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 toPHI and its operating subsidiaries. These services are provided pursuant to a service agreement among PHI, PHI Service Company, and the participating operating subsidiaries which has been filed with, and approved by, the SEC under PUHCA. The expenses of the service company are charged to PHI and the participating operating subsidiaries in accordance withcost allocationmethodologies set forth in the service agreement. |
For financial information relating to PHI's segments, see Note (3) Segment Information to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K. This segment information includes a revision of PHI's segments for 2003 and 2002 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 theSecuritiesExchange Act of 1934, as amended (the Exchange Act). Their Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports, 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/index_secfilings.html. |
The following is a description of each of PHI's 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 2004, 2003 and 2002, respectively,PHI's power delivery operations produced61%,55%, and 58% of PHI's consolidated operating revenues and70%,82%and 78%of PHI's consolidated operating income. |
PHI's power delivery business is conducted by its subsidiaries Pepco, DPL and ACE, each of which is a regulated public utility in the jurisdictions in which it serves customers. DPL and ACE conduct their power delivery operations under the tradename Conectiv Power Delivery. In the aggregate, PHI's power delivery business delivers electricity to more than1.8 million customers in the mid-Atlantic region and distributes natural gas to approximately118,000 customers in Delaware. |
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 deliver electricity to end-use customers in the utility's regulated service territory. 2
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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 mid-Atlantic region and the eastern United States. The Federal Energy Regulatory Commission (FERC) has designated a number of regional transmission operators to coordinate the operation of portions of the interstate transmission grid. Pepco, DPL and ACE are all members of PJM Interconnection, LLC (PJM), the regional transmission operator that coordinates the movement of electricity in all or parts of Delaware, Maryland, New Jersey, Ohio, Pennsylvania, Virginia, West Virginia and the District of Columbia. FERC has designated PJM as the sole provider of transmission service in the PJM territory. Any entity that wishes to deliver electricity at any point in PJM's territory must obtain transmission ser vices from PJM at rates approved by FERC. In accordance with FERC rules, Pepco, DPL, ACE and the other 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 member utilities transmission fees approved by FERC. |
In recent months, the PJM wholesale electricity marketplace has expanded substantially with the addition of companies delivering power in large portions of the Midwest, and their associated generation; additional expansion of PJM into Virginia and North Carolina is planned. This expansion is forecast to lower PJM transaction costs through greater administrative efficiencies of scale, and the addition of low-cost Midwest generation to the marketplace is expected to result in a lower average hourly energy price in the PJM market for next-day deliveries. In connection with this expansion, FERC has ordered the elimination of "through-and-out" transmission rates for energy transactions within the combined regional markets of PJM and the Midwest Independent System Operator (MISO), effective December 1, 2004, and has established transitional surcharges in PJM and MISO for the ensuing 16-month period, which are intended to recoup a portion of the "th rough-and-out" transmission revenue no longer collected by certain transmission owners in the combined region. The data underlying this transition charge and various exclusions from the charge are disputed by a majority of the utilities, including Pepco, DPL and ACE, and many other parties, including subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy) and Pepco Energy Services, Inc. (together with its subsidiaries, Pepco Energy Services); any amounts collected prior to FERC's decision are subject to refund. FERC's eventual decision cannot be predicted. |
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,recent legislative and regulatory actionsin 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 b e responsible for the distribution of electricity in their respective service territories, as the result of deregulation, customers in those service territories now are 3
_____________________________________________________________________________ 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 from suppliers 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 below. |
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 andnaturalgas 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'selectricity deliveryoperations 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'selectricity deliveryoperations 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'snaturalgas distribution operations in Delaware are regulated by the DPSC. ACE'selectricity deliveryoperations 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 approximately2 million. As of December 31,2004, Pepco delivered electricity to approximately737,000 customers, as compared to726,000 customers as of December 31,2003. Pepco delivered a total ofapproximately 26,902,000 megawatt hours of electricity in2004, compared to approximately 25,994,000 megawatt hours in2003. In 2004, approximately30% was delivered to residential customers,51% to commercial customers, and19% to United States and District of Columbia government customers. |
Under settlements approved by the MPSC and the DCPSC in connection with the divestiture of its generation assets in 2000, Pepcowas required to provide default electricity supply to customers in Maryland through June2004 4
_____________________________________________________________________________ and to customers in Washington, D.C. through February7, 2005, for which itwas paid established rates set forth in the settlements. Pepco obtained all of the energy and capacity needed to fulfillthese fixed-ratedefault supply obligations in Maryland and Washington, D.C. through January 22, 2005, from an affiliate of Mirant Corporation (Mirant). See Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Relationship with Mirant Corporation." |
Under a settlement approved by the MPSC in April 2003 addressing default supply, also known as Standard Offer Service (SOS), in Maryland following the expiration of Pepco's fixed-rate default supply obligations in July 2004, Pepco is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customersthrough May 2006,andto large commercial customers through May 2005. Pepco also has an obligation to provide service at hourly priced market rates to the largest customers through May 2006. In accordance with the settlement, Pepcopurchases the power supply required to satisfy its marke t ratedefault supply obligation fromwholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the MPSC. Pepcois entitledto recover from itsdefault supply customers thecost of thedefault supplyplus an average margin of approximately $0.002 per kilowatt hour, calculated based on total sales to residential, small, and large commercial Maryland default 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 default supply customers from each customer class and the load taken by such customers ove r the time period. Pepco is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both default supply customers and customers in Maryland who have selected another energy supplier. These delivery rates generally were capped originally through June 2004 as a result of a settlement agreement and the Electric Choice and Competition Act of 1999, and extended through December 31, 2006 pursuant to the MPSC order issued in April 2002 in connection with the merger involving Pepco and Conectiv. |
Under an order issued by the DCPSC in March 2004 addressing default supply in the District of Columbia after the expiration of Pepco's fixed-rate default supply obligations in February 2005, as amended by a DCPSC order issued in July 2004, Pepco's obligation to provide default electricity supply at market rates was extended for up to an additional 76 months for small commercial and residential customers and an additional 28 months for large commercial customers. Pepco purchases the power supply required to satisfy its market rate default supply obligation from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the DCPSC. Subsequent orders issued by the DCPSC provide for Pepco to recover from its default supply customers thecosts associated with the acquisition of the default supply plus administrative charges that are intended to allow Pepco to recover the administrative costs incurred to provide the default electricity supply. These administrative charges include an average margin for Pepco of approximately $0.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial District of Columbia default 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 default supply 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 default supply customers and customers in the District of Columbia who have selected another energy supplier. Assuming no change as a 5
_____________________________________________________________________________ result of the current Pepco distribution rate review case in the District of Columbia (see Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Rate Proceedings"), delivery rates in the District of Columbia generally are capped through July 2007, except with respect to residential low-income customers, for whom rates generally are capped through July 2009. |
For the twelve months ended December 31,2004, Pepco delivered 71% of its load (measured by megawatt hours) to Marylanddefault supply customers, as compared to70% in2003. Pepco delivered 68% of its load to District of Columbiadefault supply customers in 2004, as compared to 52% in 2003. |
DPL |
DPL is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and Virginia and providesnaturalgas 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 corporationin 1979. DPL's electricity distribution service territory covers approximately 6,000 square miles and has a population of approximately1.28 million. DPL's natural gas distribution servic e territory covers approximately 275 square miles and has a population of approximately523,000. As of December 31,2004, DPL delivered electricity to approximately501,000customers and delivered natural gas to approximately118,000 customers, as compared to 493,000electricity customers and117,000 natural gas customers as of December 31,2003. |
In2004, DPL delivered a total ofapproximately 13,902,000 megawatt hours of electricity to itscustomers, as compared toa total of approximately 14,032,000 megawatt hours in 2003. In 2004, approximately 39% of DPL's retail electricity deliveries were to residential customers,38% were to commercial customers and23% were to industrial customers. In 2004, DPL delivered approximately 21,600,000 Mcf (one thousand cubic feet) ofnaturalgas to retail customers in its Delaware service territory, as compared to approximately 22,900,000 Mcf in 2003. In 2004, approxim ately 40% of DPL's retail gas deliveries were sales to residential customers, 26% were to sales commercial customers, 5% were to sales industrial customers, and 29% were sales to customers receiving a transportation-only service. |
Under a settlement approved by the DPSC, DPL is required to provide default electricity supply, or SOS, to customers in Delaware through April 2006.DPL is paid for default supply to customers in Delaware at fixed rates established in thesettlement. DPL obtains all of the energyneeded to fulfill itsdefault supply obligationsin Delawareunder a supply agreement withits affiliate Conectiv Energy, which terminates in May 2006. DPL does not make any profit or incur any loss on the supply component of thedefault power that it delivers to its Delaware customers. DPL is paid tariff delivery ratesfor the delivery of electricity over its transmission and distribution facilities to both default supply 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 February 22, 2005, the DPSC voted to approve an SOS process that will allow a Wholesale Standard Offer Service Model with DPL as the SOS Supplier. Issues including the length of this extension and any margin that DPL may be able to earn and retain in 6
_____________________________________________________________________________ conjunction with this service have been deferred for further discussion and will be decided by the DPSC at a later date. A written DPSC order documenting this decision is expected sometime in March or April 2005. |
Under a settlement approved by the MPSC, DPLwas required to provide default electricity supply to non-residential customers in Marylandthrough May 2004 and to residential customers in Marylandthrough June 2004 for which it was paid established rates set forth in the settlement. DPL obtained all of the energy needed to fulfill its fixed-rate default supply obligations in Maryland under a supply agreement with Conectiv Energy. |
Under a settlement approved by the MPSC in April 2003 addressing default supply in Maryland following the expiration of DPL's fixed-rate default supply obligations in 2004, DPL is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customersthrough May 2006, and to large commercial customers through May 2005. In accordance with the settlement, DPLpurchases the power supply required to satisfy its market ratedefault supply obligations 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 itsdefault supply customers the costsof thedefault supplyplus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, small, and large commercial Maryland default 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 default supply 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 default supply customers and customers in Maryland who have selected another energy supplier. These delivery ra tes generally are capped through December 2006. |
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. A prior agreement, also with Conectiv Energy, terminated effective December 31, 2004. The current contract was entered into after conducting a competitive bid procedure and Conectiv Energy was the lowest bidder to provide wholesale power supply for DPL's Virginia default service customers. The new supply agreement commenced January 1, 2005 and expires in May 2006. On October 26, 2004, DPL filed an application with the VSCC for approval to increase the rates that DPL charges its Virginia default service customers to allow it to recover its costs for power under the new supply agreement plus an administrative charge and a margin. |
A VSCC order dated November 17, 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. Therefore, the November 17 order also directed the parties to file memoranda concerning whether administrative costs and a margin are properly recovered through a fuel clause mechanism. Memoranda were filed by DPL, the VSCC Staff and Virginia's Office of Attorney General. The VSCC ruled on January 18, 2005, that the administrative charge and margin are base rate items not recoverable through a fuel clause. No appeal is planned regarding this 7
_____________________________________________________________________________ filing. A settlement resolving all other issues and making the interim rates final was filed on March 4, 2005, contingent only on possible future adjustment depending on the result of a related proceeding at FERC. A hearing is scheduled for March 16, 2005, and the VSCC is expected to approve the settlement. |
DPL is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both Virginia 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 default supply customers represented 80% of total delivered megawatt hours for the twelve months ended December 31,2004,as compared to96% in2003.In Delaware, DPL sales to default supply customers represented 89% of total delivered megawatt hours for the twelve months ended December 31, 2004, as compared to87% in2003, and DPL sales to Virginia default supply customers represented 100% of total delivered megawatt hoursin both2004 and2003. |
DPL also provides regulated natural gas supply and distributionserviceto customers in its Delaware natural gas service territory. Large and medium volume commercial and industrialnaturalgas customers may purchasenaturalgas either from DPL or from other suppliers. DPL uses its natural gas distribution facilities to transportgas 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 forresale to its sales service customers from marketers and producers through a combination oflong-term agreements andnext day delivery arrangements. For the twelve months ended December 31,2004, DPL supplied 71.8% of the natural gas that it delivered, compared to 71.6% in 2003. |
ACE |
ACE is engaged in the generation, transmission and distribution of electricity in 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 approximately998,000. As of December 31,2004, ACE delivered electricity to approximately524,000 customers in its service territory, as compared toapproximately 521,000 customers as of December 31,2003. ACE delivered a total ofapproximately 9,874,000 megawatt hours of electricity in2004 compared t o approximately 9,643,000 megawatt hours in 2003. In 2004,approximately44% was delivered to residential customers,44% was delivered to commercial customers and12% was delivered to industrial customers. |
Customers in New Jersey who do not chooseanother supplier receive default electricity supply from suppliers selected through auctions approved by the NJBPU. ACE has entered into supply agreements with thedefault suppliers, including Conectiv Energy, on behalf of the default supply customers in its service territory. Each of these agreements requires thedefault supplier to provide a portion of thedefault supply customer load with full requirements service, consisting of power supply and transmission service. ACE delivers thedefault supply tocustomers. ACE is paid tariff rates established by the NJBPU that compensate it f or thecost of obtaining 8
_____________________________________________________________________________ the default supply. ACE does not make any profit or incur any loss on the supply component ofthe default power it provides to customers. |
ACE is paid tariff delivery rates for thedelivery of electricity over its transmission and distribution facilities toboth default supply customers andcustomers in its service territory who have selectedanother energy supplier. ACE currently is involved in a base rate proceeding in which it has requested an increase in its delivery rates. See Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Rate Proceedings." |
ACE sales to New Jersey default supply customers represented 76% of total delivered megawatt hours for the twelve months ended December 31,2004,as compared to91% in2003. |
As of December 31,2004, ACE ownedone electric generatingfacility, the B.L. England generating facility, and interests in two facilities jointly owned with other companies. The combined generating capacity of these facilities is555 megawatts. See Item 2 -- "Properties."ACE also has contracts with non-utility generators under which ACE purchased3.9 million megawatt hours of power in2004. ACE sells the electricity produced by the generating facilities and purchased under the non-utility generator contracts in the wholesale market administered by PJM. During2004, ACE's generation and wholesale ele ctricity sales operations produced approximately 23.2% of ACE's operating revenue. |
On March 1, 2004, ACE transferred ownership of the 185 megawatt capacity Deepwater generating facility to Conectiv Energy. |
In April 2004, PHI, Conectiv and ACE entered into a preliminary settlement agreement with the New Jersey Department of Environmental Protection (NJDEP) and the Attorney General of New Jersey that provides that, contingent upon the receipt of necessary approvals from applicable regulatory authorities and the receipt of permits to construct certain electric transmission facilities in southern New Jersey, ACE will permanently cease operation of the B.L. England generating facility by December 15, 2007. See Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Preliminary Settlement Agreement with the NJDEP." |
In 2002, ACE and the City of Vineland, New Jersey entered into a condemnation settlement agreement which provided for ACE to sell the electric distribution facilities within the city limits, and the approximately 5,400 related customer accounts (to which ACE delivered approximately 103,000 megawatt hours of power in 2003), for $23.9 million. The proceedswere received in installmentsand the sale was completed in the second quarter of 2004. |
ACE Funding |
ACE Funding was incorporated in New Jersey in 2001 by ACE. Under New Jersey law, ACE (or a financing entity) is permitted to securitize authorized portions of ACE's recoverable stranded costs through the issuance of bonds (Transition Bonds) and to collect from its customers charges sufficient to fund principal and interest payments on the Transition Bonds and related taxes, expenses and fees. The right to collect the Transition Bond charges is known as Bondable Transition Property. The sole purpose for the establishment of ACE Funding is to issue Transition Bonds, the proceeds of 9
_____________________________________________________________________________ which are transferred to ACE in exchange for the related Bondable Transition Property. |
Competitive Energy |
PHI's competitive energy business provides non-regulated generation, marketing and supply of electricity andnaturalgas, and related energy management services, in the mid-Atlantic region. In2004, 2003 and 2002, respectively, PHI's competitive energy operations produced 50%, 55%and 48%of PHI's consolidated operating revenues. In 2004 and 2002, respectively, PHI's competitive energy operations produced 19% and 12% of PHI's consolidated operating income. In2003, PHI's competitive energy operations incurred an operating loss equal to 19% of PHI's consolidated operating income. PHI's competitive energy operations are conducted through subsidiarie s 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-term bilateral contracts. Among its bilateral contractsare the power supplyagreements under which Conectiv Energy sells to DPL itsdefault electricity supply for distribution to customers in Delaware and Virginia. Conectiv Energy also sellsdefault supply to customers in ACE's service territory and to otherdefault supply customers in New Jersey. Other than itsdefault supply sales, Conectiv Energy does not currently participate in the retail competitive power sup ply market. Conectiv Energy obtains the electricity required to meet its power supply obligations from its owngenerating plants, from bilateral contract purchases from 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 for longer periods of time and for more weeks a year than peak-load plants. Conectiv Energy's most recently added mid-merit plant, a combined cycle plant located in Bethlehem, Pennsylvania with a generating capacity of 1,092 megawatts,became fully operational in June 2004. On March 1, 2004, Conectiv Energy received ownership of the 185 megawatt capacity Deepwater generating facility from ACE. As of December 31, 2004, Conectiv Energy owned and operated mid-merit plants with a combined2,689 megawatts of capacity, peak-load plants with a combined669 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-term bilateral contracts with other market participants. 10
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Conectiv Energy actively engages in commodity risk management activities to reduce its financial exposure to changes in the value of its assets andobligations due to commodity price 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. Conectiv Energy also manages commodity risk with contracts that are not classified as derivatives. Conectiv Energy has two primary risk management objectives: to 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 spread between its POLR, SOS, and BGS load supply contracts in or der 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. |
Conectiv Energy's goal is to hedge economically 75% of both the expected power output of its generation facilities and the expected costs of fuel used to operate those facilities. The economic hedge goals are approved by PHI's Corporate Risk Management Committee and may change from time to time based on market conditions. However, the actual level of hedging coverage may vary from this goal. InJuly 2003, Conectiv Energy entered into an agreementwith an international investment banking firm consisting of a series of energy contracts designed to more effectively hedge approximately 50% of Conectiv Energy's generation output and approximately 50% of its supply obligations, with t he intention of providing Conectiv Energy with a more predicable earnings stream during the term of the agreement, which expires in May 2006. The agreement consists of two major components: (i) a fixed price energy supply hedge that is used to reduce Conectiv Energy's financial exposure under its currentdefault supply commitment to DPLin Delaware through May 2006 and Virginia through December 2004and (ii) a generation off-take agreement under which 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). |
Pepco Energy Services |
Pepco Energy Services sells retail electricity and natural gas to residential, commercial, industrial and governmental customers in the mid-Atlantic region. Pepco Energy Services also provides integrated energy managementservices 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, fuel management, and home service agreements for residential customers. 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 reducethe financial exposureto changes in the value of its supply contracts and sales commitments due to commodity priceand volume fluctuations. Certain of these risk management activities are conducted 11
_____________________________________________________________________________ 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 commitmentsin 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 Servicesgenerally does not hedge the output of these plants. |
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 retailenergy 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 s ervices 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 andnaturalgas 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 generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Energy management services generally are not seasonal. |
Other Non-Regulated |
This component of PHI's business is conducted through its subsidiary Potomac Capital Investment Corporation (PCI). PHI's subsidiary Pepco Communications, Inc. (Pepcom) ceased operations in December 2004 following the sale of its principal asset described below. |
PCI |
PCI manages a portfolio of financial investments, whichconsistsprimarilyof energy leveraged leases. These transactions involve PCI's purchase and leaseback of utility assets located outside of the United States.In 2003 PCI discontinued making new investments, and in 2004 sold its three remaining aircraft. For additional information relating to PCI's energy leveraged leases, see Note (4) to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K. |
Pepcom |
In December 2004, Pepcom sold its 50% interest in Starpower Communications, LLC (Starpower) for $29 million in cash to RCN Telecom Services of Washington, D.C., Inc., a wholly owned subsidiary of RCN 12
_____________________________________________________________________________ Corporation which owned the other 50% interest in Starpower. Following the completion of the sale, Pepcom has no remaining investments. |
EMPLOYEES |
As of December 31, 2004, PHI had 5,592 employees, including 1,606 employed by Pepco, 910 employed by DPL, 647 employed by ACE and 1,686 employed by PHI Service Company. The balance were employed by PHI's competitive energy and other non-regulated businesses. |
ENVIRONMENTAL MATTERS |
PHI, through its subsidiaries, is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. PHI's subsidiaries may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. PHI currently estimates that capital expenditures for environmental control facilities by its subsidiaries will be $6.6 million in 2005 and $5.7 million in 2006. However, the actual costs of environmental compliance may be materially different from these estimates depending on t he 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. All 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 from May to September of each year. |
The New Jersey Department of Environmental Protection (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 13
_____________________________________________________________________________ pollution control technology and obtain offsets in some circumstances when those sources undergo a "major modification," as defined in the regulations. During 2002, ACE participated in preliminary discussions with EPA and NJDEP on this matter, without successful resolution. |
On October 27, 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. |
PHI does not believe that any of its subsidiaries have violated NSR requirements, but cannot predict the consequences of the EPA/NJDEP inquiries on B.L. England or Deepwater generating plant operations. |
In an effort to address NJDEP's concerns regarding ACE's compliance with NSR requirements at the B.L. England generating facility, on April 26, 2004, PHI, Conectiv and ACE entered into a preliminary settlement agreement with NJDEP and the Attorney General of New Jersey. The preliminary settlement agreement outlines the basic parameters for a definitive agreement to resolve ACE's alleged NSR liability, if any, at B.L. England and various other environmental issues involving ACE and Conectiv Energy facilities in New Jersey. While the preliminary settlement agreement does not resolve the EPA inquiry, it, among other things, provides that: |
The preliminary settlement agreement also provides that the parties will work toward a consent order or other final settlement document that reflects the terms of the preliminary settlement agreement. ACE, Conectiv and PHI continue to negotiate with the NJDEP the terms of a consent order or other final settlement document. |
On May 4, 2002, ACE and Conectiv Energy entered into an administrative consent order 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 administrative consent order (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 December 2003, the EPA proposed regulations under the CAA that would require reductions in emissions of mercury from coal-fired power plants and nickel from oil-fired power plants through implementation of Maximum Achievable Control Technology (MACT) standards. As an alternative, EPA proposed a "cap and trade" program for mercury emissions from coal-fired plants and limitations on nickel emissions from oil-fired plants. In addition, EPA's Clean Air Interstate rule, released on March 10, 2005, imposes additional reductions of SO2 and NOx emissions from electric generating units in 28 Eastern states and the District of Columbia. 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. |
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On December 6, 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 proposed mercury MACT standard 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 stringent standards regulating emissions of NOx, SO2 and 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 appli cable to that particular unit. Contingent upon receipt of necessary approvals from the NJBPU, PJM, NERC/FERC and other regulatory authorities and the receipt of permits to construct certain transmission facilities in southern New Jersey, ACE plans to shut down the B.L. England generating 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 any final EPA mercury rule that is promulgated. Conectiv Energy is investigating what, if any, capital or operational improvements are needed at the Deepwater generating facilityin order to comply with NJDEP's final mercury regulations and will analyze the need for capital or operational improvements at the Deepwater generating facility for compliance with EPA's mercury requirements after EPA promulgates a final rule. At this time, Conectiv Energy anticipates tha t activated carbon injection will be needed at Deepwater to meet these regulations at a cost of approximately $300,000. |
On June 29, 2004, New Jersey enacted legislation that imposes a tax on emissions of certain specifically identified toxic substances in New Jersey. In accordance with the legislation, an annual surcharge of $500,000 each will be imposed for ACE's B.L. England facility and for Conectiv Energy's Deepwater facility. |
On September 20, 2004, NJDEP proposed regulations regarding the further control of NOx emissions from combustion sources. These regulations would significantly reduce the NOx limit on B.L. England's diesel generators. These regulations, if adopted as proposed, may require the installation of pollution control devices on these units at a significant capital cost. |
On October 18, 2004, NJDEP proposed regulations that would classify carbon dioxide (CO2) as an air contaminant and enable NJDEP potentially to regulate CO2 emissions from power plants and other sources. These regulations, if adopted as proposed, could limit or control emissions of CO2 from ACE and Conectiv Energy facilities in New Jersey in the future. |
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. |
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On July 9, 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 will require at each facility, if any, will not be known until each facility completes various studies in accordance with a schedule to be established in each permit. 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 the Delaware Department of Natural Resources and Environmental Control (DNREC). The NPDES permit for Conectiv Energy's Edge Moor Power Plant expired on October 30, 2003, but has been administratively extended through the submission of 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 are being conducted to determine the extent of expenditures necessary to modify cooling water intake structures in order to comply with EPA's CWA Section 316(b) performance-based standards. PHI cannot predict the extent of these expenditures until the site-specific studies are completed. |
Under the New Jersey Water Pollution Control Act, NJDEP implements regulations, administers the 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 are protective of the environment. The studies required by Deepwater's NPDES 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 on February 24, 2005. Consistent with EPA's CWA Section 316(b) regulations, B.L. England's renewal permit requires ACE to submit a Proposal for Information Collection by September 7, 2005 and complete a Comprehensive Demonstration Study within three and one-half years. In addressing CWA Section 316(b) requirements for B.L. England, the April 26, 2004 preliminary settlement agreement with NJDEP provides that ACE will submit all federally required studies and complete construction of all facilities necessary to satisfy the EPA's new cooling water intake structure regulations in accordance with a schedule established by the NJDEP in the renewal of the NJPDES permit for the B.L. England facility. The NJDEP will take 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 has 17
_____________________________________________________________________________ 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 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 curren tly 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 -- Capital Resources and Liquidity -- Capital Requirements -- Environmental Remediation Obligations." |
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Item 2. PROPERTIES |
Generation Facilities |
The following table identifies the electric generation facilities owned by PHI's subsidiaries. |
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The above 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, 2004 consisted of approximately 3,502 transmission circuit miles of overhead lines, 155 transmission circuit miles of underground cables, 22,686 distribution circuit miles of overhead lines, and 18,649 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, 1,728 pipeline miles of gas distribution mains, and 1,268gas 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 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) to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K. |
Item 3. LEGAL PROCEEDINGS |
Pepco Holdings |
The legal proceedings for Pepco Holdings consist solely of those of its subsidiaries, as described below. |
GENERAL LITIGATION |
Pepco |
Asbestos |
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 20
_____________________________________________________________________________ brought into these cases on a theory of premises liability. Under this theory, plaintiffs argue 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. Of the approximately 250 remaining asbestos cases pending against Pepco, approximately 85 cases were filed after December 19, 2000, and have been tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement. |
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 condition. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco's and PHI's results of operations. |
DPL and Conectiv Energy |
Enron |
On December 2, 2001, Enron North America Corp. and several of its affiliates (collectively, Enron) filed for protection under the United States Bankruptcy Code. In December 2001, DPL and Conectiv Energy terminated all energy trading transactions under various agreements with Enron. In late January 2003, after several months of discussions between the parties concerning the amount owed by DPL and Conectiv Energy, Enron filed an adversary complaint against Conectiv Energy in the Bankruptcy Court for the Southern District of New York. The complaint sought, among other things, damages in the amount of approximately $11.7 million. |
On June 3, 2004, the Bankruptcy Court approved a settlement among Enron, Conectiv Energy and DPL pursuant to which Conectiv Energy paid Enron an agreed settlement amount that was less than the $11.7 million damages Enron sought and the parties released all claims against each other. Conectiv Energy had previously established a reserve in an amount equal to the agreed settlement payment. Accordingly, the settlement did not have an effect on earnings. |
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 21
_____________________________________________________________________________ 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. |
Pepco and DPL |
In May 2004, the U.S. Department of Justice (DOJ) invited DPL to enter into pre-filing negotiations in connection with DPL's alleged liability under CERCLA at the Diamond State Salvage site in Wilmington, Delaware. In the context of the negotiations, DOJ informed DPL that DPL is a de minimis party at the site. In February 2005, DPL entered into a de minimis consent decree with the United States which, if approved by the U.S. District Court, would require DPL to pay $144,000 as reimbursement of the government's response costs, resolve DPL's alleged liability, and provide DPL a covenant not to sue from the United States and protection from third-party claims for contribution. |
In July 2004, DPL entered into an Administrative Consent Order with the Maryland Department of the Environment (MDE) to perform a Remedial Investigation/Feasibility Study (RI/FS) to further identify the extent of soil, sediment and ground and surface water contamination related to former manufactured gas plant (MGP) operations at the Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The costs for completing the RI/FS for this site are approximately $300,000, approximately $50,000 of which will be expended in 2005. The costs of cleanup resulting from the RI/FS will not be determinable until the RI/FS is completed and an agreement with respect to cleanup is reached with the MDE. DPL expects to complete the RI/FS in the first quarter of 2005. |
In October 1995, each of Pepco and DPL received notice from EPA that it, along with several hundred other companies, might be a PRP in connection with the Spectron Superfund Site in Elkton, Maryland. The site was operated as a hazardous waste disposal, recycling and processing facility from 1961 to 1988. |
In August 2001, Pepco entered into a consent decree for de minimis parties with EPA to resolve its liability at this site. Under the terms of the consent decree, which was approved by the U.S. District Court for the District of Maryland on March 31, 2003, Pepco made de minimis payments to the United States and a group of PRPs. In return, those parties agreed not to sue Pepco for past and future costs of remediation at the site and the United States will also provide protection against third-party claims for contributions related to response actions at the site. The consent decree does not cover any damages to natural resources. However, Pepco believes that any liability that it might incur due to natural resource damage at this site would not have a material adverse effect on its financial condition or results of operations. In February 2003, the EPA informed DPL that it will have no future liability for contribution to the remediation of the site. |
In the early 1970s, both Pepco and DPL sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In 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. 22
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In October 1994, an RI/FS including a number of possible remedies was submitted to the EPA. In December 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 June 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs to conduct the design and actions called for in its decision. On May 12, 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 2, 2003, the Bankruptcy Court confirmed a Reorganization Plan that incorporates the terms of a settlement among the debtors, the United States and a group of utility PRPs including Pepco. Under the settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site. |
As of December 31, 2004, Pepco had accrued $1.7 million to meet its liability for a site remedy. At the present time, it is not possible to estimate the total extent of EPA's administrative and oversight costs or the expense associated with a site remedy ultimately implemented. However, Pepco believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations. |
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 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 condition or results of operations. |
On April 7, 2000, approximately 139,000 gallons of oil leaked from a pipeline at a generation station that was owned by Pepco at Chalk Point Generating Station in Aquasco, Maryland. The pipeline was operated by Support Terminals Services Operating Partnership LP (ST Services), an unaffiliated pipeline management company. The oil spread from Swanson Creek to the Patuxent River and several of its tributaries. The area affected covers portions of 17 miles of shoreline along the Patuxent River and approximately 45 acres of marshland adjacent to the Chalk Point property. |
In December 2000, the Department of Transportation, Office of Pipeline Safety, Research and Special Programs Administration (OPS) issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV). The NOPV alleged various deficiencies in compliance with regulations related to spill reporting, operations and maintenance of the pipeline and record keeping, none of which relate to the cause of the spill. The NOPV was issued to both Pepco and ST Services and proposed a civil penalty in the amount of $674,000. On June 2, 2004, the OPS issued a Final Order regarding the NOPV in this matter. The Final Order assessed a total fine of $330,250, with $256,250 of that amount assessed jointly against Pepco and ST Services and the remaining $74,000 assessed solely against ST Services. ST Services subsequently filed a Petition for Reconsideration. All penalties were stayed pending the outcome of the Petition for Rec onsideration. On February 9, 2005, OPS issued a Decision on the Petition for Reconsideration that affirmed the Final Order. Pepco's share of the $330,250 penalty assessed pursuant to the Final Order amounts to $128,125. |
ACE |
In June 1992, EPA identified ACE as a potentially responsible party (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 23
_____________________________________________________________________________ liability is limited to 0.232 percent of the aggregate remediation liability and thus far ACE has made contributions of approximately $105,000. Based on information currently available, ACE may be required to contribute approximately an additional $100,000. ACE believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations. |
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 administrative consent order 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. The results of groundwater monitoring over the first year of this ground water sampling plan will help to determine the extent of post-remedy operation and maintenance costs. 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 may be required to contribute approximately an additional $626,000. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial condition or results of operations. |
In an effort to address NJDEP's concerns regarding ACE's compliance with New Source Review (NSR) requirements at B.L. England, on April 26, 2004, PHI, Conectiv and ACE entered into a preliminary settlement agreement with NJDEP and the Attorney General of New Jersey. The preliminary settlement agreement outlines the basic parameters for a definitive agreement to resolve ACE's NSR liability at B.L. England and various other environmental issues at ACE and Conectiv Energy facilities in New Jersey. Among other things, the preliminary settlement agreement provides that: |
The decrease of $565.4 million in Conectiv Energy's fuel, purchased energy and other services cost of sales is broken down as follows: |
