareholders. While Pepco believes that it has substantial legal bases to oppose these efforts by Mirant, the ultimate legal outcome is uncertain. However, if Pepco is required to repay to Mirant any amounts received from Mirant in respect of the PPA-Related Obligations, Pepco believes it will be entitled to file a claim against the Mirant bankruptcy estate in an amount equal to the amount repaid. Likewise, if Mirant is successful in its efforts to reject its future obligations relating to the Panda PPA, Pepco will have a claim against Mirant in an amount corresponding to the increased costs that it would incur. In either case, Pepco anticipates that Mirant will contest the claim. To the extent Pepco is successful in its efforts to recover on these claims, it would receive, as in the case of the Pre-Petition Claims, a number of shares of New Mirant Common Stock that is calculated using the market price of the New Mirant Common Stock on the Bankruptcy Emergence Date and accordingly would receive the benefit, and bear the risk, of any change in the market price of the stock between the Bankruptcy Emergence Date and the date the stock is issued to Pepco.
Regulatory Recovery of Mirant Bankruptcy Losses
If Mirant were ultimately successful in rejecting the PPA-Related Obligations or on its alternative claims to recover payments made to Pepco related to the PPA-Related Obligations and Pepco's corresponding claims against the Mirant bankruptcy estate are not recovered in full, Pepco would seek authority from the MPSC and the DCPSC to recover its additional costs. Pepco is committed to working with its regulatory authorities to achieve a result that is appropriate for its shareholders and customers. Under the provisions of the settlement agreements approved by the MPSC and the DCPSC in the deregulation proceedings in which Pepco agreed to divest its generation assets under certain conditions, the PPAs were to become assets of Pepco's distribution business if they could not be sold. Pepco believes that these
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provisions would allow the stranded costs of the PPAs that are not recovered from the Mirant bankruptcy estate to be recovered from Pepco's customers through its distribution rates. If Pepco's interpretation of the settlement agreements is confirmed, Pepco expects to be able to establish the amount of its anticipated recovery from customers as a regulatory asset. However, there is no assurance that Pepco's interpretation of the settlement agreements would be confirmed by the respective public service commissions.
Pepco's Notice of Administrative Claims
On January 24, 2006, Pepco filed Notice of Administrative Claims in the Bankruptcy Court seeking to recover: (i) costs in excess of $70 million associated with the transmission upgrades necessitated by shut-down of the Potomac River Power Station; and (ii) costs in excess of $8 million due to Mirant's unjustified post-petition delay in executing the certificates needed to permit Pepco to refinance certain tax exempt pollution control bonds. Mirant is expected to oppose both of these claims, which must be approved by the Bankruptcy Court. There is no assurance that Pepco will be able to recover the amounts claimed.
Mirant's Fraudulent Transfer Claim
In July 2005, Mirant filed a complaint in the Bankruptcy Court against Pepco alleging that Mirant's $2.65 billion purchase of Pepco's generating assets in June 2000 constituted a fraudulent transfer for which it seeks compensatory and punitive damages. Mirant alleges in the complaint that the value of Pepco's generation assets was "not fair consideration or fair or reasonably equivalent value for the consideration paid to Pepco" and that the purchase of the assets rendered Mirant insolvent, or, alternatively, that Pepco and Southern Energy, Inc. (as predecessor to Mirant) intended that Mirant would incur debts beyond its ability to pay them.
Pepco believes this claim has no merit and is vigorously contesting the claim, which has been withdrawn to the District Court. On December 5, 2005, the District Court entered a stay pending a decision of the Court of Appeals in the appeals described above.
The SMECO Agreement
As a term of the Asset Purchase and Sale Agreement, Pepco assigned to Mirant a facility and capacity agreement with Southern Maryland Electric Cooperative (SMECO) under which Pepco was obligated to purchase the capacity of an 84-megawatt combustion turbine installed and owned by SMECO at a former Pepco generating facility (the SMECO Agreement). The SMECO Agreement expires in 2015 and contemplates a monthly payment to SMECO of approximately $.5 million. Pepco is responsible to SMECO for the performance of the SMECO Agreement if Mirant fails to perform its obligations thereunder. At this time, Mirant continues to make post-petition payments due to SMECO.
On March 15, 2004, Mirant filed a complaint with the Bankruptcy Court seeking a declaratory judgment that the SMECO Agreement is an unexpired lease of non-residential real property rather than an executory contract and that if Mirant were to successfully reject the agreement, any claim against the bankruptcy estate for damages made by SMECO (or by Pepco as subrogee) would be subject to the provisions of the Bankruptcy Code that limit the recovery of rejection damages by lessors.
On November 22, 2005, the Bankruptcy Court issued an order granting summary judgment in favor of Mirant, finding that the SMECO Agreement is an unexpired lease of nonresidential real property. On the basis of this ruling, any claim by SMECO (or by Pepco as subrogee) for
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damages arising from a successful rejection are limited to the greater of (i) the amount of future rental payments due over one year, or (ii) 15% of the future rental payments due over the remaining term of the lease, not to exceed three years.
On December 1, 2005, Mirant filed both a motion with the Bankruptcy Court seeking to reject the SMECO Agreement and a complaint against Pepco and SMECO seeking to recover payments made to SMECO after the entry of the Bankruptcy Court's November 22, 2005 order holding that the SMECO Agreement is a lease of real property. On December 15, 2005, Pepco filed a motion with the District Court to withdraw jurisdiction of this matter from the Bankruptcy Court. The motion to withdraw and Mirant's underlying motion and complaint have been stayed pending a decision of the Court of Appeals in the appeals described above.
If the SMECO Agreement is successfully rejected by Mirant, Pepco will become responsible for the performance of the SMECO Agreement. In addition, if the SMECO Agreement is ultimately determined to be an unexpired lease of nonresidential real property, Pepco's claim for recovery against the Mirant bankruptcy estate would be limited as described above. Pepco estimates that its rejection claim, assuming the SMECO Agreement is determined to be an unexpired lease of nonresidential real property, would be approximately $8 million, and that the amount it would be obligated to pay over the remaining nine years of the SMECO Agreement is approximately $44.3 million. While that amount would be offset by the sale of capacity, under current projections, the market value of the capacity is de minimis.
Rate Proceedings
Delaware
On October 3, 2005, DPL submitted its 2005 gas cost rate (GCR) filing to the DPSC, which permits DPL to recover gas procurement costs through customer rates. In its filing, DPL seeks to increase its GCR by approximately 38% in anticipation of increasing natural gas commodity costs. The proposed rate became effective November 1, 2005, subject to refund pending final DPSC approval after evidentiary hearings. A public input hearing was held on January 19, 2006. DPSC staff and the Division of the Public Advocate filed testimony on February 20, 2006.
As authorized by the April 16, 2002 settlement agreement in Delaware relating to the acquisition of Conectiv by Pepco (the Delaware Merger Settlement Agreement), on May 4, 2005, DPL filed with the DPSC a proposed increase of approximately $6.2 million in electric transmission service revenues, or about 1.1% of total Delaware retail electric revenues. This revenue increase covers the Delaware retail portion of the increase in the "Delmarva zonal" transmission rates on file with FERC under the PJM Open Access Transmission Tariff (OATT) and other transition PJM charges. This level of revenue increase will decrease to the extent that competitive suppliers provide the supply portion and its associated transmission service to retail customers. In that circumstance, PJM would charge the competitive retail supplier the PJM OATT rate for transmission service into the Delmarva zone and DPL's charges to the retail customer would exclude as a "shopping credit" an amount equal to the SOS supply charge and the transmission and ancillary charges that would otherwise be charged by DPL to the retail customer. DPL began collecting this rate change for service rendered on and after June 3, 2005, subject to refund pending final approval by the DPSC.
On September 1, 2005, DPL filed with the DPSC its first comprehensive base rate case in ten
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years. This application was filed as a result of increasing costs and is consistent with a provision in the Delaware Merger Settlement Agreement requiring DPL to file a base rate case by September 1, 2005 and permitting DPL to apply for an increase in rates to be effective no earlier than May 1, 2006. In the application, DPL sought approval of an annual increase of approximately $5.1 million in its electric rates, with an increase of approximately $1.6 million to its electric distribution base rates after proposing to assign approximately $3.5 million in costs to the supply component of rates to be collected as part of the SOS. Of the approximately $1.6 million in net increases to its electric distribution base rates, DPL proposed that approximately $1.2 million be recovered through changes in delivery charges and that the remaining approximately $0.4 million be recovered through changes in premise collection and reconnect fees. The full proposed revenue increase is approximately 0.9% of total annual electric utility revenues, while the proposed net increase to distribution rates is 0.2% of total annual electric utility revenues. DPL's distribution revenue requirement is based on a proposed return on common equity of 11%. DPL also has proposed revised depreciation rates and a number of tariff modifications.
On September 20, 2005, the DPSC issued an order approving DPL's request that the rate increase go into effect on May 1, 2006; subject to refund and pending evidentiary hearings. The order also suspends effectiveness of various proposed tariff rule changes until the case is concluded. The discovery process commenced on October 21, 2005. In its direct testimony, DPSC staff has proposed a variety of adjustments to rate base, operating expenses including depreciation and rate of return with an overall recommendation of a distribution base rate revenue decrease of $14.3 million. The DPSC staff's testimony also addresses issues such as rate design, allocation of any rate decrease and positions regarding the DPL's proposals on certain non-rate tariff modifications. The Delaware Division of Public Advocate has proposed many of the same adjustments and others with an overall recommendation of a distribution base rate revenue decrease of $18.9 million. DPL filed rebuttal testimony on January 17, 2006, which supports a distribution base rate revenue increase of $2 million. On January 30, 2006, the DPSC staff requested the Hearing Examiner approve a modification of the procedural schedule in the case to allow for inclusion of testimony regarding recalculation of DPSC staff's proposed depreciation rates to allow for a separate amortization of the cost of removal reserve. DPL objected to this modification of the procedural schedule. The Hearing Examiner issued a letter ruling on February 1, 2006, which denied DPSC staff's request for a modified procedural schedule. On February 2, 2006, DPSC staff filed an emergency motion requesting the DPSC to permit consideration of the issue by the Hearing Examiner in this docket. On February 6, 2006, the DPSC ruled to allow the issue in the case. A revised procedural schedule was established by the Hearing Examiner on February 10, 2006. On February 15, 2006, DPL filed an interlocutory appeal of the Hearing Examiner's ruling on the procedural schedule with the DPSC. On February 28, 2006, the DPSC upheld the Hearing Examiner's ruling and procedural schedule set on February 10, 2006. DPSC staff filed testimony related to this issue on February 17, 2006. DPSC staff's revised depreciation proposal reduces their recommended proposed rate decrease to $18.9 million, plus the amortization of the cost of removal of $58.4 million, which DPSC staff has recommended be returned to customers through either a 5, 7 or 10-year amortization. DPL continues to oppose the inclusion of this issue in the case for substantive and procedural grounds. Evidentiary hearings were held in early February. Hearings on the separate issue related to the depreciation of the cost of removal are scheduled to be held March 20, 2006. Briefs are due on March 31, 2006 and DPSC deliberation is scheduled to occur on April 25, 2006. DPL cannot predict the outcome of this proceeding.
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District of Columbia and Maryland
On February 27, 2006, Pepco filed for the period February 8, 2002 through February 7, 2004 and for the period February 8, 2004 through February 7, 2005, an update to the District of Columbia Generation Procurement Credit (GPC), which provides for sharing of the profit from SOS sales; and on February 24, 2006, Pepco filed an update for the period July 1, 2003 through June 30, 2004 to the Maryland GPC. The updates to the GPC in both the District of Columbia and Maryland take into account the proceeds from the sale of the $105 million claim against the Mirant bankruptcy estate related to the TPA Settlement on December 13, 2005 for $112.4 million. The filings also incorporate true-ups to previous disbursements in the GPC for both states. In the filings, Pepco requests that $24.3 million be credited to District of Columbia customers and $17.7 million be credited to Maryland customers during the twelve-month-period beginning April 2006.
Federal Energy Regulatory Commission
On January 31, 2005, Pepco, DPL, and ACE filed at FERC to reset their rates for network transmission service using a formula m ethodology. The companies also sought a 12.4% return on common equity and a 50-basis-point return on equity adder that FERC had made available to transmission utilities who had joined Regional Transmission Organizations and thus turned over control of their assets to an independent entity. FERC issued an order on May 31, 2005, approving the rates to go into effect June 1, 2005, subject to refund, hearings, and further orders. The new rates reflect a decrease of 7.7% in Pepco's transmission rate, and increases of 6.5% and 3.3% in DPL's and ACE's transmission rates, respectively. The companies continue in settlement discussions under the supervision of a FERC administrative law judge and cannot predict the ultimate outcome of this proceeding.
Restructuring Deferral
Pursuant to orders issued by the NJBPU under 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 choose a competitive energy 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) that was 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 and was in addition to the base rate increase discussed above. ACE's recovery of the deferred costs is subject to review and approval by the NJBPU in accordance with EDECA.
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
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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, and (iv) estimated the overall deferral balance as of July 31, 2003 at $195 million, of which $44.6 million was disallowed recovery by ACE. ACE believes the record does not justify the level of disallowance imposed by the NJBPU in the final order. In August 2004, ACE filed with the Appellate Division of the Superior Court of New Jersey, which hears appeals of New Jersey administrative agencies, including the NJBPU, a Notice of Appeal with respect to the July 2004 final order. ACE's initial brief was filed on August 17, 2005. Cross-appellant briefs on behalf of the Division of the New Jersey Ratepayer Advocate and Cogentrix Energy Inc., the co-owner of two cogeneration power plants with contracts to sell ACE approximately 397 megawatts of electricity, were filed on October 3, 2005. The NJBPU Staff filed briefs on December 12, 2005. ACE filed its reply briefs on January 30, 2006.
Divestiture Cases
District of Columbia
Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed 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 and its implementing regulations. As of December 31, 2005, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generation 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 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, 2005), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($5.3 million as of December 31, 2005) 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 are due by March 21, 2006, and a public hearing will be held on April 5, 2006.
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Pepco filed a letter with the DCPSC on January 12, 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 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, results of operations or cash flows. It is uncertain when the DCPSC will issue a decision regarding Pepco's divestiture proceeds sharing application.
Maryland
Pepco filed its divestiture proceeds plan application in Maryland 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, 2005, the MPSC allocated portions of EDIT and ADITC associated with the divested generation 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, 2005), 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, 2005), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($9.5 million as of December 31, 2005), 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 on January 12, 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 will be terminated without the issuance of any regulations.
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Pepco has appealed the Hearing Examiner's decision as it relates to the treatment of EDIT and ADITC and corporate reorganization costs to the MPSC. Consistent with Pepco's position in the District of Columbia, Pepco has argued that the only prudent course of action is for the MPSC to await the issuance of final regulations relating to the tax issues or a termination by the IRS of its regulation project without the issuance of any regulations, and then allow the parties to file supplemental briefs on the tax issues. Pepco believes that its calculation of the Maryland customers' share of divestiture proceeds is correct. 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 and make additional gain-sharing payments related 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, results of operations or cash flows.
Default Electricity Supply Proceedings
District of Columbia
Under an order issued by the DCPSC in March 2004, as amended by a DCPSC order issued in July 2004, Pepco is obligated to provide SOS for small commercial and residential customers through May 31, 2011 and for large commercial customers through May 31, 2007. In August 2004, the DCPSC issued an order adopting administrative charges for residential, small and large commercial District of Columbia SOS customers that are intended to allow Pepco to recover the administrative costs incurred to provide the SOS supply. The approved administrative charges include an average margin for Pepco of approximately $.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial District of Columbia SOS customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of SOS customers from each customer class and the load taken by such customers over the time period. The administrative charges went into effect for Pepco's SOS sales on February 8, 2005.
The TPA with Mirant under which Pepco obtained the fixed-rate SOS supply ended on January 22, 2005, while the new SOS supply contracts with the winning bidders in the competitive procurement process began on February 1, 2005. Pepco procured power separately on the market for next-day deliveries to cover the period from January 23 through January 31, 2005, before the new SOS contracts began. Consequently, Pepco had to pay the difference between the procurement cost of power on the market for next-day deliveries and the current SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new SOS rates did not go into effect until February 8, 2005, Pepco had to pay the difference between the procurement cost of power under the new SOS contracts and the SOS rates charged to customers for the period from February 1 to February 7, 2005. The total amount of the difference is estimated to be approximately $8.7 million. This difference, however, was included in the calculation of the GPC for the District of Columbia for the period February 8, 2004 through February 7, 2005, which was filed on July 12, 2005 with the DCPSC. The GPC provides for a sharing between Pepco's customers and shareholders, on an annual basis, of any margins, but not losses, that Pepco earned providing SOS in the District of Columbia during the four-year period from February 8, 2001 through February 7, 2005. At the
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time of the filing, based on the rates paid to Mirant by Pepco under the TPA Settlement, there was no customer sharing. On December 22, 2005 Pepco received $112.4 million in proceeds from the sale of the Pepco TPA Claim against the Mirant bankruptcy estate. A portion of this recovery related to the period February 8, 2004 through February 7, 2005 covered in the July 12 DCPSC filing. As a consequence, on February 27, 2006, Pepco filed with the DCPSC an updated calculation of the customer sharing for this period, which also takes into account the losses incurred during the January 22, 2005 through February 7, 2005 period. The updated filing shows that both residential and commercial customers will receive customer sharing that totals $17.5 million. Without the inclusion of the $8.7 million loss from the January 22, 2005 through February 7, 2005 period, the amount shared with customers would have been approximately $22.7 million, or $5.2 million greater, so that the net effect of the loss on the SOS sales during this period is approximately $3.5 million.
On February 3, 2006, Pepco announced proposed rates for its District of Columbia SOS customers to take effect on June 1, 2006. The new rate will raise the average monthly bill for residential customers by approximately 12%. The proposed rates must be approved by the DCPSC.
Delaware
Under a settlement approved by the DPSC, DPL is required to provide POLR to customers in Delaware through April 2006. DPL is paid for POLR to customers in Delaware at fixed rates established in the settlement. DPL obtains all of the energy needed to fulfill its POLR obligations in Delaware under a supply agreement with its affiliate Conectiv Energy, which terminates in May 2006. DPL does not make any profit or incur any loss on the supply component of the POLR supply that it delivers to its Delaware customers. DPL is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both POLR customers and customers who have selected another energy supplier. These delivery rates generally are frozen through April 2006, except that DPL is allowed to file for a one-time transmission rate change during this period. On March 22, 2005, the DPSC issued an order approving DPL as the SOS provider after May 1, 2006, when DPL's current fixed rate POLR obligation ends. DPL will retain the SOS obligation for an indefinite period until changed by the DPSC, and will purchase the power supply required to satisfy its SOS obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure.
On October 11, 2005, the DPSC approved a settlement agreement, under which DPL will provide SOS to all customer classes, with no specified termination date for SOS. Two categories of SOS will exist: (i) a fixed price SOS available to all but the largest customers; and (ii) an Hourly Priced Service (HPS) for the largest customers. DPL will purchase the power supply required to satisfy its fixed-price SOS obligation from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure. Power to supply the HPS customers will be acquired on next-day and other short-term PJM markets. In addition to the costs of capacity, energy, transmission, and ancillary services associated with the fixed-price SOS and HPS, DPL's initial rates will include a component referred to as the 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 a billing system to be used for billing HPS customers.
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Bids for fixed-priced SOS supply for the May 1, 2006 through May 31, 2007 period were accepted and approved by the DPSC in December 2005 and January 2006. The new SOS rates are scheduled to be effective May 1, 2006.
On February 7, 2006, the Governor of Delaware issued an Executive Order directing the DPSC and other state agencies to examine ways to mitigate the electric rate increases that are expected in May 2006 as a result of rising energy prices. The Executive Order directed the DPSC to examine the feasibility of: (1) deferring or phasing-in the increases; (2) requiring DPL to build generation or enter into long-term supply contracts to meet all, or a portion of, the SOS supply requirements under a traditional regulatory paradigm; (3) directing DPL to conduct integrated resource planning to ensure fuel diversity and least-cost supply alternatives; and (4) requiring DPL to implement demand-side management, conservation and energy efficient programs.
In response to the Executive Order and to help facilitate discussion on several key issues facing the State of Delaware, particularly the issue of rising energy prices, DPL presented a proposed plan to the DPSC on February 28, 2006. A key feature of DPL's proposed plan is a phase-in of rate increases to assist DPL's residential and small commercial customers with the impact of rising energy prices. The proposed phase-in of the rate increase would be in three steps, with one third of the increase to be phased in on May 1, 2006, another one-third on January 1, 2007 and the remainder on June 1, 2007. The phase-in would create a deferral balance of approximately $60 million that would accrue interest and would be recovered through a surcharge imposed for a 24-month period beginning June 1, 2007. DPL believes that this proposal offers a fair and reasonable solution to the concerns identified in the Executive Order.
The Delaware Governor's Cabinet Committee on Energy filed its report with the Governor on March 8, 2006. The report outlines a proposal that recommends: (1) a phase-in of the SOS increase; (2) long-term steps to ensure more stabilized prices and supply; (3) aggregation of the state of Delaware's power needs; and (4) reduction of Delaware's dependence on traditional energy sources through conservation, energy efficiency, and innovation.
DPL intends to file with the DPSC, on or about March 15, 2006, an implementation plan with proposed tariffs based on its proposed phase-in plan as described above. DPL also anticipates that others may advance other legislative or regulatory proposals to address the concerns expressed in the Executive Order. Accordingly, the nature and impact of any changes precipitated by the Executive Order are uncertain and DPL cannot predict at this time whether this phase-in proposal will be implemented.
Maryland
Because of rising energy prices and the resultant expected increases in Pepco's and DPL's rates, on March 3, 2006 the MPSC issued an order initiating an investigation to consider a residential rate stabilization plan for Pepco and DPL. This investigation is driven by the unprecedented national and international events. The MPSC directed the MPSC staff, Pepco and DPL to file comments addressing whether or not the rate stabilization plan that the MPSC adopted for Baltimore Gas & Electric Company in a March 6, 2006 order also should be used for Pepco and DPL. Comments are to be filed by March 16, 2006.
On March 7, 2006, Pepco and DPL each announced the results of competitive bids to supply electricity to its Maryland SOS customers for one year beginning June 1, 2006. The proposed new rates must be approved formally by the MPSC. Due to significant increases in the cost of
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fuels used to generate electricity, the average monthly electric bill will increase by about 38.5% and 35% for Pepco's and DPL's Maryland residential customers, respectively.
