ITEM 1. BUSINESS
PG&E National Energy Group Inc. (PG&E NEG), an integrated energy company, was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to PG&E NEG. At the end of 2002, PG&E NEG’s principal subsidiaries included:
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PG&E Generating Company, LLC and its subsidiaries, collectively referred to as PG&E Gen;
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PG&E Energy Trading Holdings Corporation and its subsidiaries, collectively referred to as PG&E ET;
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PG&E Gas Transmission Corporation and its subsidiaries, collectively referred to as PG&E GTC, which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively referred to as PG&E GTN), including North Baja Pipeline, LLC.
As result of the sustained downturn in the power industry, PG&E NEG and its affiliates have experienced a financial downturn which caused the major credit rating agencies to downgrade PG&E NEG’s and its affiliates’ credit ratings to below investment grade. PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.5 billion, but this debt is nonrecourse to PG&E NEG. PG&E NEG, its subsidiaries and their lenders are engaged in discussions to restructure PG&E NEG’s debt obligations and such other commitments. PG&E NEG and its subsidiaries are continuing to review opportunities to abandon, sell, or transfer certain assets, and have significantly reduced their energy trading operations in an ongoing effort to raise cash and reduce debt, whether through negotiation with lenders or otherwise. PG&E NEG’s objective is to limit its trading and risk management activities to only what is necessary for energy management services to facilitate the transition of PG&E NEG’s merchant generation facilities through their sale, transfer or abandonment process. PG&E NEG will then further reduce and transition to only retain limited capabilities to ensure fuel procurement and power logistics for PG&E NEG’s retained independent power plant operations. Impairment due to future asset transfers, sales, and abandonments have caused substantial charges to earnings in 2002 of approximately $3.9 billion and will cause additional charges during 2003. If the lenders exercise their default remedies or if the financial commitments are not restructured, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced involuntarily into proceedings under the U.S. Bankruptcy Code.
PG&E NEG is currently focused on power generation and natural gas transmission in the United States. PG&E NEG reports its business segments as follows: interstate pipeline operations (or “Pipeline Business”) and power generation also referenced as Integrated Energy and Marketing (or “Generation Business”). Financial information for each reportable segment is included in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation”, and in Note 14 of the “Notes to Consolidated Financial Statements.”
The consolidated financial statements of PG&E NEG included herein include the accounts of PG&E NEG and its wholly owned and controlled subsidiaries. The principal executive offices are located at 7600 Wisconsin Avenue (mailing address: 7500 Old Georgetown Road), Bethesda, Maryland 20814. PG&E NEG’s telephone number is (301) 280-6800. PG&E NEG’s quarterly and other reports filed with the Securities and Exchange Commission are available on PG&E Corporation’s website, www.pge-corp.com.
Generation Business
In the Generation Business segment, PG&E NEG engages in the generation of electricity in the continental United States. As of December 31, 2002, PG&E NEG had ownership or leasehold interests in 16 operating generating facilities with a net generating capacity of 1,476 megawatts (MW), as follows:
PG&E NEG provides operating and/or management services for 14 of these 16 owned and leased generating facilities. Plant operations are focused on maximizing power generation ability during peak energy price hours, improving operating efficiencies and minimizing operating costs while placing a heavy emphasis on safety standards, environmental compliance and plant flexibility.
These generating facilities sell all or a majority of their electrical capacity and output to one or more third parties under long-term power purchase agreements tied directly to the output of that plant.
PG&E NEG holds interests in these projects through wholly owned indirect subsidiaries and typically manages and operates these facilities through an operation and maintenance agreement and/or a management services agreement. These agreements generally provide for management, operations, maintenance and administration for day-to-day activities, including financial management, billing, accounting, public relations, contracts, reporting and budgets. In order to provide fuel for PG&E NEG’s independent power projects (IPPs), natural gas and coal supply commitments are typically purchased from third parties under long-term supply agreements.
The revenues generated from long-term power sales agreements usually consist of two components: energy payments and capacity payments. Energy payments are typically based on the facility’s actual electrical output and capacity payments are based on the facility’s total available capacity. Energy payments are made for each kilowatt-hour of energy delivered, while capacity payments, under most circumstances, are made whether or not any electricity is delivered. However, capacity payments may be reduced if the facility does not attain an agreed availability level. The average life of a power sales agreement is 15 years.
Description of Generating Facilities
The following table provides information regarding each of PG&E NEG’s owned or leased generating facilities, as of December 31, 2002:
(1)
Megawatts are based on winter output.
(2)
PG&E NEG’s net interest in the total MW of an independent power project is the current percentage ownership or leasehold interest in the project affiliate and does not necessarily correspond to PG&E NEG’s percentage of the project’s expected cash flow.
The following section describes each of PG&E NEG’s generating facilities.
New England Region Generating Facilities
MASSPOWER. PG&E NEG indirectly owns a 13% interest in MASSPOWER, a 267 MW gas-fired combined cycle cogeneration facility located in Springfield, Massachusetts. This facility, which commenced commercial operations in 1993, consists of two gas turbine generators, each feeding exhaust gases to a heat recovery steam generator. Steam from the two heat recovery steam generators is fed to a steam turbine for generating additional electricity.
MASSPOWER sells approximately 75% of its electrical capacity and output to Boston Edison Company, Commonwealth Electric Co. and Massachusetts Municipal Wholesale Electric Co. under separate power purchase agreements with initial terms of either 15 or 20 years, the earliest of which expires in 2008. Each of these power purchase agreements provides for capacity and energy payments and has fuel escalation clauses. MASSPOWER sells the balance of its electrical capacity and output to the market. MASSPOWER also sells an annual average of 50,000 pounds of steam per hour to Solutia under a steam sales agreement with an initial term of 20 years that expires in 2013.
Pittsfield. PG&E NEG indirectly owns a 89% interest in Pittsfield Generating Company L.P., which leases a 173 MW gas-fired combined cycle cogeneration facility located in Pittsfield, Massachusetts. This facility, which commenced commercial operations in 1990, consists of three gas turbine generators, each feeding exhaust gases to a heat recovery steam generator. Steam from the three heat recovery steam generators is fed to a steam turbine for generating additional electricity.
Pittsfield sells its electrical capacity and output to USGen New England, Commonwealth Electric, and Cambridge Electric under separate power purchase agreements that expire in, 2010, 2011 and 2011 respectively. Each of these power purchase agreements provides for capacity and energy payments and has fuel escalation clauses. Pittsfield has a steam sales agreement with General Electric (GE) that expires in 2008. GE is contractually obligated to purchase a minimum of 700 million pounds of steam per year up to a maximum of 840 million pounds per year.
Pittsfield failed to meet the efficiency standard required to maintain qualified facility (QF) status in 1999 through 2002. FERC granted the project a waiver for 1999 and 2000. In November 2002, FERC denied Pittsfield’s request for a waiver for 2001. Pittsfield has filed a request for a rehearing and, in January 2003, FERC responded that they would consider the request for rehearing. Failure to maintain QF status is a default under the partnership’s participation agreement, lease agreement, term loan agreement and working capital agreement. The lessor had granted a waiver to any default under these agreements for failure to maintain QF status through January 1, 2003. The lessor has not extended the term of its waiver.
Mid-Atlantic and New York Region Generating Facilities
Selkirk. PG&E NEG indirectly owns a 42% interest in the Selkirk Cogeneration Facility, a 345 MW natural gas-fired combined-cycle cogeneration facility located near Albany, New York. This facility commenced commercial operations in 1992 and is capable of producing a maximum average steam output of 400,000 pounds per hour.
Selkirk sells up to 265 MW of its electric capacity and output to Consolidated Edison under a power purchase agreement with an initial term of 20 years that expires in 2014 and is renewable for another ten years at Consolidated Edison’s option. Under an amended and restated power purchase agreement with a term that expires in 2008, Niagara Mohawk Power Corporation has contracted for approximately 52 MW of Selkirk’s electric capacity and the remaining 28 MW of electric capacity is available to be sold in the competitive market. Selkirk also sells up to 400,000 pounds per hour of steam to General Electric under a steam sale agreement with an initial term of 20 years that expires in 2014. Under this agreement, General Electric must purchase and use the minimum amount of steam required to maintain Selkirk’s status as a qualifying facility, or QF, under the Public Utility Regulatory Policies Act of 1978, or PURPA, which is currently 80,000 pounds per hour of steam. However, General Electric’s obligation to purchase and use steam is subject to reduction or termination in the event its steam requirements are reduced or cease. PG&E NEG has no reason to believe that General Electric will reduce or cease its steam purchases.
Carneys Point. PG&E NEG indirectly owns a 50% interest in Carneys Point Generating Facility, a 245 MW pulverized coal cogeneration facility. This facility is located in Carneys Point, New Jersey and commenced commercial operations in 1994.
Carneys Point sells up to 188 MW to Atlantic City Electric Company during the summer and up to 173 MW during the winter under a power sale agreement with an initial term of 30 years that expires in 2024. Under this agreement, Atlantic City Electric Company must purchase a minimum of 637,700 MWh per year or pay for an equivalent amount of energy reduced by variable operating costs.
Carneys Point sells up to 650,000 pounds per hour of steam in the summer and 1,000,000 pounds per hour of steam in the winter to DuPont under a steam and electricity purchase contract. This agreement has an initial term of 30 years that expires in 2024. As long as DuPont has not closed down or abandoned its manufacturing facility powered by Carneys Point, DuPont must take the minimum amount of steam required for Carneys Point to maintain its status as a QF under PURPA, which is currently approximately 60,000 pounds per hour. The price paid by DuPont for steam under this agreement is adjusted for changes in Carneys Point’s weighted average coal price.
Logan. PG&E NEG indirectly owns a 50% interest in Logan Generating Facility, a 225 MW pulverized coal cogeneration facility. This facility is located in Logan Township, New Jersey and commenced commercial operations in 1994. The plant provides up to 203 MW of dispatchable energy to Atlantic City Electric Company. Logan also provides 30,000-50,000 pounds per hour of steam to Ferro (formerly Monsanto/Solutia).
In 1999, Logan and Atlantic City Electric Company (Atlantic) entered into arbitration regarding determination of the project heat rate as it relates to the sale of energy to Atlantic. The arbitration prescribed a test procedure to establish the project heat rate under the power sale agreement with Atlantic. The project expects to complete the determination of the heat rate in accordance with the test procedure during 2003.
On October 29, 2002, the long-term coal supplier, Anker Energy Corporation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Under the terms of Logan’s non-recourse project financing, this filing constitutes a default, which Logan had sixty days to cure. Logan obtained a waiver from its lenders based on either the coal supply contract being assumed by Anker in bankruptcy or, if it is rejected by Anker, replaced by a similar agreement with another supplier. Anker assumed the Logan coal supply contract and the assumption has been granted by the bankruptcy court. The unsecured creditors filed a motion for reconsideration of the assumption and after completing a review of the contract have submitted a motion to withdraw the request for reconsideration. The motion to withdraw has been accepted by the bankruptcy court.
Northampton. PG&E NEG indirectly owns a 50% interest in Northampton Generating Facility, an anthracite waste coal-fired electric generating facility located in Northampton County, Pennsylvania that commenced commercial operation in 1995. The facility provides approximately 110 MW of net electrical energy under a contract with Metropolitan Edison Company that extends to 2020. Northampton also provides 14,000-80,000 pounds of steam per hour to an adjacent paper recycling and processing facility owned by Newstech PA, L.P.
Panther Creek. PG&E NEG indirectly owns a 55% equity interest in Panther Creek Generating (economic interest is less than 50%), an 80-MW waste coal electric generating facility that uses circulating fluidized bed technology. The facility is located in Nesquehoning (Carbon County), Pennsylvania and has been providing electricity to Metropolitan Edison under a 20-year contract since 1992.
Scrubgrass. PG&E NEG indirectly owns a 50% interest in Scrubgrass Generating Plant, an 87-MW bituminous waste coal facility. This facility is located in Scrubgrass Township, Venango County, Pennsylvania and commenced commercial operations in 1993. It provides electricity to Pennsylvania Electric Company under a contract that extends to 2017. Scrubgrass has the capability to produce low-pressure steam for industrial use, however, currently it has no steam contracts.
Madison: PG&E NEG indirectly owns a 100% interest in Madison Wind an 11.55 MW wind generation facility located in Madison, New York. Madison generates electricity from seven Vestas V-66 wind turbines and sells the output as a merchant facility in the New York Independent System Operator system.
Midwest Region Generating Facilities
Ohio Peakers. PG&E NEG Indirectly owns a 100% interest in three natural gas-fueled gas turbine peaking facilities in Bowling Green, Napolean and Galion, Ohio. Each unit is approximately 49.5 MW. The Bowling Green unit is under contract to American Municipal Power of Ohio until 2005.
Southern Region Generating Facilities
Indiantown. PG&E NEG indirectly owns a 35% interest in the Indiantown Cogeneration Facility, a 330 MW pulverized coal cogeneration facility located on an approximately 240-acre site in Martin County, Florida. Indiantown, which commenced commercial operations in 1995, utilizes pulverized coal technology consisting of a single pulverized coal boiler, a steam turbine generator, air pollution control equipment and a selective catalytic reduction system to reduce nitrogen oxides.
Indiantown sells all of its capacity and electrical output to Florida Power & Light Company under a power purchase agreement that expires in 2025. Indiantown also supplies up to 745 million pounds of steam per year to a citrus processing plant owned by Louis Dreyfus Citrus, Inc. (LDC) under an energy services agreement with an initial term of 15 years. Under the energy services agreement, LDC must purchase the lesser of 525 million pounds of steam per year or the minimum quantity of steam per year necessary for Indiantown to maintain its status as a QF under PURPA.
The coal supplier to Indiantown, Lodestar, is currently in bankruptcy. Indiantown has negotiated changes to the coal contract with Lodestar, which has been approved by the bankruptcy court. Separately, Lodestar’s bankruptcy proceedings has been modified so that the business and assets of Lodestar, including Indiantown’s coal contract, will be sold and it is currently anticipated that Lodestar will not emerge from its bankruptcy proceeding as a going concern. Lodestar has failed to perform certain of its obligations under the contract as it pertains to ash disposal and Indiantown has delivered a notice of default to Lodestar. In the event the contract is terminated as a result of such default, by Lodestar or otherwise, Indiantown has arranged for replacement coal supply and ash disposal agreements. Lodestar has contested the notice of default.
Cedar Bay. PG&E NEG indirectly owns a 64% equity interest in the Cedar Bay Generating Facility (economic interest is less than 50%), a 258 MW coal-fired cogeneration facility located in Jacksonville, Florida. Cedar Bay, which commenced commercial operations in 1994 and consists of three circulating fluidized bed boilers, a steam turbine generator, air pollution control equipment and selective non-catalytic reduction to reduce nitrogen oxides.
Cedar Bay sells its electric capacity and output to Florida Power & Light Company under a power purchase agreement with an initial term of 31 years that expires in 2024. Cedar Bay also sells up to 380,000 pounds per hour of steam to Smurfit Stone Container Corporation under an energy services agreement with an initial term of 19 years that expires in 2013. Under this agreement, Smurfit Stone Container Corporation pays Cedar Bay a capacity payment according to a fixed schedule and a variable payment based on Cedar Bay’s cost of coal. Cedar Bay is currently in litigation with Smurfit Stone regarding payment of liquidated damages under the energy services agreement.
The former coal supplier to Cedar Bay, Lodestar, is currently in bankruptcy. Lodestar has rejected the coal supply contract and Cedar Bay is purchasing coal from a new supplier at prices in excess of those that were charged under the Lodestar contract.
The financial statements of Cedar Bay at December 31, 2002, have been prepared on a going concern basis. Failure to make timely payments on senior project debt is an event of default. The lenders have rights and remedies if such events of default are not cured. Cedar Bay's 2003 and 2004 current cash flow projections indicate that payments due under the senior project debt will not be made on their required dates, but will be paid in full at a later date to cure any event of default.
Western Region Generating Facilities
Hermiston. PG&E NEG indirectly owns a 50.1% interest in Hermiston Generating Company L.P. (HGC). HGC, in turn, owns a 50% interest in the Hermiston Generating Facility, a 474 MW natural gas-fired cogeneration facility located in Hermiston, Oregon. This facility, which commenced commercial operations in 1996, is a combined-cycle cogeneration facility that utilizes two GE 7FA turbines and associated systems and facilities.
HGC sells its share of electric capacity and output generated by Hermiston to PacifiCorp under a power sale agreement with an initial term that expires in 2016. PacifiCorp has an option to extend the term of this agreement for an additional ten years. Hermiston also sells steam to a nearby food processing facility owned by Lamb-Weston, Inc. under a retail energy services agreement with a term of 20 years that expires in 2016.
Plains End. PG&E NEG indirectly owns a 100% interest in the 111-MW Plains End Generating Station. This peaking facility, which is located in Arvada, Colorado and commenced operating in 2002, consists of 20 reciprocating engine generators. Plains End is under contract to Public Service of Colorado to 2012.
San Diego Peakers. PG&E NEG indirectly owns a 100% interest in two natural gas-fueled gas turbine peaking facilities in Escondido and Chula Vista, California. Each unit is approximately 42 MW. Both facilities are under contract to the California Independent System Operator until November 2003.
Colstrip. PG&E NEG indirectly owns a 17% interest in Colstrip Energy, LP, which owns the Rosebud Power Plant, a 40-MW fluidized bed, waste coal electric generating facility located in Colstrip, Montana. The plant has been providing electricity to Montana Power under a 35-year contract since 1990.
Natural Gas Transmission Business
In its Pipeline Business segment, PG&E NEG owns, operates and develops natural gas pipeline facilities, including the pipelines owned by PG&E GTN (the Gas Transmission Northwest pipeline, or GTN, and the North Baja pipeline, or NBP) and, an interest in the Iroquois pipeline.
The following table summarizes PG&E NEG’s gas transmission pipelines:
GTN Pipeline System
GTN consists of over 1,350 miles of natural gas transmission pipeline in the Pacific Northwest with a capacity of approximately 2.9 billion cubic feet of natural gas per day. GTN begins at the British Columbia-Idaho border, extends for approximately 612 miles through northern Idaho, southeastern Washington and central Oregon, and ends at the Oregon-California border, where it connects with other pipelines. GTN, which is the largest transporter of Canadian natural gas into the United States, commenced commercial operations in 1961 and has subsequently been expanded various times through 2002.
The mainline system of GTN is composed of two parallel pipelines (along with 21 miles of a third parallel line) with 13 compressor stations totaling approximately 513,400 horsepower and ancillary facilities which include metering and regulating facilities and a communication system. GTN's mainline system has approximately 639 miles of 36-inch diameter gas transmission lines (612 miles of 36-inch diameter pipe and 27 miles of 36-inch diameter pipeline looping) and approximately 611 miles of 42-inch diameter pipe.
The GTN system also includes two laterals off of its mainline system, the Coyote Springs Extension, which supplies natural gas to an electric generation facility owned by Portland General Electric Company and other customers, and the Medford Extension, which supplies natural gas to Avista Utilities and PacifiCorp Power Marketing. The Coyote Springs Extension is composed of approximately 18 miles of 12-inch diameter pipe, originating at a point on the GTN mainline system approximately 27 miles south of Stanfield, Oregon and connecting to Portland General Electric’s electric generation facility near Boardman, Oregon. The Medford Extension consists of approximately 22 miles of 16-inch diameter pipe and 66 miles of 12-inch diameter pipe and extends from a point on the GTN mainline system near Bonanza, in Southern Oregon, to interconnection points with Avista Utilities at Klamath Falls and Medford, Oregon.
GTN Interconnection with Other Pipelines
The GTN system facilities interconnect with facilities owned by TransCanada PipeLines Ltd.’s B.C. System (TransCanada) and facilities owned by Foothills Pipe Lines South B.C. Ltd. (Foothills South B.C.) near the Idaho-British Columbia border. The GTN pipeline facilities also interconnect with facilities owned by Pacific Gas and Electric Company (or the Utility), at the Oregon-California border, with facilities owned by Northwest Pipeline Corporation (Northwest Pipeline) in Northern Oregon and in Eastern Washington, and with facilities owned by Tuscarora Gas Transmission Company (Tuscarora) in Southern Oregon. PG&E GTN also delivers gas along various mainline delivery points to two local gas distribution companies.
TransCanada and Foothills South B.C.-The GTN pipeline facilities interconnect with the facilities of TransCanada and Foothills South B.C. near Kingsgate, British Columbia. Through the TransCanada and Foothills South B.C. systems, GTN customers have access to natural gas from the Western Canadian Sedimentary Basin. TransCanada’s Alberta System delivers gas from production areas to provincial gas distribution utilities and to all provincial export points, including the interconnect at the Alberta-British Columbia border to TransCanada’s B.C. System and Foothills South B.C. for delivery south into GTN’s system at the British Columbia-Idaho border. TransCanada and Foothills South B.C.’s transportation services are regulated by the National Energy Board of Canada.
Northwest Pipeline Corporation-GTN’s pipeline facilities interconnect with the facilities of Northwest Pipeline near Spokane and Palouse, Washington and near Stanfield and Klamath Falls, Oregon. Northwest Pipeline is an interstate natural gas pipeline which both delivers gas to and receives gas from PG&E GTN and competes with GTN for transportation of natural gas into the Pacific Northwest and California. Northwest Pipeline’s gas transportation services are regulated by the FERC.
Tuscarora Gas Transmission Company-The GTN pipeline facilities interconnect with the facilities of Tuscarora near Malin, Oregon. Tuscarora is an interstate natural gas pipeline that transports natural gas from this interconnection to the Reno, Nevada area. Tuscarora’s gas transportation services are regulated by the FERC.
Pacific Gas and Electric Company-The GTN pipeline interconnects with the Pacific Gas and Electric Company’s (Utility) gas transmission pipeline system at the Oregon-California border. The Utility’s pipeline facilities deliver natural gas to customers in Northern and Central California and interconnect with other pipeline facilities near the California-Arizona border. The Utility’s gas transmission system is currently regulated by the
California Public Utilities Commission. In April 2001, the Utility commenced a case under Chapter 11 of the U.S. Bankruptcy Code. As part of the Utility’s proposed plan of reorganization, in November 2001, the Utility filed an application with the FERC requesting authorization to operate these facilities as a federally-regulated interstate pipeline system. In conjunction with that application, GTN filed an application with the FERC for authorization to abandon by sale to the Utility approximately 2.66 miles of 42-inch and 36-inch mainline pipe from the southernmost meter station in Oregon to the California border. The transaction implementing this abandonment closed into escrow as of November 14, 2002, pending receipt of satisfactory authorizations from FERC and the bankruptcy court.
North Baja Pipeline
The North Baja Pipeline system consists of approximately 80 miles of natural gas transmission pipeline in the desert southwest with a capacity of approximately 512 MDth of natural gas per day. The NBP system originates near Ehrenberg, in western Arizona, and traverses southern California to a point on the Baja California, Mexico - California border. The NBP system began limited commercial operation in September 2002 and includes a single compressor station at Ehrenberg, which has approximately 28,800 certificated horsepower and ancillary facilities including metering and regulating facilities and a communication system. The NBP mainline system consists of approximately 12 miles of 36-inch diameter gas transmission line and 68 miles of 30-inch diameter pipe. The NBP system connects with other pipelines near Ehrenberg, Arizona and at the Baja California, Mexico - California border.
North Baja System - Interconnections with Other Pipelines
El Paso Natural Gas (EPNG) - NBP pipeline facilities interconnect with the facilities of EPNG near Ehrenberg, Arizona. EPNG is an interstate natural gas pipeline, with a pipeline network throughout west Texas, New Mexico and Arizona, that serves customers and other pipelines, including NBP, within those states. Through EPNG, NBP customers have access to gas primarily from the Permian and San Juan basins of Texas, New Mexico and Colorado. EPNG’s transportation services are regulated by the FERC.
Gasoducto Bajanorte (GB) - NBP pipeline facilities interconnect with the facilities of GB at the Baja California, Mexico - California border near Ogilby, California. GB is the pipeline that receives gas from NPB for the purpose of delivering the gas to customers located in the northern portion of Baja California, Mexico. GB’s transportation services are regulated by the Comision Reguladora de Energia, Mexico, a regulatory agency in Mexico with responsibilities similar to those of FERC as they relate to natural gas pipelines.
Iroquois Pipeline
PG&E NEG owns a 5.2% interest in the Iroquois Gas Transmission System, an interstate pipeline which extends 375 miles from the U.S.-Canadian border in northern New York through the State of Connecticut to Long Island, New York. This pipeline, which commenced operations in 1991, provides gas transportation service to local gas distribution companies, electric utilities and electric power generators, directly or indirectly through exchanges and interconnecting pipelines, throughout the Northeast.
The Iroquois pipeline is owned by a partnership of six U.S. and Canadian energy companies, including affiliates of TransCanada Pipeline, Dominion Resources and Keyspan Energy. Iroquois has executed firm multi-year transportation services agreements totaling more than 1,000 MMcf per day. This pipeline also provides interruptible transportation services on an as available basis. On December 26, 2001, the FERC issued a Certificate of Public Convenience and Necessity authorizing Iroquois to expand its capacity by 220 MMcf per day of natural gas and extend the pipeline into the Bronx borough of New York City for a total investment of approximately $210 million. Iroquois also filed three additional applications with the FERC to expand its system capacity, and to extend the pipeline into Eastern Long Island.
Market Conditions, Customers and Services
Generation Business
PG&E NEG buys natural gas and coal to supply the fuel for its generation facilities, and sells the electricity produced at those facilities under long-term contracts to regulated utilities. The prices of the commodities that PG&E NEG uses and sells in its businesses are often subject to extreme volatility resulting from a variety of factors, many of which are beyond PG&E NEG’s control. While the fuel supply and output of PG&E NEG’s plants are generally under long-term contract, extreme or prolonged variances between contract prices and the market price of the commodities involved increases the risk that contracts will be terminated via regulatory mandate, bankruptcy, or other means.
Pipeline Business
PG&E GTN, through its GTN and NBP pipeline systems, provides firm and interruptible transportation services to third party shippers on a nondiscriminatory basis. Firm transportation services means that the customer has the highest priority rights to ship a quantity of gas between two points for the term of the applicable contract.
PG&E GTN also offers short-term firm and interruptible transportation services plus hub services, which allow customers the ability to park or borrow volumes of gas on the pipeline. If weather, maintenance schedules and other conditions allow, additional firm capacity may become available on a short-term basis. PG&E GTN provides interruptible transportation service when capacity is available. Interruptible capacity on PG&E GTN's systems is provided first to shippers offering to pay the maximum rate and, if necessary, allocated on a pro-rata basis to shippers offering to pay the maximum rate. If capacity remains after maximum tariff nominations are fulfilled, PG&E GTN allocates discounted interruptible space on a highest to lowest total revenue basis.
GTN’s customers of the pipelines are principally local retail gas distribution utilities, electric generators that utilize natural gas to generate electricity, natural gas marketing companies that purchase and resell natural gas to utilities and end-use customers, natural gas producers, and industrial companies. NBP’s customers are principally electric generators that utilize natural gas to generate electricity.
Customers are required to comply with credit and payment terms. To the extent any customer cannot meet the credit or payment terms as prescribed in the tariff, such customer is required to provide assurances in the form of cash, or an investment grade guarantee or letter of credit, to support its obligations as a shipper on the PG&E GTN’s pipelines. In the event that such customer is unable to continue to provide such assurances, the PG&E GTN can mitigate its risks through open market capacity sales.
As of December 31, 2002, 93.2% of GTN’s available long-term capacity was held among 48 shippers under long-term transportation agreements, ranging between 1 and 40 years into the future. The volume-weighted average remaining term of these contracts is approximately 11 years. Approximately 95.9% of total transportation revenue was attributable to long-term contracts in 2002.
In 2002, GTN provided transportation services to 70 customers. These services include capacity utilized via long-term firm, short-term firm, interruptible and hub services contracts. Short-term firm, interruptible and hub services accounted for approximately 4.1% of total transportation revenues in 2002.
Approximately 92.8% of GTN's transported volumes were attributable to long-term contract utilization in 2002. Short-term firm and interruptible volumes accounted for the remaining 4.8% and 2.4%, respectively.
The total quantities of natural gas transported on GTN pipeline for the years ended December 31, 1998 through 2002 are set forth in the following table:
As of December 31, 2002, 71.8% of NBP’s available long-term capacity was held under long-term transportation agreements among four shippers. Contracts for the remaining long-term capacity on NBP take effect in 2003. Also, long-term contracted capacities associated with some contracts increase between 2003 and 2006. At that time 100% of the available long-term capacity on NBP will be dedicated to long-term contracts ranging between approximately 4 and 22 years into the future. As of December 31, 2002, the volume-weighted average remaining term of all long-term contracted capacities on North Baja was approximately 20 years.
In 2002, NBP provided long-term transportation service to four customers. Long-term firm service accounted for 100% of North Baja's total transportation revenue and transported volumes in 2002.
The total quantity of natural gas transported on the NBP pipeline from the commencement of operations in 2002 throughout December 31, 2002, was 11,416 MDth.
PG&E GTN’s largest customer in 2002 was the Utility, which accounted for approximately $47 million, or 20 percent, of PG&E GTN’s transportation revenues. The primary term of the firm service transportation agreement with the Utility extends through 2005 and continues year-to-year thereafter, unless terminated. No other customer accounted for more than 10 percent of PG&E GTN’s transportation revenue in 2002. In 2001, the Utility accounted for approximately $41 million, or 17 percent, of PG&E GTN’s transportation revenues. No other customer accounted for more than 10 percent of PG&E GTN’s transportation revenue in 2001. In 2000, the Utility accounted for approximately $46 million, or 20 percent, of PG&E GTN’s transportation revenues, and Duke Energy and its affiliates accounted for approximately $26 million, or 11 percent, of PG&E GTN’s transportation revenues. No other customer accounted for more than 10 percent of PG&E GTN’s transportation revenue in 2000. Prior to 2002, revenues were based on transportation associated with GTN only, since NBP had no revenues prior to 2002.
Competition
Generation Business
Competitive factors affect the results of PG&E NEG's operations including new market entrants (e.g. construction by others of more efficient generation assets), retirements, and a participant's number of years and extent of operations in a particular energy market.
PG&E NEG's Generation Business competes against a number of other participants in the energy industry including Mirant, Dynegy, Calpine, Duke Energy, Reliant, AES and NRG. Competitive factors relevant to this industry include financial resources, credit quality, risk management acumen, insight into market prices, conditions and regulatory factors and community relations.
When economic circumstances force fuel suppliers into bankruptcy, fuel supply contracts are at risk of being terminated, especially if the current market prices are substantially higher than the prices committed to in long-term contracts. Under such circumstances, PG&E NEG is at risk for having its power sales agreements and fuel supply agreements uncoupled.
As states review the need for electric industry restructuring, there is a risk that current contracts would be found to be too expensive and attempts may be made to abrogate such contracts.
Pipeline Business
PG&E GTN’s gas transmission business competes with other pipeline companies for transportation customers on the basis of transportation rates, access to competitively priced supplies of natural gas, growing markets served by the pipeline and the quality and reliability of transportation services. PG&E GTN believes the competitiveness of a pipeline's transportation services to any market is generally determined by the total delivered natural gas price from a particular supply basin to the market served by the pipeline. The cost of transportation on the pipeline is only one component to the total delivered costs.
Overall, PG&E GTN’s transportation volumes are also affected by other factors such as the availability and economic attractiveness of other energy sources. Hydroelectric generation, for example, may become available based on ample snowfall and displace demand for natural gas as a fuel for electric generation. Finally, in providing interruptible and short-term transportation service, PG&E GTN competes with release capacity offered by shippers holding firm contract capacity on PG&E GTN’s pipelines.
Because PG&E GTN’s transportation service capacity is nearly fully committed under long-term contracts with demand charges that do not fluctuate with system usage, PG&E GTN believes the fluctuating levels of throughput caused by these competitive forces generally will not have a material effect on the financial condition or results of operations of the gas transmission business.
Transportation service on GTN accesses supplies of natural gas primarily from Western Canada and serves markets in the Pacific Northwest, California and Nevada. GTN must compete with other pipelines for access to natural gas supplies in Western Canada. GTN's major competitors for transportation services for Western Canadian natural gas supplies include TransCanada Pipelines, Alliance Pipeline, Southern Crossing Pipeline and Northern Border Pipeline Company, and Westcoast Energy Gas Transmission.
The three markets GTN serves may access supplies from several competing basins in addition to supplies from Western Canada.
Historically, natural gas supplies from Western Canada have been competitively priced on the GTN pipeline in relation to natural gas supplied from the other supply regions serving these markets. Supplies transported from Western Canada on the GTN pipeline compete in the California market with Rocky Mountain natural gas supplies delivered by Kern River Gas Pipeline and Southwest natural gas supplies delivered by Transwestern Pipeline Company, El Paso Natural Gas, and Southern Trails Pipeline. In the Pacific Northwest market, supplies transported from Western Canada on the GTN pipeline compete with Rocky Mountain gas supplies delivered by Northwest Pipeline Corporation and with British Columbia supplies delivered by Westcoast Energy Gas Transmission Company for redelivery by Northwest Pipeline Corporation.
Transportation service on NBP provides access to natural gas supplies primarily from both the Permian basin, located in western Texas and southeastern New Mexico, and the San Juan basin, primarily located in Northwestern New Mexico and Colorado. The NBP system delivers gas to Gasoducto Bajanorte Pipeline, at the Baja California, Mexico - California border, which transports the gas to markets in northern Baja California, Mexico. While there are currently no direct competitors to deliver natural gas to NBP’s downstream markets, the pipeline may compete with fuel oil which is an alternative to natural gas in the operation of some electric generation plants in the North Baja region. Moreover, NBP’s market is near locations of interest for liquefied natural gas development companies who may be interested in delivering foreign natural gas supplies to the area.
Regulation
Various aspects of PG&E NEG’s business are subject to a complex set of energy, environmental and other governmental laws and regulations at the federal, state and local levels. This section highlights some of the more significant laws and regulations affecting PG&E NEG’s business at this time. It is not an exhaustive description of all the laws and regulations that affect PG&E NEG’s business.
Regulation of the U.S. Natural Gas Industry
GTN, NBP, and Iroquois are all “natural gas companies” operating under the provisions of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 and are subject to the jurisdiction of FERC.
The Natural Gas Act of 1938 grants FERC authority over the construction and operation of pipelines and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement, or abandonment of such facilities, as well as the interstate transportation and wholesale sales of natural gas. PG&E NEG and its subsidiaries hold certificates of public convenience and necessity, issued by FERC, authorizing the construction and operation of their pipelines and related facilities now in operation and to transport natural gas in interstate commerce. FERC also has authority to regulate rates for natural gas transportation in interstate commerce.
In addition, actions of the National Energy Board of Canada, the Alberta Energy and Utilities Board, and Northern Pipeline Agency in Canada can affect the ability of TransCanada and Foothills South B.C. to construct any future facilities necessary for the transportation of gas to the interconnection with GTN’s system at the United States-Canadian border. Further, the National Energy Board of Canada and Canadian gas-exporting provinces issue various licenses and permits for the removal of gas from Canada. These requirements parallel the process employed by the U.S. Department of Energy for the importation of Canadian gas. Regulatory actions by the National Energy Board of Canada or the U.S. Department of Energy can have an impact on the ability of GTN’s customers to import Canadian gas for transportation over GTN’s system.
Similarly, actions of the Mexico Energy Regulatory Commission (CRE) can affect the ability of Gasoducto Bajanorte to construct any future facilities necessary for the transportation of gas to or from the interconnection with NBP’s system at the U.S. - Mexico border, and regulatory actions by the CRE or the U.S. Department of Energy can have an impact on the ability of NBP’s customers to import or export gas to or from Mexico over the NBP system.
Under FERC’s current policies, transportation services are classified as either firm or interruptible, and fixed and variable costs are allocated between these types of service for ratemaking purposes. Firm transportation service customers pay both a reservation charge and a delivery charge. The reservation charge is assessed for a firm shipper’s right to transport a specified maximum daily quantity of gas over the term of the shipper’s contract and is payable regardless of the actual volume of gas transported by the shipper. The delivery charge is payable only with respect to the actual volume of gas transported by the shipper. Interruptible transportation service shippers pay only a delivery charge with respect to the actual volume of gas transported by the shipper.
PG&E GTN’s firm and interruptible transportation services have both maximum rates, which are based upon total costs (fixed and variable) and minimum rates, which are based upon the related variable costs. Rates for GTN were established in its 1994 rate case. Rates for NBP were established in FERC’s initial order certificating construction and operations of its system. The maximum and minimum rates for each system are set forth in tariffs on file with FERC. Both GTN and NBP are allowed to vary or discount rates between the maximum and minimum on a non-discriminatory basis. Neither GTN nor NBP have discounted long-term firm transportation service rates, but at times may discount short-term firm and interruptible transportation service rates in order to maximize revenue. Both pipelines are also authorized to offer firm and interruptible service to shippers under individually negotiated rates. Such rates may be above the maximum rate or below the minimum rate, may vary from an “straight-fixed-variable” (SFV) rate design methodology, and may be established with reference to a formula. Such negotiated rate service may be offered only to the extent that, at the time the shipper enters into a negotiated rate agreement, that shipper had the option to receive the same service at the recourse rate, which is the maximum rate for the pipeline’s tariff. All of NBP’s long-term firm contracts are priced at negotiated rates that are fixed for the duration of the contract term.