Merchant Generation increased by $87.6 million mainly due to an increase of $109.9 million primarily due to higher fuel costs (approximately 7% higher). This increase was partially offset by a $22.3 million decrease from the implementation of EITF 03-11 on January 1, 2004. 43
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POLR Load Service decreased by $292.7 million partially due to a change in power scheduling procedures by Conectiv at PJM resulting in a $154.3 million decrease and a decrease of approximately $187.9 million that related to the implementation of EITF 03-11 on January 1, 2004. This decrease was partially offset by an increase in hedging activity. |
Power, Oil and Gas Marketing Services and Other decreased by $360.3 million due to the expiration of some large New Jersey Basic Generation Service contracts in 2003. |
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 $32.1 million to $799.9 million in 2004 from $767.8 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, (iv) $12.8 million severance costs, partially offset by $10.6 million incremental storm costs primarily related to one time charges as a result of 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 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 $28.9 million to $302.8 million in 2004 from $273.9 million in 2003. This increase primarily resulted from a $30.1 million increase attributable to the Power Delivery business due to pass-throughs of $33.9 million higher county surcharge and $3.6 million higher gross receipts/delivery taxes (offset in Regulated T&D Electric Revenue), partially offset by $9.5 million lower property tax expense due to true-ups recorded in 2004. |
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 44
_____________________________________________________________________________ the recovery of these costs are reset annually and the rates will vary year to year. On ACE's balance sheet a regulatory asset includes an under-recovery of $99.4 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 impairment. |
Gain on Sale 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 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) |
PHI's other expense (which is net of other income) decreased $88.0 million to $341.0 million in 2004, from $429.0 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 that was recorded during 2003, compared to an additional pre-tax impairment charge of $11.2 million that was recorded during the second quarter of 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 40% 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 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. 45
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The results of operations discussion below is for the year ended December 31, 2003 compared to the year ended December 31, 2002. |
Revised Segment Presentation |
In accordance with the provisions of SFAS No. 131, results for the years ended December 31, 2003 and 2002 have been revised to conform to the 2004 segment presentation. This was required by Statement of Financial Accounting Standards (SFAS) No. 131 "Disclosures about Segments of an Enterprise and Related Information," because Pepco Holdings' management identified its operating segments at January 1, 2004 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Prior to January 1, 2004, Pepco Holdings' Power Delivery business consisted of two operating segments, Pepco and Conectiv Power Delivery. However, with the continued integration of the Power Delivery businesses, effective January 1, 2004 these two businesses represented a single operating segment. Additionally, effective January 1, 2004, PHI transferred several operating businesses from one operating segment to another in order to better align their operations going forward. |
Lack of Comparability of 2003 and 2002 Operating Results |
The accompanying results of operations for the year ended December 31, 2003 include Pepco Holdings' and its subsidiaries' results for the full year. Because of merger accounting that was used to record Pepco's acquisition of Conectiv, the results of operations for 2002 include the results of Pepco and its pre-merger subsidiaries (PCI and Pepco Energy Services) for the entire year consolidated with the results of Conectiv and its subsidiaries starting on August 1, 2002, the date the merger was completed. Accordingly, the results of operations for 2003 and 2002 are not comparable. |
Operating Revenue |
PHI's operating revenue increased by $2,946.8 million to $7,271.3 million in 2003, from $4,324.5 million in 2002. This increase was primarily due to an increase in operating revenue of $1,497.2 million at Power Delivery, an increase of $1,645.7 million at Conectiv Energy, and an increase of $260.5 million at Pepco Energy Services. Intercompany revenues that are eliminated in consolidation are included as part of business segment operating revenues. |
The $1,497.2 million increase in Power Delivery's operating revenue for 2003 primarily resulted from the fact that PHI recognized $2,489.7 million in revenue from Conectiv Power Delivery in 2003 (full year) vs. $997.4 million during 2002 (post August 1, 2002 merger date operations), an increase of $1,492.3 million. Additionally, Pepco's operating revenues increased by $14.1 million in 2003. The $14.1 million increase in Pepco's operating revenue in 2003 resulted from the following: |
Delivery revenue increased by $18.5 million for the year ended December 31, 2003. This increase results from a $19.2 million increase from a fuel tax pass through, partially offset by $.7 million decrease in Delivery revenue (revenue Pepco receives for delivering energy to its customers). The $.7 million decrease results from a .6% decrease in delivered kilowatt-hour sales. 46
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Standard offer service (SOS) revenue (revenue Pepco receives for the procurement of energy by Pepco for its SOS customers) increased by $4.2 million for the year ended December 31, 2003 due to colder winter weather as heating degree days increased by 12.2%, offset by milder summer weather as cooling degree days decreased by 30.2%. |
Pepco's retail access to a competitive market for generation services was made available to all Maryland customers on July 1, 2000 and to D.C. customers on January 1, 2001. As of December 31, 2003, 14% of Pepco's Maryland customers and 11% of its D.C. customers had chosen alternate suppliers. These customers accounted for 912 megawatts of load in Maryland (of Pepco's total load of 3,439) and 970 megawatts of load in D.C. (of Pepco's total load of 2,269). As of December 31, 2002, 16% of Pepco's Maryland customers and 13% of its D.C. customers had chosen alternate suppliers. These customers accounted for 1,175 megawatts of load in Maryland (of Pepco's total load of 3,369) and 1,140 megawatts of load in D.C. (of Pepco's total load of 2,326). |
Pepco's other revenue decreased $8.6 million primarily due to lower capacity (megawatts) available to sell, lower capacity market rates and restructuring in the PJM market. |
The $1,645.7 million increase in Conectiv Energy's operating revenue during 2003 resulted from the fact that PHI recognized $2,859.0 million in revenue in 2003 (full year) vs. $1,213.3 million during 2002 (post August 1, 2002 merger date operations). |
The increase in Pepco Energy Services' operating revenue during 2003 of $260.5 million was primarily due to growth in its commodity business from sales of electricity and natural gas due to higher volumes which resulted from more commercial and industrial customers being served and higher prices due to wholesale commodity market conditions. In 2003, wholesale and retail megawatt hour sales increased by approximately 16% and wholesale and retail dekatherm sales increased by approximately 19%. |
Operating Expenses |
Fuel and Purchased Energy and Other Services Cost of Sales |
PHI's fuel and purchased energy and other services cost of sales increased by $2,400.8 million to $5,202.6 million in 2003 from $2,801.8 million in 2002. This increase was primarily due to an increase in Power Delivery of $1,005.8 million, an increase in Conectiv Energy of $1,598.4 million, and an increase in Pepco Energy Services of $255.1 million. Intercompany fuel purchases that are eliminated in consolidation are included in business segment fuel purchases. |
The $1,005.8 million increase in Power Delivery's fuel and purchased energy and other services cost of sales for 2003 primarily resulted from the fact that PHI recognized $1,610.5 million in fuel and purchased energy and other services cost of sales from Conectiv Power Delivery in 2003 (full year) vs. $641.2 million during 2002 (post August 1, 2002 merger date operations), an increase of $969.3 million. Additionally, Pepco's fuel and purchased energy increased by $29.8 million in 2003. The $29.8 million increase in Pepco's fuel and purchased energy in 2003 resulted from the recording of a $14.5 million reserve to reflect a potential exposure related to a pre-petition receivable from Mirant Corp., for which Pepco filed a creditor's claim in bankruptcy proceedings and from $15.3 million from higher SOS costs. 47
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The $1,598.4 million increase in Conectiv Energy's fuel and purchased energy and other services cost of sales for 2003 primarily resulted from the fact that PHI recognized $2,695.6 million in fuel and purchased energy and other services cost of sales from Conectiv Energy in 2003 (full year) vs. $1,097.2 million during 2002 (post August 1, 2002 merger date operations), an increase of $1,598.4 million. |
The increase in Pepco Energy Services' fuel and purchased energy and other services cost of sales during 2003 of $255.1 million primarily resulted from growth in its retail commodity business for sales of electricity and natural gas due to higher volumes which resulted from more commercial and industrial customers being served and higher prices due to wholesale commodity market conditions. |
Other Operation and Maintenance |
PHI's other operation and maintenance increased by $243.9 million to $767.8 million in 2003 from $523.9 million in 2002. This increase was primarily due to an increase in Power Delivery of $212.7 million and an increase in Conectiv Energy of $55.4 million. The $212.7 million increase in Power Delivery's other operation and maintenance for 2003 primarily resulted from the fact that PHI recognized $394.9 million in other operation and maintenance from Conectiv Power Delivery in 2003 (full year) vs. $146.3 million during 2002 (post August 1, 2002 merger date operations), an increase of $248.6 million. |
Depreciation and Amortization |
PHI's depreciation and amortization increased by $182.3 million to $422.1 million in 2003 from $239.8 million in 2002. This increase was primarily due to an increase in Power Delivery of $147.0 million and an increase in Conectiv Energy of $26.8 million. The $147.0 million increase in Power Delivery's depreciation and amortization for 2003 primarily resulted from the fact that PHI recognized $186.2 million in depreciation and amortization from Conectiv Power Delivery in 2003 (full year) vs. $62.8 million during 2002 (post August 1, 2002 merger date operations), an increase of $123.4 million. Additionally, Pepco's depreciation and amortization increased by $23.2 million in 2003 due to software amortization. |
Other Taxes |
PHI's other taxes increased by $48.3 million to $273.9 million in 2003 from $225.6 million in 2002. This increase was primarily due to an increase in Power Delivery of $44.4 million. The $44.4 million increase in Power Delivery's other taxes for 2003 primarily resulted from the fact that PHI recognized $59.7 million in other taxes from Conectiv Power Delivery in 2003 (full year) vs. $24.8 million during 2002 (post August 1, 2002 merger date operations), an increase of $34.9 million. Additionally, Pepco's other taxes increased by $9.1 million in 2003 due to higher fuel taxes. |
Deferred Electric Service Costs |
PHI's deferred electric service costs increased by $5.2 million in 2003 due to the net under-recovery associated with New Jersey NUGs, MTC and other restructuring items. 48
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Impairment Losses |
The $64.3 million in impairment losses in 2003 consists of charges of $53.3 million for Conectiv Energy CT contract cancellation and write downs and $11.0 million related to a PCI aircraft write-down. |
Gain on Sale of Assets |
The $68.8 million gain on sale of assets is recorded net against operating expenses and represents the gain on the sale of PHI's office building in 2003 which was owned by PCI. |
Other Income (Expenses) |
PHI's other expenses increased by $238.6 million to $429.0 million in 2003 from $190.4 million in 2002. This increase was primarily due to an increase in other expenses of $57.6 million recognized at Power Delivery, an increase of $99.7 million in Other Non Regulated, and an increase of $65.0 million in Corporate and Other. |
The $57.6 million increase in Power Delivery's other expenses for 2003 primarily resulted from the fact that PHI recognized $82.4 million in expenses from Conectiv Power Delivery in 2003 (full year) vs. $38.1 million in 2002 (post August 1, 2002 merger date operations), an increase of $44.3 million. |
The $99.7 million increase in Other Non Regulated operating expense for the year ended 2003 primarily includes an impairment charge of $102.6 million ($66.7 million after-tax) related to PHI's investment in Starpower. Because of the distressed telecommunications market and the changed expectations of Starpower's future performance, PHI determined that its investment in Starpower was impaired at December 31, 2003. |
"Corporate and other" in 2003 primarily represents unallocated PHI capital costs, incurred as a result of long-term acquisition financing entered into in late 2002. |
Income Tax Expense |
Pepco Holdings effective tax rates in 2003 and 2002 were 37% compared to the federal statutory rate of 35%. The major reasons for this difference are 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 the tax benefits related to certain leveraged leases. |
Extraordinary Item |
In July 2003, the New Jersey Board of Public Utilities (NJBPU) approved the determination of stranded costs related to ACE's January 31, 2003, petition relating to its B.L. England generating facility. The NJBPU approved recovery of $149.5 million. 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 Pepco Holdings' financial statements, since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999. 49
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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 2004 and 2003. |
Capital Structure |
The components of Pepco Holdings' capital structure, expressed as a percentage of total capitalization (including short-term debt and current maturities of long-term debt but excluding transition bonds issued by Atlantic City Electric Transition Funding LLC (ACE Funding) and PES' project funding secured by customer accounts receivable) is shown below as of December 31, 2004 and 2003. The debt issued by ACE Funding and Pepco Energy Services project funding, which are both effectively securitized, are excluded because the major credit rating agencies treat effectively securitized debt separately and not as general obligations of the Company, when computing credit quality measures. (Dollars in Millions). |
Common stock dividend payments were $176.0 million in 2004, $170.7 million in 2003, and $130.6 million in 2002. The increase in common dividends paid in 2004 was due to the issuance of 14,950,000 shares of common stock in September 2004 and issuances of 1,471,936 shares of common stock by the Company's Dividend Reinvestment Plan. The increase in 2003 was due to the August 1, 2002 acquisition of Conectiv by Pepco. |
In 2004, Pepco redeemed its remaining 900,000 shares of $3.40 series mandatorily redeemable preferred stock for $45 million, and 165,902 shares of $2.28 series preferred stock for $7.7 million. In 2003, redemptions of mandatorily redeemable trust preferred securities included $125 million for Pepco, $70 million for DPL, and $95 million for ACE. |
In 2004, Pepco issued $275 million of secured senior notes with maturities of 10 and 30 years; proceeds were used to redeem higher interest rate securities 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, and proceeds 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 54
_____________________________________________________________________________ of secured senior notes which mature in 2029 and 2034 respectively; proceeds were used to redeem higher interest rate securities. |
In 2003, Pepco Holdings issued $700 million of unsecured long-term debt with maturities ranging from 1 year to 7 years; proceeds 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. DPL issued $33.2 million of tax-exempt bonds having maturities ranging from 5 to 35 years, and proceeds were used to refinance higher interest debt. ACE Funding issued $152 million of Transition Bonds with maturities ranging from 8 to 17 years, and proceeds will be used to recover the stranded costs associated with an ACE generation asset and transaction costs. |
In December 2002, Pepco Holdings sold 5,750,000 shares of common stock at $19.13 per share. In September 2004, Pepco Holdings sold 14,950,000 shares of common stock at $19.25 per share. 3,808,135 shares of common stock have also been issued during the three-year period pursuant to the Company's Dividend Reinvestment Program. |
In 2002, Pepco Holdings issued $1.35 billion of unsecured notes: $350 million of 5.50% notes due in 2007, $750 million of 6.45% notes due in 2012, and $250 million of 7.45% notes due 2032. The proceeds from the sale of these notes were used to repay approximately $1.1 billion of indebtedness outstanding in connection with the Merger, and to repay approximately $240 million of outstanding commercial paper, including $106.1 million of commercial paper issued to fund the settlement of treasury lock transactions. Also, Pepco Holdings issued an additional $150 million of 5.5% notes due 2007, the proceeds of which were used to repay outstanding commercial paper. In addition, pursuant to a Stranded Cost Rate Order issued by the NJBPU, ACE Funding issued $440 million Transition Bonds, the proceeds of which will be used to recover stranded costs. |
Capital Requirements |
Construction Expenditures |
Pepco Holdings' construction expenditures for the year ended December 31, 2004 totaled $517.4 million of which $479.5 million was related to its power delivery businesses and the remainder related to Conectiv Energy and Pepco Energy Services. For the five-year period 2005 through 2009, total construction expenditures are projected to be approximately $2.1 billion, of which approximately $2.0 billion is related to the Power Delivery business. This amount includes 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, 2004, June 30, 2004, September 30, 2004 and December 31, 2004. 55
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On January 25, 2005, Pepco Holdings declared a dividend on common stock of 25 cents per share payable March 31, 2005, to shareholders of record March 10, 2005. |
Under PUHCA, PHI is prohibited, without SEC approval, from paying dividends on its common stock from capital or unearned surplus. 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) PUHCA, which prohibits a subsidiary of a registered public utility holding company from paying a dividend out of capital or unearned surplus without the prior approval of the SEC; (iii) the prior rights of holders of existing and futu re 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 (iv) 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. |
Pepco's articles of incorporation and DPL's certificate and articles of incorporation each contains 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 and articles of incorporation and ACE's certificate of incorporation each provides 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. Currently, none of these charter restrictions limits the ability of Pepco, DPL or ACE to pay dividends. |
Pension Funding |
Pepco Holdings has a noncontributory retirement plan (the Retirement Plan) that covers substantially all employees of Pepco, Conectiv and certain employees of other Pepco Holdings' subsidiaries. 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 applicable to Pepco employees are identical to those in the original Pepco plan and the provisions and benefits applicable to Conectiv employees are identical to those in the original Conectiv plan. |
As of the 2004 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 2004 and 2003, PHI made discretionary tax-deductible cash contributions to the Retirement Plan in accordance with its funding policy. |
In 2004, the accumulated benefit obligation for the Retirement Plan increased over 2003, due to the accrual of an additional year of service for 56
_____________________________________________________________________________ participants and a decrease in the discount rate used to value the accumulated benefit obligation. The change in the discount rate reflected the continued decline in interest rates in 2004. The Retirement Plan assets achieved returns in 2004 in excess of the levels assumed in the valuation. As a result of the combination of these factors, in December 2004 PHI contributed $10 million (all of which was funded by Pepco) 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 accrued benefit obligation. In 2003, PHI contributed a total of $50 million (of which $30 million was funded by Pepco and $20 million was funded by ACE) to the Retirement Plan. Assuming no changes to the current pension plan assumptions, PHI projects no funding will be required under ERISA in 2005; however, PHI may elect to make a discretionary tax-deductible contribution, if required to main tain its assets in excess of its ABO. |
Contractual Obligations And Commercial Commitments |
Summary information about Pepco Holdings' consolidated contractual obligations and commercial commitments at December 31, 2004, is as follows: |
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 temporarily fund 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 notes can be issued with maturities up to 270 days from the date of issue. 62
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In July 2004, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $650 million. This agreement replaced a $550 million 364-day credit agreement that was entered into on July 29, 2003. The respective companies also are parties to a three-year credit agreement that was entered into in July 2003 and terminates in July 2006 with an aggregate borrowing limit of $550 million. Pepco Holdings' credit limit under these facilities is $700 million, and the credit limit of each of Pepco, DPL and ACE under these facilities is the lower of $300 million and the maximum amount of short-term debt authorized by the appropriate state commission, except that the aggregate amount of credit utilized by Pepco, DPL and ACE at any given time under these facilities may not exceed $500 million. Funds borrowed under these facilities are available for general corporate purposes. Either credit facility also can be used as credit support for the commercial paper programs of the respective companies. The three-year and five-year credit agreements contain customary financial and other covenants that, if not satisfied, could result in the acceleration of repayment obligations under the agreements or restrict the ability of the companies to borrow under the agreements. Among these covenants is 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 agreements. As of December 31, 2004, the applicable ratios for Pepco Holdings, Pepco, DPL and ACE were 59.0%, 58.5%, 52.1% and 50.2%, respectively. The credit agreements also contain a number of customary events of default that could result in the acceleration of repayment obligations under the agreements, including (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 agreements) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE. |
In December 2004, PHI entered into a $50 million term loan due December 13, 2005 with a bank. The loan is variable rate, based on LIBOR. PHI has the option to select interest periods based on one, two, three or six month LIBOR rates. The covenants in the agreement are substantially consistent with those found in the three-year and five-year credit agreements. Proceeds from the loan were used to pay down commercial paper. |
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 refund or refinance existing securities. |
PUHCA Restrictions |
Because Pepco Holdings is a public utility holding company registered under the Public Utility Holding Company Act (PUHCA), it must obtain SEC approval to issue securities. PUHCA also prohibits Pepco Holdings from borrowing from its subsidiaries. Under an SEC Financing Order dated July 31, 2002 (the Financing Order), Pepco Holdings is authorized to issue equity, preferred securities and debt securities in an aggregate amount not to exceed $3.5 billion through an authorization period ending June 30, 2005, 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 for up to $3.5 63
_____________________________________________________________________________ billion. Of this amount, only $1.75 billion may be on behalf of subsidiaries engaged in energy marketing activities. |
Pepco Holdings may issue common stock to satisfy its obligations under its Shareholder Dividend Reinvestment Plan and various employee benefit plans. Under the Financing Order, Pepco Holdings is limited to issuing no more than an aggregate of 20 million shares of common stock under its Shareholder Dividend Reinvestment Plan and employee benefit plans during the period ending June 30, 2005. |
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) of at least 30 percent. At December 31, 2004, Pepco Holdings' common equity ratio for purposes of the Financing Order was 36.6 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 the SEC. |
If an amendment to the Financing Order is required to enable Pepco Holdings or any of its subsidiaries to effect a financing, there is no certainty that such an amendment could be obtained or as to the timing of SEC action. The failure to obtain timely relief from the SEC, in such circumstances, could have a material adverse effect on the financial condition of Pepco Holdings and its subsidiaries. |
The foregoing financing limitations also generally apply to Pepco, DPL, ACE and certain other Pepco Holdings' subsidiaries. |
On February 15, 2005, PHI and its subsidiaries filed an application with the SEC for authorization to engage in various financing activities described therein for an authorization period through June 30, 2008. |
Money Pool |
Under the July 31, 2002 Financing Order, Pepco Holdings has received SEC authorization under PUHCA 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 borrowin g 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. 64
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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., pursuant to an Asset Purchase and Sale Agreement. As part of the Asset Purchase and Sale Agreement, Pepco entered into several ongoing contractual arrangements with Mirant and certain of its subsidiaries (collectively, Mirant). On July 14, 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). |
Depending on the outcome of the matters discussed below, the Mirant bankruptcy could have a material adverse effect on the results of operations of Pepco Holdings and Pepco. However, management currently 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 have arisen or may arise due to the Mirant bankruptcy. Accordingly, management does not anticipate that the Mirant bankruptcy will impair the ability of Pepco Holdings or Pepco to fulfill their 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 these agreements, Mirant was obligated to supply Pepco with all of the capacity and energy needed to fulfill its standard offer service obligations in Maryland through June 2004 and its standard offer service obligations in the District of Columbia through January 22, 2005. |
To avoid the potential rejection of the TPAs, Pepco and Mirant entered into an Amended Settlement Agreement and Release dated as of October 24, 2003 (the Settlement Agreement) pursuant to which Mirant assumed both of the TPAs and the terms of the TPAs were modified. The Settlement Agreement also provided that Pepco has an allowed, pre-petition general unsecured claim against Mirant Corporation in the amount of $105 million (the Pepco TPA Claim). |
Pepco has also asserted the Pepco TPA Claim against other Mirant entities that Pepco believes are liable to Pepco under the terms of the Asset Purchase and Sale Agreement's Assignment and Assumption Agreement (the Assignment Agreement). Under the Assignment Agreement, Pepco believes that each of the Mirant entities assumed and agreed to discharge certain liabilities and obligations of Pepco as defined in the Asset Purchase and Sale Agreement. Mirant has filed objections to these claims. Under the current plan of reorganization filed by the Mirant entities with the Bankruptcy Court, certain Mirant entities other than Mirant Corporation would pay significantly higher portions of the claims of their creditors than would Mirant Corporation. The amount that Pepco will be able to recover from the Mirant bankruptcy estate with respect to the Pepco TPA Claim will depend on 65
_____________________________________________________________________________ the amount of assets available for distribution to creditors of the Mirant entities that are found to be liable for the Pepco TPA Claim. |
Power Purchase Agreements |
Under agreements with FirstEnergy Corp., formerly Ohio Edison (FirstEnergy), and Allegheny Energy, Inc., both entered into in 1987, Pepco is obligated to purchase from FirstEnergy 450 megawatts of capacity and energy annually through December 2005 (the FirstEnergy PPA). Under an agreement with Panda, entered into in 1991, Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (the Panda PPA). In each case, the purchase price is substantially in excess of current 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 is obligated, among other things, to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the FirstEnergy PPA and the Panda PPA at a price equal to the price Pepco is obligated to pay under the FirstEnergy PPA and the Panda PPA (the PPA-Related Oblig ations). |
Pepco Pre-Petition Claims |
When Mirant filed its bankruptcy petition on July 14, 2003, Mirant had unpaid obligations to Pepco of approximately $29 million, consisting primarily of payments due to Pepco in respect of the PPA-Related Obligations (the Mirant Pre-Petition Obligations). The Mirant Pre-Petition Obligations constitute part of the indebtedness for which Mirant is seeking relief in its bankruptcy proceeding. Pepco has filed Proofs of Claim in the Mirant bankruptcy proceeding in the amount of approximately $26 million to recover this indebtedness; however, the amount of Pepco's recovery, if any, is uncertain. The $3 million difference between Mirant's unpaid obligation to Pepco and the $26 million Proofs of Claim primarily represents a TPA settlement adjustment which is included in the $105 million Proofs of Claim filed by Pepco against the Mirant debtors in respect of the Pepco TPA Claim. In view of this uncertainty, Pepco, in the third quarter of 2003, expen sed $14.5 million to establish a reserve against the $29 million receivable from Mirant. In January 2004, Pepco paid approximately $2.5 million 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. Pepco believes that under the terms of the Asset Purchase and Sale Agreement, Mirant is obligated to reimburse Pepco for the settlement payment. Accordingly, in the first quarter of 2004, Pepco increased the amount of the receivable due from Mirant by approximately $2.5 million and amended its Proofs of Claim to include this amount. Pepco currently estimates that the $14.5 million expensed in the third quarter of 2003 represents the portion of the entire $31.5 million receivable unlikely to be recovered in bankruptcy, and no additional reserve has been established for the $2.5 million increase in the receivable. The amount expensed represents Pepco's estimate of the possible outcome in bankruptcy, although the amou nt ultimately recovered could be higher or lower. |
Mirant's Attempt to Reject the PPA-Related Obligations |
On August 28, 2003, Mirant filed with the Bankruptcy Court a motion seeking authorization to reject its PPA-Related Obligations. Upon motions filed with the U.S. District Court for the Northern District of Texas (the District Court) by Pepco and FERC, in October 2003, the District Court withdrew jurisdiction over the rejection proceedings from the Bankruptcy Court. In December 2003, the District Court denied Mirant's motion to reject 66
_____________________________________________________________________________ the PPA-Related Obligations on jurisdictional grounds. The District Court's decision was appealed by Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation (the Creditors' Committee) to the U.S. Court of Appeals for the Fifth Circuit (the Court of Appeals). On August 4, 2004, the Court of Appeals remanded the case to the District Court saying that the District Court has 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. |
On December 9, 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. On December 16, the Creditors' Committee appealed the District Court's order to the Court of Appeals, and on December 20, 2004, Mirant also appealed the District Court's order. |
As more fully discussed below, Mirant had been making regular periodic payments in respect of the PPA-Related Obligations. On December 9, 2004, Mirant filed a notice with the Bankruptcy Court that it was suspending payments to Pepco in respect of the PPA-Related Obligations. On December 13, 2004, Mirant failed to make a payment of approximately $17.9 million due to Pepco for the period November 1, 2004 to November 30, 2004. Mirant failed to make that payment. On December 23, 2004, Pepco received a payment of approximately $6.8 million from Mirant, which according to Mirant represented the market value of the power for which payment was due on December 13. Mirant has informed Pepco that it intends to continue to pay the market value, but not the above-market portion, of the power purchased under the PPA-Related Obligations. Pepco disagrees with Mirant's assertion that it need only pay the market value and believes that the amount repr esenting the market value calculated by Mirant is insufficient. |
On January 21, 2005, Mirant made a approximately $21.1 million, which, according to Mirant, includes the payment for the FirstEnergy PPA for December 2004 and "includes the December 2004 TPA revenue in the amount of $29,093,173.43, the TPA costs in the amount of $37,865,924.10, and an allocated share of [FirstEnergy's] PPA bill credits/charges in the amount of $5,490,164.79." Pepco disputes Mirant's contention that the amount paid reflects the full amount due Pepco under these agreements for the applicable periods. |
As of March 1, 2005, Mirant has withheld payment of approximately $34.8 million due to Pepco under the PPA-Related Obligations. |
On January 21, 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. On March 1, 2005 (as amended by order dated March 7, 2005), the District Court granted Pepco's motion to withdraw jurisdiction over the Asset Purchase and Sale Agreement rejection proceedings from the Bankruptcy Court. In addition, the District Court ordered Mirant to pay on March 18, 2005, all past-due unpaid amounts under the PPA-Related Obligations. Mirant has filed a motion for reconsideration and a stay of the March 1, 2005 order. 67
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Pepco is exercising all available legal remedies and vigorously opposing Mirant's attempt to reject the PPA-Related Obligations and other 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 the attempt to reject the agreements, the outcome of Mirant's efforts to reject the PPA-Related Obligations is uncertain. |
If Mirant ultimately is successful in rejecting the PPA-Related Obligations, Pepco could be required to repay to Mirant, for the period beginning on the effective date of the rejection (which date could be prior to the date of the court's order and possibly as early as September 18, 2003) and ending on the date Mirant is entitled to cease its purchases of energy and capacity from Pepco, all amounts paid by Mirant to Pepco in respect of the PPA-Related Obligations, less an amount equal to the price at which Mirant resold the purchased energy and capacity. Pepco estimates that the amount it could be required to repay to Mirant in the unlikely event that September 18, 2003, is determined to be the effective date of rejection, is approximately $133.2 million as of March 1, 2005 (assuming Mirant continues to withhold unpaid amounts of approximately $34.8 million as of March 1, 2005. |
Mirant has also indicated to the Bankruptcy Court that it will move to require Pepco to disgorge all amounts paid by Mirant to Pepco in respect of the PPA-Related Obligations, less an amount equal to the price at which Mirant resold the purchased energy and capacity, for the period July 14, 2003 (the date on which Mirant filed its bankruptcy petition) through rejection, if approved, on the theory that Mirant did not receive value for those payments. Pepco estimates that the amount it would be required to repay to Mirant on the disgorgement theory, in addition to the amounts described above, is approximately $22.5 million. |
Any repayment by Pepco of amounts paid by Mirant would entitle Pepco to file a claim against the bankruptcy estate in an amount equal to the amount repaid. Pepco believes that, to the extent such amounts were not recovered from the Mirant bankruptcy estate, they would be recoverable as stranded costs from customers through distribution rates as described below. |
The following are estimates prepared by Pepco of its potential future exposure if Mirant's attempt to reject the PPA-Related Obligations ultimately is successful. 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. The estimates assume no recovery from the Mirant bankruptcy estate and no regulatory recovery, either of which would mitigate the effect of the estimated loss. Pepco does not consider it realistic to assume that there will be no such recoveries. Based on these assumptions, Pepco estimates that its pre-tax exposure as of March 1, 2005, representing the loss of the future benefit of the PPA-Related Obligations to Pepco, is as follows: |
The ability of Pepco to recover from the Mirant bankruptcy estate in respect to the Mirant Pre-Petition Obligations and damages if the PPA-Related Obligations are successfully rejected will depend on whether Pepco's claims are allowed, the amount of assets available for distribution to the creditors of the Mirant companies determined to be liable for those claims, and Pepco's priority relative to other creditors. At the current stage of the bankruptcy proceeding, there is insufficient information to determine the amount, if any, that Pepco might be able to recover from the Mirant bankruptcy estate, whether the recovery would be in cash or another form of payment, or the timing of any recovery. |
If Mirant ultimately is successful in rejecting the PPA-Related Obligations and Pepco's full claim is not recovered from the Mirant bankruptcy estate, Pepco may 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, if Mirant ultimately is successful in rejecting the PPA-Related Obligations, 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 Pe pco's interpretation of the settlement agreements is confirmed, Pepco expects to be able to establish the amount of its anticipated recovery 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. |
If the PPA-Related Obligations are successfully rejected, and there is no regulatory recovery, Pepco will incur a loss. However, the accounting treatment of such a loss depends on a number of legal and regulatory factors, and is not determinable at this time. |
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, Inc. (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 facility and capacity credit 69
_____________________________________________________________________________ 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. Pepco believes that there is no reasonable factual or legal basis to support Mirant's contention that the SMECO Agreement is a lease of real property. Litigation continues and the outcome of this proceeding cannot be predicted. |
Federal Tax Treatment of cross-border Leases |
PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which as of December 31, 2004 had a book value of approximately $1.2 billion. The American Jobs Creation Act of 2004 imposed new passive loss limitation rules that apply prospectively to leases (including cross-border leases) entered into after March 12, 2004 with tax indifferent parties (i.e., municipalities and tax exempt or governmental entities). All of PCI's cross-border energy leases are with tax indifferent parties and were entered into prior to 2004. Although this legislation is prospective in nature and does not affect PCI's existing cross-border energy leases, it does not prohibit the IRS from challenging prior leasing transactions. In this regard, 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 enteri ng into certain sale-leaseback transactions with tax indifferent parties, including those entered into on or prior to March 12, 2004 (the Notice). |
PCI's cross-border energy leases are similar to those sale-leaseback transactions described in the Notice. PCI's leases are currently under examination by the IRS as part of the normal PHI tax audit. PHI believes there is a substantial likelihood that the IRS will challenge the tax benefits realized from interest and depreciation deductions claimed by PCI with respect to these leases, or the timing of these benefits, for the years 2001 through 2004. The tax benefits claimed by PCI for these years were approximately $175 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 results of operations and cash flow. |
PHI believes that its tax position related to these transactions was proper based on applicable statutes, regulations and case law, and intends to contest any adjustments proposed by the IRS; however, there is no assurance that PHI's position will prevail. |
Under SFAS No. 13, as currently interpreted, a deferral of tax benefits that does not change the total estimated net income from PHI's leases does not require an adjustment to the book value of the leases. 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 results of operations for the period in which the charge is recorded. 70
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In recent deliberations, The Financial Accounting Standards Board (FASB) has determined that a change in the timing of tax benefits also should require a repricing of the lease and an adjustment to the book value of a lease. Under this interpretation, a material change in the timing of cash flows under PHI's cross-border leases as the result of a settlement with the IRS also would require an adjustment to the book value. PHI understands that the FASB intends to publish this guidance for comment in the near future to become effective at the end of 2005. If adopted, the application of this guidance could result in a material adverse effect on PHI's results of operations even if the resolution is limited to a deferral of the tax benefits realized by PCI from its leases. |
Rate Proceedings |
In February 2003, ACE filed a petition with the NJBPU to increase its electric distribution rates and its Regulatory Asset Recovery Charge (RARC) in New Jersey. The petition was based on actual data for the nine months ended September 30, 2002, and forecasted data for the three months ended December 31, 2002 and sought an overall rate increase of approximately $68.4 million, consisting of an approximately $63.4 million increase in electricity distribution rates and $5 million for recovery of regulatory assets through the RARC. In October 2003, ACE filed an update supporting an overall rate increase of approximately $41.3 million, consisting of a $36.8 million increase in electricity distribution rates and a RARC of $4.5 million. This petition was ACE's first increase request for electric distribution rates since 1991. The requested increase would apply to all rate schedules in ACE's tariff. The Ratepayer Advocate filed testimony on January 3, 2004, proposing an annual rate decrease of $11.7 million. Intervenor groups representing industrial users and local generators filed testimony that did not take a position with respect to an overall rate change but their proposals, if implemented, would affect the way in which an overall rate increase or decrease would be applied to the particular rates under which they receive service. ACE's rebuttal testimony, filed in February 2004, made some changes to its October filing and proposed an overall rate increase of approximately $35.1 million, consisting of a $30.6 million increase in distribution rates and a $4.5 million increase in the RARC. Hearings were held before an Administrative Law Judge in late March, early April and May 2004. At the hearing held in April 2004, the Ratepayer Advocate proposed an annual rate decrease of $4.5 million, modifying its earlier proposal that rates be decreased by $11.7 million annually. The Ratepayer Advocate and Staff of the NJBPU filed their briefs in this proceeding in August 2004. The Ratepayer Advocate's brief supported its earlier proposal of an annual rate decrease of $4.5 million. The Staff's brief, however, stated for the first time its position calling for an overall decrease of $10.8 million. Reply briefs were filed on August 23, 2004. Settlement discussions between ACE, the NJBPU Staff and the Ratepayer Advocate have been ongoing. |
On December 12, 2003, the NJBPU issued an order also consolidating outstanding issues from several other proceedings into the base rate case proceeding. On December 22, 2003, ACE filed a Motion for Reconsideration in which it suggested that these issues be dealt with in a Phase II to the base rate case to address the outstanding issues identified in the December 12, 2003 Order. After discussion with the parties to the base rate case, it was agreed that a Phase II to the base rate case to address these issues, along with the $25.4 million of deferred restructuring costs previously transferred into the base rate case, would be initiated in April 2004. On April 15, 2004, ACE filed testimony with the NJBPU initiating a Phase II to the base rate proceeding described above. The parties to this case have 71