Virginia
Under amendments to the Virginia Electric Utility Restructuring Act implemented in March 2004, DPL is obligated to offer Default Service to customers in Virginia for an indefinite period until relieved of that obligation by the VSCC. DPL currently obtains all of the energy and capacity needed to fulfill its Default Service obligations in Virginia under a supply agreement with Conectiv Energy that commenced on January 1, 2005 and expires in May 2006 (the 2005 Supply Agreement). A prior agreement, also with Conectiv Energy, terminated effective December 31, 2004. DPL entered into the 2005 Supply Agreement after conducting a competitive bid procedure in which Conectiv Energy was the lowest bidder.
In October 2004, DPL filed an application with the VSCC for approval to increase the rates that DPL charges its Default Service customers to allow it to recover its costs for power under the 2005 Supply Agreement plus an administrative charge and a margin. A VSCC order issued in November 2004 allowed DPL to put interim rates into effect on January 1, 2005, subject to refund if the VSCC subsequently determined the rate is excessive. The interim rates reflected an increase of 1.0247 cents per Kwh to the fuel rate, which provide for recovery of the entire amount being paid by DPL to Conectiv Energy, but did not include an administrative charge or margin, pending further consideration of this issue. In January 2005, the VSCC ruled that the administrative charge and margin are base rate items not recoverable through a fuel clause. In March 2005, the VSCC approved a settlement resolving all other issues and making the interim rates final.
On March 10, 2006, DPL filed a rate increase with the VSCC to reflect proposed rates for its Virginia Default Service customers to take effect on June 1, 2006. The new rates will raise the average monthly bill for residential customers by approximately 43%. The proposed rates must be approved by the VSCC.
New Jersey
On October 12, 2005, the NJBPU, following the evaluation of proposals submitted by ACE and the other three electric distribution companies located in New Jersey, issued an order reaffirming the current BGS auction process for the annual period from June 1, 2006 through May 2007. The NJBPU order maintains the current size and make up of the Commercial and Industrial Energy Pricing class (CIEP) and approved the electric distribution companies' recommended approach for the CIEP auction product, but deferred a decision on the level of the retail margin funds.
Proposed Shut Down of B.L. England Generating Facility
In April 2004, pursuant to a NJBPU order, ACE filed a report with the NJBPU recommending that ACE's B.L. England generating facility, a 447 megawatt plant, be shut down. The report stated that, while operation of the B.L. England generating facility was necessary at the time of the report to satisfy reliability standards, those reliability standards could also be satisfied in other ways. The report concluded that, based on B.L. England's current and projected operating costs resulting from compliance with more restrictive environmental requirements, the most cost-effective way in which to meet reliability standards is to shut down the B.L. England
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generating facility and construct additional transmission enhancements in southern New Jersey.
In December 2004, ACE filed a petition with the NJBPU requesting that the NJBPU establish a proceeding that will consist of a Phase I and Phase II and that the procedural process for the Phase I proceeding require intervention and participation by all persons interested in the prudence of the decision to shut down B.L. England generating facility and the categories of stranded costs associated with shutting down and dismantling the facility and remediation of the site. ACE contemplates that Phase II of this proceeding, which would be initiated by an ACE filing in 2008 or 2009, would establish the actual level of prudently incurred stranded costs to be recovered from customers in rates. The NJBPU has not acted on this petition.
In a January 24, 2006 Administrative Consent Order (ACO) among PHI, Conectiv, ACE, the New Jersey Department of Environmental Protection (NJDEP) and the Attorney General of New Jersey, ACE agreed to shut down and permanently cease operations at the B.L. England generating facility by December 15, 2007 if ACE does not sell the plant. The shut-down of the B.L. England generating facility will be subject to necessary approvals from the relevant agencies and the outcomes of the auction process, discussed under "ACE Auction of Generating Assets," below.
ACE Auction of Generation Assets
In May 2005, ACE announced that it would again auction its electric generation assets, consisting of its B.L. England generating facility and its ownership interests in the Keystone and Conemaugh generating stations. On November 15, 2005, ACE announced an agreement to sell its interests in the Keystone and Conemaugh generating stations to Duquesne Light Holdings Inc. for $173.1 million. The sale, subject to approval by the NJBPU as well as other regulatory agencies and certain other legal conditions, is expected to be completed mid-year 2006.
Based on the expressed need of the potential B.L. England bidders for the details of the ACO relating to the shut down of the plant that was being negotiated between ACE and the NJDEP, ACE elected to delay the final bid due date for B.L. England until such time as a final ACO was complete and available to bidders. With the January 24, 2006 execution of the ACO by all parties, ACE is proceeding with the auction process. Indicative bids were received on February 16, 2006 and final bids are scheduled to be submitted on or about April 19, 2006.
Under the terms of sale, any successful bid for B.L. England must include assumption of all environmental liabilities associated with the plant in accordance with the auction standards previously issued by the NJBPU.
Any sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. If B.L. England is sold, ACE anticipates that, subject to regulatory approval in Phase II of the proceeding described above, approximately $9.1 million of additional assets may be eligible for recovery as stranded costs. The net gains on the sale of the Keystone and Conemaugh generating stations will be an offset to stranded costs associated with the shutdown of B.L. England or will be offset through other ratemaking adjustments. Testimony filed by ACE with the NJBPU in December 2005 estimated net gains of approximately $126.9 million; however, the net gains ultimately realized will be dependent upon the timing of the closing of the sale of Keystone and Conemaugh generating stations, transaction costs and other factors.
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Federal Tax Treatment of Cross-Border Leases
PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which, as of December 31, 2005, had a book value of approximately $1.3 billion, and from which PHI currently derives approximately $55 million per year in tax benefits in the form of interest and depreciation deductions.
On February 11, 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. In addition, on June 29, 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. On May 4, 2005, the IRS issued a Notice of Proposed Adjustment to PHI that challenges the tax benefits realized from interest and depreciation deductions claimed by PHI with respect to these leases for the tax years 2001 and 2002. The tax benefits claimed by PHI with respect to these leases from 2001 through December 31, 2005 were approximately $230 million. 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 proper based on applicable statutes, regulations and case law, and intends to contest the final adjustments proposed by the IRS; however, there is no assurance that PHI's position will prevail.
On November 18, 2005 the U.S. Senate passed The Tax Relief Act of 2005 (S.2020) which would apply passive loss limitation rules to leases with foreign tax indifferent parties effective for taxable years beginning after December 31, 2005, even if the leases were entered into on or prior to March 12, 2004. On December 8, 2005 the U.S. House of Representatives passed the Tax Relief Extension Reconciliation Act of 2005 (H.R. 4297), which does not contain any provision which would modify the current treatment of leases with tax indifferent parties. Enactment into law of a bill that is similar to S.2020 in its current form could result in a material delay of the income tax benefits that PCI would receive in connection with its cross-border energy leases and thereby adversely affect PHI's financial condition 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.
Under SFAS No. 13, as currently interpreted, a settlement with the IRS or a change in tax law that results in a deferral of tax benefits that does not change the total estimated net income from a lease does not require an adjustment to the book value of the lease. However, if the IRS were to disallow, rather than require the deferral of, certain tax deductions related to PHI's leases, 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 disallowed deductions. Such a charge to earnings, if required, is likely to have a material adverse effect on PHI's financial condition, results of operations, and cash flows for the period in which the charge is recorded.
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In July 2005, the FASB released a Proposed Staff Position paper that would amend SFAS No. 13 and require a lease to be repriced and the book value adjusted when there is a change or probable change in the timing of tax benefits. Under this proposal, a material change in the timing of cash flows under PHI's cross-border leases as the result of a settlement with the IRS or a change in tax law also would require an adjustment to the book value. If adopted in its proposed form, the application of this guidance could result in a material adverse effect on PHI's financial condition, results of operations, and cash flows, even if a resolution with the IRS or a change in tax law is limited to a deferral of the tax benefits realized by PCI from its leases.
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, which allow the companies to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions have 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. On August 2, 2005, the IRS issued Revenue Ruling 2005-53 (the Revenue Ruling) that will limit the ability of the companies to utilize this method of accounting for income tax purposes on their tax returns for 2004 and prior years. PHI intends to contest any IRS adjustment to its prior year income tax returns based on the Revenue Ruling. However, if the IRS is successful in applying this Revenue Ruling, Pepco, DPL, and ACE would be required to capitalize and depreciate a portion of the construction costs previously deducted and repay the associated income tax benefits, along with interest thereon. During 2005, PHI recorded a $10.9 million increase in income tax expense consisting of $6.0 million for Pepco, $2.9 million for DPL, and $2.0 million for ACE, to account for the accrued interest that would be paid on the portion of tax benefits that PHI estimates would be deferred to future years if the construction costs previously deducted are required to be capitalized and depreciated.
On the same day as the Revenue Ruling was issued, the Treasury Department released 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 all future tax periods beginning in 2005. Under these regulations, Pepco, DPL, and ACE will have to capitalize and depreciate a portion of the construction costs that they have previously deducted and include the impact of this adjustment in taxable income over a two-year period beginning with tax year 2005. PHI is continuing to work with the industry to determine an alternative method of accounting for capitalizable construction costs acceptable to the IRS to replace the method disallowed by the proposed regulations.
In February 2006, PHI paid approximately $121 million of taxes to cover the amount of taxes management estimates will be payable once a new final method of tax accounting is adopted on its 2005 tax return, due to the proposed regulations. Although the increase in taxable income will be spread over the 2005 and 2006 tax return periods, the cash payments would have all occurred in 2006 with the filing of the 2005 tax return and the ongoing 2006 estimated tax payments. This $121 million tax payment was accelerated to eliminate the need to accrue additional Federal interest expense for the potential IRS adjustment related to the previous tax accounting method PHI used during the 2001-2004 tax years.
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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, 2005, there are approximately 265 cases still pending against Pepco in the State Courts of Maryland; of those approximately 265 remaining asbestos cases, approximately 85 cases were filed after December 19, 2000, and have been tendered to Mirant Corporation for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement. Mirant's Plan of Reorganization, as approved by the Bankruptcy Court in connection with the Mirant bankruptcy, does not alter Mirant's indemnification obligations. However, litigation relating to Mirant's efforts to reject its contract obligations under the Asset Purchase and Sale Agreement is continuing. In the event Mirant's efforts to reject obligations under the Asset Purchase and Sale Agreement, including the indemnity obligations, were to be successful, Mirant would be relieved of these indemnity obligations and Pepco would have a pre-petition claim for the value of the damages incurred.
While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) exceeds $400 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 and PHI's financial position, results of operations or cash flows.
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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.
In July 2004, DPL entered into an 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 the 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 has completed and submitted the FS to MDE. The costs for completing the RI/FS for this site were approximately $150,000. The costs of cleanup resulting from the RI/FS will not be determinable until MDE identifies the appropriate remedy.
In the early 1970s, both Pepco and DPL sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In December 1987, Pepco and DPL were notified by EPA that they, along with a number of other utilities and non-utilities, were PRPs in connection with the PCB contamination at the site.
In 1994, an RI/FS including a number of possible remedies was submitted to the EPA. In 1997, the EPA issued a Record of Decision that set forth a selected remedial action plan with estimated implementation costs of approximately $17 million. In 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs directing them to conduct the design and actions called for in its decision. In May 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In October 2003, the bankruptcy court confirmed a reorganization plan that incorporates the terms of a settlement among the two debtor owner/operator entities, the United States and a group of utility PRPs including Pepco (the Utility PRPs). Under the bankruptcy settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site (the Bankruptcy Settlement).
On September 2, 2005 the United States lodged with the U.S. District Court for the Eastern District of Pennsylvania global consent decrees for the Metal Bank/Cottman Avenue site, entered into on August 23, 2005 involving the Utility PRPs, the U.S. Department of Justice, EPA, The City of Philadelphia and two owner/operators of the site. Under the terms of the settlement, the two owner/operators will make payments totaling $5.55 million to the U.S. and totaling $4.05 million to the Utility PRPs. The Utility PRPs will perform the remedy at the site and will be able to draw on the $13.25 million from the Bankruptcy Settlement to accomplish the remediation (the Bankruptcy Funds). The Utility PRPs will contribute funds to the extent remediation costs exceed the Bankruptcy Funds available. The Utility PRPs also will be liable for EPA costs associated with overseeing the monitoring and operation of the site remedy after the remedy
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construction is certified to be complete and also the cost of performing the "5 year" review of site conditions required by CERCLA. Any Bankruptcy Funds not spent on the remedy may be used to cover the Utility PRPs' liabilities for future costs. No parties are released from potential liability for damages to natural resources. The global settlement agreement is subject to approval by the court.
As of December 31, 2005, Pepco had accrued $1.7 million to meet its liability for a remedy at the Metal Bank/Cottman Avenue site. While final costs to Pepco of the settlement have not been determined, Pepco believes that its liability at this site will not have a material adverse effect on its financial position, results of operations or cash flows.
In 1999, DPL entered into a de minimis settlement with EPA and paid approximately $107,000 to resolve its liability for cleanup costs at the Metal Bank/Cottman Avenue site. The de minimis settlement did not resolve DPL's responsibility for natural resource damages, if any, at the site. DPL believes that any liability for natural resource damages at this site will not have a material adverse effect on its financial position, results of operations or cash flows.
In June 1992, EPA identified ACE as a PRP at the Bridgeport Rental and Oil Services Superfund site in Logan Township, New Jersey. In September 1996, ACE along with other PRPs signed a consent decree with EPA and NJDEP to address remediation of the site. ACE's liability is limited to .232 percent of the aggregate remediation liability and thus far ACE has made contributions of approximately $105,000. Based on information currently available, ACE anticipates that it may be required to contribute approximately an additional $52,000. ACE believes that its liability at this site will not have a material adverse effect on its financial position, results of operations or cash flows.
In November 1991, 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 completed and the NJDEP conditionally approved the report submitted by the parties on the implementation of the remedy in January 2003. In March 2004, NJDEP approved a Ground Water Sampling and Analysis Plan. Positive results of groundwater monitoring events have resulted in a reduced level of groundwater monitoring. In March 2003, EPA demanded from the PRP group reimbursement for EPA's past costs at the site, totaling $168,789. The PRP group objected to the demand for certain costs, but agreed to reimburse EPA approximately $19,000. Based on information currently available, ACE anticipates that its share of additional cost associated with this site will be approximately $626,000. 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.
On January 24, 2006, PHI, Conectiv and ACE entered into an ACO with NJDEP and the Attorney General of New Jersey. This ACO is the definitive agreement contemplated by the April 26, 2004 preliminary settlement agreement among the parties. The ACO resolves the NJDEP's concerns regarding ACE's compliance with NSR requirements with respect to the B.L. England generating facility and various other environmental issues relating to ACE and Conectiv Energy facilities in New Jersey. See Item 1 "Business -- Environmental Matters -- Air Quality Regulation."
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Third Party Guarantees, Indemnifications, and Off-Balance Sheet Arrangements
Pepco Holdings and certain of its subsidiaries have various financial and performance guarantees and indemnification obligations which are entered into in the normal course of business to facilitate commercial transactions with third parties as discussed below.
As of December 31, 2005, 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 fair value of these commitments and obligations was not required to be recorded in Pepco Holdings' Consolidated Balance Sheets; however, certain energy marketing obligations of Conectiv Energy were recorded. The commitments and obligations, in millions of dollars, were as follows:
1.
Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties related to routine energy sales and procurement obligations, including requirements under BGS contracts entered into with ACE.
2.
Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value related to certain equipment and fleet vehicles held through lease agreements. As of December 31, 2005, obligations under the guarantees were approximately $7.1 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.
3.
Other guarantees consist of:
·
Pepco Holdings has guaranteed payment of a bond issued by a subsidiary of $14.9 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.
·
Pepco Holdings has guaranteed a subsidiary building lease of $3.4 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, 2005, the guarantees cover the remaining $2.4 million in rental obligations.
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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.
Contractual Obligations
As of December 31, 2005, Pepco Holdings' contractual obligations under non-derivative fuel and purchase power contracts, excluding the Panda PPA discussed above under "Relationship with Mirant Corporation" and BGS supplier load commitments, were $1,823.7 million in 2006, $1,705.0 million in 2007 to 2008, $754.3 million in 2009 to 2010, and $3,123.8 million in 2011 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 primary goal of these activities is 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 manage the spread between retail sales commitments and the cost of supply used to service those commitments in order to ensure stable and known minimum cash flows and fix favorable prices and margins when they become available. To a lesser extent, Conectiv Energy also engages in market activities in an effort to profit from short-term geographical price differentials in electricity prices among markets. PHI collectively refers to these energy market activities, including its commodity risk management activities, as "other energy commodity" activities and identifies this activity separately from that of the discontinued proprietary trading activity described below.
Conectiv Energy's 2003 loss includes the unfavorable impact of net trading losses of $26.6 million that resulted from a dramatic rise in natural gas futures prices during February 2003, net of an after tax gain of $15 million on the sale of a purchase power contract in February 2003. As of March 2003, Conectiv Energy ceased all proprietary trading activities, which generally consisted of the entry into contracts to take a view of market direction, capture market price change, and put capital at risk. PHI's Competitive Energy businesses are no longer engaged in proprietary trading; however, the market exposure under certain contracts entered into prior to cessation of proprietary trading activities was not completely eliminated because perfectly offsetting contractual positions were not available in the market at that time. These contracts will remain in place until they are terminated and their values are realized.
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On June 25, 2003, Conectiv Energy entered into an agreement consisting of a series of energy contracts with an international investment banking firm with a senior unsecured debt rating of A+ / Stable from Standard & Poor's (the Counterparty). The agreement was designed to more effectively hedge approximately 50% of Conectiv Energy's generation output and approximately 50% of its supply obligations, with the intention of providing Conectiv Energy with a more predictable earnings stream during the term of the agreement. The agreement consists of two major components: a fixed price energy supply hedge and a generation off-take agreement. The fixed price energy supply hedge is used to reduce Conectiv Energy's financial exposure under its current supply commitment to DPL. Under this commitment, which extends through April 2006, Conectiv Energy is obligated to supply to DPL the electric power necessary to enable DPL to meet its POLR load obligations. Under the energy supply hedge, the volume and price risks associated with 50% of the POLR load obligation are effectively transferred from Conectiv Energy to the Counterparty through a financial "contract-for-differences." The contract-for-differences (swap) establishes a fixed cost for the energy required by Conectiv Energy to satisfy 50% of the POLR load, and any deviations of the market price from the fixed price are paid by Conectiv Energy to, or are received by Conectiv Energy from, the Counterparty. The contract does not cover the cost of capacity or ancillary services. Under the generation off-take agreement, Conectiv Energy receives a fixed monthly payment from the Counterparty and the Counterparty receives the profit realized from the sale of approximately 50% of the electricity generated by Conectiv Energy's plants (excluding the Edge Moor facility) through May 2006. This portion of the agreement is designed to hedge sales of approximately 50% of Conectiv Energy's generation output, and under assumed operating parameters and market conditions should effectively transfer this portion of Conectiv Energy's wholesale energy market risk to the Counterparty, while providing a more stable stream of revenues to Conectiv Energy. The agreement also includes several standard energy price swaps under which Conectiv Energy has locked in a sales price for approximately 50% of the output from its Edge Moor facility and has financially hedged other on-peak and off-peak energy price exposures in its portfolio to further reduce market price exposure. In total, the transaction is expected to improve Conectiv Energy's risk profile by providing hedges that are tailored to the characteristics of its generation fleet and its POLR supply obligation.
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 $40.1 million in Accumulated Other Comprehensive Income (AOCI) at December 31, 2005 related to this transaction. The portion expected to be reclassified to earnings during the next 12 months is $7.1 million. In addition, interest rate swaps have been executed in support of PCI's medium-term note program.
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, 2005. 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.
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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, 2005, 2004, and 2003, and where they were reported in the Consolidated Statements of Earnings during the period.
Operating Revenue
$ 3.0
$ 2.5
$ 1.8
Fuel and Purchased Energy Expenses
(2.7)
(8.5)
(2.8)
Total
$ .3
$(6.0)
$(1.0)
For the years ended December 31, 2005 and 2004, there were no forecasted hedged transactions 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, 2005, 2004, and 2003.
Proprietary Trading
$ .1
$ (.4)
$(67.3)
Other Energy Commodity
37.8
24.2
19.6
Total
$37.9
$23.8
$(47.7)
(14) EXTRAORDINARY ITEMS
On April 19, 2005, ACE, the staff of the New Jersey Board of Public Utilities (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.
In July 2003, the NJBPU approved the recovery of $149.5 million of stranded costs related to ACE's B.L. England generating facility. As a result of the order, ACE reversed $10.0 million of accruals for the possible disallowances related to these stranded costs. The after tax credit to income of $5.9 million
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is classified as an extraordinary gain in the 2003 financial statements, since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.
(15) RESTATEMENT
Pepco Holdings restated its previously reported consolidated financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct the accounting for certain deferred compensation arrangements. The restatement includes the correction of other errors for the same periods, primarily relating to unbilled revenue, taxes, and various accrual accounts, which were considered by management to be immaterial. These other errors would not themselves have required a restatement absent the restatement to correct the accounting for deferred compensation arrangements. This restatement was required solely because the cumulative impact of the correction, if recorded in the fourth quarter of 2005, would have been material to that period's reported net income. The impact of the restatement related to the deferred compensation arrangements on periods prior to 2003 has been reflected as a reduction of approximately $23 million to Pepco Holdings' retained earnings balance as of January 1, 2003. The following table sets forth for Pepco Holdings, for the years ended December 31, 2004 and 2003, the impact of the restatement to correct the accounting for the deferred compensation arrangements and the other errors noted above (millions of dollars):
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(16) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The unaudited quarterly financial information for the three months ended March 31, 2005, June 30, 2005, and September 30, 2005 and all interim periods during the year ended December 31, 2004 have been restated to reflect the correction of the accounting for certain deferred compensation arrangements and other noted errors that would not themselves have required a restatement absent the restatement to correct the accounting for the deferred compensation arrangements as described in Note 15. 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.
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(a)
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 an extraordinary gain since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.
(b)
Includes $8.3 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.
(c)
Includes $68.1 million gain ($40.7 million after tax) from sale of non-utility land owned by Pepco at Buzzard Point.
(d)
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 claim against the Mirant bankruptcy estate.
(e)
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.
(f)
Includes $2.6 million in income tax expense related to the mixed service cost issue under IRS Ruling
2005-53.
(g)
Includes tax benefit of $13.2 million related to a local jurisdiction's final consolidated tax return regulations, which are retroactive to 2001.
(h)
Includes an $11.2 million pre-tax impairment charge ($7.3 million after tax) to reduce the value of PHI's investment in Starpower Communications, LLC to $28 million. Also includes $11.2 million pre-tax gain ($6.6 million after tax) from the disposition of a joint venture associated with the Vineland co-generation facility.