Both GTN’s and NBP’s recourse rates for firm service are designed on a SFV methodology. Under the SFV rate design, a pipeline company’s fixed costs, including return on equity and related taxes, associated with firm transportation service are collected through the reservation charge component of the pipeline company’s firm transportation service rates. Both pipelines also offer FERC-mandated capacity release mechanisms, under which firm shippers may release capacity to other shippers on a temporary or permanent basis. In the case of a capacity release that is not permanent, a releasing shipper remains responsible to the pipeline for the reservation charges associated with the released capacity. With respect to permanent releases of capacity, the releasing shipper is no longer responsible for the reservation charges associated with the released capacity if the replacement shipper meets the creditworthiness provisions of the pipeline’s tariff and agrees to pay the full reservation fee.
Based on its 1994 rate case, GTN is permitted to recover approximately 96.4% of its fixed costs (as established in 1994) through reservation charges on long-term capacity. As of December 31, 2002, GTN had 93.1% of its available long-term capacity subscribed under long-term firm contracts.
Based on its initial FERC certificate, NBP is permitted to recover 98.1% of its fixed costs through reservation charges on long-term capacity. As of December 31, 2002, North Baja had 71.8% of its available long-term capacity subscribed under long-term contracts. Since these contracts are for fixed negotiated rates, NBP will only recover a portion of its fixed costs in the initial years.
Certain aspects of PG&E GTN’s operations primarily related to pipeline safety are regulated by the U.S. Department of Transportation.
Changing Regulatory Environment of the Natural Gas Industry
Since 1996, FERC has adopted regulations to standardize the business practices and communication methodologies of interstate pipelines in order to create a more integrated and efficient pipeline grid. In a series of related orders, FERC adopted consensus standards developed by the North American Energy Standards Board (NAESB) (successor to the Gas Industry Standards Board), a private consensus standards developer composed of members from all segments of the energy industry. NBP is fully compliant with all FERC-approved NAESB standards. GTN is fully compliant with all FERC-approved NAESB standards with certain limited exceptions for which GTN has sought temporary waiver. In Docket No. RM96-1-020, FERC is proposing to adopt a more recent version of the standards, Version 1.6, promulgated July 31, 2002 by NAESB. FERC has not yet adopted these new standards and is currently seeking comments on them.
In February 2000, FERC issued Order 637 which, among other things, lifted the rate cap for short-term capacity release transactions for a trial period extending to September 30, 2002 and established new reporting requirements that would increase price transparency for capacity in the short-term capacity market. FERC did not renew the trial period, and the rate cap for short-term capacity release transactions was reinstated on October 1, 2002. The temporary lifting of the rate cap, which only applied to capacity release transactions, and its subsequent reinstatement, did not have any significant effect on either GTN or NBP.
In September 2001, FERC issued a notice of proposed rulemaking addressing, among other things, the interactions between interstate pipelines and other energy affiliates. In the event FERC issues a final rule based on this proposal, PG&E GTN may need to establish additional procedures relating to communication among PG&E GTN and other affiliated entities.
PG&E GTN does not believe these regulatory initiatives will have a material impact on its financial condition or results of operations in the foreseeable future.
Regulation of the U.S. Electric Industry
The U.S. electric industry is subject to comprehensive regulation at the federal and state levels.
Federal Regulation. The rates, terms and conditions of the wholesale sale of power by the generating facilities owned or leased by PG&E NEG through PG&E Gen and its subsidiaries are subject to FERC jurisdiction under the Federal Power Act. Various PG&E NEG subsidiaries and affiliates have FERC-approved market-based rate schedules and accordingly have been granted waivers of many of the accounting, record-keeping, and reporting requirements imposed on entities with cost-based rate schedules. This market-based rate authority may be revoked or limited at any time by FERC. Complaints have been filed at FERC seeking to reduce or limit market-based rates and FERC has begun inquiries into whether market-based rates in certain situations have been just and reasonable. For example, on February 13, 2002, FERC ordered its staff to investigate whether Enron Corporation, or any other entity, manipulated short-term prices for electricity and natural gas in the western United States or otherwise exercised undue influence over wholesale electric prices since January 1, 2000, resulting in potentially unjust and unreasonable rates. In addition, on February 25, 2002 the California Public Utilities Commission and the California Electricity Oversight Board each filed complaints at the FERC asking the FERC to rule that certain contracts with market-based rates between the California Department of Water Resources and numerous counterparties (including PG&E ET) were unjust and unreasonable. Numerous other state and federal investigations are ongoing, including investigation into alleged unlawful trading activities.
Currently, most of PG&E NEG’s facilities are exempted to varying degrees from various regulations and reporting requirements because they are qualifying facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 and the Energy Policy Act of 1992 (PURPA) or Exempt Wholesale Generators (EWGs) under PUHCA.
Congress is considering legislation to modify federal laws affecting the electric industry. Bills have been introduced that propose to amend both PURPA and PUHCA. In addition, various states have either enacted or are considering legislation designed to deregulate or reregulate the production and sale of electricity. It is unclear whether or when all power customers will obtain open access to power supplies or whether and, if so, the extent to which deregulation of the electric industry will proceed.
FERC also regulates the rates, terms and conditions for electric transmission in interstate commerce. Tariffs established under FERC regulation provide PG&E NEG with access to transmission lines, which enable PG&E NEG to sell the energy it produces into competitive markets for wholesale energy. In April 1996, FERC issued an order requiring all public utilities to file “open access” transmission tariffs. Some utilities are seeking permission from FERC to recover costs associated with stranded investments through add-ons to their transmission rates. To the extent that FERC will permit these charges, the cost of transmission may be significantly increased and may affect the cost of PG&E NEG’s operations. FERC is also encouraging the restructuring of transmission operations through the use of independent system operators and regional transmission groups. Typically, the establishment of these entities results in the elimination or reduction of transmission charges imposed by successive transmission systems. FERC is also moving forward with a standard market design. The full effect of these changes on PG&E NEG is uncertain at this time.
FERC also licenses all of PG&E NEG’s hydroelectric and pumped storage projects. These licenses, which are issued for 30 to 50 years, will expire at different times between 2003 and 2020. The relicensing process often involves complex administrative processes that may take as long as 10 years. FERC may issue a new license to the existing licensee, issue a license to a new licensee, order that the project be taken over by the federal government (with compensation to the licensee), or order the decommissioning of the project at the owner’s expense. These hydroelectric licenses are owned by USGenNE. USGenNE is held for sale at December 31, 2002.
The Department of Energy also regulates the importation of natural gas from Canada and exportation of power to Canada.
State and Other Regulations. In addition to federal laws and regulation, PG&E NEG is also subject to various state regulations. First, public utility regulatory commissions at the state level are responsible for approving rates and other terms and conditions under which public utilities purchase electric power from most of PG&E NEG’s independent power projects. As a result, power sales agreements, which PG&E NEG affiliates enter into with such utilities, are potentially subject to review by the public utility commissions, through the commissions’ power to approve utilities’ rates and cost recoveries. Second, state public utility commissions also have the authority to promulgate regulations for implementing some federal laws, including certain aspects of PURPA. Third, some public utility commissions have asserted limited jurisdiction over independent power producers. For example, in New York the state public utility commission has imposed limited requirements involving safety, reliability, construction and the issuance of securities by subsidiaries operating assets located in that state. Fourth, state regulators have jurisdiction over the restructuring of retail electric markets and related deregulation of their electric markets. Finally, states may also assert jurisdiction over the siting, construction and operation of PG&E NEG’s facilities.
Environmental Regulation
PG&E NEG’s operations are subject to extensive federal, state, local and foreign laws and regulations relating to air quality, water quality, waste management, natural resources and health and safety. PG&E NEG’s compliance with these environmental requirements necessitates significant capital and operating expenditures related to monitoring, pollution control equipment, emission fees and permitting at various operating facilities.
PG&E NEG believes it is in substantial compliance with applicable environmental laws and applicable health and safety laws. However, it is possible that additional costs will be incurred or operations by some of PG&E NEG’s generating affiliates will be limited as a result of new interpretations or application of existing laws and regulations, the enactment of more stringent requirements, or the identification of conditions that could result in additional obligations or liabilities.
If PG&E NEG does not comply with environmental requirements that apply to its operations, regulatory agencies could seek to impose civil, administrative and/or criminal liabilities, as well as seek to curtail operations. Under some statutes, private parties could also seek to impose civil fines or liabilities for property damage, personal injury and possibly other costs. If such actions are brought against PG&E NEG or any of its generating affiliates and are determined adversely to PG&E NEG, such actions could have a material adverse effect on its financial condition, cash flows and results of operations.
Regulation of PG&E Corporation
PG&E NEG and its parent, PG&E Corporation, are exempt from all provisions, except Section 9(a)(2), of PUHCA although, as discussed below, the California Attorney General (AG) recently filed a petition with the Securities and Exchange Commission (SEC) to revoke PG&E Corporation’s exemption. At present, PG&E Corporation has no expectation of becoming a registered holding company under PUHCA.
Although PG&E Corporation is not a public utility under the laws of California and is not subject to regulation as such by the California Public Utilities Commission (CPUC), the CPUC approval authorizing the Utility to form a holding company was granted subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The CPUC, as discussed below, issued a decision asserting that it maintains jurisdiction to enforce the conditions against the holding companies and to modify, clarify or add to the conditions. The financial conditions provide, among other things, that the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s service obligation to serve or to operate the Utility in a prudent and efficient manner, shall be given first priority by the Board of Directors of PG&E Corporation (the “first priority condition”).
The CPUC also has adopted complex and detailed rules governing transactions between California’s natural gas local distribution and electric utility companies and their non-regulated affiliates. The rules permit non-regulated affiliates of regulated utilities to compete in the affiliated utility’s service territory, and also to use the name and logo of their affiliated utility, provided that in California the affiliate includes certain designated disclaimer language which emphasizes the separateness of the entities and that the affiliate is not regulated by the CPUC. The rules also address the separation of regulated utilities and their non-regulated affiliates and information exchange among the affiliates. The rules prohibit the utilities from engaging in certain practices that would discriminate against energy service providers that compete with the Utility’s non-regulated affiliates. The CPUC has also established specific penalties and enforcement procedures for affiliate rules violations.
Employees
As of February 24, 2003, PG&E NEG employed approximately 1,900 people, of which approximately 530 were covered by collective bargaining agreements.
ITEM 2.
ITEM 2. PROPERTIES
PG&E NEG’s corporate offices currently occupy approximately 230,000 square feet of leased office space in several buildings principally in Bethesda and Rockville, Maryland.
In addition to PG&E NEG’s corporate office space, PG&E NEG leases or owns various real property and facilities relating to its generating facilities, pipeline facilities and development activities. PG&E NEG’s principal generating facilities are generally described under the descriptions of its regional asset portfolios. PG&E NEG believes that it has title to its facilities in accordance with standards generally accepted in the energy industry, subject to exceptions which, in its opinion, would not have a material adverse effect on the use or value of the facilities. All of PG&E NEG’s independent power projects and some of the merchant plants are pledged to lenders under non-recourse project loans.
PG&E NEG believes that all of the existing office and generating facilities are adequate for its needs through calendar year 2003.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
California Energy Trading Litigation-PG&E Energy Trading Holdings Corporation and various of its affiliates (collectively ET-Power) have been named as defendants, along with other generators and market participants in the California electricity market, in connection with a variety of claims arising out of the California energy crisis. ET-Power has been served with complaints in the following cases. It is possible that it will be served with additional complaints and that some of these cases will be consolidated with other cases in which similar allegations have been raised respecting other market participants. These proceedings are administrative and judicial in nature.
ET-Power has been named, along with multiple other defendants, in four class action lawsuits known as Pier 23 against marketers and other unnamed sellers of electricity in California markets. These cases are (1) Pier 23 Restaurant v. PG&E Energy Trading Corporation, et al., filed on January 24, 2001, in San Francisco Superior Court and subsequently removed to the United States District Court for the Northern District of California; (2) Hendricks v. Dynegy Power Marketing, Inc., PG&E Energy Trading Corporation, et al., filed on November 29, 2000, in San Diego Superior Court and subsequently removed to the United States District Court for the Southern District of California; (3) Sweetwater Authority v. Dynergy Inc., PG&E Energy Trading Corporation, et al., filed on January 16, 2001, in San Diego Superior Court and subsequently removed to the United States District Court for the Southern District of California; and (4) People of the State of California v. Dynegy Power Marketing, Inc., PG&E Energy Trading Corporation, et al., filed on January 18, 2001, in San Francisco Superior Court and subsequently removed to the United States District Court for the Northern District of California.
These suits allege violation by the defendants of state antitrust laws and state laws against unfair and unlawful business practices. Specifically, the named plaintiffs allege that the defendants, including the owners of in-state generation and various power marketers, conspired to manipulate the California wholesale power market to the detriment of California consumers. Included among the acts forming the basis of the plaintiffs’ claims are the alleged improper sharing of generation outage data, improper withholding of generation capacity, and the manipulation of power market bid practices. The plaintiffs seek unspecified treble damages and, among other remedies, disgorgement of alleged unlawful profits for sales of electricity beginning in 1999 or 2000, restitution, injunctive relief, and attorneys’ fees.
These cases are pending in the U.S. District Court for the Southern District of California. Plaintiffs have a filed motion to remand the proceedings to state court and in January 2003, the motion was granted. However, in view of various appeals of this order, the cases remain in federal court.
On May 13, 2002, ET-Power was named, along with multiple other defendants, in a complaint filed in San Francisco Superior Court by James A. Millar, individually and on behalf of the general public and as a representative taxpayer against energy suppliers and other unnamed sellers of electricity in the California market. In his complaint, plaintiff asserts the defendants violated state laws against unfair and fraudulent business practices by entering into certain long-term energy contracts with the California Department of Water Resources (DWR). The plaintiff claims that the contracts were made under circumstances that resulted in excessively high and unfair prices and, as a result, refunds should be made to the extent that the prices in the contracts were excessive. In addition, plaintiff seeks, among other remedies, an order enjoining enforcement of the allegedly unfair terms and conditions of the long-term contracts, declaratory relief, and attorneys’ fees. FERC is currently addressing the DWR contracts in the administrative actions before FERC brought by the CPUC and California Electricity Oversight Board on February 25, 2002. On June 13, 2002 the defendants removed the case to the U.S. District Court for the Northern District of California based on federal preemption. The plaintiff filed a motion to remand the case to state court. On October 11, 2002, the Judicial Panel on Multidistrict Litigation entered a final order transferring this case to the Southern District of California and to the same judge presiding over the Pier 23 case. The panel determined that the Millar case, as well as seven other pending lawsuits, involved common questions of law and fact. ET-Power is currently not a defendant in any of these other lawsuits. Plaintiff has renewed his motion to remand these cases to state court.
On July 15, 2002, ET-Power was named among other sellers of power in an action filed by the Public Utility District No. 1 of Snohomish County, Public Utility District No. 1 of Snohomish County v. Dynegy Power Marketing, et al., in the U.S. District Court for the Central District of California. Plaintiff alleges various theories of manipulation of the deregulated California electricity market by the defendants in violation of state antitrust laws and state laws against unlawful and fraudulent business practices. Plaintiff claims that the defendants manipulated the energy market, resulting in higher electricity prices and seeks, among other remedies, disgorgement, restitution, injunctive relief, and treble damages. Plaintiff also claims that defendants failed to file their rates in advance with the FERC, which failure plaintiff asserts was a violation of the Federal Power Act. On October 11, 2002, the Judicial Panel on Multidistrict Litigation entered a final order transferring the Snohomish case to the U.S. District Court for the Southern District of California and to the same judge presiding over the Pier 23 and Millar proceedings. The defendants filed a joint motion to dismiss and to strike various elements of the complaint. On January 8, 2003, the U.S. District Court for the Southern District of California dismissed the complaint, finding that the issue of whether and how market manipulation affected electricity rates was one that should be determined by the FERC. Plaintiff has filed a notice of appeal of the district court’s decision with the U.S. Court of Appeals for the Ninth Circuit.
By letter dated May 7, 2002, ET-Power was advised by the Attorney General of California that it believes ET-Power (along with numerous other generators and market participants) violated state laws governing unfair and fraudulent business practices and that unless ET-Power settled the matter the California Attorney General would by June 1, 2002, file suit against ET-Power. The California Attorney General stated that he will claim that ET-Power failed to have its rates on file with FERC and that accordingly any sales made under such rates violated the Federal Power Act (a claim that the California Attorney General has made before FERC and which FERC has rejected) and that ET-Power exercised market power in charging unjust and unreasonable prices. ET-Power has not yet been served with a complaint in this matter.
In addition to these judicial proceedings, on March 20, 2002, the California Attorney General filed a complaint at FERC against ET-Power and other named and unnamed public utility sellers of energy and ancillary services. The California Attorney General alleges that wholesale sellers of energy to the California ISO, California Power Exchange (PX) and the DWR failed to file their rates in accordance with the requirements of Section 205 of the Federal Power Act. Specifically, the California Attorney General claims that FERC has not been able to determine whether the rates charged by such sellers are just and reasonable; that FERC’s reporting requirements are insufficient to provide FERC the information necessary to make this determination and that even if FERC’s policies and procedures did comply with Section 205 of the Federal Power Act, the wholesale sellers failed to comply with its quarterly reporting requirements. As a result, the California Attorney General requests that: (1) sellers should be directed to comply, on a prospective basis, with the requirements of Section 205 of the Federal Power Act; (2) sellers should be required to provide transaction-specific information regarding their short-term sales to the ISO, PX and DWR for the years 2000 and 2001 to FERC; (3) if rates were charged that were not just and reasonable, refunds should be ordered; (4) FERC should declare that market-based rates are not subject to the filed rate doctrine; and (5) FERC should institute proceedings to determine whether any further relief would be appropriate. On May 31, 2002, FERC issued a decision denying most of the relief requested and on July 1, 2002, the California Attorney General filed a petition with FERC seeking rehearing of its order, which petition FERC denied on September 23, 2002. The California Attorney General has appealed this decision to the U.S. Court of Appeals for the Ninth Circuit. PG&E NEG believes that the outcome of these matters will not have a material adverse affect on PG&E NEG’s financial condition or results of operations.
Brayton Point-On March 27, 2002, Rhode Island Attorney General notified USGenNE of his belief that USGenNE’s Brayton Point Station “is in violation of applicable statutory and regulatory provisions governing its operations...”, including “protections accorded by common law” respecting discharges from the facility into Mt. Hope Bay. He stated that he intends to seek judicial relief “to abate these environmental law violations and to recover damages...” within the next 30 days. The notice purportedly was provided pursuant to section 7A of chapter 214 of Massachusetts General Laws. PG&E NEG believes that Brayton Point Station is in full compliance with all applicable permits, laws and regulations. The complaint has not yet been filed or served. In early May 2002, the Rhode Island Attorney General stated that he did not plan to file the action until EPA issues a draft Clean Water Act NPDES permit for Brayton Point. EPA issued the draft NPDES permit on July 22, 2002, and the Rhode Island Attorney General has since stated he has no intention of pursuing the matter until he reviews USGenNE’s response to the draft permit which was submitted on October 4, 2002. Management is unable to predict whether he will pursue this matter and, if he does, the extent to which it will have a material adverse affect on PG&E NEG’s financial condition or results of operations.
Natural Gas Royalties Litigation-For information regarding this matter, please see Note 5 of the Notes to the Consolidated Financial Statements.
North Baja Pipeline Litigation-North Baja and the California State Lands Commission are defendants in an action brought by the County of Imperial and the City of El Centro alleging that the environmental impact report prepared for the North Baja pipeline by the California State Lands Commission fails to meet the requirements of the California Environmental Quality Act (CEQA). The action contains eleven causes of action, all of which are alleged violations of CEQA. The first cause of action alleges that the State Lands Commission in preparing the environmental impact report, failed to address environmental justice issues. The remaining causes of action all challenge the environmental impact report on various grounds. Most of these causes of action are based on a claim and theory that the environmental impact report was required to evaluate and mitigate, as part of the North Baja pipeline project, potential air emissions from power plants located in Mexico which (in addition to plants in San Diego County) will be served by the pipeline. Petitioners’ prayer for relief further seeks to enjoin construction of the pipeline, although to date no injunction has been sought. A hearing on the merits of the case was held on September 13, 2002. On November 27, 2002, the Sacramento County Superior Court entered a Judgment Denying the Petition for Writ of Mandate and Denying Request for Declaratory and Injunctive Relief granting judgment in favor of the California Court of Appeal, Third District. To date, Petitioners have not applied for an injunction from the Court of Appeal pending final resolution of their appeal by that court. PG&E GTN believes that the outcome of this matter will not have a material adverse affect on its financial condition or results of operations.
Shaw Litigation-On December 13, 2002, The Shaw Group, Inc. (Shaw) filed complaints in the United States District Court for the District of Delaware against PG&E NEG and certain affiliates including the owners of the Covert and Harquahala projects. Shaw is the construction contractor for these projects. In its complaints, Shaw alleges that it has not received adequate assurance of payment from PG&E NEG or its affiliates, that PG&E NEG’s pre-financing payment guarantees for each of the Covert and Harquahala projects have been restablished, and that PG&E NEG has repudiated its obligations under
various guarantees. Shaw seeks declaratory relief that it is relieved from its obligations under the construction contracts for Covert and Harquahala and certain other agreements and that these contracts have been repudiated by PG&E NEG and its affiliates entitling Shaw to damages. On February 11, 2003, Shaw amended its complaint so that, in effect, the complaint now seeks to prevent PG&E NEG from turning over the projects to the GenHoldings lenders. GenHoldings believes that Shaw is not entitled to adequate assurances as a matter of law and that, in any case, the credit arrangements which became effective on December 23, 2002, by which the lenders agreed to provide funds to complete construction, are sufficient to provide Shaw adequate assurances. PG&E NEG believes Shaw’s other claims are entirely without merit and intends to vigorously defend all claims and pursue any counterclaims it or its affiliates may have against Shaw. Due to the recent deterioration of PG&E NEG’s financial condition, PG&E NEG believes that the ultimate outcome of all of this litigation may have a material adverse affect on PG&E NEG’s financial condition or results of operations.
Southaven and Caledonia Tolling Agreements. PG&E ET signed a tolling agreement with Southaven Power, LLC (Southaven) dated as of June 1, 2000, under which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade as defined in the tolling agreement. The amount of the guarantee does not exceed $175 million. By letter dated August 31, 2002, Southaven advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade as defined in the tolling agreement and as PG&E ET had failed to provide, within thirty days from the downgrade substitute credit support that meets the requirement of the tolling agreement. Under the tolling agreement, Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Southaven with a notice of default respecting Southaven’s performance under the tolling agreement and concerning the inability of the facility to inject its output into the local grid. Southaven has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.
In addition, PG&E ET signed a tolling agreement with Caledonia Generating, LLC (Caledonia) dated as of September 20, 2000, pursuant to which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade as defined in the agreement. The amount of the guarantee now does not exceed $250 million. By letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade as defined in the tolling agreement and because PG&E ET had failed to provide, within thirty days from the downgrade substitute credit support that meets the requirement of the agreement. Under the tolling agreement, Caledonia has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Caledonia with a notice of default respecting Caledonia’s performance under the agreement. The notice of default concerned the inability of the facility to inject its output into the local grid. Caledonia has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.
Under each of these agreements, if a party terminates the tolling agreement it has the right to seek recovery of a termination payment. The determination of the termination payment is based on a formula that takes into account a number of factors, including market conditions such as the price of power and the price of fuel. In the event of a dispute over whether such a payment is due or, if due, its amount, that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. The dispute resolution process could take as long as 6 months to more than a year to complete.
On February 7, 2003, Southaven and Caledonia filed an emergency petition to compel arbitration or, in the alternative, for a temporary restraining order and preliminary injunction with the Circuit Court for Montgomery County, Maryland. The Court has denied the relief requested and set the matter for hearing on March 3, 2003. Following oral argument, the judge ruled, subject to entry of a written order, that PG&E ET was required to continue to perform under the agreements.
PG&E ET is not able to predict whether the counter parties will seek to terminate the agreements or whether the Court will grant the requested relief. Accordingly, it is not able to predict whether and, if so, the extent to which, these proceedings will have a material adverse effect on PG&E NEG’s financial condition or results of operation.
ITEM 4.
ITEM 4. SUBMISSON OF MATTERS TO A VOTE OF SECURITY HOLDERS
PG&E NEG is a wholly owned subsidiary of PG&E National Energy Group, LLC which, in turn, is a direct wholly owned subsidiary of PG&E Corporation. PG&E NEG’s Board of Directors was re-elected in August 2002 and Thomas B. King was elected as a director in November 2002, and the actions taken by the Board of Directors in 2002 were ratified and confirmed by the shareholder in August 2002.
PART II.
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS
PG&E NEG is a wholly owned subsidiary of PG&E National Energy Group, LLC which, in turn, is a direct wholly owned subsidiary of PG&E Corporation. During the twelve months ended December 31, 2002 and 2001, PG&E NEG paid no dividends on its common stock. In 2000 and 1999, PG&E NEG distributed $284 million and $111 million, respectively, in dividends on its common stock. PG&E NEG is restricted in its ability to declare and distribute dividends.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following tables present PG&E NEG’s summary historical financial data. You should read this data together with the section entitled Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a further explanation of the financial data summarized here. The historical financial information may not be indicative of PG&E NEG’s future performance.
(1)
Operating revenues and operating expenses reflect the adoption, during 2002, of a new accounting policy implementing a change from gross to net method of reporting revenues and expenses on trading activities. The amounts for trading activities for the comparative periods in 1998 through 2001 have been reclassified to conform with the new net presentation.
(2)
For purposes of calculating the ratio of earnings to fixed charges, earnings consist of earnings from continuing operations before income taxes and fixed charges (exclusive of interest capitalized). Fixed charges consist of interest on all indebtedness (including amounts capitalized), amortization of debt issuance costs and the portion of lease rental expense that represents a reasonable approximation of the interest factor.
(3)
The ratio of earnings to fixed charges was negative for the year ended December 31, 2002 and December 31, 1999. The amount of the coverage deficiency was $3,070 million and $1,245 million, respectively.
Above data includes “Assets Held for Sale”. Refer to Note 5 in Item 8 for a further discussion.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Background
PG&E National Energy Group, Inc. (PG&E NEG) is an integrated energy company with a focus on power generation, natural gas transmission and wholesale energy marketing and trading in North America. PG&E NEG and its subsidiaries have integrated their generation, development and energy marketing and trading activities.
PG&E NEG was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to PG&E NEG. PG&E NEG is an indirect wholly owned subsidiary of PG&E Corporation. PG&E NEG and its subsidiaries are principally located in the United States and Canada and are engaged in power generation, wholesale energy marketing and trading, risk management, and natural gas transmission. PG&E NEG’s principal subsidiaries include:
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PG&E Generating Company, LLC and its subsidiaries, collectively referred to as PG&E Gen;
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PG&E Energy Trading Holdings Corporation and its subsidiaries, collectively referred to as PG&E ET;
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PG&E Gas Transmission Corporation and its subsidiaries, collectively referred to as PG&E GTC, which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively referred to as PG&E GTN) including North Baja Pipeline, LLC,
PG&E NEG has identified two reportable operating segments:
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Interstate Pipeline Operations, or the Pipeline Business; and
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Integrated Energy and Marketing, or the Energy Generation Business.
PG&E National Energy Group, LLC owns 100 percent of the stock of PG&E NEG, GTN Holdings, LLC owns 100 percent of the stock of PG&E GTN, and PG&E Energy Trading Holdings, LLC owns 100 percent of the stock of PG&E ET. The organizational documents of PG&E NEG and these limited liability companies require unanimous approval of their respective boards of directors, including at least one independent director, before they can:
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Consolidate or merge with any entity;
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Transfer substantially all of their assets to any entity; or
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Institute or consent to bankruptcy, insolvency or similar proceedings or actions.
The limited liability companies may not declare or pay dividends unless the respective boards of directors have unanimously approved such action, and the company meets specified financial requirements.
As a result of the sustained downturn in the power industry, PG&E NEG and its affiliates have experienced a financial downturn, which caused the major credit rating agencies to downgrade PG&E NEG’s and its subsidiaries’ credit ratings to below investment grade. PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.5 billion, but this debt is non-recourse to PG&E NEG. PG&E NEG and these subsidiaries continue to negotiate with their lenders regarding a restructuring of this indebtedness and these commitments. The factors affecting PG&E NEG’s business causing these defaults and the principal actions being taken by PG&E NEG are discussed later in this MD&A and in the Note 3 of the Notes to the Consolidated Financial Statements.
During the fourth quarter of 2002, PG&E NEG and certain subsidiaries have agreed to sell or have sold certain assets, have abandoned other assets, and have significantly reduced energy trading operations. As a result of these actions, PG&E NEG has incurred pre-tax charges to earnings of approximately $3.9 billion in 2002. PG&E NEG and its subsidiaries are continuing their efforts to abandon, sell, or transfer additional assets in an ongoing effort to raise cash and reduce debt, whether through negotiation with lenders or otherwise. As a result, PG&E NEG expects to incur additional charges to earnings in 2003 as it restructures its operations. In addition, if a restructuring agreement is not reached and the lenders exercise their default remedies, or if the financial commitments are not restructured, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced into a proceeding under the Bankruptcy code.
These segments were determined based on the following characteristics:
This Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read in conjunction with the Consolidated Financial Statements and Notes to the Consolidated Financial Statements included herein.
Financial information about each reportable operating segment is provided in this MD&A and in Note 14 of the Notes to the Consolidated Financial Statements.
Forward-Looking Statements and Risk Factors
This report contains forward-looking statements about the future that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on information currently available to management. These forward-looking statements are identified by words such as “estimates,” “expects,” “anticipates,” “plans,” “believes,” “could,” “should,” “would,” “may,”and other similar expressions. Actual results could differ materially from those contemplated by the forward-looking statements. Although PG&E NEG is not able to predict all of the factors that may affect future results, some of the factors that could cause future results to differ materially from historical results or those expressed or implied by the forward-looking statements include:
Efforts to Restructure Indebtedness. Whether PG&E NEG and certain of its subsidiaries seek protection under or are forced into a proceeding under the U.S. Bankruptcy Code will be affected by:
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the outcome of PG&E NEG’s negotiations with its lenders under various credit facilities, as well as with representatives of the holders of PG&E NEG’s Senior Notes, to restructure PG&E NEG and its subsidiaries’ indebtedness and commitments;
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the terms and conditions of any sale, transfer, or abandonment of certain of PG&E NEG’s merchant assets, including its New England generating assets, that PG&E NEG may enter into; and
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the terms and conditions under which certain generating projects will be transferred to the project lenders as required by recent restructuring agreements.
Operational Risks. PG&E NEG’s future results of operation and financial condition will be affected by:
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the extent to which PG&E NEG incurs further charges to earnings as a result of the abandonment, sale or transfer of assets or termination of contractual commitments, whether such transactions occur in connection with restructuring of PG&E NEG’s indebtedness or otherwise;
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any potential charges to income that would result from the reduction and potential discontinuance of PG&E NEG’s energy trading and marketing operations including tolling transactions;
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any potential charges to income that would result from the discontinuance or transfer of any of its merchant generation assets;
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the inability of PG&E NEG, its merchant assets and other subsidiaries, including USGen New England, Inc., to maintain sufficient liquidity necessary to meet their commodity and other obligations;
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the extent to which PG&E NEG’s current construction of generation, pipeline, and storage facilities are completed and the pace and cost of that completion, including the extent to which commercial operations of these construction projects are delayed or prevented because of financial or liquidity constraints, changes in the national energy markets and by the extent and timing of generating, pipeline, and storage capacity expansion and retirements by others, or by various development and construction risks such as PG&E NEG’s failure to obtain necessary permits or equipment, the failure of third-party contractors to perform their contractual obligations, or the failure of necessary equipment to perform as anticipated and the potential loss of permits or other rights in connection with PG&E NEG’s decision to delay or defer construction;
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the impact of layoffs and loss of personnel; and
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future sales levels which can be affected by economic conditions, weather, conservation efforts, outages, and other factors.
Current Conditions in the Energy Markets and the Economy. PG&E NEG’s future results of operation and financial condition will be affected by changes in energy markets, changes in the general economy, wars, embargoes, financial markets, interest rates, other industry participant failures, the markets’ perception of energy merchant facilities and other factors.
Actions of Counterparties. PG&E NEG’s future results of operation and financial condition may be affected by:
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the extent to which counterparties demand collateral in connection with PG&E ET’s trading and nontrading activities and the ability of PG&E NEG and its subsidiaries to meet the liquidity calls that may be made; and
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the extent to which tolling agreements and other contracts are terminated and the amount of any termination damages they may seek to recover from PG&E NEG as guarantor.
Accounting and Risk Management. PG&E NEG’s future results of operation and financial condition may be affected by:
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the effect of new accounting pronouncements;
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changes in critical accounting estimates;
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volatility in income resulting from mark-to-market accounting, or changes in mark-to-market methodologies;
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the extent to which the assumptions underlying critical accounting estimates, mark-to-market accounting, and risk management programs are not realized;
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the volatility of commodity fuel and electricity prices and the effectiveness of risk management policies and procedures designed to address volatility; and
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the ability of counterparties to satisfy their financial commitments and the impact of counterparties’ nonperformance on PG&E NEG’s liquidity.
Legislative and Regulatory Matters. PG&E NEG’s business may be affected by:
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legislative or regulatory changes affecting the electric and natural gas industries in the United States, including the pace and extent of efforts to restructure the electric and natural gas industries; and
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heightened regulatory and enforcement agency focus on the merchant energy business including investigations into “wash” or “round-trip” trading, specific trading strategies and other industry issues, with the potential for changes in industry regulations and in the treatment of PG&E NEG by state and federal agencies.
Pending Litigation and Environmental Matters. PG&E NEG’s future results of operation and financial condition may be affected by:
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the effect of compliance with existing and future environmental laws, regulations, and policies, the cost of which could be significant;
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the outcome of pending litigation and environmental matters; and
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the outcome of the California Attorney General’s petition requesting revocation of PG&E Corporation’s exemption from the Public Utility Holding Company Act of 1935, and the effect of such outcomes, if any, on PG&E NEG.
As the ultimate impact of these and other factors is uncertain, these and other factors may cause future earnings to differ materially from historical results or outcomes currently sought or expected.
PG&E NEG’s Consolidated Financial Statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. However, as a result of current liquidity concerns and restructuring discussions with PG&E NEG’s lenders, such realization of assets and liquidation of liabilities are subject to uncertainty.
MARKET CONDITIONS AND BUSINESS ENVIRONMENT
Background and Recent Developments
In 2002, energy markets experienced several significant adverse changes including:
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Contractions and instability of wholesale electricity and energy commodity markets;
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Significant decline in generation margins (spark spreads) caused by excess supply and reduced demand in most regions of the United States;
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Loss of confidence in energy companies due to increased scrutiny by regulators, elected officials, and investors as a result of a string of financial reporting scandals;
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Heightened scrutiny by credit rating agencies prompted by these market changes and scandals which resulted in lower credit ratings for many market participants; and
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Resulting significant financial distress and liquidity problems among market participants leading to numerous financial restructurings and less market participation.
PG&E NEG has been significantly impacted by these adverse changes in 2002. New generation came online while the demand for power was dropping. This oversupply and reduced demand created low spark spreads (i.e. the net of power prices less fuel costs) and depressed operating margins. These changes in the power industry have had a significant negative impact on the financial results and liquidity of PG&E NEG. Before July 31, 2002, most of the various debt instruments of PG&E NEG and its affiliates carried investment grade credit ratings assigned by Standard & Poor’s Ratings Group (S&P) and Moody’s Investors Service (Moody’s). Since July 31, 2002, these credit rating agencies have downgraded all of PG&E NEG’s debt facilities to below investment grade.
PG&E NEG is currently in default under various debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.5 billion, but this debt is non-recourse to PG&E NEG. On November 14, 2002, PG&E NEG defaulted on the repayment of its $431 million 364-day tranche of its corporate revolving credit facility (Corporate Revolver). This resulted in a default under the two-year tranche of the Corporate Revolver which had an outstanding balance of $273 million at December 31, 2002, the majority of which supports outstanding letters of credit. The default under the Corporate Revolver also constitutes a cross-default under PG&E NEG’s (amounts outstanding at December 31, 2002) (1) the Senior Notes ($1 billion), (2) its guarantee of a turbine revolving credit facility (Turbine Revolver) ($205 million), and (3) its equity commitment guarantees for the GenHoldings I, LLC’s (GenHoldings) credit facility ($355 million), for the La Paloma credit facility ($375 million) and for the Lake Road credit facility ($230 million). In addition, on November 15, 2002, PG&E NEG failed to pay a $52 million interest payment due under the Senior Notes. PG&E NEG does not currently have sufficient cash to meet its financial obligations and has ceased making payments on its debt and equity commitments.
PG&E NEG, and its subsidiaries are restructuring their operations to increase cash, reduce financial obligations, dispose of merchant plant facilities, and decrease energy trading operations. PG&E NEG’s objective is to limit its asset trading and risk management activities to only what is necessary for energy management services to facilitate the transition of PG&E NEG’s merchant generation facilities through their sale, transfer or abandonment. PG&E NEG will then further reduce and transition to only retain limited capabilities to ensure fuel procurement and power logistics for PG&E NEG’s retained independent power plant operations. These restructuring activities have caused material charges to earnings in 2002, and are anticipated to cause substantial additional charges to earnings in 2003.