_____________________________________________________________________________ been actively engaged in settlement discussions in conjunction with settlement of Phase I issues. |
On August 31, 2004, ACE filed requests with the NJBPU proposing changes to its Transition Bond Charge, its Market Transition Charge - Tax rate, and its BGS Reconciliation charges. The net impact of these rate changes is to decrease ACE's annual revenues by approximately 1.5%. All of these rate changes were implemented on October 1, 2004. |
On October 1, 2004, DPL submitted its annual Gas Cost Rate (GCR) filing to the DPSC. In its filing, DPL sought to increase its GCR by approximately 16.8% in anticipation of increasing natural gas commodity costs. The GCR, which permits DPL to recover its procurement gas costs through customer rates, became effective November 1, 2004 and is subject to refund pending evidentiary hearings. In addition, on November 29, 2004, DPL filed a supplemental filing seeking approval to further increase GCR rates by an additional 6.5% effective December 29, 2004. The additional GCR increase became effective December 29, 2004 and is subject to refund pending evidentiary hearings. The DPSC Staff and the Division of Public Advocate filed their testimony on March 7, 2005 recommending full approval of the GCR changes being sought by DPL, including the revisions to the tariff in the original and supplemental filings. A final order addressing both the Nov ember 1 and December 29 increases is expected in the spring of 2005. |
On February 13, 2004, DPL filed with the DPSC for a change in electric ancillary service rates that would have an aggregate effect of increasing annual Delaware electric revenues by $13.1 million or 2.4%. This filing was prompted by the increasing ancillary service costs charged to DPL by PJM. The proposed rates went into effect on March 15, 2004, subject to refund. On June 22, 2004, the DPSC approved a settlement agreement that provided for an increase having an aggregate effect of increasing annual Delaware electric revenues by $12.4 million, or 2.3%, with rates effective June 23, 2004. The approved increase was slightly less than the proposed increase that went into effect on March 15, 2004. As part of the settlement, the resulting estimated over-collection of $75,000 was given by DPL to the State of Delaware Low Income Fund administered by the Delaware Department of Human Services on July 15, 2004. |
In compliance with the settlement approved by the MPSC in connection with the merger of Pepco and Conectiv, on December 4, 2003, DPL and Pepco submitted testimony and supporting schedules to review and reset if necessary its electricity distribution rates in Maryland to be effective July 1, 2004, when the then-current distribution rate freeze/caps ended. DPL's filing demonstrated that it was in an under-earning situation and, as allowed in the merger settlement, DPL requested that a temporary rate reduction implemented on July 1, 2003 for non-residential customers be terminated effective July 1, 2004. DPL estimated that the termination of the rate reduction would increase its annual revenues by approximately $1.1 million. A settlement reached between the parties allowing for this $1.1 million increase to be effective July 1, 2004 was approved by the MPSC in Order No. 79186. With limited exceptions, DPL cannot increase its distribution rates until January 1, 2007. |
Pepco's filing demonstrated that it also was in an under-earning situation. However the merger settlement provided that Pepco's distribution rates after July 1, 2004 could only remain the same or be decreased. With limited exceptions, Pepco cannot increase its distribution rates until January 1, 2007. In an order dated July 6, 2004 the MPSC affirmed the 72
_____________________________________________________________________________ Hearing Examiner's recommendation that no rate decrease was warranted at that time. |
On July 3, 2004, Pepco filed a distribution rate review case with the DCPSC as required by the terms of the Pepco-Conectiv merger settlement approved by the DCPSC. This case will determine whether Pepco's distribution rates will be decreased. In accordance with the terms of the merger settlement, Pepco's distribution rates cannot be increased as a result of the case. On November 24, 2004, the DCPSC issued an order that designated the issues to be considered in the case and set the hearing schedule. On December 17, 2004, Pepco filed supplemental direct testimony addressing the DCPSC-designated issues. Pepco's filings indicate that no rate decrease is warranted. On March 4, 2005, the DCPSC issued an order granting a joint motion filed on March 3, 2005, on behalf of Pepco and several other parties in the case to suspend the procedural schedule to allow the parties to focus on completing settlement discussions. In the joint motion, the movin g parties informed the DCPSC that they had agreed in principle to settlement provisions that would resolve all issues in the proceeding and that a settlement agreement could be filed in the near future. |
Restructuring Deferral |
Pursuant to a July 1999 summary order issued by the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA) (which was subsequently affirmed by a final decision and order issued in March 2001), ACE was obligated to provide basic generation service (BGS) from August 1, 1999 to at least July 31, 2002 to retail electricity customers in ACE's service territory who did not choose a competitive energy supplier. The order allowed ACE to recover through customer rates certain costs incurred in providing BGS. ACE's obligation to provide BGS was subsequently extended to July 31, 2003. At the allowed rates, for the period August 1, 1999 through July 31, 2003, ACE's aggregate allowed costs 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 Ener gy Adjustment Clause and ACE's Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance. |
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. The deferred balance was 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 2003, the NJBPU issued a 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 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. In July 2004, the NJBPU issued its final order in the restructuring deferral 73
_____________________________________________________________________________ proceeding. The final order did not modify the amount of the disallowances set forth in the July 2003 summary order, but did provide a much more detailed analysis of evidence and other information relied on by the NJBPU as justification for the disallowances. ACE believes the record does not justify the level of disallowance imposed by the NJBPU. 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 related to the July 2004 final order. ACE cannot predict the outcome of this appeal. |
Divestiture Cases |
District of Columbia |
Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed on July 31, 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. 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. On March 4, 2003, theInternal Revenue S ervice (IRS) issued a notice of proposed rulemaking (NOPR)that is relevant to that principal issue.Comments on the NOPR were filed byseveral parties on June 2, 2003, and the IRS held a public hearing on June 25,2003.As a result of the NOPR, three of the parties in the divestiture case filed comments with the DCPSC urging the DCPSC to decide the tax issues now on the basis of the proposed rule.Pepco filed comments with the DCPSC in reply to those comments, in which Pepco stated that thecourts have held and the IRS has stated that proposed rules are notauthoritative and that no decision should be issued on the basis of proposedrules. Instead, Pepco argued that the only prudent course of action is for the DCPSC to await the issuance of final regulations relating to the taxissues and then allow the parties to file supplemental briefs on the tax issues.Pepco cannot predict whether the IRS will adopt the regulations as proposed,make changes before issuing final regulations or decide not to adoptregulations. Other issues in the proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture. |
Pepco believes that a sharing of EDIT and ADITC would violate the normalization rules. 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. Pepco, in addition to sharing with customers the generation-related ADITC balance, would have to pay to the IRS an amount equal to Pepco's $5.8 million District of Columbia jurisdictional generation-related ADITC balance as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance 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. As of December 31, 2004, the District of Columbia jurisdictional transmission and distribution-related ADITC balance was approximately $6.0 million. 74
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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 D.C. 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 condition. It is uncertain when the DCPSC will issue a decision. |
Maryland |
Pepco filed its divestiture proceeds plan application in Maryland in April 2001. Reply briefs were filed in May 2002. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that was raised in the D.C. case. As of December 31, 2004, the Maryland 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 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 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,i.e., $9.1 million, and the generation-related ADITC. If such sharing were to violate the normalization rules, Pepco, in addition to sharing with customers an amount equal to approximately 50 percent of the generation-related ADITC balance, would be unable to use accelerated depreciation on Maryland allocated or assigned property. Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco's $10.4 million Maryland jurisdictional generation-related ADITC balance, as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance 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. As of December 31, 2004, the Maryland retail jurisdiction al transmission and distribution-related ADITC balance was approximately $10.7 million. The Hearing Examiner decided all other issues in favor of Pepco, except 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. See also the disclosure above under "Divestiture Cases - District of Columbia" regarding the March 4, 2003 IRS NOPR. |
Under Maryland law, if the proposed order is appealed to the MPSC, the proposed order is not a final, binding order of the MPSC and further action by the MPSC is required with respect to this matter. Pepco has appealed the Hearing Examiner's decision on the treatment of EDIT and ADITC and corporate reorganization costs to the MPSC. Pepco cannot predict what the outcome of the appeal will be or when the appeal might be decided. 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 75
_____________________________________________________________________________ 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 condition. |
SOS and Default Service Proceedings |
District of Columbia |
In February 2003, the DCPSC opened a new proceeding to consider issues relating to (a) the establishment of terms and conditions for providing SOS in the District of Columbia after Pepco's obligation to provide SOS terminated on February 7, 2005, and (b) the selection of a new SOS provider. |
In December 2003, the DCPSC issued an order that set forth the terms and conditions for the selection of a new SOS provider(s) and the provision of SOS by Pepco on a contingency basis. In December 2003, the DCPSC also issued an order adopting terms and conditions that would apply if Pepco continued as the SOS provider after February 7, 2005. In March 2004, the DCPSC issued an order adopting the wholesale SOS model,i.e., Pepco would continue to be the SOS provider in the District of Columbia after February 7, 2005. This March 2004 order, as amended by a DCPSC order issued in July 2004, extends Pepco's obligation to provide default electricity supply at market rates for up to an additional 76 months for small commercial and residential customers, and for an additional 28 months for large commercial customers. |
In August 2004, the DCPSC issued an order adopting administrative charges for residential, small and large commercial DC 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 $0.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial DC 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 DC 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 DC SOS sales on February 8, 2005. Pepco completed the first competitive procurement process for DC SOS at the end of October and filed the proposed new SOS rates with the DC PSC on November 3, 2004. |
The TPA with Mirant under which Pepco obtained the fixed-rate DC 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 DC 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 DC SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new DC 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 DC SOS contracts and the DC SOS rates charged to customers for the period from February 1 to February 7, 2005. The total amount of the diff erence is estimated to be approximately $8.7 million. This difference, however, will 76
_____________________________________________________________________________ be included in the calculation of the Generation Procurement Credit (GPC) for DC for the period February 8, 2004 through February 7, 2005. 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. Currently, based on the rates paid by Pepco to Mirant under the TPA Settlement, there is no customer sharing. However, in the event that Pepco were to ultimately realize a significant recovery from the Mirant bankruptcy estate associated with the TPA Settlement, the GPC would be recalculated, and the amount of customer sharing with respect to such recovery would be reduced because of the $8.7 million loss being included in the GPC calculation. |
Maryland |
Under a settlement approved by the MPSC in April 2003 addressing SOS service in Maryland following the expiration of Pepco's fixed-rate default supply obligations in July 2004, Pepco is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, Pepco purchases the power supply required to satisfy its market rate default supply obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the MPSC. Pepco is entitled to recover from its default supply customers the cost of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, small and large commercial Maryland SOS customers over the twelve months ended December 31, 200 3. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period. |
Under a settlement approved by the MPSC in April 2003 addressing SOS service in Maryland following the expiration of DPL's fixed-rate default supply obligations to non-residential customers in June 2004 and to residential customers through June 2004, DPL is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, DPL purchases the power supply required to satisfy its market rate default supply obligations 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 default supply customers the costs of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, 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 will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period. |
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 77
_____________________________________________________________________________ agreement with Conectiv Energy. A prior agreement, also with Conectiv Energy, terminated effective December 31, 2004. The current contract was entered into after conducting a competitive bid procedure identical to the Maryland SOS process in most respects and Conectiv Energy was the lowest bidder to provide wholesale power supply for DPL's Virginia default service customers. The new supply agreement commenced January 1, 2005 and expires in May 2006. On October 26, 2004, DPL filed an application with the VSCC for approval to increase the rates that DPL charges its Virginia default service customers to allow it to recover its costs for power under the new supply agreement plus an administrative charge and a margin. |
A VSCC order dated November 17, 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. Therefore, the November 17 order also directed the parties to file memoranda concerning whether administrative costs and a margin are properly recovered through a fuel clause mechanism. Memoranda were filed by DPL, the VSCC Staff and Virginia's Office of Attorney General. The VSCC ruled on January 18, 2005, that the administrative charge and margin are base rate items not recoverable through a fuel clause. No appeal is planned regarding this filing. A settlement resolving all other issues and m aking the interim rates final was filed on March 4, 2005, contingent only on possible future adjustment depending on the result of a related proceeding at FERC. A hearing is scheduled for March 16, 2005, and the VSCC is expected to approve the settlement. |
Also in October, DPL and Conectiv Energy jointly filed an application with the VSCC under Virginia's Affiliates Act requesting authorization for DPL to enter into a contract to purchase power from an affiliate. This authorization permits the contract to be executed with an affiliate, but is not a ruling on the merits of the contract. A VSCC order dated December 17, 2004 granted approval for DPL to purchase power from Conectiv Energy under the new contract according to its terms beginning January 1, 2005. |
On October 29, 2004, Conectiv Energy made a filing with FERC requesting authorization to enter into a contract to supply power to an affiliate. On December 30, 2004, FERC granted the requested authorization effective January 1, 2005, subject to refund and hearings on the narrow question whether, in the absence of direct VSCC oversight over the DPL competitive bid process, DPL unduly preferred its own affiliate, Conectiv Energy, in the design and implementation of the DPL competitive bid process, or unduly favored Conectiv Energy in the credit criteria and analysis applied. DPL cannot predict the outcome of this proceeding. |
Delaware |
Under a settlement approved by the DPSC, DPL is required to provide default electricity supply to customers in Delaware until May 1, 2006. On October 19, 2004, the DPSC initiated a proceeding to investigate and determine which entity should act as the standard offer supplier in DPL's Delaware service territory after May 1, 2006, and what prices should be charged for SOS after May 1, 2006. Similar to the process used in Maryland, the process used in Delaware consists of three separate stages. The stage 1 process was constructed to allow the DPSC to determine by February 28, 2005 the fundamental issues related to the selection of an SOS supplier. Stage 2 will resolve issues relating to the process under which supply will be 78
_____________________________________________________________________________ acquired by the SOS provider and way in which SOS prices will be set and monitored. In the last stage, these selection and pricing mechanisms would be implemented to determine the post-May 2006 SOS supplier and the post-May 2006 SOS price. On January 26, 2005, the DPSC Staff issued a report recommending to the DPSC that DPL be selected as the SOS supplier, subject to further discussions as to how to establish SOS prices. On February 22, 2005, the DPSC voted to approve an SOS process that will allow a Wholesale Standard Offer Service Model with DPL as the SOS Provider. Issues including the length of this extension and any profit margin that DPL may be able to earn and retain in conjunction with this service have been deferred for further discussion and will be decided by the DPSC at a later date. A written DPSC order documenting this decision is expected sometime in March or April 2005. |
Proposed Shut Down of B.L. England Generating Facility; Construction of Transmission Facilities |
Pursuant to a September 25, 2003 NJBPU order, ACE filed a report on April 30, 2004 with the NJBPU recommending that the B.L. England generating facility be shut down in accordance with the terms of an April 26, 2004 preliminary settlement agreement among PHI, Conectiv and ACE, NJDEP and the Attorney General of New Jersey. The report stated that the operation of the B.L. England facility is necessary at the present time to satisfy reliability standards, but that those reliability standards could also be satisfied in other ways. The report concludes 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 facility and construct additional transmission lines into southern New Jersey. ACE cannot predict whether the NJBPU will approve the construction of the additional transmission lines. |
In letters dated May and September 2004 to PJM, ACE informed PJM of its intent, as owner of the B.L. England generating plant, to retire the entire plant (447 MW) on December 15, 2007. PJM completed its independent analysis to determine the upgrades required to eliminate any identified reliability problems resulting from the retirement of B.L. England and recommended that certain transmission upgrades be installed prior to the summer of 2008. ACE's independent assessment confirmed that the transmission upgrades identified by PJM are the transmission upgrades necessary to maintain reliability in the Atlantic zone after the retirement of B.L. England. The amount of the costs incurred by ACE to construct the recommended transmission upgrades that ACE would be permitted to recover from load serving entities that use ACE's transmission system would be subject to approval by FERC. The amount of construction costs that ACE would be permitted to re cover from retail ratepayers would be determined in accordance with the treatment of transmission-related revenue requirements in retail rates under the jurisdiction of the appropriate state regulatory commission. ACE cannot predict how the recovery of such costs will ultimately be treated by FERC and the state regulatory commissions and, therefore, cannot predict the financial impact to ACE of installing the recommended transmission upgrades. However, in the event that the NJBPU makes satisfactory findings and grants other requested approvals concerning the retirement of B.L. England and approves the construction of the transmission upgrades required to maintain reliability in the Atlantic zone after such retirement, ACE expects to begin construction of the appropriate transmission upgrades while final decisions by FERC and state regulatory commissions concerning the methodology for recovery of the costs of such construction are still pending. 79
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On November 1, 2004, ACE made a filing with the NJBPU requesting approval of the transmission upgrades required to maintain reliability in the Atlantic zone after the retirement of B.L. England. On December 22, 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. ACE cannot predict the outcome of these two proceedings. |
On November 12, 2004, ACE made a filing with the NJBPU requesting approval of year 2005 capital projects with respect to B.L. England. This filing was made pursuant the September 25, 2003 B.L. England rate order, which established a requirement that ACE file for approval of capital expenditures in excess of $1 million. For 2005, four projects, totaling $3.2 million in capital expenditures, have been identified as necessary to allow continued operation of B.L. England until its retirement. Two of these projects are well below the $1 million threshold set forth in the September 25, 2003 NJBPU order and two are above that threshold. ACE cannot predict the outcome of this proceeding. |
General Litigation |
Asbestos |
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, plaintiffs argue 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. Of the approximately 250 remaining asbestos cases pending against Pepco, approximately 85 cases were filed after December 19, 2000, and have been tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement. |
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 condition. However, if an 80
_____________________________________________________________________________ unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco's and PHI's results of operations. |
Enron |
On December 2, 2001, Enron North America Corp. and several of its affiliates (collectively, Enron) filed for protection under the United States Bankruptcy Code. In December 2001, DPL and Conectiv Energy terminated all energy trading transactions under various agreements with Enron. In late January 2003, after several months of discussions between the parties concerning the amount owed by DPL and Conectiv Energy, Enron filed an adversary complaint against Conectiv Energy in the Bankruptcy Court for the Southern District of New York. The complaint sought, among other things, damages in the amount of approximately $11.7 million. |
On June 3, 2004, the Bankruptcy Court approved a settlement among Enron, Conectiv Energy and DPL pursuant to which Conectiv Energy paid Enron an agreed settlement amount that was less than the $11.7 million damages Enron sought and the parties released all claims against each other. Conectiv Energy had previously established a reserve in an amount equal to the agreed settlement payment. Accordingly, the settlement did not have an effect on earnings. |
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. |
In May 2004, the U.S. Department of Justice (DOJ) invited DPL to enter into pre-filing negotiations in connection with DPL's alleged liability under CERCLA at the Diamond State Salvage site in Wilmington, Delaware. In the context of the negotiations, DOJ informed DPL that DPL is a de minimis party at the site. In February 2005, DPL entered into a de minimis consent decree with the United States which, if approved by the U.S. District Court, would require DPL to pay $144,000 as reimbursement of the government's response costs, resolve DPL's alleged liability, and provide DPL a covenant not to sue from the United States and protection from third-party claims for contribution. |
In July 2004, DPL entered into an Administrative Consent Order with the Maryland Department of the Environment (MDE) to perform a Remedial Investigation/Feasibility Study (RI/FS) to further identify the extent of soil, sediment and ground and surface water contamination related to former manufactured gas plant (MGP) operations at the Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The costs for completing the RI/FS for this site are approximately $300,000, approximately $50,000 of which will be expended in 2005. The costs of cleanup resulting from the RI/FS will not be determinable until the RI/FS is completed and an agreement with respect to cleanup is 81
_____________________________________________________________________________ reached with the MDE. DPL expects to complete the RI/FS in the first quarter of 2005. |
In October 1995, each of Pepco and DPL received notice from EPA that it, along with several hundred other companies, might be a PRP in connection with the Spectron Superfund Site in Elkton, Maryland. The site was operated as a hazardous waste disposal, recycling and processing facility from 1961 to 1988. |
In August 2001, Pepco entered into a consent decree for de minimis parties with EPA to resolve its liability at this site. Under the terms of the consent decree, which was approved by the U.S. District Court for the District of Maryland on March 31, 2003, Pepco made de minimis payments to the United States and a group of PRPs. In return, those parties agreed not to sue Pepco for past and future costs of remediation at the site and the United States will also provide protection against third-party claims for contributions related to response actions at the site. The consent decree does not cover any damages to natural resources. However, Pepco believes that any liability that it might incur due to natural resource damage at this site would not have a material adverse effect on its financial condition or results of operations. In February 2003, the EPA informed DPL that it will have no future liability for contribution to the remediation of the site. |
In the early 1970s, both Pepco and DPL sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In 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 October 1994, an RI/FS including a number of possible remedies was submitted to the EPA. In December 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 June 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs to conduct the design and actions called for in its decision. On May 12, 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 2, 2003, the Bankruptcy Court confirmed a Reorganization Plan that incorporates the terms of a settlement among the debtors, the United States and a group of utility PRPs including Pepco. Under the settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site. |
As of December 31, 2004, Pepco had accrued $1.7 million to meet its liability for a site remedy. At the present time, it is not possible to estimate the total extent of EPA's administrative and oversight costs or the expense associated with a site remedy ultimately implemented. However, Pepco believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations. |
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 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 condition or results of operations. |
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 82
_____________________________________________________________________________ 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 0.232 percent of the aggregate remediation liability and thus far ACE has made contributions of approximately $105,000. Based on information currently available, ACE may be required to contribute approximately an additional $100,000. ACE believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations. |
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 administrative consent order 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. The results of groundwater monitoring over the first year of this ground water sampling plan will help to determine the extent of post-remedy operation and maintenance costs. 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 may be required to contribute approximately an additional $626,000. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial condition or results of operations. |
On April 7, 2000, approximately 139,000 gallons of oil leaked from a pipeline at a generation station that was owned by Pepco at Chalk Point Generating Station in Aquasco, Maryland. The pipeline was operated by Support Terminals Services Operating Partnership LP (ST Services), an unaffiliated pipeline management company. The oil spread from Swanson Creek to the Patuxent River and several of its tributaries. The area affected covers portions of 17 miles of shoreline along the Patuxent River and approximately 45 acres of marshland adjacent to the Chalk Point property. |
In December 2000, the Department of Transportation, Office of Pipeline Safety, Research and Special Programs Administration (OPS) issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV). The NOPV alleged various deficiencies in compliance with regulations related to spill reporting, operations and maintenance of the pipeline and record keeping, none of which relate to the cause of the spill. The NOPV was issued to both Pepco and ST Services and proposed a civil penalty in the amount of $674,000. On June 2, 2004, the OPS issued a Final Order regarding the NOPV in this matter. The Final Order assessed a total fine of $330,250, with $256,250 of that amount assessed jointly against Pepco and ST Services and the remaining $74,000 assessed solely against ST Services. ST Services subsequently filed a Petition for Reconsideration. All penalties were stayed pending the outcome of the Petition for Rec onsideration. On February 9, 2005, OPS issued a Decision on the Petition for Reconsideration that affirmed the Final Order. Pepco's share of the $330,250 penalty assessed pursuant to the Final Order amounts to $128,125. |
Preliminary Settlement Agreement with the NJDEP |
In an effort to address NJDEP's concerns regarding ACE's compliance with New Source Review (NSR) requirements at B.L. England, on April 26, 2004, PHI, Conectiv and ACE entered into a preliminary settlement agreement with NJDEP and the Attorney General of New Jersey. The preliminary settlement agreement outlines the basic parameters for a definitive agreement to resolve ACE's NSR liability at B.L. England and various other environmental issues at ACE and 83
_____________________________________________________________________________ Conectiv Energy facilities in New Jersey. Among other things, the preliminary settlement agreement provides that: |
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The preliminary settlement agreement also provides that the parties will work toward a consent order or other final settlement document that reflects the terms of the preliminary settlement agreement. ACE, Conectiv and PHI continue to negotiate with the NJDEP the terms of a consent order or other final settlement document. |
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. |
Accounting Policy Choices |
Pepco Holdings' management believes that based on the nature of the businesses in which its subsidiaries are primarily engaged, Pepco Holdings has very little choice regarding many of the accounting policies it utilizes. In that regard, the most significant portion of Pepco Holdings' business consists of its regulated utility operations, which are subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 does allow regulated entities, in appropriate circumstances, to establish regulatory assets and regulatory liabilities and to defer the income statement impact of certain costs that are expected to be recovered in future rates. However, management believes that in the areas that Pepco Holdings is afforded accounting policy choices, its selection from among the alternatives available generally would not have a material impact on the Compan y's financial condition or results of operations. |
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 (refer to the "Relationship with Mirant" section, herein), the calculation of future cash flows and fair value amounts for use in goodwill and asset impairment evaluations, fair value calculations (based on estimating market pricing) associated with derivative instruments, pension and other post-retirement 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 our business. We record an estimated liability for these proceedings and claims based upon the probable and reasonably estimatable 85
_____________________________________________________________________________ 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 presently available. Actual results may differ significantly from these estimates. |
Goodwill Impairment Evaluation |
Pepco Holdings believes that the estimates involved in its goodwill impairment evaluation process represent "Critical Accounting Estimates" because they (i) 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 or 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. Pepco Holdings' goodwill that was 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, 2004. This testing concluded that Pepco Holdings' goodwill balance was not impaired. A hypothetical decrease in PHI 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 they (i) 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 shall 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 to not 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 86
_____________________________________________________________________________ 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, discussed above. |
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. Refer to Note 2, Summary of Significant Accounting Policies - Accounting for Derivatives, herein, 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. Models are also used to estimate volumes for certain transactions. The same valuation methods are used to determine the value of non-derivative, commodity exposure for risk management purposes. |
Pension and Other Post-retirement Benefit Plans |
Pepco Holdings believes that the estimates involved in reporting the costs of providing pension and other post-retirement 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 post-retirement benefit liability on the balance sheet, and the reported annual net periodic pension and other post-retirement 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 benef it obligations could result in a $5 million impact on its consolidated balance sheets and income statements. 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 income statements and a .25% change in the assumed healthcare cost trend rate could result in a $.5 million impact on its consolidated balance sheets and income statements. Pepco Holdings' management consults with its actuaries and investment consultants when selecting its plan assumptions. 87
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Pepco Holdings follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions," and SFAS No. 106, "Employers' Accounting for Post-retirement 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 post-retirement obligations is generally recognized over the working lives of the employees who benefit under the plans rather than immediately recognized in the income statement. Plan assets are stated at their market value as of the measurement date, December 31. |
Regulation of Power Delivery Operations |
The requirements of SFAS No. 71 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. |
New Accounting Policies Issued |
SFAS 123R |
In December 2004, the FASB issued Statement No. 123 (revised 2004), "Share-Based Payment" which establishes standards for the accounting for transactions in which an entity exchanges its equity instruments primarily for employee services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity's equity instruments or that may be settled by the issuance of those equity instruments. In most cases, FAS 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award and to recognize that cost over the service period, normally the vesting period. FAS 123R will be effective for Pepco Holdings as of the July 1, 2005. Pepco Holdings is in the process of evaluating the impact of FAS 123R and does not anticipate that its implementation will hav e a material effect on its overall financial position or net results of operations. |
RISK FACTORS |
The business 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 results of operations and financial condition. |
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 is a registered public utility holding company that is subject to regulation by the SEC under PUHCA. As a registered public utility holding 88
_____________________________________________________________________________ company, PHI requires SEC approval to, among other things, issue securities, acquire or dispose of utility assets or securities of utility companies and acquire other businesses. In addition, under PUHCA transactions among PHI and its subsidiaries generally must be performed at cost and subsidiaries are prohibited from paying dividends out of capital or unearned surplus without SEC approval. |
The utility businesses conducted by PHI's power delivery subsidiaries 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 public service commissions in its service territories, with respect to, among other things, the rates it can charge retail customers for the delivery of electricity. In addition, the rates that the companies can charge for electricity transmission are regulated by FERC. The companies cannot change delivery or transmission rates without approval by the applicable regulatory authority. While the approved delivery 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 it s 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 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, the Mirant bankruptcy could adversely affect PHI's business. See "Relationship with Mirant Corporation," herein. |
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 89
_____________________________________________________________________________ accumulated deferred investment tax credits, and Pepco might be unable to use accelerated depreciation on District of Columbia and Maryland allocated or assigned property. See Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters." |
The operating results of PHI's power delivery and competitive energy subsidiaries fluctuate on a seasonal basis and can be adversely affected by changes in weather. |
The businesses of PHI's power delivery and competitive energy subsidiaries 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. Accordingly, PHI's power delivery and competitive energy subsidiaries historically have generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. |
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. |
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 good 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 operatin g 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 subsidiaries 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, Maryland, New Jersey, Ohio, Pennsylvania, 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 o n the operations of the other utilities. However, the systems put in 90
_____________________________________________________________________________ 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. |
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. |
PHI's competitive energy business is 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 power marketers and brokers, and traditional utilities that continue to operate generation assets. 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 and distribution assets that they do not own or control to deliver wholesale electricity and to obtain fuel for their generation facilities. |
PHI's competitive energy businesses depend upon transmission facilities owned and operated by others for delivery to customers. The operation of their generation facilities also depends upon coal, natural gas or diesel fuel supplied by others. If electric transmission is disrupted or capacity is inadequate or unavailable, the competitive energy businesses' ability to sell and deliver wholesale power, 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 91
_____________________________________________________________________________ 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, microturbines and photovoltaic (solar) cells. It is possible that advances in these or other alternative technologies will reduce the costs of electricity production from these technologies, thereby making the generating facilities of PHI's competitive energy businesses less competitive. In addition, increased conservation efforts and advances in technology could reduce demand for electricity supply and distribution, which could adversely affect 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 businesses. |
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 the potential one-day favorable or unfavorable price movement. These estimates are based on historical price volatility and assume a normal distribution of price changes. 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. Conectiv Energy's goal is to hedge 75% of both the expected power output of its generation facilities and the costs of fuel used to operate those facilities. However, the actual level of hedging coverage may vary from these goals. The economic hedge goals are approved by PHI's Corporate Risk Management Committee and may change from time to time based on market conditions. Due to the high heat rate of the Pepco Energy Services power plant generation, Pepco Energy Services infrequently locks in the f orward value of these plants with wholesale contracts. To the extent that PHI's competitive energy businesses have unhedged positions or their hedging procedures do not work as planned, fluctuating commodity prices could result in significant losses. |
The expiration of certain hedging arrangements could result in exposure of Conectiv Energy to a higher level of commodity price risk. 92
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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 35-month 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 POLR and SOS supply commitment to DPL which extends through May 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 elect ricity generated by Conectiv Energy's plants (excluding the Edge Moor facility). |
This series of energy contracts will terminate in May 2006. As a result, Conectiv Energy will be exposed to a higher level of commodity price risk, unless it were to replace the expiring contracts with new or similar contracts to hedge plant output and any future supply obligations that Conectiv Energy might enter into. Conectiv Energy cannot at this time predict whether or to what extent it will, or will be able to, enter into new hedging contracts that provide commodity price risk protection. |
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. 93
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PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which as of December 31, 2004 had a book value of approximately $1.2 billion. 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. |
PHI believes there is a substantial likelihood that the IRS will challenge the tax benefits realized from the interest and depreciation deductions claimed by PCI with respect to these transactions, or the timing of these benefits, for the years 2001 through 2004. The tax benefits claimed by PCI for these years were approximately $175 million. 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 flow. |
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." |
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, would increase the cost of borrowing or could adversely affect their ability to access one or more financial markets. Disruptions to the capital markets could include, but are not limited to: |
The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue). Regulated T&D (Transmission & Distribution) 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 (DSR) also known as Standard Offer Service (SOS) consists of revenue Pepco receives from the supply of electricity at regulated rates. The costs related to the supply of electricity are included in Fuel and Purchased Energy. Other Electric Revenue includes work and services performed on behalf of customers including other utilities, which is not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rents, late payments, and col lection fees. |