(i)
Includes $12.8 million pre-tax loss ($7.7 million after tax) associated with the prepayment of the debt incurred by Conectiv Bethlehem, LLC.
(j)
Includes a $14.7 million pre-tax ($8.6 million after tax) gain from the condemnation settlement associated with the transfer of Vineland distribution assets.
(k)
Includes a $19.7 million charge related to an IRS Settlement.
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(17) SUBSEQUENT EVENTS
On February 9, 2006, certain institutional buyers tentatively agreed to purchase in a private placement $105 million of ACE's senior notes having an interest rate of 5.80% and a term of 30 years. The execution of a definitive purchase agreement and closing is expected on or about March 15, 2006. The proceeds from the notes would be used to repay outstanding commercial paper issued by ACE to fund the payment at maturity of $105 million in principal amount of various issues of medium-term notes.
On March 1, 2006, Pepco redeemed all outstanding shares of its Serial Preferred Stock of each series, at 102% of par, for an aggregate redemption amount of $21.9 million.
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Report of Independent Registered Public Accounting Firm
To the 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, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 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 disclosed in Note 13 to the financial statements, the Company restated its financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003.
PricewaterhouseCoopers LLP
Washington, D.C.
March 13, 2006
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NOTES TO FINANCIAL STATEMENTS
POTOMAC ELECTRIC POWER COMPANY
(1) ORGANIZATION
Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in Washington, D.C. and major portions of Prince George's 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's service territory covers approximately 640 square miles and has a population of approximately 2 million. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or 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 Pepco and certain activities of Pepco are subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC) under PUHCA 2005.
(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, such as Statement of Position 94-6, "Disclosure of Certain Significant Risks and Uncertainties," 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. Examples of 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, and judgment involved with assessing the probability of recovery of regulatory assets. 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 based upon the probable and reasonably estimable criteria contained in SFAS No. 5, "Accounting for Contingencies." 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.
Change in Accounting Estimates
During 2005, Pepco recorded the impact of an increase in estimated unbilled revenue, primarily reflecting a change in Pepco's unbilled revenue estimation process. This modification in accounting estimate increased Pepco's net earnings for the year ended December 31, 2005 by approximately $2.2 million.
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Regulation of Power Delivery Operations
Pepco is regulated by the Maryland Public Service Commission (MPSC) and the District of Columbia Public Service Commission (DCPSC), and its wholesale business is regulated by the Federal Energy Regulatory Commission (FERC).
Based on the regulatory framework in which it has operated, Pepco has historically applied, and in connection with its transmission and distribution business continues to apply, the provisions of Statement of Financial Accounting Standards 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.
The components of Pepco's regulatory asset balances at December 31, 2005 and 2004, are as follows:
The components of Pepco's regulatory liability balances at December 31, 2005 and 2004, are as follows:
A description of the regulatory assets and regulatory liabilities is as follows:
Deferred Recoverable Income Taxes: Represents deferred income tax assets recognized from the normalization of flow-through items as a result of amounts previously provided to customers. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return on these deferrals.
Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period. A return is received
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on these deferrals.
Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years and generally do not receive a return.
Deferred Income Taxes Due to Customers: Represents the portion of deferred income tax liabilities applicable to Pepco's utility operations that has not been reflected in current customer rates for which future payment to customers is probable. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized.
Generation Procurement Credit (GPC) and Customer Sharing Commitment: Pepco's generation divestiture settlement agreements, approved by both the DCPSC and MPSC, required the sharing between customers and shareholders of any profits earned during the four year transition period from February 8, 2001 through February 7, 2005 in each jurisdiction. The GPC represents the customers' share of profits that Pepco has realized on the procurement and resale of Standard Offer Service electricity supply to customers in Maryland and the District of Columbia that has not yet been distributed to customers. Pepco is currently distributing the customers' share of profits monthly to customers in a billing credit.
Accrued Asset Removal Costs: Represents Pepco's asset retirement obligation associated with removal costs accrued using public service commission approved depreciation rates for transmission, distribution, and general utility property. In accordance with the SEC interpretation of SFAS No. 143, accruals for removal costs were classified as a regulatory liability.
Revenue Recognition
Pepco recognizes revenue for the supply and delivery of electricity to customers, including amounts for services rendered, but not yet billed (unbilled revenue). Pepco recorded amounts for unbilled revenue of $92.6 million and $103.2 million as of December 31, 2005 and 2004, respectively. These amounts are included in the "accounts receivable" line item in the accompanying balance sheets. Pepco calculates unbilled revenue using an output based methodology. This methodology is based on the supply of electricity or gas distributed to customers. The unbilled revenue process requires management 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), 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 the Company's tariffs and, as such, are billed to customers and recorded in Operating Revenues. Accruals for these taxes by the Company are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by the Company in the normal course of business is charged to operations, maintenance or construction, and is de minimis.
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Asset Retirement Obligations
Pepco adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," on January 1, 2003 and FIN 47 as of December 31, 2005. This statement and related interpretation establish the accounting and reporting standards for measuring and recording asset retirement obligations. Based on the implementation of SFAS No. 143, $65.0 million and $77.2 million at December 31, 2005 and 2004, 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 expense 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 $73.1 million at December 31, 2005.
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.
Capitalized Interest and Allowance for Funds Used During Construction
In accordance with the provisions of SFAS No. 34, "Capitalization of Interest Cost," the cost of financing the construction of Pepco Holdings' subsidiaries electric generating plants is capitalized. Other non-utility construction projects also include financing costs in accordance with SFAS No. 34. In accordance with the provisions of SFAS No. 71, utilities can capitalize Allowance for Funds Used During Construction (AFUDC) as part of the cost of plant and equipment. AFUDC recognizes that utility construction is financed partially by debt and partially by equity.
Pepco recorded AFUDC for borrowed funds of $1.6 million, $1.2 million, and $1.8 million for the years ended December 31, 2005, 2004, and 2003, respectively. These amounts are recorded as a reduction of "interest expense" in the accompanying Statements of Earnings.
Pepco recorded amounts for the equity component of AFUDC of $2.6 million, $2.0 million, and $2.9 million for the years ended December 31, 2005, 2004, and 2003, respectively. The amounts are included in the "other income" caption of the accompanying Statements of Earnings.
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Amortization Of Debt Issuance And Reacquisition Costs
Expenses incurred in connection with the issuance of long-term debt, including premiums and discounts associated with such debt, are deferred and amortized over the lives of the respective debt issues. Costs associated with the reacquisition of debt are also deferred and amortized over the lives of the new issues.
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. Additionally, during 2002, Pepco Holdings' management approved initiatives by Pepco and Conectiv to streamline its operating structure by reducing the number of employees at each company. These initiatives met the criteria for the accounting treatment provided under EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." A roll forward of Pepco's severance accrual balance is as follows (Millions of dollars).
Balance, December 31, 2003
$ 3.3
Accrued during 2004
.9
Payments/reversals during 2004
(2.0
)
Balance, December 31, 2004
2.2
Accrued during 2005
(.1)
Payments/reversals during 2005
(2.1)
Balance, December 31, 2005
$ -
Pension and Other Postretirement Benefit Plans
Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings' subsidiaries (Retirement Plan). Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan for Pepco employees are identical to those of the original Pepco plan and for Conectiv employees are identical to the original Conectiv plan. 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 Company accounts for the Retirement Plan in accordance with SFAS No. 87, "Employers' Accounting for Pensions," and its other postretirement benefits in accordance with SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." PHI's financial statement disclosures were prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits."
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Long-Lived Asset Impairment Evaluation
Pepco is required to evaluate certain assets that have long lives (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist. SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," provides the accounting for impairments of long-lived assets and indicates that companies are required to test long-lived assets for recoverability 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. For long-lived assets that are expected to be held and used, SFAS No. 144 requires that an impairment loss be recognized only if the carrying amount of an asset is not recoverable and exceeds its fair value.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. 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 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 2005, 2004, and 2003 for Pepco's transmission and distribution system property were approximately 3.4%, 3.5%, and 3.5%, 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.
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 taxes are discussed below.
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.
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Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.
Investment tax credits from utility plants purchased in prior years are reported on the 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
Due to a variable element in the pricing structure of Pepco's purchase power agreement (Panda PPA) with Panda-Brandywine, L.P. (Panda), Pepco potentially assumes the variability in the operations of the plants related to this PPA and therefore has a variable interest in the entity. As required by FIN 46R, Pepco continued during 2005 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, 2005, 2004 and 2003, were approximately $91 million, $76 million and $80 million, respectively. Pepco's exposure to loss under the Panda PPA is discussed in Note (11), Commitments and Contingencies, under "Relationship with Mirant Corporation."
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 the current portion of deferred income taxes.
Other Deferred Credits
The other deferred credits balance principally consists of miscellaneous deferred liabilities.
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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; (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; and (iii) certain provisions of the charter of Pepco, which impose restrictions on payment of common stock dividends for the benefit of future preferred stockholders.
New Accounting Standards
SFAS No. 154
In May 2005, the FASB issued Statement No. 154, "Accounting Changes and Error Corrections (SFAS No. 154), a replacement of APB Opinion No. 20 and FASB Statement No. 3." SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. The reporting of a correction of an error by restating previously issued financial statements is also addressed by SFAS No. 154. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 (the year ended December 31, 2006 for Pepco). Early adoption is permitted.
EITF 04-13
In September 2005, the FASB ratified EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" (EITF 04-13), which addresses circumstances under which two or more exchange transactions involving inventory with the same counterparty should be viewed as a single exchange transaction for the purposes of evaluating the effect of APB Opinion 29. EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006 (April 1, 2006 for Pepco). EITF 04-13 would not affect Pepco's net income, overall financial condition, or cash flows, but rather could result in certain revenues and costs, including wholesale revenues and purchased power expenses, being presented on a net basis. Pepco is in the process of evaluating the impact of EITF 04-13 on its Statements of Earnings presentation of purchases and sales.
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(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's power dispatchers to centrally control the operation of its transmission and distribution systems. The 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 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 of 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, 2005 and 2004 are comprised of the following:
(Millions of dollars)
At December 31, 2005
Original Cost
Accumulated
Amortization
Net Book Value
Transmission
$ 76.0
$15.7
$ 60.3
Distribution
76.0
15.7
60.3
Other
2.6
1.8
.8
Total
$154.6
$33.2
$121.4
At December 31, 2004
Transmission
$ 76.0
$13.6
$ 62.4
Distribution
76.0
13.6
62.4
Other
2.6
1.2
1.4
Total
$154.6
$28.4
$126.2
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(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. The system-wide composite depreciation rates for 2005, 2004, and 2003 for Pepco's transmission and distribution system property were approximately 3.4%, 3.5%, and 3.5%, respectively.
Gain on Sales of Assets
In August 2005, Pepco sold for $75 million in cash 384,051 square feet of excess non-utility land owned by Pepco 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
Pension Benefits
Pepco Holdings sponsors a defined benefit Retirement Plan that 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.
Other Postretirement Benefits
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.
During 2004, PHI amended its postretirement health care plans for certain groups of eligible employees effective January 1, 2005 or January 1, 2006. The amendments included changes to coverage and retiree cost-sharing, and are reflected as a reduction in PHI's 2004 net periodic
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benefit cost and a reduction of $42 million in the projected benefit obligation at December 31, 2004.
Pepco Holdings uses a December 31 measurement date for its plans. Plan assets are stated at their market value as of the measurement date, December 31. All dollar amounts in the following tables are in millions of dollars.
The following table provides a reconciliation of the projected benefit obligation, plan assets and funded status of the plans.
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The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheet as of December 31:
The accumulated benefit obligation for the Retirement Plan (the qualified defined benefit pension plan) was $1,556.2 million and $1,462.9 million at December 31, 2005, and 2004, respectively. The table below provides the projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the PHI nonqualified pension plan with an accumulated benefit obligation in excess of plan assets at December 31, 2005 and 2004.
In 2005 and 2004, PHI was required to recognize an additional minimum liability and an intangible asset related to its nonqualified pension plan as prescribed by SFAS No. 87. The liability was recorded as a reduction to shareholders' equity (other comprehensive income), and the equity will be restored to the balance sheet in future periods when the accrued benefit liability exceeds the accumulated benefit obligation at future measurement dates. The amount of reduction to shareholders' equity (net of income taxes) in 2005 was $7.3 million and in 2004 was $4.1 million. The recording of this reduction did not affect net income or cash flows in 2005 or 2004 or compliance with debt covenants.
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The table below provides the components of net periodic benefit costs recognized for the years ended December 31.
Approximately $28.9 million, $24.1 million and $33.7 million were included in capital and operating and maintenance expense, in 2005, 2004 and 2003, respectively, for Pepco's allocated portion of PHI's combined pension and other postretirement benefit expense.
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
Effect on total of service and interest cost
$ 1.8
$ (1.7)
Effect on postretirement benefit obligation
27.0
(25.1)
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The following weighted average assumptions were used to determine the net periodic benefit cost for years ended December 31:
A cash flow matched bond portfolio approach to developing a discount rate is used to value FAS 87 and FAS 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 time horizon, are expected to yield a return on assets of 8.50%.
Plan Assets
Pepco Holdings' Retirement Plan weighted-average asset allocations at December 31, 2005, and 2004, by asset category are as follows:
Pepco Holdings' other postretirement plan weighted-average asset allocations at December 31, 2005, and 2004, by asset category are as follows:
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In developing an asset allocation policy for its 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 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 - Retirement Plan
Pepco Holdings' funding policy with regard to the Retirement Plan is to maintain a funding level in excess of 100% with respect to its accumulated benefit obligation (ABO). PHI's Retirement Plan currently meets the minimum funding requirements of ERISA without any additional funding. In 2005 and 2004, PHI made discretionary tax-deductible cash contributions to the plan of $60.0 million and $10.0 million, respectively, in line with its funding policy. Assuming no changes to the current pension plan assumptions, PHI projects no funding will be required under ERISA in 2006; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its plan assets in excess of its ABO.
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Contributions - Other Postretirement Benefits
In 2005, PHI combined its health and welfare plans and the existing IRC 501 (c) (9) Voluntary Employee Beneficiary Association (VEBA) trusts for Pepco, DPL and ACE to fund a portion of their estimated postretirement liabilities. Pepco contributed $3.1 million and $4.7 million to the PHI-sponsored plan in 2005 and 2004, respectively. Assuming no changes to the current plan assumptions, Pepco expects to contribute amounts similar to its allocated portion of PHI's other postretirement benefit expense to the other postretirement welfare benefit plan in 2006.
Expected Benefit Payments
Estimated future benefit payments to participants in PHI's qualified pension and postretirement welfare benefit plans, which reflect expected future service as appropriate, as of December 31, 2005 are in millions of dollars:
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(7) 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 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. At such time as there are no First Mortgage Bonds of an issuing company outstanding, other than collateral First Mortgage Bonds securing payment of senior notes and tax-exempt bonds, each outstanding series of senior notes and tax-exempt bonds of the company will automatically cease to be secured by the corresponding series of collateral First Mortgage Bonds and all of the outstanding collateral First Mortgage Bonds of the company will be cancelled. 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.
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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, 2005, that will mature in each of 2006 through 2010 and thereafter is as follows: $50 million in 2006, $210 million in 2007, $128 million in 2008, $50 million in 2009, $16 million in 2010, and $797.8 million thereafter.
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. Pepco had no short-term debt outstanding at December 31, 2005 and $14.0 million in inter-company borrowings outstanding at December 31, 2004.
Commercial Paper
Pepco maintains an ongoing commercial paper program of up to $300 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 DPL and ACE.
Pepco had no commercial paper outstanding at December 31, 2005 and December 31, 2004. No commercial paper was issued during 2005. The interest rate for commercial paper issued during 2004 was 1.07%.
Credit Facility
In May 2005, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $1.2 billion. This agreement replaces a $650 million five-year credit agreement that was entered into in July 2004 and a $550 million three-year credit agreement entered into in July 2003. Pepco Holdings' credit limit under this agreement is $700 million. The credit limit of each of Pepco, DPL and ACE is the lower of $300 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 under the agreement may not exceed $500 million. Under the terms of the credit agreement, the companies are entitled to request increases in the principal amount of available credit up to an aggregate increase of $300 million, with any such increase proportionately increasing the credit limit of each of the respective borrowers and the $300 million sublimits for each of Pepco, DPL and ACE. The interest rate payable by the respective companies on utilized funds is determined by a pricing schedule with rates corresponding to the credit rating of the borrower. Any indebtedness incurred under the credit agreement would be unsecured.
The credit agreement 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
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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 contained in the credit agreement 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, (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 failure to satisfy any of the covenants or the occurrence of specified events that constitute an event of default could result in the acceleration of the repayment obligations of the borrower. The events of default include (i) the failure of any borrowing company or any of its significant subsidiaries to pay when due, or the acceleration of, certain indebtedness under other borrowing arrangements, (ii) certain bankruptcy events, judgments or decrees against any borrowing company or its significant subsidiaries, and (iii) a change in control (as defined in the credit agreement) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE. The agreement does not include any ratings triggers. There were no balances outstanding at December 31, 2005 and 2004.
(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 which was approved by the Securities and Exchange Commission pursuant to regulations under the Public Utility Holding Company Act of 1935 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, with the exception of the tax benefits applicable to non-acquisition debt expenses of PHI. Such tax benefits are allocated to subsidiaries with taxable income.
The provision for income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred income tax liabilities (assets) are shown below.
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Provision for Income Taxes
Reconciliation of Income Tax Expense
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Components of Deferred Income Tax Liabilities (Assets)
The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement 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, 2005 and 2004.
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.
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 credit carrybacks from subsequent years.
Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below.
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(9) PREFERRED STOCK
The preferred stock amounts outstanding as of December 31, 2005 and 2004 are as follows.
(1)
In September and October of 2004, Pepco redeemed 81,400 and 84,502 shares, respectively, of its $2.28 Series 1965 Serial Preferred Stock for aggregate redemption amounts of $4.1 million and $4.2 million, respectively. In October 2005, Pepco redeemed 74,103 shares of its $2.46 Series 1958 Serial Preferred Stock, 13,148 shares of its $2.28 Series 1965 Serial Preferred Stock and 22,795 shares of its $2.44 Series 1957 Serial Preferred Stock for an aggregate redemption amount of $3.7 million, $.7 million and $1.1 million, respectively. On March 1, 2006, Pepco redeemed all outstanding shares of its Serial Preferred Stock of each series, at 102% of par, for an aggregate redemption amount of $21.9 million.
(10) FAIR VALUES OF FINANCIAL INSTRUMENTS
The estimated fair values of Pepco's financial instruments at December 31, 2005 and 2004 are shown below.
The methods and assumptions described below were used to estimate, at December 31, 2005 and 2004, 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, Medium-Term Notes, and Unsecured Notes, excluding 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.
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The fair value of the Serial Preferred Stock, excluding amounts due within one year, was 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's accompanying financial statements approximate fair value.
(11) COMMITMENTS AND CONTINGENCIES
REGULATORY AND OTHER MATTERS
Relationship with Mirant Corporation
In 2000, Pepco sold substantially all of its electricity generation assets to Mirant Corporation, formerly Southern Energy, Inc. As part of the Asset Purchase and Sale Agreement, Pepco entered into several ongoing contractual arrangements with Mirant Corporation and certain of its subsidiaries. In July 2003, Mirant Corporation and most of its subsidiaries filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas (the Bankruptcy Court). On December 9, 2005, the Bankruptcy Court approved Mirant's Plan of Reorganization (the Reorganization Plan) and the Mirant business emerged from bankruptcy on January 3, 2006 (the Bankruptcy Emergence Date), in the form of a new corporation of the same name (together with its predecessors, Mirant). However, as discussed below, the Reorganization Plan did not resolve all of the outstanding matters between Pepco and Mirant relating to the Mirant bankruptcy and the litigation between Pepco and Mirant over these matters is ongoing.
Depending on the outcome of ongoing litigation, the Mirant bankruptcy could have a material adverse effect on the results of operations and cash flows of Pepco Holdings and Pepco. However, management believes that Pepco Holdings and Pepco currently have sufficient cash, cash flow and borrowing capacity under their credit facilities and in the capital markets to be able to satisfy any additional cash requirements that may arise due to the Mirant bankruptcy. Accordingly, management does not anticipate that the Mirant bankruptcy will impair the ability of either Pepco Holdings or Pepco to fulfill its contractual obligations or to fund projected capital expenditures. On this basis, management currently does not believe that the Mirant bankruptcy will have a material adverse effect on the financial condition of either company.
Transition Power Agreements
As part of the Asset Purchase and Sale Agreement, Pepco and Mirant entered into Transition Power Agreements for Maryland and the District of Columbia, respectively (collectively, the TPAs). Under the TPAs, Mirant was obligated to supply Pepco with all of the capacity and energy needed to fulfill Pepco's SOS obligations during the rate cap periods in each jurisdiction immediately following deregulation, which in Maryland extended through June 2004 and in the District of Columbia extended until January 22, 2005.
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To avoid the potential rejection of the TPAs by Mirant in the bankruptcy proceeding, Pepco and Mirant in October 2003 entered into an Amended Settlement Agreement and Release (the Settlement Agreement) pursuant to which the terms of the TPAs were modified to increase the purchase price of the capacity and energy supplied by Mirant. In exchange, the Settlement Agreement provided Pepco with an allowed, pre-petition general unsecured claim against Mirant Corporation in the amount of $105 million (the Pepco TPA Claim).
On December 22, 2005, Pepco completed the sale of the Pepco TPA Claim, plus the right to receive accrued interest thereon, to Deutsche Bank for a cash payment of $112.4 million. Additionally, Pepco received $0.5 million in proceeds from Mirant in settlement of an asbestos claim against the Mirant bankruptcy estate. Pepco Holdings and Pepco recognized a total gain of $70.5 million (pre-tax) related to the settlement of these claims. Based on the regulatory settlements entered into in connection with deregulation in Maryland and the District of Columbia, Pepco is obligated to share with its customers the profits it realizes from the provision of SOS during the rate cap periods. The proceeds of the sale of the Pepco TPA Claim will be included in the calculations of the amounts required to be shared with customers in both jurisdictions. Based on the applicable sharing formulas in the respective jurisdictions, Pepco anticipates that customers will receive (through billing credits) approximately $42.3 million of the proceeds over a 12-month period beginning in March 2006 (subject to DCPSC and MPSC approvals).