PG&E NEG, and its subsidiaries and these lenders are engaged in discussions regarding the restructuring of these commitments. If a restructuring agreement is not reached and the lenders exercise their default remedies or if the financial commitments are not restructured, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced involuntarily into proceedings under the U.S. Bankruptcy Code.
Asset transfers, sales or abandonments, liquidity issues and potential restructuring have resulted in substantial charges in earnings in 2002. The following table outlines the pretax charges for impairments, write-offs and other charges that PG&E NEG recorded in the fourth quarter of 2002 and the total pretax charges for the year 2002. In addition to these 2002 charges, PG&E NEG and its subsidiaries expect to incur substantial charges to earnings in 2003 primarily related to:
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The reduction in energy trading activities;
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The possible settlement of tolling arrangements (see discussion of tolling agreements in this MD&A under Commitments and Capital Expenditures - Tolling Agreements);
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Charges related to the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, ”Accounting for Asset Retirement Obligations“ (see discussion in this MD&A under Accounting Pronouncements issued but not yet adopted);
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A possible settlement under the Attala tolling agreement and related lease (see discussion below in Impairments, Write-offs, and Other Charges);
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Potential conversion of existing debt and equity funding commitments to new discounted obligations, including potential write-offs of deferred financing costs; and
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Further restructuring costs.
Impairments, Write-offs & Other Charges
The following table outlines the pre-tax changes for Impairments, Write-offs and Other charges that PG&E NEG and its subsidiaries recorded (in millions):
Impairment of GenHoldings Projects: GenHoldings, an indirect subsidiary of PG&E NEG, is obligated under its credit facility to make equity contributions to fund construction of the Harquahala, Covert and Athens generating projects. This credit facility is secured by these projects in addition to the Millennium generating facility. GenHoldings defaulted under its credit agreement in October 2002, by failing to make equity contributions to fund construction draws for the Athens, Harquahala and Covert generating projects. Although PG&E NEG has guaranteed GenHoldings’ obligations to make equity contributions of up to $355 million, PG&E NEG notified the GenHoldings’ lenders that it would not make further equity contributions on behalf of GenHoldings. In November and December 2002, the lenders executed waivers and amendments to the credit agreement under which they agreed to continue to waive, until March 31, 2003, the default caused by GenHoldings’ failure to make equity contributions. In addition, certain of these lenders have agreed to increase their loan commitments to an amount intended to be sufficient to provide: (1) the funds necessary to complete construction of the Athens, Covert and Harquahala facilities under the construction contracts; and (2) additional working capital facilities to enable each project, including Millennium, to timely pay for its fuel requirements and to provide its own collateral to support natural gas pipeline capacity reservations and independent transmission operator requirements. The November and December increased loan commitments rank equally with each other but are senior to amounts loaned through and including the October credit extension.
In consideration of the lenders’ forbearance and additional funding, PG&E NEG and GenHoldings have agreed to cooperate with any reasonable proposal by the lenders regarding disposition of the equity in or assets of any or all of the GenHoldings subsidiaries holding the Athens, Covert, Harquahala and Millennium projects in connection with the restructuring of PG&E NEG’s and its subsidiaries financial commitments to such lenders. The amended credit agreement provides that an event of default will occur if the Athens, Covert, Harquahala and Millennium projects are not transferred to the lenders or their designees on or before March 31, 2003. Such a default would trigger lender remedies, including the right to foreclose on the projects. Under the waiver, PG&E NEG has re-affirmed its guarantee of GenHoldings’ obligation to make remaining equity contributions of approximately $355 million to these projects. Neither PG&E NEG nor GenHoldings currently expects to have sufficient funds to make this payment. The requirement to pay $355 million remains an obligation of PG&E NEG that would survive the transfer of the projects.
In accordance with the provisions of SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” (SFAS 144) GenHoldings has been accounted for as assets held for use at December 31, 2002. In accordance with SFAS 144, GenHoldings was tested for impairment. As a result of the test the asset was determined to be impaired and was written down to fair value. Based on the current estimated fair value of the assets of GenHoldings, PG&E NEG recorded a pretax loss from impairment of $1.147 billion in the fourth quarter of 2002.
Impairment of Lake Road and La Paloma Projects: On November 14, 2002, PG&E NEG defaulted under its equity commitment guarantees for the Lake Road and the La Paloma credit facilities. On December 4, 2002, PG&E NEG subsidiaries entered into agreements with respect to each of the Lake Road and La Paloma generating projects providing for: (1) funding of construction costs required to complete the La Paloma facility; and (2) additional working capital facilities to enable each subsidiary to timely pay for its fuel requirements and to provide its own collateral to support natural gas pipeline capacity reservations and independent transmission system operator requirements, as well as for general working capital purposes. Lenders extending new credit under these agreements have received liens on the projects that are senior to the existing lenders’ liens.
The Lake Road and La Paloma projects have been financed entirely with debt. PG&E NEG has guaranteed the repayment of a portion of the project subsidiary debt of approximately $230 million for Lake Road and $375 million for La Paloma, which amounts represent the subsidiaries’ equity contributions in the projects. The lenders have demanded the immediate payment of these equity contributions. Neither the PG&E NEG subsidiaries nor PG&E NEG have sufficient funds to make these payments. The requirement to make the payments will remain an obligation of PG&E NEG that would survive the transfer of the projects.
In consideration of the lenders’ forbearance and additional funding, PG&E NEG has agreed to cooperate with any reasonable proposal by the lenders regarding disposition of the equity in or assets of any or all of the PG&E NEG subsidiaries holding the La Paloma project in connection with the restructuring of PG&E NEG’s financial commitments. In addition, it is a default under the financing agreements, for the project if Lake Road or La Paloma do not transfer the projects to their lenders or the lenders’ designees on or before June 9, 2003.
In accordance with the provisions of SFAS No. 144, the long-lived assets of the Lake Road and La Paloma project subsidiaries at December 31, 2002, were tested for impairment. As a result of the test, assets were determined to be impaired and were written down to fair value. Based on the current estimated fair value of these assets, the Lake Road and La Paloma project subsidiaries recorded a pretax loss from impairment of approximately $186 million for Lake Road and $266 million for La Paloma, in the fourth quarter of 2002.
Impairment of Mantua Creek Project: The Mantua Creek project is a nominal 897 MW combined cycle merchant power plant located in the Township of West Deptford, New Jersey. Construction began in October 2001 and the project was 24 percent complete as of October 31, 2002. Due to liquidity concerns, PG&E NEG could no longer provide equity contributions to the project and efforts to sell the project were unsuccessful. Beginning in the fourth quarter of 2002, contracts with vendors were suspended or terminated to eliminate an increase in project costs. In December 2002, the project provided notices of termination to the Pennsylvania, New Jersey and Maryland Independent System Operator (PJM) and other significant counterparties. With all significant contracts terminated, PG&E NEG’s subsidiary will abandon this project in early 2003. PG&E NEG’s subsidiary has written off the capitalized development and construction costs of $257 million at December 31, 2002. In addition, PG&E NEG has recorded an accrual of $22 million for charges and associated termination costs at December 31, 2002.
Impairment of Turbines and Other Related Equipment: To support PG&E NEG’s electric generating development program, a subsidiary of PG&E NEG had contractual commitments and options to purchase a significant number of combustion turbines and related equipment. A subsidiary of PG&E NEG’s commitment to purchase combustion turbines and related equipment exceeded the new planned development activities. In the second quarter of 2002, PG&E NEG recognized a pretax charge of $246 million. The charge consisted of the impairment of the previously capitalized costs associated with prior payments made under the terms of the turbine and equipment contracts in the amount of $188 million and an accrual of $58 million for future termination payments required under the turbine and related equipment contracts. In addition, at that time, PG&E NEG retained capitalized prepayment costs associated with three development projects that were to be further developed or sold. Along with the impairment of these development projects in the fourth quarter of 2002, PG&E NEG has incurred an additional pretax charge of $30 million associated with the write-off of prior prepayments.
In November 2002, subsidiaries of PG&E NEG reached agreement with General Electric Company (GEC) to terminate its master turbine purchase agreement and with General Electric International, Inc. (GEII) to terminate its master long-term service agreement. GEC and GEII were paid a portion of the termination fees and reduced the remaining termination fees to approximately $22 million and deferred payment of the reduced fees to December 31, 2004. The costs to terminate this contract were accrued for in the second quarter of 2002.
Also in November 2002, Mitsubishi Power Systems, Inc. (MPS) notified PG&E NEG’s subsidiary that it was terminating its turbine purchase agreement for failure to pay past due amounts and failure to collateralize PG&E NEG’s guarantee. While PG&E NEG’s subsidiary has disputed that such amounts were due before January and July 2003 and has asserted that a breach under PG&E NEG’s guarantee did not give rise to a breach of the turbine purchase agreement, neither PG&E NEG nor its subsidiary intends to contest the termination. The costs to terminate this contract were accrued in the second quarter of 2002. On January 31, 2003, a termination payment of $4.5 million was made, with the remaining amount of $9.5 million expected to be paid in July 2003.
Termination of Interest Rate Swaps on Lake Road, La Paloma and GenHoldings: As a result of the Lake Road and La Paloma subsidiaries’ failure to make required equity payments under the interest rate hedge contracts entered into by them, the counterparties to such interest rate hedge contracts have terminated the contracts. Settlement amounts due from the Lake Road and La Paloma project subsidiaries in connection with such terminated contracts are, in the aggregate, $61 million for Lake Road and $78 million for La Paloma. These amounts have been rolled into the debt existing prior to December 11, 2002 and have, therefore been likewise accelerated.
As a result of GenHoldings’ failure to make required payments under the interest rate hedge contracts entered into by GenHoldings, the counterparties to such interest rate hedge contracts terminated the contracts during December 2002. Settlement amounts due by GenHoldings in connection with such terminated contracts are, in the aggregate, approximately $50 million. The Lake Road and LaPaloma project subsidiaries and GenHoldings incurred a pretax charge to earnings in the fourth quarter of 2002 for settlement amounts connected with terminated interest rate hedge contracts totaling $189 million.
Impairment of Dispersed Generation: PG&E NEG is seeking a buyer for PG&E Dispersed Generation, LLC, Plains End, LLC, Dispersed Properties, LLC and 100 percent of the capital stock of Ramco, Inc. (collectively referred to as Dispersed Gen Companies or Dispersed Generation). In accordance with the provisions of SFAS No. 144, the long-lived assets of the Dispersed Gen Companies have been accounted for as an asset held for use at December 31, 2002. In accordance with SFAS No. 144, the Dispersed Gen Companies were tested for impairment. As a result of the test, these assets were determined to be impaired and were written-down to fair value. Based on the current estimated fair value (based on the estimated proceeds) of a sale, Dispersed Generation recorded a pretax loss from impairment of $88 million in the fourth quarter of 2002. This is in addition to a pretax loss from impairment of $30 million that was recorded in the third quarter of 2002, which related to certain equipment (turbines, generators, transformers, etc.) that was purchased and or refurbished and held for future expansion at current Dispersed Generation facilities.
Impairment of Goodwill: SFAS No. 142, “Goodwill and Other Intangible Assets,” requires that goodwill be reviewed at least annually for impairment. Due to significant adverse changes within the national energy markets, PG&E NEG tested its goodwill for possible impairment in the third quarter of 2002. Based upon the results of the fair value test, PG&E NEG and its subsidiaries recognized a goodwill impairment loss of $95 million in the third quarter of 2002. The fair value of the segment was estimated using the discounted cash flows method. At December 31, 2002, there is no goodwill remaining at PG&E NEG and its subsidiaries.
Impairment of Development Costs: In the second quarter of 2002, PG&E NEG recognized an impairment loss related to the capitalized costs associated with certain development projects. PG&E NEG analyzed the potential future cash flow from those projects that it no longer anticipated developing and recognized an impairment of the asset carrying value for those projects. The aggregate pre-tax impairment charge recorded by PG&E NEG for its development assets (excluding associated equipment) was $19 million recorded in the second quarter of 2002. At that time, PG&E NEG continued to develop or planned to sell three additional projects. PG&E NEG has now ceased developing these projects and sought to sell the development assets. To date, PG&E NEG has been unsuccessful in selling these projects. PG&E NEG tested the capitalized costs associated with the projects for impairment at December 31, 2002. Based on the results of these tests, an additional aggregate pre-tax impairment charge of approximately $57 million was recorded by PG&E NEG for its development assets (excluding associated equipment costs as discussed above) in the fourth quarter of 2002. While PG&E NEG has impaired all of its development projects, it has not abandoned the permits or rights to these projects. It is anticipated that PG&E NEG will abandon all development projects, permits and rights in 2003.
Impairment of Southaven Loan Receivable: PG&E ET signed a tolling agreement with Southaven Power, LLC (Southaven) dated June 1, 2000, pursuant to which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing an investment-grade guarantee from PG&E NEG. The original maximum amount of the guarantee was $250 million. However, this amount was reduced by approximately $74 million, the amount of a subordinated loan that PG&E ET made to Southaven on August 31, 2002.
Southaven has advised PG&E ET that it believes an event of default under the tolling agreement has taken place with respect to the obligation for a guarantee because PG&E NEG is no longer investment-grade as defined in the agreement and because PG&E ET has failed to provide within thirty days from the downgrade substitute credit support that meets the requirements of the agreement. Under the tolling agreement, Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Southaven with a notice of default respecting Southaven’s performance under the tolling agreement. If this default is not cured, PG&E ET has the right to terminate the tolling agreement and seek recovery of a termination payment. On February 4, 2003, PG&E ET provided a notice of termination. Southaven has objected to the notice and has filed suit in connection with this matter. PG&E ET has recorded an impairment of the loan receivable due to the uncertainty associated with the recoverability of the loan which was subordinate to the senior debt of the project and reliant upon operations of the plant under the terms of the tolling agreement.
Impairment of Prepaid Rents on Attala Lease: On May 7, 2002, Attala Generating Company, LLC (Attala Generating), an indirect wholly owned subsidiary of PG&E NEG, completed a $340 million sale and leaseback transaction whereby it sold and leased back its approximately 526 MW generation facility located in Mississippi to a third-party special purpose entity. PG&E NEG has provided a $300 million guarantee to support the payment obligations of another indirect wholly owned subsidiary, Attala Energy Company, LLC (Attala Energy), under a tolling agreement entered into with Attala Generating. The payments under the 25-year term tolling agreement provide Attala Generating, as lessee, with sufficient cash flows during the term of the tolling agreement to pay rent under a 37-year lease and certain other operating costs. Due to current energy market conditions, Attala Energy is unable to make the payments under the tolling agreement and failed to make the required payment due on November 27, 2002 to Attala Generating. Failure to cure this payment default constituted an event of default under the tolling agreement. Further, PG&E NEG’s failure to pay maturing principal under its Corporate Revolver on November 14, 2002 became an event of default under the tolling agreement upon Attala Energy’s failure to replace the PG&E NEG guarantee by December 16, 2002. On December 31, 2002, the tolling agreement was terminated following notice of termination given by Attala Generating. The parties are currently determining the termination payment, if any, that Attala Energy would owe Attala Generating. Despite the termination of the tolling agreement, Attala Energy remains obligated to provide an acceptable guarantee or collateral to secure its obligations under the tolling agreement including the payment of any termination payment that may be determined to be due.
No default has occurred under the related lease and Attala Generating timely made the $22 million lease payment due on January 2, 2003. However, the lease provides that failure to replace the tolling agreement with a satisfactory replacement tolling agreement within 180 days after the first default under the tolling agreement, which occurred on November 27, 2002, will constitute an event of default under the lease. After the termination payment has been determined in accordance with the tolling agreement and if Attala Energy or PG&E NEG both fail to provide security as required by the tolling agreement, the time period would not extend beyond the 60th day after such failure to provide security. Upon the occurrence of an event of default under the lease, the lessor would be entitled to exercise various remedies, including termination of the lease and foreclosure of the assets securing the lease. At December 31, 2002, PG&E NEG wrote-off prepaid rental payments of $43 million due to the uncertainty of future cash flows associated with the lease.
Impairment of Kentucky Hydro: The Kentucky Hydro generating project consists of two run-of-river hydroelectric power plants (Smithland Hydroelectric and Cannelton Hydroelectric) on the Ohio River. A PG&E NEG subsidiary owned interests in the project companies owning the hydroelectric facilities. The project owners negotiated a turnkey, fixed price contract with VA Tech MCE Corporation (VA Tech) and issued a limited notice to proceed in August 2001. Beginning in the fourth quarter of 2002, all work on the project was suspended except for minimal expenditures to maintain the FERC licenses and the construction contracts were terminated. The termination cost due to VA Tech of approximately $14 million was fully paid. As a part of the settlement of its partnership arrangements, PG&E NEG assigned its interest in the project companies to the original developer, DJL Corporation for Smithland Hydroelectric and W.V. Hydro for Cannelton Hydroelectric, on February 7, 2003. PG&E NEG has abandoned its partnership interest as of such date. PG&E NEG has impaired the capitalized development and construction costs and provided for all termination costs by recording a pretax charge of $18 million at December 31, 2002.
Assets Held for Sale - USGen New England: Consistent with its previously announced strategy to dispose of certain merchant assets, in December 2002, the Board of Directors of PG&E Corporation approved management’s plans for the proposed sale of USGen New England, Inc. (USGenNE). Under the provisions of SFAS No. 144, the equity of USGenNE has been accounted for as an asset held for sale at December 31, 2002. This requires that the asset be recorded at the lower of fair value, less costs to sell, or book value. Based on the current estimated fair value (based on the estimated proceeds) of a sale of USGenNE, PG&E NEG recorded a pretax loss of $1.1 billion with no tax benefits associated with the loss, in the fourth quarter of 2002.
It is anticipated that the sale of the USGenNE assets will occur during 2003. This loss on sale as well as the operating results from USGenNE is being reported as discontinued operations in the Financial Statements of PG&E NEG at December 31, 2002.
Assets Held for Sale - ET Canada: In December 2002, the proposed sale of PG&E Energy Trading, Canada Corporation (ET Canada) to Seminole Gas Company Limited was approved. Based upon the sales price, PG&E Energy Trading Holdings Corporation, the direct owner of the shares of ET Canada, recorded a $25 million pre-tax loss, with no tax benefits associated with the loss, on the disposition of ET Canada. The transaction is anticipated to close in early March 2003. In accordance with the provisions of SFAS No. 144, the equity of ET Canada has been classified as assets held for sale and will be reflected as discontinued operations in the financial statements of PG&E NEG and subsidiaries as of December 31, 2002.
COMMITMENTS AND CONTINGENCIES
Firm Commitments
PG&E NEG’s subsidiaries have entered into various long-term firm commitments. PG&E NEG’s subsidiaries are negotiating with the lenders, debtholders and other counterparties in an attempt to restructure these commitments. The ability of PG&E NEG’s subsidiaries to fund these commitments depends on the terms of any restructuring plan that may be agreed to by appropriate parties. The following table identifies by year the aggregate amounts of these commitments (millions):
Fuel Supply and Transportation Agreements - PG&E NEG’s subsidiaries have entered into gas supply and firm transportation agreements with a number of pipelines and transporters to provide fuel transportation services. Under these agreements, PG&E NEG’s subsidiaries must make specified minimum payments each month.
Power Purchase Agreements - USGen New England assumed rights and duties under several power purchase contracts with third party independent power producers as part of the acquisition of the New England Electric System assets. As of December 31, 2002, these agreements provided for an aggregate of approximately 800 MW of capacity. USGen New England is required to pay New England Power Company amounts due to third-party producers under the power purchase contracts.
Operating Leases - Various subsidiaries of PG&E NEG entered into several operating lease agreements for generating facilities and office space. Lease terms vary between 3 and 48 years.
In November 1998, USGen New England entered into a $479 million sale-leaseback transaction whereby the subsidiary sold and leased back a pumped storage station under an operating lease.
On May 7, 2002, Attala Generating Company, LLC, an indirect subsidiary of PG&E NEG, completed a $340 million sale and leaseback transaction whereby it sold and leased back its facility to a third party special purpose entity. The related lease is being accounted for as an operating lease. See Note 6, “Impairments, Write-Offs and Other Charges”, for further discussion relating to the Attala lease agreement.
Operating lease expense amounted to $78 million, $54 million, and $70 million in 2002, 2001, and 2000, respectively.
Long Term Service Agreements - Various subsidiaries of PG&E NEG have entered into long-term service agreements for the maintenance and repair of certain of its combustion turbine or combined-cycle generating plants. These agreements are for periods up to 18 years.
Payments in Lieu of Property Taxes - Various subsidiaries of PG&E NEG have entered into certain agreements with local governments that provide for payments in lieu of property taxes for some of its generating facilities.
Construction Commitments - Various subsidiaries of PG&E NEG currently have projects (Athens, Covert, La Paloma, and Harquahala) under construction. PG&E NEG’s construction commitments are generally related to the major construction agreements including the construction and other related contracts. Certain construction contracts also contain commitments for turbines and related equipment.
Tolling Agreements - PG&E ET entered into tolling agreements with several counterparties allowing it the right to sell electricity generated by facilities owned and operated by other parties. Under the tolling agreements, PG&E ET, at its discretion, supplies the fuel to the power plants, then sells the plant’s output in the competitive market. Committed payments are reduced if the plant facilities do not achieve agreed-upon levels of performance. See Guarantees - Tolling Agreements below for additional information relating to these agreements.
GUARANTEES
PG&E NEG’s and its subsidiaries’ guarantees fall into four broad categories:
•
equity commitments;
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PG&E ET’s energy trading and non-trading activities related to PG&E NEG’s merchant energy portfolio, excluding tolling agreements;
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tolling agreements; and
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other guarantees.
PG&E NEG is currently in default under various debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. On November 14, 2002, PG&E NEG defaulted on the repayment of its $431 million 364-day tranche of its Corporate Revolver. This resulted in a default under the two-year tranche of the Corporate Revolver which had an outstanding balance of $273 million, the majority of which supports outstanding letters of credit. The default under the Corporate Revolver also constitutes a cross-default under (1) PG&E NEG’s Senior Notes ($1 billion outstanding), (2) its guarantee of the turbine revolver ($205 million outstanding), and (3) its equity commitment guarantees for the GenHoldings I, LLC credit facility ($355 million outstanding), for the La Paloma credit facility ($375 million outstanding) and for the Lake Road credit facility ($230 million outstanding). In addition, on November 15, 2002, PG&E NEG failed to pay a $52 million interest payment due under the Senior Notes. PG&E NEG does not currently have sufficient cash to meet its financial obligations and has ceased making payments on its debt and equity commitments.
Equity Commitments Refer to discussion above on impairments under “Market Conditions and Business Environment.”
Activities Related to Merchant Portfolio Operations
PG&E NEG and certain subsidiaries have provided guarantees as of January 31, 2003, to approximately 232 counterparties in support of PG&E ET’s energy trading and non-trading activities related to PG&E NEG’s merchant energy portfolio in the face amount of $2.7 billion. Typically, the overall exposure under these guarantees is only a fraction of the face value of these guarantees, since not all counterparty credit limits are fully used at any time. As of January 31, 2003, PG&E NEG and its subsidiaries’ aggregate exposure under these guarantees was approximately $83 million. The amount of such exposure varies daily depending on changes in market prices and net changes in position. In light of the downgrades, some counterparties have sought and others may seek replacement security to collateralize the exposure guaranteed by PG&E NEG and its subsidiaries. PG&E GTN and PG&E ET have terminated the arrangements pursuant to which PG&E GTN provided guarantees on behalf of PG&E ET such that PG&E GTN will provide no new guarantees on behalf of PG&E ET.
At January 31, 2003, PG&E ET’s estimated exposure not covered by a guarantee (excluding exposure under tolling agreements) is approximately $90 million.
To date, PG&E ET has met those replacement security requirements properly demanded by counterparties and has not defaulted under any of its master trading agreements although one counterparty has alleged a default. No demands have been made upon the guarantors of PG&E ET’s obligations under these trading agreements. In the past, PG&E ET has been able to negotiate acceptable arrangements and reduce its overall exposure to counterparties when PG&E ET or its counterparties have faced similar situations. There can be no assurance that PG&E ET can continue to negotiate acceptable arrangements in the current circumstances. PG&E NEG cannot quantify with any certainty the actual future calls on PG&E ET’s liquidity. PG&E NEG’s and its subsidiaries’ ability to meet these calls on their liquidity will vary with market price volatility, uncertainty with respect to PG&E NEG’s financial condition and the degree of liquidity in the energy markets. The actual calls for collateral will depend largely upon the ability to enter into forbearance agreements and pre- and early-pay arrangements with counterparties, the continued performance of PG&E NEG companies under the underlying agreements, whether counterparties have the right to demand such collateral, the execution of master netting agreements and offsetting transactions, changes in the amount of exposure, and the counterparties’ other commercial considerations.
Tolling Agreements
PG&E ET has entered into tolling agreements with several counterparties under which at its discretion, it supplies the fuel to the power plants and then sells the plant’s output in the competitive market. Payments to the counterparties are reduced if the plants do not achieve agreed-upon levels of performance. The face amount of PG&E NEG’s and its subsidiaries’ guarantees relating to PG&E ET’s tolling agreements is approximately $600 million. The tolling agreements currently in place are with: (1) Liberty Electric Power, L.P. (Liberty) guaranteed primarily by PG&E NEG and secondarily by PG&E GTN for an aggregate amount of up to $150 million; (2) DTE-Georgetown, LLC (DTE) guaranteed by PG&E GTN for up to $24 million; (3) Calpine Energy Services, L.P. (Calpine) for which no guarantee is in place; (4) Southaven Power, LLC (Southaven) guaranteed by PG&E NEG for up to $175 million; and (5) Caledonia Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million.
Liberty - Liberty has provided notice to PG&E ET that the ratings downgrade of PG&E NEG constituted a material adverse change under the tolling agreement requiring PG&E ET to replace the guarantee and post security in the amount of $150 million. PG&E ET has not posted such security. Liberty has the right to terminate the agreement and seek recovery of a termination payment. Under the terms of the guarantees to Liberty for the aggregate $150 million, Liberty must first proceed against PG&E NEG’s guarantee, and can demand payment under PG&E GTN’s guarantee only if (1) PG&E NEG is in bankruptcy or (2) Liberty has made a payment demand on PG&E NEG which remains unpaid five business days after the payment demand is made. In addition, PG&E ET has provided notices to Liberty of several breaches of the tolling agreement by Liberty and has advised Liberty that, unless cured, these breaches would constitute a default under the agreement. If these defaults remain uncured, PG&E ET has the right to terminate the agreement and seek recovery of a termination payment.
DTE Georgetown - By letter dated October 14, 2002, DTE provided notice to PG&E ET that the downgrade of PG&E GTN constituted a material adverse change under the tolling agreement between PG&E ET and DTE and that PG&E ET was required to post replacement security within ten days. By letter dated October 23, 2002, PG&E ET advised DTE that because there had not been a material adverse change with respect to PG&E GTN within the meaning of the tolling agreement, PG&E ET was not required to post replacement security. If PG&E ET was required to post replacement security and it failed to do so, DTE would have the right to terminate the tolling agreement and seek recovery of a termination payment.
Calpine- The tolling agreement states that on or before October 15, 2002, Calpine was to have issued a full notice to proceed under its construction contract to its engineering, procurement and construction contractor for the Otay Mesa facility. On October 16, 2002 PG&E ET asked Calpine to confirm that it had issued this full notice to proceed and Calpine was not able to do so to the satisfaction of PG&E ET. Consequently, PG&E ET advised Calpine by letter dated October 30, 2002 that it was terminating the tolling agreement effective November 29, 2002. Calpine has indicated that this termination was improper and constituted a default under the agreement, but has not taken any further action.
Southaven and Caledonia Tolling Agreements. PG&E ET signed a tolling agreement with Southaven dated as of June 1, 2000, under which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing an investment-grade guarantee from PG&E NEG as defined in the agreement. The amount of the guarantee now does not exceed $175 million. By letter dated August 31, 2002, Southaven advised PG&E ET that it believed an event of default under the tolling agreement had taken place as PG&E NEG was no longer investment-grade as defined in the tolling agreement and because PG&E ET had failed to provide within thirty days from the downgrade substitute credit support that met the requirements of the agreement. Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Southaven with a notice of default respecting Southaven’s performance under the agreement, concerning the inability of the facility to inject its output into the local grid. Southaven has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.
In addition, PG&E ET signed a tolling agreement with Caledonia dated as of September 20, 2000, under which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade as defined in the agreement. The amount of the guarantee does not exceed $250 million. By letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an event of default under the tolling agreement had taken place with respect to this obligation as PG&E NEG was no longer investment-grade as defined in the tolling agreement and as PG&E ET had failed to provide within thirty days from the downgrade substitute credit support that met the requirement of the agreement. Caledonia has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Caledonia with a notice of default respecting Caledonia’s performance under the agreement, concerning the inability of the facility to inject its output into the local grid. Caledonia has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.
On February 7, 2003, Southaven and Caledonia filed an emergency petition to compel arbitration or, in the alternative, for a temporary restraining order and preliminary injunction with the Circuit Court for Montgomery County, Maryland. The Court has denied the relief requested and has set the matter for hearing on March 3, 2003. Following oral argument, the judge ruled, subject to entry of a written order, that PG&E ET was required to continue to perform under the agreements.
PG&E ET is not able to predict whether the counter parties will seek to terminate the agreements or whether the Court will grant the requested relief. Accordingly, it is not able to predict whether or the extent to which, these proceedings will have a material adverse effect on PG&E NEG’s financial condition or results of operation.
Under each tolling agreement determination of the termination payment is based on a formula that takes into account a number of factors including market conditions such as the price of power and the price of fuel. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. The dispute resolution process could take as long as six months to more than a year to complete. To the extent that PG&E ET did not pay these damages, the counterparties could seek payment under the guarantees for an aggregate amount not to exceed $600 million. PG&E NEG is unable to predict whether counterparties will seek to terminate their tolling agreements. PG&E NEG does not currently expect to be able to pay any termination payments that may become due.
Other Guarantees
PG&E NEG has provided guarantees related to other obligations by PG&E NEG companies to counterparties for goods or services. PG&E NEG does not believe that it has significant exposure under these guarantees. The most significant of these guarantees relate to performance under certain construction contracts. In the event PG&E NEG is unable to provide any additional or replacement security which may be required as a result of rating downgrades, the counterparty providing the goods or services could suspend performance or terminate the underlying agreement and seek recovery of damages. These guarantees represent guarantees of subsidiary obligations for transactions entered into in the ordinary course of business. Some of the guarantees relate to the construction or development of PG&E NEG’s power plants and pipelines. These guarantees are described below.
PG&E NEG has issued guarantees to construction financing lenders for the performance of the contractors building the Harquahala and Covert power projects for up to $555 million. Any exposure under the guarantees for construction completion is mitigated by guarantees in favor of PG&E NEG from the constructor and equipment vendors related to performance, schedule and cost. The constructor and various equipment vendors are currently performing under their underlying contracts. On August 8, 2002, PG&E NEG replaced the rating triggers contained in these guarantees with financial covenants that are consistent with those contained in PG&E NEG’s Corporate Revolver.
PG&E NEG has issued $100 million of guarantees to the constructor of the Harquahala and Covert projects to cover certain separate cost-sharing arrangements. Failure to perform under those separate cost-sharing arrangements or the related guarantees would not have an impact on the constructor’s obligations to complete the Harquahala and Covert projects pursuant to the construction contracts. However, in the event that the construction contractor incurs certain unreimbursed project costs or cost overruns, the contractor could assert a claim against PG&E NEG’s subsidiary or PG&E NEG under its guarantees. PG&E NEG believes that no claim can be validly asserted by the construction contractor as of the date of this Report.
PG&E NEG has provided a $300 million guarantee to support a tolling agreement that a wholly owned subsidiary, Attala Energy, has entered into with Attala Generating. See discussion above under “Impairment of Prepaid Rents on Attala Lease” for additional discussion of this guarantee.
The balance of the guarantees are for commitments undertaken by PG&E NEG or its subsidiaries in the ordinary course of business for services such as facility and equipment leases, ash disposal rights, and surety bonds.
PG&E NEG has the following credit facilities outstanding at January 31, 2003 (in millions):
(a)
PG&E NEG is currently in default on both its Tranche A and Tranche B credit facility.
STATEMENT OF CASH FLOWS FOR 2002, 2001 and 2000
The cash from operations for the years 2002, 2001 and 2000 will not be indicative of the future cash flow from operations due to the changes in the operations of PG&E NEG (discussed above). To the extent that the commitments of PG&E NEG and its subsidiaries can be restructured, future cash from operations will be principally generated by the PG&E NEG pipeline business as well as dividends from PG&E NEG independent power producer project companies which are principally accounted for under the equity method of accounting. If the commitments are not restructured, PG&E NEG will not generate sufficient funds to meet its outstanding cash requirements and may file or be forced into bankruptcy.
In addition to the impacts of PG&E NEG’s downgrades, PG&E NEG’s and its subsidiaries’ ability to service these obligations is impacted by constraints on the ability to move cash from one subsidiary to another or to PG&E NEG itself. PG&E National Energy Group, LLC, a wholly owned subsidiary of PG&E Corporation, owns 100 percent of the stock of PG&E NEG. GTN Holdings LLC owns 100 percent of the stock of PG&E GTN, and PG&E Energy Trading Holdings, LLC owns 100 percent of the stock of PG&E ET. The organizational documents of PG&E NEG and these limited liability companies require unanimous approval of their respective boards of directors, including at least one independent director, before they can (a) consolidate or merge with any entity, (b) transfer substantially all of their assets to any entity, or (c) institute or consent to bankruptcy, insolvency or similar proceedings or actions. The limited liability companies may not declare or pay dividends unless the respective boards of directors unanimously approve such action and PG&E NEG meets specified financial requirements.
PG&E NEG’s subsidiaries must now independently determine, in light of each company’s financial situation, whether any proposed dividend, distribution or intercompany loan is permitted and is in such subsidiary’s interest. Therefore, consolidated statements of cash flow and consolidated balance sheets quantifying PG&E NEG’s cash and cash equivalents do not reflect the cash actually available to PG&E NEG or any particular subsidiary to meet its obligations.
At January 31, 2003, PG&E NEG and its subsidiaries had the following unrestricted cash and short-term investment balances (not including in-transit items) (in millions):
PG&E Corporation Credit Agreement
On October 18, 2002, PG&E Corporation entered into a Second Amended and Restated Credit Agreement with certain lenders (the “PG&E Credit Agreement”). All obligations of PG&E Corporation under the PG&E Credit Agreement are secured by, among other things, a perfected first priority security interest in 100 percent of the equity interests in PG&E NEG LLC and 100 percent of the common stock of PG&E NEG, and all proceeds thereof.
The PG&E Credit Agreement generally does not limit the ability of PG&E NEG, or its subsidiaries to grant liens or incur debt. The PG&E Credit Agreement generally permits PG&E NEG and its subsidiaries to enter into certain sales and other dispositions of assets in the ordinary course of business and in certain qualified transactions. In addition, in connection with certain sales and restructuring transactions of PG&E NEG and its subsidiaries, PG&E Corporation is permitted to use tax benefits generated at the PG&E Corporation level by such transactions to make investments in PG&E NEG provided that no default or event of default has occurred and is continuing under the PG&E Credit Agreement and neither PG&E NEG, LLC nor PG&E NEG are in bankruptcy. The amount of such investment is limited to 75 percent of the net cash tax savings (less certain costs and expenses) actually received by PG&E Corporation after October 1, 2002. PG&E Corporation is also permitted to make investments in PG&E NEG and its subsidiaries (including, without limitation, incurring obligations for which PG&E Corporation becomes a surety or a guarantor of PG&E NEG and its subsidiaries) up to a cumulative amount not to exceed $15 million, provided that no default or event of default has occurred and is continuing under the PG&E Credit Agreement and provided further that PG&E NEG LLC and PG&E NEG are not in bankruptcy. The proceeds of the new loans obtained under the PG&E Credit Agreement may not be used to make investments in PG&E NEG LLC or PG&E NEG, or any of its subsidiaries.
Operating Activities
Results from PG&E NEG’s consolidated cash flows from operating activities for the twelve months ended 2002, 2001, and 2000 are as follows on a summarized basis (in millions):
During 2002, PG&E NEG used net cash from operating activities of $218 million. Net cash from operating activities before changes in operating assets and liabilities and price risk management assets and liabilities was $116 million in 2002, created principally from results of operations offset by the timing of deferred tax benefits and lower distributions from unconsolidated affiliates. Change in price risk management assets and liabilities increased cash flow by $99 million due to realization of cash from price risk management activities. The change in inventories, prepaid expenses, deposits, and other liabilities decreased cash flow by $471 million primarily due to increased credit collateral deposit requirements in PG&E NEG’s trading operations. Adding to these cash outflows were $62 million of increased restricted cash requirements.
During 2001, PG&E NEG generated net cash from operating activities of $386 million. Net cash from operating activities before changes in operating assets and liabilities and price risk management assets and liabilities was $133 million in 2001, created principally from results of operations offset by the timing of deferred tax benefits and lower distributions from unconsolidated affiliates. Change in price risk management assets and liabilities increased cash flow by $130 million due to realization of cash from price risk management activities. PG&E NEG’s net cash inflow related to the change in accounts
receivable, accounts payable and accrued liabilities from operations was $42 million. The change in inventories, prepaid expenses, deposits, and other liabilities increased cash flow by $143 million primarily due to repayments of margin deposits in PG&E NEG’s trading operations. Offsetting these cash inflows were $62 million of increased restricted cash requirements in several of PG&E NEG’s projects in construction.