Regulated T&D Electric Revenue |
Regulated T&D Electric Revenue increased by $58.6 million primarily due to the following: (i) $12.4 million increase due to sales growth of 2.4%, (ii) $10.4 million increase due to favorable weather, and (iii) $39.9 million increase in tax pass-throughs, primarily a county surcharge (offset in Other Taxes) reduced by (iv) $3.3 million decrease related to PJM network transmission revenue. Delivery sales were approximately 26,902,000 MwH, compared to approximately 25,994,000 MwH for the comparable period in 2003. Cooling degree days increased by 19.5% and heating degree days decreased by 6.5% for the year ended December 31, 2004 as compared to the same period in 2003. |
Default Supply Revenue |
Default Supply Revenue increased by $185.3 million primarily due to higher retail energy rates, the result of an effective rate increase in Maryland beginning in July 2004 and lower customer migration, principally in DC. |
For the twelve months ended December 31, 2004, Pepco's Maryland customers served by an alternate supplier represented 29% of Pepco's total 99
_____________________________________________________________________________ Maryland load, and Pepco's DC customers served by an alternate supplier represented 32% of Pepco's total DC load. For the twelve months ended December 31, 2003, Pepco's Maryland customers served by an alternate supplier represented 30% of Pepco's total Maryland load, and Pepco's DC customers served by an alternate supplier represented 48% of Pepco's total DC load. |
Default Supply sales were approximately 18,819,000 MwH for the twelve months ended December 31, 2004, compared to approximately 16,199,000 MwH for the comparable period in 2003. |
Other Electric Revenue |
Other Electric Revenue increased by $14.0 million primarily due to increased customer requested work for the year ended December 31, 2004 (offset in Other Operation and Maintenance). |
Operating Expenses |
Fuel and Purchased Energy |
Fuel and Purchased Energy increased by $215.2 million to $899.3 million in 2004, from $684.1 million in 2003. The increase was primarily due to the following: (i) $180.6 million higher energy costs, the result of the new Default Supply rates for Maryland beginning in July 2004, and less customer migration, principally in DC, (ii) $74.6 million higher costs due to an increased rate change from the TPA Settlement with Mirant, effective October 2003, and (iii) $4.0 million higher PJM network transmission costs. These increases were partially offset by (i) $29.5 million reduction in the General Procurement Credit (GPC) which resulted from the lower Default Supply margin, and (ii) $14.5 million reserve recorded in September 2003 to reflect a potential exposure related to a pre-petition receivable from Mirant Corp. for which Pepco filed a creditor's claim in the bankruptcy proceedings. See the Regulatory and Other Matters - Relationship with Mirant section herein for additional information related to Mirant. |
Other Operation and Maintenance |
Other Operation and Maintenance increased by $33.8 million to $272.3 million in 2004, from $238.5 million in 2003. The increase was primarily due to (i) $12.1 million of customer requested work (offset in Other Electric Revenue), (ii) $9.7 million higher electric system operation and maintenance costs, (iii) $4.8 million for severance costs, (iv) $2.8 million for right of way maintenance, (v)$2.7 million for the uncollectible and claims reserve, (vi) $3.3 million for Sarbanes-Oxley external compliance costs, (vii) $2.5 million for legal and commission fees, (viii) $2.5 million for deferred costs and inventory adjustments, (ix) $2.5 million bad debt expense, offset by (x) $7.1 million for storm costs primarily related to one time charges related to Hurricane Isabel in September 2003 and (xi) $2.0 million decrease in other costs. |
Depreciation and Amortization |
Depreciation and Amortization expenses decreased by $3.5 million to $166.3 million in 2004 from $169.8 million in 2003. The decrease is primarily due to a $4.1 million decrease in energy use management (EUM) amortization. 100
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Other Taxes |
Other Taxes increased by $42.2 million to $248.7 million in 2004, from $206.5 million in 2003. The increase was primarily due to (i) pass-throughs of $33.9 million higher county surcharge and $3.6 million higher gross receipts/delivery taxes (offset in Regulated T&D Electric Revenue), (ii) $1.4 million higher Public Service Commission fees, (iii) $1.1 million county Right-of-Way fee adjustment in 2003, and (iv) $.8 million higher use tax. |
Gain on Sale of Assets |
GainonSale of Assets increased by $6.9 million primarily resulting from $6.6 million for the sale of land in the first quarter of 2004. |
Other Income (Expenses) |
Other Expenses increased by $2.1 million to a net expense of $72.9 million in 2004 from a net expense of $70.8 million in 2003. This was primarily due to $2.5 million lower interest income. |
Preferred Stock Dividend Requirements |
Preferred Stock Dividend Requirements decreased by $6.9 million from 2003. Of this decrease $4.6 million resulted from lower dividends in 2004 due to the redemption of the Trust Originated Preferred Securities in 2003 and $1.6 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. |
Income Tax Expense |
Pepco's effective tax rate for 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). |
Pepco's effective tax rate for 2003 was 40% 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. |
The results of operations discussion below is for the year ended December 31, 2003 compared to the year ended December 31, 2002. |
Lack Of Comparability Of Operating Results With Prior Years |
Pepco's results of operations for the year ended December 31, 2003 include only its operations. However, Pepco's results of operations for the year ended 2002, as previously reported by Pepco, include Pepco's operations consolidated with its pre-merger subsidiaries' (Potomac Capital Investment Corporation (PCI) and Pepco Energy Services) operations through July 2002. Accordingly, the results of operations for 2003 and 2002 are not comparable. In connection with Pepco's acquisition of Conectiv in August 2002, PCI and Pepco Energy Services were transferred to PHI. 101
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Operating Revenue |
Pepco's consolidated operating revenue decreased by $440.0 million to $1,548.0 million in 2003 from $1,988.0 million in 2002. This decrease was primarily due to a decrease in operating revenue recognized of $401.0 million at Pepco Energy Services and a decrease of $53.1 million at PCI. These decreases were due to the fact that Pepco Energy Services and PCI's operating results were not recorded by Pepco in 2003 because subsequent to July 2002 their ownership was transferred to PHI. These decreases were partially offset by an increase of $14.1 million in Pepco's operating revenue due to the following: |
Regulated T&D Electric Revenue increased by $18.5 million in 2003. This increase results from a $19.2 million increase from a fuel tax pass-through, partially offset by a $.7 million decrease in Regulated T&D Electric Revenue. The $.7 million decrease resulted from a .6% decrease in delivered kilowatt-hour sales. |
DSR increased by $4.2 million in 2003 due to colder winter weather as heating degree days increased by 12.2% offset by a 30.2% decrease in cooling degree days. |
Pepco's retail access to a competitive market for generation services was made available to all Maryland customers on July 1, 2000 and to D.C. customers on January 1, 2001. At December 31, 2003, 14% of Pepco's Maryland customers and 11% of its D.C. customers have chosen alternate suppliers. These customers accounted for 912 megawatts of load in Maryland (of Pepco's total load of 3,439) and 970 megawatts of load in D.C. (of Pepco's total load of 2,269). At December 31, 2002, 16% of Pepco's Maryland customers and 13% of its D.C. customers have chosen alternate suppliers. These customers accounted for 1,175 megawatts of load in Maryland (of Pepco's total load of 3,369) and 1,140 megawatts of load in D.C. (of Pepco's total load of 2,326). |
Other Electric Revenue decreased $8.6 million primarily due to lower capacity (megawatts) available to sell, lower capacity market rates and restructuring in the PJM market. |
Operating Expenses |
Fuel and Purchased Energy |
Pepco's consolidated fuel and purchased energy decreased by $310.6 million to $684.1 million in 2003 from $994.7 million in 2002. This decrease was primarily due to a decrease in fuel and purchases energy recognized of $340.3 million at Pepco Energy Services due to the fact that Pepco Energy Services operating results were not recorded by Pepco in 2003 because subsequent to July 2002 its ownership was transferred to PHI. This decrease was partially offset by an increase of $29.7 million at Pepco primarily due to the recording of a $14.5 million reserve to reflect a potential exposure related to a pre-petition receivable from Mirant Corp., for which Pepco filed a creditor's claim in bankruptcy proceedings and from $15.3 million higher SOS costs. |
Other Operation and Maintenance |
Pepco's consolidated other operation and maintenance decreased by $78.4 million to $238.5 million in 2003 from $316.9 million in 2002. This decrease was primarily due to a decrease in other operation and maintenance expense recognized of $57.9 million at Pepco Energy Services and a decrease of $24.6 million at PCI. These decreases were due to the fact that Pepco Energy 102
_____________________________________________________________________________ Services and PCI's operating results were not recorded by Pepco in 2003 because subsequent to July 2002 their ownership was transferred to PHI. These decreases were partially offset by an increase of $4.1 million in Pepco's other operation and maintenance expense due to storm restoration expenses incurred. |
Depreciation and Amortization |
Pepco's consolidated depreciation and amortization increased by $16.5 million to $169.8 million in 2003 from $153.3 million in 2002. This increase was primarily due to an increase at Pepco of $11.6 related to software amortization during the year, partially offset by a decrease of $1.7 million at Pepco Energy Services and $3.2 million at PCI due to the fact that Pepco Energy Services and PCI's operating results were not recorded by Pepco in 2003 because subsequent to July 2002 their ownership was transferred to PHI. |
Other Taxes |
Pepco's consolidated other taxes increased by $8.3 million to $206.5 million in 2003, from $198.2 million for the corresponding period in 2002. This increase was due to higher fuel taxes over the period. |
Other Income (Expenses) |
Pepco's consolidated other expenses decreased by $25.5 million to $70.8 million in 2003 from $96.3 million for the corresponding period in 2002. This decrease was primarily due to a decrease in operating revenue recognized of $19.8 at PCI, partially offset by a $3.1 million increase at Pepco. The decrease at PCI was due to the fact that its operating results were not recorded by Pepco in 2003 because subsequent to July 2002 its ownership was transferred to PHI. |
Income Tax Expense |
Pepco's effective tax rate in 2003 was 40% as compared to the federal statutory rate of 35%. The major reasons for this difference are state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences. In 2002, the effective rate was 37% as compared to the federal statutory rate of 35%. The major reasons for this difference are state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences, partially offset by the inclusion of the tax benefits of Pepco's pre-merger subsidiaries through July 2002. |
CAPITAL RESOURCES AND LIQUIDITY |
General |
Financing Activities |
Pepco issued $275 million of secured senior notes with maturities of 10 and 30 years. Proceeds of $272.8 million were used to redeem higher interest rate securities of $210 million and to repay short-term debt of $56.6 million. Pepco borrowed $100 million under a bank loan due in 2006. Proceeds were used to redeem Mandatorily Redeemable Preferred Stock of $42.5 million and to repay short-term debt. 103
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Working Capital |
At December 31, 2004, Pepco's current assets on a consolidated basis totaled $354.4 million and its current liabilities totaled $416.1 million. At December 31, 2003, PHI's current assets totaled $347.2 million and its current liabilities totaled $418.6 million. |
Pepco's working capital deficit results in large part from the fact that, in the normal course of business, it acquires energy supplies for its customers before the supplies are delivered to, metered and then billed to customers. Short-term financings are used to meet liquidity needs. Short-term financings are also used, at times, to temporarily fund redemptions of long-term debt, until long-term replacement issues are completed. |
Summary of Cash Flows |
Pepco's cash flows for 2004, 2003, and 2002 are summarized below. |
Sources Of Capital |
Pepco's sources to meet its long-term funding needs, such as capital expenditures, and its short-term funding needs, such as working capital and the temporary funding of long-term funding needs, include internally generated funds, security issuances and bank financing under new or existing facilities. Pepco'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. |
Short-Term Funding Sources |
Pepco has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. |
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. |
In July 2004, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $650 million. This agreement replaced a $550 million 364-day credit agreement that was entered into on July 29, 2003. The respective companies also are parties to a three-year credit agreement that was entered into in July 2003 and terminates in July 2006 with an aggregate borrowing limit of $550 million. Pepco Holdings' credit limit under these facilities is $700 million, and the credit limit of each of Pepco, DPL and ACE under these facilities is the lower of $300 million and the maximum amount of short-term debt authorized by the appropriate state commission, except that the aggregate amount of credit utilized by Pepco, DPL and ACE at any given time under these facilities may not exceed $500 million. Funds borrowed under these facilities are available for general corporate purposes. Either credit facility also can be used as credit support for the commercial paper programs of the respective companies. 107
_____________________________________________________________________________ The three-year and five-year credit agreements contain customary financial and other covenants that, if not satisfied, could result in the acceleration of repayment obligations under the agreements or restrict the ability of the companies to borrow under the agreements. Among these covenants is 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 agreements. As of December 31, 2004, the applicable ratios for Pepco Holdings, Pepco, DPL and ACE were 59.0%, 58.5%, 52.1% and 50.2%, respectively. The credit agreements also contain a number of customary events of default that could result in the acceleration of repayment obligations under the agreements, including (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 agreements) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE. |
In December 2004, PHI entered into a $50 million term loan due December 13, 2005 with a bank. The loan is variable rate, based on LIBOR. PHI has the option to select interest periods based on one, two, three or six month LIBOR rates. The covenants in the agreement are substantially consistent with those found in the three-year and five-year credit agreements. Proceeds from the loan were used to pay down commercial paper. |
Long-Term Funding Sources |
The sources of long-term funding for Pepco 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 refund or refinance existing securities. |
PUHCA Restrictions |
An SEC Financing Order dated July 31, 2002 (the "Financing Order"), requires that, in order to issue debt or equity securities, including commercial paper, Pepco 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) of at least 30 percent. At December 31, 2004 and 2003, Pepco's common equity ratio was 42.8 percent and 43.4 percent, respectively. The Financing Order also requires that all rated securities issued by Pepco be rated "investment grade" by at least one nationally recognized rating agency. Accordingly, if Pepco's common equity ratio were less than 30 percent or if no nationally recognized rating agency rated a security investment grade, Pepco could not issue the security without first obtaining from the SEC an amendment to the Financing Order. |
If an amendment to the Financing Order is required to enable Pepco to effect a financing, there is no certainty that such an amendment could be obtained, as to the terms and conditions on which an amendment could be obtained or as to the timing of SEC action. The failure to obtain timely relief from the SEC, in such circumstances, could have a material adverse effect on the financial condition of Pepco. 108
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Other Liquidity Considerations |
For a discussion of the potential impact of the Mirant bankruptcy on liquidity, see "Relationship with Mirant Corporation" section that follows. |
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., pursuant to an Asset Purchase and Sale Agreement. As part of the Asset Purchase and Sale Agreement, Pepco entered into several ongoing contractual arrangements with Mirant and certain of its subsidiaries (collectively, Mirant). On July 14, 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). |
Depending on the outcome of the matters discussed below, the Mirant bankruptcy could have a material adverse effect on the results of operations of Pepco Holdings and Pepco. However, management currently 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 have arisen or may arise due to the Mirant bankruptcy. Accordingly, management does not anticipate that the Mirant bankruptcy will impair the ability of Pepco Holdings or Pepco to fulfill their 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 these agreements, Mirant was obligated to supply Pepco with all of the capacity and energy needed to fulfill its standard offer service obligations in Maryland through June 2004 and its standard offer service obligations in the District of Columbia through January 22, 2005. |
To avoid the potential rejection of the TPAs, Pepco and Mirant entered into an Amended Settlement Agreement and Release dated as of October 24, 2003 (the Settlement Agreement) pursuant to which Mirant assumed both of the TPAs and the terms of the TPAs were modified. The Settlement Agreement also provided that Pepco has an allowed, pre-petition general unsecured claim against Mirant Corporation in the amount of $105 million (the Pepco TPA Claim). |
Pepco has also asserted the Pepco TPA Claim against other Mirant entities that Pepco believes are liable to Pepco under the terms of the Asset Purchase and Sale Agreement's Assignment and Assumption Agreement (the Assignment Agreement). Under the Assignment Agreement, Pepco believes that each of the Mirant entities assumed and agreed to discharge certain liabilities and obligations of Pepco as defined in the Asset Purchase and Sale Agreement. Mirant has filed objections to these claims. Under the current plan of reorganization filed by the Mirant entities with the Bankruptcy Court, certain Mirant entities other than Mirant Corporation would 109
_____________________________________________________________________________ pay significantly higher portions of the claims of their creditors than would Mirant Corporation. The amount that Pepco will be able to recover from the Mirant bankruptcy estate with respect to the Pepco TPA Claim will depend on the amount of assets available for distribution to creditors of the Mirant entities that are found to be liable for the Pepco TPA Claim. |
Power Purchase Agreements |
Under agreements with FirstEnergy Corp., formerly Ohio Edison (FirstEnergy), and Allegheny Energy, Inc., both entered into in 1987, Pepco is obligated to purchase from FirstEnergy 450 megawatts of capacity and energy annually through December 2005 (the FirstEnergy PPA). Under an agreement with Panda, entered into in 1991, Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (the Panda PPA). In each case, the purchase price is substantially in excess of current 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 is obligated, among other things, to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the FirstEnergy PPA and the Panda PPA at a price equal to the price Pepco is obligated to pay under the FirstEnergy PPA and the Panda PPA (the PPA-Related Oblig ations). |
Pepco Pre-Petition Claims |
When Mirant filed its bankruptcy petition on July 14, 2003, Mirant had unpaid obligations to Pepco of approximately $29 million, consisting primarily of payments due to Pepco in respect of the PPA-Related Obligations (the Mirant Pre-Petition Obligations). The Mirant Pre-Petition Obligations constitute part of the indebtedness for which Mirant is seeking relief in its bankruptcy proceeding. Pepco has filed Proofs of Claim in the Mirant bankruptcy proceeding in the amount of approximately $26 million to recover this indebtedness; however, the amount of Pepco's recovery, if any, is uncertain. The $3 million difference between Mirant's unpaid obligation to Pepco and the $26 million Proofs of Claim primarily represents a TPA settlement adjustment which is included in the $105 million Proofs of Claim filed by Pepco against the Mirant debtors in respect of the Pepco TPA Claim. In view of this uncertainty, Pepco, in the third quarter of 2003, expen sed $14.5 million to establish a reserve against the $29 million receivable from Mirant. In January 2004, Pepco paid approximately $2.5 million 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. Pepco believes that under the terms of the Asset Purchase and Sale Agreement, Mirant is obligated to reimburse Pepco for the settlement payment. Accordingly, in the first quarter of 2004, Pepco increased the amount of the receivable due from Mirant by approximately $2.5 million and amended its Proofs of Claim to include this amount. Pepco currently estimates that the $14.5 million expensed in the third quarter of 2003 represents the portion of the entire $31.5 million receivable unlikely to be recovered in bankruptcy, and no additional reserve has been established for the $2.5 million increase in the receivable. The amount expensed represents Pepco's estimate of the possible outcome in bankruptcy, although the amou nt ultimately recovered could be higher or lower. |
Mirant's Attempt to Reject the PPA-Related Obligations |
On August 28, 2003, Mirant filed with the Bankruptcy Court a motion seeking authorization to reject its PPA-Related Obligations. Upon motions filed with the U.S. District Court for the Northern District of Texas (the 110
_____________________________________________________________________________ District Court) by Pepco and FERC, in October 2003, the District Court withdrew jurisdiction over the rejection proceedings from the Bankruptcy Court. In December 2003, the District Court denied Mirant's motion to reject the PPA-Related Obligations on jurisdictional grounds. The District Court's decision was appealed by Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation (the Creditors' Committee) to the U.S. Court of Appeals for the Fifth Circuit (the Court of Appeals). On August 4, 2004, the Court of Appeals remanded the case to the District Court saying that the District Court has 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. |
On December 9, 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. On December 16, the Creditors' Committee appealed the District Court's order to the Court of Appeals, and on December 20, 2004, Mirant also appealed the District Court's order. |
As more fully discussed below, Mirant had been making regular periodic payments in respect of the PPA-Related Obligations. On December 9, 2004, Mirant filed a notice with the Bankruptcy Court that it was suspending payments to Pepco in respect of the PPA-Related Obligations. On December 13, 2004, Mirant failed to make a payment of approximately $17.9 million due to Pepco for the period November 1, 2004 to November 30, 2004. Mirant failed to make that payment. On December 23, 2004, Pepco received a payment of approximately $6.8 million from Mirant, which according to Mirant represented the market value of the power for which payment was due on December 13. Mirant has informed Pepco that it intends to continue to pay the market value, but not the above-market portion, of the power purchased under the PPA-Related Obligations. Pepco disagrees with Mirant's assertion that it need only pay the market value and believes that the amount repr esenting the market value calculated by Mirant is insufficient. |
On January 21, 2005, Mirant made a approximately $21.1 million, which, according to Mirant, includes the payment for the FirstEnergy PPA for December 2004 and "includes the December 2004 TPA revenue in the amount of $29,093,173.43, the TPA costs in the amount of $37,865,924.10, and an allocated share of [FirstEnergy's] PPA bill credits/charges in the amount of $5,490,164.79." Pepco disputes Mirant's contention that the amount paid reflects the full amount due Pepco under these agreements for the applicable periods. |
As of March 1, 2005, Mirant has withheld payment of approximately $34.8 million due to Pepco under the PPA-Related Obligations. |
On January 21, 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. On March 1, 2005 (as amended by order dated March 7, 2005), the District Court granted Pepco's motion to withdraw jurisdiction over the Asset Purchase and Sale Agreement rejection proceedings from the Bankruptcy Court. In addition, the District Court ordered Mirant to pay on March 18, 2005, all past-due unpaid amounts under the PPA-Related Obligations. Mirant has filed a motion for reconsideration and a stay of the March 1, 2005 order. 111
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Pepco is exercising all available legal remedies and vigorously opposing Mirant's attempt to reject the PPA-Related Obligations and other 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 the attempt to reject the agreements, the outcome of Mirant's efforts to reject the PPA-Related Obligations is uncertain. |
If Mirant ultimately is successful in rejecting the PPA-Related Obligations, Pepco could be required to repay to Mirant, for the period beginning on the effective date of the rejection (which date could be prior to the date of the court's order and possibly as early as September 18, 2003) and ending on the date Mirant is entitled to cease its purchases of energy and capacity from Pepco, all amounts paid by Mirant to Pepco in respect of the PPA-Related Obligations, less an amount equal to the price at which Mirant resold the purchased energy and capacity. Pepco estimates that the amount it could be required to repay to Mirant in the unlikely event that September 18, 2003, is determined to be the effective date of rejection, is approximately $133.2 million as of March 1, 2005 (assuming Mirant continues to withhold unpaid amounts of approximately $34.8 million as of March 1, 2005. |
Mirant has also indicated to the Bankruptcy Court that it will move to require Pepco to disgorge all amounts paid by Mirant to Pepco in respect of the PPA-Related Obligations, less an amount equal to the price at which Mirant resold the purchased energy and capacity, for the period July 14, 2003 (the date on which Mirant filed its bankruptcy petition) through rejection, if approved, on the theory that Mirant did not receive value for those payments. Pepco estimates that the amount it would be required to repay to Mirant on the disgorgement theory, in addition to the amounts described above, is approximately $22.5 million. |
Any repayment by Pepco of amounts paid by Mirant would entitle Pepco to file a claim against the bankruptcy estate in an amount equal to the amount repaid. Pepco believes that, to the extent such amounts were not recovered from the Mirant bankruptcy estate, they would be recoverable as stranded costs from customers through distribution rates as described below. |
The following are estimates prepared by Pepco of its potential future exposure if Mirant's attempt to reject the PPA-Related Obligations ultimately is successful. 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. The estimates assume no recovery from the Mirant bankruptcy estate and no regulatory recovery, either of which would mitigate the effect of the estimated loss. Pepco does not consider it realistic to assume that there will be no such recoveries. Based on these assumptions, Pepco estimates that its pre-tax exposure as of March 1, 2005, representing the loss of the future benefit of the PPA-Related Obligations to Pepco, is as follows: |
The ability of Pepco to recover from the Mirant bankruptcy estate in respect to the Mirant Pre-Petition Obligations and damages if the PPA-Related Obligations are successfully rejected will depend on whether Pepco's claims are allowed, the amount of assets available for distribution to the creditors of the Mirant companies determined to be liable for those claims, and Pepco's priority relative to other creditors. At the current stage of the bankruptcy proceeding, there is insufficient information to determine the amount, if any, that Pepco might be able to recover from the Mirant bankruptcy estate, whether the recovery would be in cash or another form of payment, or the timing of any recovery. |
If Mirant ultimately is successful in rejecting the PPA-Related Obligations and Pepco's full claim is not recovered from the Mirant bankruptcy estate, Pepco may 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, if Mirant ultimately is successful in rejecting the PPA-Related Obligations, 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 Pe pco's interpretation of the settlement agreements is confirmed, Pepco expects to be able to establish the amount of its anticipated recovery 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. |
If the PPA-Related Obligations are successfully rejected, and there is no regulatory recovery, Pepco will incur a loss. However, the accounting treatment of such a loss depends on a number of legal and regulatory factors, and is not determinable at this time. |
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, Inc. (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 facility and capacity credit 113
_____________________________________________________________________________ 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. Pepco believes that there is no reasonable factual or legal basis to support Mirant's contention that the SMECO Agreement is a lease of real property. Litigation continues and the outcome of this proceeding cannot be predicted. |
Rate Proceedings |
In compliance with the settlement approved by the MPSC in connection with the merger of Pepco and Conectiv, on December 4, 2003, Pepco submitted testimony and supporting schedules to review and reset if necessary its electricity distribution rates in Maryland to be effective July 1, 2004, when the then-current distribution rate freeze/caps ended. Pepco's filing demonstrated that it was in an under-earning situation. However the merger settlement provided that Pepco's distribution rates after July 1, 2004 could only remain the same or be decreased. With limited exceptions, Pepco cannot increase its distribution rates until January 1, 2007. In an order dated July 6, 2004 the MPSC affirmed the Hearing Examiner's recommendation that no rate decrease was warranted at that time. |
On July 3, 2004, Pepco filed a distribution rate review case with the DCPSC as required by the terms of the Pepco-Conectiv merger settlement approved by the DCPSC. This case will determine whether Pepco's distribution rates will be decreased. In accordance with the terms of the merger settlement, Pepco's distribution rates cannot be increased as a result of the case. On November 24, 2004, the DCPSC issued an order that designated the issues to be considered in the case and set the hearing schedule. On December 17, 2004, Pepco filed supplemental direct testimony addressing the DCPSC-designated issues. Pepco's filings indicate that no rate decrease is warranted. On March 4, 2005, the DCPSC issued an order granting a joint motion filed on March 3, 2005, on behalf of Pepco and several other parties in the case to suspend the procedural schedule to allow the parties to focus on completing settlement discussions. In the joint motion, the movin g parties informed the DCPSC that they had agreed in principle to settlement provisions that would resolve all issues in the proceeding and that a settlement agreement could be filed in the near future. |
Divestiture Cases |
District of Columbia |
Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed on July 31, 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. 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. On March 4, 2003, the Internal Revenue Service (IRS) issued a notice of proposed rulemaking (NOPR) that is relevant to that principal issue. Comments on the NOPR were filed by several parties on June 2, 2003, and the IRS held a public hearing on June 25, 2003. As a result of the NOPR, 114
_____________________________________________________________________________ three of the parties in the divestiture case filed comments with the DCPSC urging the DCPSC to decide the tax issues now on the basis of the proposed rule. Pepco filed comments with the DCPSC in reply to those comments, in which Pepco stated that the courts have held and the IRS has stated that proposed rules are not authoritative and that no decision should be issued on the basis of proposed rules. Instead, Pepco argued that the only prudent course of action is for the DCPSC to await the issuance of final regulations relating to the tax issues and then allow the parties to file supplemental briefs on the tax issues. Pepco cannot predict whether the IRS will adopt the regulations as proposed, make changes before issuing final regulations or decide not to adopt regulations. Other issues in the proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture. |
Pepco believes that a sharing of EDIT and ADITC would violate the normalization rules. 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. Pepco, in addition to sharing with customers the generation-related ADITC balance, would have to pay to the IRS an amount equal to Pepco's $5.8 million District of Columbia jurisdictional generation-related ADITC balance as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance 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. As of December 31, 2004, the District of Columbia jurisdictional transmission and distribution-related ADITC balance was approximately $6.0 million. |
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 D.C. 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 condition. It is uncertain when the DCPSC will issue a decision. |
Maryland |
Pepco filed its divestiture proceeds plan application in Maryland in April 2001. Reply briefs were filed in May 2002. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that was raised in the D.C. case. As of December 31, 2004, the Maryland 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 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 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, i.e., $9.1 million, and the generation-related ADITC. If such sharing were to 115
_____________________________________________________________________________ violate the normalization rules, Pepco, in addition to sharing with customers an amount equal to approximately 50 percent of the generation-related ADITC balance, would be unable to use accelerated depreciation on Maryland allocated or assigned property. Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco's $10.4 million Maryland jurisdictional generation-related ADITC balance, as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance 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. As of December 31, 2004, the Maryland retail jurisdictional transmission and distribution-related ADITC balance was approximately $10.7 million. The Hearing Examiner decided all other issues in favor of Pepco, except that only one-half of the severance payments that Pepco included in its calculation of corporate reorga nization costs should be deducted from the sales proceeds before sharing of the net gain between Pepco and customers. See also the disclosure above under "Divestiture Cases - District of Columbia" regarding the March 4, 2003 IRS NOPR. |
Under Maryland law, if the proposed order is appealed to the MPSC, the proposed order is not a final, binding order of the MPSC and further action by the MPSC is required with respect to this matter. Pepco has appealed the Hearing Examiner's decision on the treatment of EDIT and ADITC and corporate reorganization costs to the MPSC. Pepco cannot predict what the outcome of the appeal will be or when the appeal might be decided. 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 a dverse 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 condition. |
SOS and Default Service Proceedings |
District of Columbia |
In February 2003, the DCPSC opened a new proceeding to consider issues relating to (a) the establishment of terms and conditions for providing standard offer service (SOS) in the District of Columbia after Pepco's obligation to provide SOS terminated on February 7, 2005, and (b) the selection of a new SOS provider. |
In December 2003, the DCPSC issued an order that set forth the terms and conditions for the selection of a new SOS provider(s) and the provision of SOS by Pepco on a contingency basis. In December 2003, the DCPSC also issued an order adopting terms and conditions that would apply if Pepco continued as the SOS provider after February 7, 2005. In March 2004, the DCPSC issued an order adopting the wholesale SOS model, i.e., Pepco would continue to be the SOS provider in the District of Columbia after February 7, 2005. This March 2004 order, as amended by a DCPSC order issued in July 2004, extends Pepco's obligation to provide default electricity supply at market rates for up to an additional 76 months for small commercial and residential customers, and for an additional 28 months for large commercial customers. |
In August 2004, the DCPSC issued an order adopting administrative charges for residential, small and large commercial DC SOS customers that are 116
_____________________________________________________________________________ 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 $0.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial DC 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 DC 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 DC SOS sales on February 8, 2005. Pepco completed the first competitive procurement process for DC SOS at the end of October and filed the proposed new SOS rates with the DCPSC on November 3, 2004. |
The TPA with Mirant under which Pepco obtained the fixed-rate DC 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 DC 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 DC SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new DC 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 DC SOS contracts and the DC SOS rates charged to customers for the period from February 1 to February 7, 2005. The total amount of the diff erence is estimated to be approximately $8.7 million. This difference, however, will be included in the calculation of the Generation Procurement Credit (GPC) for DC for the period February 8, 2004 through February 7, 2005. 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. Currently, based on the rates paid by Pepco to Mirant under the TPA Settlement, there is no customer sharing. However, in the event that Pepco were to ultimately realize a significant recovery from the Mirant bankruptcy estate associated with the TPA Settlement, the GPC would be recalculated, and the amount of customer sharing with respect to such recovery would be reduced because of the $8.7 million loss being included in the GPC calculation. |
Maryland |
Under a settlement approved by the MPSC in April 2003 addressing SOS service in Maryland following the expiration of Pepco's fixed-rate default supply obligations in July 2004, Pepco is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, Pepco purchases the power supply required to satisfy its market rate default supply obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the MPSC. Pepco is entitled to recover from its default supply customers the cost of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, small and large commercial Maryland SOS customers over the twelve months ended December 31, 200 3. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period. 117
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General Litigation |
Asbestos |
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, plaintiffs argue 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. Of the approximately 250 remaining asbestos cases pending against Pepco, approximately 85 cases were filed after December 19, 2000, and have been tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement. |
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 condition. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco's and PHI's results of operations. |
Environmental Litigation |
Pepco is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. Pepco may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. |
In October 1995, Pepco received notice from the Environmental Protection Agency (EPA) that it, along with several hundred other companies, might be a potentially responsible party (PRP) in connection with the Spectron Superfund Site in Elkton, Maryland. The site was operated as a hazardous waste disposal, recycling and processing facility from 1961 to 1988. |
In August 2001, Pepco entered into a consent decree for de minimis parties with EPA to resolve its liability at this site. Under the terms of the consent decree, which was approved by the U.S. District Court for the District of Maryland on March 31, 2003, Pepco made de minimis payments to the United States and a group of PRPs. In return, those parties agreed not to sue Pepco for past and future costs of remediation at the site and the United 118
_____________________________________________________________________________ States will also provide protection against third-party claims for contributions related to response actions at the site. The consent decree does not cover any damages to natural resources. However, Pepco believes that any liability that it might incur due to natural resource damage at this site would not have a material adverse effect on its financial condition or results of operations. |
In the early 1970s, Pepco sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In December 1987, Pepco was notified by EPA that it, along with a number of other utilities and non-utilities, was a PRP in connection with the PCB contamination at the site. |
In October 1994, Remedial Investigation/Feasibility Study including a number of possible remedies was submitted to the EPA. In December 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 June 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs to conduct the design and actions called for in its decision. On May 12, 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 2, 2003, the Bankruptcy Court confirmed a Reorganization Plan that incorporates the terms of a settlement among the debtors, the United States and a group of utility PRPs including Pepco. Under the settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site. |
As of December 31, 2004, Pepco had accrued $1.7 million to meet its liability for a site remedy. At the present time, it is not possible to estimate the total extent of EPA's administrative and oversight costs or the expense associated with a site remedy ultimately implemented. However, Pepco believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations. |
On April 7, 2000, approximately 139,000 gallons of oil leaked from a pipeline at a generating facility that was owned by Pepco at Chalk Point generating facility in Aquasco, Maryland. The pipeline was operated by Support Terminals Services Operating Partnership LP (ST Services), an unaffiliated pipeline management company. The oil spread from Swanson Creek to the Patuxent River and several of its tributaries. The area affected covers portions of 17 miles of shoreline along the Patuxent River and approximately 45 acres of marshland adjacent to the Chalk Point property. |
In December 2000, the Department of Transportation, Office of Pipeline Safety, Research and Special Programs Administration (OPS) issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV). The NOPV alleged various deficiencies in compliance with regulations related to spill reporting, operations and maintenance of the pipeline and record keeping, none of which relate to the cause of the spill. The NOPV was issued to both Pepco and ST Services and proposed a civil penalty in the amount of $674,000. On June 2, 2004, the OPS issued a Final Order regarding the NOPV in this matter. The Final Order assessed a total fine of $330,250, with $256,250 of that amount assessed jointly against Pepco and ST Services and the remaining $74,000 assessed solely against ST Services. ST Services subsequently filed a Petition for Reconsideration. All penalties were stayed pending the outcome of the Petition for Rec onsideration. On February 9, 2005, OPS issued a Decision on the Petition for Reconsideration that affirmed the Final Order. Pepco's share of the $330,250 penalty assessed pursuant to the Final Order amounts to $128,125. 119
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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. |
Accounting Policy Choices |