Power Purchase Agreements
Under agreements with FirstEnergy Corp., formerly Ohio Edison (FirstEnergy), and Allegheny Energy, Inc., both entered into in 1987, Pepco was obligated to purchase 450 megawatts of capacity and energy from FirstEnergy annually through December 2005 (the FirstEnergy PPA). Under the Panda PPA, entered into in 1991, Pepco is obligated to purchase 230 megawatts of capacity and energy from Panda annually through 2021. At the time of the sale of Pepco's generation assets to Mirant, the purchase price of the energy and capacity under the PPAs was, and since that time has continued to be, substantially in excess of the market price. As a part of the Asset Purchase and Sale Agreement, Pepco entered into a "back-to-back" arrangement with Mirant. Under this arrangement, Mirant (i) was obligated, through December 2005, to purchase from Pepco the capacity and energy that Pepco was obligated to purchase under the FirstEnergy PPA at a price equal to Pepco's purchase price from FirstEnergy, and (ii) is obligated through 2021 to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the Panda PPA at a price equal to Pepco's purchase price from Panda (the PPA-Related Obligations). Mirant currently is making these required payments.
Pepco Pre-Petition Claims
At the time the Reorganization Plan was approved by the Bankruptcy Court, Pepco had pending pre-petition claims against Mirant totaling approximately $28.5 million (the Pre-Petition Claims), consisting of (i) approximately $26 million in payments due to Pepco in respect of the PPA-Related Obligations and (ii) approximately $2.5 million that Pepco has paid to Panda in settlement of certain billing disputes under the Panda PPA that related to periods after the sale of Pepco's generation assets to Mirant and prior to Mirant's bankruptcy filing, for which Pepco believes Mirant is obligated to reimburse it under the terms of the Asset Purchase and Sale Agreement. In the bankruptcy proceeding, Mirant filed an objection to the Pre-Petition Claims. The Pre-Petition Claims were not resolved in the Reorganization Plan and are the subject of ongoing litigation between Pepco and Mirant. To the extent Pepco is successful in its
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efforts to recover the Pre-Petition Claims, it would receive under the terms of the Reorganization Plan a number of shares of common stock of the new corporation created pursuant to the Reorganization Plan (the New Mirant Common Stock) equal to (i) the amount of the allowed claim (ii) divided by the market price of the New Mirant Common Stock on the Bankruptcy Emergence Date. Because the number of shares is based on the market price of the New Mirant Common Stock on the Bankruptcy Emergence Date, Pepco would receive the benefit, and bear the risk, of any change in the market price of the stock between the Bankruptcy Emergence Date and the date the stock is issued to Pepco.
As of December 31, 2005, Pepco maintained a receivable in the amount of $28.5 million, representing the Pre-Petition Claims, which was offset by a reserve of $14.5 million established by an expense recorded in 2003 to reflect the uncertainty as to whether the entire amount of the Pre-Petition Claims is recoverable. As of December 31, 2005, this reserve was reduced to $9.6 million to reflect the fact that there was no longer an objection to $15 million of Pepco's claim.
Mirant's Efforts to Reject the PPA-Related Obligations and Disgorgement Claims
In August 2003, Mirant filed with the Bankruptcy Court a motion seeking authorization to reject the PPA-Related Obligations (the First Motion to Reject). Upon motions filed with the U.S. District Court for the Northern District of Texas (the District Court) by Pepco and FERC, the District Court in October 2003 withdrew jurisdiction over this matter from the Bankruptcy Court. In December 2003, the District Court denied Mirant's motion to reject the PPA-Related Obligations on jurisdictional grounds. Mirant appealed the District Court's decision to the U.S. Court of Appeals for the Fifth Circuit (the Court of Appeals). In August 2004, the Court of Appeals remanded the case to the District Court holding that the District Court had jurisdiction to rule on the merits of Mirant's rejection motion, suggesting that in doing so the court apply a "more rigorous standard" than the business judgment rule usually applied by bankruptcy courts in ruling on rejection motions.
In December 2004, the District Court issued an order again denying Mirant's motion to reject the PPA-Related Obligations. The District Court found that the PPA-Related Obligations are not severable from the Asset Purchase and Sale Agreement and that the Asset Purchase and Sale Agreement cannot be rejected in part, as Mirant was seeking to do. Mirant has appealed the District Court's order to the Court of Appeals.
In January 2005, Mirant filed in the Bankruptcy Court a motion seeking to reject certain of its ongoing obligations under the Asset Purchase and Sale Agreement, including the PPA-Related Obligations (the Second Motion to Reject). In March 2005, the District Court entered orders granting Pepco's motion to withdraw jurisdiction over these rejection proceedings from the Bankruptcy Court and ordering Mirant to continue to perform the PPA-Related Obligations (the March 2005 Orders). Mirant has appealed the March 2005 Orders to the Court of Appeals.
In March 2005, Pepco, FERC, the Office of People's Counsel of the District of Columbia (the District of Columbia OPC), the MPSC and the Office of People's Counsel of Maryland (Maryland OPC) filed in the District Court oppositions to the Second Motion to Reject. In August 2005, the District Court issued an order informally staying this matter, pending a decision by the Court of Appeals on the March 2005 Orders.
On February 9, 2006, oral arguments on Mirant's appeals of the District Court's order relating to the First Motion to Reject and the March 2005 Orders were held before the Court of Appeals;
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an opinion has not yet been issued.
On December 1, 2005, Mirant filed with the Bankruptcy Court a motion seeking to reject the executory parts of the Asset Purchase and Sale Agreement and its obligations under all other related agreements with Pepco, with the exception of Mirant's obligations relating to operation of the electric generating stations owned by Pepco Energy Services (the Third Motion to Reject). The Third Motion to Reject also seeks disgorgement of payments made by Mirant to Pepco in respect of the PPA-Related Obligations after filing of its bankruptcy petition in July 2003 to the extent the payments exceed the market value of the capacity and energy purchased. On December 21, 2005, Pepco filed an opposition to the Third Motion to Reject in the Bankruptcy Court.
On December 1, 2005, Mirant, in an attempt to "recharacterize" the PPA-Related Obligations, filed a complaint with the Bankruptcy Court seeking (i) a declaratory judgment that the payments due under the PPA-Related Obligations to Pepco are pre-petition debt obligations; and (ii) an order entitling Mirant to recover all payments that it made to Pepco on account of these pre-petition obligations after the petition date to the extent permitted under bankruptcy law (i.e., disgorgement).
On December 15, 2005, Pepco filed a motion with the District Court to withdraw jurisdiction over both of the December 1 filings from the Bankruptcy Court. The motion to withdraw and Mirant's underlying complaint have both been stayed pending a decision of the Court of Appeals in the appeals described above.
Each of the theories advanced by Mirant to recover funds paid to Pepco relating to the PPA-Related Obligations as a practical matter seeks reimbursement for the above-market cost of the capacity and energy purchased from Pepco over a period beginning, at the earliest, from the date on which Mirant filed its bankruptcy petition and ending on the date of rejection or the date through which disgorgement is approved. Under these theories, Pepco's financial exposure is the amount paid by Mirant to Pepco in respect of the PPA-Related Obligations during the relevant period, less the amount realized by Mirant from the resale of the purchased energy and capacity. On this basis, Pepco estimates that if Mirant ultimately is successful in rejecting the PPA-Related Obligations or on its alternative claims to recover payments made to Pepco related to the PPA-Related Obligations, Pepco's maximum reimbursement obligation would be approximately $263 million as of March 1, 2006.
If Mirant were ultimately successful in its effort to reject its obligations relating to the Panda PPA, Pepco also would lose the benefit on a going-forward basis of the offsetting transaction that negates the financial risk to Pepco of the Panda PPA. Accordingly, if Pepco were required to purchase capacity and energy from Panda commencing as of March 1, 2006, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 17.1 cents), and resold the capacity and energy at market rates projected, given the characteristics of the Panda PPA, to be approximately 11.0 cents per kilowatt hour, Pepco estimates that it would incur losses of approximately $24 million for the remainder of 2006, approximately $30 million in 2007, and approximately $27 million to $38 million annually thereafter through the 2021 contract termination date. These estimates are based in part on current market prices and forward price estimates for energy and capacity, and do not include financing costs, all of which could be subject to significant fluctuation.
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Pepco is continuing to exercise all available legal remedies to vigorously oppose Mirant's efforts to reject or recharacterize the PPA-Related Obligations under the Asset Purchase and Sale Agreement in order to protect the interests of its customers and shareholders. While Pepco believes that it has substantial legal bases to oppose these efforts by Mirant, the ultimate legal outcome is uncertain. However, if Pepco is required to repay to Mirant any amounts received from Mirant in respect of the PPA-Related Obligations, Pepco believes it will be entitled to file a claim against the Mirant bankruptcy estate in an amount equal to the amount repaid. Likewise, if Mirant is successful in its efforts to reject its future obligations relating to the Panda PPA, Pepco will have a claim against Mirant in an amount corresponding to the increased costs that it would incur. In either case, Pepco anticipates that Mirant will contest the claim. To the extent Pepco is successful in its efforts to recover on these claims, it would receive, as in the case of the Pre-Petition Claims, a number of shares of New Mirant Common Stock that is calculated using the market price of the New Mirant Common Stock on the Bankruptcy Emergence Date and accordingly would receive the benefit, and bear the risk, of any change in the market price of the stock between the Bankruptcy Emergence Date and the date the stock is issued to Pepco.
Regulatory Recovery of Mirant Bankruptcy Losses
If Mirant were ultimately successful in rejecting the PPA-Related Obligations or on its alternative claims to recover payments made to Pepco related to the PPA-Related Obligations and Pepco's corresponding claims against the Mirant bankruptcy estate are not recovered in full, Pepco would seek authority from the MPSC and the DCPSC to recover its additional costs. Pepco is committed to working with its regulatory authorities to achieve a result that is appropriate for its shareholders and customers. Under the provisions of the settlement agreements approved by the MPSC and the DCPSC in the deregulation proceedings in which Pepco agreed to divest its generation assets under certain conditions, the PPAs were to become assets of Pepco's distribution business if they could not be sold. Pepco believes that these provisions would allow the stranded costs of the PPAs that are not recovered from the Mirant bankruptcy estate to be recovered from Pepco's customers through its distribution rates. If Pepco's interpretation of the settlement agreements is confirmed, Pepco expects to be able to establish the amount of its anticipated recovery from customers as a regulatory asset. However, there is no assurance that Pepco's interpretation of the settlement agreements would be confirmed by the respective public service commissions.
Pepco's Notice of Administrative Claims
On January 24, 2006, Pepco filed Notice of Administrative Claims in the Bankruptcy Court seeking to recover: (i) costs in excess of $70 million associated with the transmission upgrades necessitated by shut-down of the Potomac River Power Station; and (ii) costs in excess of $8 million due to Mirant's unjustified post-petition delay in executing the certificates needed to permit Pepco to refinance certain tax exempt pollution control bonds. Mirant is expected to oppose both of these claims, which must be approved by the Bankruptcy Court. There is no assurance that Pepco will be able to recover the amounts claimed.
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Mirant's Fraudulent Transfer Claim
In July 2005, Mirant filed a complaint in the Bankruptcy Court against Pepco alleging that Mirant's $2.65 billion purchase of Pepco's generating assets in June 2000 constituted a fraudulent transfer for which it seeks compensatory and punitive damages. Mirant alleges in the complaint that the value of Pepco's generation assets was "not fair consideration or fair or reasonably equivalent value for the consideration paid to Pepco" and that the purchase of the assets rendered Mirant insolvent, or, alternatively, that Pepco and Southern Energy, Inc. (as predecessor to Mirant) intended that Mirant would incur debts beyond its ability to pay them.
Pepco believes this claim has no merit and is vigorously contesting the claim, which has been withdrawn to the District Court. On December 5, 2005, the District Court entered a stay pending a decision of the Court of Appeals in the appeals described above.
The SMECO Agreement
As a term of the Asset Purchase and Sale Agreement, Pepco assigned to Mirant a facility and capacity agreement with Southern Maryland Electric Cooperative (SMECO) under which Pepco was obligated to purchase the capacity of an 84-megawatt combustion turbine installed and owned by SMECO at a former Pepco generating facility (the SMECO Agreement). The SMECO Agreement expires in 2015 and contemplates a monthly payment to SMECO of approximately $.5 million. Pepco is responsible to SMECO for the performance of the SMECO Agreement if Mirant fails to perform its obligations thereunder. At this time, Mirant continues to make post-petition payments due to SMECO.
On March 15, 2004, Mirant filed a complaint with the Bankruptcy Court seeking a declaratory judgment that the SMECO Agreement is an unexpired lease of non-residential real property rather than an executory contract and that if Mirant were to successfully reject the agreement, any claim against the bankruptcy estate for damages made by SMECO (or by Pepco as subrogee) would be subject to the provisions of the Bankruptcy Code that limit the recovery of rejection damages by lessors.
On November 22, 2005, the Bankruptcy Court issued an order granting summary judgment in favor of Mirant, finding that the SMECO Agreement is an unexpired lease of nonresidential real property. On the basis of this ruling, any claim by SMECO (or by Pepco as subrogee) for damages arising from a successful rejection are limited to the greater of (i) the amount of future rental payments due over one year, or (ii) 15% of the future rental payments due over the remaining term of the lease, not to exceed three years.
On December 1, 2005, Mirant filed both a motion with the Bankruptcy Court seeking to reject the SMECO Agreement and a complaint against Pepco and SMECO seeking to recover payments made to SMECO after the entry of the Bankruptcy Court's November 22, 2005 order holding that the SMECO Agreement is a lease of real property. On December 15, 2005, Pepco filed a motion with the District Court to withdraw jurisdiction of this matter from the Bankruptcy Court. The motion to withdraw and Mirant's underlying motion and complaint have been stayed pending a decision of the Court of Appeals in the appeals described above.
If the SMECO Agreement is successfully rejected by Mirant, Pepco will become responsible for the performance of the SMECO Agreement. In addition, if the SMECO Agreement is ultimately determined to be an unexpired lease of nonresidential real property, Pepco's claim for recovery against the Mirant bankruptcy estate would be limited as described above. Pepco
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estimates that its rejection claim, assuming the SMECO Agreement is determined to be an unexpired lease of nonresidential real property, would be approximately $8 million, and that the amount it would be obligated to pay over the remaining nine years of the SMECO Agreement is approximately $44.3 million. While that amount would be offset by the sale of capacity, under current projections, the market value of the capacity is de minimis.
Rate Proceedings
District of Columbia and Maryland
On February 27, 2006, Pepco filed for the period February 8, 2002 through February 7, 2004 and for the period February 8, 2004 through February 7, 2005, an update to the District of Columbia Generation Procurement Credit (GPC), which provides for sharing of the profit from SOS sales; and on February 24, 2006, Pepco filed an update for the period July1, 2003 through June 30, 2004 to the Maryland GPC. The updates to the GPC in both the District of Columbia and Maryland take into account the proceeds from the sale of the $105 million claim against the Mirant bankruptcy estate related to the TPA Settlement on December 13, 2005 for $112.4 million. The filings also incorporate true-ups to previous disbursements in the GPC for both states. In the filings, Pepco requests that $24.3 million be credited to District of Columbia customers and $17.7 million be credited to Maryland customers during the twelve-month-period beginning April 2006.
Federal Energy Regulatory Commission
On January 31, 2005, Pepco filed at FERC to reset its rates for network transmission service using a formula methodology. Pepco also sought a 12.4% return on common equity and a 50-basis-point return on equity adder that FERC had made available to transmission utilities who had joined Regional Transmission Organizations and thus turned over control of their assets to an independent entity. FERC issued an order on May 31, 2005, approving the rates to go into effect June 1, 2005, subject to refund, hearings, and further orders. The new rates reflect a decrease of 7.7% in Pepco's transmission rate. Pepco continues in settlement discussions under the supervision of a FERC administrative law judge and cannot predict the ultimate outcome of this proceeding.
Divestiture Cases
District of Columbia
Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed 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 and its implementing regulations. As of December 31, 2005, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generation 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
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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 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, 2005), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($5.3 million as of December 31, 2005) 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 are due by March 21, 2006, and a public hearing will be held on April 5, 2006. Pepco filed a letter with the DCPSC on January 12, 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 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, results of operations or cash flows. It is uncertain when the DCPSC will issue a decision regarding Pepco's divestiture proceeds sharing application.
Maryland
Pepco filed its divestiture proceeds plan application in Maryland 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, 2005, the MPSC allocated portions of EDIT and ADITC associated with the divested generation 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
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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, 2005), 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, 2005), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($9.5 million as of December 31, 2005), 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 on January 12, 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 will be terminated without the issuance of any regulations.
Pepco has appealed the Hearing Examiner's decision as it relates to the treatment of EDIT and ADITC and corporate reorganization costs to the MPSC. Consistent with Pepco's position in the District of Columbia, Pepco has argued that the only prudent course of action is for the MPSC to await the issuance of final regulations relating to the tax issues or a termination by the IRS of its regulation project without the issuance of any regulations, and then allow the parties to file supplemental briefs on the tax issues. Pepco believes that its calculation of the Maryland customers' share of divestiture proceeds is correct. 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 and make additional gain-sharing payments related 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, results of operations or cash flows.
Default Electricity Supply Proceedings
District of Columbia
Under an order issued by the DCPSC in March 2004, as amended by a DCPSC order issued in July 2004, Pepco is obligated to provide SOS for small commercial and residential customers through May 31, 2011 and for large commercial customers through May 31, 2007. In August 2004, the DCPSC issued an order adopting administrative charges for residential, small and large commercial District of Columbia SOS customers that are intended to allow Pepco to recover the administrative costs incurred to provide the SOS supply. The approved administrative charges include an average margin for Pepco of approximately $.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial District of Columbia SOS customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of SOS customers from each customer class and the load taken by such customers over the time period. The administrative charges went into effect for Pepco's SOS
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sales on February 8, 2005.
The TPA with Mirant under which Pepco obtained the fixed-rate SOS supply ended on January 22, 2005, while the new SOS supply contracts with the winning bidders in the competitive procurement process began on February 1, 2005. Pepco procured power separately on the market for next-day deliveries to cover the period from January 23 through January 31, 2005, before the new SOS contracts began. Consequently, Pepco had to pay the difference between the procurement cost of power on the market for next-day deliveries and the current SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new SOS rates did not go into effect until February 8, 2005, Pepco had to pay the difference between the procurement cost of power under the new SOS contracts and the SOS rates charged to customers for the period from February 1 to February 7, 2005. The total amount of the difference is estimated to be approximately $8.7 million. This difference, however, was included in the calculation of the GPC for the District of Columbia for the period February 8, 2004 through February 7, 2005, which was filed on July 12, 2005 with the DCPSC. The GPC provides for a sharing between Pepco's customers and shareholders, on an annual basis, of any margins, but not losses, that Pepco earned providing SOS in the District of Columbia during the four-year period from February 8, 2001 through February 7, 2005. At the time of the filing, based on the rates paid to Mirant by Pepco under the TPA Settlement, there was no customer sharing. On December 22, 2005 Pepco received $112.4 million in proceeds from the sale of the Pepco TPA Claim against the Mirant bankruptcy estate. A portion of this recovery related to the period February 8, 2004 through February 7, 2005 covered in the July 12 DCPSC filing. As a consequence, on February 27, 2006, Pepco filed with the DCPSC an updated calculation of the customer sharing for this period, which also takes into account the losses incurred during the January 22, 2005 through February 7, 2005 period. The updated filing shows that both residential and commercial customers will receive customer sharing that totals $17.5 million. Without the inclusion of the $8.7 million loss from the January 22, 2005 through February 7, 2005 period, the amount shared with customers would have been approximately $22.7 million, or $5.2 million greater, so that the net effect of the loss on the SOS sales during this period is approximately $3.5 million.
On February 3, 2006, Pepco announced proposed rates for its District of Columbia SOS customers to take effect on June 1, 2006. The new rate will raise the average monthly bill for residential customers by approximately 12%. The proposed rates must be approved by the DCPSC.
Maryland
Because of rising energy prices and the resultant expected increases in Pepco's rates, on March 3, 2006 the MPSC issued an order initiating an investigation to consider a residential rate stabilization plan for Pepco. This investigation is driven by the unprecedented national and international events. The MPSC directed the MPSC staff and Pepco to file comments addressing whether or not the rate stabilization plan that the MPSC adopted for Baltimore Gas & Electric Company in a March 6, 2006 order also should be used for Pepco. Comments are to be filed by March 16, 2006.
On March 7, 2006, Pepco announced the results of competitive bids to supply electricity to its Maryland SOS customers for one year beginning June 1, 2006. The proposed new rates must be approved formally by the MPSC. Due to significant increases in the cost of fuels used to generate electricity, the average monthly electric bill for Pepco's Maryland residential customers
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will increase by about 38.5%.
IRS Mixed Service Cost Issue
During 2001, Pepco changed its methods of accounting with respect to capitalizable construction costs for income tax purposes, which allow Pepco to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions have generated incremental tax cash flow benefits of approximately $94 million for Pepco, primarily attributable to its 2001 tax returns. On August 2, 2005, the IRS issued Revenue Ruling 2005-53 (the Revenue Ruling) that will limit the ability of Pepco to utilize this method of accounting for income tax purposes on its tax returns for 2004 and prior years. Pepco intends to contest any IRS adjustment to its prior year income tax returns based on the Revenue Ruling. However, if the IRS is successful in applying this Revenue Ruling Pepco would be required to capitalize and depreciate a portion of the construction costs previously deducted and repay the associated income tax benefits, along with interest thereon. During 2005, Pepco recorded a $6.0 million increase in income tax expense to account for the accrued interest that would be paid on the portion of tax benefits that Pepco estimates would be deferred to future years if the construction costs previously deducted are required to be capitalized and depreciated.
On the same day as the Revenue Ruling was issued, the Treasury Department released 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 all future tax periods beginning in 2005. Under these regulations, Pepco will have to capitalize and depreciate a portion of the construction costs that it has previously deducted and include the impact of this adjustment in taxable income over a two-year period beginning with tax year 2005. Pepco is continuing to work with the industry to determine an alternative method of accounting for capitalizable construction costs acceptable to the IRS to replace the method disallowed by the proposed regulations.
In February 2006, PHI paid approximately $121 million, a portion of which is attributable to Pepco, of taxes to cover the amount of taxes management estimates will be payable once a new final method of tax accounting is adopted on its 2005 tax return, due to the proposed regulations. Although the increase in taxable income will be spread over the 2005 and 2006 tax return periods, the cash payments would have all occurred in 2006 with the filing of the 2005 tax return and the ongoing 2006 estimated tax payments. This $121 million tax payment was accelerated to eliminate the need to accrue additional federal interest expense for the potential IRS adjustment related to the previous tax accounting method PHI used during the 2001-2004 tax years.