During 2000, PG&E NEG generated net cash from operating activities of $164 million. Net cash from operating activities before changes in operating assets and liabilities and price risk management assets and liabilities was $271 million in 2000, created principally from the timing of deferred tax benefits and higher distributions from unconsolidated affiliates. Change in price risk management assets and liabilities decreased cash flow by $21 million. PG&E NEG’s net cash inflow related to the change in accounts receivables, accounts payable and accrued liabilities increased cash flow by $65 million. The change in inventories, prepaid expenses, deposits, and other liabilities decreased cash flow by $154 million principally due to increased margin deposits in PG&E NEG’s trading operations.
Investing Activities
The cash outflows from investing activities for the years 2002, 2001 and 2000 will not be indicative of the future cash outflow from investing activities due to the changes in the operations of PG&E NEG (discussed above). Future cash outflows from investing operations will be principally related to maintenance of capital expenditures in the pipeline business.
Results from PG&E NEG’s consolidated cash flows from investing activities for the twelve months ended 2002, 2001, and 2000 are as follows (in millions):
Total capital expenditures detailed by business segment and expenditure amount associated with construction work in progress for the twelve months ended 2002, 2001, and 2000 are as follows (in millions):
During 2002, PG&E NEG used net cash of $1,040 million in investing activities compared to $1,534 million for the same period in 2001, or a decrease of $494 million. The decrease in cash used in investing activities from period to period were primarily due to proceeds from the Attala Generating Company sale leaseback transaction providing $340 million, proceeds of $46 million from the partial sale of PG&E NEG’s interest in Hermiston and the repayment of a $75 million loan to PG&E Corporation from PG&E GTN. Offsetting these proceeds were capital expenditures of $1,485 million in 2002 versus $1,426 million in 2001. These capital expenditures were used primarily for construction work in progress and were financed by non-recourse debt. Due to PG&E NEG’s default on making equity commitments, these construction projects are likely to be transferred
to lenders in 2003. Advanced development and turbine prepayments were $144 million less in 2002 versus 2001 due to the reductions and cancellations in new construction efforts. All remaining development assets and related turbine and other equipment contracts will be abandoned and terminated during 2003. As a result of investment downgrades, PG&E ET replaced a $74 million letter of credit issued to Southaven with cash pursuant to a subordinated loan agreement. No such activity occurred in 2001.
Included in investing activities for 2002 and 2001, are cash flows of $136 million and $81 million, respectively, related to the long-term receivable from New England Power Company associated with the assumption of power purchase agreements. These cash flows offset cash payments made to New England Power Company which are reflected in operating activities. PG&E NEG intends to seek to sell USGen New England in 2003.
During 2001, PG&E NEG used net cash of $1.5 billion for investing activities which were primarily attributable to capital expenditures associated with generating projects in construction, its purchase of the Mountain View wind project, and prepayments on turbines and related equipment.
During 2000, PG&E NEG used net cash of $864 million for investing activities. The primary cash outflows from investing activities were for capital expenditures associated with generating projects in construction, the acquisition of Attala, and prepayments on turbines and related equipment. These outflows were partially offset by the receipt of $442 million in proceeds from sales of assets and equity investments. Included in Investing Activities is a cash flow of $75 million related to the long-term receivable from New England Power Company associated with the assumption of power purchase agreements. These cash flows offset cash payments made to New England Power Company which are reflected in operating activities.
Financing Activities
Results from PG&E NEG’s consolidated cash flows from financing activities for the twelve months ended 2002, 2001, and 2000 are as follows (in millions):
During 2002, PG&E NEG provided net cash flows from financing activities of $962 million. PG&E NEG’s cash inflows from financing activities were primarily attributable to increases in long-term debt issued relating to increased borrowings under PG&E NEG’s continuing construction facilities.
During 2001, net cash provided by financing activities was $1.1 billion, principally from the net proceeds related to the issuance of the Senior Unsecured Notes due 2011.
During 2000, net cash provided by financing activities was $1.2 billion. Net cash provided by financing activities resulted primarily from non-recourse project debt of $711 million, and capital contributions by PG&E Corporation of $608 million, principally offset by distributions to PG&E Corporation of $106 million.
RESULTS OF OPERATIONS
The following table shows for the years ended December 31, 2002, 2001 and 2000, certain items from the accompanying Consolidated Statements of Operations detailed by reportable segments of PG&E NEG. (In the “Total” column, the table shows the combined results of operations for those items). The information for PG&E NEG (the “Total” column) includes the appropriate intercompany eliminations. The table below should be read in conjunction with Item 6: Selected Financial Data.
Results of operations by segment are discussed following this table (in millions):
(1)
Operating revenues and operating expenses reflect the adoption during 2002 of a new accounting policy implementing a change from gross to net method of reporting revenues and expenses on trading activities. The amounts for trading activities for the comparative periods in 2001 and 2000 have been reclassified to conform with the new net presentation.
(2)
All inter-segment transactions are eliminated.
PG&E NEG has experienced significant impacts to its results of operations from various acquisitions, disposals, and more recently from its efforts to raise cash and reduce indebtedness through sale, transfer or abandonment of assets.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Overall Results - PG&E NEG’s net loss (after discontinued operations and cumulative effect of a change in accounting principle) was $3.4 billion for the year ended 2002, a decrease of $3.6 billion from the year ended 2001.
The year ended 2002 included an expected loss on the disposal of USGenNE of $1.1 billion and ET Canada of $25 million. Additionally, the earnings from operations of USGenNE, Mountain View and ET Canada were reclassified to discontinued operations. USGenNE, Mountain View and ET Canada were determined to be assets held for sale per SFAS No. 144. As such, their operating results were reclassified as part of discontinued operations and an evaluation of the value on an asset-by-asset basis conducted. PG&E NEG determined that USGenNE’s and ET Canada’s book values exceeded their anticipated selling prices and, as such, recorded losses. Earnings from operations included in discontinued operations were $11 million or a decrease of $96 million principally due to USGenNE’s unfavorable operating results and market conditions in New England.
The year ended 2002 included a net loss for the cumulative effect of a change in accounting principle of $61 million. The cumulative effect was based on PG&E NEG’s adoption as of April 1, 2002, interpretations issued by the Derivatives Implementation Group (DIG), DIG C15 and DIG C16, reflecting the mark-to-market value of certain contracts that had previously been accounted for under the accrual basis as normal purchases and sales.
PG&E NEG’s income from continuing operations (after tax) was a loss of $2.2 billion in 2002 or a decrease of $2.3 billion from the prior year. The decline in pre-tax operating income was mainly due to impairments, write-offs and other charges previously discussed and taken during 2002 of $2.8 billion.
The following highlights the principal changes in operating revenues and operating expenses.
Operating Revenues - PG&E NEG’s operating revenues were $2.1 billion for the year ended 2002, an increase of $155 million from the year ended 2001. These revenue increases occurred primarily in PG&E NEG’s Integrated Energy and Marketing Activities segment principally due to new generation plants coming on line within the wholesale energy business. The principal drivers in the increase in PG&E NEG’s Interstate Pipeline segments operating revenues, which increased $7 million, were principally due to the North Baja’s pipeline system commencing operations and PG&E GTN pipeline system contract termination settlements. These operating revenue increases in the Interstate Pipeline segment were slightly offset by weak pricing fundamentals on gas transportation to the California and Pacific Northwest gas markets compared to the same period last year.
Operating Expenses - PG&E NEG’s operating expenses were $4.8 billion for the year ended 2002, an increase of $3.0 billion from the same period in the prior year. These increases occurred primarily in PG&E NEG’s Integrated Energy and Marketing segment, principally due to impairments, write-offs and other charges previously discussed of $2.8 billion. The cost of commodity sales and fuel increased $197 million in line with the increases in operating revenues, compressed spark spreads and new generation plants coming on line within the wholesale energy business. Operations, maintenance and management costs increased $33 million in 2002 as compared to the same period last year primarily due to new plants coming on line. In addition, depreciation and amortization costs increased $15 million in the period also mainly due to new plants coming on line. Administrative and general costs increased in 2002 as compared to the same period last year due to one-time charges associated with the PG&E NEG’s cost reduction and restructuring programs. These increases were slightly offset on a year-to-date basis by lower costs in the first half of 2002 associated with lower employee related expense.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Overall Results - PG&E NEG’s net income (after discontinued operations and cumulative effect of a change in accounting principle) was $171 million for the year ended 2001, an increase of $19 million from the year ended 2000.
The year ended 2001 included earnings from discontinued operations related to USGenNE, Mountain View and ET Canada of $107 million or an increase of $8 million from 2000. In addition, the year ended 2000 included a loss from discontinued operations of $40 million related to losses on the disposal of PG&E Energy Services.
The year ended 2001 included a net gain for the cumulative effect of a change in accounting principle of $9 million. The cumulative effect was based on an interpretation issued by the DIG C11that clarified how certain commodity contracts should be treated. In applying this new DIG guidance, PG&E NEG determined that one of its derivative contracts no longer qualified for normal purchases and sales treatment and must be marked-to-market through earnings.
PG&E NEG’s income from continuing operations (after tax) was $55 million in 2001 or a decrease of $38 million from the prior year. The decline in pre-tax operating income of $97 million in 2001 was primarily due to the sale of GTT in December 2000 which provided operating income of $77 million in 2000, and a one-time charge in the fourth quarter of 2000 of $60 million related to the termination of certain contracts resulting from the Enron bankruptcy (principally related to PG&E NEG’s energy trading business). These declines were partially offset by the sale of a development project in the third quarter of 2001, which provided operating income of $23 million, and general improvement in operating margins in the integrated energy and marketing segment. Net interest expense was $33 million lower in 2001 as compared to the prior year, principally due to increased capitalization of interest for projects under construction.
The following highlights the principal changes in operating revenues and operating expenses.
Operating Revenues - PG&E NEG’s operating revenues were $1.9 billion in 2001, a decrease of $1.4 billion from 2000. This decline in operating revenues occurred within both PG&E NEG’s Energy and Pipeline segments. The decline in PG&E NEG’s Integrated Energy and Marketing Activities segment of $563 million is mainly due to lower trade volumes and lower realized prices achieved primarily in the third and fourth quarter of 2001. These declines generally were due to higher commodity prices in the wake of the California energy crisis in the second half of 2000 and the decline in economic activity in the U.S. in the second half of 2001. The decline in PG&E NEG’s Interstate Pipeline segment of $866 million is primarily due to the sale of GTT in December 2000.
Operating Expenses - PG&E NEG’s operating expenses were $1.8 billion in 2001, a decrease of $1.3 billion from 2000. This decline in operating expenses occurred within both PG&E NEG’s Energy and Pipeline segments. The decline in PG&E NEG’s Integrated Energy and Marketing Activities segment of $492 million is mainly due to lower trade volumes and lower realized prices achieved primarily in the third and fourth quarter of 2001. These declines generally were due to higher commodity prices in the wake of the California energy crisis in the second half of 2000 and the decline in economic activity in the U.S. in the second half of 2001. The decline in PG&E NEG’s Interstate Pipeline segment of $792 million is primarily due to the sale of GTT in December 2000.
RISK MANAGEMENT ACTIVITIES
PG&E NEG is exposed to various risks associated with its operations, the marketplace, contractual obligations, financing arrangements and other aspects of its business. PG&E NEG actively manages these risks through risk management programs. These programs are designed to support business objectives, minimize costs, discourage unauthorized risk, and reduce the volatility of earnings and manage cash flows. At PG&E NEG risk management activities often include the use of energy and financial derivative instruments and other instruments and agreements.
These derivatives include forward contracts, futures, swaps, options, and other contracts.
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A forward contract is a commitment to purchase or sell a fixed amount of a commodity at a specified future date at a specified price;
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A futures contract is a standardized commitment, traded on an organized exchange, to purchase or sell a fixed amount of a commodity at a specified future date at a specified price;
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A swap contract is an agreement between two counterparties to exchange cash flows in the future based on changes in the underlying commodity or index; and
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An option contract provides the right, but not the obligation, to buy or sell the underlying asset at a predetermined price in the future.
PG&E NEG uses derivatives for both non-trading and trading (i.e., speculative) purposes. PG&E NEG may use energy and financial derivatives and other instruments and agreements to mitigate the risks associated with an asset (e.g., the natural position embedded in asset ownership and regulatory arrangements), liability, committed transaction, or probable forecasted transaction. Additionally, PG&E NEG may engage in trading activities for purposes of generating profit, gathering market intelligence, creating liquidity, and maintaining a market presence. These instruments are used in accordance with approved
risk management policies adopted by a senior officer-level risk oversight committee. Derivative activity is permitted only after the risk oversight committee approves appropriate risk limits for such activity. The organizational unit proposing the activity must successfully demonstrate that there is a business need for such activity and that the market risks will be adequately measured, monitored, and controlled.
The activities affecting the estimated fair value of trading activities and the non-trading activities balance, included in net price risk management assets and liabilities, are presented below (in millions).
The changes in fair values attributable to changes in valuation techniques and assumptions, as reported in the table above, are composed of a $14 million loss related to PG&E NEG’s implementation of a new methodology for estimating forward prices in illiquid periods, for which price information is not readily available, and a $2 million gain related to changes in assumptions used to value transportation contracts. The change in forward prices is described more fully in Note 1 of the Notes to the Consolidated Financial Statements.
PG&E NEG estimates the gross mark-to-market value of its non-trading and trading contracts at December 31, 2002, using the midpoint of quoted bid and ask prices, where available. When market data is not available, PG&E NEG uses its forward price curve methodology described in Note 1 to the Consolidated Financial Statements.
The gross mark-to-market valuation is then adjusted for the time value of money, creditworthiness of contractual counterparties, market liquidity in future periods, and other adjustments necessary to determine fair value. Most of PG&E NEG’s risk management models are reviewed by or purchased from third-party experts in specific derivative applications.
The following table shows the fair value of PG&E NEG’s trading contracts grouped by maturity at December 31, 2002 (in millions).
(1)
Excludes all non-trading contracts, including non-trading contracts that receive mark-to-market accounting treatment.
(2)
Actively quoted markets are exchanged traded quotes.
(3)
In many cases, these prices are an input into option models that calculate a gross mark-to-market value from which fair value is derived.
The amounts disclosed above are not indicative of likely future cash flows. The future value of trading contracts may be impacted by changes in underlying valuations, new transactions, market liquidity, and PG&E NEG risk management portfolio needs and strategies.
Market Risk
Market risk is the risk that changes in market conditions will adversely affect earnings or cash flow.
PG&E NEG categorizes its market risks as price risk, interest rate risk, foreign currency risk, and credit risk. These market risks may impact PG&E NEG and its subsidiaries’ assets and trading portfolios. Immediately below is an overview of PG&E NEG’s market risks followed by detailed descriptions of the market risks and explanations as to how each of these risks are managed.
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Price risk results from exposure to the impacts of market fluctuations in price and transportation costs of commodities such as electricity, natural gas, other fuels, and other energy-related products;
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Interest rate risk primarily results from exposure to the volatility of interest rates as a result of financing or refinancing through the issuance of variable-rate and fixed-rate debt;
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Foreign currency risk results from exposure to volatilities in currency rates; and
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Credit risk results from exposure to counterparties who may fail to perform under their contractual obligations.
Price Risk
Price risk is the risk that changes in primarily commodity market prices will adversely affect earnings and cash flows.
PG&E NEG is exposed to price risk from its portfolio of proprietary trading contracts and its portfolio of electric generation assets and supply contracts that serve wholesale and industrial customers, and various merchant plants currently in development and construction.
As described above, PG&E NEG is in the process of reducing and unwinding its trading positions. Additionally, asset hedge positions associated with the merchant plants will either remain with the assets or be terminated. PG&E NEG has significantly reduced its energy trading operations in an ongoing effort to raise cash and reduce debt. PG&E NEG’s objective is to limit its asset trading and risk management activities to only what is necessary for energy management services to facilitate the transition of PG&E NEG’s merchant generation facilities through their sale, transfer, or abandonment process. PG&E NEG will then further reduce and transition to only retain limited capabilities to ensure fuel procurement and power logistics for PG&E NEG’s retained independent power plant operations.
Value-at-Risk
PG&E NEG measures price risk exposure using value-at-risk and other methodologies that simulate future price movements in the energy markets to estimate the probability of future potential losses. Price risk is quantified using what is referred to as the variance-covariance technique of measuring value-at-risk, which provides a consistent measure of risk across diverse energy markets and products. This methodology requires the selection of a number of important assumptions, including a confidence level for losses, price volatility, market liquidity, and a specified holding period. This technique uses historical price movements data and specific, defined mathematical parameters to estimate the characteristics of and the relationships between components of assets and liabilities held for price risk management activities. PG&E NEG therefore uses the historical data for calculating the expected price volatility of its portfolio’s contractual positions to project the likelihood that the prices of those positions will move together.
The value-at-risk model includes all of PG&E NEG’s commodity derivatives and other financial instruments over the entire length of the terms of the transactions in the trading and non-trading portfolios. PG&E NEG’s value-at-risk calculation is a dollar amount reflecting the maximum potential one-day loss in the fair value of their portfolios due to adverse market movements over a defined time horizon within a specified confidence level. This calculation is based on a 95 percent confidence level, which means that there is a 5 percent probability that PG&E NEG’s portfolios will incur a loss in value in one day at least as large as the reported value-at-risk. For example, if the value-at-risk is calculated at $5 million, there is a 95 percent probability that if prices moved against current positions, the reduction in the value of the portfolio resulting from such one-day price movements would not exceed $5 million. There would also be a 5 percent probability that a one-day price movement would be greater that $5 million.
The following table illustrates the potential one-day unfavorable impact for price risk as measured by the value-at-risk model, based on a one-day holding period. A two-year comparison of daily value-at-risk is included in order to provide context around the one-day amounts. The high and low valuations represent the highest and lowest of the values during 2002. The average valuation represents the average of the values during 2002.
(1)
Includes derivative power and fuels contracts that do not qualify under the SFAS No. 133 normal purchases and normal sales exception and do not qualify to be accounted for as cash flow hedges.
(2)
Includes only the risk related to the derivative instruments that serve as hedges and does not include the related underlying hedged item. Any gain or loss on these derivative commodity instruments would be substantially offset by a corresponding gain or loss on the hedged commodity positions, which are not included.
Value-at-risk has several limitations as a measure of portfolio risk, including, but not limited to, underestimation of the risk of a portfolio with significant options exposure, inadequate indication of the exposure of a portfolio to extreme price movements, and the inability to address the risk resulting from intra-day trading activities.
PG&E NEG’s value-at-risk levels have increased at December 31, 2002, as compared to levels at December 31, 2001, due to strong prices and increased market volatility across all commodities in 2002. It is expected that PG&E NEG’s value-at-risk levels will eventually peak and start to decrease because, as previously discussed, PG&E NEG is in the process of reducing and unwinding its trading positions. Additionally, asset hedge positions associated with the merchant plants will either remain with the assets or be terminated. See the discussion above in the MD&A’s Liquidity and Financial Resources section for further information regarding PG&E NEG’s current financial situation.
Interest Rate Risk
Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cash flows. Specific interest rate risks for PG&E NEG include the risk of increasing interest rates on working capital facilities and variable rate debt.
PG&E NEG may use the following interest rate instruments to manage its interest rate exposure: interest rate swaps, interest rate caps, floors, or collars, swaptions, or interest rate forward and futures contracts. Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2002, if interest rates change by 1 percent for all variable rate debt at PG&E NEG, the change would affect net income by approximately $1 million for PG&E NEG based on variable rate debt and hedging derivatives and other interest rate-sensitive instruments outstanding.
The table included above in the MD&A’s Commitments and Contingencies section provides the maturity of the carrying amounts and the related weighted average interest rates on PG&E NEG’s interest bearing securities, by expected maturity dates.
Foreign Currency Risk
Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies in relation to the U.S. dollar.
PG&E NEG is exposed to such risk associated with foreign currency exchange variations related to Canadian-denominated purchase and swap agreements. PG&E NEG is also exposed to foreign currency risk resulting from the need to translate Canadian-denominated financial statements of an affiliate into U.S. dollars for PG&E NEG’s Consolidated Financial Statements. PG&E NEG uses forwards, swaps, and options to hedge foreign currency exposure.
PG&E NEG uses sensitivity analysis to measure its exchange rate exposure to the Canadian dollar. Based on a sensitivity analysis at December 31, 2002, a 10 percent devaluation of the Canadian dollar would be immaterial to PG&E NEG’s Consolidated Financial Statements.
Credit Risk
Credit risk is the risk of loss that PG&E NEG would incur if counterparties failed to perform their contractual obligations (these obligations are reflected as: Accounts receivable - customers, net; notes receivable included in Other noncurrent assets - other; PRM assets; and Assets held for sale on the balance sheet). PG&E NEG conducts business primarily with customers or vendors, referred to as counterparties, in the energy industry. These counterparties include other investor-owned utilities, municipal utilities, energy trading companies, financial institutions, and oil and gas production companies located in the United States and Canada. This concentration of counterparties may impact PG&E NEG’s overall exposure to credit risk because their counterparties may be similarly affected by economic or regulatory changes or other changes in conditions.
PG&E NEG manages its credit risk in accordance with PG&E Corporation Risk Management Policy. This establishes processes for assigning credit limits to counterparties before entering into agreements with significant exposure to PG&E NEG. These processes include an evaluation of a potential counterparty’s financial condition, net worth, credit rating, and other credit criteria as deemed appropriate, and are performed at least annually.
Credit exposure is calculated daily and, in the event that exposure exceeds the established limits, PG&E NEG takes immediate action to reduce the exposure, or obtain additional collateral, or both. Further, PG&E NEG relies heavily on master agreements that require the counterparty to post security, referred to as credit collateral, in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.
PG&E NEG calculates gross credit exposure for each counterparty as the current mark-to-market value of the contract (that is, the amount that would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, prior to the application of the counterparty’s credit collateral.
In 2002, PG&E NEG’s credit risk has increased partially due to downgrades of some of the counterparties credit ratings to levels below investment grade. The downgrades increase PG&E NEG’s credit risk because any collateral provided by these counterparties in the form of corporate guarantees or eligible securities may be of lesser of no value. Therefore, in the event these counterparties failed to perform under their contracts, PG&E NEG may face a greater potential maximum loss amount. In contrast, PG&E NEG does not face any additional risk if counterparties’ credit collateral is in the form of cash or letters of credit, as this collateral is not affected by a credit rating downgrade.
For the year ended December 31, 2002, PG&E NEG recognized no losses due to contract defaults or bankruptcies of counterparties. However, in 2001, PG&E NEG terminated its contracts with a bankrupt company, which resulted in a pre-tax charge to earnings of $60 million related to trading and non-trading activities, after application of collateral held and accounts payable.
At December 31, 2002, PG&E NEG had no single counterparty that represented greater than 10 percent of PG&E NEG’s net credit exposure. At December 31, 2001, PG&E NEG had one below investment grade counterparty that represented 10 percent of PG&E NEG’s net credit exposure, with a net credit exposure amount of $85 million.
The schedule below summarizes PG&E NEG’s credit risk exposure to counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange provides for contract settlement on a daily basis) at December 31, 2002, and December 31, 2001 (in millions):
(1)
Gross credit exposure equals mark-to-market value (adjusted for applicable credit valuation adjustments), notes receivable, and net (payables) receivables where netting is allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value, liquidity, or model.
(2)
Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit).
At December 31, 2002, approximately $172 million, or 21 percent of PG&E NEG’s net credit exposure was to entities that had credit ratings below investment grade. At December 31, 2001, approximately $237 million, or 27 percent of PG&E NEG’s net credit exposure was to entities that had credit ratings below investment grade. Investment grade is determined using publicly available information, i.e. rated at least Baa3 by Moody’s and BBB- by S&P. If the counterparty provides a guarantee by a higher rated entity (e.g., its parent), the credit rating determination is based on the rating of its guarantor. At December 31, 2002, approximately $65 million, or 8 percent of PG&E NEG’s net credit exposure was with counterparties that were not rated. At December 31, 2001, none of PG&E NEG’s net credit exposure was with counterparties that were not rated. Most counterparties with no credit rating are governmental authorities which are not rated, but which PG&E NEG has assessed as equivalent to investment grade. Other counterparties with no credit rating are subject to an internal assessment of their credit quality and a credit rating designation.
PG&E NEG has regional concentrations of credit exposure to counterparties that conduct business primarily in the western United States and also to counterparties that conduct business primarily throughout North America.
CRITICAL ACCOUNTING POLICIES
The preparation of consolidated financial statements in accordance with accounting principles generally accepted in the United States involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Certain of these estimates and assumptions are considered to be Critical Accounting Policies, due to their complexity, subjectivity, and uncertainty, along with their relevance to the financial performance of PG&E NEG. Actual results may differ substantially from these estimates. These policies and their key characteristics are outlined below.
In 2001, PG&E NEG adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Hedging Activities” (collectively, SFAS No. 133), which required all derivative instruments to be recognized in the financial statements at their fair value. Prior to its rescission, PG&E NEG accounted for its energy trading activities in accordance with EITF No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10), and SFAS No. 133, which require certain energy trading contracts to be accounted for at fair values using mark-to-market accounting. See discussion of rescission of EITF 98-10 below.
Effective for the third quarter ended September 30, 2002, PG&E NEG adopted the net method of recognizing realized gains and losses on energy trading contracts. Under the net method, revenues and expenses are netted and trading gains (or losses) are reflected in revenues on the income statement, as opposed to reporting revenues and expenses under the previously used gross method.
PG&E NEG also has derivative commodity contracts for the physical delivery of purchase and sale quantities such as natural gas and electricity transacted in the normal course of business. These derivatives are exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and are not reflected on the balance sheet at fair value. See further discussion in Notes 1 and 11 of the Notes to the Consolidated Financial Statements.
PG&E NEG applies SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” to its regulated operations. Under SFAS No. 71, regulatory assets represent capitalized costs that would otherwise be charged to expense. These costs are later recovered through regulated rates. Regulatory liabilities are rate actions of a regulator that will later be credited to customers through the rate making process. Regulatory assets and liabilities are capitalized when it is probable that these items will be recovered or reflected in future rates. If it is determined that these items are no longer subject to recoverability under SFAS No. 71, then they will be written-off at that time. See Note 1 of the Notes to the Consolidated Financial Statements.
TAX MATTERS
PG&E NEG accounts for income taxes under the liability method. Deferred tax assets and liabilities are determined based on the differences between financial statement carrying amounts and the tax basis of assets and liabilities, using currently enacted tax rates. PG&E NEG is included in the consolidated tax return of PG&E Corporation. PG&E NEG computes its provision for income taxes on a separate company basis as if it filed its own consolidated or combined tax return separate from PG&E Corporation.
Certain states require that each entity doing business in that state file a separate tax return (the “Separate State Taxes”). Canadian subsidiaries are subject to Canadian Federal and Provincial Income Taxes based on their net income (the “Canadian Taxes”). PG&E NEG separately accounts for the tax consequences of Separate State Taxes and Canadian Taxes.
For certain of the years before 2001, PG&E Corporation made payments to PG&E NEG commensurate with the tax savings achieved through the incorporation of PG&E NEG’s losses and tax credits in PG&E Corporation’s consolidated federal tax return for those years. In tax year 2001, PG&E NEG paid to PG&E Corporation the amount of its federal tax liability. At December 31, 2002, PG&E NEG has reflected a tax liability for amounts owed to PG&E Corporation.
Certain creditors of PG&E NEG have asserted that the aforementioned payments gave rise to an implied tax sharing agreement between PG&E Corporation and PG&E NEG. PG&E Corporation disputes that assertion. On November 12, 2002, PG&E Corporation notified PG&E NEG that to the extent that such an implied tax sharing agreement existed and was not terminated previously, it was terminated effective immediately. On December 24, 2002, PG&E NEG sent a letter to PG&E Corporation reserving all rights against PG&E Corporation with respect to such tax sharing agreement, if such agreement does in fact exist.
Under the PG&E Credit Agreement, PG&E Corporation agreed among other things not to permit PG&E NEG or any of its subsidiaries to (1) sell or abandon any of their respective assets except in compliance with certain conditions or (2) restructure any of their respective obligations except in compliance with certain conditions. These prohibitions do not apply to a “Qualified Asset Sale,” a “Qualified Bankruptcy Sale,” a “Qualified Abandonment,” or a “Qualified Restructuring,” all as defined in the PG&E Credit Agreement. In general, these definitions permit transactions in which PG&E Corporation (1) is released from existing liabilities related to the assets that are the subject of the transaction, (2) incurs no new liabilities as a result of the transaction, and (3) receives payment at closing for any new liability incurred, including any tax liability that would be payable as a result of the transaction. The PG&E Credit Agreement also restricts (with limited exceptions) PG&E Corporation’s investment in PG&E NEG to an amount that is no more than 75 percent of the net cash tax savings received by PG&E Corporation after October 1, 2002, as a result of a “Qualified Bankruptcy Sale,” a “Qualified Abandonment,” or a “Qualified Restructuring” (as defined in the PG&E Credit Agreement).
PG&E NEG recorded deferred tax assets of $1,403 million resulting from impairments and write-offs during 2002. As a result of such impairments, PG&E NEG has a net deferred tax asset of $1,003 million at December 31, 2002 before valuation allowance. Due to uncertainty in realizing the tax benefits associated with these deferred tax assets, PG&E NEG established valuation allowances for the full amount of the net deferred tax assets. The valuation allowances were determined in accordance with the provisions of SFAS No. 109 “Accounting for Income Taxes.” In assessing the realizability of deferred tax assets, PG&E NEG considered whether it is more likely than not that some portion of all of the deferred tax assets would not be realized. PG&E NEG is currently in default under various debt agreements and guaranteed equity commitments. PG&E NEG and its lenders are in discussions regarding a restructuring of these commitments. At this time, it is uncertain whether PG&E NEG will be able to reach agreement with the lenders regarding restructuring of its financial commitments, or whether it will be forced into proceedings under the Bankruptcy Code.
The Internal Revenue Service (IRS) has completed its audit of PG&E Corporation’s 1997 and 1998 consolidated U.S. federal income tax returns and has assessed additional federal income taxes of $53 million (including interest) related to PG&E NEG. PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and is currently discussing those adjustments with the IRS’s Appeals Office.
The IRS is also auditing PG&E Corporation’s 1999 and 2000 consolidated U.S. federal income tax returns, but has not issued its final report. However, the IRS has proposed adjustments totalling $67 million (including interest) with respect to PG&E NEG. All of PG&E Corporation’s federal income tax returns before 1997 have been closed, including those portions attributable to PG&E NEG. In addition, the State of California’s Franchise Tax Board and certain other state tax authorities are currently auditing various state tax returns.
ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED
Consolidation of Variable Interest Entities - In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), which expands upon existing accounting guidance addressing when a company should include in its financial statements the assets, liabilities, and activities of another entity. FIN 46 notes that many of what are now referred to as “variable interest entities” have commonly been referred to as special-purpose entities or off-balance sheet structures. However, the Interpretation’s guidance is to be applied to not only these entities but to all entities found within a company. FIN 46 provides some general guidance as to the definition of a variable interest entity. PG&E NEG is currently evaluating all entities to determine if they meet the FIN 46 criteria as variable interest entities.
Until the issuance of FIN 46, one company generally included another entity in its consolidated financial statements only if it controlled the entity through voting interests. FIN 46 changes that by requiring a variable interest entity to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity’s activities or entitled to receive a majority of the entity’s residual returns, or both. A company that consolidates a variable interest entity is now referred to as the “primary beneficiary” of that entity.
FIN 46 requires disclosures of variable interest entities that the company is not required to consolidate but in which it has a significant variable interest.
The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. The consolidation requirements apply to variable interest entities created before January 31, 2003 in the first fiscal year or interim period beginning after June 15, 2003, so these requirements would be applicable to PG&E NEG in the third quarter 2003. Certain new and expanded disclosure requirements apply to all financial statements issued after January 31, 2003, regardless of when the variable interest entity was established. These disclosures are required if there is an assessment that it is reasonably possible that an enterprise will consolidate or disclose information about a variable interest equity when FIN 46 becomes effective. PG&E NEG is currently evaluating the impacts of Interpretation No. 46’s initial recognition, measurement, and disclosure provisions on its Consolidated Financial Statements.
Guarantor’s Accounting and Disclosure Requirements for Guarantees - In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). FIN 45 expands on the accounting guidance of SFAS No. 5, “Accounting for Contingencies,” SFAS No. 57, “Related Party Disclosures,” and SFAS No. 107, “Disclosures about Fair Value of Financial Instruments.” FIN 45 also incorporates, without change, the provisions of FASB Interpretation No. 34, “Disclosures of Indirect Guarantees of the Indebtedness of Others,” which it supersedes.
FIN 45 elaborates on the existing disclosure requirements for most guarantees. It clarifies that a guarantor’s required disclosures include the nature of the guarantee, the maximum potential undiscounted payments that could be required, the current carrying amount of the liability, if any, for the guarantor’s obligations (including the liability recognized under SFAS No. 5), and the nature of any recourse provisions or available collateral that would enable the guarantor to recover amounts paid under the guarantee.
FIN 45 also clarifies that at the time a company issues a guarantee, it must recognize an initial liability for the fair value, or market value, of the obligation it assumes under that guarantee, including its ongoing obligation to stand ready to perform over the term of the guarantee in the event that the specified triggering events or conditions occur. This information must also be disclosed in interim and annual financial statements.
FIN 45 does not prescribe a specific account for the guarantor’s offsetting entry when it recognized the liability at the inception of the guarantee that the offsetting entry would depend on the circumstances in which the guarantee was issued. There also is no prescribed approach included for subsequently measuring the guarantor’s recognized liability over the term of the related guarantee. It is noted that the liability would typically be reduced by a credit to earnings as the guarantor is released from risk under the guarantee.
The initial recognition and initial measurement provisions apply on a prospective basis to guarantees issued or modified after December 31, 2002. PG&E NEG is currently evaluating the impact of FIN 45’s initial recognition and measurement provisions on its Consolidated Financial Statements. The disclosure requirements for FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002, and have been incorporated into PG&E NEG’s December 31, 2002, disclosures of guarantees.
Rescission of EITF 98-10 - In October 2002, the Emerging Issues Task Force rescinded EITF 98-10. Energy trading contracts that are derivatives in accordance with SFAS No. 133 will continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked to market as trading activities under EITF 98-10 that do not meet the definition of a derivative will be recorded at cost with a one-time adjustment to be recorded as a cumulative effect of a change in accounting principle as of January 1, 2003. For PG&E NEG, the majority of trading contracts are derivative instruments as defined in SFAS No. 133. Therefore, the rescission of EITF 98-10 will have minimal impact, applying primarily to trading contracts for transportation and storage. Furthermore, the rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading purposes, which continue to be accounted for in accordance with SFAS No. 133.
The reporting requirements associated with the rescission of EITF 98-10 are to be applied prospectively for all EITF 98-10 energy trading contracts entered into after October 25, 2002. For all EITF 98-10 energy trading contracts in existence at or prior to October 25, 2002, the estimated impact of the first quarter 2003 cumulative effect of a change in accounting principle is a loss of $5 million, net of taxes, at December 31, 2002.
Accounting for Costs Associated with Exit or Disposal Activities - In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity” (EITF 94-3). PG&E NEG will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF 94-3, a liability for an exit cost was recognized at the date of the company’s commitment to an exit plan if certain other criteria were met. SFAS No. 146 also establishes that the liability initially should be measured and recorded at fair value. Accordingly, the prospective implementation of SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized.
Accounting for Asset Retirement Obligations - In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” PG&E NEG will adopt this Statement effective January 1, 2003. SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets. Under the Statement, the asset retirement obligation is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the related asset. Upon adoption, the cumulative effect of applying this Statement will be recognized as a change in accounting principle in the Consolidated Statements of Operations.
PG&E NEG estimates that it will recognize a liability in the range of $11 million to $21 million for asset retirement obligations on January 1, 2003. The cumulative effect of a change in accounting principle from unrecognized accretion and depreciation expense is estimated to be a loss in the range of $4 million to $6 million (pre-tax).
PENSION AND OTHER POST-RETIREMENT PLANS
Certain subsidiaries of PG&E NEG provide qualified and non-qualified non-contributory defined benefit pension plans for their employees, retirees, and non-employee directors. PG&E NEG and its subsidiaries also provide contributory defined benefit medical plans for certain retired employees and their eligible dependents, and noncontributory defined benefit life insurance plans for certain retired employees (referred to collectively as other benefits). Amounts that PG&E NEG recognizes as obligations to provide pension benefits under SFAS No. 87, “Employers’ Accounting for Pensions,” and other benefits under SFAS No. 106, “Employers Accounting for Postretirement Benefits other than Pensions” are based on certain actuarial assumptions. Actuarial assumptions used in determining pension obligations include the discount rate, the average rate of future compensation increases, and the expected return on plan assets. Actuarial assumptions used in determining other benefit obligations include the discount rate, the average rate of future compensation increases, the expected return on plan assets and the assumed health care cost trend rate. While PG&E NEG believes the assumptions used are appropriate, significant differences in actual experience, plan changes, or significant changes in assumptions may materially affect the pension obligation and future pension expense.