Pepco's management believes that based on the nature of the businesses in which its subsidiaries are primarily engaged, Pepco Holdings has very little choice regarding many of the accounting policies it utilizes. In that regard, the most significant portion of Pepco Holdings' business consists of its regulated utility operations, which are subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 does allow regulated entities, in appropriate circumstances, to establish regulatory assets and regulatory liabilities and to defer the income statement impact of certain costs that are expected to be recovered in future rates. However, management believes that in the areas that Pepco is afforded accounting policy choices, its selection from among the alternatives available generally would not have a material impact on the Company's financial con dition or results of operations. |
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 (refer to the "Relationship with Mirant" section, herein), the calculation of future cash flows and fair value amounts for use in goodwill and asset impairment evaluations, fair value calculations (based on estimating market pricing) associated with derivative instruments, pension and other post-retirement 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 our business. We record an estimated liability for these proceedings and claims based upon the probable and reasonably estimatable criteria contained in SFAS No. 5 "Accounting for Contingencies." Although Pepco believes tha t its estimates and assumptions are reasonable, they are based upon information presently available. Actual results may differ significantly from these estimates. 120
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Long-Lived Assets Impairment Evaluation |
Pepco believes that the estimates involved in its long-lived asset impairment evaluation process represent "Critical Accounting Estimates" because they (i) 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 estimates and the impact of such variations could be material, and (iii) the impact that recognizing an impairment would have on Pepco's assets as well as the net loss related to an impairment charge could be material. |
In accordance with the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," an impairment loss shall 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 to not 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 considers historical cash flows. Pepco 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. |
Pension and Other Post-retirement Benefit Plans |
Pepco believes that the estimates involved in reporting the costs of providing pension and other post-retirement 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's expected future cash funding requirements for the plans and would have an impact on the projected benefit obligations, the reported pension and other post-retirement benefit liability on the balance sheet, and the reported annual net periodic pension and other post-retirement benefit cost on the income statement. In terms of quantifying the anticipated impact of a change in assumptions, PHI estimates that a .25% change in the discount rate used to value the benefit obligations co uld result in a $5 million impact on its consolidated balance sheets and income statements. Additionally, PHI 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 income statements and a .25% change in the assumed healthcare cost trend rate could result in a $.5 million impact on its consolidated balance sheets and income statements. Pepco's management consults with its actuaries and investment consultants when selecting its plan assumptions. |
Pepco follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions," and SFAS No. 106, "Employers' Accounting for Post-retirement 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 post-retirement obligations is generally recognized over the working lives of the employees who benefit under the plans rather than immediately recognized in the income statement. 121
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Regulation of Power Delivery Operations |
The requirements of SFAS No. 71 apply to Pepco's business. Pepco 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's estimates and the impact of such variations could be material, and (iii) the impact that writing off a regulatory asset would have on Pepco's assets and the net loss related to the charge could be material. |
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, its results of operations and financial condition. |
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 delivery of electricity. In addition, the rates that Pepco can charge for electricity transmission are regulated by FERC. Pepco cannot change delivery or transmission rates without approval by the applicable regulatory authority. While the approved delivery 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 rate s, 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. 122
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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, the Mirant bankruptcy could adversely affect Pepco's business. See "Relationship with Mirant Corporation." |
Pepco could 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 "Management's Discussion and Analysis of Financial Condition an d Results of Operations -- Regulatory and Other Matters." |
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 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 good 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 obligat ions for any of these reasons, it may incur penalties or damages. 123
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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, Maryland, New Jersey, Ohio, Pennsylvania, 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. Howeve r, 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, waste management, natural resources, site remediation, and health and safety. These laws and regulations require Pepco to incur expenses 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 electricity delivery businesses. |
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. 124
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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. |
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, 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: |
The table above shows the amounts of Natural Gas Operating Revenue from sources that were subject to price regulation (Regulated Gas Revenue) and that were generally not subject to price regulation (Other Gas Revenue). Regulated Gas Revenue includes on-system natural gas sales and the transportation of natural gas for customers. Other Gas Revenue includes off-system natural gas sales and the resale of excess gas or system capacity. |
Regulated Gas Revenue |
Regulated Gas Revenue increased by $18.9 million primarily due to the following: (i) $21.0 million increase in the Gas Cost Rate due to higher natural gas commodity costs; this was effective November 1, 2003; (ii) $8.2 million increase in Gas Base Rates due to higher operating expenses and costs of capital; this was effective December 9, 2003; (iii) $2.0 million adjustment to unbilled revenues in 2003; and 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. For the year ended December 31, 2004, gas sales were approximately 21,600,000 Mcf as compared to approximately 22,900,000 Mcf for the comparable period in 2003. For the year ended December 31, 2004, heating degree days decreased 7.1% for the year ended December 31, 2004 as compared to the same period in 2003. |
Other Gas Revenue |
Other Gas Revenue increased by $17.8 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, as a result, reduced customer demand. (offset in Gas Purchased) 130
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Operating Expenses |
Fuel and Purchased Energy |
Fuel and Purchased Energy decreased by $42.7 million to $656.8 million in 2004 from $699.5 million in 2003 due primarily to: (i)$43.0 million from the expiration of the DMEC contract in December 2003 (offset in Other Electric Revenue), (ii) $4.3 million reduction in PJM network transmission costs (partial offset in Regulated T&D Electric Revenue) offset by (iii) $4.6 million higher average energy costs, the result of the new Default Supply rates for Maryland beginning in June and July 2004. |
Gas Purchased |
Gas Purchased increased by $30.2 million to $162.5 million in 2004 from $132.3 million in 2003. Regulated gas purchased primarily resulted from the following: (i) net $20.4 million increase (substantially offset in revenue) from the settlement of financial hedges (entered into as part of DPL's regulated Natural Gas Hedge program), (ii) offset by a $7.2 million decrease in on- system purchases due to warmer weather. In addition, other gas purchased increased by $17.0 million due to the increase in off-system sales (offset in Other Gas Revenue). |
Other Operation and Maintenance |
Other Operation and Maintenance decreased by $7.8 million to $179.1 million in 2004 from $186.9 million in 2003. The decrease primarily resulted from (i) $3.3 million lower billing system IT costs, (ii) $2.5 million incremental storm costs primarily related to one time charges as a result of Hurricane Isabel in September 2003, (iii) $2.5 million decrease in uncollectible reserve, (iv) $2.4 million lower pension costs in 2004,and (v) $1.1 million decrease other costs, offset by (vi) $2.4 million higher severance costs in 2004 and (vii) $2.0 million for Sarbanes-Oxley external compliance costs. |
Other Taxes |
Other Taxes decreased by $8.3 million to $27.6 million in 2004 from $35.9 million in 2003. The decrease primarily resulted from property tax true-ups. |
Other Income (Expenses) |
Other Expenses decreased by $3.6 million to a net expense of $29.4 million in 2004 from a net expense of $33.0 million in 2003. This decrease is primarily due to a $4.2 million decrease in interest charges due to a reduction in long-term debt, partially offset by a $1.2 million increase in short-term interest charges. |
Preferred Stock Dividend Requirements |
Preferred Stock Dividend Requirements decreased by $2.8 million from 2003. This is 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. 131
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Income Tax Expense |
DPL's effective tax rate for 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 (which was the primary reason for the higher effective tax rate as compared to 2003) partially offset by the flow-through of Deferred Investment Tax Credits. |
DPL's effective tax rate for 2003 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), 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. |
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 delivery of electricity and gas. In addition, the rates that DPL can charge for electricity transmission are regulated by FERC. DPL cannot change delivery or transmission rates without approval by the applicable regulatory authority. While the approved delivery 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 included in the approved r ates, 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 132
____________________________________________________________________________ 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 good 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, Maryland, New Jersey, Ohio, Pennsylvania, 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 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 incur expenses to, among other things, conduct site remediation and obtain permits. 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 133
____________________________________________________________________________ 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 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. |
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. 134
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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: |
The table above shows the amounts of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue). Regulated T&D (Transmission & Distribution) Electric Revenue includes revenue ACE receives for delivery of electricity to its customers. Default Supply Revenue (DSR), also known as Basic Generation Service (BGS) includes revenue ACE receives from the supply of electricity at regulated rates. The costs related to the supply of electricity are included in Fuel and Purchased Energy. Also included in DSR is revenue from non-utility generators (NUGs), transition bond charges (TBC), market transition charges (MTC) and other restructuring related revenues (see Deferred Electric Service Cost). Other 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 Revenue |
Regulated T&D Electric Revenue increased by $1.1 million primarily due to the following: (i) $9.0 million increased average customer usage, (ii) $4.8 million increase in higher average effective rates, offset by, (iii) $5.5 million lower PJM network transmission revenue (offset in Fuel and Purchased Energy), (iv) $5.1 million lower transmission revenue related to increased customer migration, and (v) $2.1 million unfavorable weather impact. Delivered sales for the year ended December 31, 2004 were approximately 9,874,000 MwH compared to approximately 9,643,000 MwH for the comparable period in 2003. Cooling degree days decreased by .5% and heating degree days decreased by 7.9% for the year ended December 31, 2004 compared to the same period in 2003. |
Default Supply Revenue |
Default Supply Revenue is offset in operating expenses and has minimal earnings impact due to deferral accounting as a result of electric restructuring in New Jersey. The $105.7 million increase in DSR resulted from the following: (i) $83.1 million of higher wholesale energy revenues due to higher market prices in 2004, (ii) $76.3 million due to higher 138
__________________________________________________________________________ effective rates as the result of an increase in BGS retail energy rates beginning in June 2004 and an increase in net NUG and MTC rates beginning in August 2003, (iii) $24.4 million of higher average customer use, partially offset by (iv) $68.9 million decrease related to increased customer migration, and (v) $9.2 million unfavorable weather impact. |
For the twelve months ended December 31, 2004, ACE's New Jersey customers served by an alternate supplier represented 22% of ACE's total load. For the twelve months ended December 31, 2003, ACE's New Jersey customers served by an alternate supplier represented 11% of ACE's total load. |
Default Supply sales for the twelve months ended December 31, 2004 were approximately 7,669,000 MwH compared to approximately 8,597,000 MwH for the comparable period in 2003. |
Other Electric Revenue |
Other Electric Revenue decreased by $9.6 million primarily due to the following: (i) $5.2 million decrease in inter-company revenue related to Deepwater tolling transaction between ACE and CEH, (ii) $3.2 million fuel oil sale in the first quarter of 2003, and (iii) $.6 million lower customer requested work. |
Operating Expenses |
Fuel and Purchased Energy |
Fuel and Purchased Energy increased by $28.0 million to $806.7 million in 2004 from $778.7 million in 2003. This increase was primarily due to: (i) $36.4 million higher average costs, the result of the new Default Supply rates for New Jersey beginning in June 2004 and offset by (ii) $8.4 million reduced PJM network transmission costs (partial offset in Regulated T&D Electric Revenue). |
Other Operation and Maintenance |
Other Operation and Maintenance decreased by $15.3 million to $192.7 million in 2004 from $208.0 million in 2003. The decrease primarily resulted from: (i) $10.2 million for Deepwater, plant transferred to CE in 2004; (ii) $6.8 million for reduced pension costs in 2004; (iii) $3.5 million related to billing system IT costs; (iv) $2.0 million primarily for Default Supply and Demand Side Management related costs; (v) $1.0 million incremental storm costs primarily related to one time charges as a result of Hurricane Isabel in September 2003, partially offset by (vi) $4.6 million severance costs in 2004; (vii) $1.5 million for electric system maintenance; (viii) $2.0 million for Sarbanes-Oxley external compliance costs; and (ix) $.7 million for bad debt expense. |
Depreciation and Amortization |
Depreciation and Amortization expenses increased by $20.3 million to $132.8 million in 2004 from $112.5 million in 2003 primarily due to: (i) $12.8 million increase for amortization of bondable transition property as a result of additional transition bonds issued in December 2003; (ii) $3.8 million for the amortization of the deferred service costs balance which began in August 2003, (iii) $2.4 million increase for amortization of a regulatory tax asset related to New Jersey stranded costs, and (iv) $1.3 million other various items. 139
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Other Taxes |
Other Taxes decreased by $3.7 million to $20.1 million in 2004 from $23.8 million in 2003. The decrease primarily resulted from a $3.3 million New Jersey delivery tax expense true-up in 2004. |
Deferred Electric Service Costs |
Deferred Electric Service Costs (DESC), which relates only to ACE, increased by $43.3 million to $36.3 million for the year ended December 31, 2004 from a $7.0 million credit to operating expense for the year ended December 31, 2003. The $43.3 million increase represents a net over-recovery associated with New Jersey NUGs, MTC and other restructuring items. Additionally, the 2003 period contained a $27.5 million charge related to the New Jersey deferral disallowance regarding the procurement of fuel and purchased energy. Customers in New Jersey who do not choose a competitive supplier receive default electricity supply from suppliers selected through auctions approved by the NJBPU. ACE's rates for the recovery of these costs are reset annually. On ACE's balance sheet a regulatory asset includes an under-recovery of $99.4 million as of December 31, 2004. This amount is net of a $46.1 million reserve on previously disallowed items under appe al. |
Gain on Sale of Assets |
The Gain on Sale of Assets increase of $14.7 million in 2004 is due to a settlement with the City of Vineland, New Jersey. During the second quarter of 2004, ACE and the City of Vineland finalized condemnation settlement under which ACE transferred to the City of Vineland its distribution assets within the geographical limits of the City of Vineland and related customer accounts. The transaction resulted in a pre-tax gain of approximately $14.7 million, which is recorded as a reduction to operating expenses in the line item entitled "gain on sale of assets" on the consolidated statements of earnings. |
Other Income (Expenses) |
Other Expenses increased by $3.0 million to a net expense of $52.4 million in 2004 from a net expense of $49.4 million in 2003. This increase is primarily due to the following: (i) $5.5 million increase in interest expense on Transition Bonds issued by ACE Funding due to additional transition bonds issued in December, 2003, partially offset by; (ii) $2.1 million decrease in income from customers to recover income tax expense on contributions in aid of construction. |
Preferred Stock Dividend Requirements |
Preferred Stock Dividend Requirements decreased by $1.8 million from 2003. This 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. 140
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Income Tax Expense |
ACE's effective tax rate for 2004 was 40% 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, partially offset by the flow-through of Deferred Investment Tax Credits. |
ACE's effective tax rate for 2003 was 40% 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, partially offset by the flow-through of Deferred Investment Tax Credits. |
Extraordinary Item |
In July 2003, the New Jersey Board of Public Utilities (NJBPU) approved the determination of stranded costs related to ACE's January 31, 2003, petition relating to its B.L. England generating facility. The NJBPU approved recovery of $149.5 million. 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 ACE's financial statements, since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999. |
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 by the NJBPU with respect to, among other things, the rates it can charge retail customers for the delivery of electricity. In addition, the rates that ACE can charge for electricity transmission are regulated by FERC. ACE cannot change delivery or transmission rates without approval by the applicable regulatory authority. While the approved delivery 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 141
_________________________________________________________________________ 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 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 good 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 ACE is unable to perf orm 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 the 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, Maryland, New Jersey, Ohio, Pennsylvania, 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 system s 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. 142
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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 incur expenses to, among other things, conduct site remediation and obtain permits. 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. |
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 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. 143
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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: |
PHI is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA)and is subject to the regulatory oversight of the Securities and Exchange Commission (SEC) under PUHCA. As a registered public utility holding company, PHI requires SEC approval to, among other things, issue securities, acquire or dispose of utility assets or securities of utility companies and acquire other businesses. In addition, under PUHCA, transactions among PHI and its subsidiaries generally must be performed at cost and subsidiaries are prohibited from paying dividends out of capital or unearned surplus without SEC approval. |
PHI was incorporated in Delaware on February 9, 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. Conectiv also is a registered public utility holding company under PUHCA. |
PHI Service Company, a subsidiary service company of PHI, provides a variety of support services, including legal, accounting, tax, 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 has been filed with, and approved by, the SEC under PUHCA. The expenses of the service company are charged to PHI and the participating operating subsidiaries in accordance with costing methodologies set forth in the service agreement. |
The following is a description of each of PHI's 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. PHI's power delivery business is conducted by its subsidiaries Pepco, DPL and ACE, each of which is a regulated public utility in the jurisdictions in which it serves customers. DPL and ACE 163
_____________________________________________________________________________ conduct their power delivery operations under the tradename Conectiv Power Delivery. |
Competitive Energy |
PHI's competitive energy business provides competitive generation, marketing and supply of electricity and gas, and related energy management services, 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 and its subsidiaries (collectively, Pepco Energy Services). |
Other Non-Regulated |
This component of PHI's business is conducted through itssubsidiary Potomac Capital Investment Corporation (PCI), which manages a portfolio of financial investments, consisting primarily of energy leveraged leases. In 2003, PCI discontinued making new investments. PHI's subsidiary Pepco Communications, Inc. (Pepcom) ceased operations in December 2004 following the sale of its principal asset, a 50% interest in Starpower Communications, LLC (Starpower) for $29 million in cash. |
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 and 2002 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 segment. |
(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 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, and with the FASB Interpretation No. 46-R "Consolidation of Variable Interest Entities" (FIN 46R) issued in December 2003, Pepco Holdings deconsolidated several entities that had previously been consolidated and consolidated several small entities that had not previously been consolidated. FIN 46 and FIN 46R address 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 46 and FIN 46R, refer to the FIN 46 discussion later in this Note. 164
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Composition of Consolidated Financial Statements |
The accompanying consolidated statements of earnings, consolidated statements of comprehensive earnings, and consolidated statements of cash flows for the years ended December 31, 2004 and 2003 include Pepco Holdings and its subsidiaries' results for the full year. These statements for the year ended December 31, 2002 include Pepco and its pre-merger subsidiaries' results for the entire year consolidated with Conectiv and its subsidiaries operating results starting on August 1, 2002, the date the acquisition of Conectiv was consummated. Accordingly, the statements referred to above for the years ended December 31, 2004 and 2003 are not comparable with those for the year ended December 31, 2002. However, the amounts included in the accompanying consolidated balance sheets and consolidated statements of shareholders' equity for the years ended December 31, 2004 and 2003 are comparable since both years reflect the accounting impact of the merger transaction. |
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 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 (refer to the "Relationship with Mirant" section, herein), the calculation of future cash flows and fair value amounts for use in goodwill and asset impairment evaluations, fair value calculations (based on estimating market pricing) associated with derivative instruments, pension and other post-re tirement 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 our business. We record an estimated liability for these proceedings and claims based upon the probable and reasonably estimatable 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 presently available. Actual results may differ significantly from these estimates. |
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). |
The wholesale power delivery operations of each of Pepco, DPL, and ACE are regulated by the Federal Energy Regulatory Commission (FERC). 165
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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 would be eliminated through a charge to earnings. |
The components of Pepco Holdings' regulatory asset balances at December 31, 2004 and 2003, are as follows: |
A description of the regulatory assets and regulatory liabilities is as 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 interest payments on the Transition Bonds. 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. Also includes deferred fuel costs for DPL's gas business. All deferrals receive a return. ACE deferrals 166
_____________________________________________________________________________ are recoverable over the next 9 years. DPL's 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 Contracts: Represents deferred costs related to purchase power contracts at ACE and DPL which are being recovered over 3 and 9 years and earn a return. |
Deferred Other Post-retirement Benefit Costs:Represents the non-cash portion of other post-retirement 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 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 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), Customer Sharing Commitment, and Other:GPC represents the customers' share of profits that Pepco has realized on the procurement and resale of generation services to standard offer service customers that has not yet been distributed to customers. Pepco is currently distributing the customers' share of profits monthly to customers in a billing credit. Pepco's 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 in each jurisdiction. |
Removal Costs: Represents Pepco's and DPL's asset retirement obligations associated with removal costs accrued using Commission approved depreciation rates for transmission, distribution, and general utility 167
_____________________________________________________________________________ property. In accordance with SFAS 143, accruals for removal costs were classified as a regulatory liability. |
Revenue Recognition |
Regulated Revenue |
The power delivery 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. Pepco Holdings recorded amounts for unbilled revenue of $226.7 million and $184.6 million as of December 31, 2004 and 2003, respectively. These amounts are included in the "accounts receivable" line item in the accompanying consolidated balance sheets. |
Additionally, the collection of 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. Payments of 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. |
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 l ines 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. |
Transition Power Agreement and Generation Procurement Credit |
As part of the agreement to divest its generation assets, Pepco entered into separate Transition Power Agreements (TPAs) with Mirant for the District of Columbia and Maryland. In connection with Mirant's bankruptcy proceeding, the TPAs were amended by the Amended Settlement Agreement and Release dated as of October 24, 2003 (Settlement Agreement). For information regarding the impact of Mirant's bankruptcy on Pepco's operations, refer to the Note (12) Commitments and Contingencies, "Relationship with Mirant Corporation" section, herein. |
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 168
_____________________________________________________________________________ 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" (SFAS 133) as amended by subsequent pronouncements. SFAS 133 requires derivative instruments to be measured at fair value. Derivatives are recorded on the 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: (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 chooses not to designate as hedges. Derivatives that were used for proprietary trading were marked-to-market through earnings. |
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. Any ineffective portion of the cash flow hedge is 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. The contracts are used in the company's normal operations, typically settle physically, and follow standard accrual accounting. Unrealized gains and losses on these contracts do not appear on PHI's Consolidated Balance Sheets. Examples of these transactions include 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. |
PHI uses option contracts to mitigate certain risk factors. 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 are used when available. If market prices are not available, the market value of the options is estimated using Black-Scholes closed form models and is included in earnings. Option contracts typically make up only a small portion of PHI's total portfolio. 169
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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. |
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 in net on the Consolidated Statement of Earnings. When a hedging gain or loss is realized, it is presented net in the same category as the underlying item being hedged. Normal purchase and sales transactions are presented gross on the Consolidated Statement 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. |
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. |
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 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 represents the underlying hedged item. The total portfolio is risk managed based on its net 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. Total portfolio-level hedging includes 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 physical natural gas and 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 are fully recoverable through the fuel adjustment clause approved by the DPSC and are deferred under SFAS No. 71 until recovered. At December 31, 2004 there was a 170
_____________________________________________________________________________ deferred derivative liability on DPL's balance sheet of $1.5 million, and an inventory contra-asset balance of $1.1 million, offset by a $2.6 million regulatory asset. |
Pepco Energy Services purchases natural gas futures and natural gas and electricity 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 natural gas futures contracts as cash flow hedges of forecasted transactions. Its natural gas and electricity forward contracts are accounted for under standard accrual accounting as these contracts are exempted under SFAS No. 133 because they are used in the company's normal operations. |
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 has incurred. CBI hedged 75% of the interest rate payments for its variable rate debt. CBI formally designated its interest rate swap agreements as a cash flow hedge. CBI repaid all of its external debt and settled its interest rate swap agreement ($6.8 million) in September 2004. |
PCI has entered into interest rate swap agreements for the purpose of managing its overall borrowing rate and limiting its interest rate risk associated with debt it has issued. PCI currently hedges 100% of its variable rate debt and approximately 55% of its fixed rate debt for its Medium Term Note program. PCI formally designated its interest rate swap agreements as both cash flow hedge and fair value hedge instruments, as appropriate. |
EITF 03-11 |
On January 1, 2004, Pepco Holdings implemented EITF Issue No. 03-11 (EITF 03-11), "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, 'Accounting for Derivative Instruments and Hedging Activities,' and not 'Held for Trading Purposes' as Defined in EITF Issue No. 02-3, 'Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.'" As a result of the implementation of this EITF, $219.1 million of operating revenues and operating expenses related to certain Conectiv Energy and Pepco Energy Services energy contracts are reported on a net basis in the accompanying consolidated statements of earnings for the year ended December 31, 2004, as these energy contracts did not physically settle. Had EITF 03-11 been effective for the year ended December 31, 2003, Pepco Holdings' operating revenues a nd operating expenses would have been reduced by $291.8 million. The implementation of EITF 03-11 did not have an impact on Pepco Holdings' financial condition, net earnings or cash flows. |
Accounting For Marketable Securities |
PCI's investment activity, which prior to 2004 consisted of preferred stock investments with mandatorily redeemable features and marketable equity securities has decreased since Pepco Holdings announced the discontinuation of further new investment activity by PCI. Under the specific identification method, PCI realized gross gains of $1.0 million, $.9 million, and $.6 million, respectively, on sales or calls of securities for the years ended December 31, 2004, 2003 and 2002. In addition, PCI recorded gross losses of $.2 million, $.6 million, and $.7 million, respectively, on sales or calls of securities for the years ended December 31, 2004, 2003 and 2002. 171
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Included in net unrealized gains/losses at December 31, 2003, are gross unrealized losses of zero and gross unrealized gains of $4.5 million. |
In April 2004, PCI received a cash dividend (including dividends in arrears) of $3.8 million from its remaining preferred stock investment and recorded an after-tax gain of approximately $3.1 million. The remaining preferred shares were also sold in April resulting in an after-tax gain of approximately $.4 million. |
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 its 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. Substantially all of Pepco Holdings' goodwill was generated by the acquisition of Conectiv by Pepco that closed in 2002. |
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 2004 Pepco Holdings tested its goodwill for impairment as of July 1, 2004. This testing 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 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 shall only be recognized 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. 172
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During 2003 PHI recorded an impairment charge of $53.3 million from the cancellation of a CT contract and an $11.0 million aircraft impairment. |
Pro Forma Information (unaudited) |
Since the purchase method was used to account for the August 1, 2002 purchase of Conectiv by Pepco, the accompanying consolidated financial results include Conectiv and its pre-merger subsidiaries' operating results commencing on August 1, 2002. Accordingly, Pepco Holdings' consolidated operating results for the year ended December 31, 2002 are not comparable with the corresponding 2004 and 2003 results. |
The following pro forma unaudited financial information for Pepco Holdings on a consolidated basis gives effect to the merger as if it had occurred at the beginning of 2002. This information does not reflect future revenues or cost savings that may result from the acquisition and is not indicative of actual results of operations had the acquisition occurred at the beginning of 2002 or of results that may occur in the future. Amounts, except earnings per share, are in millions. |
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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 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 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, or 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" shown 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 plants purchased in prior years are reported on the Consolidated Balance Sheets as "Investment tax credits." These investment tax credits are being amortized to income over the useful lives of the related utility plant. |
SFAS No. 150 |
Effective July 1, 2003, Pepco Holdings implemented SFAS No. 150 entitled "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). This Statement established standards for how an issuer classifies and measures, in its Consolidated Balance Sheets, certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 resulted in Pepco Holdings' reclassification (initially as of September 30, 2003) of PHI's "Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Which Holds Solely Parent Junior Subordinated Debentures" (TOPrS) and "Mandatorily Redeemable Serial Preferred Stock" on its Consolidated Balance Sheets to a long term liability classification. Additionally, in accordance with the provisions of SFAS No. 150, dividends on the TOPrS and Mandatorily Redeemable Serial Preferred Stock, declared subsequent to the July 1, 2003 imp lementation of SFAS No. 150, are recorded as interest expense in Pepco Holdings' Consolidated Statements of Earnings for the years ended December 31, 2004 and 2003. In accordance with the transition provisions of SFAS No. 150, amounts prior to 2003 were not reclassified. |
In December 2003, the FASB deferred for an indefinite period the application of the guidance in SFAS No. 150 to non-controlling interests that are classified as equity in the financial statements of a subsidiary, but 178
_____________________________________________________________________________ would be classified as a liability in the parent's financial statements under SFAS No. 150. The deferral is limited to mandatorily redeemable non-controlling interests associated with finite-lived subsidiaries. Pepco Holdings does not have an interest in any such applicable entities as of December 31, 2004, but will continue to evaluate the applicability of this deferral to entities which may be consolidated as a result of FASB Interpretation No. 46, "Consolidation of Variable Interest Entities." |
FIN 45 |
Pepco Holdings applied the provisions of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45), commencing in 2003, to its agreements that contain guarantee and indemnification clauses. These provisions expand those required by FASB Statement No. 5, "Accounting for Contingencies," by requiring a guarantor to recognize a liability on its balance sheet for the fair value of obligations it assumes under certain guarantees issued or modified after December 31, 2002 and to disclose certain types of guarantees, even if the likelihood of requiring the guarantor's performance under the guarantee is remote. |
As of December 31, 2004 and 2003, Pepco Holdings did not have material obligations under guarantees or indemnifications issued or modified after December 31, 2002, that are required to be recognized as a liability on its consolidated balance sheets; however, certain energy marketing obligations of Conectiv Energy were recorded as liabilities. |
FIN 46 |
On December 31, 2003, FIN 46 was implemented by Pepco Holdings. FIN 46 was revised and superseded by FASB Interpretation No. 46R (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. FIN 46R was effective December 31, 2003 for variable interest entities that were considered to be special-purpose entities, and effective March 31, 2004 to all other variable interest entities. The implementation of FIN 46R (including the evaluation of interests in power purchase arrangements) did not impact Pepco Holdings' financial condition or results of operations for the years ended December 31, 2004 and 2003. |
As part of its FIN 46R evaluation, Pepco Holdings reviewed its subsidiaries' power purchase agreements (PPAs), including its Non-Utility Generation (NUG) contracts, to determine (i) if the subsidiary's interest in each entity that is a counterparty to a PPA was a variable interest, (ii) whether the entity was a variable interest entity and (iii) if so, whether Pepco Holdings' subsidiary was the primary beneficiary. Due to a variable element in the pricing structure of PPAs with four entities, including Pepco's agreement with Panda-Brandywine, L.P. (Panda), Pepco Holdings' subsidiaries potentially assume the variability in the operations of the plants of these entities and therefore have a variable interest in the entities. Pepco Holdings was unable to obtain sufficient information from these entities to conduct the analysis required under FIN 46R to determine whether these four entities were variable interest entities or if Pepco Holdings' su bsidiaries 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. 179
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Net purchase activities with these four entities in the years ended December 31, 2004, 2003, and 2002 were approximately $341 million, $326 million and $316 million, respectively, of which approximately $312 million, $299 million, and $295 million, respectively related to power purchases under the PPAs. Pepco Holdings' exposure to loss under the Panda PPA is discussed in Note (12) Commitments and Contingencies, under "Relationship with Mirant Corporation." Pepco Holdings does not have loss exposure under the remaining three PPAs because 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, unrealized derivative assets, and deferred compensation trust assets. |
Other Current Liabilities |
The other current liability balance principally consists of customer deposits, accrued vacation liability, current unrealized derivative liabilities, and 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. |
Reclassifications |
Certain prior year amounts have been reclassified in order to conform to the current year presentation. |
New Accounting Standards |
SFAS 123R |
In December 2004, the FASB issued Statement No. 123 (revised 2004), "Share-Based Payment" (FAS 123R) which establishes standards for the accounting for transactions in which an entity exchanges its equity instruments primarily for employee services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity's equity instruments or that may be settled by the issuance of those equity instruments. In most cases, FAS 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award and to recognize that cost over the service period, normally the vesting period. FAS 123R will be effective for Pepco Holdings as of the July 1, 2005. Pepco Holdings is in the process of evaluating the impact of FAS 123R and does not anticipate that its implementati on will have a material effect on its overall financial position or net results of operations. |
(3) SEGMENT INFORMATION |
Based on the provisions of Statement of Financial Accounting Standards (SFAS) No. 131 "Disclosures about Segments of an Enterprise and Related Information," Pepco Holdings' management has identified its operating segments at December 31, 2004 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Prior to January 1, 2004, Pepco 180
_____________________________________________________________________________ Holdings' Power Delivery business consisted of two operating segments, Pepco Power Delivery and Conectiv Power Delivery. However, with the continued integration of the Power Delivery businesses, effective January 1, 2004 management determined that the two businesses represent a single operating segment. Additionally, during the quarter ended March 31, 2004, Pepco Holdings transferred several operating businesses from one operating segment to another in order to better reflect the management of those operations going forward. In accordance with the provisions of SFAS No. 131, results for the years ended December 31, 2003 and 2002 have been reclassified to conform to the current period segment presentation. 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, 2004, 2003 and 2002, is as follows. |
Relationship with Mirant Corporation |
In 2000, Pepco sold substantially all of its electricity generation assets to Mirant Corporation, formerly Southern Energy, Inc., pursuant to an Asset Purchase and Sale Agreement. As part of the Asset Purchase and Sale Agreement, Pepco entered into several ongoing contractual arrangements with Mirant and certain of its subsidiaries (collectively, Mirant). On July 14, 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). |
Depending on the outcome of the matters discussed below, the Mirant bankruptcy could have a material adverse effect on the results of operations of Pepco Holdings and Pepco. However, management currently 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 have arisen or may arise due to the Mirant bankruptcy. Accordingly, management does not anticipate that the Mirant bankruptcy will impair the ability of Pepco Holdings or Pepco to fulfill their 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 these agreements, Mirant was obligated to supply Pepco with all of the capacity and energy needed to fulfill its standard offer service obligations in Maryland through June 2004 and its standard offer service obligations in the District of Columbia through January 22, 2005. |