Contractual Obligations
As of December 31, 2005, Pepco's contractual obligations under non-derivative fuel and power purchase contracts (excluding PPA related obligations that are part of the back-to-back agreement with Mirant) were $248.6 million in 2006, $428.2 million in 2007 to 2008, zero in 2009 to 2010, and zero in 2011 and thereafter.
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(12) 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 in consolidation and no profit results from these transactions. PHI Service Company costs directly charged or allocated to Pepco for the years ended December 31, 2005, 2004 and 2003 were approximately $114.6 million, $91.1 million and $82.8 million, respectively.
Certain subsidiaries of Pepco Energy Services perform utility maintenance services, including services that are treated as capital costs, for Pepco. Amounts paid by Pepco to these companies for the years ended December 31, 2005, 2004 and 2003 were approximately $11.6 million, $14.1 million and $11.3 million, respectively.
In addition to the transactions described above, Pepco's financial statements include the following related party transactions in its Statements of Earnings:
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As of December 31, 2005 and 2004, 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.
(b)
Included in operating revenue.
(c)
Included in other operation and maintenance.
(d)
Included in interest expense.
(13) RESTATEMENT
Pepco restated its previously reported financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct the accounting for certain deferred compensation arrangements. The restatement includes the correction of other errors for the same periods, primarily relating to unbilled revenue, taxes, and various accrual accounts, which were considered by management to be immaterial. These other errors would not themselves have required a restatement absent the restatement to correct the accounting for deferred compensation arrangements. This restatement was required solely because the cumulative impact of the correction, if recorded in the fourth quarter of 2005, would have been material to that period's reported net income. The impact of the restatement related to the deferred compensation arrangements on periods prior to 2003 has been reflected as a reduction of approximately $21.4 million to Pepco's retained earnings balance as of January 1, 2003. The following table sets forth for Pepco, for the years ended December 31, 2004 and 2003, the impact of the restatement to correct the accounting for the deferred compensation arrangements and the other errors noted above (millions of dollars):
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(14) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The unaudited quarterly financial information for the three months ended March 31, 2005, June 30, 2005, and September 30, 2005 and all interim periods during the year ended December 31, 2004 have been restated to reflect the correction of the accounting for certain deferred compensation arrangements and other noted errors that would not themselves have required a restatement absent the restatement to correct the accounting for the deferred compensation arrangements as described in Note 13. 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.
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NOTE:
Sales of electric energy are seasonal and, accordingly, comparisons by quarter within a year are not meaningful.
(a)
Includes $68.1 million gain ($40.7 million after tax) from sale of non-utility land owned by Pepco at Buzzard Point.
(b)
Includes $70.5 million gain ($42.2 million after tax) from the settlement of the TPA claim with Mirant.
(c)
Includes $4.6 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.
(d)
Includes $1.4 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.
(15) SUBSEQUENT EVENT
On March 1, 2006, Pepco redeemed all outstanding shares of its Serial Preferred Stock of each series, at 102% of par, for an aggregate redemption amount of $21.9 million.
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Report of Independent Registered Public Accounting Firm
To the 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, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 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 disclosed in Note 13 to the financial statements, the Company restated its financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003.
PricewaterhouseCoopers LLP
Washington, D.C.
March 13, 2006
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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, 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 (POLR) -- before May 1, 2006
Standard Offer Service (SOS) -- on and after May 1, 2006
Maryland
SOS
Virginia
Default Service
DPL also refers to this supply service in each of its jurisdictions generally as Default Electricity Supply.
DPL's electricity distribution service territory covers approximately 6,000 square miles and has a population of approximately 1.28 million. DPL's natural gas distribution service territory covers approximately 275 square miles and has a population of approximately 523,000. DPL is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or 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 the Federal Energy Regulatory Commission (FERC) under PUHCA 2005.
(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, such as compliance with Statement of Position 94-6, "Disclosure of Certain Significant Risks and Uncertainties," 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. Examples of 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, and judgment involved with assessing the probability of recovery of regulatory assets. 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 based upon the probable and reasonably estimable criteria contained in SFAS No. 5, "Accounting for Contingencies." Although DPL believes that its estimates and assumptions are reasonable, they are based upon information available to
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management at the time the estimates are made. Actual results may differ significantly from these estimates.
Change in Accounting Estimates
During 2005, DPL recorded the impact of a reduction in estimated unbilled revenue, primarily reflecting an increase in the estimated amount of power line losses (estimates of electricity expected to be 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 for the supply and delivery of electricity and gas upon delivery to the customers, including amounts for services rendered, but not yet billed (unbilled revenue). DPL recorded amounts for unbilled revenue of $63.5 million and $66.9 million as of December 31, 2005 and 2004, respectively. These amounts are included in the "accounts receivable" line item in the accompanying Balance Sheets. DPL calculates unbilled revenue using an output based methodology. This methodology is based on the supply of electricity or gas distributed to customers. The unbilled revenue process requires management 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), which are inherently uncertain and susceptible to change from period to period, the impact of which could be material. Similarly, 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 the Company's tariffs and, as such, are billed to customers and recorded in Operating Revenues. Accruals for these taxes by the Company are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by the Company 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 DPSC and MPSC, and the Virginia State Corporation Commission (VSCC), and its wholesale operations are subject to regulation by the Federal Energy Regulatory Commission (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 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.
The components of DPL's regulatory asset balances at December 31, 2005 and 2004, are as
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follows:
The components of DPL's regulatory liability balances at December 31, 2005 and 2004, 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. All deferrals receive a return. The deferred fuel costs are recovered annually.
Deferred Recoverable Income Taxes: Represents deferred income tax assets recognized from the normalization of flow-through items as a result of amounts previously provided to customers. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return on these deferrals.
Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period. A return is received on these deferrals.
Unrecovered Purchased Power Contract Costs: Represents deferred costs related to purchase power contracts at DPL, which are being recovered from February 1996 through October 2007 and which earn a return.
Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 2 years and generally do not receive a return.
Deferred Income Taxes Due to Customers: Represents the portion of deferred income tax liabilities applicable to DPL's utility operations that has not been reflected in current customer rates, for which future payment to customers is probable. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are
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amortized.
Accrued Asset Removal Costs: Represents DPL's asset retirement obligation associated with removal costs accrued using public service commission approved depreciation rates for transmission, distribution and general utility property. In accordance with the SEC interpretation of SFAS No. 143, accruals for removal costs were classified as a regulatory liability.
Other: Includes costs associated with DPL's natural gas hedging activity and Maryland 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.
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 taxes are discussed below.
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.
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, 2005, there was a deferred derivative receivable on DPL's balance sheet of $21.6 million, offset by a $21.6 million regulatory liability.
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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. 34, "Capitalization of Interest Cost," the cost of financing the construction of DPL's electric generating plants is capitalized. Other non-utility construction projects also include financing costs in accordance with SFAS No. 34. In accordance with the provisions of SFAS No. 71, utilities can capitalize Allowance for Funds Used During Construction (AFUDC) as part of the cost of plant and equipment. AFUDC recognizes that utility construction is financed partially by debt and partially by equity.
DPL recorded AFUDC for borrowed funds of $.9 million, $.3 million, and $.3 million for the years ended December 31, 2005, 2004, and 2003, respectively. These amounts are recorded as a reduction of "interest expense" in the accompanying Statements of Earnings.
DPL recorded amounts for the equity component of AFUDC of $.5 million, $.4 million and $.5 million for the years ended December 31, 2005, 2004 and 2003, respectively. The amounts are included in the "other income" caption of the accompanying Statements of Earnings.
Amortization of Debt Issuance and Reacquisition Costs
The amortization of debt discount, premium, and expense, including deferred debt extinguishment costs associated with the regulated electric and gas transmission and distribution businesses, is included in interest expense.
Accounting for Goodwill
Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. DPL's goodwill balance at December 31, 2005 and 2004 of $48.5 million was derived from DPL's acquisition of Conowingo Power Company in 1995. The accounting for goodwill is governed by SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting and broadens the criteria for recording intangible assets apart from goodwill. SFAS No. 142 requires that purchased goodwill and certain indefinite-lived intangibles no longer be amortized, but instead be tested for impairment at least annually.
Goodwill Impairment Evaluation
The provisions of SFAS No. 142 require the evaluation of goodwill for impairment at least annually or more frequently if events and circumstances indicate that the asset might be impaired. Examples of such events and circumstances include an adverse action or assessment by a regulator, a significant adverse change in legal factors or in the business climate, and unanticipated competition. SFAS No. 142 indicates that if the fair value of a reporting unit is less than its carrying value, including goodwill, an impairment charge may be necessary. During
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2005, DPL tested its goodwill for impairment as of July 1, 2005. This test concluded that none of DPL's goodwill balance was impaired.
Long-Lived Asset Impairment Evaluation
DPL is required to evaluate certain long-lived assets (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist. SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," provides the accounting for impairments of long-lived assets and indicates that companies are required to test long-lived assets for recoverability 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.
For long-lived assets that are expected to be held and used, SFAS No. 144 requires that an impairment loss be recognized only if the carrying amount of an asset is not recoverable and exceeds its fair value. For long-lived assets that can be classified as assets to be disposed of by sale under SFAS No. 144, an impairment loss shall be recognized to the extent their carrying amount exceeds their fair value, including costs to sell.
Pension and Other Postretirement Plans
Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings' subsidiaries (Retirement Plan). Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan for Pepco employees are identical to those of the original Pepco plan and for Conectiv employees are identical to the original Conectiv plan. 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 Company accounts for the Retirement Plan in accordance with SFAS No. 87, "Employers' Accounting for Pensions," and its other postretirement benefits in accordance with SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." DPL's financial statement disclosures were prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits."
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. 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
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and other recoveries. The system-wide composite depreciation rate for 2005, 2004 and 2003 for DPL's transmission and distribution system property was approximately 3.1%. 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.
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
DPL adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," on January 1, 2003 and FIN 47 as of December 31, 2005. This statement and related interpretation establish the accounting and reporting standards for measuring and recording asset retirement obligations. Based on the implementation of SFAS No. 143, $179.2 million and $176.8 million at December 31, 2005 and 2004 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 expense for these asset retirement obligations has been recorded as a regulatory asset.
FIN 46R
On December 31, 2003, FIN 46 was implemented by DPL. FIN 46 was revised and superseded by FASB Interpretation No. 46 (revised December 2003), "Consolidation of Variable Interest Entities" (FIN 46R), which clarified some of the provisions of FIN 46 and exempted certain entities from its requirements. The implementation of FIN 46R did not impact DPL's financial condition or results of operations for the years ended December 31, 2005, 2004 and 2003.
Other Non-Current Assets
The other assets balance principally consists of real estate under development, equity and other investments, and deferred compensation trust assets.
Other Current Liabilities
The other current liabilities balance principally consists of customer deposits, accrued vacation liability, and the current portion of deferred income taxes.
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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; (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; and (iii) certain provisions of the charter of DPL, which impose restrictions on payment of common stock dividends for the benefit of preferred stockholders.
New Accounting Standards
SFAS No. 154
In May 2005, the FASB issued Statement No. 154, "Accounting Changes and Error Corrections (SFAS No. 154), a replacement of APB Opinion No. 20 and FASB Statement No. 3." SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. The reporting of a correction of an error by restating previously issued financial statements is also addressed by SFAS No. 154. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 (the year ended December 31, 2006 for Pepco Holdings). Early adoption is permitted.
EITF 04-13
In September 2005, the FASB ratified EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" (EITF 04-13), which addresses circumstances under which two or more exchange transactions involving inventory with the same counterparty should be viewed as a single exchange transaction for the purposes of evaluating the effect of APB Opinion 29. EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006 (April 1, 2006 for DPL). EITF 04-13 would not affect DPL's net income, overall financial condition, or cash flows, but rather could result in certain revenues and costs, including wholesale revenues and purchased power expenses, being presented on a net basis. DPL is in the process of evaluating the impact of EITF 04-13 on its Statements of Earnings presentation of purchases and sales.
(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.
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(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 $118.6 million in the aggregate. DPL also has long-term leases for certain other facilities and equipment. Minimum commitments as of December 31, 2005, under the Merrill Creek Reservoir lease and other lease agreements, are as follows: 2006-$8.5 million; 2007-$8.4 million; 2008-$9.2 million; 2009-$9.2 million; 2010-$9.2 million; beyond 2010-$102.1 million; total-$146.6 million.
(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. The system-wide composite depreciation rate in 2005 and 2004 for DPL's transmission and distribution system property was approximately 3.1%.
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(6) PENSIONS AND OTHER POSTRETIREMENT BENEFITS
Pension Benefits
Pepco Holdings sponsors a defined benefit Retirement Plan that 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.
Other Postretirement Benefits
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.
During 2004, PHI amended its postretirement health care plans for certain groups of eligible employees effective January 1, 2005 or January 1, 2006. The amendments included changes to coverage and retiree cost-sharing, and are reflected as a reduction in PHI's 2004 net periodic benefit cost and a reduction of $42 million in the projected benefit obligation at December 31, 2004.
Pepco Holdings uses a December 31 measurement date for its plans. Plan assets are stated at their market value as of the measurement date, December 31. All dollar amounts in the following tables are in millions of dollars.
The following table provides a reconciliation of the projected benefit obligation, plan assets and funded status of the plans.
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The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheet as of December 31:
The accumulated benefit obligation for the Retirement Plan (the qualified defined benefit pension plan) was $1,556.2 million and $1,462.9 million at December 31, 2005, and 2004, respectively. The table below provides the projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the PHI nonqualified pension plan with an accumulated benefit obligation in excess of plan assets at December 31, 2005 and 2004.
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In 2005 and 2004, PHI was required to recognize an additional minimum liability and an intangible asset related to its nonqualified pension plan as prescribed by SFAS No. 87. The liability was recorded as a reduction to shareholders' equity (other comprehensive income), and the equity will be restored to the balance sheet in future periods when the accrued benefit liability exceeds the accumulated benefit obligation at future measurement dates. The amount of reduction to shareholders' equity (net of income taxes) in 2005 was $7.3 million and in 2004 was $4.1 million. The recording of this reduction did not affect net income or cash flows in 2005 or 2004 or compliance with debt covenants.
The table below provides the components of net periodic benefit costs recognized for the years ended December 31.
Approximately $(2.0) million, $1.0 million and $7.1 million were included in capital and operating and maintenance expense, in 2005, 2004 and 2003, respectively, for DPL's allocated portion of PHI's combined pension and other postretirement benefit expense.
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
Effect on total of service and interest cost
$ 1.8
$ (1.7)
Effect on postretirement benefit obligation
27.0
(25.1)
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The following weighted average assumptions were used to determine the net periodic benefit cost for years ended December 31:
A cash flow matched bond portfolio approach to developing a discount rate is used to value FAS 87 and FAS 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 time horizon, are expected to yield a return on assets of 8.50%.
Plan Assets
Pepco Holdings' Retirement Plan weighted-average asset allocations at December 31, 2005, and 2004, by asset category are as follows:
Pepco Holdings' other postretirement plan weighted-average asset allocations at December 31, 2005, and 2004, by asset category are as follows:
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In developing an asset allocation policy for its 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 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 - Retirement Plan
Pepco Holdings' funding policy with regard to the Retirement Plan is to maintain a funding level in excess of 100% with respect to its accumulated benefit obligation (ABO). PHI's Retirement Plan currently meets the minimum funding requirements of ERISA without any additional funding. In 2005 and 2004, PHI made discretionary tax-deductible cash contributions to the plan of $60.0 million and $10.0 million, respectively, in line with its funding policy. Assuming no changes to the current pension plan assumptions, PHI projects no funding will be required under ERISA in 2006; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its plan assets in excess of its ABO.
Contributions - Other Postretirement Benefits
In 2005, PHI combined its health and welfare plans and the existing IRC 501 (C) (9) Voluntary Employee Beneficiary Association (VEBA) trusts for Pepco, DPL and ACE to fund a portion of their estimated postretirement liabilities. DPL contributed $6.0 million and $9.5 million to the PHI-sponsored plan in 2005 and 2004, respectively. Assuming no changes to the current plan assumptions, DPL expects to contribute amounts similar to its allocated portion of PHI's other postretirement benefit expense to the other postretirement welfare benefit plan in 2006.
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Expected Benefit Payments
Estimated future benefit payments to participants in PHI's qualified pension and postretirement welfare benefit plans, which reflect expected future service as appropriate, as of December 31, 2005 are in millions of dollars:
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(7) LONG-TERM DEBT
Long-term debt outstanding as of December 31, 2005 and 2004 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: 2006-$22.9 million; 2007-$64.7 million; 2008-$22.6 million; 2009-zero; 2010-$31.2 million; and $398.9 million thereafter.
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SHORT-TERM DEBT
DPL, a regulated utility, has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. A detail of the components of DPL's short-term debt at December 31, 2005 and 2004 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 Pepco and ACE.
DPL had no commercial paper outstanding at December 31, 2005 and December 31, 2004. The interest rate for commercial paper issued during 2004 was 1.10%.
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 VRDBs as a source of long-term financing. The VRDB outstanding in 2005 and 2004 mature in 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 2.63% during 2005 and ranged from 1.04% to 2.47% in 2004.
Credit Facility
In May 2005, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $1.2 billion. This agreement replaces a $650 million five-year credit agreement that was entered into in July 2004 and a $550 million three-year credit agreement entered into in July 2003. Pepco Holdings' credit limit under this agreement is $700 million. The credit limit of each of Pepco, DPL and ACE is the lower of $300 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 under the agreement may not exceed $500 million. Under the terms of the
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credit agreement, the companies are entitled to request increases in the principal amount of available credit up to an aggregate increase of $300 million, with any such increase proportionately increasing the credit limit of each of the respective borrowers and the $300 million sublimits for each of Pepco, DPL and ACE. The interest rate payable by the respective companies on utilized funds is determined by a pricing schedule with rates corresponding to the credit rating of the borrower. Any indebtedness incurred under the credit agreement would be unsecured.
The credit agreement 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 contained in the credit agreement 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, (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 failure to satisfy any of the covenants or the occurrence of specified events that constitute an event of default could result in the acceleration of the repayment obligations of the borrower. The events of default include (i) the failure of any borrowing company or any of its significant subsidiaries to pay when due, or the acceleration of, certain indebtedness under other borrowing arrangements, (ii) certain bankruptcy events, judgments or decrees against any borrowing company or its significant subsidiaries, and (iii) a change in control (as defined in the credit agreement) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE. The agreement does not include any ratings triggers. There were no balances outstanding at December 31, 2005 and 2004.
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(8) INCOME TAXES
DPL, as an indirect subsidiary of PHI, is included in the Federal income tax return of PHI. Federal income taxes are allocated to DPL pursuant to a written tax sharing agreement which was approved by the Securities and Exchange Commission pursuant to regulations under the Public Utility Holding Company Act of 1935 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, with the exception of the tax benefits applicable to non-acquisition debt expenses of PHI. Such tax benefits are allocated only to subsidiaries with taxable income.
The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.
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Components of Deferred Income Tax Liabilities (Assets)
The tax effects of temporary differences that give rise to DPL's net deferred tax liability are shown below. There were no valuation allowances for deferred tax assets as of December 31, 2005 and December 31, 2004.
Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below.
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(9) PREFERRED STOCK
The preferred stock amounts outstanding as of December 31, 2005 and 2004 are as follows:
(1)
In December 2005, DPL redeemed all outstanding shares of its 6.75% Serial Preferred Stock, at par, for an aggregate redemption amount of $3.5 million.
(10) FAIR VALUES OF FINANCIAL INSTRUMENTS
The estimated fair values of DPL's financial instruments at December 31, 2005 and 2004 are shown below.
The methods and assumptions below were used to estimate, at December 31, 2005 and 2004, 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, excluding 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
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statements approximate fair value.
(11) COMMITMENTS AND CONTINGENCIES
REGULATORY AND OTHER MATTERS
Rate Proceedings
Delaware
On October 3, 2005, DPL submitted its 2005 gas cost rate (GCR) filing to the DPSC, which permits DPL to recover gas procurement costs through customer rates. In its filing, DPL seeks to increase its GCR by approximately 38% in anticipation of increasing natural gas commodity costs. The proposed rate became effective November 1, 2005, subject to refund pending final DPSC approval after evidentiary hearings. A public input hearing was held on January 19, 2006. DPSC staff and the Division of the Public Advocate filed testimony on February 20, 2006.
As authorized by the April 16, 2002 settlement agreement in Delaware relating to the acquisition of Conectiv by Pepco (the Delaware Merger Settlement Agreement), on May 4, 2005, DPL filed with the DPSC a proposed increase of approximately $6.2 million in electric transmission service revenues, or about 1.1% of total Delaware retail electric revenues. This revenue increase covers the Delaware retail portion of the increase in the "Delmarva zonal" transmission rates on file with FERC under the PJM Interconnection, LLC (PJM) Open Access Transmission Tariff (OATT) and other transition of PJM charges. This level of revenue increase will decrease to the extent that competitive suppliers provide the supply portion and its associated transmission service to retail customers. In that circumstance, PJM would charge the competitive retail supplier the PJM OATT rate for transmission service into the Delmarva zone and DPL's charges to the retail customer would exclude as a "shopping credit" an amount equal to the SOS supply charge and the transmission and ancillary charges that would otherwise be charged by DPL to the retail customer. DPL began collecting this rate change for service rendered on and after June 3, 2005, subject to refund pending final approval by the DPSC.
On September 1, 2005, DPL filed with the DPSC its first comprehensive base rate case in ten years. This application was filed as a result of increasing costs and is consistent with a provision in the Delaware Merger Settlement Agreement requiring DPL to file a base rate case by September 1, 2005 and permitting DPL to apply for an increase in rates to be effective no earlier than May 1, 2006. In the application, DPL sought approval of an annual increase of approximately $5.1 million in its electric rates, with an increase of approximately $1.6 million to its electric distribution base rates after proposing to assign approximately $3.5 million in costs to the supply component of rates to be collected as part of the SOS. Of the approximately $1.6 million in net increases to its electric distribution base rates, DPL proposed that approximately $1.2 million be recovered through changes in delivery charges and that the remaining approximately $0.4 million be recovered through changes in premise collection and reconnect fees. The full proposed revenue increase is approximately 0.9% of total annual electric utility revenues, while the proposed net increase to distribution rates is 0.2% of total annual electric utility revenues. DPL's distribution revenue requirement is based on a proposed return on common equity of 11%. DPL also has proposed revised depreciation rates and a number of tariff modifications.