Pension and other benefit funds are held in external trust funds. Trust assets, including accumulated earnings, must be used exclusively for pension and other benefit payments. Consistent with the trusts’ investment policies, assets are invested in U.S. equities, non-U.S. equities, and fixed income securities. Investment securities are exposed to various risks, such as interest rate, credit, and overall market volatility risks. As a result of these risks, it is reasonably possible that the market value of investment securities could increase or decrease in the near term. Increases or decreases in market values could materially affect the current value of the trusts and, as a result, the future level of pension and other benefit expense.
Expected rates of return on plan assets were developed by determining protected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit trusts, resulting in a weighted average rate of return on plan assets. Fixed income returns were based on historic returns for the broad U.S. bond market. Equity returns were determined by applying a market risk premium of 3.5 percent to the U.S. bond market return. For the qualified pension plan, the assumed return of 8.1 percent compares to a ten-year actual return of 8.4 percent.
The rate used to discount pension and other post-retirement benefit plan liabilities was based on a yield curve developed from the Moody’s AA Corporate Bond Index at December 31, 2002. This yield curve has discount rates that vary based on the maturity of the obligations. The estimated future cash flows for the pension and other post-retirement obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate. The resulting rate was validated by comparison to the yield of a high-quality, non-callable corporate bond portfolio with cash flows corresponding to expected future benefit payments. For the PG&E GTN qualified pension plan, a 25 basis point decrease in the discount rate would increase the accumulated benefit obligation by approximately $1.5 million.
ENVIRONMENTAL AND LEGAL MATTERS
PG&E NEG is subject to laws and regulations established to both maintain and improve the quality of the environment. Where PG&E NEG properties contain hazardous substances, these laws and regulations require PG&E NEG to remove those substances or remedy effects on the environment. Also, in the normal course of business, PG&E NEG is named as a party in a number of claims and lawsuits. See Note 4 of the Notes of the Consolidated: Financial Statements for further discussion of environmental matters and significant pending legal matters.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information responding to Item 7A appears in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and under Note 11 to the Notes to the Consolidated Financial Statements
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2002, 2001, AND 2000
(in millions)
The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements
PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2002 AND 2001
(in millions)
PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2002 AND 2001
(in millions)
The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.
PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(in millions)
The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.
PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (DEFICIT)
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(in millions, except for shares)
The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001, AND 2000
NOTE 1: GENERAL
Organization and Basis of Presentation
PG&E National Energy Group, Inc. (PG&E NEG) was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to PG&E NEG. PG&E National Energy Group, LLC, a wholly owned subsidiary of PG&E Corporation, owns all the equity in PG&E NEG. PG&E NEG and its subsidiaries are principally located in the United States and Canada and are engaged in power generation, wholesale energy marketing and trading, risk management, and natural gas transmission. PG&E NEG’s principal subsidiaries include:
•
PG&E Generating Company, LLC and its subsidiaries, collectively referred to as PG&E Gen LLC;
•
PG&E Energy Trading Holdings Corporation and its subsidiaries, collectively referred to as PG&E Energy Trading or PG&E ET;
•
PG&E Gas Transmission Corporation and its subsidiaries, collectively referred to as PG&E GTC, which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries, including North Baja Pipeline, LLC (collectively referred to as PG&E GTN) .
In addition, PG&E NEG also included PG&E Gas Transmission, Texas Corporation and subsidiaries, and PG&E Gas Transmission Teco, Inc. and subsidiaries (collectively referred to as, GTT). GTT was sold in 2000. See Note 5 for a further discussion. PG&E NEG also included PG&E Energy Services Corporation (PG&E ES) which provided retail energy services, and was discontinued in 1999 and sold. See Note 5 for a further discussion of the PG&E ES disposal. PG&E NEG also has other less significant subsidiaries.
PG&E NEG’s Consolidated Financial Statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and repayment of liabilities in the ordinary course of business. However, as a result of current liquidity concerns and restructuring discussions with PG&E NEG’s lenders and the possibility of a bankruptcy filing, such realization of assets and liquidation of liabilities are subject to uncertainty.
As a result of the sustained downturn in the power industry, PG&E NEG and its affiliates have experienced a financial downturn which caused the major credit rating agencies to downgrade PG&E NEG’s and its affiliates’ credit ratings to below investment-grade. PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.5 billion, but this debt is non-recourse to PG&E NEG. PG&E NEG, its subsidiaries and their lenders are engaged in discussions to restructure PG&E NEG’s debt obligations and other commitments. PG&E NEG and its subsidiaries are continuing to review opportunities to abandon, sell, or transfer assets and have significantly reduced their energy trading operations in an ongoing effort to raise cash and reduce debt, whether through negotiation with lenders or otherwise. These asset transfers, sales, and abandonments have caused substantial charges to earnings in 2002 of approximately $3.9 billion and will cause additional charges to earnings in 2003. If the lenders exercise their default remedies or if the financial obligations and commitments are not restructured, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced involuntarily into proceedings under the Bankruptcy Code. Management is unable to predict the form a restructuring plan would take in proceedings under the Bankruptcy Code.
The Consolidated Financial Statements of PG&E NEG for the years ended December 31, 2002, 2001 and 2000, have been prepared on a basis that includes the historical financial position and results of operations of the subsidiaries that were wholly owned or majority-owned and controlled as of December 31, 2002. For those subsidiaries that were acquired or disposed of during the periods presented by PG&E NEG, or by PG&E Corporation before or after PG&E NEG’s formation, the results of operations are included from the date of acquisition. For those subsidiaries disposed of during the periods presented, the results of operations are included through the date of disposal.
The Consolidated Financial Statements of PG&E NEG include the accounts of PG&E NEG and its wholly owned and controlled subsidiaries. PG&E NEG has investments in various power generation and other energy projects which PG&E NEG does not control. The equity method of accounting is applied to these investments in affiliated entities, which include corporations, limited liability companies and partnerships. Under this method, PG&E NEG’s share of equity income or losses of these entities is reflected as equity in earnings of affiliates.
All significant intercompany accounts and transactions have been eliminated in consolidation. Investments in affiliates in which PG&E NEG has the ability to exercise significant influence but not control are accounted for using the equity method.
The consolidated statements of operations include all revenues and costs directly attributable to PG&E NEG, including costs for functions and services performed by centralized PG&E Corporation organizations and directly charged to PG&E NEG based on usage or other allocation factors. The Results of Operations in these Consolidated Financial Statements also include general corporate expenses allocated by PG&E Corporation to PG&E NEG based on assumptions that management believes are reasonable under the circumstances. However, these allocations may not necessarily be indicative of the costs and expenses that would have resulted if PG&E NEG had operated as a separate entity.
Adoption of New Accounting Policies
Consolidation of Variable Interest Entities - In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), which expands upon existing accounting guidance addressing when a company should include in its financial statements the assets, liabilities, and activities of another entity. FIN 46 notes that many of what are now referred to as “variable interest entities” have commonly been referred to as special-purpose entities or off-balance sheet structures. However, the Interpretation’s guidance is to be applied to not only these entities but to all entities found within a company. FIN 46 provides some general guidance as to the definition of a variable interest entity. PG&E NEG is currently evaluating all entities to determine if they meet the FIN 46 criteria as variable interest entities.
Until the issuance of FIN 46, one company generally included another entity in its Consolidated Financial Statements only if it controlled the entity through voting interests. FIN 46 changes that by requiring a variable interest entity to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity’s activities or entitled to receive a majority of the entity’s residual returns, or both. A company that consolidates a variable interest entity is now referred to as the “primary beneficiary” of that entity.
FIN 46 requires disclosures of variable interest entities that the company is not required to consolidate but in which it has a significant variable interest.
The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. The consolidation requirements apply to variable interest entities created before January 31, 2003, in the first fiscal year or interim period beginning after June 15, 2003, so these requirements would be applicable to PG&E NEG in the third quarter 2003. Certain new and expanded disclosure requirements apply to all financial statements issued after January 31, 2003, regardless of when the variable interest entity was established. These disclosures are required if there is an assessment that it is reasonably possible that an enterprise will consolidate or disclose information about a variable interest entity when FIN 46 becomes effective. PG&E NEG is currently evaluating the impacts of Fin 46’s initial recognition, measurement, and disclosure provisions on its Consolidated Financial Statements.
Guarantor’s Accounting and Disclosure Requirements for Guarantees - In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). FIN 45 expands on the accounting guidance of SFAS No. 5, “Accounting for Contingencies,” SFAS No. 57, “Related Party Disclosures,” and SFAS No. 107, “Disclosures about Fair Value of Financial Instruments.” FIN 45 also incorporates, without change, the provisions of FASB Interpretation No. 34, “Disclosures of Indirect Guarantees of the Indebtedness of Others,” which it supersedes.
FIN 45 elaborates on the existing disclosure requirements for most guarantees. It clarifies that a guarantor’s required disclosures include the nature of the guarantee, the maximum potential undiscounted payments that could be required, the current carrying amount of the liability, if any, for the guarantor’s obligations (including the liability recognized under SFAS No. 5), and the nature of any recourse provisions or available collateral that would enable the guarantor to recover amounts paid under the guarantee.
FIN 45 also clarifies that at the time a company issues a guarantee, it must recognize an initial liability for the fair value, or market value, of the obligation it assumes under that guarantee, including its ongoing obligation to stand ready to perform over the term of the guarantee in the event that the specified triggering events or conditions occur. This information must also be disclosed in interim and annual financial statements.
FIN 45 does not prescribe a specific account for the guarantor’s offsetting entry when it recognized the liability at the inception of the guarantee, noting that the offsetting entry would depend on the circumstances in which the guarantee was issued.
There also is no prescribed approach included for subsequently measuring the guarantor’s recognized liability over the term of the related guarantee. It is noted that the liability would typically be reduced by a credit to earnings as the guarantor is released from risk under the guarantee.
The initial recognition and initial measurement provisions apply on a prospective basis to guarantees issued or modified after December 31, 2002. PG&E NEG is currently evaluating the impact of FIN 45’s initial recognition and measurement provisions on its Consolidated Financial Statements. The disclosure requirements for FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002, and have been incorporated into PG&E NEG’s December 31, 2002, disclosures of guarantees in these footnotes.
Accounting for Stock-Based Compensation - Transition and Disclosures - On December 31, 2002, FASB issued the Statement of Financial Accounting Standard (SFAS) No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosures, an Amendment of FASB Statement No. 123.” This Statement provides alternative methods of transition for companies who voluntarily change to the fair value-based method of accounting for stock-based employee compensation in accordance with SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 148 does not permit the use of the original SFAS No. 123 prospective method of transition for changes to the fair value based method made in fiscal years beginning after December 15, 2003. The Statement also requires prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based compensation and the effect of the method used on reported results. This Statement is effective upon its issuance.
PG&E NEG continues to account for stock-based compensation using the intrinsic value method in accordance with the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” elected under SFAS No. 123, as amended. As a result, the adoption of this Statement did not have any impact on the Consolidated Financial Statements of PG&E NEG. Please refer to the Stock-Based Compensation section of this Note 1 for additional information.
Change from Gross to Net Method of Reporting Revenues and Expenses on Trading Activities - Effective for the quarter ended September 30, 2002, PG&E NEG changed its method of reporting realized gains and losses associated with energy trading contracts from the gross method of presentation to the net method. PG&E NEG believes that the net method provides a more accurate and consistent presentation of energy trading activities on the financial statements. Amounts to be presented under the net method include all gross margin elements related to energy trading activities, including both unrealized and realized trades and both physical and financial trades.
Before implementation of the net method, PG&E NEG already had reported unrealized gains and losses on trading activities on a net basis in operating revenues. However, PG&E NEG had reported realized gains and losses on a gross basis in operating income, as both operating revenues and costs of commodity sales and fuel. PG&E NEG is now reporting all gains and losses from trading activities, including amounts that are realized, on a net basis as operating revenues. This will provide greater consistency in reporting the results of all energy trading activities. All prior financial statements have been reclassified to conform to the net method.
Implementation of the net method has no net effect on gross margin, operating income, or net income. Accordingly, PG&E NEG continues to report realized income from non-trading activities on a gross basis in operating revenues and operating expenses. The schedule below summarizes the amounts impacted by the change in methodology on PG&E NEG’s Consolidated Statements of Operations for the years ended December 31, 2001 and 2000 (in millions).
Rescission of EITF 98-10 - In October 2002, the Emerging Issues Task Force (EITF) rescinded EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10). Energy trading contracts that are derivatives in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (collectively, SFAS No. 133) will continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked to market as trading activities under EITF 98-10 that do not meet the definition of a derivative will be recorded at cost, with a one-time adjustment to be recorded as a cumulative effect of a change in accounting principle as of January 1, 2003. For PG&E NEG, the majority of trading contracts are derivative instruments as defined in SFAS No. 133. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading purposes, which continue to be accounted for in accordance with SFAS No. 133.
The reporting requirements associated with the rescission of EITF 98-10 are to be applied prospectively for all EITF 98-10 energy trading contracts entered into after October 25, 2002. For all EITF 98-10 energy trading contracts in existence at or prior to October 25, 2002, the estimated impact of the first quarter 2003 cumulative effect of a change in accounting principle is a loss of $5 million, net of taxes at December 31, 2002.
Change in Estimate Due to Changes in Certain Fair Value Assumptions - PG&E NEG estimates the gross mark-to-market value of its trading contracts and certain non-trading contracts using forward curves. The forward curves used to calculate mark-to-market value have liquid periods (includes continuous maturities starting from the month for which broker quotes are available on a daily basis) and illiquid periods (includes those maturities for which broker quotes are not readily available). When market data is not available, PG&E NEG historically has utilized alternative pricing methodologies, including third-party pricing curves, the extrapolation of forward pricing curves using historically reported data, and interpolation between existing data points. The gross mark-to-market valuation is then adjusted for time value of money, creditworthiness of contractual counterparties, market liquidity in future periods, and other adjustments necessary to determine fair value. For trading activities, these models are used to estimate the fair value of long-term transactions, including certain tolling agreements. For non-trading activities, these models are used to estimate the fair value of certain derivative contracts accounted for as cash flow hedges or at fair value through earnings under SFAS No. 133.
Beginning in the third quarter of 2002, PG&E NEG implemented a new model for projecting forward power and gas prices during illiquid periods. This new process primarily impacts the estimation of power prices. The model estimates forward power prices in illiquid periods using the mid-point of the marginal cost curve (the lowest variable cost of generation available in a particular region) and the forecast curve (the price at which a generation unit will recover its capital costs and a return on investment). Assumptions about cost recovery are combined with assumptions about volatility and correlation in an option model to project forward power prices. Interpolation methods continue to be used for intermediate periods when broker quotes are intermittent. In addition to implementing the new process for projecting forward power prices in illiquid periods, PG&E NEG also enhanced its models to better incorporate certain physical characteristics of its power plants and to account for uncertainties surrounding projected forward prices, volumetric assumptions, and modeling complexity. PG&E NEG also refined its process for estimating the bid-ask spread in illiquid periods for purposes of liquidity adjustments.
All of these changes in fair values are being accounted for on a prospective basis as a change in accounting estimate. The change in fair values had a pre-tax income effect of a $14 million loss from trading activities and a pre-tax gain of $25 million from non-trading activities. These income effects, totaling a pre-tax gain of $11 million for both trading and non-trading activities, were recognized in the quarter ended September 30, 2002.
Accounting for Gains and Losses on Debt Extinguishment and Certain Lease Modifications - On July 1, 2002, PG&E NEG adopted SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” This Statement eliminates the current requirement that gains and losses on debt extinguishment be classified as extraordinary items. Instead, such gains and losses will generally be classified as interest expense. PG&E NEG will implement SFAS No. 145 prospectively; initial implementation had no impact on its financial position or results of operations.
In addition, SFAS No. 145 eliminates an inconsistency in lease accounting by requiring that modifications of capital leases that result in reclassification as operating leases be accounted for consistently with sale-leaseback accounting rules. This provision did not have any impact on the Consolidated Financial Statements of PG&E NEG at the date of adoption.
Changes to Accounting for Certain Derivative Contracts - On April 1, 2002, PG&E NEG implemented two interpretations issued by the FASB’s Derivatives Implementation Group (DIG). DIG Issues C15 and C16 changed the definition of normal
purchases and sales included in SFAS No. 133. Previously, certain derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business were exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and thus were not marked to market and reflected on the balance sheet like other derivatives. Instead, these contracts were recorded on an accrual basis.
DIG C15 changed the definition of normal purchases and sales for certain power contracts. DIG C16 disallowed normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. PG&E NEG determined that five of its derivative commodity contracts for the physical delivery of power and purchase of fuel no longer qualified for normal purchases and sales treatment under these interpretations. Beginning April 1, 2002, these five contracts were required to be recorded on the balance sheet at fair value and marked to market through earnings. Three of the contracts had positive market values and resulted in pre-tax income of $125 million. The remaining two contracts had negative market values that resulted in a pre-tax charge of $127 million. The cumulative effects of implementing these accounting changes at April 1, 2002, resulted in PG&E NEG recording price risk management assets of $37 million, price risk management liabilities of $255 million, and a reduction of out-of-market obligations of $129 million reclassified to net price risk management liabilities.
One of the contracts with a positive market value included above is a power sales contract at a partnership in which PG&E NEG has a 50 percent ownership interest. PG&E NEG reflects its investment in this partnership on an equity basis (Investments in Unconsolidated Affiliates). Upon adoption of DIG C15 and C16, PG&E NEG recognized its equity share of the gain from the cumulative change in accounting method and correspondingly increased the book value of its equity investment in the partnership. However, the future net cash flows from the partnership do not support the increased equity investment balance.
Therefore, PG&E NEG has recognized an impairment charge of $101 million to reduce its equity-method investment to fair value. The cumulative effect of the change in accounting principle for DIG C15 and C16 was a net charge of $61 million, after-tax, and included the recognition of the fair market value of the five contracts impacted by DIG C15 and C16 and the impairment charge for the equity method investment.
Implementation of these accounting changes will not impact the timing and amount of cash flows associated with the affected contracts; however, it will impact the timing and magnitude of future earnings. Future earnings will reflect the gradual reversal of the assets and liabilities recorded upon adoption over the contracts’ lives, as well as any prospective changes in the market value of the contracts. Prospective changes in the market value of these contracts could result in significant volatility in earnings. However, over the total lives of the contracts, there will be no net impact to total operating results after netting the cumulative effect of adoption against the subsequent years’ impacts (assuming that the affected contracts are held to their expiration).
Accounting for the Impairment or Disposal of Long-Lived Assets - On January 1, 2002, PG&E NEG adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144). SFAS No. 144 supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of,” but retains its fundamental provision for recognizing and measuring impairment of long-lived assets to be held and used. This Statement requires that all long-lived assets to be disposed of by sale be carried at the lower of carrying amount or fair value less cost to sell, and that depreciation ceases to be recorded on such assets. SFAS No. 144 standardizes the accounting and presentation requirements for all long-lived assets to be disposed of by sale, and supersedes previous guidance for discontinued operations of business segments. The initial adoption of this Statement at January 1, 2002 did not have any impact on the Consolidated Financial Statements of PG&E NEG. During 2002, PG&E NEG recorded certain impairment charges in accordance with SFAS No. 144, (see Note 5, “Discontinued Operations and Assets Held for Sale” and Note 6, “Impairments, Write-offs and Other Charges”).
Accounting for Goodwill and Other Intangible Assets - On January 1, 2002, PG&E NEG adopted SFAS No. 142, “Goodwill and Other Intangible Assets.” This Statement eliminates the amortization of goodwill and requires that goodwill be reviewed at least annually for impairment. Upon implementation of this Statement, the transition impairment test for goodwill was performed as of January 1, 2002, and no impairment loss was recorded. Goodwill amortization expense was $5 million in 2001 and 2000. During 2002, PG&E NEG recorded a charge for impairment of goodwill in accordance with SFAS No. 142, (see Note 6, “Impairments, Write-offs and Other Charges”).
This Statement also requires that the useful lives of previously recognized intangible assets be reassessed and the remaining amortization periods be adjusted accordingly. Adoption of this Statement did not require any adjustments to be made to the useful lives of existing intangible assets and no reclassifications of intangible assets to goodwill were necessary.
Intangible assets other than goodwill are being amortized on a straight-line basis over their estimated useful lives and are reported under noncurrent assets in the Consolidated Balance Sheets.
The schedule below summarizes the amount of intangible assets by major classes (in millions):
PG&E NEG’s amortization expense on intangible assets was $7 million in 2002, $3 million in 2001 and $4 million in 2000.
The following schedule shows the estimated amortization expenses for intangible assets for full years 2003 through 2007 (in millions).
Accounting for Asset Retirement Obligations - In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” PG&E NEG will adopt this Statement effective January 1, 2003. SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets. Under the Statement, the asset retirement obligation is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the related asset. Upon adoption, the cumulative effect of applying this Statement will be recognized as a change in accounting principle in the Consolidated Statements of Operations. However, rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with this Statement and costs recovered through the ratemaking process. Regulatory assets and liabilities may be recorded when it is probable that the asset retirement costs will be recovered through the ratemaking process. PG&E GTN collects removal costs in rates, which are recorded through depreciation. PG&E GTN is in the process of calculating the amount of the regulatory liabilities recorded in accumulated depreciation and will disclose this amount upon adoption of the Statement.
PG&E NEG estimates that it will recognize a liability in the range of $11 million to $21 million for asset retirement obligations on January 1, 2003. The cumulative effect of a change in accounting principle from unrecognized accretion and depreciation expense is estimated to be a loss in the range of $4 million to $6 million (pre-tax). The impact to PG&E NEG of implementing SFAS No. 143 by its unconsolidated affiliates is expected to be immaterial.
Summary of Significant Accounting Policies
Use of Estimates - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets, liabilities and disclosure of contingencies at the date of the financial statements. Actual results could differ from these estimates.
Regulation - PG&E GTN’s rates and charges for its natural gas transportation business are regulated by the Federal Energy Regulatory Commission (FERC). The consolidated financial statements reflect the ratemaking policies of FERC in conformity with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”. This Statement allows PG&E GTN to record certain regulatory assets and liabilities that will be included in future rates and would not be recorded under generally accepted accounting principles for nonregulated entities in the United States.
PG&E NEG’s regulatory assets and liabilities consist of the following (in millions):
Regulatory assets and liabilities represent future probable increases or decreases, respectively, in revenue to be recorded by PG&E GTN associated with certain costs to be collected from or refunded to customers as a result of the ratemaking process. PG&E GTN’s regulatory assets are provided for in rates charged to customers and are being amortized over future periods in conjunction with the regulatory recovery period. PG&E GTN’s regulatory liabilities are the result of FERC approved mechanisms that provide for adjustment of future rates. Regulatory assets are included in other noncurrent assets on the consolidated balance sheets. PG&E GTN does not earn a return on regulatory assets on which it does not incur a carrying cost. Regulatory liabilities are included in other noncurrent liabilities on the Consolidated Balance Sheets.
Cash and Cash Equivalents - Invested cash and other investments with original maturities of three months or less, and money market funds which make such investments, are considered cash equivalents. Cash equivalents are stated at cost, which approximates fair value. PG&E NEG’s cash equivalents are held in a variety of high quality money market funds that mainly invest in:
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Certificates of deposit and time deposits,
Bankers’ acceptances, and other short-term securities issued by banks,
Asset-backed securities,
Repurchase agreements,
High-grade commercial paper, and
Discounted notes issued or guaranteed by the United States government or its agencies.
Restricted Cash - Restricted cash includes cash and cash equivalent amounts, as defined above, which are restricted under the terms of certain agreements for payment to third-parties, primarily for debt service.
Inventory - Inventory consists principally of materials and supplies, coal, natural gas, natural gas liquids, and fuel oil. Materials and supplies and natural gas are valued at lower of average cost or market. Gas storage inventory is valued at cost as discussed in Note 1, Rescission of EITF 98-10.
Property, Plant, and Equipment - Property, plant, and equipment is recorded at cost, which includes costs of purchased equipment, related labor and materials, and interest during construction. Property, plant, and equipment purchased as part of an acquisition is reflected at fair value on the acquisition date. These capitalized costs are depreciated on a straight-line basis over estimated useful lives, less any residual or salvage value. Routine maintenance and repairs are charged to expense as incurred. The estimated lives range from 2 through 50 years. Estimated useful lives are as follows:
Electric generating facilities
20 to 50 years
Gas transmission assets
15 to 40 years
Other
2 to 20 years
Interest is capitalized as a component of projects under construction and is amortized over the projects’ estimated useful lives. During 2002, 2001, and 2000, PG&E NEG capitalized interest of approximately $193 million, $119 million, and $48 million.
PG&E GTN utility plant also includes an allowance for funds used during construction (AFUDC), which is the estimated cost of debt and equity funds used to finance regulated plant additions. AFUDC rates, calculated in accordance with FERC authorizations, are based upon the last approved return on equity and an embedded rate for borrowed funds. The equity component of AFUDC is included in other income and the borrowed funds component is recorded as a reduction of interest expense. The costs of utility plant additions for PG&E GTN, including replacements of plant retired, are capitalized. The original cost of plant retired plus removal costs, less salvage, is charged to accumulated depreciation upon retirement of plant in service. No gain or loss is recognized upon normal retirement of utility plant.
Depreciation expense, including amortization expense under capital leases, was $98 million, $75 million, and $59 million for the years ended December 31, 2002, 2001, and 2000.
Refer to this note 1, Accounting for the Impairment or Disposal of Long-Lived Assets and Note 6 for discussion of impairments and the effect on the Property, Plant, and Equipment.
Project Development Costs - Project development costs represent amounts incurred for professional services, direct salaries, permits, options and other direct incremental costs related to the development of new property, plant and equipment, principally electric generating facilities and gas transmission pipelines. These costs are expensed as incurred until development reaches a stage when it is probable that the project will be completed. A project is considered probable of completion upon meeting one or more milestones, which may include a power sales contract, gas transmission contract, obtaining a viable project site, securing project construction or operating permits, among others. Project development costs that are incurred after a project is considered probable of completion but prior to starting physical construction are capitalized. Project development costs are included in construction in progress when physical construction begins. PG&E NEG periodically assesses project development costs for impairment. Project development costs are included in other noncurrent assets in the Consolidated Balance Sheets at December 31, 2001. During 2002, PG&E NEG fully impaired all remaining capitalized development costs. See Note 6: Impairments, Write-offs, and Other Charges for a further discussion of amounts impaired during 2002.
Credit collateral deposits - Credit collateral deposits consists principally of margin cash for future physical and financial exposures with counterparties. Margin deposits are subject to price fluctuations and will be refunded to PG&E NEG at the time which all obligations have been fulfilled.
Prepaid Expenses and Other - Prepaid expenses and other consist principally of early payments and pre-payments with counterparties for current month deliveries. Amounts will be credited to PG&E NEG at the time at which obligations are settled.
Intangible Assets -Intangible assets include the value assigned, based on the expected benefits to be received, to acquired management service agreements, operations and maintenance agreements, and power sales agreements (PSA). These intangible assets are being amortized on a straight-line basis over their estimated useful lives, ranging from 3 to 35 years.
Amortization expense related to intangible assets was $7 million, $3 million, and $4 million for the years ended December 31, 2002, 2001, and 2000, respectively. These amounts do not include amortization expense related to intangibles for certain PSA, which are recorded against the related revenue or expense.
Deferred financing costs - Deferred financing costs consist primarily of those costs incurred to obtain debt financing. These costs are deferred and amortized using the effective interest rate method or straight line over the term of the credit agreement. Amortization expense related to deferred financing costs for the years ended December 31, 2002, 2001, and 2000 was approximately $33 million, $8 million, and $4 million, respectively.
Capitalized Software Costs - PG&E NEG capitalizes costs incurred during the application development stage of internal use software projects to property, plant and equipment. Capitalized software costs totaled $46 million at December 31, 2002, and $44 million at December 31, 2001, net of accumulated amortization of $33 million at December 31, 2002, and $26 million at December 31, 2001. PG&E NEG amortizes the capitalized software cost over periods ranging from 3 to 7 years, in accordance with regulatory requirements ratably over the expected lives of the projects when they become operational.
Fair value of financial instruments - The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts. The fair values of financial instruments relating to cash and cash equivalents, restricted cash and deposits, net accounts receivable, debt in default, current portion of long-term debt and accounts payable approximate their carrying values as of December 31, 2002, and 2001.
Due to the illiquid nature and limited market demand for PG&E NEG’s long-term debt, the estimated fair market value is not able to be determined at December 31, 2002. At December 31, 2001, PG&E NEG’s long-term receivables and long-term debt had carrying values of $536 million and $3.4 billion, respectively, with estimated fair values of $467 million and $3.5 billion, respectively. The fair values of long-term debt were based upon quoted market prices. The carrying value for LIBOR-based debt approximates fair value.
Revenue Recognition - Revenues are recorded in accordance with the Securities and Exchange Commission (SEC’s) Staff Accounting Bulletin (SAB) No. 101, “Revenue Recognition,” as amended.
Energy commodities and services revenues derived from power generation are primarily recognized upon output, product delivery, or satisfaction of specific targets, all as specified by contractual terms. Regulated gas transmission revenues are recorded as services are provided, based on rate schedules approved by FERC.
In accordance with EITF 98-10, and SFAS No. 133, certain energy contracts, that are not designated as hedging instruments or as normal purchase and sale contracts, are recorded at fair value using mark-to-market accounting, which records a change in fair value as income (or a charge) on the income statement, and correspondingly adjusts the fair value of the instrument on the balance sheet. Effective January 1, 2003, all non-derivative energy trading contracts that were marked to market under EITF 98-10 will be accounted for using the cost method. Please refer to the Adoption of New Accounting Policies section of Note 1 of the Notes to the Consolidated Financial Statements for additional information.
Revenues from trading activities are reported on a net basis in operating revenues for both realized and unrealized gains and losses. Realized revenues and costs of sales from non-trading activities are reported on a gross basis as operating revenues and operating expenses, respectively.
Accounting for Price Risk Management Activities - PG&E NEG, primarily through its subsidiaries, engages in price risk management activities for both non-trading and trading purposes. Non-trading activities are conducted to optimize and secure the return on risk capital deployed within PG&E NEG’s existing asset and contractual portfolio.
PG&E NEG conducts trading activities principally through its unregulated lines of business. Trading activities are conducted to generate profit, create liquidity, and maintain a market presence. Net open positions often exist or are established due to PG&E NEG’s assessment of and response to changing market conditions. PG&E NEG is significantly reducing their energy trading operations.
Derivatives associated with both trading and non-trading activities include forward contracts, futures, swaps, options, and other contracts.
Derivative instruments associated with non-trading activities are accounted for at fair value in accordance with SFAS No. 133 and ongoing interpretations of the FASB’s DIG. Derivative and other financial instruments associated with trading activities in electric and other energy commodities are accounted for at fair value in accordance with SFAS No. 133 and EITF 98-10, subject to the transition requirements of the rescission of EITF 98-10 discussed above.
Both non-trading and trading derivatives are classified as price risk management assets and price risk management liabilities in the accompanying Consolidated Balance Sheets. Non-trading derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. For non-trading derivatives that are effective hedges, changes in the fair value are recognized in accumulated other comprehensive income (loss) until the hedged item is recognized in earnings. Derivatives associated with trading activities are adjusted to fair value through income, subject to the effects of the rescission of EITF 98-10 discussed above.
Net realized gains or losses on non-trading derivative instruments recognized for the year ended December 31, 2002, were included in various lines on the Consolidated Statements of Operations, including energy commodities and services revenue, cost of energy commodities and services, interest income or interest expense, and other income (expense), net. Changes in the market value of the trading contracts, resulting primarily from newly originated transactions and the impact of commodity prices or interest rate movements, are recognized in operating income in the period of change. On an unrealized basis and a realized basis, PG&E NEG now recognizes trading contracts on a net basis, as previously described in this Note.
As described more fully in this Note under Change in Estimate Due to Changes in Certain Fair Value Assumptions, for non-trading and trading contracts, models are used to estimate the fair value of derivatives and other contracts that are accounted for as derivative contracts. Gross mark-to-market value is estimated using the midpoint of quoted bid and ask prices for liquid periods and, for illiquid periods, using the mid-point of the marginal cost curve and the forecast curve. Interpolation methods are used for intermediate periods when broker quotes are intermittent. The gross mark-to-market valuation is then adjusted for time value of money, creditworthiness of contractual counterparties, market liquidity in future periods, and other adjustments necessary to determine fair value.
PG&E NEG engages in non-trading activities to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies. Before the implementation of SFAS No. 133, PG&E NEG accounted for hedging activities under the deferral method, whereby unrealized gains and losses on hedging transactions were deferred. When the underlying item settled, PG&E NEG recognized the gain or loss from the hedge instrument in operating income. In instances where the anticipated correlation of price movements did not occur, hedge accounting was terminated and future changes in the value of the derivative were recognized as gains or losses. If the hedged item was sold, the value of the associated derivative was recognized in income.
Effective January 1, 2001, PG&E NEG adopted SFAS No. 133 that requires that all derivatives, as defined, are recognized on the balance sheet at fair value. PG&E NEG’s transition adjustment to implement SFAS No. 133 on January 1, 2001, resulted in an immaterial decrease to earnings and an after-tax decrease of $333 million to accumulated other comprehensive income. These transition adjustments, which relate to hedges of interest rate, foreign currency, and commodity price risk exposure, were recognized as of January 1, 2001, as a cumulative effect of a change in accounting principle.
PG&E NEG also has derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business. These derivatives are exempt from the requirements of SFAS No. 133 under the normal purchase and sales exception, and are not reflected on the balance sheet at fair value. The FASB has approved two interpretations issued by the DIG that changed the definition of normal purchases and sales for certain power contracts. As previously described in this Note under “Changes to Accounting for Certain Derivative Contracts,” PG&E NEG implemented these interpretations on April 1, 2002.
To qualify for the normal purchases and sales exemption from SFAS No. 133, a contract must have pricing that is deemed to be clearly and closely related to the asset to be delivered under the contract. In 2001, the FASB approved another interpretation issued by the DIG that clarifies how this requirement applied to certain commodity contracts. In applying this new DIG guidance, PG&E NEG determined that one of its derivative commodity contracts no longer qualifies for normal purchase and sales treatment, and must be marked-to-market through earnings. The cumulative effect of this change in accounting principle increased earnings by approximately $9 million (after-tax).
Stock-Based Compensation - PG&E NEG accounts for stock-based compensation using the intrinsic value method in accordance with the provisions of Accounting Principles Board Opinion No. 25, as allowed by SFAS No. 123, as amended by SFAS No. 148. Under the intrinsic value method, PG&E NEG does not recognize any compensation expense, as the exercise price of all stock options is equal to the fair market value at the time the options are granted. Had compensation expense been recognized using the fair value-based method under SFAS No. 123, PG&E NEG’s pro forma consolidated earnings (loss) would have been as follows:
Income Taxes-PG&E NEG accounts for income taxes under the the liability method. Deferred tax assets and liabilities are determined based on the differences between financial statement carrying amounts and the tax basis of assets and liabilities, using currently enacted tax rates.
PG&E NEG is included in the consolidated tax return of PG&E Corporation. PG&E NEG computes its provision for income taxes on a separate company basis as if it filed its own consolidated or combined tax return separate from PG&E Corporation.
Certain states require that each entity doing business in that state file a separate tax return (the “Separate State Taxes”). Canadian subsidiaries are subject to Canadian Federal and Provincial Income Taxes based on their net income (the “Canadian Taxes”). PG&E NEG separately accounts for the tax consequences of Separate State Taxes and Canadian Taxes.
For certain of the years before 2001, PG&E Corporation made payments to PG&E NEG commensurate with the tax savings achieved through the incorporation of PG&E NEG’s losses and tax credits in PG&E Corporation’s consolidated federal tax return for those years. In tax year 2001, PG&E NEG paid to PG&E Corporation the amount of its federal tax liability. At December 31, 2002, PG&E NEG has reflected a tax liability for amounts owed to PG&E Corporation.
Certain creditors of PG&E NEG have asserted that the aforementioned payments gave rise to an implied tax sharing agreement between PG&E Corporation and PG&E NEG. PG&E Corporation disputes that assertion. On November 12, 2002, PG&E Corporation notified PG&E NEG that to the extent that such an implied tax sharing agreement existed and was not terminated previously, it was terminated effective immediately. On December 24, 2002, PG&E NEG sent a letter to PG&E Corporation reserving all rights against PG&E Corporation with respect to such tax sharing agreement, if such agreement does in fact exist.
Under the PG&E Credit Agreement, PG&E Corporation agreed among other things not to permit PG&E NEG or any of its subsidiaries to (1) sell or abandon any of their respective assets except in compliance with certain conditions or (2) restructure any of their respective obligations except in compliance with certain conditions. These prohibitions do not apply to a “Qualified Asset Sale,” a “Qualified Bankruptcy Sale,” a “Qualified Abandonment,” or a “Qualified Restructuring,” all as defined in the PG&E Credit Agreement. In general, these definitions permit transactions in which PG&E Corporation (1) is released from existing liabilities related to the assets that are the subject of the transaction, (2) incurs no new liabilities as a result of the transaction, and (3) receives payment at closing for any new liability incurred, including any tax liability that would be payable as a result of the transaction. The PG&E Credit Agreement also restricts (with limited exceptions) PG&E Corporation’s investment in PG&E NEG to an amount that is no more than 75 percent of the net cash tax savings received by PG&E Corporation after October 1, 2002, as a result of a “Qualified Bankruptcy Sale,” a “Qualified Abandonment,” or a “Qualified Restructuring” (as defined in the PG&E Credit Agreement).