To avoid the potential rejection of the TPAs, Pepco and Mirant entered into an Amended Settlement Agreement and Release dated as of October 24, 2003 (the Settlement Agreement) pursuant to which Mirant assumed both of the TPAs and the terms of the TPAs were modified. The Settlement Agreement also provided that Pepco has an allowed, pre-petition general unsecured claim against Mirant Corporation in the amount of $105 million (the Pepco TPA Claim). |
Pepco has also asserted the Pepco TPA Claim against other Mirant entities that Pepco believes are liable to Pepco under the terms of the Asset Purchase and Sale Agreement's Assignment and Assumption Agreement (the Assignment 210
_____________________________________________________________________________ Agreement). Under the Assignment Agreement, Pepco believes that each of the Mirant entities assumed and agreed to discharge certain liabilities and obligations of Pepco as defined in the Asset Purchase and Sale Agreement. Mirant has filed objections to these claims. Under the current plan of reorganization filed by the Mirant entities with the Bankruptcy Court, certain Mirant entities other than Mirant Corporation would pay significantly higher portions of the claims of their creditors than would Mirant Corporation. The amount that Pepco will be able to recover from the Mirant bankruptcy estate with respect to the Pepco TPA Claim will depend on the amount of assets available for distribution to creditors of the Mirant entities that are found to be liable for the Pepco TPA Claim. |
Power Purchase Agreements |
Under agreements with FirstEnergy Corp., formerly Ohio Edison (FirstEnergy), and Allegheny Energy, Inc., both entered into in 1987, Pepco is obligated to purchase from FirstEnergy 450 megawatts of capacity and energy annually through December 2005 (the FirstEnergy PPA). Under an agreement with Panda, entered into in 1991, Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (the Panda PPA). In each case, the purchase price is substantially in excess of current 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 is obligated, among other things, to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the FirstEnergy PPA and the Panda PPA at a price equal to the price Pepco is obligated to pay under the FirstEnergy PPA and the Panda PPA (the PPA-Related Oblig ations). |
Pepco Pre-Petition Claims |
When Mirant filed its bankruptcy petition on July 14, 2003, Mirant had unpaid obligations to Pepco of approximately $29 million, consisting primarily of payments due to Pepco in respect of the PPA-Related Obligations (the Mirant Pre-Petition Obligations). The Mirant Pre-Petition Obligations constitute part of the indebtedness for which Mirant is seeking relief in its bankruptcy proceeding. Pepco has filed Proofs of Claim in the Mirant bankruptcy proceeding in the amount of approximately $26 million to recover this indebtedness; however, the amount of Pepco's recovery, if any, is uncertain. The $3 million difference between Mirant's unpaid obligation to Pepco and the $26 million Proofs of Claim primarily represents a TPA settlement adjustment which is included in the $105 million Proofs of Claim filed by Pepco against the Mirant debtors in respect of the Pepco TPA Claim. In view of this uncertainty, Pepco, in the third quarter of 2003, expen sed $14.5 million to establish a reserve against the $29 million receivable from Mirant. In January 2004, Pepco paid approximately $2.5 million 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. Pepco believes that under the terms of the Asset Purchase and Sale Agreement, Mirant is obligated to reimburse Pepco for the settlement payment. Accordingly, in the first quarter of 2004, Pepco increased the amount of the receivable due from Mirant by approximately $2.5 million and amended its Proofs of Claim to include this amount. Pepco currently estimates that the $14.5 million expensed in the third quarter of 2003 represents the portion of the entire $31.5 million receivable unlikely to be recovered in bankruptcy, and no additional reserve has been established for the $2.5 million increase in the receivable. The amount expensed represents Pepco's estimate of the possible outcome in bankruptcy, although the amou nt ultimately recovered could be higher or lower. 211
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Mirant's Attempt to Reject the PPA-Related Obligations |
On August 28, 2003, Mirant filed with the Bankruptcy Court a motion seeking authorization to reject its PPA-Related Obligations. Upon motions filed with the U.S. District Court for the Northern District of Texas (the District Court) by Pepco and FERC, in October 2003, the District Court withdrew jurisdiction over the rejection proceedings from the Bankruptcy Court. In December 2003, the District Court denied Mirant's motion to reject the PPA-Related Obligations on jurisdictional grounds. The District Court's decision was appealed by Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation (the Creditors' Committee) to the U.S. Court of Appeals for the Fifth Circuit (the Court of Appeals). On August 4, 2004, the Court of Appeals remanded the case to the District Court saying that the District Court has jurisdiction to rule on the merits of Mirant's rejection motion, suggesting that in doing so the court apply a "more ri gorous standard" than the business judgment rule usually applied by bankruptcy courts in ruling on rejection motions. |
On December 9, 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. On December 16, the Creditors' Committee appealed the District Court's order to the Court of Appeals, and on December 20, 2004, Mirant also appealed the District Court's order. |
As more fully discussed below, Mirant had been making regular periodic payments in respect of the PPA-Related Obligations. On December 9, 2004, Mirant filed a notice with the Bankruptcy Court that it was suspending payments to Pepco in respect of the PPA-Related Obligations. On December 13, 2004, Mirant failed to make a payment of approximately $17.9 million due to Pepco for the period November 1, 2004 to November 30, 2004. Mirant failed to make that payment. On December 23, 2004, Pepco received a payment of approximately $6.8 million from Mirant, which according to Mirant represented the market value of the power for which payment was due on December 13. Mirant has informed Pepco that it intends to continue to pay the market value, but not the above-market portion, of the power purchased under the PPA-Related Obligations. Pepco disagrees with Mirant's assertion that it need only pay the market value and believes that the amount repr esenting the market value calculated by Mirant is insufficient. |
On January 21, 2005, Mirant made a approximately $21.1 million, which, according to Mirant, includes the payment for the FirstEnergy PPA for December 2004 and "includes the December 2004 TPA revenue in the amount of $29,093,173.43, the TPA costs in the amount of $37,865,924.10, and an allocated share of [FirstEnergy's] PPA bill credits/charges in the amount of $5,490,164.79." Pepco disputes Mirant's contention that the amount paid reflects the full amount due Pepco under these agreements for the applicable periods. |
As of March 1, 2005, Mirant has withheld payment of approximately $34.8 million due to Pepco under the PPA-Related Obligations. |
On January 21, 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. On March 1, 2005 (as amended by order dated March 7, 2005), the District Court granted Pepco's motion to withdraw jurisdiction over the Asset Purchase and Sale Agreement 212
_____________________________________________________________________________ rejection proceedings from the Bankruptcy Court. In addition, the District Court ordered Mirant to pay on March 18, 2005, all past-due unpaid amounts under the PPA-Related Obligations. Mirant has filed a motion for reconsideration and a stay of the March 1, 2005 order. |
Pepco is exercising all available legal remedies and vigorously opposing Mirant's attempt to reject the PPA-Related Obligations and other 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 the attempt to reject the agreements, the outcome of Mirant's efforts to reject the PPA-Related Obligations is uncertain. |
If Mirant ultimately is successful in rejecting the PPA-Related Obligations, Pepco could be required to repay to Mirant, for the period beginning on the effective date of the rejection (which date could be prior to the date of the court's order and possibly as early as September 18, 2003) and ending on the date Mirant is entitled to cease its purchases of energy and capacity from Pepco, all amounts paid by Mirant to Pepco in respect of the PPA-Related Obligations, less an amount equal to the price at which Mirant resold the purchased energy and capacity. Pepco estimates that the amount it could be required to repay to Mirant in the unlikely event that September 18, 2003, is determined to be the effective date of rejection, is approximately $133.2 million as of March 1, 2005 (assuming Mirant continues to withhold unpaid amounts of approximately $34.8 million as of March 1, 2005. |
Mirant has also indicated to the Bankruptcy Court that it will move to require Pepco to disgorge all amounts paid by Mirant to Pepco in respect of the PPA-Related Obligations, less an amount equal to the price at which Mirant resold the purchased energy and capacity, for the period July 14, 2003 (the date on which Mirant filed its bankruptcy petition) through rejection, if approved, on the theory that Mirant did not receive value for those payments. Pepco estimates that the amount it would be required to repay to Mirant on the disgorgement theory, in addition to the amounts described above, is approximately $22.5 million. |
Any repayment by Pepco of amounts paid by Mirant would entitle Pepco to file a claim against the bankruptcy estate in an amount equal to the amount repaid. Pepco believes that, to the extent such amounts were not recovered from the Mirant bankruptcy estate, they would be recoverable as stranded costs from customers through distribution rates as described below. |
The following are estimates prepared by Pepco of its potential future exposure if Mirant's attempt to reject the PPA-Related Obligations ultimately is successful. 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. The estimates assume no recovery from the Mirant bankruptcy estate and no regulatory recovery, either of which would mitigate the effect of the estimated loss. Pepco does not consider it realistic to assume that there will be no such recoveries. Based on these assumptions, Pepco estimates that its pre-tax exposure as of March 1, 2005, representing the loss of the future benefit of the PPA-Related Obligations to Pepco, is as follows: |
The ability of Pepco to recover from the Mirant bankruptcy estate in respect to the Mirant Pre-Petition Obligations and damages if the PPA-Related Obligations are successfully rejected will depend on whether Pepco's claims are allowed, the amount of assets available for distribution to the creditors of the Mirant companies determined to be liable for those claims, and Pepco's priority relative to other creditors. At the current stage of the bankruptcy proceeding, there is insufficient information to determine the amount, if any, that Pepco might be able to recover from the Mirant bankruptcy estate, whether the recovery would be in cash or another form of payment, or the timing of any recovery. |
If Mirant ultimately is successful in rejecting the PPA-Related Obligations and Pepco's full claim is not recovered from the Mirant bankruptcy estate, Pepco may 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, if Mirant ultimately is successful in rejecting the PPA-Related Obligations, 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 Pe pco's interpretation of the settlement agreements is confirmed, Pepco expects to be able to establish the amount of its anticipated recovery 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. |
If the PPA-Related Obligations are successfully rejected, and there is no regulatory recovery, Pepco will incur a loss. However, the accounting treatment of such a loss depends on a number of legal and regulatory factors, and is not determinable at this time. |
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, Inc. (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 214
_____________________________________________________________________________ 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 facility and capacity credit 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. Pepco believes that there is no reasonable factual or legal basis to support Mirant's contention that the SMECO Agreement is a lease of real property. Litigation continues and the outcome of this proceeding cannot be predicted. |
Federal Tax Treatment of cross-border Leases |
PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which as of December 31, 2004 had a book value of approximately $1.2 billion. The American Jobs Creation Act of 2004 imposed new passive loss limitation rules that apply prospectively to leases (including cross-border leases) entered into after March 12, 2004 with tax indifferent parties (i.e., municipalities and tax exempt or governmental entities). All of PCI's cross-border energy leases are with tax indifferent parties and were entered into prior to 2004. Although this legislation is prospective in nature and does not affect PCI's existing cross-border energy leases, it does not prohibit the IRS from challenging prior leasing transactions. In this regard, 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 enteri ng into certain sale-leaseback transactions with tax indifferent parties, including those entered into on or prior to March 12, 2004 (the Notice). |
PCI's cross-border energy leases are similar to those sale-leaseback transactions described in the Notice. PCI's leases are currently under examination by the IRS as part of the normal PHI tax audit. PHI believes there is a substantial likelihood that the IRS will challenge the tax benefits realized from interest and depreciation deductions claimed by PCI with respect to these leases, or the timing of these benefits, for the years 2001 through 2004. The tax benefits claimed by PCI for these years were approximately $175 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 results of operations and cash flow. |
PHI believes that its tax position related to these transactions was proper based on applicable statutes, regulations and case law, and intends to contest any adjustments proposed by the IRS; however, there is no assurance that PHI's position will prevail. |
Under SFAS No. 13, as currently interpreted, a deferral of tax benefits that does not change the total estimated net income from PHI's leases does not require an adjustment to the book value of the leases. 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 results of operations for the period in which the charge is recorded. 215
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In recent deliberations, The Financial Accounting Standards Board (FASB) has determined that a change in the timing of tax benefits also should require a repricing of the lease and an adjustment to the book value of a lease. Under this interpretation, a material change in the timing of cash flows under PHI's cross-border leases as the result of a settlement with the IRS also would require an adjustment to the book value. PHI understands that the FASB intends to publish this guidance for comment in the near future to become effective at the end of 2005. If adopted, the application of this guidance could result in a material adverse effect on PHI's results of operations even if the resolution is limited to a deferral of the tax benefits realized by PCI from its leases. |
Rate Proceedings |
In February 2003, ACE filed a petition with the NJBPU to increase its electric distribution rates and its Regulatory Asset Recovery Charge (RARC) in New Jersey. The petition was based on actual data for the nine months ended September 30, 2002, and forecasted data for the three months ended December 31, 2002 and sought an overall rate increase of approximately $68.4 million, consisting of an approximately $63.4 million increase in electricity distribution rates and $5 million for recovery of regulatory assets through the RARC. In October 2003, ACE filed an update supporting an overall rate increase of approximately $41.3 million, consisting of a $36.8 million increase in electricity distribution rates and a RARC of $4.5 million. This petition was ACE's first increase request for electric distribution rates since 1991. The requested increase would apply to all rate schedules in ACE's tariff. The Ratepayer Advocate filed testimony on January 3, 2004, proposing an annual rate decrease of $11.7 million. Intervenor groups representing industrial users and local generators filed testimony that did not take a position with respect to an overall rate change but their proposals, if implemented, would affect the way in which an overall rate increase or decrease would be applied to the particular rates under which they receive service. ACE's rebuttal testimony, filed in February 2004, made some changes to its October filing and proposed an overall rate increase of approximately $35.1 million, consisting of a $30.6 million increase in distribution rates and a $4.5 million increase in the RARC. Hearings were held before an Administrative Law Judge in late March, early April and May 2004. At the hearing held in April 2004, the Ratepayer Advocate proposed an annual rate decrease of $4.5 million, modifying its earlier proposal that rates be decreased by $11.7 million annually. The Ratepayer Advocate and Staff of the NJBPU filed their briefs in this proceeding in August 2004. The Ratepayer Advocate's brief supported its earlier proposal of an annual rate decrease of $4.5 million. The Staff's brief, however, stated for the first time its position calling for an overall decrease of $10.8 million. Reply briefs were filed on August 23, 2004. Settlement discussions between ACE, the NJBPU Staff and the Ratepayer Advocate have been ongoing. |
On December 12, 2003, the NJBPU issued an order also consolidating outstanding issues from several other proceedings into the base rate case proceeding. On December 22, 2003, ACE filed a Motion for Reconsideration in which it suggested that these issues be dealt with in a Phase II to the base rate case to address the outstanding issues identified in the December 12, 2003 Order. After discussion with the parties to the base rate case, it was agreed that a Phase II to the base rate case to address these issues, along with the $25.4 million of deferred restructuring costs previously transferred into the base rate case, would be initiated in April 2004. On April 15, 2004, ACE filed testimony with the NJBPU initiating a Phase II to the base rate proceeding described above. The parties to this case have 216
_____________________________________________________________________________ been actively engaged in settlement discussions in conjunction with settlement of Phase I issues. |
On August 31, 2004, ACE filed requests with the NJBPU proposing changes to its Transition Bond Charge, its Market Transition Charge - Tax rate, and its BGS Reconciliation charges. The net impact of these rate changes is to decrease ACE's annual revenues by approximately 1.5%. All of these rate changes were implemented on October 1, 2004. |
On October 1, 2004, DPL submitted its annual Gas Cost Rate (GCR) filing to the DPSC. In its filing, DPL sought to increase its GCR by approximately 16.8% in anticipation of increasing natural gas commodity costs. The GCR, which permits DPL to recover its procurement gas costs through customer rates, became effective November 1, 2004 and is subject to refund pending evidentiary hearings. In addition, on November 29, 2004, DPL filed a supplemental filing seeking approval to further increase GCR rates by an additional 6.5% effective December 29, 2004. The additional GCR increase became effective December 29, 2004 and is subject to refund pending evidentiary hearings. The DPSC Staff and the Division of Public Advocate filed their testimony on March 7, 2005 recommending full approval of the GCR changes being sought by DPL, including the revisions to the tariff in the original and supplemental filings. A final order addressing both the Nov ember 1 and December 29 increases is expected in the spring of 2005. |
On February 13, 2004, DPL filed with the DPSC for a change in electric ancillary service rates that would have an aggregate effect of increasing annual Delaware electric revenues by $13.1 million or 2.4%. This filing was prompted by the increasing ancillary service costs charged to DPL by PJM Interconnection, LLC (PJM). The proposed rates went into effect on March 15, 2004, subject to refund. On June 22, 2004, the DPSC approved a settlement agreement that provided for an increase having an aggregate effect of increasing annual Delaware electric revenues by $12.4 million, or 2.3%, with rates effective June 23, 2004. The approved increase was slightly less than the proposed increase that went into effect on March 15, 2004. As part of the settlement, the resulting estimated over-collection of $75,000 was given by DPL to the State of Delaware Low Income Fund administered by the Delaware Department of Human Services on July 15, 2 004. |
In compliance with the settlement approved by the MPSC in connection with the merger of Pepco and Conectiv, on December 4, 2003, DPL and Pepco submitted testimony and supporting schedules to review and reset if necessary its electricity distribution rates in Maryland to be effective July 1, 2004, when the then-current distribution rate freeze/caps ended. DPL's filing demonstrated that it was in an under-earning situation and, as allowed in the merger settlement, DPL requested that a temporary rate reduction implemented on July 1, 2003 for non-residential customers be terminated effective July 1, 2004. DPL estimated that the termination of the rate reduction would increase its annual revenues by approximately $1.1 million. A settlement reached between the parties allowing for this $1.1 million increase to be effective July 1, 2004 was approved by the MPSC in Order No. 79186. With limited exceptions, DPL cannot increase its distribution rates until January 1, 2007. |
Pepco's filing demonstrated that it also was in an under-earning situation. However the merger settlement provided that Pepco's distribution rates after July 1, 2004 could only remain the same or be decreased. With limited exceptions, Pepco cannot increase its distribution rates until January 1, 2007. In an order dated July 6, 2004 the MPSC affirmed the 217
_____________________________________________________________________________ Hearing Examiner's recommendation that no rate decrease was warranted at that time. |
On July 3, 2004, Pepco filed a distribution rate review case with the DCPSC as required by the terms of the Pepco-Conectiv merger settlement approved by the DCPSC. This case will determine whether Pepco's distribution rates will be decreased. In accordance with the terms of the merger settlement, Pepco's distribution rates cannot be increased as a result of the case. On November 24, 2004, the DCPSC issued an order that designated the issues to be considered in the case and set the hearing schedule. On December 17, 2004, Pepco filed supplemental direct testimony addressing the DCPSC-designated issues. Pepco's filings indicate that no rate decrease is warranted. On March 4, 2005, the DCPSC issued an order granting a joint motion filed on March 3, 2005, on behalf of Pepco and several other parties in the case to suspend the procedural schedule to allow the parties to focus on completing settlement discussions. In the joint motion, the movin g parties informed the DCPSC that they had agreed in principle to settlement provisions that would resolve all issues in the proceeding and that a settlement agreement could be filed in the near future. |
Restructuring Deferral |
Pursuant to a July 1999 summary order issued by the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA) (which was subsequently affirmed by a final decision and order issued in March 2001), ACE was obligated to provide basic generation service (BGS) from August 1, 1999 to at least July 31, 2002 to retail electricity customers in ACE's service territory who did not choose a competitive energy supplier. The order allowed ACE to recover through customer rates certain costs incurred in providing BGS. ACE's obligation to provide BGS was subsequently extended to July 31, 2003. At the allowed rates, for the period August 1, 1999 through July 31, 2003, ACE's aggregate allowed costs 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 Ener gy Adjustment Clause and ACE's Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance. |
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. The deferred balance was 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 2003, the NJBPU issued a 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 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. In July 2004, the NJBPU issued its final order in the restructuring deferral 218
_____________________________________________________________________________ proceeding. The final order did not modify the amount of the disallowances set forth in the July 2003 summary order, but did provide a much more detailed analysis of evidence and other information relied on by the NJBPU as justification for the disallowances. ACE believes the record does not justify the level of disallowance imposed by the NJBPU. 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 related to the July 2004 final order. ACE cannot predict the outcome of this appeal. |
Divestiture Cases |
District of Columbia |
Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed on July 31, 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. 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. On March 4, 2003, theInternal Revenue S ervice (IRS) issued a notice of proposed rulemaking (NOPR)that is relevant to that principal issue.Comments on the NOPR were filed byseveral parties on June 2, 2003, and the IRS held a public hearing on June 25,2003.As a result of the NOPR, three of the parties in the divestiture case filed comments with the DCPSC urging the DCPSC to decide the tax issues now on the basis of the proposed rule.Pepco filed comments with the DCPSC in reply to those comments, in which Pepco stated that thecourts have held and the IRS has stated that proposed rules are notauthoritative and that no decision should be issued on the basis of proposedrules. Instead, Pepco argued that the only prudent course of action is for the DCPSC to await the issuance of final regulations relating to the taxissues and then allow the parties to file supplemental briefs on the tax issues.Pepco cannot predict whether the IRS will adopt the regulations as proposed,make changes before issuing final regulations or decide not to adoptregulations. Other issues in the proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture. |
Pepco believes that a sharing of EDIT and ADITC would violate the normalization rules. 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. Pepco, in addition to sharing with customers the generation-related ADITC balance, would have to pay to the IRS an amount equal to Pepco's $5.8 million District of Columbia jurisdictional generation-related ADITC balance as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance 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. As of December 31, 2004, the District of Columbia jurisdictional transmission and distribution-related ADITC balance was approximately $6.0 million. 219
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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 D.C. 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 condition. It is uncertain when the DCPSC will issue a decision. |
Maryland |
Pepco filed its divestiture proceeds plan application in Maryland in April 2001. Reply briefs were filed in May 2002. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that was raised in the D.C. case. As of December 31, 2004, the Maryland 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 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 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,i.e., $9.1 million, and the generation-related ADITC. If such sharing were to violate the normalization rules, Pepco, in addition to sharing with customers an amount equal to approximately 50 percent of the generation-related ADITC balance, would be unable to use accelerated depreciation on Maryland allocated or assigned property. Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco's $10.4 million Maryland jurisdictional generation-related ADITC balance, as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance 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. As of December 31, 2004, the Maryland retail jurisdiction al transmission and distribution-related ADITC balance was approximately $10.7 million. The Hearing Examiner decided all other issues in favor of Pepco, except 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. See also the disclosure above under "Divestiture Cases - District of Columbia" regarding the March 4, 2003 IRS NOPR. |
Under Maryland law, if the proposed order is appealed to the MPSC, the proposed order is not a final, binding order of the MPSC and further action by the MPSC is required with respect to this matter. Pepco has appealed the Hearing Examiner's decision on the treatment of EDIT and ADITC and corporate reorganization costs to the MPSC. Pepco cannot predict what the outcome of the appeal will be or when the appeal might be decided. 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 220
_____________________________________________________________________________ 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 condition. |
SOS and Default Service Proceedings |
District of Columbia |
In February 2003, the DCPSC opened a new proceeding to consider issues relating to (a) the establishment of terms and conditions for providing SOS in the District of Columbia after Pepco's obligation to provide SOS terminated on February 7, 2005, and (b) the selection of a new SOS provider. |
In December 2003, the DCPSC issued an order that set forth the terms and conditions for the selection of a new SOS provider(s) and the provision of SOS by Pepco on a contingency basis. In December 2003, the DCPSC also issued an order adopting terms and conditions that would apply if Pepco continued as the SOS provider after February 7, 2005. In March 2004, the DCPSC issued an order adopting the wholesale SOS model,i.e., Pepco would continue to be the SOS provider in the District of Columbia after February 7, 2005. This March 2004 order, as amended by a DCPSC order issued in July 2004, extends Pepco's obligation to provide default electricity supply at market rates for up to an additional 76 months for small commercial and residential customers, and for an additional 28 months for large commercial customers. |
In August 2004, the DCPSC issued an order adopting administrative charges for residential, small and large commercial DC 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 $0.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial DC 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 DC 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 DC SOS sales on February 8, 2005. Pepco completed the first competitive procurement process for DC SOS at the end of October and filed the proposed new SOS rates with the DC PSC on November 3, 2004. |
The TPA with Mirant under which Pepco obtained the fixed-rate DC 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 DC 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 DC SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new DC 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 DC SOS contracts and the DC SOS rates charged to customers for the period from February 1 to February 7, 2005. The total amount of the diff erence is estimated to be approximately $8.7 million. This difference, however, will 221
_____________________________________________________________________________ be included in the calculation of the Generation Procurement Credit (GPC) for DC for the period February 8, 2004 through February 7, 2005. 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. Currently, based on the rates paid by Pepco to Mirant under the TPA Settlement, there is no customer sharing. However, in the event that Pepco were to ultimately realize a significant recovery from the Mirant bankruptcy estate associated with the TPA Settlement, the GPC would be recalculated, and the amount of customer sharing with respect to such recovery would be reduced because of the $8.7 million loss being included in the GPC calculation. |
Maryland |
Under a settlement approved by the MPSC in April 2003 addressing SOS service in Maryland following the expiration of Pepco's fixed-rate default supply obligations in July 2004, Pepco is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, Pepco purchases the power supply required to satisfy its market rate default supply obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the MPSC. Pepco is entitled to recover from its default supply customers the cost of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, small and large commercial Maryland SOS customers over the twelve months ended December 31, 200 3. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period. |
Under a settlement approved by the MPSC in April 2003 addressing SOS service in Maryland following the expiration of DPL's fixed-rate default supply obligations to non-residential customers in June 2004 and to residential customers through June 2004, DPL is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, DPL purchases the power supply required to satisfy its market rate default supply obligations 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 default supply customers the costs of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, 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 will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period. |
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 222
_____________________________________________________________________________ agreement with Conectiv Energy. A prior agreement, also with Conectiv Energy, terminated effective December 31, 2004. The current contract was entered into after conducting a competitive bid procedure identical to the Maryland SOS process in most respects and Conectiv Energy was the lowest bidder to provide wholesale power supply for DPL's Virginia default service customers. The new supply agreement commenced January 1, 2005 and expires in May 2006. On October 26, 2004, DPL filed an application with the VSCC for approval to increase the rates that DPL charges its Virginia default service customers to allow it to recover its costs for power under the new supply agreement plus an administrative charge and a margin. |
A VSCC order dated November 17, 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. Therefore, the November 17 order also directed the parties to file memoranda concerning whether administrative costs and a margin are properly recovered through a fuel clause mechanism. Memoranda were filed by DPL, the VSCC Staff and Virginia's Office of Attorney General. The VSCC ruled on January 18, 2005, that the administrative charge and margin are base rate items not recoverable through a fuel clause. No appeal is planned regarding this filing. A settlement resolving all other issues and m aking the interim rates final was filed on March 4, 2005, contingent only on possible future adjustment depending on the result of a related proceeding at FERC. A hearing is scheduled for March 16, 2005, and the VSCC is expected to approve the settlement. |
Also in October, DPL and Conectiv Energy jointly filed an application with the VSCC under Virginia's Affiliates Act requesting authorization for DPL to enter into a contract to purchase power from an affiliate. This authorization permits the contract to be executed with an affiliate, but is not a ruling on the merits of the contract. A VSCC order dated December 17, 2004 granted approval for DPL to purchase power from Conectiv Energy under the new contract according to its terms beginning January 1, 2005. |
On October 29, 2004, Conectiv Energy made a filing with FERC requesting authorization to enter into a contract to supply power to an affiliate. On December 30, 2004, FERC granted the requested authorization effective January 1, 2005, subject to refund and hearings on the narrow question whether, in the absence of direct VSCC oversight over the DPL competitive bid process, DPL unduly preferred its own affiliate, Conectiv Energy, in the design and implementation of the DPL competitive bid process, or unduly favored Conectiv Energy in the credit criteria and analysis applied. DPL cannot predict the outcome of this proceeding. |
Delaware |
Under a settlement approved by the DPSC, DPL is required to provide default electricity supply to customers in Delaware until May 1, 2006. On October 19, 2004, the DPSC initiated a proceeding to investigate and determine which entity should act as the standard offer supplier in DPL's Delaware service territory after May 1, 2006, and what prices should be charged for SOS after May 1, 2006. Similar to the process used in Maryland, the process used in Delaware consists of three separate stages. The stage 1 process was constructed to allow the DPSC to determine by February 28, 2005 the fundamental issues related to the selection of an SOS supplier. Stage 2 will resolve issues relating to the process under which supply will be 223
_____________________________________________________________________________ acquired by the SOS provider and way in which SOS prices will be set and monitored. In the last stage, these selection and pricing mechanisms would be implemented to determine the post-May 2006 SOS supplier and the post-May 2006 SOS price. On January 26, 2005, the DPSC Staff issued a report recommending to the DPSC that DPL be selected as the SOS supplier, subject to further discussions as to how to establish SOS prices. On February 22, 2005, the DPSC voted to approve an SOS process that will allow a Wholesale Standard Offer Service Model with DPL as the SOS Provider. Issues including the length of this extension and any profit margin that DPL may be able to earn and retain in conjunction with this service have been deferred for further discussion and will be decided by the DPSC at a later date. A written DPSC order documenting this decision is expected sometime in March or April 2005. |
Proposed Shut Down of B.L. England Generating Facility; Construction of Transmission Facilities |
Pursuant to a September 25, 2003 NJBPU order, ACE filed a report on April 30, 2004 with the NJBPU recommending that the B.L. England generating facility be shut down in accordance with the terms of an April 26, 2004 preliminary settlement agreement among PHI, Conectiv and ACE, New Jersey Department of Environmental Protection (NJDEP) and the Attorney General of New Jersey. The report stated that the operation of the B.L. England facility is necessary at the present time to satisfy reliability standards, but that those reliability standards could also be satisfied in other ways. The report concludes 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 facility and construct additional transmission lines into southern New Jersey. ACE cannot predict wh ether the NJBPU will approve the construction of the additional transmission lines. |
In letters dated May and September 2004 to PJM, ACE informed PJM of its intent, as owner of the B.L. England generating plant, to retire the entire plant (447 MW) on December 15, 2007. PJM completed its independent analysis to determine the upgrades required to eliminate any identified reliability problems resulting from the retirement of B.L. England and recommended that certain transmission upgrades be installed prior to the summer of 2008. ACE's independent assessment confirmed that the transmission upgrades identified by PJM are the transmission upgrades necessary to maintain reliability in the Atlantic zone after the retirement of B.L. England. The amount of the costs incurred by ACE to construct the recommended transmission upgrades that ACE would be permitted to recover from load serving entities that use ACE's transmission system would be subject to approval by FERC. The amount of construction costs that ACE would be permitted to re cover from retail ratepayers would be determined in accordance with the treatment of transmission-related revenue requirements in retail rates under the jurisdiction of the appropriate state regulatory commission. ACE cannot predict how the recovery of such costs will ultimately be treated by FERC and the state regulatory commissions and, therefore, cannot predict the financial impact to ACE of installing the recommended transmission upgrades. However, in the event that the NJBPU makes satisfactory findings and grants other requested approvals concerning the retirement of B.L. England and approves the construction of the transmission upgrades required to maintain reliability in the Atlantic zone after such retirement, ACE expects to begin construction of the appropriate transmission upgrades while final decisions by FERC and state regulatory commissions concerning the methodology for recovery of the costs of such construction are still pending. 224
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On November 1, 2004, ACE made a filing with the NJBPU requesting approval of the transmission upgrades required to maintain reliability in the Atlantic zone after the retirement of B.L. England. On December 22, 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. ACE cannot predict the outcome of these two proceedings. |
On November 12, 2004, ACE made a filing with the NJBPU requesting approval of year 2005 capital projects with respect to B.L. England. This filing was made pursuant the September 25, 2003 B.L. England rate order, which established a requirement that ACE file for approval of capital expenditures in excess of $1 million. For 2005, four projects, totaling $3.2 million in capital expenditures, have been identified as necessary to allow continued operation of B.L. England until its retirement. Two of these projects are well below the $1 million threshold set forth in the September 25, 2003 NJBPU order and two are above that threshold. ACE cannot predict the outcome of this proceeding. |
General Litigation |
Asbestos |
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, plaintiffs argue 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. Of the approximately 250 remaining asbestos cases pending against Pepco, approximately 85 cases were filed after December 19, 2000, and have been tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement. |
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 condition. However, if an 225
_____________________________________________________________________________ unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco's and PHI's results of operations. |
Enron |
On December 2, 2001, Enron North America Corp. and several of its affiliates (collectively, Enron) filed for protection under the United States Bankruptcy Code. In December 2001, DPL and Conectiv Energy terminated all energy trading transactions under various agreements with Enron. In late January 2003, after several months of discussions between the parties concerning the amount owed by DPL and Conectiv Energy, Enron filed an adversary complaint against Conectiv Energy in the Bankruptcy Court for the Southern District of New York. The complaint sought, among other things, damages in the amount of approximately $11.7 million. |
On June 3, 2004, the Bankruptcy Court approved a settlement among Enron, Conectiv Energy and DPL pursuant to which Conectiv Energy paid Enron an agreed settlement amount that was less than the $11.7 million damages Enron sought and the parties released all claims against each other. Conectiv Energy had previously established a reserve in an amount equal to the agreed settlement payment. Accordingly, the settlement did not have an effect on earnings. |
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. |
In May 2004, the U.S. Department of Justice (DOJ) invited DPL to enter into pre-filing negotiations in connection with DPL's alleged liability under CERCLA at the Diamond State Salvage site in Wilmington, Delaware. In the context of the negotiations, DOJ informed DPL that DPL is a de minimis party at the site. In February 2005, DPL entered into a de minimis consent decree with the United States which, if approved by the U.S. District Court, would require DPL to pay $144,000 as reimbursement of the government's response costs, resolve DPL's alleged liability, and provide DPL a covenant not to sue from the United States and protection from third-party claims for contribution. |
In July 2004, DPL entered into an Administrative Consent Order with the Maryland Department of the Environment (MDE) to perform a Remedial Investigation/Feasibility Study (RI/FS) to further identify the extent of soil, sediment and ground and surface water contamination related to former manufactured gas plant (MGP) operations at the Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The costs for completing the RI/FS for this site are approximately $300,000, approximately $50,000 of which will be expended in 2005. The costs of cleanup resulting from the RI/FS will not be determinable until the RI/FS is completed and an agreement with respect to cleanup is 226
_____________________________________________________________________________ reached with the MDE. DPL expects to complete the RI/FS in the first quarter of 2005. |
In October 1995, each of Pepco and DPL received notice from EPA that it, along with several hundred other companies, might be a PRP in connection with the Spectron Superfund Site in Elkton, Maryland. The site was operated as a hazardous waste disposal, recycling and processing facility from 1961 to 1988. |