On September 20, 2005, the DPSC issued an order approving DPL's request that the rate
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increase go into effect on May 1, 2006; subject to refund and pending evidentiary hearings. The order also suspends effectiveness of various proposed tariff rule changes until the case is concluded. The discovery process commenced on October 21, 2005. In its direct testimony, DPSC staff has proposed a variety of adjustments to rate base, operating expenses including depreciation and rate of return with an overall recommendation of a distribution base rate revenue decrease of $14.3 million. The DPSC staff's testimony also addresses issues such as rate design, allocation of any rate decrease and positions regarding the DPL's proposals on certain non-rate tariff modifications. The Delaware Division of Public Advocate has proposed many of the same adjustments and others with an overall recommendation of a distribution base rate revenue decrease of $18.9 million. DPL filed rebuttal testimony on January 17, 2006, which supports a distribution base rate revenue increase of $2 million. On January 30, 2006, the DPSC staff requested the Hearing Examiner approve a modification of the procedural schedule in the case to allow for inclusion of testimony regarding recalculation of DPSC staff's proposed depreciation rates to allow for a separate amortization of the cost of removal reserve. DPL objected to this modification of the procedural schedule. The Hearing Examiner issued a letter ruling on February 1, 2006, which denied DPSC staff's request for a modified procedural schedule. On February 2, 2006, DPSC staff filed an emergency motion requesting the DPSC to permit consideration of the issue by the Hearing Examiner in this docket. On February 6, 2006, the DPSC ruled to allow the issue in the case. A revised procedural schedule was established by the Hearing Examiner on February 10, 2006. On February 15, 2006, DPL filed an interlocutory appeal of the Hearing Examiner's ruling on the procedural schedule with the DPSC. On February 28, 2006, the DPSC upheld the Hearing Examiner's ruling and procedural schedule set on February 10, 2006. DPSC staff filed testimony related to this issue on February 17, 2006. DPSC staff's revised depreciation proposal reduces their recommended proposed rate decrease to $18.9 million, plus the amortization of the cost of removal of $58.4 million, which DPSC staff has recommended be returned to customers through either a 5-, 7- or 10-year amortization. DPL continues to oppose the inclusion of this issue in the case for substantive and procedural grounds. Evidentiary hearings were held in early February. Hearings on the separate issue related to the depreciation of the cost of removal are scheduled to be held March 20, 2006. Briefs are due on March 31, 2006 and DPSC deliberation is scheduled to occur on April 25, 2006. DPL cannot predict the outcome of this proceeding.
Federal Energy Regulatory Commission
On January 31, 2005, DPL filed at FERC to reset its rates for network transmission service using a formula methodology. DPL also sought a 12.4% return on common equity and a 50-basis-point return on equity adder that FERC had made available to transmission utilities who had joined Regional Transmission Organizations and thus turned over control of their assets to an independent entity. FERC issued an order on May 31, 2005, approving the rates to go into effect June 1, 2005, subject to refund, hearings, and further orders. The new rates reflect an increase of 6.5% in DPL's transmission rates. DPL continues in settlement discussions under the supervision of a FERC administrative law judge and cannot predict the ultimate outcome of this proceeding.
Default Electricity Supply Proceedings
Delaware
Under a settlement approved by the DPSC, DPL is required to provide POLR to customers in Delaware through April 2006. DPL is paid for POLR to customers in Delaware at fixed rates
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established in the settlement. DPL obtains all of the energy needed to fulfill its POLR obligations in Delaware under a supply agreement with its affiliate Conectiv Energy, which terminates in May 2006. DPL does not make any profit or incur any loss on the supply component of the POLR supply that it delivers to its Delaware customers. DPL is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both POLR customers and customers who have selected another energy supplier. These delivery rates generally are frozen through April 2006, except that DPL is allowed to file for a one-time transmission rate change during this period. On March 22, 2005, the DPSC issued an order approving DPL as the SOS provider after May 1, 2006, when DPL's current fixed rate POLR obligation ends. DPL will retain the SOS obligation for an indefinite period until changed by the DPSC, and will purchase the power supply required to satisfy its SOS obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure.
On October 11, 2005, the DPSC approved a settlement agreement, under which DPL will provide SOS to all customer classes, with no specified termination date for SOS. Two categories of SOS will exist: (i) a fixed price SOS available to all but the largest customers; and (ii) an Hourly Priced Service (HPS) for the largest customers. DPL will purchase the power supply required to satisfy its fixed-price SOS obligation from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure. Power to supply the HPS customers will be acquired on next-day and other short-term PJM markets. In addition to the costs of capacity, energy, transmission, and ancillary services associated with the fixed-price SOS and HPS, DPL's initial rates will include a component referred to as the 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 a billing system to be used for billing HPS customers.
Bids for fixed-priced SOS supply for the May 1, 2006 through May 31, 2007 period were accepted and approved by the DPSC in December 2005 and January 2006. The new SOS rates are scheduled to be effective May 1, 2006.
On February 7, 2006, the Governor of Delaware issued an Executive Order directing the DPSC and other state agencies to examine ways to mitigate the electric rate increases that are expected in May 2006 as a result of rising energy prices. The Executive Order directed the DPSC to examine the feasibility of: (1) deferring or phasing-in the increases; (2) requiring DPL to build generation or enter into long-term supply contracts to meet all, or a portion of, the SOS supply requirements under a traditional regulatory paradigm; (3) directing DPL to conduct integrated resource planning to ensure fuel diversity and least-cost supply alternatives; and (4) requiring DPL to implement demand-side management, conservation and energy efficient programs.
In response to the Executive Order and to help facilitate discussion on several key issues facing the State of Delaware, particularly the issue of rising energy prices, DPL presented a proposed plan to the DPSC on February 28, 2006. A key feature of DPL's proposed plan is a phase-in of rate increases to assist DPL's residential and small commercial customers with the impact of rising energy prices. The proposed phase-in of the rate increase would be in three steps, with one third of the increase to be phased in on May 1, 2006, another one-third on January 1, 2007 and the remainder on June 1, 2007. The phase-in would create a deferral balance of approximately $60 million dollars that would accrue interest and would be recovered
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through a surcharge imposed for a 24-month period beginning June 1, 2007. DPL believes that this proposal offers a fair and reasonable solution to the concerns identified in the Executive Order.
The Delaware Governor's Cabinet Committee on Energy filed its report with the Governor on March 8, 2006. The report outlines a proposal that recommends: (1) a phase-in of the SOS increase; (2) long-term steps to ensure more stabilized prices and supply; (3) aggregation of the state of Delaware's power needs; and (4) reduction of Delaware's dependence on traditional energy sources through conservation, energy efficiency, and innovation.
DPL intends to file with the DPSC, on or about March 15, 2006, an implementation plan with proposed tariffs based on its proposed phase-in plan as described above. DPL also anticipates that others may advance other legislative or regulatory proposals to address the concerns expressed in the Executive Order. Accordingly, the nature and impact of any changes precipitated by the Executive Order are uncertain and DPL cannot predict at this time whether this phase-in proposal will be implemented.
Maryland
Because of rising energy prices and the resultant expected increases in DPL's rates, on March 3, 2006 the MPSC issued an order initiating an investigation to consider a residential rate stabilization plan for DPL. This investigation is driven by the unprecedented national and international events. The MPSC directed the MPSC staff and DPL to file comments addressing whether or not the rate stabilization plan that the MPSC adopted for Baltimore Gas & Electric Company in a March 6, 2006 order also should be used for DPL. Comments are to be filed by March 16, 2006.
On March 7, 2006, DPL announced the results of competitive bids to supply electricity to its Maryland SOS customers for one year beginning June 1, 2006. The proposed new rates must be approved formally by the MPSC. Due to significant increases in the cost of fuels used to generate electricity, the average monthly electric bill for and DPL's Maryland residential customers will increase by about 35%.
Virginia
Under amendments to the Virginia Electric Utility Restructuring Act implemented in March 2004, DPL is obligated to offer Default Service to customers in Virginia for an indefinite period until relieved of that obligation by the VSCC. DPL currently obtains all of the energy and capacity needed to fulfill its Default Service obligations in Virginia under a supply agreement with Conectiv Energy that commenced on January 1, 2005 and expires in May 2006 (the 2005 Supply Agreement). A prior agreement, also with Conectiv Energy, terminated effective December 31, 2004. DPL entered into the 2005 Supply Agreement after conducting a competitive bid procedure in which Conectiv Energy was the lowest bidder.
In October 2004, DPL filed an application with the VSCC for approval to increase the rates that DPL charges its Default Service customers to allow it to recover its costs for power under the 2005 Supply Agreement plus an administrative charge and a margin. A VSCC order issued in November 2004 allowed DPL to put interim rates into effect on January 1, 2005, subject to refund if the VSCC subsequently determined the rate is excessive. The interim rates reflected an increase of 1.0247 cents per Kwh to the fuel rate, which provide for recovery of the entire amount being paid by DPL to Conectiv Energy, but did not include an administrative charge or
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margin, pending further consideration of this issue. In January 2005, the VSCC ruled that the administrative charge and margin are base rate items not recoverable through a fuel clause. In March 2005, the VSCC approved a settlement resolving all other issues and making the interim rates final.
On March 10, 2006, DPL filed a rate increase with the VSCC to reflect proposed rates for its Virginia Default Service customers to take effect on June 1, 2006. The new rates will raise the average monthly bill for residential customers by approximately 43%. The proposed rates must be approved by the VSCC.
IRS Mixed Service Cost Issue
During 2001, DPL changed its methods of accounting with respect to capitalizable construction costs for income tax purposes, which allow DPL to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions have generated incremental tax cash flow benefits of approximately $62 million for DPL, primarily attributable to its 2001 tax returns. On August 2, 2005, the IRS issued Revenue Ruling 2005-53 (the Revenue Ruling) that will limit the ability of DPL to utilize this method of accounting for income tax purposes on its tax returns for 2004 and prior years. DPL intends to contest any IRS adjustment to its prior year income tax returns based on the Revenue Ruling. However, if the IRS is successful in applying this Revenue Ruling DPL would be required to capitalize and depreciate a portion of the construction costs previously deducted and repay the associated income tax benefits, along with interest thereon. During 2005, DPL recorded a $2.9 million increase in income tax expense to account for the accrued interest that would be paid on the portion of tax benefits that DPL estimates would be deferred to future years if the construction costs previously deducted are required to be capitalized and depreciated.
On the same day as the Revenue Ruling was issued, the Treasury Department released 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 all future tax periods beginning in 2005. Under these regulations, DPL will have to capitalize and depreciate a portion of the construction costs that it has previously deducted and include the impact of this adjustment in taxable income over a two-year period beginning with tax year 2005. DPL is continuing to work with the industry to determine an alternative method of accounting for capitalizable construction costs acceptable to the IRS to replace the method disallowed by the proposed regulations.
In February 2006, PHI paid approximately $121 million, a portion of which is attributable to DPL, of taxes to cover the amount of taxes management estimates will be payable once a new final method of tax accounting is adopted on its 2005 tax return, due to the proposed regulations. Although the increase in taxable income will be spread over the 2005 and 2006 tax return periods, the cash payments would have all occurred in 2006 with the filing of the 2005 tax return and the ongoing 2006 estimated tax payments. This $121 million tax payment was accelerated to eliminate the need to accrue additional federal interest expense for the potential IRS adjustment related to the previous tax accounting method PHI used during the 2001-2004 tax years.
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(a)
Included in fuel and purchased energy.
(b)
Included in electric revenue.
(c)
Included in interest expense.
(d)
Included in gas purchased.
(e)
Included in gas revenue.
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As of December 31, 2005 and 2004, DPL had the following balances on its balance sheets due (to)/from related parties:
(13) RESTATEMENT
Our parent company, Pepco Holdings, restated its previously reported consolidated financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct the accounting for certain deferred compensation arrangements. The restatement includes the correction of other errors for the same periods, primarily relating to unbilled revenue, taxes, and various accrual accounts, which were considered by management to be immaterial. These other errors would not themselves have required a restatement absent the restatement to correct the accounting for deferred compensation arrangements. The restatement of Pepco Holdings consolidated financial statements was required solely because the cumulative impact of the correction, if recorded in the fourth quarter of 2005, would have been material to that period's reported net income. The restatement to correct the accounting for the deferred compensation arrangements had no impact on DPL; however, DPL restated its previously reported financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, and the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to reflect the correction of other errors. The correction of these other errors, primarily relating to unbilled revenue, taxes, and various accrual accounts, was considered by management to be immaterial. See Note 13 "Restatement" for further discussion.
The following table sets forth for DPL, for the years ended December 31, 2004 and 2003, the impact of the restatement to correct the errors noted above (millions of dollars):
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(14) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The unaudited quarterly financial information for the three months ended March 31, 2005, June 30, 2005 and September 30, 2005 and all interim periods during the year ended December 31, 2004 have been restated to reflect the correction of certain immaterial errors. See Note 13 for further discussion. 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.
Note:
Sales of electric energy are seasonal and, accordingly, comparisons by quarter within a year are not meaningful.
(a)
Includes $2.0 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.
(b)
Includes $1.0 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.
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Report of Independent Registered Public Accounting Firm
To the 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 disclosed in Note 14 to the consolidated financial statements, the Company restated its financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003.
PricewaterhouseCoopers LLP
Washington, D.C.
March 13, 2006
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The accompanying Notes are an integral part of these Consolidated Financial Statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ATLANTIC CITY ELECTRIC COMPANY
(1) ORGANIZATION
Atlantic City Electric Company (ACE) is engaged in the 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). ACE's service territory covers approximately 2,700 square miles and has a population of approximately 998,000. ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or 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 ACE and certain activities of ACE are subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC) under PUHCA 2005.
(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. Under the equity method, ACE records its interest in the entity as an investment in the accompanying Consolidated Balance Sheets, and its percentage share of the entity's earnings are recorded in the accompanying Consolidated Statements of Earnings. Additionally, the proportionate interests in jointly owned electric plants are consolidated.
In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46), issued in January 2003, with a revised interpretation issued in December 2003, FASB Interpretation No. 46-R, "Consolidation of Variable Interest Entities" (FIN 46R), ACE deconsolidated its trust preferred securities that had previously been consolidated. FIN 46 and FIN 46R address conditions when an entity should be consolidated based upon variable interests rather than voting interests. For additional information regarding the impact of implementing FIN 46 and FIN 46R, see the "New Accounting Standards" section 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, such as compliance with Statement of Position 94-6, "Disclosure of Certain Significant Risks and Uncertainties," 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. Examples of significant estimates used by ACE include the assessment of contingencies, the calculation of future cash flows and fair value
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amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, and judgment involved with assessing the probability of recovery of regulatory assets. 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 based upon the probable and reasonably estimable criteria contained in SFAS No. 5, "Accounting for Contingencies." 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.
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 (estimates of electricity expected to be 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 for the supply and delivery of electricity upon delivery to the customer, including amounts for services rendered, but not yet billed (unbilled revenue). ACE recorded amounts for unbilled revenue of $42.0 million and $57.2 million as of December 31, 2005 and December 31, 2004, respectively. These amounts are included in the "accounts receivable" line item in the accompanying Consolidated Balance Sheets. ACE calculates unbilled revenue using an output based methodology. This methodology is based on the supply of electricity or gas distributed to customers. The unbilled revenue process requires management 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), which are inherently uncertain and susceptible to change from period to period, the impact of which could be material.
The taxes related to the delivery of electricity to its customers are a component of the Company's tariffs and, as such, is billed to customers and recorded in Operating Revenues. Accruals for these taxes by the Company are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by the Company 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 NJBPU and its wholesale operations are subject to regulation by the Federal Energy Regulatory Commission (FERC).
Based on the regulatory framework in which it has operated, ACE has historically applied, and in connection with its transmission and distribution business continues to apply, the provisions of Statement of Financial Accounting Standards 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
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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, 2005 and 2004 are as follows:
The components of ACE's regulatory liability balances at December 31, 2005 and 2004 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 (NUG) 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 of Transition Bonds by Atlantic City Electric Transition Funding LLC (ACE Funding). 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 Energy Supply Costs: Primarily represents deferred costs relating to the provision of Basic Generation Service (BGS) and other restructuring related costs incurred by ACE. All deferrals receive a return. ACE deferrals are recoverable over the next 9 years.
Deferred Recoverable Income Taxes: Represents deferred income tax assets recognized from the normalization of flow-through items as a result of amounts previously provided to customers. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return on these deferrals.
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Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period. A return is 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.
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 the New Jersey rate case settlement. This excess reserve is the result of a change in estimated depreciable lives from remaining life to whole life. The excess will be amortized over about 8.25 years.
Regulatory Liability for Federal and New Jersey Tax Benefit and Other: 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.
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. Deposits in the PHI money pool were $4.0 million and $1.7 million at December 31, 2005, and 2004, respectively.
Restricted Cash
Restricted cash represents cash either held as collateral or pledged as collateral, and is restricted from use for general corporate purposes.
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Capitalized Interest and Allowance for Funds Used During Construction
In accordance with the provisions of SFAS No. 34, "Capitalization of Interest Cost," the cost of financing the construction of ACE's subsidiaries electric generating plants is capitalized. Other non-utility construction projects also include financing costs in accordance with SFAS No. 34. In accordance with the provisions of SFAS No. 71, utilities can capitalize Allowance for Funds Used During Construction (AFUDC) as part of the cost of plant and equipment. AFUDC recognizes that utility construction is financed partially by debt and partially by equity.
ACE recorded AFUDC for borrowed funds of $.8 million, $1.2 million and $.9 million for the years ended December 31, 2005, 2004 and 2003, respectively. These amounts are recorded as a reduction of "interest expense" in the accompanying Consolidated Statements of Earnings.
ACE recorded amounts for the equity component of AFUDC of $1.6 million, $1.7 million and $1.2 million for the years ended December 31, 2005, 2004 and 2003, respectively. The amounts are included in the "other income" caption of the accompanying Consolidated Statements of Earnings.
Amortization of Debt Issuance and Reacquisition Costs
The amortization of debt discount, premium, and expense, including deferred debt extinguishment costs associated with the regulated electric businesses, is included in interest expense.
Emission Allowances
Emission allowances for Sulfur Dioxide (SO2) and Nitrous Oxide (NOX) are allocated to generation owners by the Environmental Protection Agency (EPA) based on Federal programs designed to regulate the emissions from power plants. The 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 so that generation companies can avoid stiff penalties for noncompliance.
ACE accounts for emission allowances as inventory. 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 zero-basis allowances. ACE has a committee established 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.
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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 taxes are discussed below.
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.
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 retirement plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings' subsidiaries (Retirement Plan). Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan for Pepco employees are identical to those of the original Pepco plan and for Conectiv employees are identical to the original Conectiv plan. 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.
PHI accounts for the Retirement Plan 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." PHI's financial statement disclosures were prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits."
Long-Lived Asset Impairment Evaluation
ACE is required to evaluate certain long-lived assets (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist. SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," provides the accounting for impairments of long-lived assets and indicates that companies are required to test long-lived assets for recoverability 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. For long-lived assets that are
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expected to be held and used, SFAS No. 144 requires that an impairment loss be recognized only if the carrying amount of an asset is not recoverable and exceeds its fair value.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. 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. The system-wide composite depreciation rates for 2005, 2004 and 2003 for ACE's generation, transmission and distribution system property were 3.1%, 3.3% and 3.2%, respectively. Property, plant and equipment other than electric facilities is generally depreciated on a straight-line basis over the useful lives of the assets.
Accounts Receivable and Allowance for Uncollectible Accounts
ACE's 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). ACE uses the allowance method to account for uncollectible accounts receivable.
FIN 46R
ACE has power purchase agreements (PPAs) with a number of entities, including three non-utility generation contracts (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. As required by FIN 46R, ACE continued, during 2005, 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, 2005, 2004 and 2003, were approximately $327 million, $265 million and $247 million, respectively, of which $289 million, $236 million and $220 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.
Other Non-Current Assets
The other assets balance principally consists of real estate under development, equity and other investments, and deferred compensation trust assets.
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Other Current Liabilities
The other current liability balance principally consists of customer deposits, accrued vacation liability, and the current portion of deferred income taxes.
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.
New Accounting Standards
SFAS No. 154
In May 2005, the FASB issued Statement No. 154, "Accounting Changes and Error Corrections (SFAS No. 154), a replacement of APB Opinion No. 20 and FASB Statement No. 3." SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. The reporting of a correction of an error by restating previously issued financial statements is also addressed by SFAS No. 154. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 (the year ended December 31, 2006 for Pepco Holdings). Early adoption is permitted.
EITF 04-13
In September 2005, the FASB ratified EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" (EITF 04-13), which addresses circumstances under which two or more exchange transactions involving inventory with the same counterparty should be viewed as a single exchange transaction for the purposes of evaluating the effect of APB Opinion 29. EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006 (April 1, 2006 for ACE). EITF 04-13 would not affect ACE's net income, overall financial condition, or cash flows, but rather could result in certain revenues and costs, including wholesale revenues and purchased power expenses, being presented on a net basis. ACE is in the process of evaluating the impact of EITF 04-13 on its Consolidated Statements of Earnings presentation of purchases and sales.
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(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 other types of property and equipment for use in its operations. Amounts charged to operating expenses for these leases were $11.0 million in 2005, $11.7 million in 2004, and $10.0 million in 2003. Future minimum rental payments for all non-cancelable lease agreements are less than $10 million per year for each of the next five years.
(5) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of the following:
The balances of all property, plant and equipment, which is primarily electric transmission and distribution property, are stated at original cost. Utility plant is generally subject to a first mortgage lien. The system-wide composite depreciation rates in 2005 and 2004 for ACE's generation, transmission and distribution system property were approximately 3.1% and 3.3%, respectively.
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 electric generating plants, 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, 2005 is shown below.
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As discussed in Note (12), Commitments and Contingencies, during the fourth quarter of 2005, ACE entered into an agreement to sell its interests in Keystone and Conemaugh. The sale is expected to be completed by the third quarter of 2006.
(6) PENSIONS AND OTHER POSTRETIREMENT BENEFITS
Pension Benefits
Pepco Holdings sponsors a defined benefit Retirement Plan that 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.
Other Postretirement Benefits
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.
During 2004, PHI amended its postretirement health care plans for certain groups of eligible employees effective January 1, 2005 or January 1, 2006. The amendments included changes to coverage and retiree cost-sharing, and are reflected as a reduction in PHI's 2004 net periodic benefit cost and a reduction of $42 million in the projected benefit obligation at December 31, 2004.
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Pepco Holdings uses a December 31 measurement date for its plans. Plan assets are stated at their market value as of the measurement date, December 31. All dollar amounts in the following tables are in millions of dollars.
The following table provides a reconciliation of the projected benefit obligation, plan assets and funded status of the plans.