PG&E NEG recorded deferred tax assets of $1,403 million resulting from impairments and write-offs during 2002. As a result of such impairments, PG&E NEG has a net deferred tax asset of $1,003 million at December 31, 2002 before valuation allowance. Due to uncertainty in realizing the tax benefits associated with these deferred tax assets, PG&E NEG established valuation allowances for the full amount of the net deferred tax assets. The valuation allowances were determined in accordance with the provisions of SFAS No. 109 “Accounting for Income Taxes.” In assessing the realizability of deferred tax assets, PG&E NEG considered whether it is more likely than not that some portion of all of the deferred tax assets would not be realized. PG&E NEG is currently in default under various debt agreements and guaranteed equity commitments. PG&E NEG and its lenders are in discussions regarding a restructuring of these commitments. At this time, it is uncertain whether PG&E NEG will be able to reach agreement with the leaders regarding restructuring of its financial commitments or will be forced into proceedings under the Bankruptcy Code. As a result of this uncertainty, PG&E NEG established valuation allowances equal to its net deferred tax assets.
The Internal Revenue Service (IRS) has completed its audit of PG&E Corporation’s 1997 and 1998 consolidated U.S. federal income tax returns and has assessed additional federal income taxes of $53 million (including interest) related to PG&E NEG. PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and is currently discussing those adjustments with the IRS’s Appeals Office. The IRS is also auditing PG&E Corporation’s 1999 and 2000 consolidated U.S. federal income tax returns, but has not issued its final report. However, the IRS has proposed adjustments totalling $67 million (including interest) with respect to PG&E NEG. All of PG&E Corporation’s federal income tax returns before 1997 have been closed, including those portions attributable to PG&E NEG. In addition, California and certain other state tax authorities are currently auditing various state tax returns.
Minority Interests - Minority interests in earnings of consolidated affiliates are included in other income (expense) - net, in the Consolidated Statements of Operations. Minority interest expense total $2 million, $8 million and $2 million, for the years ended December 31, 2002, 2001 and 2000.
Foreign Currency Translation - The asset and liability accounts of PG&E NEG’s foreign subsidiaries are translated at year-end exchange rates and revenue and expenses are translated at average exchange rates prevailing during the period. The resulting translation adjustments are included in other comprehensive income. Currency transaction gains and losses are recorded in income.
Accumulated Other Comprehensive Income (Loss) - Accumulated other comprehensive income (loss) reports a measure for accumulated changes in equity of an enterprise that result from transactions and other economic events other than transactions with shareholders. PG&E NEG’s accumulated other comprehensive income (loss) consists principally of changes in the market value of certain financial hedges with the implementation of SFAS No. 133 on January 1, 2001, as well as foreign currency translation adjustments.
Reclassifications - Certain amounts in the 2001 and 2000 consolidated financial statements have been reclassified to conform to the 2002 presentation. These reclassifications did not affect consolidated net income for the years presented.
NOTE 2: RELATIONSHIP WITH PG&E CORPORATION
For periods before 2001, PG&E Corporation provided financial support in the form of loans to PG&E NEG, and the provision of collateral to third parties to support PG&E NEG’s contractual commitments and daily operations. Funds from operations were managed through net investments or borrowings in a pooled cash management arrangement, and PG&E Corporation provided credit support for trading activities through PG&E Corporation’s guarantees and surety bonds. Certain development and construction activities were funded in part through PG&E Corporation’s equity contributions or secured using instruments such as PG&E Corporation’s guarantees or equity commitments. PG&E Corporation also assisted with financing activities through short-term demand borrowings and long-term notes between PG&E Corporation and PG&E NEG and PG&E Corporation’s guarantees of certain minor credit facilities.
As of December 31, 2001, PG&E NEG had replaced or eliminated all of the previously issued PG&E Corporation guarantees and two guarantees of non-debt obligations of other PG&E NEG subsidiaries (except for a $16 million office lease guarantee relating to PG&E NEG’s San Francisco office, two guarantees of PG&E NEG’s indemnification obligations to purchasers of PG&E NEG’s assets and a guarantee related to PG&E NEG’s obligations to the sellers of assets purchased by PG&E NEG) with a combination of guarantees provided by PG&E NEG or its subsidiaries and letters of credit obtained independently by PG&E NEG. The $16 million office lease guarantee was reduced to $9.7 million as of December 31, 2002.
As of December 31, 2001, Attala Power Corporation (APC), an indirect, wholly-owned subsidiary of PG&E NEG, had a non-recourse demand note payable to PG&E Corporation of $309 million. As of December 31, 2002, the balance is $209 million. The APC note is classified as long-term on the Consolidated Balance Sheets as of December 31, 2002. The demand note between APC and PG&E Corporation is recourse only to APC and not to PG&E NEG. Interest is paid on the note quarterly based on the London interbank offer rate plus a 2.5% margin. At December 31, 2002, accrued interest of $2.3 million was recorded.
In addition, as of December 31, 2002, other wholly owned subsidiaries of PG&E NEG had net amounts payable in the amount of $118 million in the form of promissory notes to PG&E Corporation, related primarily to past funding of generating asset development and acquisition, and these amounts are classified as long-term on the Consolidated Balance Sheet.
In accordance with various arrangements, PG&E NEG and its subsidiaries enter into transactions with Pacific Gas and Electric Company (the Utility), another wholly owned subsidiary of PG&E Corporation and PG&E Corporation to provide and receive various services. The principal nature of the transactions between the Utility and PG&E NEG is the purchase and sale of energy commodities through PG&E ET and transportation services with PG&E GTN. These services are priced at either tariff rates or fair market value depending on the nature of the services provided.
The following table summarizes the significant related party transactions for PG&E NEG and its subsidiaries (in millions).
(A)This amount includes $22 million of pre-bankruptcy claims. The Utility is current on amounts owed to PG&E ET arising after the Utility’s April 6, 2001, bankruptcy filing. On January 31, 2003, PG&E ET sold its $22 million pre-bankruptcy claim for approximately $18 million.
(B)Subsequent to the Bankruptcy the Utility is current on all subsequent obligations. In accordance with PG&E GTN’s Federal Energy Regulatory Commission (FERC) tariff provisions, the Utility has provided assurances in the form of cash to support its position as a shipper on the PG&E GTN pipeline.
PG&E Corporation exchanges administrative and professional support services in support of operations, which are priced at the lower of total actual cost incurred or fair market value depending on the nature of the services provided. Additionally, PG&E Corporation allocates certain other corporate administrative and general costs to PG&E NEG and its subsidiaries. A variety of factors is used when allocating these costs, which are based upon the number of employees, operating expenses, total assets, and other cost causal methods. Allocated costs totaled $30 million in 2002, $25 million in 2001, and $43 million in 2000. The total amount due PG&E Corporation for these services and direct assignment of costs was $19 million at December 31, 2002 and $13 million at December 31 2001.
On October 18, 2002, PG&E Corporation entered into a Second Amended and Restated Credit Agreement (the “PG&E Credit Agreement”), with certain lenders. All obligations of PG&E Corporation under the PG&E Credit Agreement are secured by, among other things, perfected a first priority security interest in 100 percent of the equity interests in PG&E NEG LLC and 100 percent of the common stock of PG&E NEG held by PG&E NEG LLC, and all proceeds thereof.
The PG&E Credit Agreement generally does not limit the ability of PG&E NEG or its subsidiaries to grant liens or incur debt. The PG&E Credit Agreement generally permits PG&E NEG and its subsidiaries to enter into certain sales and other dispositions of assets in the ordinary course of business and in certain qualified transactions. In addition, in connection with certain sales and debt restructuring transactions of PG&E NEG and its subsidiaries, PG&E Corporation is permitted to use tax benefits generated at the PG&E Corporation level by such transactions to make investments in PG&E NEG provided that no default or event of default has occurred and is continuing under the PG&E Credit Agreement and neither PG&E NEG, LLC nor PG&E NEG are in bankruptcy. The amount of such investment is limited to 75 percent of the net cash tax savings (less certain costs and expenses) actually received by PG&E Corporation after October 1, 2002. PG&E Corporation is also permitted to make investments in PG&E NEG and its subsidiaries (including, without limitation, incurring obligations for which PG&E Corporation becomes a surety or a guarantor of PG&E NEG and its subsidiaries) up to a cumulative amount not to exceed $15 million, provided that no default or event of default has occurred and is continuing under the PG&E Credit Agreement and provided further that PG&E NEG LLC and PG&E NEG are not in bankruptcy. The proceeds of the new loans obtained under the PG&E Credit Agreement may not be used to make investments in PG&E NEG LLC or PG&E NEG, or any of their subsidiaries.
NOTE 3: LIQUIDITY & FINANCING RESOURCES
Credit Ratings
As previously reported in PG&E NEG’s recent filings on Form 8-K with the SEC, prior to July 31, 2002, most of the various debt instruments of PG&E NEG and its subsidiaries carried investment-grade credit ratings as assigned by Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s), two major credit rating agencies. Since July 31, 2002, PG&E NEG’s rated entities have been downgraded several times. The result of these downgrades has left all of PG&E NEG consolidated rated entities and debt instruments at below investment-grade.
The downgrade of PG&E NEG’s credit ratings impacts various guarantees and financial arrangements that require PG&E NEG to maintain certain credit ratings from S&P and/or Moody’s. Because of the downgrades PG&E NEG’s counterparties have demanded that PG&E NEG provide additional security for performance in the form of cash, letters of credit, acceptable replacement guarantees or advanced funding of obligations. Other counterparties continue to have the right to make such demands. If PG&E NEG fails to provide this additional collateral within defined cure periods, PG&E NEG may be in default under contractual terms. In addition to agreements containing ratings triggers, other agreements allow counterparties to seek additional security for performance whenever such counterparty becomes concerned about PG&E NEG’s or its subsidiaries’ creditworthiness. PG&E NEG’s credit downgrades constrained its access to additional capital and triggered increases in cost of indebtedness under many of its outstanding debt arrangements.
The credit downgrades also impacted PG&E NEG’s and its subsidiaries’ ability to service their financial obligations by putting constraints on the ability to move cash from one subsidiary to another or to PG&E NEG itself. PG&E NEG’s subsidiaries must now independently determine, in light of each company’s financial situation, whether any proposed dividend, distribution or intercompany loan is permitted and is in such subsidiary’s interest.
The effects of the credit downgrades on PG&E NEG’s debt facilities and other contractual arrangements are described below. Amounts required to be paid under debt agreements and other significant contractual commitments also are described below.
Debt Restructuring
PG&E NEG is currently in default under various debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.5 billion, but this debt is non-recourse to PG&E NEG. On November 14, 2002, PG&E NEG defaulted on the repayment of the $431 million 364-day tranche of its corporate revolving credit facility (Corporate Revolver). The amount outstanding under the two-year tranche of the Corporate Revolver is $273 million, the majority of which supports outstanding letters of credit. The default under the Corporate Revolver also constitutes a cross-default under (1) PG&E NEG’s Senior Notes ($1 billion outstanding), (2) its guarantee of a turbine revolver ($205 million outstanding), and (3) its equity commitment guarantees for the GenHoldings credit facility ($355 million outstanding), for the LaPaloma credit facility ($375 million outstanding) and for the Lake Road credit facility ($230 million outstanding). In addition, on November 15, 2002, PG&E NEG failed to pay a $52 million interest payment due under the Senior Notes. PG&E NEG does not currently have sufficient cash to meet its financial objectives and has ceased making payments on its debt and equity commitments.
PG&E NEG and its lenders are in discussions regarding a restructuring of these commitments. If lenders exercise their default remedies or if PG&E NEG’s financial commitments are not restructured, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced involuntarily into proceedings of the Bankruptcy Code.
Debt in Default and Long-Term Debt
The schedule below summarizes PG&E NEG’s outstanding debt in default and long-term debt as of December 31, 2002 and December 31, 2001 (in millions):
(1) Certain PG&E NEG long-term debt has been reclassified under debt in default about and has been classified as current liabilities in the accompanying Consolidated Balance Sheets. These instruments were not in default during 2001.
As of December 31, 2002, scheduled maturities of long-term debt were as follows (in millions):
PG&E NEG Senior Unsecured Notes - On May 22, 2001, PG&E NEG completed an offering of $1 billion in senior unsecured notes (Senior Notes) and received net proceeds of approximately $972 million after bond debt discount and note issuance costs. On November 15, 2002, PG&E NEG failed to pay a $52 million interest payment due on these notes. At December 31, 2002, PG&E NEG has outstanding interest accrued on these notes of $65 million.
Credit Facilities - In August 2001, PG&E NEG arranged a $1.25 billion working capital and letter of credit facility consisting of a $750 million tranche with a 364-day term and a $500 million tranche with a two-year term. On October 21, 2002, the available commitments were reduced to $431 million and $279 million respectively. As of December 31, 2002, $431 million had been drawn against the 364-day revolving credit facility and $42 million had been drawn against the two-year facility, in addition to $231 million of letters of credit issued under the two-year facility. At December 31, 2002, PG&E NEG had outstanding interest accrued on these facilities of $6 million.
PG&E NEG also has other revolving credit facilities held by subsidiaries. These facilities relate specifically to funding requirements of these entities and are not available to PG&E NEG. Under the terms of the various revolving credit facilities, the credit spread component of the interest rates and fees charged for borrowings was increased as a result of PG&E NEG’s credit downgrades. PG&E NEG’s credit downgrades did not trigger any acceleration of payments due under these long-term debt arrangements.
PG&E GTN Credit Facility - On May 2, 2002, PG&E GTN entered into a three-year $125 million revolving credit facility. At December 31, 2002, there was $58 million outstanding under this facility. The average weighted interest rate on the amount outstanding at December 31, 2002, is approximately 2.89 percent.
Turbine and Equipment Facility - In May 2001, PG&E NEG established a revolving credit facility of up to $280 million to fund turbine payments and equipment purchases associated with its generation facilities. The average weighted interest rate on the amount outstanding at December 31, 2002, is approximately 4.66 percent.
USGenNE Credit Facility - In August 2001, USGenNE entered into a credit and letter of credit facility that has a total commitment of $100 million of which $75 million has been drawn upon and $13 million letters of credit have been issued and are outstanding at December 31, 2002. The average weighted interest rate on the amount outstanding is approximately 2.61 percent. Total amounts outstanding under this facility, including any accrued interest, are included in Liabilities held for sale in the Consolidated Balance Sheets. See Note 5, Discontinued Operations and Assets Held for Sale.
GenHoldings Construction Facility -In December 2001, PG&E NEG entered into a $1.075 billion 5-year non-recourse credit facility, which increased to $1.460 billion on April 5, 2002, for the GenHoldings I, LLC, (GenHoldings) portfolio of projects secured by the Millennium, Harquahala, Covert and Athens projects. The facility was intended to be used to reimburse PG&E NEG and lenders for a portion of the construction costs already incurred on these projects and to fund a portion of the balance of the construction costs through completion.
GenHoldings I, LLC (GenHoldings), has defaulted under its credit agreement by failing to make equity contributions to fund construction draws for the Athens, Harquahala, and Covert generating projects. Through December 31, 2002, GenHoldings has contributed $833 million of equity to the projects. Although PG&E NEG has guaranteed GenHoldings’ obligation to make equity contributions, PG&E NEG has notified the GenHoldings lenders that it will not make further equity contributions on behalf of GenHoldings. In November and December 2002, the lenders executed waivers and amendments to the credit agreement under which they agreed to continue to waive until March 31, 2003, the default caused by GenHoldings’ failure to make equity contributions. In addition, certain of these lenders agreed to increase their loan commitments to an amount sufficient to provide (1) the funds necessary to complete construction of the Athens, Covert and Harquahala facilities under the construction contracts; and (2) additional working capital facilities to enable each project, including Millennium, to timely pay for its fuel requirements and to provide its own collateral to support natural gas pipeline capacity reservations and independent transmission system operator requirements. The November and December 2002 increased loan commitments and rank equally with each other but are senior to amounts loaned through and including the October credit extension.
In connection with the lenders’ waiver of various defaults and additional funding commitments, PG&E NEG has agreed to cooperate with any reasonable proposal by the lenders regarding disposition of the equity in or assets of any or all of the PG&E NEG subsidiaries holding the Athens, Covert, Harquahala and Millennium projects. The amended credit agreement provides that an event of default will occur if the Athens, Covert, Harquahala and Millennium facilities are not transferred to the lenders or their designees on or before March 31, 2003. Such a default would trigger lender remedies, including the right to foreclose on the projects.
Under the waiver, PG&E NEG has re-affirmed its guarantee of GenHoldings’ remaining obligation to make equity contributions to these projects of approximately $355 million. Neither PG&E NEG nor GenHoldings currently expects to have sufficient funds to make this payment. The requirement to pay $355 million will remain an obligation of PG&E NEG that would survive the transfer of the projects.
Further, as a result of GenHoldings’ failure to make required payments under the interest rate hedge contracts entered into by GenHoldings, the counterparties to such interest rate hedge contracts terminated the contracts during December 2002. Settlement amounts due by GenHoldings in connection with such terminated contracts are, in the aggregate, approximately $50 million.
Lake Road and La Paloma Construction Facilities -In September 1999 and March 2000, Lake Road and La Paloma (respectively) entered into Participation Agreements to finance the construction of the two plants. In 2001, management determined that the assets and liabilities related to these leased facilities should have been consolidated. In November 2002, Lake Road and La Paloma defaulted on their obligations to pay interest and swap payments. In addition, as a result of PG&E NEG’s downgrade to below investment grade by both S&P and Moody’s, PG&E NEG, as guarantor of certain debt obligations of Lake Road and La Paloma, became required to make equity contributions to Lake Road and La Paloma of $230 million and $375 million respectively. None of PG&E NEG, Lake Road or La Paloma have sufficient funds to make these payments.
As of December 4, 2002, PG&E NEG and certain subsidiaries entered into various agreements with the respective lenders for each of the Lake Road and La Paloma generating projects providing for (1) funding of construction costs required to complete the La Paloma facility; and (2) additional working capital facilities to enable each subsidiary to timely pay for its fuel requirements and to provide its own collateral to support natural gas pipeline capacity reservations and independent transmission system operator requirements, as well as for general working capital purposes. Lenders extending new credit under these agreements have received liens on the projects that are senior to the existing lenders’ liens. These agreements provide, among other things, that the failure to transfer right, title and interest in, to and under the Lake Road and La Paloma projects to the respective lenders by June 9, 2003 will constitute a default under the agreements. The failure to transfer the facilities would entitle the lenders to accelerate the new indebtedness and exercise other remedies.
In consideration of the lenders’ forebearance and additional funding, PG&E NEG had previously agreed to cooperate, and cause its subsidiaries to cooperate, with any reasonable proposal regarding disposition of the ownership interests in and/or assets of the La Paloma project, on terms and conditions satisfactory to the lenders in their sole discretion.
The La Paloma and Lake Road projects have been financed entirely with debt. PG&E NEG has guaranteed the repayment of a portion of the project subsidiary debt in the approximate aggregate amounts of $375 million for La Paloma and $230 million for Lake Road, which amounts represent the subsidiaries’ equity contribution in the projects. The lenders have accelerated all the debt existing prior to December 11, 2002, including the guaranteed portion of the debt and made a payment demand under the PG&E NEG guarantee. Neither the PG&E NEG subsidiaries nor PG&E NEG have sufficient funds to make these payments. The requirement to make the payments will remain an obligation of PG&E NEG that would survive the transfer of the projects.
Further, as a result of the La Paloma and Lake Road subsidiaries’ failure to make required payments under the interest rate hedge contracts entered into by them, the counterparties to such interest rate hedge contracts have terminated the contracts. Settlement amounts due from the Lake Road and La Paloma project subsidiaries in connection with such terminated contracts are, in the aggregate, approximately $61 million for Lake Road and $79 million for La Paloma.
PG&E GTN Senior Unsecured Notes, Debentures and Medium Term Notes - On May 31, 1995, PG&E GTN completed the sale of $400 million of debt securities through a $700 million shelf registration. PG&E GTN issued $250 million of 7.10 percent 10-year senior unsecured notes due June 1, 2005, and $150 million of 7.8 percent 30-year senior unsecured debentures due June 1, 2025. The 10-year notes were issued at a discount to yield 7.11 percent and the 30-year debentures were issued at a discount to yield 7.95 percent. At December 31, 2002, the unamortized debt discount balance for the notes and debentures were $0.1 million and $1.9 million, respectively. The 30-year debentures are callable after June 1, 2005, at the option of PG&E GTN. Both the Senior unsecured notes and the senior unsecured debentures were downgraded during 2002 to a credit rating of CCC from Standard and Poor’s and B1 from Moody’s Investors Service.
On June 6, 2002, PG&E GTN issued $100 million of 6.62 percent Senior Notes due June 6, 2012. Proceeds were used to repay $90 million of debt on its revolving credit facility, and the balance retained to meet general corporate needs.
In addition, during 1995, $70 million of medium term notes were issued at face values ranging from $1 million to $17 million. The medium-term notes currently carry a credit rating of CCC from Standard and Poor’s and B1 from Moody’s Investors Service. Medium term notes totaling $33 million in 2002 and $31 million in 2001 matured and were accordingly paid. The remaining notes mature during 2003 and have an average interest rate of 6.96 percent.
Plains End Construction Facility -In September 2001, PG&E NEG’s subsidiary established a facility for $69 million. The debt facility was used to fund the balance of construction costs for the Plains End project. The facility expires upon the earlier of five years after commercial operations have been declared which is May, 2007. The average weighted interest rate on the amount outstanding is approximately 5.17 percent.
Other long-term debt consists of non-recourse project financing associated with unregulated generating facilities, premiums, and other loans.
Certain credit agreements contain, among other restrictions, customary affirmative covenants, representations and warranties and have cross-default provisions with respect to PG&E NEG’s other obligations. The credit agreements also contain certain negative covenants including restrictions on the following: consolidations, mergers, sales of assets and investments; certain liens on the PG&E NEG’s property or assets; incurrence of indebtedness; entering into agreements limiting the right of any subsidiary of PG&E NEG to make payments to its shareholders; and certain transactions with affiliates. Certain credit agreements also require that PG&E NEG maintain a minimum ratio of cash flow available for fixed charges to fixed charges and a maximum ratio of funded indebtedness to total capitalization.
NOTE 4: COMMITMENTS AND CONTINGENCIES
Letters of Credit
In addition to the outstanding balances under the above credit facilities, PG&E NEG has commitments available under facilities to issue letters of credit. The following table lists the various letter of credit facilities that have the capacity to issue letters of credit (in millions):
Firm Commitments
PG&E NEG’s subsidiaries have entered into various long-term firm commitments. PG&E NEG’s subsidiaries are negotiating with the lenders, debtholders and other counterparties in an attempt to restructure these commitments. The ability of PG&E NEG’s subsidiaries to fund these commitments depends on the terms of any restructuring plan that may be agreed to by the appropriate parties. The following table identifies, by year, the aggregate amounts of these commitments (millions):
Fuel Supply and Transportation Agreements - PG&E NEG’s subsidiaries have entered into gas supply and firm transportation agreements with a number of pipelines and transporters to provide fuel transportation services. Under these agreements, PG&E NEG’s subsidiaries must make specified minimum payments each month.
Power Purchase Agreements -USGen New England assumed rights and duties under several power purchase contracts with third party independent power producers as part of the acquisition of the New England Electric System assets. As of December 31, 2002, these agreements provided for an aggregate of approximately 800 MW of capacity. USGen New England is required to pay New England Power Company amounts due to third-party producers under the power purchase contracts.
Operating Leases -Various subsidiaries of PG&E NEG entered into several operating lease agreements for generating facilities and office space. Lease terms vary between 3 and 48 years.
In November 1998, USGen New England entered into a $479 million sale-leaseback transaction whereby the subsidiary sold and leased back a pumped storage station under an operating lease.
On May 7, 2002, Attala Generating Company, LLC, an indirect subsidiary of PG&E NEG, completed a $340 million sale and leaseback transaction whereby it sold and leased back its facility to a third party special purpose entity. The related lease is being accounted for as an operating lease. See Note 6, “Impairments, Write-Offs and Other Charges”, for further discussion relating to the Attala lease agreement.
Operating lease expense amounted to $78 million, $54 million, and $70 million in 2002, 2001, and 2000, respectively.
Long Term Service Agreements - Various subsidiaries of PG&E NEG have entered into long-term service agreements for the maintenance and repair of certain of its combustion turbine or combined-cycle generating plants. These agreements are for periods up to 18 years.
Payments in Lieu of Property Taxes - Various subsidiaries of PG&E NEG have into certain agreements with local governments that provide for payments in lieu of property taxes for some of its generating facilities.
Construction Commitments - Various subsidiaries of PG&E NEG currently have projects (Athens, Covert, La Paloma, and Harquahala) under construction. PG&E NEG’s construction commitments are generally related to the major construction agreements including the construction and other related contracts. Certain construction contracts also contain commitments for turbines and related equipment.
Tolling Agreements -PG&E ET, entered into tolling agreements with several counterparties under which it, at its discretion, supplies the fuel to the power plants and then sells the plant’s output in the competitive market. Payments to counterparties are reduced if the plants do not achieve agreed-upon levels of performance. The face amount of PG&E NEG’s and its subsidiaries’ guarantees relating to PG&E ET’s tolling agreements is approximately $600 million. The tolling agreements are with: (1) Liberty Electric Power, L.P. (Liberty) guaranteed by both PG&E NEG and PG&E GTN for an aggregate amount of up to $150 million; (2) DTE-Georgetown, LLC (DTE) guaranteed by PG&E GTN for up to $24 million; (3) Calpine Energy Services, L.P. (Calpine) for which no guarantee is in place; (4) Southaven Power, LLC (Southaven) guaranteed by PG&E NEG for up to $175 million; and (5) Caledonia Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million.
Liberty - Liberty has provided notice to PG&E ET that the ratings downgrade of PG&E NEG constituted a material adverse change under the tolling agreement requiring PG&E ET to replace the guarantee and post security in the amount of $150 million. PG&E ET has not posted such security. Liberty has the right to terminate the agreement and seek recovery of a termination payment. Under the terms of the guarantees to Liberty for the aggregate $150 million, Liberty must first proceed against PG&E NEG’s guarantee, and can demand payment under PG&E GTN’s guarantee only if (1) PG&E NEG is in bankruptcy or (2) Liberty has made a payment demand on PG&E NEG which remains unpaid five business days after the payment demand is made. In addition, PG&E ET has provided notices to Liberty of several breaches of the tolling agreement by Liberty and has advised Liberty that, unless cured, these breaches would constitute a default under the agreement. If these defaults remain uncured, PG&E ET has the right to terminate the agreement and seek recovery of a termination payment.
DTE Georgetown - By letter dated October 14, 2002, DTE provided notice to PG&E ET that the downgrade of PG&E GTN constituted a material adverse change under the tolling agreement between PG&E ET and DTE and that PG&E ET was required to post replacement security within ten days. By letter dated October 23, 2002, PG&E ET advised DTE that because there had not been a material adverse change with respect to PG&E GTN within the meaning of the tolling agreement, PG&E ET was not required to post replacement security. If PG&E ET was required to post replacement security and it failed to do so, DTE would have the right to terminate the tolling agreement and seek recovery of a termination payment.
Calpine- The tolling agreement states that on or before October 15, 2002, Calpine was to have issued a full notice to proceed under its construction contract to its engineering, procurement and construction contractor for the Otay Mesa facility. On October 16, 2002 PG&E ET asked Calpine to confirm that it had issued this full notice to proceed and Calpine was not able to do so to the satisfaction of PG&E ET. Consequently, PG&E ET advised Calpine by letter dated October 30, 2002 that it was terminating the tolling agreement effective November 29, 2002. Calpine has indicated that this termination was improper and constituted a default under the agreement, but has not taken any further action.
Southaven and Caledonia Tolling Agreements. PG&E ET signed a tolling agreement with Southaven dated as of June 1, 2000, under which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade as defined in the tolling agreement. The amount of the guarantee does not exceed $175 million. By letter dated August 31, 2002, Southaven advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade as defined in the tolling agreement and as PG&E ET had failed to provide, within thirty days from the downgrade substitute credit support that meets the requirement of the tolling agreement. Under the tolling agreement, Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Southaven with a notice of default respecting Southaven’s performance under the tolling agreement and concerning the inability of the facility to inject its output into the local grid. Southaven has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.
In addition, PG&E ET signed a tolling agreement with Caledonia dated as of September 20, 2000, pursuant to which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade as defined in the
agreement. The amount of the guarantee does not exceed $250 million. By letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation as PG&E NEG was no longer investment-grade as defined in the tolling agreement and because PG&E ET had failed to provide, within thirty days from the downgrade substitute credit support that met the requirements of the tolling agreement. Caledonia has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Caledonia with a notice of default respecting Caledonia’s performance under the tolling agreement concerning the inability of the facility to inject its output into the local grid. Caledonia has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.
On February 7, 2003, Southaven and Caledonia filed emergency petitions to compel arbitration or, in the alternative, for a temporary restraining order and preliminary injunction with the Circuit Court for Montgomery County, Maryland. The Court has denied the relief requested and has set the matter for hearing on March 3, 2003. Following oral agreement, the judge ruled, subject to entry of a written order, that PG&E ET was required to continue to perform under the agreements.
PG&E ET is not able to predict whether the counter parties will seek to terminate the agreements or whether the Court will grant the requested relief. Accordingly, it is not able to predict whether or the extent to which, these proceedings will have a material adverse effect on PG&E NEG’s financial condition or results of operation.
Under each tolling agreement determination of the termination payment is based on a formula that takes into account a number of factors including market conditions such as the price of power and the price of fuel. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. The dispute resolution process could take as long as 6 months to more than a year to complete. To the extent that PG&E ET did not pay these damages, the counterparties could seek payment under the guarantees for an aggregate amount not to exceed $600 million. PG&E NEG is unable to predict whether counterparties will seek to terminate their tolling agreements. PG&E NEG does not currently expect to be able to pay any termination payments that may become due.
Guarantees
PG&E NEG and certain subsidiaries have provided guarantees as of December 31, 2002 to approximately 232 counterparties in support of PG&E ET’s energy trading and non-trading activities related to PG&E NEG’s merchant energy portfolio in the face amount of $2.7 billion. Typically, the overall exposure under these guarantees is only a fraction of the face value of these guarantees, since not all counterparty credit limits are fully used at any time. As of December 31, 2002, PG&E NEG and its rated subsidiaries’ aggregate exposure under these guarantees was approximately $83 million. The amount of such exposure varies daily depending on changes in market prices and net changes in position. In light of the downgrades, some counterparties have sought and others may seek replacement security to collateralize the exposure guaranteed by PG&E NEG and its subsidiaries. PG&E GTN and PG&E ET have terminated the arrangements pursuant to which PG&E GTN provided guarantees on behalf of PG&E ET such that PG&E GTN will provide no new guarantees on behalf of PG&E ET.
At December 31, 2002, PG&E ET’s estimated exposure not covered by a guarantee (excluding exposure under tolling agreements) is approximately $94 million.
To date, PG&E ET has met those replacement security requirements properly demanded by counterparties and has not defaulted under any of its master trading agreements although one counterparty has alleged a default. No demands have been made upon the guarantors of PG&E ET’s obligations under these trading agreements. In the past, PG&E ET has been able to negotiate acceptable arrangements and reduce its overall exposure to counterparties when PG&E ET or its counterparties have faced similar situations. There can be no assurance that PG&E ET can continue to negotiate acceptable arrangements in the current circumstances. PG&E NEG cannot quantify with any certainty the actual future calls on PG&E ET’s liquidity. PG&E NEG’s and its subsidiaries’ ability to meet these calls on their liquidity will vary with market price volatility, uncertainty with respect to PG&E NEG’s financial condition and the degree of liquidity in the energy markets. The actual calls for collateral will depend largely upon the ability to enter into forbearance agreements and pre- and early-pay arrangements with counterparties, the continued performance of PG&E NEG companies under the underlying agreements with counterparties, whether counterparties have the right to demand such collateral, the execution of master netting agreements and offsetting transactions, changes in the amount of exposure, and the counterparties’ other commercial considerations.
Other Guarantees
PG&E NEG has provided guarantees related to other obligations by PG&E NEG companies to counterparties for goods or services. PG&E NEG does not believe that it has significant exposure under these guarantees. The most significant of these guarantees relate to performance under certain construction contracts. In the event PG&E NEG is unable to provide any additional or replacement security which may be required as a result of rating downgrades, the counterparty providing the goods or services could suspend performance or terminate the underlying agreement and seek recovery of damages. These guarantees represent guarantees of subsidiary obligations for transactions entered into in the ordinary course of business. Some of the guarantees relate to the construction or development of PG&E NEG’s power plants and pipelines. These guarantees are described below.
PG&E NEG has issued guarantees to construction financing lenders for the performance of the contractors building the Harquahala and Covert power projects for up to $555 million. Any exposure under the guarantees for construction completion is mitigated by guarantees in favor of PG&E NEG from the constructor and equipment vendors related to performance, schedule and cost. The constructor and various equipment vendors are currently performing under their underlying contracts. On August 8, 2002, PG&E NEG replaced the rating triggers contained in these guarantees with financial covenants that are consistent with those contained in PG&E NEG’s Corporate Revolver.
PG&E NEG has issued $100 million of guarantees to the constructor of the Harquahala and Covert projects to cover certain separate cost-sharing arrangements. Failure to perform under those separate cost-sharing arrangements or the related guarantees would not have an impact on the constructor’s obligations to complete the Harquahala and Covert projects pursuant to the construction contracts. However, in the event that the construction contractor incurs certain unreimbursed project costs or cost overruns, the contractor could assert a claim against PG&E NEG’s subsidiary or PG&E NEG under its guarantees. PG&E NEG believes that no claim can be validly asserted by the construction contractor as of the date of this Report.
PG&E NEG has provided a $300 million guarantee to support a tolling agreement that a wholly owned subsidiary, Attala Energy Company, LLC, has entered into with another wholly-owned subsidiary, Attala Generating Company, LLC. See discussion above under “Impairment of Prepaid Rents on Attala Lease” for additional discussion of this guarantee.
The balance of the guarantees are for commitments undertaken by PG&E NEG or subsidiaries in the ordinary course of business for services such as facility and equipment leases, ash disposal rights, and surety bonds.
Contingencies
Environmental Matters
In May 2000, USGen New England, Inc. (USGenNE), an indirect subsidiary of PG&E NEG, received an Information Request from the U.S. Environmental Protection Agency (EPA), pursuant to Section 114 of the Federal Clean Air Act (CAA). The Information Request asked USGenNE to provide certain information relative to the compliance of its Brayton Point and Salem Harbor plants with the CAA. No enforcement action has been brought by the EPA to date. USGenNE has had preliminary discussions with the EPA to explore a potential settlement of this matter. Management believes that it is not possible to predict at this point whether any such settlement will occur or, in the absence of a settlement, the likelihood of whether the EPA will bring an enforcement action.
As a result of the EPA Information Request and environmental regulatory initiatives by the Commonwealth of Massachusetts, USGenNE is exploring ways to achieve significant reductions of sulfur dioxide and nitrogen oxide emissions. Additional requirements for the control of mercury and carbon dioxide emissions also will be forthcoming as part of these regulatory initiatives. Management believes that USGenNE would meet these requirements through installation of controls at the Brayton Point and Salem Harbor plants and estimates that capital expenditures on these environmental projects could approximate $348 million over the next four years. To date PG&E NEG has incurred expenditures related to these projects of $15.7 million. These estimates are currently under review and it is possible that actual expenditures may be higher. Based on an emission control plan filed for Brayton Point under the regulations implementing these initiatives, the Massachusetts Department of Environmental Protection (DEP) ruled that Brayton Point is required to meet the newer, more stringent emission limitations for sulfur dioxide and nitrogen oxide by 2006. However, on June 7, 2002, the DEP ruled that Salem Harbor must satisfy these limitations by 2004. USGenNE filed with DEP a revised plan for Salem Harbor in April that it believes meets the DEP requirements for the 2006 compliance date. USGenNE has also filed an administrative appeal of DEP’s ruling that Salem Harbor must meet the 2004 compliance date. On December 13, 2002, DEP issued an amended draft approval ruling that Salem Harbor that the initial compliance date is October 2006. However, on February 6, 2003, DEP issued a final decision denying approval of the amended plan. Although it is USGenNE’s current intention to appeal DEP’s denial, in the absence of a final decision in USGenNE’s favor following the conclusion of the adjudicatory proceeding, the compliance date for Salem Harbor remains October 2004. USGenNE will not be able to operate Salem Harbor unless it is in compliance with these emission limitations. PG&E NEG believes that it is impossible to meet the October 2004 deadline. Therefore, it may not be able to operate the facility after that deadline.
Various aspects of DEP’s regulations allow for public participation in the process through which DEP determines whether the 2004 or 2006 deadline applies and approves the specific activities that USGenNE will undertake to meet the new regulations. A local environmental group has made various filings with DEP requesting such participation.
The EPA is required under the CAA to establish new regulations for controlling hazardous air pollutants from combustion turbines and reciprocating internal combustion engines. Although the EPA has yet to propose the regulations, the CAA required that they be promulgated by November 2000. Another provision in the CAA requires companies to submit case-by-case Maximum Achievable Control Technology (MACT) determinations for individual plants if the EPA fails to finalize regulations within eighteen months past the deadline. On April 5, 2002, the EPA promulgated a regulation that extends this deadline for the case-by-case permits until May 2004. The EPA intends to finalize the MACT regulations before this date, thus eliminating the need for the plant-specific permits. PG&E NEG will not be able to accurately quantify the economic impact of the future regulations until more details are available through the rulemaking process.