In August 2001, Pepco entered into a consent decree for de minimis parties with EPA to resolve its liability at this site. Under the terms of the consent decree, which was approved by the U.S. District Court for the District of Maryland on March 31, 2003, Pepco made de minimis payments to the United States and a group of PRPs. In return, those parties agreed not to sue Pepco for past and future costs of remediation at the site and the United States will also provide protection against third-party claims for contributions related to response actions at the site. The consent decree does not cover any damages to natural resources. However, Pepco believes that any liability that it might incur due to natural resource damage at this site would not have a material adverse effect on its financial condition or results of operations. In February 2003, the EPA informed DPL that it will have no future liability for contribution to the remediation of the site. |
In the early 1970s, both Pepco and DPL sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In 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 October 1994, an RI/FS including a number of possible remedies was submitted to the EPA. In December 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 June 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs to conduct the design and actions called for in its decision. On May 12, 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 2, 2003, the Bankruptcy Court confirmed a Reorganization Plan that incorporates the terms of a settlement among the debtors, the United States and a group of utility PRPs including Pepco. Under the settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site. |
As of December 31, 2004, Pepco had accrued $1.7 million to meet its liability for a site remedy. At the present time, it is not possible to estimate the total extent of EPA's administrative and oversight costs or the expense associated with a site remedy ultimately implemented. However, Pepco believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations. |
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 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 condition or results of operations. |
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 227
_____________________________________________________________________________ 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 0.232 percent of the aggregate remediation liability and thus far ACE has made contributions of approximately $105,000. Based on information currently available, ACE may be required to contribute approximately an additional $100,000. ACE believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations. |
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 administrative consent order 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. The results of groundwater monitoring over the first year of this ground water sampling plan will help to determine the extent of post-remedy operation and maintenance costs. 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 may be required to contribute approximately an additional $626,000. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial condition or results of operations. |
On April 7, 2000, approximately 139,000 gallons of oil leaked from a pipeline at a generating facility that was owned by Pepco at Chalk Point generating facility in Aquasco, Maryland. The pipeline was operated by Support Terminals Services Operating Partnership LP (ST Services), an unaffiliated pipeline management company. The oil spread from Swanson Creek to the Patuxent River and several of its tributaries. The area affected covers portions of 17 miles of shoreline along the Patuxent River and approximately 45 acres of marshland adjacent to the Chalk Point property. |
In December 2000, the Department of Transportation, Office of Pipeline Safety, Research and Special Programs Administration (OPS) issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV). The NOPV alleged various deficiencies in compliance with regulations related to spill reporting, operations and maintenance of the pipeline and record keeping, none of which relate to the cause of the spill. The NOPV was issued to both Pepco and ST Services and proposed a civil penalty in the amount of $674,000. On June 2, 2004, the OPS issued a Final Order regarding the NOPV in this matter. The Final Order assessed a total fine of $330,250, with $256,250 of that amount assessed jointly against Pepco and ST Services and the remaining $74,000 assessed solely against ST Services. ST Services subsequently filed a Petition for Reconsideration. All penalties were stayed pending the outcome of the Petition for Rec onsideration. On February 9, 2005, OPS issued a Decision on the Petition for Reconsideration that affirmed the Final Order. Pepco's share of the $330,250 penalty assessed pursuant to the Final Order amounts to $128,125. 228
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Preliminary Settlement Agreement with the NJDEP |
In an effort to address NJDEP's concerns regarding ACE's compliance with New Source Review (NSR) requirements at B.L. England, on April 26, 2004, PHI, Conectiv and ACE entered into a preliminary settlement agreement with NJDEP and the Attorney General of New Jersey. The preliminary settlement agreement outlines the basic parameters for a definitive agreement to resolve ACE's NSR liability at B.L. England and various other environmental issues at ACE and Conectiv Energy facilities in New Jersey. Among other things, the preliminary settlement agreement provides that: |
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 246
_____________________________________________________________________________ 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. |
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. |
General Procurement Credit (GPC), Customer Sharing Commitment and Other: GPC represents the customers' share of profits that Pepco has realized on the procurement and resale of generation services to standard offer service customers that has not yet been distributed to customers. Pepco is currently distributing the customers' share of profits monthly to customers in a billing credit. 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 in each jurisdiction. |
Removal Costs: Represents Pepco's asset retirement obligation associated with removal costs accrued using Commission approved depreciation rates for transmission, distribution, and general utility property. In accordance with SFAS No. 143, accruals for removal costs were classified as a regulatory liability. |
Revenue Recognition |
Pepco's revenue for services rendered but unbilled as of the end of each month is accrued and included in the accounts receivable balance on the accompanying consolidated balance sheets. Pepco recorded amounts for unbilled revenue of $103.2 million and $74.5 million as of December 31, 2004 and 2003, respectively. These amounts are included in the "accounts receivable" line item in the accompanying consolidated balance sheets. Additionally, the collection of 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. Payments of 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. |
In connection with Pepco's acquisition of Conectiv on August 1, 2002, ownership of Pepco's pre-merger subsidiaries, Potomac Capital Investment Corporation (PCI) and Pepco Energy Services, Inc. (Pepco Energy Services) was transferred to Pepco Holdings. Pre-merger revenue in 2002 recorded by Pepco from Pepco Energy Services' energy services contracts and from PCI's utility industry services contracts was recognized using the percentage-of-completion method of revenue recognition, which recognized revenue as work progressed on the contract. Revenue from Pepco Energy Services' electric 247
_____________________________________________________________________________ and gas marketing businesses was recognized as services when rendered. Pepco Energy Services' and PCI's revenues were recorded by Pepco pre-merger. |
Transition Power Agreement and Generation Procurement Credit |
As part of the agreement to divest its generation assets, Pepco entered into separate Transition Power Agreements (TPAs) with Mirant for the District of Columbia and Maryland. In connection with Mirant's bankruptcy proceeding, the TPAs were amended by the Amended Settlement Agreement and Release dated as of October 24, 2003 (Settlement Agreement). For information regarding the impact of Mirant's bankruptcy on Pepco's operations, refer to the Note (11) "Commitments and Contingencies, Relationship with Mirant Corporation" section, herein. |
Asset Retirement Obligations |
Pepco adopted Financial Accounting Standards Board (FASB) Statement No. 143 entitled "Accounting for Asset Retirement Obligations" (SFAS No. 143), on January 1, 2003. This Statement establishes the accounting and reporting standards for measuring and recording asset retirement obligations. Based on the implementation of SFAS No. 143, at December 31, 2004 and 2003, $77.2 million and $76.4 million, respectively, of removal costs have been classified as a regulatory liability in the accompanying Consolidated Balance Sheets. |
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 PHI and certain of its subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources. |
Accounts Receivable and Allowance for Uncollectible Accounts |
Pepco's accounts receivable balances primarily consist of customer account 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. Pepco uses the allowance method to account for uncollectible accounts receivable. |
Capitalizable 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. The cost of additions to, and replacements or betterments of, retirement units of property and plant is capitalized. Such costs include material, labor, the capitalization of an Allowance for Funds Used During Construction (AFUDC) and applicable indirect costs, including engineering, supervision, payroll taxes and employee benefits. 248
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Pepco recorded AFUDC for borrowed funds of $1.2 million, $1.8 million, and $2.7 million for the years ended December 31, 2004, 2003, and 2002, respectively. These amounts are recorded as a reduction of "interest expense" within the "other income (expense)" caption in the accompanying consolidated statements of earnings. |
Pepco recorded amounts for AFUDC equity income of $2.0 million, $2.9 million, and $2.5 million for the years ended December 31, 2004, 2003, and 2002, respectively. The amounts are included in the "other income" caption of the accompanying consolidated statements of earnings. |
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 November 2004, PHI announced that its Power Delivery business planned to reduce its 4,200 employee work force by approximately 2% to 3% by the end of 2004. This work force reduction was accomplished 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 Association 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 Ex it an Activity (including Certain Costs Incurred in a Restructuring)." A roll forward of the severance accrual balance is as follows. (Amounts in millions) |
Based on the number of employees that have accepted or are expected to accept the severance packages, substantially all of the severance liability related to the 2002 plan will be paid through mid 2005. Employees have the option of taking severance payments in a lump sum or over a period of time. |
Pension and Other Post Retirement Benefit Plans |
Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, Conectiv 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 the provisions and benefits of 249
_____________________________________________________________________________ the merged Retirement Plan are identical to the original Conectiv plan. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. In addition to sponsoring non-contributory retirement plans, Pepco Holdings provides certain post-retirement 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 post-retirement benefits in accordance with SFAS No. 106, "Employers' Accounting for Post-retirement Benefits Other Than Pensions." PHI's financial statement disclosures were prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Post-retirement Benefits." |
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 if there is 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 shall only be recognized 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, refer to the "Asset Retirement Obligations" section included in this Note to the consolidated financial statements. |
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. The relationship of the annual provision for depreciation for financial accounting purposes to average depreciable property was 3.5% for 2004, 2003, and 2002. 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. |
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, determined on a separate return basis. 250
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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 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 Consolidated Balance Sheets. For additional information, see the discussion under "Regulation of Power Delivery Operations" shown 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 plants purchased in prior years are reported on the Consolidated Balance Sheets as "Investment tax credits." These investment tax credits are being amortized to income over the useful lives of the related utility plant. |
SFAS No. 150 |
Effective July 1, 2003 Pepco implemented SFAS No. 150 entitled "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). This Statement established standards for how an issuer classifies and measures in its Consolidated Balance Sheet certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 resulted in Pepco's reclassification (initially as of September 30, 2003) of its "Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Which Holds Solely Parent Junior Subordinated Debentures" (TOPrS) and "Mandatorily Redeemable Serial Preferred Stock" on its Consolidated Balance Sheet to a long-term liability classification. Additionally, in accordance with the provisions of SFAS No. 150, dividends on the TOPrS and Mandatorily Redeemable Serial Preferred Stock, declared subsequent to the July 1, 2003 implementation of SFAS No. 150, are recorded as interest expense in Pepco's Consolidated Statement of Earnings for the years ended December 31, 2004 and 2003. In accordance with the transition provisions of SFAS No. 150, amounts prior to 2003 were not reclassified. |
FIN 45 |
Pepco applied the provisions of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45), commencing in 2003 to its agreements that contain guarantee and indemnification clauses. These provisions expand those required by FASB Statement No. 5, "Accounting for Contingencies," by requiring a guarantor to recognize a liability on its balance sheet for the fair value of obligations it assumes under certain guarantees issued or modified after December 31, 2002 and to disclose certain types of guarantees, even if the likelihood of requiring the guarantor's performance under the guarantee is remote. 251
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As of December 31, 2004 and 2003, Pepco did not have material obligations under guarantees or indemnifications issued or modified after December 31, 2002, that are required to be recognized as a liability on its balance sheets. |
FIN 46 |
On December 31, 2003, FIN 46 was implemented by Pepco. FIN 46 was revised and superseded by FASB Interpretation No. 46R (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. FIN 46R was effective December 31, 2003 for variable interest entities that were considered to be special-purpose entities, and effective March 31, 2004 to all other variable interest entities. The implementation of FIN 46R (including the evaluation of interests in power purchase arrangements) did not impact Pepco's financial condition or results of operations for the years ended December 31, 2004 and 2003. |
As part of its FIN 46R evaluation, Pepco reviewed its power purchase agreements (PPAs), including its Non-Utility Generation (NUG) contracts, to determine (i) if its interest in each entity that is a counterparty to a PPA agreement was a variable interest, (ii) whether the entity was a variable interest entity and (iii) if so, whether Pepco was the primary beneficiary. Due to a variable element in the pricing structure of its PPA with one entity, Panda-Brandywine, L.P. (Panda), Pepco potentially assumes the variability in the operations of the plant of this entity and therefore has a variable interest in the entity. However, due to Pepco's inability to obtain information considered to be confidential and proprietary from the entity, Pepco 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. |
Power purchases related to the Panda PPA in the years ended December 31, 2004, 2003, and 2002 were approximately $76 million, $80 million, and $74 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. 252
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Reclassifications |
Certain prior year amounts have been reclassified in order to conform to current year presentations. |
(3) SEGMENT INFORMATION |
As a result of the merger transaction on August 1, 2002, Pepco has determined that its utility operations represent its only operating segment under the provisions of Statement of Financial Accounting Standards No. 131 "Disclosures about Segments of an Enterprise and Related Information" (SFAS No. 131). The information presented is in millions of dollars. |
The methods and assumptions below were used to estimate, at December 31, 2004 and 2003, the fair value of each class of financial instrument shown above for which it is practicable to estimate that value. |
The fair values of the Long-term Debt, which include First Mortgage Bonds and Medium-Term 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. |
The fair values of the Serial Preferred Stock and Mandatorily Redeemable Serial Preferred Stock, excluding amounts due within one year, were 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., pursuant to an Asset Purchase and Sale Agreement. As part of the Asset Purchase and Sale Agreement, Pepco entered into several ongoing contractual arrangements with Mirant and certain of its subsidiaries (collectively, Mirant). On July 14, 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). |
Depending on the outcome of the matters discussed below, the Mirant bankruptcy could have a material adverse effect on the results of operations of Pepco Holdings and Pepco. However, management currently 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 have arisen or may arise due to the Mirant bankruptcy. Accordingly, management does not 269
_____________________________________________________________________________ anticipate that the Mirant bankruptcy will impair the ability of Pepco Holdings or Pepco to fulfill their 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 these agreements, Mirant was obligated to supply Pepco with all of the capacity and energy needed to fulfill its standard offer service obligations in Maryland through June 2004 and its standard offer service obligations in the District of Columbia through January 22, 2005. |
To avoid the potential rejection of the TPAs, Pepco and Mirant entered into an Amended Settlement Agreement and Release dated as of October 24, 2003 (the Settlement Agreement) pursuant to which Mirant assumed both of the TPAs and the terms of the TPAs were modified. The Settlement Agreement also provided that Pepco has an allowed, pre-petition general unsecured claim against Mirant Corporation in the amount of $105 million (the Pepco TPA Claim). |
Pepco has also asserted the Pepco TPA Claim against other Mirant entities that Pepco believes are liable to Pepco under the terms of the Asset Purchase and Sale Agreement's Assignment and Assumption Agreement (the Assignment Agreement). Under the Assignment Agreement, Pepco believes that each of the Mirant entities assumed and agreed to discharge certain liabilities and obligations of Pepco as defined in the Asset Purchase and Sale Agreement. Mirant has filed objections to these claims. Under the current plan of reorganization filed by the Mirant entities with the Bankruptcy Court, certain Mirant entities other than Mirant Corporation would pay significantly higher portions of the claims of their creditors than would Mirant Corporation. The amount that Pepco will be able to recover from the Mirant bankruptcy estate with respect to the Pepco TPA Claim will depend on the amount of assets available for distribution to creditors of the Mirant e ntities that are found to be liable for the Pepco TPA Claim. |
Power Purchase Agreements |
Under agreements with FirstEnergy Corp., formerly Ohio Edison (FirstEnergy), and Allegheny Energy, Inc., both entered into in 1987, Pepco is obligated to purchase from FirstEnergy 450 megawatts of capacity and energy annually through December 2005 (the FirstEnergy PPA). Under an agreement with Panda, entered into in 1991, Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (the Panda PPA). In each case, the purchase price is substantially in excess of current 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 is obligated, among other things, to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the FirstEnergy PPA and the Panda PPA at a price equal to the price Pepco is obligated to pay under the FirstEnergy PPA and the Panda PPA (the PPA-Related Oblig ations). 270
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Pepco Pre-Petition Claims |
When Mirant filed its bankruptcy petition on July 14, 2003, Mirant had unpaid obligations to Pepco of approximately $29 million, consisting primarily of payments due to Pepco in respect of the PPA-Related Obligations (the Mirant Pre-Petition Obligations). The Mirant Pre-Petition Obligations constitute part of the indebtedness for which Mirant is seeking relief in its bankruptcy proceeding. Pepco has filed Proofs of Claim in the Mirant bankruptcy proceeding in the amount of approximately $26 million to recover this indebtedness; however, the amount of Pepco's recovery, if any, is uncertain. The $3 million difference between Mirant's unpaid obligation to Pepco and the $26 million Proofs of Claim primarily represents a TPA settlement adjustment which is included in the $105 million Proofs of Claim filed by Pepco against the Mirant debtors in respect of the Pepco TPA Claim. In view of this uncertainty, Pepco, in the third quarter of 2003, expen sed $14.5 million to establish a reserve against the $29 million receivable from Mirant. In January 2004, Pepco paid approximately $2.5 million 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. Pepco believes that under the terms of the Asset Purchase and Sale Agreement, Mirant is obligated to reimburse Pepco for the settlement payment. Accordingly, in the first quarter of 2004, Pepco increased the amount of the receivable due from Mirant by approximately $2.5 million and amended its Proofs of Claim to include this amount. Pepco currently estimates that the $14.5 million expensed in the third quarter of 2003 represents the portion of the entire $31.5 million receivable unlikely to be recovered in bankruptcy, and no additional reserve has been established for the $2.5 million increase in the receivable. The amount expensed represents Pepco's estimate of the possible outcome in bankruptcy, although the amou nt ultimately recovered could be higher or lower. |
Mirant's Attempt to Reject the PPA-Related Obligations |
On August 28, 2003, Mirant filed with the Bankruptcy Court a motion seeking authorization to reject its PPA-Related Obligations. Upon motions filed with the U.S. District Court for the Northern District of Texas (the District Court) by Pepco and FERC, in October 2003, the District Court withdrew jurisdiction over the rejection proceedings from the Bankruptcy Court. In December 2003, the District Court denied Mirant's motion to reject the PPA-Related Obligations on jurisdictional grounds. The District Court's decision was appealed by Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation (the Creditors' Committee) to the U.S. Court of Appeals for the Fifth Circuit (the Court of Appeals). On August 4, 2004, the Court of Appeals remanded the case to the District Court saying that the District Court has jurisdiction to rule on the merits of Mirant's rejection motion, suggesting that in doing so the court apply a "more ri gorous standard" than the business judgment rule usually applied by bankruptcy courts in ruling on rejection motions. |
On December 9, 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. On December 16, the Creditors' Committee appealed the District Court's order to the Court of Appeals, and on December 20, 2004, Mirant also appealed the District Court's order. 271
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As more fully discussed below, Mirant had been making regular periodic payments in respect of the PPA-Related Obligations. On December 9, 2004, Mirant filed a notice with the Bankruptcy Court that it was suspending payments to Pepco in respect of the PPA-Related Obligations. On December 13, 2004, Mirant failed to make a payment of approximately $17.9 million due to Pepco for the period November 1, 2004 to November 30, 2004. Mirant failed to make that payment. On December 23, 2004, Pepco received a payment of approximately $6.8 million from Mirant, which according to Mirant represented the market value of the power for which payment was due on December 13. Mirant has informed Pepco that it intends to continue to pay the market value, but not the above-market portion, of the power purchased under the PPA-Related Obligations. Pepco disagrees with Mirant's assertion that it need only pay the market value and believes that the amount repr esenting the market value calculated by Mirant is insufficient. |
On January 21, 2005, Mirant made a approximately $21.1 million, which, according to Mirant, includes the payment for the FirstEnergy PPA for December 2004 and "includes the December 2004 TPA revenue in the amount of $29,093,173.43, the TPA costs in the amount of $37,865,924.10, and an allocated share of [FirstEnergy's] PPA bill credits/charges in the amount of $5,490,164.79." Pepco disputes Mirant's contention that the amount paid reflects the full amount due Pepco under these agreements for the applicable periods. |
As of March 1, 2005, Mirant has withheld payment of approximately $34.8 million due to Pepco under the PPA-Related Obligations. |
On January 21, 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. On March 1, 2005 (as amended by order dated March 7, 2005), the District Court granted Pepco's motion to withdraw jurisdiction over the Asset Purchase and Sale Agreement rejection proceedings from the Bankruptcy Court. In addition, the District Court ordered Mirant to pay on March 18, 2005, all past-due unpaid amounts under the PPA-Related Obligations. Mirant has filed a motion for reconsideration and a stay of the March 1, 2005 order. |
Pepco is exercising all available legal remedies and vigorously opposing Mirant's attempt to reject the PPA-Related Obligations and other 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 the attempt to reject the agreements, the outcome of Mirant's efforts to reject the PPA-Related Obligations is uncertain. |
If Mirant ultimately is successful in rejecting the PPA-Related Obligations, Pepco could be required to repay to Mirant, for the period beginning on the effective date of the rejection (which date could be prior to the date of the court's order and possibly as early as September 18, 2003) and ending on the date Mirant is entitled to cease its purchases of energy and capacity from Pepco, all amounts paid by Mirant to Pepco in respect of the PPA-Related Obligations, less an amount equal to the price at which Mirant resold the purchased energy and capacity. Pepco estimates that the amount it could be required to repay to Mirant in the unlikely event that September 18, 2003, is determined to be the effective date of rejection, is approximately $133.2 million as of March 1, 2005 (assuming Mirant continues to withhold unpaid amounts of approximately $34.8 million as of March 1, 2005. 272
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Mirant has also indicated to the Bankruptcy Court that it will move to require Pepco to disgorge all amounts paid by Mirant to Pepco in respect of the PPA-Related Obligations, less an amount equal to the price at which Mirant resold the purchased energy and capacity, for the period July 14, 2003 (the date on which Mirant filed its bankruptcy petition) through rejection, if approved, on the theory that Mirant did not receive value for those payments. Pepco estimates that the amount it would be required to repay to Mirant on the disgorgement theory, in addition to the amounts described above, is approximately $22.5 million. |
Any repayment by Pepco of amounts paid by Mirant would entitle Pepco to file a claim against the bankruptcy estate in an amount equal to the amount repaid. Pepco believes that, to the extent such amounts were not recovered from the Mirant bankruptcy estate, they would be recoverable as stranded costs from customers through distribution rates as described below. |
The following are estimates prepared by Pepco of its potential future exposure if Mirant's attempt to reject the PPA-Related Obligations ultimately is successful. 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. The estimates assume no recovery from the Mirant bankruptcy estate and no regulatory recovery, either of which would mitigate the effect of the estimated loss. Pepco does not consider it realistic to assume that there will be no such recoveries. Based on these assumptions, Pepco estimates that its pre-tax exposure as of March 1, 2005, representing the loss of the future benefit of the PPA-Related Obligations to Pepco, is as follows: |
The ability of Pepco to recover from the Mirant bankruptcy estate in respect to the Mirant Pre-Petition Obligations and damages if the PPA-Related Obligations are successfully rejected will depend on whether Pepco's claims are allowed, the amount of assets available for distribution to the creditors of the Mirant companies determined to be liable for those claims, and Pepco's priority relative to other creditors. At the current stage of the bankruptcy proceeding, there is insufficient information to determine the amount, if any, that Pepco might be able to recover from the Mirant bankruptcy estate, whether the recovery would be in cash or another form of payment, or the timing of any recovery. |
If Mirant ultimately is successful in rejecting the PPA-Related Obligations and Pepco's full claim is not recovered from the Mirant 273
_____________________________________________________________________________ bankruptcy estate, Pepco may 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, if Mirant ultimately is successful in rejecting the PPA-Related Obligations, 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 as a regulator y asset. However, there is no assurance that Pepco's interpretation of the settlement agreements would be confirmed by the respective public service commissions. |
If the PPA-Related Obligations are successfully rejected, and there is no regulatory recovery, Pepco will incur a loss. However, the accounting treatment of such a loss depends on a number of legal and regulatory factors, and is not determinable at this time. |
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, Inc. (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 facility and capacity credit 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. Pepco believes that there is no reasonable factual or legal basis to support Mirant's contention that the SMECO Agreement is a lease of real property. Litigation continues and the outcome of this proceeding cannot be predicted. |
Rate Proceedings |
In compliance with the settlement approved by the MPSC in connection with the merger of Pepco and Conectiv, on December 4, 2003, Pepco submitted testimony and supporting schedules to review and reset if necessary its electricity distribution rates in Maryland to be effective July 1, 2004, when the then-current distribution rate freeze/caps ended. Pepco's filing demonstrated that it was in an under-earning situation. However the merger settlement provided that Pepco's distribution rates after July 1, 2004 could only remain the same or be decreased. With limited exceptions, Pepco cannot increase its distribution rates until January 1, 2007. In an order dated July 6, 2004 the MPSC affirmed the Hearing Examiner's recommendation that no rate decrease was warranted at that time. 274
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On July 3, 2004, Pepco filed a distribution rate review case with the DCPSC as required by the terms of the Pepco-Conectiv merger settlement approved by the DCPSC. This case will determine whether Pepco's distribution rates will be decreased. In accordance with the terms of the merger settlement, Pepco's distribution rates cannot be increased as a result of the case. On November 24, 2004, the DCPSC issued an order that designated the issues to be considered in the case and set the hearing schedule. On December 17, 2004, Pepco filed supplemental direct testimony addressing the DCPSC-designated issues. Pepco's filings indicate that no rate decrease is warranted. On March 4, 2005, the DCPSC issued an order granting a joint motion filed on March 3, 2005, on behalf of Pepco and several other parties in the case to suspend the procedural schedule to allow the parties to focus on completing settlement discussions. In the joint motion, the movin g parties informed the DCPSC that they had agreed in principle to settlement provisions that would resolve all issues in the proceeding and that a settlement agreement could be filed in the near future. |
Divestiture Cases |
District of Columbia |
Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed on July 31, 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. 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. On March 4, 2003, the Internal Revenue Service (IRS) issued a notice of proposed rulemaking (NOPR) that is relevant to that principal issue. Comments on the NOPR were filed by several parties on June 2, 2003, and the IRS held a public hearing on June 25, 2003. As a result of the NOPR, three of the parties in the divestiture case filed comments with the DCPSC urging the DCPSC to decide the tax issues now on the basis of the proposed rule. Pepco filed comments with the DCPSC in reply to those comments, in which Pepco stated that the courts have held and the IRS has stated that proposed rules are not authoritative and that no decision should be issued on the basis of proposed rules. Instead, Pepco argued that the only prudent course of action is for the DCPSC to await the issuance of final regulations relating to the tax issues and then allow the parties to file supplemental briefs on the tax issues. Pepco cannot predict whether the IRS will adopt the regulations as proposed, make changes before issuing final regulations or decide not to adopt regulati ons. Other issues in the proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture. |
Pepco believes that a sharing of EDIT and ADITC would violate the normalization rules. 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. Pepco, in addition to sharing with customers the generation-related ADITC balance, would have to pay to the IRS an amount equal to Pepco's $5.8 million District of Columbia jurisdictional generation-related ADITC balance as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance as of the later of the date a DCPSC 275
_____________________________________________________________________________ order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative. As of December 31, 2004, the District of Columbia jurisdictional transmission and distribution-related ADITC balance was approximately $6.0 million. |
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 D.C. 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 condition. It is uncertain when the DCPSC will issue a decision. |
Maryland |
Pepco filed its divestiture proceeds plan application in Maryland in April 2001. Reply briefs were filed in May 2002. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that was raised in the D.C. case. As of December 31, 2004, the Maryland 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 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 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, i.e., $9.1 million, and the generation-related ADITC. If such sharing were to violate the normalization rules, Pepco, in addition to sharing with customers an amount equal to approximately 50 percent of the generation-related ADITC balance, would be unable to use accelerated depreciation on Maryland allocated or assigned property. Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco's $10.4 million Maryland jurisdictional generation-related ADITC balance, as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance 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. As of December 31, 2004, the Maryland retail jurisdictional tran smission and distribution-related ADITC balance was approximately $10.7 million. The Hearing Examiner decided all other issues in favor of Pepco, except 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. See also the disclosure above under "Divestiture Cases - District of Columbia" regarding the March 4, 2003 IRS NOPR. |
Under Maryland law, if the proposed order is appealed to the MPSC, the proposed order is not a final, binding order of the MPSC and further action by the MPSC is required with respect to this matter. Pepco has appealed the Hearing Examiner's decision on the treatment of EDIT and ADITC and corporate reorganization costs to the MPSC. Pepco cannot predict what the outcome of 276
_____________________________________________________________________________ the appeal will be or when the appeal might be decided. 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 condition. |
SOS and Default Service Proceedings |
District of Columbia |
In February 2003, the DCPSC opened a new proceeding to consider issues relating to (a) the establishment of terms and conditions for providing standard offer service (SOS) in the District of Columbia after Pepco's obligation to provide SOS terminated on February 7, 2005, and (b) the selection of a new SOS provider. |
In December 2003, the DCPSC issued an order that set forth the terms and conditions for the selection of a new SOS provider(s) and the provision of SOS by Pepco on a contingency basis. In December 2003, the DCPSC also issued an order adopting terms and conditions that would apply if Pepco continued as the SOS provider after February 7, 2005. In March 2004, the DCPSC issued an order adopting the wholesale SOS model, i.e., Pepco would continue to be the SOS provider in the District of Columbia after February 7, 2005. This March 2004 order, as amended by a DCPSC order issued in July 2004, extends Pepco's obligation to provide default electricity supply at market rates for up to an additional 76 months for small commercial and residential customers, and for an additional 28 months for large commercial customers. |
In August 2004, the DCPSC issued an order adopting administrative charges for residential, small and large commercial DC 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 $0.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial DC 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 DC 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 DC SOS sales on February 8, 2005. Pepco completed the first competitive procurement process for DC SOS at the end of October and filed the proposed new SOS rates with the DC PSC on November 3, 2004. |
The TPA with Mirant under which Pepco obtained the fixed-rate DC 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 DC 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 DC SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new DC SOS rates did not go into effect until February 8, 2005, Pepco had to pay the 277
_____________________________________________________________________________ difference between the procurement cost of power under the new DC SOS contracts and the DC 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, will be included in the calculation of the Generation Procurement Credit (GPC) for DC for the period February 8, 2004 through February 7, 2005. 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. Currently, based on the rates paid by Pepco to Mirant under the TPA Settlement, there is no customer sharing. However, in the event that Pepco were to ultimately realize a significant recovery from the Mirant bankruptcy estate associated with the TPA Settlement, the GPC would be re calculated, and the amount of customer sharing with respect to such recovery would be reduced because of the $8.7 million loss being included in the GPC calculation. |
Maryland |
Under a settlement approved by the MPSC in April 2003 addressing SOS service in Maryland following the expiration of Pepco's fixed-rate default supply obligations in July 2004, Pepco is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, Pepco purchases the power supply required to satisfy its market rate default supply obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the MPSC. Pepco is entitled to recover from its default supply customers the cost of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, small and large commercial Maryland SOS customers over the twelve months ended December 31, 200 3. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period. |
General Litigation |
Asbestos |
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, plaintiffs argue 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. Of the approximately 250 remaining asbestos cases pending 278
_____________________________________________________________________________ against Pepco, approximately 85 cases were filed after December 19, 2000, and have been tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement. |
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 condition. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco's and PHI's results of operations. |
Environmental Litigation |
Pepco is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. Pepco may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. |
In October 1995, Pepco received notice from the Environmental Protection Agency (EPA) that it, along with several hundred other companies, might be a potentially responsible party (PRP) in connection with the Spectron Superfund Site in Elkton, Maryland. The site was operated as a hazardous waste disposal, recycling and processing facility from 1961 to 1988. |
In August 2001, Pepco entered into a consent decree for de minimis parties with EPA to resolve its liability at this site. Under the terms of the consent decree, which was approved by the U.S. District Court for the District of Maryland on March 31, 2003, Pepco made de minimis payments to the United States and a group of PRPs. In return, those parties agreed not to sue Pepco for past and future costs of remediation at the site and the United States will also provide protection against third-party claims for contributions related to response actions at the site. The consent decree does not cover any damages to natural resources. However, Pepco believes that any liability that it might incur due to natural resource damage at this site would not have a material adverse effect on its financial condition or results of operations. |
In the early 1970s, Pepco sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In December 1987, Pepco was notified by EPA that it, along with a number of other utilities and non-utilities, was a PRP in connection with the PCB contamination at the site. |
In October 1994, Remedial Investigation/Feasibility Study including a number of possible remedies was submitted to the EPA. In December 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 June 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs to conduct the design and actions called for in its decision. On May 12, 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 2, 2003, the Bankruptcy Court confirmed a Reorganization Plan that incorporates 279
_____________________________________________________________________________ the terms of a settlement among the debtors, the United States and a group of utility PRPs including Pepco. Under the settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site. |
As of December 31, 2004, Pepco had accrued $1.7 million to meet its liability for a site remedy. At the present time, it is not possible to estimate the total extent of EPA's administrative and oversight costs or the expense associated with a site remedy ultimately implemented. However, Pepco believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations. |
On April 7, 2000, approximately 139,000 gallons of oil leaked from a pipeline at a generating facility that was owned by Pepco at Chalk Point generating facility in Aquasco, Maryland. The pipeline was operated by Support Terminals Services Operating Partnership LP (ST Services), an unaffiliated pipeline management company. The oil spread from Swanson Creek to the Patuxent River and several of its tributaries. The area affected covers portions of 17 miles of shoreline along the Patuxent River and approximately 45 acres of marshland adjacent to the Chalk Point property. |
In December 2000, the Department of Transportation, Office of Pipeline Safety, Research and Special Programs Administration (OPS) issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV). The NOPV alleged various deficiencies in compliance with regulations related to spill reporting, operations and maintenance of the pipeline and record keeping, none of which relate to the cause of the spill. The NOPV was issued to both Pepco and ST Services and proposed a civil penalty in the amount of $674,000. On June 2, 2004, the OPS issued a Final Order regarding the NOPV in this matter. The Final Order assessed a total fine of $330,250, with $256,250 of that amount assessed jointly against Pepco and ST Services and the remaining $74,000 assessed solely against ST Services. ST Services subsequently filed a Petition for Reconsideration. All penalties were stayed pending the outcome of the Petition for Rec onsideration. On February 9, 2005, OPS issued a Decision on the Petition for Reconsideration that affirmed the Final Order. Pepco's share of the $330,250 penalty assessed pursuant to the Final Order amounts to $128,125. |