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The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheet as of December 31:
The accumulated benefit obligation for the Retirement Plan (the qualified defined benefit pension plan) was $1,556.2 million and $1,462.9 million at December 31, 2005, and 2004, respectively. The table below provides the projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the PHI nonqualified pension plan with an accumulated benefit obligation in excess of plan assets at December 31, 2005 and 2004.
In 2005 and 2004, PHI was required to recognize an additional minimum liability and an intangible asset related to its nonqualified pension plan as prescribed by SFAS No. 87. The liability was recorded as a reduction to shareholders' equity (other comprehensive income), and the equity will be restored to the balance sheet in future periods when the accrued benefit liability exceeds the accumulated benefit obligation at future measurement dates. The amount of reduction to shareholders' equity (net of income taxes) in 2005 was $7.3 million and in 2004 was $4.1 million. The recording of this reduction did not affect net income or cash flows in 2005 or 2004 or compliance with debt covenants.
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The table below provides the components of net periodic benefit costs recognized for the years ended December 31.
Approximately $16.9 million, $17.6 million and $20.8 million were included in capital and operating and maintenance expense, in 2005, 2004 and 2003, respectively, for ACE's allocated portion of PHI's combined pension and other postretirement benefit expense.
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
Effect on total of service and interest cost
$ 1.8
$ (1.7)
Effect on postretirement benefit obligation
27.0
(25.1)
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The following weighted average assumptions were used to determine the net periodic benefit cost for years ended December 31:
A cash flow matched bond portfolio approach to developing a discount rate is used to value FAS 87 and FAS 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 time horizon, are expected to yield a return on assets of 8.50%.
Plan Assets
Pepco Holdings' Retirement Plan weighted-average asset allocations at December 31, 2005, and 2004, by asset category are as follows:
Pepco Holdings' other postretirement plan weighted-average asset allocations at December 31, 2005, and 2004, by asset category are as follows:
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In developing an asset allocation policy for its 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 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 - Retirement Plan
Pepco Holdings' funding policy with regard to the Retirement Plan is to maintain a funding level in excess of 100% with respect to its accumulated benefit obligation (ABO). PHI's Retirement Plan currently meets the minimum funding requirements of ERISA without any additional funding. In 2005 and 2004, PHI made discretionary tax-deductible cash contributions to the plan of $60.0 million and $10.0 million, respectively, in line with its funding policy. Assuming no changes to the current pension plan assumptions, PHI projects no funding will be required under ERISA in 2006; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its plan assets in excess of its ABO.
Contributions - Other Postretirement Benefits
In 2005, PHI combined its health and welfare plans and the existing IRC 501 (C) (9) Voluntary Employee Beneficiary Association (VEBA) trusts for Pepco, DPL and ACE to fund a portion of their estimated postretirement liabilities. ACE contributed $7.0 million and $9.3 million to the PHI-sponsored plan in 2005 and 2004, respectively. A ssuming no changes to the current plan assumptions, ACE expects to contribute amounts similar to its allocated portion of PHI's other postretirement benefit expense to the other postretirement welfare benefit plan in 2006.
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Expected Benefit Payments
Estimated future benefit payments to participants in PHI's qualified pension and postretirement welfare benefit plans, which reflect expected future service as appropriate, as of December 31, 2005 are in millions of dollars:
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(7) LONG-TERM DEBT
Long-term debt outstanding as of December 31, 2005 and 2004 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 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. At such time as there are no First Mortgage Bonds of an issuing company outstanding, other than collateral First Mortgage Bonds securing payment of senior notes and tax-exempt bonds, each outstanding series of senior notes and tax-exempt bonds of the company will automatically cease to be secured by the corresponding series of collateral First Mortgage Bonds and all of the outstanding collateral First Mortgage Bonds of the company will be cancelled. 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.
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The outstanding First Mortgage Bonds issued by ACE are secured by a lien on substantially all of ACE's property, plant and equipment.
Atlantic City Electric Transition Funding L.L.C. (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 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 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, 2005, that will mature in each of 2006 through 2010 and thereafter is as follows: 2006-$94 million; 2007-$45.9 million; 2008-$81 million; 2009-$32.2 million; 2010-$34.7 million; and thereafter $677.9 million.
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, 2005 and 2004 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 Pepco and DPL.
ACE had no commercial paper outstanding at December 31, 2005 and $32.7 million of commercial paper outstanding at December 31, 2004. The weighted average interest rate for commercial paper issued during 2005 was 3.24%. Interest rates for commercial paper issued during 2004 ranged from 1.07% to 2.63%. Maturities were less than 270 days for all commercial paper issued.
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Variable Rate Demand Bonds
Variable Rate Demand Bonds ("VRDB") are subject to repayment on the demand of the holders and for this reason are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. ACE expects the bonds submitted for purchase will continue to be remarketed successfully due to the credit worthiness of the company and because the remarketing resets the interest rate to the then-current market rate. The company also may utilize one of the fixed rate/fixed term conversion options of the bonds to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, ACE views VRDBs as a source of long-term financing. The VRDB outstanding in 2005 and 2004 mature in 2014 ($18.2 million) and 2017 ($4.4 million). The weighted average interest rate for VRDB was 2.47% during 2005 and ranged from .82% to 1.98% in 2004.
Credit Facility
In May 2005, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $1.2 billion. This agreement replaces a $650 million five-year credit agreement that was entered into in July 2004 and a $550 million three-year credit agreement entered into in July 2003. Pepco Holdings' credit limit under this agreement is $700 million. The credit limit of each of Pepco, DPL and ACE is the lower of $300 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 under the agreement may not exceed $500 million. Under the terms of the credit agreement, the companies are entitled to request increases in the principal amount of available credit up to an aggregate increase of $300 million, with any such increase proportionately increasing the credit limit of each of the respective borrowers and the $300 million sublimits for each of Pepco, DPL and ACE. The interest rate payable by the respective companies on utilized funds is determined by a pricing schedule with rates corresponding to the credit rating of the borrower. Any indebtedness incurred under the credit agreement would be unsecured.
The credit agreement 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 contained in the credit agreement 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, (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 failure to satisfy any of the covenants or the occurrence of specified events that constitute an event of default could result in the acceleration of the repayment obligations of the borrower. The events of default include (i) the failure of any borrowing company or any of its significant subsidiaries to pay when due, or the acceleration of,
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certain indebtedness under other borrowing arrangements, (ii) certain bankruptcy events, judgments or decrees against any borrowing company or its significant subsidiaries, and (iii) a change in control (as defined in the credit agreement) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE. The agreement does not include any ratings triggers. There were no balances outstanding at December 31, 2005 and 2004.
(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 which was approved by the Securities and Exchange Commission pursuant to regulations under the Public Utility Holding Company Act of 1935 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, with the exception of the tax benefits applicable to non-acquisition debt expenses of PHI. Such tax benefits are allocated only to subsidiaries with taxable income.
The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred income tax liabilities (assets) are shown below.
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Components of Deferred Income Tax Liabilities (Assets)
The tax effects of temporary differences that give rise to ACE's net deferred tax liability are shown below, the majority of which are recoverable in rates.
Taxes Other Than Income Taxes
Taxes other than income taxes for each year are shown below.
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(9) PREFERRED STOCK
The preferred stock amounts outstanding as of December 31, 2005 and 2004 are as follows:
(10) FAIR VALUES OF FINANCIAL INSTRUMENTS
The estimated fair values of ACE's financial instruments at December 31, 2005 and 2004 are shown below.
The methods and assumptions below were used to estimate, at December 31, 2005 and 2004, 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, excluding 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.
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(11) COMMITMENTS AND CONTINGENCIES
REGULATORY AND OTHER MATTERS
Rate Proceedings
Federal Energy Regulatory Commission
On January 31, 2005, ACE filed at FERC to reset its rates for network transmission service using a formula methodology. ACE also sought a 12.4% return on common equity and a 50-basis-point return on equity adder that FERC had made available to transmission utilities who had joined Regional Transmission Organizations and thus turned over control of their assets to an independent entity. FERC issued an order on May 31, 2005, approving the rates to go into effect June 1, 2005, subject to refund, hearings, and further orders. The new rates reflect an increase of 3.3% ACE's transmission rates. ACE continues in settlement discussions under the supervision of a FERC administrative law judge and cannot predict the ultimate outcome of this proceeding.
Restructuring Deferral
Pursuant to orders issued by the NJBPU under 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 choose a competitive energy 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) that was 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 and was in addition to the base rate increase discussed above. ACE's recovery of the deferred costs is subject to review and approval by the NJBPU in accordance with EDECA.
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, and (iv) estimated the overall deferral balance as of July 31, 2003 at $195 million, of which $44.6 million was disallowed recovery by ACE. ACE believes the record does not justify the level of disallowance imposed by the NJBPU in the final order. In August 2004, ACE filed with the Appellate Division of the Superior Court of New Jersey, which hears appeals of New Jersey administrative
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agencies, including the NJBPU, a Notice of Appeal with respect to the July 2004 final order. ACE's initial brief was filed on August 17, 2005. Cross-appellant briefs on behalf of the Division of the New Jersey Ratepayer Advocate and Cogentrix Energy Inc., the co-owner of two cogeneration power plants with contracts to sell ACE approximately 397 megawatts of electricity, were filed on October 3, 2005. The NJBPU Staff filed briefs on December 12, 2005. ACE filed its reply briefs on January 30, 2006.
Default Electricity Supply Proceedings
New Jersey
On October 12, 2005, the NJBPU, following the evaluation of proposals submitted by ACE and the other three electric distribution companies located in New Jersey, issued an order reaffirming the current BGS auction process for the annual period from June 1, 2006 through May 2007. The NJBPU order maintains the current size and make up of the Commercial and Industrial Energy Pricing class (CIEP) and approved the electric distribution companies' recommended approach for the CIEP auction product, but deferred a decision on the level of the retail margin funds.
Proposed Shut Down of B.L. England Generating Facility
In April 2004, pursuant to a NJBPU order, ACE filed a report with the NJBPU recommending that ACE's B.L. England generating facility, a 447 megawatt plant, be shut down. The report stated that, while operation of the B.L. England generating facility was necessary at the time of the report to satisfy reliability standards, those reliability standards could also be satisfied in other ways. The report concluded that, based on B.L. England's current and projected operating costs resulting from compliance with more restrictive environmental requirements, the most cost-effective way in which to meet reliability standards is to shut down the B.L. England generating facility and construct additional transmission enhancements in southern New Jersey.
In December 2004, ACE filed a petition with the NJBPU requesting that the NJBPU establish a proceeding that will consist of a Phase I and Phase II and that the procedural process for the Phase I proceeding require intervention and participation by all persons interested in the prudence of the decision to shut down B.L. England generating facility and the categories of stranded costs associated with shutting down and dismantling the facility and remediation of the site. ACE contemplates that Phase II of this proceeding, which would be initiated by an ACE filing in 2008 or 2009, would establish the actual level of prudently incurred stranded costs to be recovered from customers in rates. The NJBPU has not acted on this petition.
In a January 24, 2006 Administrative Consent Order (ACO) among PHI, Conectiv, ACE, the New Jersey Department of Environmental Protection (NJDEP) and the Attorney General of New Jersey, ACE agreed to shut down and permanently cease operations at the B.L. England generating facility by December 15, 2007 if ACE does not sell the plant. The shut-down of the B.L. England generating facility will be subject to necessary approvals from the relevant agencies and the outcomes of the auction process, discussed under "ACE Auction of Generating Assets," below.
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ACE Auction of Generation Assets
In May 2005, ACE announced that it would again auction its electric generation assets, consisting of its B.L. England generating facility and its ownership interests in the Keystone and Conemaugh generating stations. On November 15, 2005, ACE announced an agreement to sell its interests in the Keystone and Conemaugh generating stations to Duquesne Light Holdings Inc. for $173.1 million. The sale, subject to approval by the NJBPU as well as other regulatory agencies and certain other legal conditions, is expected to be completed mid-year 2006.
Based on the expressed need of the potential B.L. England bidders for the details of the ACO relating to the shut down of the plant that was being negotiated between ACE and the NJDEP, ACE elected to delay the final bid due date for B.L. England until such time as a final ACO was complete and available to bidders. With the January 24, 2006 execution of the ACO by all parties, ACE is proceeding with the auction process. Indicative bids were received on February 16, 2006 and final bids are scheduled to be submitted on or about April 19, 2006.
Under the terms of sale, any successful bid for B.L. England must include assumption of all environmental liabilities associated with the plant in accordance with the auction standards previously issued by the NJBPU.
Any sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. If B.L. England is sold, ACE anticipates that, subject to regulatory approval in Phase II of the proceeding described above, approximately $9.1 million of additional assets may be eligible for recovery as stranded costs. The net gains on the sale of the Keystone and Conemaugh generating stations will be an offset to stranded costs associated with the shutdown of B. L. England or will be offset through other ratemaking adjustments. Testimony filed by ACE with the NJBPU in December 2005 estimated net gains of approximately $126.9 million; however, the net gains ultimately realized will be dependent upon the timing of the closing of the sale of Keystone and Conemaugh generating stations, transaction costs and other factors.
IRS Mixed Service Cost Issue
During 2001, ACE changed its methods of accounting with respect to capitalizable construction costs for income tax purposes, which allow the companies to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions have generated incremental tax cash flow benefits of approximately $49 million for ACE, primarily attributable to its 2001 tax returns. On August 2, 2005, the IRS issued Revenue Ruling 2005-53 (the Revenue Ruling) that will limit the ability of ACE to utilize this method of accounting for income tax purposes on its tax returns for 2004 and prior years. ACE intends to contest any IRS adjustment to its prior year income tax returns based on the Revenue Ruling. However, if the IRS is successful in applying this Revenue Ruling, ACE would be required to capitalize and depreciate a portion of the construction costs previously deducted and repay the associated income tax benefits, along with interest thereon. During 2005, ACE recorded a $2.0 million increase in income tax expense to account for the accrued interest that would be paid on the portion of tax benefits that ACE estimates would be deferred to future years if the construction costs previously deducted are required to be capitalized and depreciated.
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On the same day as the Revenue Ruling was issued, the Treasury Department released 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 all future tax periods beginning in 2005. Under these regulations, ACE will have to capitalize and depreciate a portion of the construction costs that it has previously deducted and include the impact of this adjustment in taxable income over a two-year period beginning with tax year 2005. ACE is continuing to work with the industry to determine an alternative method of accounting for capitalizable construction costs acceptable to the IRS to replace the method disallowed by the proposed regulations.
In February 2006, PHI paid approximately $121 million, a portion of which is attributable to ACE, of taxes to cover the amount of taxes management estimates will be payable once a new final method of tax accounting is adopted on its 2005 tax return, due to the proposed regulations. Although the increase in taxable income will be spread over the 2005 and 2006 tax return periods, the cash payments would have all occurred in 2006 with the filing of the 2005 tax return and the ongoing 2006 estimated tax payments. This $121 million tax payment was accelerated to eliminate the need to accrue additional federal interest expense for the potential IRS adjustment related to the previous tax accounting method PHI used during the 2001-2004 tax years.
Contractual Obligations
As of December 31, 2005, ACE's contractual obligations under non-derivative fuel and power purchase contracts (excluding BGS supplier load commitments) were $308.8 million in 2006, $589.9 million in 2007 to 2008, $548.0 million in 2009 to 2010, and $3,070.5 million in 2011 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 in consolidation and no profit results from these transactions. PHI Service Company costs directly charged or allocated to ACE for the years ended December 31, 2005, 2004 and 2003 were $82.2 million, $86.3 million and $89.5 million, respectively.
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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 operating revenue.
(b)
Included in fuel and purchased energy.
(c)
Included in interest and dividend income.
(d)
Included in other operation and maintenance.
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As of December 31, 2005 and 2004, ACE had the following balances due (to)/from related parties:
(13) EXTRAORDINARY ITEMS
On April 19, 2005, ACE, the staff of the New Jersey Board of Public Utilities (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.
In July 2003, the NJBPU approved the recovery of $149.5 million of stranded costs related to ACE's B.L. England generating facility. As a result of the order, ACE reversed $10.0 million of accruals for the possible disallowances related to these stranded costs. The after tax credit to income of $5.9 million is classified as an extraordinary gain in the 2003 financial statements, since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.
(14) RESTATEMENT
Our parent company, Pepco Holdings, restated its previously reported consolidated financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct the accounting for certain deferred compensation arrangements. The restatement includes the correction of other errors for the same periods, primarily relating to unbilled revenue, taxes, and various accrual accounts,which were considered by management to be immaterial. These other errors would not themselves have required a restatement absent the restatement to correct the accounting for deferred compensation arrangements. The restatement of Pepco Holdings
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consolidated financial statements was required solely because the cumulative impact of the correction, if recorded in the fourth quarter of 2005, would have been material to that period's reported net income. The restatement to correct the accounting for the deferred compensation arrangements had no impact on ACE; however, ACE restated its previously reported consolidated financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to reflect the correction of other errors. The correction of these other errors, primarily relating to taxes and various accrual accounts, was considered by management to be immaterial. The following table sets forth for ACE, for the years ended December 31, 2004 and 2003, the impact of the restatement to correct the errors noted above (millions of dollars):
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(15) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The unaudited quarterly financial information for the three months ended March 31, 2005, June 30, 2005, and September 30, 2005 and all interim periods during the year ended December 31, 2004 have been restated to reflect the correction of certain immaterial errors. See Note 14 for further discussion. 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.
NOTE:
Sales of electric energy are seasonal and, accordingly, comparisons by quarter within a year are not meaningful.
(a)
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 an extraordinary gain since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.
(b)
Includes a $14.7 million pre-tax ($8.6 million after tax) gain from the condemnation settlement associated with the transfer of Vineland distribution assets.
(c)
Includes $1.7 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.
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(d)
Includes $.3 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.
(16) SUBSEQUENT EVENT
On February 9, 2006, certain institutional buyers tentatively agreed to purchase in a private placement $105 million of ACE's senior notes having an interest rate of 5.80% and a term of 30 years. The execution of a definitive purchase agreement and closing is expected on or about March 15, 2006. The proceeds from the notes would be used to repay outstanding commercial paper issued by ACE to fund the payment at maturity of $105 million in principal amount of various issues of medium-term notes.
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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, 2005, 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 SEC under the Securities Exchange Act of 1934 (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 Consideration of the Restatement
As discussed in Note 15 of the Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, Pepco Holdings restated its previously reported consolidated financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct the accounting for certain deferred compensation arrangements and to correct errors with respect to unbilled revenue, taxes and various accrual accounts. In coming to the conclusion that the Company's disclosure controls and procedures and the Company's internal control over financial reporting were effective as of December 31, 2005 management concluded that the restatement items described in Note 15 of the Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, individually or in the aggregate, did not constitute a material weakness. In coming to this conclusion management reviewed and analyzed the Securities and Exchange Commission's Staff Accounting Bulletin ("SAB") No. 99, "Materiality," paragraph 29 of Accounting Principles Board Opinion No. 28, "Interim Financial Reporting," and SAB Topic 5F, "Accounting Changes Not Retroactively Applied Due to Immateriality," and took into consideration (i) that the restatement adjustments did not have a material impact on the financial statements of prior interim or annual periods taken as a whole; (ii) that the cumulative impact of the restatement adjustments on shareholders' equity was not material to the financial statements of prior interim or annual periods; and (iii) that Pepco Holdings decided to restate its previously issued financial statements solely because the cumulative impact of the adjustments would have been material to the fourth quarter of 2005 reported net income.
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Management's Report on Internal Control Over Financial Reporting
See "Management's Report on Internal Control Over Financial Reporting" in Part II, Item 8 of this Form 10-K.
Attestation Report of the Registered Public Accounting Firm
See "Report of Independent Registered Public Accounting Firm" in Part II, Item 8 of this Form 10-K.
Changes in Internal Control Over Financial Reporting
During the quarter ended December 31, 2005, 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.
Pepco Holdings' subsidiary, Conectiv Energy, which operates a competitive energy business, is in the process of installing new energy transaction software that provides additional functionality, such as enhanced PJM reconciliation capability, hedge accounting, greater risk analysis capability and enhanced regulatory reporting capability. During the second quarter of 2006, Conectiv Energy anticipates implementing the new software for all energy commodity transactions. The Conectiv Energy implementation will be the first commercial implementation of this software and extensive pre-implementation testing has been performed to ensure internal controls over financial reporting continue to be effective. Operating effectiveness of internal controls over financial reporting will continue to be evaluated post implementation.
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, 2005, 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 Securities Exchange Act of 1934 (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 Consideration of the Restatement
As discussed in Note 13 of the Notes to Financial Statements in Part II, Item 8 of this Form 10-K, Pepco restated its previously reported financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct the accounting for certain deferred compensation arrangements and to correct errors with respect to unbilled revenue, taxes, and various accrual accounts. In coming to the conclusion that the Company's disclosure controls and procedures were effective as of December 31, 2005, management concluded that the restatement items described in Note 13 of the Notes to Financial Statements in Part II, Item 8
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of this Form 10-K, individually or in the aggregate, did not constitute a material weakness. In coming to this conclusion management reviewed and analyzed the Securities and Exchange Commission's Staff Accounting Bulletin ("SAB") No. 99, "Materiality," paragraph 29 of Accounting Principles Board Opinion No. 28, "Interim Financial Reporting," and SAB Topic 5F, "Accounting Changes Not Retroactively Applied Due to Immateriality," and took into consideration (i) that the restatement adjustments did not have a material impact on the financial statements of prior interim or annual periods taken as a whole; (ii) that the cumulative impact of the restatement adjustments on shareholder's equity was not material to the financial statements of prior interim or annual periods; and (iii) that Pepco decided to restate its previously issued financial statements solely because the cumulative impact of the adjustments would have been material to the fourth quarter of 2005 reported net income.
Changes in Internal Control Over Financial Reporting
During the quarter ended December 31, 2005, 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, 2005, 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 Securities Exchange Act of 1934 (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 Consideration of the Restatement
As further discussed in Note 13 of the Notes to Financial Statements in Part II, Item 8 of this Form 10-K, DPL restated its financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct errors with respect to unbilled revenue, taxes and various accrual accounts. In coming to the conclusion that the Company's disclosure controls and procedures were effective as of December 31, 2005, management concluded that the restatement items described in Note 13 of the Notes to Financial Statements in Part II, Item 8 of this Form 10-K, individually or in the aggregate, did not constitute a material weakness. In coming to this conclusion management reviewed and analyzed the Securities and Exchange Commission's Staff Accounting Bulletin ("SAB") No. 99, "Materiality," paragraph 29 of Accounting Principles Board Opinion No. 28, "Interim Financial Reporting," and SAB Topic 5F, "Accounting Changes Not Retroactively Applied Due to Immateriality," and took into consideration (i) that the restatement adjustments did not have a material impact on the financial statements of prior interim or annual periods taken as a whole; (ii) that the cumulative impact of the restatement adjustments on shareholder's equity was not material to the financial statements
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of prior interim or annual periods; and (iii) that the Company decided to restate its previously issued financial statements solely because of corrections recorded in Pepco Holdings consolidated financial statements.