PG&E NEG’s existing power plants are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE (Salem Harbor, Manchester Street, and Brayton Point) are operating pursuant to National Pollutant Discharge Elimination System (NPDES) permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and all three facilities are continuing to operate under existing terms and conditions until new permits are issued. On July 22, 2002, the EPA and DEP issued a draft NPDES permit for Brayton Point that, among other things, substantially limits the discharge of heat by Brayton Point into Mount Hope Bay. Based on its initial review of the draft permit, USGenNE believes that the draft permit is excessively stringent. It is estimated that USGenNE’s cost to comply with the new permit conditions could be as much as $248 million through 2006, but this is a preliminary estimate. There are various administrative and judicial proceedings that must be completed before the draft NPDES permit for Brayton Point becomes final, and these proceedings are not expected to be completed during 2003. In addition, it is possible that the new permits for Salem Harbor and Manchester Street may also contain more stringent limitations than prior permits and that the cost to comply with the new permit conditions could be greater than the current estimate of $4 million. In addition, the issuance of any final NPDES permits may be affected by the EPA’s proposed regulations under Section 316(b) of the Clean Water Act.
On March 27, 2002, the Rhode Island Attorney General notified USGenNE of his belief that Brayton Point “is in violation of applicable statutory and regulatory provisions governing its operations...”, including “protections accorded by common law” respecting discharges from the facility into Mount Hope Bay. He stated that he intends to seek judicial relief “to abate these environmental law violations and to recover damages...” within the next 30 days. The notice purportedly was provided pursuant to section 7A of chapter 214 of Massachusetts General Laws. PG&E NEG believes that Brayton Point is in full compliance with all applicable permits, laws and regulations. The complaint has not yet been filed or served. In early May 2002, the Rhode Island Attorney General stated that he did not plan to file the action until the EPA issues a draft Clean Water Act NPDES permit for Brayton Point. The EPA issued this draft permit on July 22, 2002, and the Rhode Island Attorney General has since stated he has no intention of pursuing this matter until he reviews USGenNE’s response to the draft permit which was submitted on October 4, 2002. Management is unable to predict whether he will pursue this matter and, if he does, the extent to which it will have a material adverse effect on PG&E NEG’s financial condition or results of operation.
On April 9, 2002, the EPA proposed regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations would affect existing power generation facilities using over 50 million gallons per day typically including some form of “once-through” cooling. Brayton Point, Salem Harbor, and Manchester Street are among an estimated 539 plants nationwide that would be affected by this rulemaking. The proposed rule calls for a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. The final regulations are scheduled to be promulgated in February 2004. The extent to which they may require additional capital investment will depend on the timing of the NPDES permit proceedings for the affected facilities. It is possible that the regulations may allow greater flexibility in achieving specified permit limits and thereby reduce the cost of compliance.
During April 2000, an environmental group served USGenNE and other PG&E NEG’s subsidiaries with a notice of its intent to file a citizen’s suit under the Resource Conservation Recovery Act. In September 2000, PG&E NEG signed a series of agreements with DEP and the environmental group to resolve these matters that require PG&E NEG to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities. PG&E NEG began the activities during 2000 and is expected to complete them in 2003. PG&E NEG incurred expenditures related to these agreements of $5.4 million in 2000, $2.6 million in 2001 and $4.7 million in 2002. In addition to the costs previously incurred, PG&E NEG maintains a reserve in the amount of $6 million relating to its estimate of the remaining environmental expenditures to fulfill its obligations under these agreements. PG&E NEG has deferred costs associated with capital expenditures and has set up a receivable for amounts it believes are probable of recovery from insurance proceeds.
PG&E NEG believes that it may be required to spend up to approximately $608 million, excluding insurance proceeds, through 2008 for environmental compliance to continue operating these facilities. This amount may change, however, and the timing of any necessary capital expenditures could be accelerated in the event of a change in environmental regulations or the commencement of any enforcement proceeding against PG&E NEG. PG&E NEG has not made any commitments to spend these amounts. In the event PG&E NEG does not spend required amounts as of each facility’s compliance deadline to maintain environmental compliance, PG&E NEG may not be able to continue to operate one or all of these facilities.
Global climate change is a significant environmental issue that is likely to require sustained global action and investment over many decades. PG&E Corporation has been engaged on the climate change issue for several years and is working with others on developing appropriate public policy responses to this challenge. PG&E Corporation continuously assesses the financial and operational implications of this issue; however, the outcome and timing of these initiatives are uncertain.
There are six greenhouse gases. PG&E NEG emits varying quantities of these greenhouse gases, including carbon dioxide and methane, in the course of its operations. Depending on the ultimate regulatory regime put into place for greenhouse gases, PG&E NEG’s operations, cash flows and financial condition could be adversely affected. Given the uncertainty of the regulatory regime, it is not possible to predict the extent to which climate change regulation will have a material adverse effect on PG&E NEG’s financial condition or results of operations.
Legal Matters
In the normal course of business, PG&E NEG is named as a party in a number of claims and lawsuits. The most significant of these are discussed below.
NSTAR Electric & Gas Corporation - On May 14, 2001, NSTAR Electric & Gas Corporation (NSTAR) the Boston-area retail electric distribution utility holding company, filed a complaint at the FERC contesting the market-based rate authority of PG&E ET-Power and affiliates of Sithe Energies, Inc. (Sithe). In support of its complaint, NSTAR argues that the Northeastern Massachusetts Area (NEMA), at times suffers transmission constraints which limit the delivery of power into NEMA and that PG&E ET-Power and Sithe possess market power based on their share of generation within NEMA. NSTAR requests remedies including revocation of the suppliers’ market-based pricing authority during periods of transmission congestion into NEMA, divestiture of generation resources in NEMA, imposition of a rate cap on the suppliers’ generation resources during transmission constraints based on the marginal cost of production of those resources, and more effective and open exercise of market monitoring and mitigation by Independent System Operator-New England (ISO-New England), the independent system operator for the New England control area (NEPOOL). Under the NEPOOL market rules and procedures, ISO-New England is empowered to monitor and mitigate bids during periods of transmission congestion. PG&E NEG believes that ISO-New England has actively mitigated bids and has used its authority to mitigate the impact of transmission constraints on costs within NEMA and that PG&E ET-Power has operated its resources in compliance with NEPOOL market rules and procedures and applicable law. In addition, PG&E ET-Power and its affiliate, USGenNE, the entity that owns the generating assets located in NEPOOL, have had their market-based rate authority confirmed by FERC on two prior occasions.
On February 5, 2002, NSTAR filed a petition for review with the United States Court of Appeals for the D.C. Circuit of the series of FERC Orders relating to ISO-New England’s implementation of its market mitigation authority under the NEPOOL Market Rules and Procedures 17 (MRP 17). On February 25, 2002, ISO-New England filed all agreements entered into pursuant to MRP 17, including its agreement with PG&E ET-Power with respect to Salem Harbor. The FERC has ruled that no refunds will be required with respect to the agreements for periods prior to acceptance by FERC of the filing. NSTAR claims that until accepted by the FERC, these agreements cannot be effective and that any amounts collected pursuant to these agreements prior to their effectiveness must be refunded to the extent that amounts are in excess of certain rate formulas contained in MRP 17. PG&E ET-Power, as the party that bids USGenNE’s assets into the NEPOOL markets, entered into an agreement with ISO-New England for calendar years 2000, 2001, and 2002. This agreement sets forth terms on which bids from Salem Harbor Station Unit 4 may be mitigated without challenge by PG&E ET-Power. To date, bid amounts collected subject to the mitigation agreements are approximately $34.1 million.
In addition, on October 17, 2002, FERC issued an order denying NSTAR’s complaint against PG&E ET-Power and Sithe, holding that MRP 17 was properly applied; that the prices ET-Power and Sithe charged were within the zone of reasonableness; and rejecting numerous other of NSTAR’s claims. PG&E NEG believes that the ultimate outcome of this litigation will not have a material adverse effect on its financial condition or results of operations.
FERC California Refund Proceeding - In a June 19, 2001 order, FERC required that all public utility sellers and buyers in certain California markets participate in settlement discussions to complete the task of settling past accounts and structuring the new arrangements for California’s future energy markets. PG&E ET-Power is one such seller and buyer. These settlement discussions have been completed and they were not successful. As a result, the administrative law judge presiding over the
discussions recommended to FERC a methodology to be used in connection with evidentiary hearings that are to be undertaken to, among other things, determine a settlement of past accounts. On July 25, 2001, FERC ordered that refunds may be due from sellers who engaged in transactions in the California markets between October 2, 2000, and June 20, 2001, including PG&E ET-Power and established a methodology to determine what refunds and payments are due for the defined period of October 2, 2000 through June 30, 2001. On December 19, 2001, FERC issued a decision purporting to clarify its earlier orders. The California Independent System Operator (California ISO) has provided an update of its August 17, 2001 data and a hearing took place this summer before a FERC administrative law judge to determine the refund amounts and additional amounts owed. In addition, on August 21, 2002, the U.S. Court of Appeals for the Ninth Circuit issued an order consolidating the appeals of certain FERC dockets related to this docket and remanded those other proceedings for FERC to take additional evidence of market manipulation by various sellers. On December 12, 2002 the administrative law judge issued proposed findings of fact and conclusions of law. The proposed findings indicate that ET-Power owes refunds of $9.5 million to the ISO after crediting the amount that the ISO owes it for past sales. In addition, the proposed findings indicate that PG&E ET is owed by the PX, which is in bankruptcy. These figures are preliminary and will be recalculated after FERC rules on the appeals filed with the Commission on the administrative law judge’s proposed findings.
In addition on November 20, 2002, the FERC opened a second phase of its investigation of all wholesale sellers of electricity in California. It authorized 100 days of discovery relating to market manipulation in the period of January 1, 2000 through June 20, 2001. This discovery period ends February 28, 2003. PG&E ET has received and is responding to discovery in this proceeding. All parties are entitled to file evidence of market manipulation or contrary evidence on February 28, 2003. FERC has announced that any such evidence will be taken into account during its consideration of the appeals from the December 12, 2002 proposed findings by the administrative law judge on California refund liability. PG&E NEG believes that the ultimate outcome of this matter will not have a material adverse effect on NEG’s financial condition or results of operations.
Natural Gas Royalties Litigation - This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Grynberg (called a relator in the parlance of the False Claims Act) on behalf of the United States of America against more than 330 defendants, including PG&E GTN. The cases were consolidated for pretrial purposes in the U.S. District Court, for the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998. Under procedures established by the False Claims Act, the United States (acting through the Department of Justice (DOJ)) is given an opportunity to investigate the allegations and to intervene in the case and take over its prosecution if it chooses to do so. In April 1999, the DOJ declined to intervene in any of the cases. The complaints allege that the various defendants (most of which are pipeline companies or their affiliates) mismeasured the volume and heating content of natural gas produced from federal or Indian leases. As a result, the relator alleges that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases. The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties and expenses associated with the litigation. PG&E NEG believes that the allegations of the complaint are without merit and will vigorously respond to and defend the litigation. PG&E NEG believes that it is reasonably possible that it could incur a loss, but it is not able to determine the amount of such loss and, therefore, whether in light of the recent deterioration of PG&E NEG’s financial condition, such loss would have a material adverse effect on PG&E NEG’s financial condition or results of operations.
Asbestos Litigation - Pursuant to an Asset Purchase Agreement dated as of August 5, 1997, USGenNE agreed to indemnify New England Power Company (NEPCo) for certain losses. Such losses included claims arising from certain conditions on the site of the generation assets USGenNE purchased under the Asset Purchase Agreement. Several parties have filed suit or indicated that they may file suit against NEPCo for damages they claim arose out of exposure to asbestos fibers, which exposure allegedly took place while working at one or more of the generation assets that USGenNE purchased from NEPCo. Under the Asset Purchase Agreement USGenNE may be required to indemnify NEPCo for some or all of these claims. PG&E NEG believes that the ultimate outcome of this litigation will not have a material adverse effect on PG&E NEG’s financial condition or results of operations.
Wholesale Standard Offer Service- USGenNE acquired from NEPCo and Narragansett Electric Company (Narragansett) certain generation assets in New England. As part of the acquisition, USGenNE entered into certain Wholesale Standard Offer Service Agreements (WSOS Agreements) with NEPCo’s distribution affiliates. A dispute has arisen over the party responsible for certain power pool imposed charges including ISO-New England expenses, uplift charges and congestion costs. NEPCo and Narragansett are currently paying the charges under an agreement which expires by its terms on April 30, 2003, unless extended by mutual agreement. The agreement does not prohibit either party from undertaking proceedings to decide the allocation issues. FERC has rejected certain attempts by NEPCo to affirmatively transfer these obligations on a going forward basis by means of NEPOOL market rules and procedures but FERC has consistently refused to insert itself in the contractual dispute. In a letter dated August 31, 2001, distribution company affiliates of NEPCo informed USGenNE that they are invoking the dispute resolution provisions of the WSOS Agreements and that they will seek reimbursement for these costs
along with a ruling that under the WSOS Agreements these costs should be imposed on USGenNE going forward. On March 27, 2002, the parties formally commenced arbitration. As of December 31, 2002, NEPCo has incurred approximately $29 million for these power pool costs. Because of changes in the market rules that are to become effective, it is not possible to estimate going forward costs. The WSOS Agreements will expire at the end of 2004 and 2009.
Due to the recent deterioration of PG&E NEG’s financial condition, PG&E NEG believes that the ultimate outcome of this litigation may have a material adverse effect on PG&E NEG’s financial condition or results of operations.
Shaw Litigation- On August 13, 2001, Harquahala entered into an Engineering Procurement and Construction Contract (“EPC”) with the Shaw Group Inc. (“Shaw”) to design, procure materials and equipment for, and construct the Harquahala generating facility. In addition, during July of 2001 Harquahala entered into a contract (the “Power Island Supply Contract”) with Siemens Westinghouse Power Corporation (Siemens), pursuant to which Siemens was to supply the thermal island equipment for the facility. The contract was subsequently assigned by Harquahala to Shaw, although Harquahala retained the obligation to make payments to Siemens following the assignment. Shaw directed Harquahala to withhold funds from Siemens. Siemens alleged that if Harquahala withheld such funds, it would be a default under the Power Island Supply Contract. When Harquahala declined to do so, Shaw alleged that such failure to withhold funds from Siemens as directed by Shaw constituted a breach of the EPC contract.
On November 13, 2002, Harquahala commenced an arbitration against Shaw seeking a declaration that it is not obligated to withhold payments from Siemens based upon Shaw’s alleged back charges or improperly documented warranty claims. Harquahala Generating Company, LLC v. The Shaw Group, Inc. et al., American Arbitration Association Case No. 161100085102. On or around December 4, 2002 Shaw filed a counterclaim for the value of certain change order requests. Shaw’s counterclaim seeks approximately $21.5 million and an extension of time by which to complete the facility. The most significant elements of the counterclaim are: a change order involving productivity losses that Shaw alleges resulted from the issuance by NEG of an 8-K in October detailing its financial condition; the acceleration of certain payments; a change order associated with the Siemens cover lift; and a change order associated with Siemens heat recovery steam generator assembly. The parties are now in the process of selecting arbitrators.
In a related proceeding, on January 6, 2003, Siemens commenced an arbitration proceeding against Harquahala seeking payment of approximately $5 million allegedly due under its July 2001 agreement with Harquahala to supply the thermal island equipment for its facility, plus all additional amounts that subsequently became due but are not paid as well as interest and arbitration costs and fees. Siemens Westinghouse Power Corporation Harquahala Generating Company, LLC, American Arbitration Association. Harquahala has withheld the amounts from Siemens at the direction of Shaw, to which the contract was assigned, based on Shaw’s assertion that Siemens has failed to perform in accordance with the terms of its July 2001 contract. The parties have agreed, in principle, to consolidate the proceedings.
On August 13, 2001, Covert Generating Company signed an EPC contract with Shaw respecting the Covert generating facility. On November 27, 2002, Shaw commenced an arbitration against Covert Generating Company claiming that it was entitled to approximately $23.6 million for certain change order requests. The Shaw Group Inc., et al. v. Covert Generating Company, LLC, American Arbitration Association Case No. 16Y1100090602. In addition, Shaw is also seeking an extension of time to complete the project. The parties are now in the process of selecting arbitrators.
At the time Harquahala and Covert signed their EPC contracts with Shaw, NEG Construction Finance Company, LLC (“CFC”) and PG&E NEG entered into related agreements pertaining to, among other things, the sharing of cost overruns in connection with the Covert and Harquahala facilities. On December 13, 2002, Shaw filed a lawsuit against each of these two parties as well as Harquahala and Covert. The Shaw Group, Inc. et al. v. PG&E National Energy Group, Inc., et al., United States District Court for the District of Delaware, Case No. 02-1676 GMS. Shaw alleges in its complaint that it has not received adequate assurances of payments from defendants and it seeks a declaration that, among other things, it is relieved of its obligations to perform under the EPC contracts and its agreements with CFC and PG&E NEG. Along with its complaint, Shaw filed a Motion for Expedite Declaratory and Injunctive Relief. At the end of December 2002, defendants filed oppositions to Shaw’s motion as well as motions to dismiss Shaw’s complaints. In addition, Societe Generale (as administrative agent for the project lenders) has filed a Motion to Intervene and a separate Opposition to Shaw’s Motion. On February 11, 2003, Shaw amended its complaint to seek to prevent PG&E NEG and its affiliates from turning over to the lenders the Covert and Harquahala projects, which turnover is one component of PG&E NEG’s restructuring. The court has not yet ruled on any of these matters.
Due to the recent deterioration of PG&E NEG’s financial condition, PG&E NEG believes that the ultimate outcome of all of this litigation may have a material adverse effect on PG&E NEG’s financial condition or results of operations.
NOTE 5: DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE
USGen New England - In September 1998, USGen New England, Inc. (USGenNE) acquired the non-nuclear generating assets of the New England Electric System (NEES) for approximately $1.8 billion. These assets included:
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2,344 megawatts (MW) of coal and oil fired power plants in Massachusetts;
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1,166 MW of hydroelectric facilities in New Hampshire, Vermont and Massachusetts;
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495 MW of gas-fired power plants in Rhode Island;
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above-market power purchase agreements with support payments provided by NEES for the first nine years;
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gas pipeline transportation contracts; and
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transition wholesale load contracts known as Standard Offer Agreements.
Consistent with its previously announced strategy to dispose of certain merchant assets, in December 2002, the Board of Directors of PG&E Corporation approved management’s plans for the proposed sale of USGenNE. Under the provisions of SFAS No. 144, the equity of USGenNE has been accounted for as an asset held for sale at December 31, 2002. This requires that the asset be recorded at the lower of fair value, less costs to sell, or book value. Based on the current estimated fair value (based on the estimated proceeds) of a sale of USGenNE, PG&E NEG recorded a pretax loss of $1.1 billion, with no tax benefits associated with the loss, in the fourth quarter of 2002. It is anticipated that the sale of the USGenNE assets will occur during 2003. This loss on sale as well as the operating results from USGenNE is being reported as discontinued operations in the Consolidated Financial Statements of PG&E NEG and subsidiaries for the year ended December 31, 2002.
Mountain View - On September 17 and 28, 2001, PG&E NEG purchased Mountain View Power Partners, LLC and Mountain View Power Partners II, LLC, respectively (collectively referred to as Mountain View). These companies own 44 and 22 megawatt wind energy projects, respectively, near Palm Springs, California. PG&E NEG contracted with SeaWest for the operation and maintenance of the wind units. Total consideration for these two companies was $92 million. The two companies were merged on October 1, 2002. The power is sold to the California Department of Water Resources (DWR) under a 10-year contract.
In December 2002, the Board of Directors of PG&E Corporation approved the sale of Mountain View. On December 18, 2002, a subsidiary of PG&E NEG entered into an agreement to sell Mountain View to Centennial Power, Inc. for $102 million. The sale occurred on January 3, 2003.
Under the provisions of SFAS No. 144 Mountain View is accounted for as an asset held for sale at December 31, 2002. This requires that the asset be recorded at the lower of fair value less costs to sell or book value. Based upon the current estimated proceeds of the sale of Mountain View, PG&E NEG will record an immaterial gain in the first quarter of 2003. The operating results from Mountain View are being reported as discontinued operations in the Consolidated Financial Statements of PG&E NEG and subsidiaries at December 31, 2002.
ET Canada - In December 2002, the proposed sale of PG&E Energy Trading, Canada Corporation (ET Canada) to Seminole Gas Company Limited was approved. Based upon the sales price, PG&E Energy Trading Holdings Corporation, the direct owner of shares of ET Canada, recorded a $25 million pretax loss, with no tax benefits associated with the loss, on the disposition of ET Canada. The transaction is anticipated to close by the end of February or early March 2003. Under the provisions of SFAS No. 144, the assets and liabilities of ET Canada have been classified as assets held for sale and reflected as discontinued operations in the Consolidated Financial Statements of PG&E NEG and subsidiaries as of December 31, 2002.
The following table reflects the operating results of the combined USGenNE, Mountain View and ET Canada before reclassification to discontinued operations for the years ended December 31, 2002, 2001, and 2000 (in millions):
The following table reflects the components of assets and liabilities held for sale of the combined USGenNE, Mountain View and ET Canada before reclassification to discontinued operations at December 31, 2002 and 2001 (in millions):
Included in the assets and liabilities held for sale summary above, are certain amounts paid to USGenNE related to the assumption of power supply agreements and certain purchase obligations assumed by USGenNE from the acquisition that occurred in 1998. These are more fully explained and detailed below.
(1) Includes impairment charges made against property, plant and equipment as further discussed in Note 6: Impairments, Write-offs and Other Charges.
(2) USGenNE receives payments from a wholly owned subsidiary of NEES, related to the assumption of power supply agreements, which are payable monthly through January 2008. The long-term receivables are valued at the present value of the scheduled payments using a discount rate that reflects NEES’ credit rating on the date of acquisition.
(3) Commitments contained in the underlying Power Purchase Agreements (PPAs) by USGenNE, gas commodity and transportation agreements (collectively, the Gas Agreements), and Standard Offer Agreements, acquired by USGenNE in September 1998, were recorded at fair value, based on management’s estimate of either or both the gas commodity and gas transportation markets and electric markets over the life of the underlying contracts, discounted at a rate commensurate with the risks associated with such contracts. Standard Offer Agreements reflect a commitment to supply electric capacity and energy necessary for certain affiliates to meet their obligations to supply fixed-rate service. PPAs and Gas Agreements are amortized on a straight-line basis over their specific lives. The Standard Offer Agreements are amortized using an accelerated method since the decline in value is greater in earlier years due to increasing contract pricing terms designed to reduce demand for our supply service over time.
Discontinued Operations of Energy Services - In December 1999, PG&E Corporation’s Board of Directors approved a plan to dispose of PG&E Energy Services (PG&E ES), its wholly owned subsidiary, through a sale. The disposal has been accounted for as a discontinued operation and PG&E NEG’s investment in ES was written down to its estimated net realizable value. In addition, PG&E NEG provided a reserve for anticipated losses through the date of sale. In 2000, $31 million (net of taxes) of actual operating losses were charged against the reserve. During the second quarter of 2000, PG&E NEG finalized the transactions related to the disposal of the energy commodity portion of PG&E ES for $20 million, plus net working capital of approximately $65 million, for a total of $85 million. In addition, a portion of the PG&E ES business and assets was sold on July 21, 2000, for a total consideration of $18 million. For the year ended December 31, 2000, an additional loss of $40 million, which includes an income tax benefit of $36 million, was recorded as actual losses in connection with the disposal, which exceeded the original 1999 estimate. The principal reason for the additional loss was due to the mix of assets, and the structure and timing of the actual sales agreements, as opposed to the one reflected in the initial provision established in 1999. In addition, the worsening energy situation in California also contributed to the actual loss incurred.
NOTE 6: IMPAIRMENTS, WRITE-OFFS AND OTHER CHARGES
The following is a summary of Impairments, Write-offs and Other Charges incurred by PG&E NEG during 2002 (in millions):
Impairment of GenHoldings Projects: GenHoldings, an indirect subsidiary of PG&E NEG, is obligated under its credit facility to make equity contributions to fund construction of the Harquahala, Covert and Athens generating projects. This credit facility is secured by these projects in addition to the Millennium generating facility. GenHoldings defaulted under its credit agreement in October 2002, by failing to make equity contributions to fund construction draws for the Athens, Harquahala and Covert generating projects. Although PG&E NEG has guaranteed GenHoldings’ obligations to make equity contributions of up to $355 million, PG&E NEG notified the GenHoldings’ lenders that it would not make further equity contributions on behalf of GenHoldings. In November and December 2002, the lenders executed waivers and amendments to the credit agreement under which they agreed to continue to waive, until March 31, 2003, the default caused by GenHoldings’ failure to make equity contributions. In addition, certain of these lenders have agreed to increase their loan commitments to an amount intended to be sufficient to provide: (i) the funds necessary to complete construction of the Athens, Covert and Harquahala facilities under the construction contracts; and (ii) additional working capital facilities to enable each project, including Millennium, to timely pay for its fuel requirements and to provide its own collateral to support natural gas pipeline capacity reservations and independent transmission operator requirements. The November and December increased loan commitments rank equally with each other but are senior to amounts loaned through and including the October credit extension.
In consideration of the lenders’ forbearance and additional funding, PG&E NEG and GenHoldings have agreed to cooperate with any reasonable proposal by the lenders regarding disposition of the equity in or assets of any or all of the GenHoldings subsidiaries holding the Athens, Covert, Harquahala and Millennium projects in connection with the restructuring of PG&E NEG’s and its subsidiaries’ financial commitments to such lenders. The amended credit agreement provides that an event of default will occur if the Athens, Covert, Harquahala and Millennium projects are not transferred to the lenders or their designees on or before March 31, 2003. Such a default would trigger lender remedies, including the right to foreclose on the projects. Under the waiver, PG&E NEG has re-affirmed its guarantee of GenHoldings’ obligation to make remaining equity contributions of approximately $355 million to these projects. Neither PG&E NEG nor GenHoldings currently expects to have sufficient funds to make this payment. The requirement to pay $355 million remains an obligation of PG&E NEG that would survive the transfer of the projects.
In accordance with the provisions of SFAS No. 144, the long-lived assets of GenHoldings at December 31, 2002 were tested for impairment. As a result of the test, the assets were determined to be impaired and were written-down to fair value. Based on the current estimated fair value of these assets, GenHoldings recorded a pre-tax loss from impairment of $1.147 billion in the fourth quarter of 2002.
Impairment of Lake Road and LaPaloma Projects: On November 14, 2002, PG&E NEG defaulted under its equity commitment guarantees for the Lake Road and the La Paloma credit facilities. On December 4, 2002, PG&E NEG subsidiaries entered into agreements with respect to each of the Lake Road and La Paloma generating projects providing for: (i) funding of construction costs required to complete the La Paloma facility; and (ii) additional working capital facilities to enable each subsidiary to timely pay for its fuel requirements and to provide its own collateral to support natural gas pipeline capacity reservations and independent transmission system operator requirements, as well as for general working capital purposes. Lenders extending new credit under these agreements have received liens on the projects that are senior to the existing lenders’ liens.
The Lake Road and La Paloma projects have been financed entirely with debt. PG&E NEG has guaranteed the repayment of a portion of the project subsidiary debt of approximately $230 million for Lake Road and $375 million for La Paloma, which amounts represent the subsidiaries’ equity contributions in the projects. The lenders have demanded the immediate payment of these equity contributions. Neither the PG&E NEG subsidiaries nor PG&E NEG have sufficient funds to make these payments. The requirement to make the payments will remain an obligation of PG&E NEG that would survive the transfer of the projects.
In consideration of the lenders’ forbearance and additional funding, PG&E NEG has agreed to cooperate with any reasonable proposal by the lenders regarding disposition of the equity in or assets of any or all of the PG&E NEG subsidiaries holding the La Paloma project in connection with the restructuring of PG&E NEG’s financial commitments. In addition, it is a default under the financing agreements for the projects if Lake Road or La Paloma do not transfer the projects to their lenders or the lenders’ designees on or before June 9, 2003.
In accordance with the provisions of SFAS No. 144, the long-lived assets of the Lake Road and La Paloma project subsidiaries at December 31, 2002, were tested for impairment. As a result of the test, these assets were determined to be impaired and were written down to fair value. Based on the current estimated fair value of these assets, the Lake Road and La Paloma project subsidiaries recorded a pretax loss from impairment of approximately $186 million for Lake Road and $266 million for La Paloma in the fourth quarter of 2002.
Impairment of Mantua Creek Project: The Mantua Creek project is a nominal 897 MW combined cycle merchant power plant located in the Township of West Deptford, New Jersey. Construction began in October 2001 and the project was 24 percent complete as of October 31, 2002. Due to liquidity concerns, PG&E NEG could no longer provide equity contributions to the project and efforts to sell the project were unsuccessful. Beginning in the fourth quarter of 2002, contracts with vendors were suspended or terminated to eliminate an increase in project costs. In December 2002, the project provided notices of termination to the Pennsylvania, New Jersey and Maryland Independent System Operator (PJM) and other significant counterparties. With all significant contracts terminated, PG&E NEG’s subsidiary will abandon this project in early 2003. PG&E NEG’s subsidiary has written off the capitalized development and construction costs of $257 million at December 31, 2002. In addition, PG&E NEG has recorded an accrual of $22 million for charges and associated termination costs at December 31, 2002.
Impairment of Turbines and Other Related Equipment: To support PG&E NEG’s electric generating development program, a subsidiary of PG&E NEG had contractual commitments and options to purchase a significant number of combustion turbines and related equipment. A subsidiary of PG&E NEG had a commitment to purchase combustion turbines and related equipment exceeded the new planned development activities. In the second quarter of 2002, PG&E NEG recognized a pretax charge of $246 million. The charge consisted of the impairment of the previously capitalized costs associated with prior payments made under the terms of the turbine and equipment contracts in the amount of $188 million and an accrual of $58 million for future termination payments required under the turbine and related equipment contracts. In addition, at that time, PG&E NEG retained capitalized prepayment costs associated with three development projects that were to be further developed or sold. Along with the impairment of these development projects in the fourth quarter of 2002, PG&E NEG incurred an additional pretax charge of $30 million associated with the write-off of prior prepayments.
In November 2002, subsidiaries of PG&E NEG reached agreement with General Electric Company (GEC) to terminate its master turbine purchase agreement and with General Electric International, Inc. (GEII) to terminate its master long-term service agreement. GEC and GEII were paid a portion of the termination fees and reduced the remaining termination fees to approximately $22 million and deferred payment of the reduced fees to December 31, 2004. The costs to terminate this contract were accrued for in the second quarter of 2002.
Also in November 2002, Mitsubishi Power Systems, Inc. (MPS) notified PG&E NEG’s subsidiary that it was terminating its turbine purchase agreement for failure to pay past due amounts and failure to collateralize PG&E NEG’s guarantee. While PG&E NEG’s subsidiary has disputed that such amounts were due before January and July 2003 and has asserted that a breach under PG&E NEG’s guarantee did not give rise to a breach of the turbine purchase agreement, neither PG&E NEG nor its subsidiary intends to contest the termination. The costs to terminate this contract were accrued in the second quarter of 2002 . On January 31, 2003, a termination payment of $4.5 million was made, with the remaining amount of $9.5 million expected to be paid in July 2003.
Termination of Interest Rate Swaps on Lake Road, La Paloma and GenHoldings Projects: As a result of the Lake Road and La Paloma project subsidiaries’ failure to make required equity payments under the interest rate hedge contracts entered into by them, the counterparties to such interest rate hedge contracts have terminated the contracts. Settlement amounts due from the Lake Road and La Paloma project subsidiaries in connection with such terminated contracts are, in the aggregate, $61 million for Lake Road and $78 million for La Paloma. These amounts have been rolled into the debt existing prior to December 11, 2002 and have, therefore been likewise accelerated.
As a result of GenHoldings’ failure to make required payments under the interest rate hedge contracts entered into by GenHoldings, the counterparties to such interest rate hedge contracts terminated the contracts during December 2002. Settlement amounts due by GenHoldings in connection with such terminated contracts are, in the aggregate, approximately $50 million. The La Paloma and Lake Road project subsidiaries and GenHoldings incurred a pretax charge to earnings in the fourth quarter of 2002 for settlement amounts connected with terminated interest rate hedge contracts, totaling $189 million.
Impairment of Dispersed Generation: PG&E NEG is seeking a buyer for PG&E Dispersed Generation LLC, Plains End LLC, Dispersed Properties, LLC and 100 percent of the capital stock of Ramco, Inc. (collectively referred to as Dispersed Gen Companies or Dispersed Generation). In accordance with the provisions of SFAS No. 144, the long-lived assets of the Dispersed Gen Companies were tested for impairment. As a result of the test, these assets were determined to be impaired and were written-down to fair value. Based on the current estimated fair value (based on the estimated proceeds) of a sale, Dispersed Generation recorded a pretax loss from impairment of $88 million in the fourth quarter of 2002. This is in addition to a pretax loss from impairment of $30 million that was recorded in the third quarter of 2002 which related to certain equipment (turbines, generators, transformers, etc.) that was purchased and or refurbished and held for future expansion at current Dispersed Generation facilities.
Impairment of Goodwill: SFAS No. 142 requires that goodwill be reviewed at least annually for impairment. Due to significant adverse changes within the national energy markets, PG&E NEG and its subsidiaries tested its goodwill for possible impairment in the third quarter of 2002. Based upon the results of the fair value test, PG&E NEG recognized a goodwill impairment loss of $95 million in the third quarter of 2002. The fair value of the segment was estimated using the discounted cash flows method. At December 31, 2002, there is no goodwill remaining at PG&E NEG and its subsidiaries.
Impairment of Development Costs: In the second quarter of 2002, PG&E NEG recognized an impairment loss related to the capitalized costs associated with certain development projects. PG&E NEG analyzed the potential future cash flows from those projects that it no longer anticipated developing and recognized an impairment of the asset carrying value for those projects. The aggregate pre-tax impairment charge recorded by PG&E NEG for its development assets (excluding associated equipment) was $19 million recorded in the second quarter of 2002. At that time, PG&E NEG continued to develop or planned to sell three additional projects. PG&E NEG has now ceased developing these projects and sought to sell the development assets. To date, PG&E NEG has been unsuccessful in selling these projects. PG&E NEG tested the capitalized costs associated with the projects for impairment at December 31, 2002. Based on the results of these tests, an additional aggregate pre-tax impairment charge of approximately $57 million was recorded by PG&E NEG for its development assets (excluding associated equipment costs as discussed above) in the fourth quarter of 2002. While PG&E NEG has impaired all of its development projects, it has not abandoned the permits or rights to these projects. It is anticipated that PG&E NEG will abandon all development projects permits and rights in 2003.
Impairment of Southaven Loan Receivable: PG&E ET signed a tolling agreement with Southaven Power, LLC (Southaven) dated June 1, 2000, pursuant to which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing an investment-grade guarantee from PG&E NEG. The original maximum amount of the guarantee was $250 million. However, this amount was reduced by approximately $74 million, the amount of a subordinated loan that PG&E ET made to Southaven on August 31, 2002.
Southaven has advised PG&E ET that it believes an event of default under the tolling agreement has taken place with respect to the obligation for a guarantee because PG&E NEG is no longer investment-grade as defined in the agreement and because PG&E ET has failed to provide within thirty days from the downgrade substitute credit support that meets the requirements of the agreement. Under the tolling agreement, Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Southaven with a notice of default respecting Southaven’s performance under the tolling agreement. If this default is not cured, PG&E ET has the right to terminate the tolling agreement and seek recovery of a termination payment. On February 4, 2003, PG&E ET provided a notice of termination. Southaven has objected to the notice and has filed suit in connection with this matter. PG&E ET has recorded an impairment of the loan receivable due to the uncertainty associated with the recoverability of the loan which was subordinate to the senior debt of the project and reliant upon operations of the plant under the terms of the tolling agreement.
Impairment of Prepaid Rents on Attala Lease: On May 7, 2002, Attala Generating Company, LLC (Attala Generating), an indirect wholly owned subsidiary of PG&E NEG, completed a $340 million sale and leaseback transaction whereby it sold and leased back its approximately 526 MW generation facility located in Mississippi to a third-party special purpose entity.
PG&E NEG has provided a $300 million guarantee to support the payment obligations of another indirect wholly owned subsidiary, Attala Energy Company, LLC (Attala Energy), under a tolling agreement entered into with Attala Generating. The payments under the 25-year term tolling agreement provide Attala Generating, as lessee, with sufficient cash flows during the term of the tolling agreement to pay rent under a 37-year lease and certain other operating costs. Due to current energy market conditions, Attala Energy is unable to make the payments under the tolling agreement and failed to make the required payment due on November 27, 2002 to Attala Generating. Failure to cure this payment default constituted an event of default under the tolling agreement. Further, PG&E NEG’s failure to pay maturing principal under its Corporate Revolver on November 14, 2002 became an event of default under the tolling agreement upon Attala Energy’s failure to replace the PG&E NEG guarantee by December 16, 2002. On December 31, 2002, the tolling agreement was terminated following notice of termination given by Attala Generating. The parties are currently determining the termination payment, if any, that Attala Energy would owe Attala Generating. Despite the termination of the tolling agreements, Attala Energy remains obligated to provide an acceptable guarantee or collateral to secure its obligations under the tolling agreement including the payment of any termination payment that may be determined to be due.