(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, 2004, 2003 and 2002 were approximately $90.1 million, $82.8 million and $2.6 million, respectively. In 2002, Pepco charged $6.4 million to PHI Service Company for various administrative and professional services. |
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, 2004, 2003 and 2002 were approximately $14.1 million, $11.3 million and $10.7 million, respectively. 280
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In addition to the transactions described above, Pepco's financial statements include the following related party transactions in its Consolidated Statement of Earnings: |
A description of the regulatory assets and regulatory liabilities is as follows: |
Deferred Energy Supply Costs: Primarily represents deferred costs relating to the provision of Basic Generation Service (BGS) and other restructuring related costs incurred by DPL. Also includes 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 Contracts: Represents deferred costs related to purchase power contracts at DPL which are being recovered over 9 years and 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 amortized. |
Removal Costs: Represents DPL's asset retirement obligation associated with removal costs accrued using Commission approved depreciation rates for transmission, distribution and general utility property. In accordance with SFAS No. 143, accruals for removal costs were classified as a regulatory liability. |
Revenue Recognition |
DPL recognizes revenues for the supply and delivery of electricity and gas upon delivery to the customer, including amounts for services rendered, but not yet billed. DPL recorded amounts for unbilled revenue of $66.2 million and $57.8 million as of December 31, 2004 and 2003, respectively. These amounts are included in the "accounts receivable" line item in the accompanying consolidated balance sheets. Similarly, revenues from other 292
_____________________________________________________________________________ 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 "Gas" revenues, respectively. Additionally, the collection of 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. Payments of 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. |
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, determined on a separate return basis. |
The Consolidated 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 Consolidated Balance Sheets. For additional information, see the discussion under "Regulation of Power Delivery Operations," shown 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. |
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, are fully recoverable through the fuel adjustment clause approved by the DPSC and are deferred under SFAS No. 71 until recovered. At December 31, 2004, there was a deferred derivative liability on DPL's balance sheet of $1.5 million, and a negative adjustment balance for the fair value hedge of $1.1 mil lion, offset by a $2.6 million regulatory asset. 293
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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. The Company 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. The cost of additions to, and replacements or betterments of, retirement units of property and plant is capitalized. Such costs include material, labor, the capitalization of an Allowance for Funds Used During Construction (AFUDC) and applicable indirect costs, including engineering, supervision, payroll taxes and employee benefits. |
DPL recorded AFUDC for borrowed funds of $.3 million, $.3 million, and $.6 million for the years ended December 31, 2004, 2003, and 2002, respectively. These amounts are recorded as a reduction of "interest expense" in the accompanying consolidated statements of earnings. |
DPL recorded amounts for AFUDC equity income of $.4 million, $.5 million and $.9 million for the years ended December 31, 2004, 2003 and 2002, 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 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. 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. |
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 2004 DPL tested its goodwill for 294
_____________________________________________________________________________ impairment as of July 1, 2004. This testing 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 if there is 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 shall only be recognized 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 Post Retirement Plans |
Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, Conectiv 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 the provisions and benefits of the merged Retirement Plan are identical to the original Conectiv plan. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. In addition to sponsoring non-contributory retirement plans, Pepco Holdings provides certain post-retirement health care and life insurance benefits fo r eligible retired employees. |
The Company accounts for the Retirement Plan in accordance with SFAS No. 87, "Employers' Accounting for Pensions" and its other post-retirement benefits in accordance with SFAS No. 106, "Employers' Accounting for Post-retirement Benefits Other Than Pensions." DPL's financial statement disclosures were prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Post-retirement 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, refer to the "Asset Retirement Obligations" section included in this Note to the consolidated financial statements. 295
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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. The relationship of the annual provision for depreciation for financial accounting purposes to average depreciable property was 3.1% for 2004, 3.1% for 2003, and 3.2% for 2002. 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 PHI and certain of its 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 Financial Accounting Standards Board (FASB) Statement No. 143 entitled "Accounting for Asset Retirement Obligations," (SFAS No. 143) on January 1, 2003. This Statement establishes the accounting and reporting standards for measuring and recording asset retirement obligations. Based on the implementation of SFAS No. 143, at December 31, 2004 and 2003, $176.9 million and $181.5 million in asset removal costs have been classified as a regulatory liability in the accompanying Consolidated Balance Sheets. |
SFAS 150 |
Effective July 1, 2003, DPL implemented SFAS No. 150 entitled "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). This Statement established standards for how an issuer classifies and measures, in its Consolidated Balance Sheet, certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 resulted in DPL's reclassification (initially as of September 30, 2003) of its "Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Which Holds Solely Parent Junior Subordinated Debentures" (TOPrS) on its Consolidated Balance Sheet to a long term liability classification. Additionally, in accordance with the provisions of SFAS No. 150, dividends on the TOPrS declared subsequent to the July 1, 2003 implementation of SFAS No. 150, are recorded as interest expense in DPL's Consolidated Statement of Earnings for the years end ed December 31, 2004 and 2003. In accordance with the transition provisions of SFAS No. 150, amounts prior to 2003 were not reclassified. |
In December 2003, the FASB deferred for an indefinite period the application of the guidance in SFAS No. 150 to non-controlling interests that are classified as equity in the financial statements of a subsidiary but would be classified as a liability in the parent's financial statements under SFAS No. 150. The deferral is limited to mandatorily redeemable non-controlling interests associated with finite-lived subsidiaries. DPL does not have an 296
_____________________________________________________________________________ interest in any such applicable entities as of December 31, 2004 and 2003, but will continue to evaluate the applicability of this deferral to entities which may be consolidated as a result of FASB Interpretation No. 46, "Consolidation of Variable Interest Entities." |
FIN 45 |
DPL applied the provisions of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45), commencing in 2003 to its agreements that contain guarantee and indemnification clauses. These provisions expand those required by FASB Statement No. 5, "Accounting for Contingencies," by requiring a guarantor to recognize a liability on its balance sheet for the fair value of obligations it assumes under certain guarantees issued or modified after December 31, 2002 and to disclose certain types of guarantees, even if the likelihood of requiring the guarantor's performance under the guarantee is remote. |
As of December 31, 2004 and 2003, DPL did not have material obligations under guarantees or indemnifications issued or modified after December 31, 2002, that are required to be recognized as a liability on its consolidated balance sheets. |
FIN 46 |
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, 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 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. |
Reclassifications |
Certain prior year amounts have been reclassified in order to conform to current year presentations. 297
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(3) SEGMENT INFORMATION |
In accordance with SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," DPL has one segment, its regulated utility business. |
(4) LEASING ACTIVITIES |
DPL leases an 11.9% interest in the Merrill Creek Reservoir. The lease is an operating lease and payments over the remaining lease term, which ends in 2032, are $122.4 million in aggregate. DPL also has long-term leases for certain other facilities and equipment. Minimum commitments as of December 31, 2004, under the Merrill Creek Reservoir lease and other lease agreements are as follows: 2005-$8.6 million; 2006-$8.6 million; 2007-$8.6 million; 2008-$9.4 million; 2009-$9.4 million; beyond 2009-$106.8 million; total-$151.4 million. |
(5) PROPERTY, PLANT AND EQUIPMENT |
Property, plant and equipment is comprised of the following: |
The methods and assumptions below were used to estimate, at December 31, 2004 and 2003, the fair value of each class of financial instruments shown above for which it is practicable to estimate that value. |
The fair value of the Investments was derived based on quoted market prices. |
The fair values of the Long-term Debt, which includes First Mortgage Bonds, Amortizing First Mortgage Bonds, Unsecuritized Tax-Exempt Bonds, and Medium-Term 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 values of the Debentures issued to Financing Trust 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 DPL's accompanying financial statements approximate fair value. |
(11) COMMITMENTS AND CONTINGENCIES |
REGULATORY AND OTHER MATTERS |
Rate Proceedings |
On October 1, 2004, DPL submitted its annual Gas Cost Rate (GCR) filing to the DPSC. In its filing, DPL sought to increase its GCR by approximately 16.8% in anticipation of increasing natural gas commodity costs. The GCR, which permits DPL to recover its procurement gas costs through customer rates, became effective November 1, 2004 and is subject to refund pending evidentiary hearings. In addition, on November 29, 2004, DPL filed a supplemental filing seeking approval to further increase GCR rates by an additional 6.5% effective December 29, 2004. The additional GCR increase became effective December 29, 2004 and is subject to refund pending evidentiary hearings. The DPSC Staff and the Division of Public Advocate filed their testimony on March 7, 2005 recommending full approval of the GCR changes being sought by DPL, including the revisions to the tariff in the original and supplemental filings. A final order addressing both the Nov ember 1 and December 29 increases is expected in the spring of 2005. |
On February 13, 2004, DPL filed with the DPSC for a change in electric ancillary service rates that would have an aggregate effect of increasing annual Delaware electric revenues by $13.1 million or 2.4%. This filing was 312
_____________________________________________________________________________ prompted by the increasing ancillary service costs charged to DPL by PJM. The proposed rates went into effect on March 15, 2004, subject to refund. On June 22, 2004, the DPSC approved a settlement agreement that provided for an increase having an aggregate effect of increasing annual Delaware electric revenues by $12.4 million, or 2.3%, with rates effective June 23, 2004. The approved increase was slightly less than the proposed increase that went into effect on March 15, 2004. As part of the settlement, the resulting estimated over-collection of $75,000 was given by DPL to the State of Delaware Low Income Fund administered by the Delaware Department of Human Services on July 15, 2004. |
In compliance with the settlement approved by the MPSC in connection with the merger of Pepco and Conectiv, on December 4, 2003, DPL submitted testimony and supporting schedules to review and reset if necessary its electricity distribution rates in Maryland to be effective July 1, 2004, when the then-current distribution rate freeze/caps ended. DPL's filing demonstrated that it was in an under-earning situation and, as allowed in the merger settlement, DPL requested that a temporary rate reduction implemented on July 1, 2003 for non-residential customers be terminated effective July 1, 2004. DPL estimated that the termination of the rate reduction would increase its annual revenues by approximately $1.1 million. A settlement reached between the parties allowing for this $1.1 million increase to be effective July 1, 2004 was approved by the MPSC in Order No. 79186. With limited exceptions, DPL cannot increase its distribution rates until Jan uary 1, 2007. |
SOS and Default Service Proceedings |
Maryland |
Under a settlement approved by the MPSC in April 2003 addressing standard offer service (SOS) service in Maryland following the expiration of DPL's fixed-rate default supply obligations to non-residential customers in June 2004 and to residential customers through June 2004, DPL is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, DPL purchases the power supply required to satisfy its market rate default supply obligations 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 default supply customers the costs of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sal es to residential, 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 will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period. |
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 a subsidiary of Conectiv Energy Holding Company (the subsidiaries of Conectiv Energy Holding Company are referred to as Conectiv Energy). A prior agreement, also with Conectiv Energy terminated effective 313
_____________________________________________________________________________ December 31, 2004. The current contract was entered into after conducting a competitive bid procedure identical to the Maryland SOS process in most respects and Conectiv Energy was the lowest bidder to provide wholesale power supply for DPL's Virginia default service customers. The new supply agreement commenced January 1, 2005 and expires in May 2006. On October 26, 2004, DPL filed an application with the VSCC for approval to increase the rates that DPL charges its Virginia default service customers to allow it to recover its costs for power under the new supply agreement plus an administrative charge and a margin. |
A VSCC order dated November 17, 2004 allowed DPL to put interim rates into effect on January 1, 2005, subject to refund if the VSCC subsequently determines 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. Therefore, the November 17 order also directed the parties to file memoranda concerning whether administrative costs and a margin are properly recovered through a fuel clause mechanism. Memoranda were filed by DPL, the VSCC Staff and Virginia's Office of Attorney General. The VSCC ruled on January 18, 2005, that the administrative charge and margin are base rate items not recoverable through a fuel clause. No appeal is planned regarding this filing. A settlement resolving all other issues and m aking the interim rates final was filed on March 4, 2005, contingent only on possible future adjustment depending on the result of a related proceeding at FERC. A hearing is scheduled for March 16, 2005, and the VSCC is expected to approve the settlement. |
Also in October, DPL and Conectiv Energy jointly filed an application with the VSCC under Virginia's Affiliates Act requesting authorization for DPL to enter into a contract to purchase power from an affiliate. This authorization permits the contract to be executed with an affiliate, but is not a ruling on the merits of the contract. A VSCC order dated December 17, 2004 granted approval for DPL to purchase power from Conectiv Energy under the new contract according to its terms beginning January 1, 2005. |
On October 29, 2004, Conectiv Energy made a filing with FERC requesting authorization to enter into a contract to supply power to an affiliate. On December 30, 2004, FERC granted the requested authorization effective January 1, 2005, subject to refund and hearings on the narrow question whether, in the absence of direct VSCC oversight over the DPL competitive bid process, DPL unduly preferred its own affiliate, Conectiv Energy, in the design and implementation of the DPL competitive bid process, or unduly favored Conectiv Energy in the credit criteria and analysis applied. DPL cannot predict the outcome of this proceeding. |
Delaware |
Under a settlement approved by the DPSC, DPL is required to provide default electricity supply to customers in Delaware until May 1, 2006. On October 19, 2004, the DPSC initiated a proceeding to investigate and determine which entity should act as the standard offer supplier in DPL's Delaware service territory after May 1, 2006, and what prices should be charged for SOS after May 1, 2006. Similar to the process used in Maryland, the process used in Delaware consists of three separate stages. The stage 1 process was constructed to allow the DPSC to determine by February 28, 2005 the fundamental issues related to the selection of an SOS supplier. Stage 2 will resolve issues relating to the process under which supply will be acquired by the SOS provider and way in which SOS prices will be set and 314
_____________________________________________________________________________ monitored. In the last stage, these selection and pricing mechanisms would be implemented to determine the post-May 2006 SOS supplier and the post-May 2006 SOS price. On January 26, 2005, the DPSC Staff issued a report recommending to the DPSC that DPL be selected as the SOS supplier, subject to further discussions as to how to establish SOS prices. On February 22, 2005, the DPSC voted to approve an SOS process that will allow a Wholesale Standard Offer Service Model with DPL as the SOS Provider. Issues including the length of this extension and any profit margin that DPL may be able to earn and retain in conjunction with this service have been deferred for further discussion and will be decided by the DPSC at a later date. A written DPSC order documenting this decision is expected sometime in March or April 2005. |
Environmental Litigation |
DPL is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. DPL may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. |
In May 2004, the U.S. Department of Justice (DOJ) invited DPL to enter into pre-filing negotiations in connection with DPL's alleged liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) at the Diamond State Salvage site in Wilmington, Delaware. In the context of the negotiations, DOJ informed DPL that DPL is a de minimis party at the site. In February 2005, DPL entered into a de minimis consent decree with the United States which, if approved by the U.S. District Court, would require DPL to pay $144,000 as reimbursement of the government's response costs, resolve DPL's alleged liability, and provide DPL a covenant not to sue from the United States and protection from third-party claims for contribution. |
In July 2004, DPL entered into an Administrative Consent Order with the Maryland Department of the Environment (MDE) to perform a Remedial Investigation/Feasibility Study (RI/FS) to further identify the extent of soil, sediment and ground and surface water contamination related to former manufactured gas plant (MGP) operations at the Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The costs for completing the RI/FS for this site are approximately $300,000, approximately $50,000 of which will be expended in 2005. The costs of cleanup resulting from the RI/FS will not be determinable until the RI/FS is completed and an agreement with respect to cleanup is reached with the MDE. DPL expects to complete the RI/FS in the first quarter of 2005. |
In October 1995, DPL received notice from the Environmental Protection Agency (EPA) that it, along with several hundred other companies, might be a potentially responsible party (PRP) in connection with the Spectron Superfund Site in Elkton, Maryland. The site was operated as a hazardous waste disposal, recycling and processing facility from 1961 to 1988. In February 2003, the EPA informed DPL that it will have no future liability for contribution to the remediation of the site. |
In the early 1970s, DPL sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal 315
_____________________________________________________________________________ Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In December 1987, DPL was notified by EPA that it, along with a number of other utilities and non-utilities, was a PRP in connection with the PCB contamination at the site. |
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 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 condition or results of operations. |
(12) RELATED PARTY TRANSACTIONS |
PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries' share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated in consolidation and no profit results from these transactions. PHI Service Company costs directly charged or allocated to DPL for the years ended December 31, 2004, 2003 and 2002 were $98.4 million, $100.3 million and $102.6 million, respectively. |
In addition to the PHI Service Company charges described above, DPL's financial statements include the following related party transactions in its Consolidated Statement of Earnings: |
A description of the regulatory assets and regulatory liabilities is as 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. 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. |
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. 329
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Deferred Other Post-retirement Benefit Costs: Represents the non-cash portion of other post-retirement 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 Contracts: Represents deferred costs related to purchase power contracts at ACE which are being recovered over 3 years and 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. |
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 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 PHI and certain of its 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 $1.7 million and $103.0 million at December 31, 2004, and 2003, respectively. |
Restricted Cash |
Restricted cash represents cash either held as collateral or pledged as collateral and is restricted from use for general corporate purposes. |
Capitalized Interest and Allowance for Funds Used During Construction |
In accordance with the provisions of SFAS No. 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. The cost of additions to, and replacements or betterments of, retirement units of property and plant is capitalized. Such costs include material, labor, the capitalization of an Allowance for Funds Used During Construction (AFUDC) and applicable indirect costs, including engineering, supervision, payroll taxes and employee benefits. |
ACE recorded AFUDC for borrowed funds of $1.2 million, $.9 million and $1.4 million for the years ended December 31, 2004, 2003 and 2002, respectively. These amounts are recorded as a reduction of "interest expense" in the accompanying consolidated statements of earnings. 330
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ACE recorded amounts for AFUDC equity income of $1.7 million, $1.2 million and $1.1 million for the years ended December 31, 2004, 2003 and 2002, 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 and gas transmission and distribution businesses, is included in interest expense. |
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, determined on a separate return basis. |
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," shown 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 Post-Retirement Benefit Plans |
Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, Conectiv 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 the provisions and benefits of the merged Retirement Plan are identical to the original Conectiv plan. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. In addition to sponsoring non-contributory retirement plans, Pepco Holdings provides certain post-retirement health care and life insurance benefits fo r eligible retired employees. 331
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PHI accounts for the Retirement Plan in accordance with SFAS No. 87, "Employers' Accounting for Pensions" and its post-retirement health care and life insurance benefits for eligible employees in accordance with SFAS No. 106, "Employers' Accounting for Post-retirement Benefits Other Than Pensions." PHI's financial statement disclosures were prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Post-retirement 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 if there is 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 shall only be recognized 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 relationship of the annual provision for depreciation for financial accounting purposes to average depreciable property was 3.3% for 2004, 3.2% for 2003, and 3.3% for 2002. 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. ACE uses the allowance method to account for uncollectible accounts receivable. |
SFAS No. 150 |
Effective July 1, 2003 ACE implemented SFAS No. 150 entitled "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). This Statement established standards for how an issuer classifies and measures in its Consolidated Balance Sheet certain financial instruments with characteristics of both liabilities and equity. 332
_____________________________________________________________________________ SFAS No. 150 resulted in ACE's reclassification (initially as of September 30, 2003) of its "Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Which Holds Solely Parent Junior Subordinated Debentures" (TOPrS) on its Consolidated Balance Sheet to a long term liability classification. Additionally, in accordance with the provisions of SFAS No. 150, dividends on the TOPrS declared subsequent to the July 1, 2003 implementation of SFAS No. 150, are recorded as interest expense in ACE's Consolidated Statement of Earnings for the years ended December 31, 2004 and 2003. In accordance with the transition provisions of SFAS No. 150, amounts prior to 2003 were not reclassified. In 2003, Atlantic Capital I redeemed all $70 million of its 8.25% Quarterly Income Preferred Securities at par. |
In December 2003, the FASB deferred for an indefinite period the application of the guidance in SFAS No. 150 to non-controlling interests that are classified as equity in the financial statements of a subsidiary but would be classified as a liability in the parent's financial statements under SFAS No. 150. The deferral is limited to mandatorily redeemable non-controlling interests associated with finite-lived subsidiaries. ACE does not have an interest in any such applicable entities as of December 31, 2004 and 2003, but will continue to evaluate the applicability of this deferral to entities which may be consolidated as a result of FASB Interpretation No. 46, "Consolidation of Variable Interest Entities." |
FIN 45 |
ACE applied the provisions of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45), commencing in 2003 to its agreements that contain guarantee and indemnification clauses. These provisions expand those required by FASB Statement No. 5, "Accounting for Contingencies," by requiring a guarantor to recognize a liability on its balance sheet for the fair value of obligations it assumes under certain guarantees issued or modified after December 31, 2002 and to disclose certain types of guarantees, even if the likelihood of requiring the guarantor's performance under the guarantee is remote. |
As of December 31, 2004 and 2003, ACE did not have material obligations under guarantees or indemnifications issued or modified after December 31, 2002, that are required to be recognized as a liability on its consolidated balance sheets. |
FIN 46 |
On December 31, 2003, FIN 46 was implemented by ACE. 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 (including the evaluation of interests in power purchase arrangements) did not impact ACE's financial condition or results of operations for the years ended December 31, 2004 and 2003. |
As part of its FIN 46R evaluation, ACE reviewed its power purchase agreements (PPAs), including its Non-Utility Generation (NUG) contracts, to determine (i) if its interest in each entity that is a counterparty to a PPA agreement was a variable interest, (ii) whether the entity was a variable interest entity and (iii) if so, whether ACE was the primary beneficiary. Due to a variable element in the pricing structure of PPAs with three 333
_____________________________________________________________________________ entities, ACE potentially assumes the variability in the operations of the plants of these entities and therefore has a variable interest in the entities. However, due to ACE's inability to obtain information considered to be confidential and proprietary from certain of these entities or the certain entities' own determination that they qualified for exemption as a business, ACE 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. |
Net purchase activities with these three entities in the years ended December 31, 2004, 2003, and 2002 were approximately $265 million, $247 million, and $241 million, respectively, of which $236 million, $220 million, and $221 million, respectively, related to purchases under the PPA agreements. 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. |
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. |
Reclassifications |
Certain prior year amounts have been reclassified in order to conform to current year presentations. |
(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 $11.7 million in 2004, $10.0 million in 2003, and $9.2 million in 2002. Future minimum rental payments for all non-cancelable lease agreements are less than $10 million per year for each of the next five years. 334
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(5) PROPERTY, PLANT AND EQUIPMENT |
Property, plant and equipment is comprised of the following: |
The methods and assumptions below were used to estimate, at December 31, 2004 and 2003, the fair value of each class of financial instruments shown above for which it is practicable to estimate that value. |
The fair value of the Investments was derived based on quoted market prices. |
The fair values of the Long-term Debt, which includes First Mortgage Bonds, Amortizing First Mortgage Bonds, Medium-Term Notes, and Transition Bonds Issues 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 Debentures issued to Financing Trust 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 ACE's accompanying financial statements approximate fair value. |
(11) LONG-TERM PURCHASED POWER CONTRACTS |
As of December 31, 2004, ACE's commitments under long-term purchased power contracts provided ACE 500 megawatts of capacity and varying amounts of firm electricity per hour during each month of a given year. Commitments for purchased capacity under contracts decreased by approximately 200 megawatts in 2004, primarily due to the replacement of the capacity supplied by these contracts with the capacity and energy to be provided by the BGS suppliers that were selected by the NJBPU required auction sale of BGS load. Based on existing contracts as of December 31, 2004, the commitments of ACE during the next five years for capacity and energy under long-term purchased power contracts are estimated to be as follows: $261.7 million in 2005, $255.6 million in 2006, $257.1 million in 2007, $256.6 million in 2008, and $258.4 million in 2009. 350
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(12)COMMITMENTS AND CONTINGENCIES |
REGULATORY AND OTHER MATTERS |
Rate Proceedings |
In February 2003, ACE filed a petition with the NJBPU to increase its electric distribution rates and its Regulatory Asset Recovery Charge (RARC) in New Jersey. The petition was based on actual data for the nine months ended September 30, 2002, and forecasted data for the three months ended December 31, 2002 and sought an overall rate increase of approximately $68.4 million, consisting of an approximately $63.4 million increase in electricity distribution rates and $5 million for recovery of regulatory assets through the RARC. In October 2003, ACE filed an update supporting an overall rate increase of approximately $41.3 million, consisting of a $36.8 million increase in electricity distribution rates and a RARC of $4.5 million. This petition was ACE's first increase request for electric distribution rates since 1991. The requested increase would apply to all rate schedules in ACE's tariff. The Ratepayer Advocate filed testimony on January 3, 2004, proposing an annual rate decrease of $11.7 million. Intervenor groups representing industrial users and local generators filed testimony that did not take a position with respect to an overall rate change but their proposals, if implemented, would affect the way in which an overall rate increase or decrease would be applied to the particular rates under which they receive service. ACE's rebuttal testimony, filed in February 2004, made some changes to its October filing and proposed an overall rate increase of approximately $35.1 million, consisting of a $30.6 million increase in distribution rates and a $4.5 million increase in the RARC. Hearings were held before an Administrative Law Judge in late March, early April and May 2004. At the hearing held in April 2004, the Ratepayer Advocate proposed an annual rate decrease of $4.5 million, modifying its earlier proposal that rates be decreased by $11.7 million annually. The Ratepayer Advocate and Staff of the NJBPU filed their briefs in this proceeding in August 2004. The Ratepayer Advocate's brief supported its earlier proposal of an annual rate decrease of $4.5 million. The Staff's brief, however, stated for the first time its position calling for an overall decrease of $10.8 million. Reply briefs were filed on August 23, 2004. Settlement discussions between ACE, the NJBPU Staff and the Ratepayer Advocate have been ongoing. |
On December 12, 2003, the NJBPU issued an order also consolidating outstanding issues from several other proceedings into the base rate case proceeding. On December 22, 2003, ACE filed a Motion for Reconsideration in which it suggested that these issues be dealt with in a Phase II to the base rate case to address the outstanding issues identified in the December 12, 2003 Order. After discussion with the parties to the base rate case, it was agreed that a Phase II to the base rate case to address these issues, along with the $25.4 million of deferred restructuring costs previously transferred into the base rate case, would be initiated in April 2004. On April 15, 2004, ACE filed testimony with the NJBPU initiating a Phase II to the base rate proceeding described above. The parties to this case have been actively engaged in settlement discussions in conjunction with settlement of Phase I issues. |
On August 31, 2004, ACE filed requests with the NJBPU proposing changes to its Transition Bond Charge, its Market Transition Charge - Tax rate, and its BGS Reconciliation charges. The net impact of these rate changes is to decrease ACE's annual revenues by approximately 1.5%. All of these rate changes were implemented on October 1, 2004. 351
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Restructuring Deferral |
Pursuant to a July 1999 summary order issued by the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA) (which was subsequently affirmed by a final decision and order issued in March 2001), ACE was obligated to provide basic generation service (BGS) from August 1, 1999 to at least July 31, 2002 to retail electricity customers in ACE's service territory who did not choose a competitive energy supplier. The order allowed ACE to recover through customer rates certain costs incurred in providing BGS. ACE's obligation to provide BGS was subsequently extended to July 31, 2003. At the allowed rates, for the period August 1, 1999 through July 31, 2003, ACE's aggregate allowed costs 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 Ener gy Adjustment Clause and ACE's Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance. |
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. The deferred balance was 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 2003, the NJBPU issued a 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 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. In July 2004, the NJBPU issued its final order in the restructuring deferral proceeding. The final order did not modify the amount of the disallowances set forth in the July 2003 summary order, but did provide a much more detailed analysis of evidence and other information relied on by the NJBPU as justification for the disallowa nces. ACE believes the record does not justify the level of disallowance imposed by the NJBPU. 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 related to the July 2004 final order. ACE cannot predict the outcome of this appeal. |
Proposed Shut Down of B.L. England Generating Facility; Construction of Transmission Facilities |
Pursuant to a September 25, 2003 NJBPU order, ACE filed a report on April 30, 2004 with the NJBPU recommending that the B.L. England generating facility be shut down in accordance with the terms of an April 26, 2004 preliminary settlement agreement among PHI, Conectiv and ACE, the New Jersey Department of Environmental Protection (NJDEP) and the Attorney General of New Jersey. The report stated that the operation of the B.L. England facility is necessary at the present time to satisfy reliability standards, 352
_____________________________________________________________________________ but that those reliability standards could also be satisfied in other ways. The report concludes 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 facility and construct additional transmission lines into southern New Jersey. ACE cannot predict whether the NJBPU will approve the construction of the additional transmission lines. |
In letters dated May and September 2004 to PJM Interconnection, LLC (PJM), ACE informed PJM of its intent, as owner of the B.L. England generating plant, to retire the entire plant (447 MW) on December 15, 2007. PJM completed its independent analysis to determine the upgrades required to eliminate any identified reliability problems resulting from the retirement of B.L. England and recommended that certain transmission upgrades be installed prior to the summer of 2008. ACE's independent assessment confirmed that the transmission upgrades identified by PJM are the transmission upgrades necessary to maintain reliability in the Atlantic zone after the retirement of B.L. England. The amount of the costs incurred by ACE to construct the recommended transmission upgrades that ACE would be permitted to recover from load serving entities that use ACE's transmission system would be subject to approval by FERC. The amount of construction costs that A CE would be permitted to recover from retail ratepayers would be determined in accordance with the treatment of transmission-related revenue requirements in retail rates under the jurisdiction of the appropriate state regulatory commission. ACE cannot predict how the recovery of such costs will ultimately be treated by FERC and the state regulatory commissions and, therefore, cannot predict the financial impact to ACE of installing the recommended transmission upgrades. However, in the event that the NJBPU makes satisfactory findings and grants other requested approvals concerning the retirement of B.L. England and approves the construction of the transmission upgrades required to maintain reliability in the Atlantic zone after such retirement, ACE expects to begin construction of the appropriate transmission upgrades while final decisions by FERC and state regulatory commissions concerning the methodology for recovery of the costs of such construction are still pending. |
On November 1, 2004, ACE made a filing with the NJBPU requesting approval of the transmission upgrades required to maintain reliability in the Atlantic zone after the retirement of B.L. England. On December 22, 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. ACE cannot predict the outcome of these two proceedings. |
On November 12, 2004, ACE made a filing with the NJBPU requesting approval of year 2005 capital projects with respect to B.L. England. This filing was made pursuant the September 25, 2003 B.L. England rate order, which established a requirement that ACE file for approval of capital expenditures in excess of $1 million. For 2005, four projects, totaling $3.2 million in capital expenditures, have been identified as necessary to allow continued operation of B.L. England until its retirement. Two of these projects are well below the $1 million threshold set forth in the 353
_____________________________________________________________________________ September 25, 2003 NJBPU order and two are above that threshold. ACE cannot predict the outcome of this proceeding. |
Environmental Litigation |
ACE is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. ACE may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. |
In June 1992, the Environmental Protection Agency (EPA) identified ACE as a potentially responsible party (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 0.232 percent of the aggregate remediation liability and thus far ACE has made contributions of approximately $105,000. Based on information currently available, ACE may be required to contribute approximately an additional $100,000. ACE believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations. |
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 administrative consent order 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. The results of groundwater monitoring over the first year of this ground water sampling plan will help to determine the extent of post-remedy operation and maintenance costs. 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 may be required to contribute approximately an additional $626,000. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial condition or results of operations. |
Preliminary Settlement Agreement with the NJDEP |
In an effort to address NJDEP's concerns regarding ACE's compliance with New Source Review (NSR) requirements at B.L. England, on April 26, 2004, PHI, Conectiv and ACE entered into a preliminary settlement agreement with NJDEP and the Attorney General of New Jersey. The preliminary settlement agreement outlines the basic parameters for a definitive agreement to resolve ACE's NSR liability at B.L. England and various other environmental issues at ACE and Conectiv Energy facilities in New Jersey. Among other things, the preliminary settlement agreement provides that: |
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE |
None for all registrants. |
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, 2004, 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 accounting officer, as appropriate to allow timely decision s regarding required disclosure. |
Management's Report on Internal Control Over Financial Reporting |
See "Management's Report on Internal Control Over Financial Reporting" in Part II, Item 8 on page 154 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 on page 155 of this Form 10-K. |
Changes in Internal Control Over Financial Reporting |
During the quarter ended December 31, 2004, there was no change in Pepco Holdings' internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco Holdings' internal controls over financial reporting. |
Potomac Electric Power Company |
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures |
Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2004, 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 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 360
_____________________________________________________________________________ specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief accounting officer, as appropriate to allow timely decisions regarding required disclosure. |
Changes in Internal Control Over Financial Reporting |
During the quarter ended December 31, 2004, 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, 2004, 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 accounting officer, as appropriate to allow timely decisions regarding required disclosure. |
Changes in Internal Control Over Financial Reporting |
During the quarter ended December 31, 2004, 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, 2004, 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 accounting officer, as appropriate to allow timely decisions regarding required disclosure. 361
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Changes in Internal Control Over Financial Reporting |
During the quarter ended December 31, 2004, 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. 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 2003 compensation, or in the cases of Messrs. Rigby and Spence, 2004 compensation) information concerning determinations made with respect to the compensation paid or payable for services in all capacities to PHI and its subsidiaries consisting of (i) the establishment of base salary for 2005, (ii) the determination of the annual bonus for 2004, and (iii) the determination of the long-term incentive plan payout for the performance cycle ending in 2004. |