Changes in Internal Control Over Financial Reporting
During the quarter ended December 31, 2005, 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, 2005, 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 Securities Exchange Act of 1934 (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 Consideration of the Restatement
As further discussed in Note 14 of the Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, ACE restated its consolidated financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct errors with respect to taxes and various accrual accounts. In coming to the conclusion that the Company's disclosure controls and procedures were effective as of December 31, 2005, management concluded that the restatement items described in Note 14 of the Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, individually or in the aggregate, did not constitute a material weakness. In coming to this conclusion management reviewed and analyzed the Securities and Exchange Commission's Staff Accounting Bulletin ("SAB") No. 99, "Materiality," paragraph 29 of Accounting Principles Board Opinion No. 28, "Interim Financial Reporting," and SAB Topic 5F, "Accounting Changes Not Retroactively Applied Due to Immateriality," and took into consideration (i) that the restatement adjustments did not have a material impact on the financial statements of prior interim or annual periods taken as a whole; (ii) that the cumulative impact of the restatement adjustments on shareholder's equity was not material to the financial statements of prior interim or annual periods; and (iii) that ACE restated its previously issued consolidated financial statements solely because of corrections recorded in Pepco Holdings consolidated financial statements.
___________________________________________________________________________________
Changes in Internal Control Over Financial Reporting
During the quarter ended December 31, 2005, 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.
The following table sets forth for each Named Executive Officer of Pepco Holdings, Inc. ("PHI") (which officers were determined by reference to SEC Regulation S-K, Item 402(a)(3) based on 2004 compensation) information concerning determinations made on March 7, 2006 by the PHI Compensation/Human Resources Committee with respect to (i) annual bonus for 2005, and (ii) long-term incentive plan payout for the performance cycle ending in 2005 under the Merger Integration Success Program.
Name
Title
Annual
Bonus (1)
Incentive Plan
Payout (2)
Dennis R. Wraase
Chairman, President and
Chief Executive Officer
$601,920
$220,546
William T. Torgerson
Vice Chairman and
General Counsel
$299,136
$151,416
Thomas S. Shaw
Executive Vice President and
Chief Operating Officer
$296,704
$184,166
Joseph M. Rigby
Senior Vice President and
Chief Financial Officer
$170,240
$ 80,624
William H. Spence
Senior Vice President
$190,124
$ 80,624
(1)
Consists of awards under the Annual Executive Incentive Compensation Plan based on the extent to which the following criteria established in 2004 were satisfied: (1) earnings relative to the corporate plan, (2) cash available for debt reduction, (3) electric system reliability, (4) diversity and (5) safety.
(2)
Amounts in this column represent the value of Common Stock awarded under the Merger Integration Success Program which is a component of PHI's Long-Term Incentive Plan. In 2002, PHI granted award opportunities under the Merger Integration Success Program under which the recipient would have been entitled to earn some or all of the maximum award of Common Stock based on PHI's performance and the extent to which operating efficiencies and expense reduction goals were attained through December 31, 2003. Although the goals were met in 2003, the Compensation/Human Resources Committee determined that the shares would not vest until 2005, and then only if the cost reduction goals were maintained and PHI's financial performance remained satisfactory. On March 7, 2006, the PHI Compensation/Human Resources Committee approved the vesting of these awards under the Merger Integration Success Program. The value of the vested Common Stock has been calculated by multiplying the number of vested shares by the market price of the Common Stock on the day preceding the vesting date. Also, in 2002, PHI granted award opportunities under the Performance Restricted Stock Program pursuant to which the recipient would have been entitled to earn some or all of the maximum award of shares of PHI's Common Stock, based on PHI's total shareholder return compared to other companies in a peer group comprised of 20 gas and electric distribution companies over a three-year period January 1, 2003 through December 31, 2005. For the three-year period, total shareholder return was below the threshold level of performance and, accordingly, no Common Stock was earned.
___________________________________________________________________________________
Potomac Electric Power Company
None.
Delmarva Power & Light Company
None
Atlantic City Electric Company
None
Part III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Pepco Holdings, Inc.
Except as set forth below, the information required by this Item 10 with regard to PHI is incorporated by reference to the information contained in PHI's definitive proxy statement for the 2006 Annual Meeting of Shareholders to be filed with the SEC on or about March 30, 2006.
Executive Officers of PHI
The names of the executive officers of Pepco Holdings and their ages and the positions they held as of March 13, 2006 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.
William J. Sim
Senior Vice President
8/02 - Present (7)
William H. Spence
Senior Vice President
8/02 - Present (8)
Ronald K. Clark
Vice President and Controller
8/05 - Present (9)
(9)
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. From June 2002 until December 2003, Mr. Clark served as Vice President, Controller and Chief Accounting Officer of Allegheny Energy, Inc. From January 2002 until May 2002, he was Controller of Lockheed Martin Global Telecommunications, a business segment of Lockheed Martin Corporation, and from April 2001 until January 2002, he was Assistant Controller of that entity. From March 1995 until March 2001, Mr. Clark served as Director, Financial Transactions and Reporting for Lockheed Martin Corporation.
The PHI executive officers serve until the next succeeding Annual Meeting and until their respective successors have been elected and qualified.
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 the information contained under the caption "Executive Compensation" in its definitive Proxy Statement for the 2006 Annual Meeting of Shareholders to be filed with the SEC on or about March 30, 2006.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Pepco Holdings, Inc.
The information required by Item 12 for Pepco Holdings concerning the security ownership of certain beneficial owners and management is incorporated herein by reference to information contained under the caption "Security Ownership of Certain Beneficial Owners and Management" in its definitive proxy statement for the 2006 Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission on or about March 30, 2006.
___________________________________________________________________________________
The following table provides information as of December 31, 2005, with respect to the shares of PHI's common stock that may be issued under PHI's existing equity compensation plans.
(1) Consists solely of the Pepco Holdings, Inc. Long-Term Incentive Plan.
(2) In connection with the merger of Pepco and Conectiv (i) outstanding options granted under the Potomac Electric Power Company Long-Term Incentive Plan were converted into options to purchase 1,365,941 shares of PHI common stock and (ii) options granted under the Conectiv Incentive Compensation Plan were converted into options to purchase 756,660 shares of PHI common stock, of which 3,205 were forfeited in 2005 and 196,299 were exercised in 2005. Collectively, these outstanding options to purchase an aggregate of 1,864,250 shares of PHI common stock have a weighted average exercise price of $22.1944.
(3) On January 1, 2005, the PHI Non-Management Directors Compensation Plan (the "Plan") became effective, pursuant to which 500,000 shares of PHI common stock became available for future issuance. Under the 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 the Company's Executive and Director Deferred Compensation Plan or (iv) any combination thereof. The Plan expires on December 31, 2014 unless terminated earlier by the Board of Directors.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
___________________________________________________________________________________
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pepco Holdings, Inc.
The information required by Item 13, if any, with regard to PHI is incorporated herein by reference to the information contained in its definitive proxy statement for the 2006 Annual Meeting of Shareholders to be filed with the SEC on or about March 30, 2006.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 14.
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item 14 with regard to PHI (which includes the information required with regard to Pepco, DPL and ACE) is incorporated herein by reference to information contained in PHI's definitive proxy statement for the 2006 Annual Meeting of Shareholders to be filed with the SEC on or about March 30, 2006.
___________________________________________________________________________________
Part IV
Item 15.
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(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 Supplemental Data."
2. FINANCIAL STATEMENT SCHEDULES
Pepco Holdings restated its previously reported consolidated financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct the accounting for certain deferred compensation arrangements. The restatement includes the correction of other errors for the same periods, primarily relating to unbilled revenue, taxes, and various accrual accounts, which were considered by management to be immaterial. These other errors would not themselves have required a restatement absent the restatement to correct the accounting for deferred compensation arrangements. This restatement was required solely because the cumulative impact of the correction, if recorded in the fourth quarter of 2005, would have been material to that period's reported net income. See Note 15 "Restatement" for further discussion.
All other financial statement schedules, other than those included below, are omitted because either they are not applicable, or the required information is presented in the financial statements, which are included in Item 8. "Financial Statements and Supplemental Data," herein.
Registrants
Item
Pepco
Holdings
Pepco
DPL
ACE
Schedule I, Condensed Financial
Information of Parent Company
N/A
N/A
N/A
Schedule II, Valuation and
Qualifying Accounts
___________________________________________________________________________________
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
Pepco Holdings restated its previously reported consolidated financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003, the quarterly financial information for the first three quarters in 2005, and all quarterly periods in 2004, to correct the accounting for certain deferred compensation arrangements.
The restatement includes the correction of other errors for the same periods, primarily relating to unbilled revenue, taxes, and various accrual accounts, which were considered by management to be immaterial. These other errors would not themselves have required a restatement absent the restatement to correct the accounting for deferred compensation arrangements. This restatement was required solely because the cumulative impact of the correction, if recorded in the fourth quarter of 2005, would have been material to that period's reported net income. The impact of the restatement related to the deferred compensation arrangements on periods prior to 2003 has been reflected as a reduction of approximately $23 million to Pepco Holdings' retained earnings balance as of January 1, 2003.
___________________________________________________________________________________
These condensed financial statements represent the financial information for Pepco Holdings, Inc. (Parent Company). No other financial statement schedules have been filed either because the required information is not present in amounts sufficient to require submission of the schedule or the information is included in the accompanying consolidated financial statements or the notes to the consolidated financial statements.
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 required by SEC Regulation S-K (summarized below).
EXHIBITS
The documents listed below are being filed or have previously been filed on behalf of Pepco Holdings, Inc. (PHI), Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) and are incorporated herein by reference from the documents indicated and made a part hereof.
23.3
DPL
Consent of Independent Registered Public Accounting Firm
Filed herewith.
23.4
ACE
Consent of Independent Registered Public Accounting Firm
Filed herewith.
31.1
PHI
Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
Filed herewith.
31.2
PHI
Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
Filed herewith.
31.3
Pepco
Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
Filed herewith.
31.4
Pepco
Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
Filed herewith.
31.5
DPL
Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
Filed herewith.
31.6
DPL
Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
Filed herewith.
31.7
ACE
Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
Filed herewith.
31.8
ACE
Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
Filed herewith.
* Management contract or compensatory plan or arrangement.
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 instrument) 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 omitted by it.
___________________________________________________________________________________
(c) Exhibits
Exhibit 11 Statements Re. Computation of Earnings Per Common Share
The information required by this Exhibit is included in Note 10 of the "Notes to Consolidated Financial Statements," which is included in Exhibit 13.
___________________________________________________________________________________
Exhibit 12.1 Statements Re. Computation of Ratios
PEPCO HOLDINGS, INC.
Exhibit 12.2 Statements Re. Computation of Ratios
POTOMAC ELECTRIC POWER COMPANY
Exhibit 12.3 Statements Re. Computation of Ratios
DELMARVA POWER & LIGHT COMPANY
(a)
As discussed in Note (13) to the financial statements of DPL included in Item 8 "Financial Statements and Supplementary Data," DPL restated its financial statements to reflect the correction of errors that management deemed to be immaterial. These errors otherwise would not have required restatement except for the restatement by Pepco Holdings to correct the accounting for certain deferred compensation arrangements.
___________________________________________________________________________________
Exhibit 12.4 Statements Re. Computation of Ratios
ATLANTIC CITY ELECTRIC COMPANY
(a)
As discussed in Note (14) to the consolidated financial statements of ACE included in Item 8 "Financial Statements and Supplementary Data," ACE restated its financial statements to reflect the correction of errors that management deemed to be immaterial. These errors otherwise would not have required restatement except for the restatement by Pepco Holdings to correct the accounting for certain deferred compensation arrangements.
___________________________________________________________________________________
Exhibit 21 Subsidiaries of the Registrants
Name of Company
Jurisdiction of
Incorporation or
Organization
Pepco Holdings, Inc.
DE
Potomac Electric Power Company
D.C. & VA
GriDCo International L.L.C.
DE
POM Holdings, Inc.
DE
Microcell Corporation
NC
Pepco Energy Services, Inc.
DE
Pepco Building Services, Inc.
DE
MET Electrical Testing Company, Inc.
DE
W.A. Chester, LC
DE
W.A. Chester Corporation
DE
Engineered Services, Inc.
DE
Severn Construction Services, LLC
DE
Unitemp, Inc.
DE
Seaboard Mechanical Services, Inc.
DE
Eastern Landfill Gas, LLC
DE
Blue Ridge Renewable Energy LLC
DE
Distributed General Partners, LLC
DE
Rolling Hills Landfill Gas, LLC
DE
PES Home Services of Virginia
VA
Potomac Power Resources, LLC
DE
Fauquier Landfill Gas, LLC
DE
Trigen-Pepco Energy Services, LLC
DC
Pepco Government Services, LLC
DE
Pepco Enterprises, Inc.
DE
Electro Ecology, Inc.
NY
Carolina Electrical Testing, Inc.
DE
Pepco Energy Cogeneration LLC
DE
Bethlehem Renewable Energy LLC
DE
Potomac Capital Investment Corporation
DE
PCI Netherlands Corporation
NV
PCI Queensland Corporation
NV
Kramer Junction Company
CA
KJC Operating Company
CA
Pepco Technologies, LLC (cancelled as of 12/30/2005)
DE
AMP Funding, LLC
DE
RAMP Investments, LLC
DE
PCI Air Management Partners, LLC
DE
PCI Ever, Inc.
DE
Friendly Skies, Inc.
Virgin Islands
PCI Air Management Corporation
NV
American Energy Corporation
DE
PCI-BT Investing, LLC
DE
___________________________________________________________________________________
Potomac Aircraft Leasing Corporation (dissolved as of 12/30/2005)
NV
Potomac Capital Markets Corporation (dissolved as of 12/30/2005)
DE
Edison Place, LLC (cancelled as of 12/30/2005)
DE
Linpro Harmans Land LTD Partnership
MD
Potomac Harmans Corporation (dissolved as of 12/30/2005)
MD
Potomac Nevada Corporation
NV
Potomac Delaware Leasing Corporation
DE
Potomac Equipment Leasing Corporation
NV
Potomac Leasing Associates, LP
DE
Potomac Nevada Leasing Corporation
NV
PCI Engine Trading, Ltd.
Bermuda
Potomac Capital Joint Leasing Corporation
DE
PCI Nevada Investments
DE
PCI Holdings, Inc.
DE
Aircraft International Management Company
DE
PCI-DB Ventures
DE
Potomac Nevada Investment, Inc.
NV
Carbon Composite, LLC (cancelled as of 12/30/2005)
DE
PCI Energy Corporation
DE
Pepco Communications, Inc. (merged into Potomac Capital
Investment Corporation 1/31/2006)
DE
PHI Service Company
DE
Conectiv
DE
Delmarva Power & Light Company
DE & VA
Atlantic City Electric Company
NJ
Atlantic City Electric Company Transition Funding LLC
DE
Conemaugh Fuels, LLC
DE
Keystone Fuels, LLC
DE
Conectiv Properties and Investments, Inc.
DE
DCTC-Burney, Inc.
DE
Burney Biomass Power, LLC
CA
Forest Products, L.P.
DE
Burney Forest Products, A Joint Venture
CA
Conectiv Solutions LLC
DE
ATE Investments, Inc.
DE
King Street Assurance Ltd.
Bermuda
Enertech Capital Partners, L.P.
DE
Enertech Capital Partners II, L.P.
DE
Black Light Power, Inc.
DE
Millenium Account Services, LLC
DE
Conectiv Services, Inc.
DE
Conectiv Plumbing, L.L.C. (dissolved 1/26/2006)
DE
Conectiv Thermal Systems, Inc.
DE
ATS Operating Services, Inc.
DE
Atlantic Jersey Thermal Systems, Inc.
DE
Thermal Energy Limited Partnership I
DE
Atlantic Generation, Inc.
NJ
Vineland Limited, Inc.
DE
___________________________________________________________________________________
Vineland Cogeneration L. P.
DE
Vineland General, Inc.
DE
Pedrick Gen., Inc.
NJ
Project Finance Fund III, L.P.
DE
Cogeneration Partners of America
NJ
Binghamton Limited, Inc.
DE
Binghamton General, Inc.
DE
Conectiv Communications, Inc.
DE
Atlantic Southern Properties, Inc.
NJ
Conectiv Energy Holding Company
DE
ACE REIT, Inc
DE
Conectiv Atlantic Generation, L.L.C.
DE
Conectiv Bethlehem LLC
DE
Conectiv Delmarva Generation, Inc.
DE
Conectiv Pennsylvania Generation, LLC
DE
Conectiv Energy Supply, Inc.
DE
Conectiv Mid Merit, LLC
DE
Energy Systems North East, LLC
DE
Delaware Operating Services Company
DE
PHI Operating Services Company
DE
Tech Leaders II, L.P.
DE
___________________________________________________________________________________
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Numbers 333-123525 and 333-129429) and the Registration Statements on Form S-8 (Numbers 333-96675, 333-121823 and 333-131371) of Pepco Holdings, Inc. of our report dated March 13, 2006 relating to the financial statements, financial statement schedules, management's assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Washington, D.C.
March 13, 2006
___________________________________________________________________________________
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. 333-106209) of Potomac Electric Power Company of our report dated March 13, 2006 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Washington, D.C.
March 13, 2006
___________________________________________________________________________________
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 (Nos. 333-115879 and 333-124331) of Delmarva Power & Light Company of our report dated March 13, 2006 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Washington, D.C.
March 13, 2006
___________________________________________________________________________________
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 Amendment #2 (No. 333-108861) of Atlantic City Electric Company of our report dated March 13, 2006 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Washington, D.C.
March 13, 2006
___________________________________________________________________________________
Exhibit 31.1
CERTIFICATION
I, Dennis R. Wraase, certify that:
1.
I have reviewed this report on Form 10-K of Pepco Holdings, Inc.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 13, 2006
/S/ D. R. WRAASE
Dennis R. Wraase
Chairman of the Board, President
and Chief Executive Officer
___________________________________________________________________________________
Exhibit 31.2
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.
I have reviewed this report on Form 10-K of Pepco Holdings, Inc.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 13, 2006
/S/ JOSEPH M. RIGBY
Joseph M. Rigby
Senior Vice President and
Chief Financial Officer
___________________________________________________________________________________
Exhibit 31.3
CERTIFICATION
I, William J. Sim, certify that:
1.
I have reviewed this report on Form 10-K of Potomac Electric Power Company.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) 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)
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
c)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 13, 2006
/S/ W. J. SIM
William J. Sim
President and Chief Executive Officer
___________________________________________________________________________________
Exhibit 31.4
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.
I have reviewed this report on Form 10-K of Potomac Electric Power Company.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) 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)
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
c)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 13, 2006
/S/ JOSEPH M. RIGBY
Joseph M. Rigby
Senior Vice President and
Chief Financial Officer
___________________________________________________________________________________
Exhibit 31.5
CERTIFICATION
I, Thomas S. Shaw, certify that:
1.
I have reviewed this report on Form 10-K of Delmarva Power & Light Company.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) 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)
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
c)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 13, 2006
/S/ T. S. SHAW
Thomas S. Shaw
President and Chief Executive Officer
___________________________________________________________________________________
Exhibit 31.6
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.
I have reviewed this report on Form 10-K of Delmarva Power & Light Company.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) 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)
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
c)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 13, 2006
/S/ JOSEPH M. RIGBY
Joseph M. Rigby
Senior Vice President and
Chief Financial Officer
___________________________________________________________________________________
Exhibit 31.7
CERTIFICATION
I, William J. Sim, certify that:
1.
I have reviewed this report on Form 10-K of Atlantic City Electric Company.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) 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)
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
c)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 13, 2006
/S/ W. J. SIM
William J. Sim
President and Chief Executive Officer
___________________________________________________________________________________
Exhibit 31.8
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.
I have reviewed this report on Form 10-K of Atlantic City Electric Company.
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) 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)
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
c)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 13, 2006
/S/ JOSEPH M. RIGBY
Joseph M. Rigby
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, Joseph M. Rigby, 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, 2005, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Pepco Holdings, Inc.
March 13, 2006
/S/ D. R. WRAASE
Dennis R. Wraase
President and Chief Executive Officer
March 13, 2006
/S/ JOSEPH M. RIGBY
Joseph M. Rigby
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, William J. Sim, and I, Joseph M. Rigby, 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, 2005, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Potomac Electric Power Company.
March 13, 2006
/S/ W. J. SIM
William J. Sim
President and
Chief Executive Officer
March 13, 2006
/S/ JOSEPH M. RIGBY
Joseph M. Rigby
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, Thomas S. Shaw, and I, Joseph M. Rigby, 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, 2005, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Delmarva Power & Light Company.
March 13, 2006
/S/ T. W. SHAW
Thomas S. Shaw
Chief Executive Officer
March 13, 2006
/S/ JOSEPH M. RIGBY
Joseph M. Rigby
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, William J. Sim, and I, Joseph M. Rigby, 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, 2005, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Atlantic City Electric Company.
March 13, 2006
/S/ W. J. SIM
William J. Sim
President and Chief Executive Officer
March 13, 2006
/S/ JOSEPH M. RIGBY
Joseph M. Rigby
Chief Financial Officer
A signed original of this written statement required by Section 906 has been provided to Atlantic City Electric Company and will be retained by Atlantic City Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.
___________________________________________________________________________________
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the above named registrants and in the capacities and on the dates indicated:
/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, Pepco Holdings)
March 13, 2006
/S/ W. J. SIM
William J. Sim
Director, President and Chief Executive Officer of Pepco and President and Chief Executive Officer of ACE
(Principal Executive Officer of Pepco and ACE)
March 13, 2006
/S/ T. W. SHAW
Thomas S. Shaw
President and Chief Executive Officer of DPL and Director of Pepco, DPL and ACE
(Principal Executive Officer of DPL)
March 13, 2006
/S/ JOSEPH M. RIGBY
Joseph M. Rigby
Senior Vice President and Chief Financial Officer of Pepco Holdings, Pepco, and DPL, Chief Financial Officer of ACE and Director of Pepco, DPL and ACE
(Principal Financial Officer of Pepco Holdings, Pepco, DPL and ACE)
March 13, 2006
/S/ RONALD 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)
March 13, 2006
___________________________________________________________________________________