No default has occurred under the related lease and Attala Generating timely made the $22 million lease payment due on January 2, 2003. However, the lease provides that failure to replace the tolling agreement with a satisfactory replacement tolling agreement within 180 days after the first default under the tolling agreement, which occurred on November 27, 2002, will constitute an event of default under the lease. After the termination payment has been determined in accordance with the tolling agreement and if Attala Energy or PG&E NEG both fail to provide security as required by the tolling agreement, the time period would not extend beyond the 60th day after such failure to provide security. Upon the occurrence of an event of default under the lease, the lessor would be entitled to exercise various remedies, including termination of the lease and foreclosure of the assets securing the lease. At December 31, 2002, PG&E NEG wrote off prepaid rental payments of $43 million due to the uncertainty of future cash flows associated with the lease.
Impairment of Kentucky Hydro: The Kentucky Hydro generating project consists of two run-of-river hydroelectric power plants (Smithland Hydroelectric and Cannelton Hydroelectric) on the Ohio River. A PG&E NEG subsidiary owned interests in the project companies owning the hydroelectric facilities. The project owners negotiated a turnkey, fixed price contract with VA Tech MCE Corporation (VA Tech) and issued a limited notice to proceed in August 2001. Beginning in the fourth quarter of 2002, all work on the project was suspended except for minimal expenditures to maintain FERC licenses and the construction contracts were terminated. The termination cost due to VA Tech of approximately $14 million was fully paid. As a part of the settlement of its partnership arrangements, PG&E NEG assigned its interest in the project companies to the original developer, DJL Corporation for Smithland Hydroelectric and W.V. Hydro for Cannelton Hydroelectric, on February 7, 2003. PG&E NEG abandoned its partnership interest as of such date. PG&E NEG has impaired the capitalized development and construction costs and provided for all termination costs by recording a pretax charge of $18 million at December 31, 2002.
NOTE 7: COSTS INCURRED IN AN ORGANIZATIONAL RESTRUCTURING
In the third and fourth quarters of 2002, PG&E NEG initiated a restructuring effort in order to adopt a new organizational structure that more closely reflects PG&E NEG’s business strategies. The termination benefits accrued and charged to earnings during 2002 were $13 million and are principally included in “Administrative and general” in the operating expenses of PG&E NEG’s Consolidated Statements of Operations. To date there have been 247 employees who are affected by this restructuring of which 228 were terminated as of December 31, 2002 (the remaining 19 employees will be affected within one year). As of December 31, 2002 the remaining liability associated with future payments of termination benefits is $4 million. All employee groups were impacted by this restructuring. The following table summarizes the activity related to accrued severance costs by quarter in 2002 (in millions):
In addition to these termination costs, PG&E NEG accrued and charged to earnings $26 million due to the closing of certain regional offices associated with project development and other third party costs, such as legal and financial advisors, related to the organizational restructuring efforts. These costs are included in the operating expenses of PG&E NEG’s Consolidated Statements of Operations in the year ended 2002.
NOTE 8: ACQUISITIONS AND DISPOSALS
Sale of Interest in Hermiston - On November 4, 2002, affiliates of PG&E NEG entered into an agreement to sell 49.9 percent of their ownership interest in Hermiston Generating Company, L.P. (HGC) to Sumitomo Corporation and Sumitomo Corporation of America. The buyer was granted an option to purchase, during the three month period beginning thirteen months immediately following the closing date, an additional 0.1 percent interest (at the fair market value at the date of exercise) in HGC. HGC owns an undivided 50 percent interest in a 474 MW gas-fired generating plant in Hermiston, Oregon. The other 50 percent is owned by PacifiCorp which also purchases the output of the plant under a long-term contract. The sale was completed on December 20, 2002, following the receipt of necessary regulatory approvals. PG&E NEG received $46 million
in proceeds for the sale of HGC resulting in a pre-tax $11 million gain, after the sale of a net investment balance of $25 million and reversal of Other Comprehensive Income of $10 million. Gain from the sale of HGC is included in other operating expenses. Prior to this sale of partnership interest, PG&E NEG owned 100 percent of this partnership and was fully consolidating HGC into its results.
Sale of Development Assets - On July 10, 2001, PG&E NEG completed the sale of certain development assets, resulting in a pre-tax gain of $23 million.
Purchase and Closing of Spencer Station - On June 29, 2001, PG&E ET contracted to supply the full service power requirements of the city of Denton, Texas, for a period of five years beginning July 1, 2001. PG&E ET’s supply obligation to the city was net of approximately 97 mw of generation entitlements retained by the city, plus 40 mw of purchased power that the city had assigned to PG&E ET for the summer of 2001. Another affiliate of PG&E NEG acquired a 178 mw generating station and small hydroelectric facility from the city. The total consideration was approximately $12 million for this transaction.
On November 5, 2002, PG&E NEG announced its plan to shut down its Spencer Station generating plant located in Denton, Texas. However, PG&E NEG did not shut down Spencer Station and instead sold Spencer Station to the City of Garland on February 13, 2003. In addition, PG&E ET has sold its obligation to supply the full service power requirements of the City of Denton. Based on the current fair value (based on the proceeds) of a sale of the Spencer Station plant, PG&E NEG will record an immaterial gain in the first quarter of 2003.
Purchase of Attala - On September 28, 2000, PG&E NEG purchased for $311 million Attala Generating Company, LLC, which owns a gas-fired power plant that was under construction. Under the purchase agreement, PG&E NEG prepaid the estimated remaining construction costs, which were being managed by the seller. The project, which was approximately 82% complete as of December 31, 2000, began commercial service in June 2001. In connection with the acquisition, PG&E NEG also assumed industrial revenue bonds issued by the Mississippi Business Finance Corporation in the amount of $159 million, under an agreement that the seller would pay off the bonds. Accordingly, a $159 million receivable was recorded. At December 31, 2001, the seller had paid off the bonds. See Note 6 for a current status of this facility.
Sale of GTT - On January 27, 2000, PG&E NEG signed a definitive agreement with El Paso Field Services Company (El Paso) providing for the sale of the stock of GTT to El Paso, a subsidiary of El Paso Energy Corporation. On December 22, 2000, after receipt of governmental approvals, PG&E NEG completed the stock sale. The total consideration received was $456 million, less $150 million used to retire the GTT short-term debt, and the assumption by El Paso of GTT’s of long-term debt having a book value of $564 million.
The following table reflects GTT’s results of operations included in PG&E NEG’s Consolidated Statements of Operations for the year ended December 31, 2000 (in millions):
NOTE 9: INVESTMENTS IN UNCONSOLIDATED AFFILIATES
PG&E NEG has non-controlling investments in various power generation and other energy projects. The equity method of accounting is applied to such investments in affiliated entities, which include corporations, joint ventures and partnerships, due to the ownership structure preventing PG&E NEG from exercising control. Under this method, PG&E NEG’s share of equity income or losses of these entities is reflected as equity in earnings of affiliates.
Operating entities which PG&E NEG does not control are as follows ($ in millions):
(a)
See discussion of the sale of interest in Hermiston in Note 8 above. Prior to the sale of interest in HGC, PG&E NEG consolidated the results of HGC’s operations. As a result of the sale, PG&E NEG no longer exerts a substantive ability to control the partnership and as such, as of the date of sale and going forward, PG&E NEG uses the equity method of accounting.
(b)
The value of the company’s investment has been recorded to zero. See Note 1, “Accounting for Certain Derivative Contracts”
(c)
On May 4, 2001 the Company purchased an additional 0.84% interest in Iroquois Gas Transmission.
Net gains from the sale of interests in unconsolidated affiliates were $21 million during 2000. Amounts are included in other operating expenses. There were no sales of unconsolidated affiliates in 2002 and 2001.
The following table sets forth summarized financial information of PG&E NEG’s investments in affiliates accounted for under the equity method for the years ended December 31, 2002, 2001, and 2000 (in millions):
The reconciliation of the PG&E NEG’s share of equity to investment balance is as follows (in millions):
The purchase premium over book value is being amortized over periods ranging from 16 to 35 years and is recorded through amortization expense. The yearly purchase premium amortization expenses were $7 million in 2002, $7 million in 2001, and $7 million in 2000.
NOTE 10: PREFERRED STOCK OF SUBSIDIARY
Preferred stock consists of $58 million of preferred stock issued by a subsidiary of PG&E NEG that owns an interest in the Cedar Bay Project. The preferred stock, with $100 par value, has a stated non-cumulative dividend of $3.35 per share, per quarter, and is redeemable when there is an excess of available cash. There were 549,594 shares outstanding at December 31, 2002 and 2001.
NOTE 11: PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
As previously discussed, PG&E NEG is in the process of reducing and unwinding its trading positions. Additionally, asset hedge positions associated with the merchant plants will either remain with the assets or be terminated. PG&E NEG has significantly reduced its energy trading operations in an ongoing effort to raise cash and reduce debt. PG&E NEG’s objective is to limit its asset trading and risk management activities to only what is necessary for energy management services to facilitate the transition of PG&E NEG’s merchant generation facilities through their sale, transfer or abandonment process. PG&E NEG will then further reduce and transition to only retain limited capabilities to ensure fuel procurement and power logistics for PG&E NEG’s retained independent power plant operations.
Non-Trading Activities
At December 31, 2002, PG&E NEG had cash flow hedges of varying durations associated with commodity price risk, interest rate risk and foreign currency risk, the longest of which extend through December 2011, March 2014, and December 2004, respectively.
The amount of commodity hedges included in Accumulated Other Comprehensive Income or Loss (OCI), net of taxes, at December 31, 2002, was a loss of $27 million. The amount of interest rate hedges included in OCI, net of taxes, at December 31, 2002, was a loss of $61 million. The amount of foreign currency hedges included in OCI, net of taxes, at December 31, 2002, was a loss of $2 million.
PG&E NEG’s net derivative losses included in OCI at December 31, 2002, were $90 million, of which approximately $70 million is expected to be reclassified to earnings within the next 12 months based on the contractual terms of the contracts or the termination of the hedge positions. The actual amounts reclassified from OCI to earnings will differ as a result of market price changes.
The schedule below summarizes the activities affecting accumulated other comprehensive income (loss), net of tax, from derivative instruments (in millions):
For most non-trading activities, earnings are recognized on an accrual basis as revenues are earned and as expenses are incurred. Thus, most non-trading activities do not affect earnings on a mark-to-market basis. For example, the effective portion of contracts accounted for as cash flow hedges have no mark-to-market effect on earnings; these contracts are presented on a mark-to-market basis on the balance sheet in PRM assets and liabilities and OCI. Other non-trading contracts are exempt from the SFAS No. 133 fair value requirements under the normal purchases and sales exception and thus have no mark-to-market effect on earnings.
However, in a few instances non-trading activities affect PG&E NEG’s earnings on a mark-to-market basis. PG&E NEG recognizes the ineffective portion of the fair value of cash flow hedges in earnings. PG&E NEG also has certain derivative contracts which, while they are meant for non-trading purposes, do not qualify for cash flow hedge accounting or for the normal purchases and sales exception to SFAS No. 133. These derivatives are reported in earnings on a mark-to-market basis. These contracts primarily consist of those derivative commodity contracts for which normal purchases and sales treatment was disallowed upon PG&E NEG’s implementation of DIG C15 and C16 effective April 1, 2002 (see Note 1).
For the period ended December 31, 2002, the effects on pre-tax earnings of non-trading activities that are reflected in income on a mark-to-market basis are a $2 million loss on the ineffective portion of cash flow hedges; and a $203 million loss from earnings from discontinued cash flow hedges.
The $203 million pre-tax loss from discontinuance of cash flow hedges is primarily due to the interest rate hedges. Accounting hedge treatment was discontinued when certain PG&E NEG subsidiaries failed to make payments under their debt agreements and, therefore, the hedged transactions were no longer considered probable of occurrence. The $189 million loss in OCI relating to the interest rate hedges was reclassified to earnings, in accordance with the provisions of SFAS No. 133. (See further discussions in Note 3, GenHoldings Construction Facility and Lake Road and La Paloma Construction Facilities.) The remainder of the $203 million pre-tax loss relates to financial commodity hedges that were discontinued after the hedged transactions were no longer considered probable of occurrence. These comparative amounts for the years ended December 31, 2001 and 2000 are zero or immaterial.
Trading Activities
Unrealized gains and losses from trading activities, including the reversal of unrealized gains and losses previously recognized on contracts that go to settlement or delivery, are presented on a net basis in operating revenues. Realized gains and losses from trading activities also are presented on a net basis in operating revenues, beginning in the third quarter of 2002, as more fully described in Note 1.
Gains and losses on trading contracts affect PG&E NEG’s gross margin in the accompanying PG&E NEG Consolidated Statements of Income on an unrealized, mark-to-market basis as the fair value of the forward positions on these contracts fluctuate. Settlement or delivery on a contract is generally not an event that results in incremental net income recognition, because the profit or loss on a contract is recognized in income on an unrealized, mark-to-market basis during the periods before settlement occurs.
Gains and losses on trading contracts affect PG&E NEG’s cash flow when these contracts are settled. Net realized gains reported in the table below primarily reflect the net effect of contracts that have been settled in cash. Net realized gains also include certain non-cash items, including amortization of option premiums that were paid or received in cash in earlier periods but are considered realized when the related options are exercised or expire.
PG&E NEG’s net gains (losses) on trading activities are as follows:
See Note 1 for a discussion of the rescission of EITF 98-10, which impacted the accounting for trading activities.
Price Risk Management Assets and Liabilities
PRM assets and liabilities on the accompanying PG&E NEG Consolidated Balance Sheets reflect the aggregation of the fair values of outstanding contracts. These fair values are calculated on a mark-to-market basis for contracts that will be settled in future periods. PRM assets and liabilities at December 31, 2002, include amounts for trading and non-trading activities, as described below.
Non-trading activities include certain long-term contracts that are not included in PG&E NEG’s trading portfolio but that, due to certain pricing provisions and volumetric variability, are unable to receive hedge accounting treatment or the normal purchases and sales exception, as outlined by interpretations of SFAS No. 133. PG&E NEG has certain other non-trading derivative commodity contracts for the physical delivery of purchases and sales quantities transacted in the normal course of business. These other non-trading activities include contracts that are exempt from SFAS No. 133 fair value requirements under the normal purchases and sales exemption, as described previously. Although the fair value of these other non-trading contracts is not required to be presented on the balance sheet, revenues and expenses generally are recognized in income using the same timing and basis as are used for the non-trading activities accounted for as cash flow hedges. Hence, revenues are recognized as earned and expenses are recognized as incurred.
Credit Risk
Credit risk is the risk of loss that PG&E NEG would incur if counterparties failed to perform their contractual obligations (these obligations are reflected as Accounts receivable - Customers, net; notes receivable included in Other noncurrent assets - Other; PRM assets; and Assets held for sale on the balance sheet). PG&E NEG conducts business primarily with customers or vendors, referred to as counterparties, in the energy industry. These counterparties include other investor-owned utilities, municipal utilities, energy trading companies, financial institutions, and oil and gas production companies located in the United States and Canada. This concentration of counterparties may impact PG&E NEG’s overall exposure to credit risk because its counterparties may be similarly affected by economic or regulatory changes, or other changes in conditions.
PG&E NEG manages its credit risk in accordance with the PG&E Corporation Risk Management Policy. This establishes processes for assigning credit limits to counterparties entering into agreements with significant exposure to PG&E NEG. These processes include an evaluation of a potential counterparty’s financial condition, net worth, credit rating, and other credit criteria as deemed appropriate, and are performed at least annually.
Credit exposure is calculated daily and, in the event that exposure exceeds the established limits, PG&E NEG takes immediate action to reduce the exposure, or obtain additional collateral, or both. Further, PG&E NEG relies heavily on master agreements that require the counterparty to post security, referred to as credit collateral, in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.
PG&E NEG calculates gross credit exposure for each counterparty as the current mark-to-market value of the contract (that is, the amount that would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, prior to the application of the counterparty’s credit collateral.
In 2002, PG&E NEG’s credit risk increased due in part to downgrades of some counterparties’ credit ratings to levels below investment grade. The downgrades increase PG&E NEG’s credit risk because any collateral provided by these counterparties in the form of corporate guarantees or eligible securities may be of lesser or no value. Therefore, in the event these counterparties failed to perform under their contracts, PG&E NEG may face a greater potential maximum loss. In contrast, PG&E NEG does not face any additional risk if counterparties’ credit collateral is in the form of cash or letters of credit, as this collateral is not affected by a credit rating downgrade.
For the year ended December 31, 2002, PG&E NEG has recognized no losses due to the contract defaults or bankruptcies of counterparties. However, in 2001, PG&E NEG terminated its contracts with a bankrupt company, which resulted in a pre-tax charge to earnings of $60 million related to trading and non-trading activities, after application of collateral held and accounts payable.
At December 31, 2002, PG&E NEG had no single counterparty that represented greater than 10 percent of PG&E NEG’s net credit exposure. At December 31, 2001, PG&E NEG had one below investment grade counterparty that represented 10 percent of PG&E NEG’s net credit exposure, with a net credit exposure amount of $85 million.
The schedule below summarizes PG&E NEG’s credit risk exposure to counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange provides for contract settlement on a daily basis), at December 31, 2002, and December 31, 2001:
(1)
Gross credit exposure equals mark-to-market value (adjusted for applicable credit valuation adjustments), notes receivable, and net (payables) receivables where netting is allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value, liquidity, or model.
(2)
Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit).
At December 31, 2002, approximately $172 million, or 21 percent of PG&E NEG’s net credit exposure was to entities that had credit ratings below investment grade. At December 31, 2001, approximately $237 million, or 27 percent of PG&E NEG’s net credit exposure was to entities that had credit ratings below investment grade. Investment grade is determined using publicly available information, i.e. rated at least Baa3 by Moody’s and BBB- by S&P. If the counterparty provides a guarantee by a higher rated entity (e.g., its parent), the credit rating determination is based on the rating of its guarantor. At December 31, 2002, approximately $65 million, or 8 percent of PG&E NEG’s net
credit exposure was with counterparties that were not rated. At December 31, 2001, none of PG&E NEG’s net credit exposure was with counterparties that were not rated. Most counterparties with no credit rating are governmental authorities which are not rated, but which PG&E NEG has assessed as equivalent to investment grade. Other counterparties with no credit rating are subject to an internal assessment of their credit quality and a credit rating designation.
PG&E NEG’s regional concentrations of credit exposure are to counterparties that conduct business primarily in the western United States and also to counterparties that conduct business primarily throughout North America.
NOTE 12: EMPLOYEE BENEFIT PLANS
Certain subsidiaries of PG&E NEG provide separate noncontributory defined benefit pension plans, and “Other Retirement Benefits” including contributory defined benefit medical plans, and noncontributory benefit life insurance plans for employees and retirees as set forth in the plan agreements.
The following table reconciles the plans’ funded status (the difference between fair value of plan assets and the related benefit obligation) to the accrued liability recorded on the Consolidated Balance Sheet as of and for the years ended December 31, 2002 and 2001 (in millions):
As of December 31, 2002 and 2001, the defined benefit pension plan for the employees of PG&E GTN had plan benefit obligations of $12 million while plan assets exceeded plan benefit obligations by $3 million as in December 31, 2002. The unrecognized net actuarial (gains) losses are amortized on a straight-line basis over the average remaining service period of active participants. The unrecognized net transition obligation for pension benefits and other benefits are being amortized over 20 years.
Net periodic benefit cost (income) was as follows (in millions):
The following actuarial assumptions were used in determining the plans’ funded status and net periodic benefit cost (income). For Other Retirement Benefits, the expected return on plan assets and rate of future compensation is for the plan held by PG&E GTN only, as the other plans are not funded. Year-end assumptions are used to compute funded status, while prior year-end assumptions are used to compute net benefit cost (income).
The 2003 assumed health care cost trend rate for benefits prior to age 65 and for benefits at age 65 and later, is approximately 10.5%, respectively, grading down to an ultimate rate in 2008 of approximately 5.5% for both age groups. The assumed health care cost trend rate can have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in millions):
Defined Contribution Plans - Employees of PG&E NEG are eligible to participate in several different defined contribution plans, as set forth by the specific subsidiary for which they work. The contribution percentages and employer contribution options are set forth in each specific plan ranging from 0% to 10% of the employee’s compensation. Employer contributions totaled approximately $14 million, $13 million, and $14 million for 2002, 2001, and 2000, respectively.
Regulatory Matters - In conformity with SFAS No. 71, regulatory adjustments for PG&E GTN have been recorded for the difference between pension cost determined for accounting purposes and that for ratemaking, which is based on a funding approach. FERC’s ratemaking policy with regard to Other Retirement Benefits provides for the recognition, as a component of cost-based rates, of allowances for prudently incurred costs of such benefits when determined on an accrual basis that is consistent with the accounting principles set forth in SFAS No. 106, Employers’ Accounting for Post-retirement Benefits Other Than Pensions, subject to certain funding conditions.
As required by FERC’s policy, PG&E GTN established irrevocable trusts to fund all benefit payments based upon a prescribed annual test period allowance of $2 million. To the extent actual SFAS No. 106 accruals differ from the annual funded amount, a regulatory asset or liability is established to defer the difference pending treatment in the next general rate case filing. Based upon this treatment, PG&E GTN had over collected $10 million at December 31, 2002 and $8 million at December 31, 2001. Plan assets consist primarily of common stock, fixed-income securities, and cash equivalents.
Long-term Incentive Program - Employees of PG&E NEG participate in PG&E Corporation’s Long-term Incentive Program (Program) that provides for grants of stock options to eligible participants with or without associated stock appreciation rights and dividend equivalents. The following disclosures relate to the PG&E NEG employees’ share of benefits under the program.
Fair values of options granted in 2002, 2001, and 2000 under the Black-Scholes valuation method are as follows:
Significant assumptions used in the Black-Scholes valuation method for shares granted in 2002, 2001 (two sets of assumptions), and 2000 were:
Outstanding stock options become exercisable on a cumulative basis at one-third each year commencing two years from the date of grant and expire ten years and one day after the date of grant. As of December 31, 2002, 9,265,698 options were outstanding of which 3,544,457 were exercisable.
In addition, 220,100 options were granted on January 2, 2003, at an option price of $14.61, the then-current market price of PG&E Corporation common stock.
In addition, certain employees of the PG&E NEG also participate in PG&E Corporation’s Performance Unit Plan (another component of the Program) that provides incentive compensation to participants based upon the year-end stock price of PG&E Corporation and a predetermined comparison group. For the years ended December 31, 2002, 2001, and 2000, the compensation expense under this program for PG&E NEG employees was $0.6 million, $0.3 million, and $0.3 million, respectively.
NOTE 13: INCOME TAXES
The significant components of income tax expense (benefit) from continuing operations were as follows (in millions):
The differences between income taxes and amounts determined by applying the federal statutory rate to income before income tax expenses for continuing operations were:
The significant components of net deferred income taxes were as follows (in millions):
NOTE 14: SEGMENT INFORMATION
PG&E NEG has two reportable operating segments, which were determined based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment, and how information is reported to PG&E NEG key decision makers. The first business segment is composed of PG&E NEG’s Integrated Energy and Marketing Activities, principally the generation and energy trading operations, which are managed and operated in an integrated manner. The second business segment is PG&E NEG’s Interstate Pipeline Operations.
Segment information for the years 2002, 2001, and 2000 was as follows (in millions):
(1)
Operating revenues and operating expenses reflect the adoption during 2002 of a new accounting policy implementing a change from gross to net method of reporting revenues and expenses on trading activities. The amounts for trading activities for the comparative periods in 2001 and 2000 have been reclassified to conform with the new net presentation.
(2)
Inter-segment revenues are recorded at market prices for services provided.
(3)
Includes PG&E NEG holding company costs, principally unallocated interest and fee related expense, elimination entries, and other miscellaneous ventures not associated with core business segments.
QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
INDEPENDENT AUDITORS’ REPORT
To the Board of Directors and Stockholder of
PG&E National Energy Group, Inc:
We have audited the accompanying consolidated balance sheets of PG&E National Energy Group, Inc. and subsidiaries (the “Company”) as of December 31, 2002 and 2001, and the related consolidated statements of operations, common stockholder’s equity (deficit), and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in Item 15, Schedule II. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We did not audit the financial statements of certain partnerships which are accounted for by the Company using the equity method. The Company’s equity of $105 million in the partnerships’ net assets at December 31, 2002, and $22 million of the partnerships’ net income for the year ended December 31, 2002 are included in the accompanying consolidated financial statements. The financial statements of the partnerships were audited by other auditors whose reports (one of which contains an explanatory paragraph relating to a partnership’s ability to continue as a going concern) have been furnished to us, and our opinion, insofar as it relates to the amounts included for such partnerships, is based solely on the reports of such other auditors. We also did not audit the financial statements of certain partnerships for the year ended December 31, 2001, which comprise the Company’s equity of $154 million in the partnerships’ net assets and $46 million in the partnerships’ net income, included in the accompanying consolidated financial statements as of, and for the year ended December 31, 2001. These financial statements have been audited by other auditors, who have ceased operations, and whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for such partnerships, is based solely on the reports of such other auditors.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of PG&E National Energy Group, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, based on our audits and the reports of other auditors, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1 of the Notes to the Consolidated Financial Statements, during 2002, the Company adopted new accounting standards to account for goodwill and intangible assets, impairment of long-lived assets, discontinued operations, and certain derivative contracts. Additionally, during 2002, the Company changed the method of reporting gains and losses associated with energy trading contracts from the gross method to the net method and retroactively reclassified the consolidated statements of operations for 2001 and 2000. During 2001, as discussed in Note 1 to the Consolidated Financial Statements, the Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and the Company adopted certain interpretations issued by the Derivatives Implementation Group of the Financial Accounting Standards Board.
The accompanying consolidated financial statements for the year ended December 31, 2002 have been prepared assuming the Company will continue as a going concern. As discussed in Notes 1 and 3 of the Notes to the Consolidated Financial Statements, the Company has defaulted on various debt and financing obligations. These matters raise substantial doubt about the ability of the Company to continue as a going concern. Management’s plans in regard to these matters are also described in Notes 1 and 3 of the Notes to the Consolidated Financial Statements. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
DELOITTE & TOUCHE LLP
McLean, Virginia
February 24, 2003
Report of Independent Auditors
The Boards of Control of
Chambers Cogeneration, L.P. and
Carney’s Point Generating Company, L.P.
We have audited the accompanying combined balance sheet of Chambers Cogeneration, L.P and Carneys Point Generating Company, L.P. as of December 31, 2002, and the related combined statements of income, partners’ capital, and cash flows for the year then ended. These financial statements are the responsibility of the Partnerships’ management. Our responsibility is to express an opinion on these financial statements based on our audit. The combined financial statements of Chambers Cogeneration, L.P. and Carneys Point Generating Company, L.P for the year ended December 31, 2001, were audited by other auditors who have ceased operations and whose report dated January 23, 2002, expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements referred to above present fairly, in all material respects, the combined financial position of Chambers Cogeneration, L.P. and Carneys Point Generating Company, L.P. at December 31, 2002, and the combined results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States.
February 24, 2003
Report of Independent Auditors
The Board of Control of
Cedar Bay Generating Company, L.P.
We have audited the accompanying balance sheet of Cedar Bay Generating Company, L.P. as of December 31, 2002 and the related statements of operations, changes in partners’ deficit and cash flows for the year then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Cedar Bay Generating Company, L.P. for the year ended December 31, 2001, were audited by other auditors who have ceased operations and whose report dated January 23, 2002 (except with respect to the matter discussed in Note 7, as to which the date was February 7, 2002), expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements referred to above present fairly, in all material respects, the financial position of Cedar Bay Generating Company, L.P. at December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States.
The accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. As more fully described in Note 1, the Partnership has incurred recurring operating losses, has a working capital deficiency and a partners’ capital deficit. In addition, the Partnership’s projections for 2003 reflect an inability to make certain debt payments under its Senior Debt Agreement when due. The Senior Lenders have reserved their rights and remedies under the Senior Debt Agreement. These conditions raise substantial doubt about the Partnership’s ability to continue as a going concern. The financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty.
February 24, 2003
Report of Independent Auditors
The Board of Control of
Indiantown Cogeneration, L.P.
We have audited the accompanying consolidated balance sheet of Indiantown Cogeneration, L.P. and subsidiary as of December 31, 2002 and the related consolidated statements of operations, changes in partners’ capital and cash flows for the year then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. The accompanying consolidated balance sheet of Indiantown Cogeneration, L.P. and subsidiary for the year ended December 31, 2001 and the related consolidated statements of operations, changes in partners’ capital and cash flows for each of the two years in the period ended December 31, 2001, were audited by other auditors who have ceased operations and whose report dated January 23, 2002, expressed an unqualified opinion on those statements and included an explanatory paragraph that disclosed the change in the Partnership’s method of accounting for scheduled major overhauls discussed in Note 2 to the financial statements.
We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Indiantown Cogeneration, L.P. and subsidiary at December 31, 2002, and the consolidated results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States.
February 24, 2003
Report of Independent Auditors
The Board of Control of
Northampton Generating Company, L.P.
We have audited the accompanying consolidated balance sheet of Northampton Generating Company, L.P. and subsidiaries as of December 31, 2002 and the related consolidated statements of operations, changes in partners’ capital and cash flows for the year then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Northampton Generating Company, L.P. and subsidiaries for the year ended December 31, 2001, were audited by other auditors who have ceased operations and whose report dated January 23, 2002, expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Northampton Generating Company, L.P. and subsidiaries at December 31, 2002, and the consolidated results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States.
As discussed in Note 2 to the consolidated financial statements, in 2002 the Partnership changed its method of accounting for certain derivative contracts.
February 24, 2003
Report of Independent Auditors
The Board of Control of
Scrubgrass Generating Company, L.P.
We have audited the accompanying consolidated balance sheet of Scrubgrass Generating Company, L.P. and subsidiaries as of December 31, 2002 and the related consolidated statements of operations, changes in partners’ capital and cash flows for the year then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Scrubgrass Generating Company, L.P. and subsidiaries for the year ended December 31, 2001, were audited by other auditors who have ceased operations and whose report dated January 23, 2002, expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Scrubgrass Generating Company, L.P. and subsidiaries at December 31, 2002, and the consolidated results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States.
February 24, 2003
Report of Independent Auditors
The Boards of Control of
Logan Generating Company, L.P. and
Keystone Urban Renewal Limited Partnership
We have audited the accompanying combined balance sheet of Logan Generating Company, L.P. and Keystone Urban Renewal Limited Partnership as of December 31, 2002, and the related combined statements of operations, partners’ capital, and cash flows for the year then ended. These financial statements are the responsibility of the Partnerships’ management. Our responsibility is to express an opinion on these financial statements based on our audit. The combined financial statements of Logan Generating Company, L.P. and Keystone Urban Renewal Limited Partnership for the year ended December 31, 2001, were audited by other auditors who have ceased operations and whose report dated January 23, 2002, expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements referred to above present fairly, in all material respects, the combined financial position of Logan Generating Company, L.P. and Keystone Urban Renewal Limited Partnership at December 31, 2002, and the combined results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States.
February 24, 2003
This report is a copy of the report previously issued by Arthur Andersen and has not been reissued by Arthur Andersen.
Report of independent public accountants
To Scrubgrass Generating Company, L.P.:
We have audited the accompanying consolidated balance sheets of Scrubgrass Generating Company, L.P. (a Delaware limited partnership) and subsidiaries (“the Partnership”) as of December 31, 2001 and 2000, and the related consolidated statements of operations, changes in partners’ capital and cash flows for the years then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Scrubgrass Generating Company, L.P. and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.
As discussed in Note 2 to the financial statements, the Partnership changed its method of accounting for scheduled major overhauls in 2000.
Vienna, Virginia
January 23, 2002
/s/ Arthur Andersen
This report is a copy of the report previously issued by Arthur Andersen and has not been reissued by Arthur Andersen.
Report of independent public accountants
To Cedar Bay Generating Company, L.P.:
We have audited the accompanying balance sheets of Cedar Bay Generating Company, L.P. (a Delaware limited partnership) (“the Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ deficit and cash flows for the years then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cedar Bay Generating Company, L.P. as of December 31, 2001 and 2000, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.
As discussed in Note 2 to the financial statements, the Partnership changed its method of accounting for scheduled major overhauls in 2000.
Vienna, Virginia
January 23, 2002
(except with respect to the matter discussed in Note 7 of the Cedar Bay Generating Company, L.P. financial statements, as to which the date is February 7, 2002)
/s/ Arthur Andersen
This report is a copy of the report previously issued by Arthur Andersen and has not been reissued by Arthur Andersen.
Report of independent public accountants
To Chambers Cogeneration, L.P.:
We have audited the accompanying balance sheets of Chambers Cogeneration, L.P. (a Delaware limited partnership) (“the Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ capital and cash flows for the years then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Chambers Cogeneration, L.P. as of December 31, 2001 and 2000, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.
As discussed in Note 2 to the financial statements, the Partnerships changed their method of accounting for scheduled major overhauls in 2000.
Vienna, Virginia
January 23, 2002
/s/ Arthur Andersen
This report is a copy of the report previously issued by Arthur Andersen and has not been reissued by Arthur Andersen.
Report of independent public accountants
To Indiantown Cogeneration, L.P.:
We have audited the accompanying consolidated balance sheets of Indiantown Cogeneration, L.P. (a Delaware limited partnership) and subsidiary (“the Partnership”) as of December 31, 2001 and 2000, and the related consolidated statements of operations, changes in partners’ capital and cash flows for the years then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Indiantown Cogeneration, L.P. and subsidiary as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.
As discussed in Note 2 to the financial statements, the Partnership changed its method of accounting for scheduled major overhauls in 2000.
Vienna, Virginia
January 23, 2002
/s/ Arthur Andersen
This report is a copy of the report previously issued by Arthur Andersen and has not been reissued by Arthur Andersen.
Report of independent public accountants
To Logan Generating Company, L.P. and
Keystone Urban Renewal Limited Partnership:
We have audited the accompanying combined balance sheets of Logan Generating Company, L.P. (a Delaware limited partnership) and Keystone Urban Renewal Limited Partnership (a Delaware limited partnership),(collectively “the Partnerships”) as of December 31, 2001 and 2000, and the related combined statements of operations, changes in partners’ capital and cash flows for the years then ended. These financial statements are the responsibility of the Partnerships’ management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Logan Generating Company, L.P. and Keystone Urban Renewal Limited Partnership as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.
As discussed in Note 2 to the financial statements, the Partnerships changed their method of accounting for scheduled major overhauls in 2000.
Vienna, Virginia
January 23, 2002
/s/ Arthur Andersen
This report is a copy of the report previously issued by Arthur Andersen and has not been reissued by Arthur Andersen.
Report of independent public accountants
To Northampton Generating Company, L.P.:
We have audited the accompanying consolidated balance sheets of Northampton Generating Company, L.P. (a Delaware limited partnership) and subsidiaries (“the Partnership”) as of December 31, 2001 and 2000, and the related consolidated statements of operations, changes in partners’ capital and cash flows for the years then ended. These financial statements and schedules are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northampton Generating Company, L.P. and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.
Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The consolidating balance sheet and consolidating statement of operations as of and for the year ended December 31, 2001 on Schedule I and Schedule II are presented for purposes of additional analysis and are not a required part of the consolidated financial statements. This information has been subjected to the auditing procedures applied in our audit of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the consolidated financial statements taken as a whole.
As discussed in Note 2 to the financial statements, the Partnerships changed their method of accounting for scheduled major overhauls in 2000.
Vienna, Virginia
January 23, 2002
/s/ Arthur Andersen
This report is a copy of the report previously issued by Arthur Andersen and has not been reissued by Arthur Andersen.
Report of Independent Public Accountants
To the Management Committee of
MASSPOWER:
We have audited the accompanying balance sheets of MASSPOWER (a Massachusetts general partnership) as of December 31, 2001 and 2000, and the related statements of operations, changes in Partners’ Capital and cash flows for the years then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of MASSPOWER as of December 31, 2001 and 2000, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States.
Boston, Massachusetts
January 11, 2002
/s/ Arthur Andersen
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
NONE
PART III.
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table provides information on our directors and executive officers as of February 28, 2003:
Name
Age
Position
Thomas B. King
President and Director
P. Chrisman Iribe
Executive Vice President
Lyn E. Maddox
Executive Vice President
Thomas E. Legro
Vice President, Controller and
Chief Accounting Officer
Sanford L. Hartman
Vice President and Chief Counsel
G. Brent Stanley
Senior Vice President, Human
Resources and Director
Peter A. Darbee
Director
Bruce R. Worthington
Director
Andrew L. Stidd
Director
Thomas B. King has been our President and a member of our Board of Directors since November 2002. Prior to that, he had been our President and Chief Operating Officer, Western Region since July 2000. He has also served as Senior Vice President of PG&E Corporation since December 16, 1998. Mr. King has also served as President of PG&E Gas Transmission, Northwest Corporation, one of our subsidiaries, since November 1998, and served as Chief Operating Officer of that entity from November 1998 to December 2002. Prior to joining PG&E Gas Transmission Company, he was President and Chief Operating Officer of Kinder Morgan Energy Partners, L.P. (energy pipeline operations) from February 1997 to November 1998, and was Vice President, Commercial Operations for Enron Liquids, from September 1995 to February 1997.
P. Chrisman Iribe has been our Executive Vice President since December 2002. Prior to that he had been our President and Chief Operating Officer, Eastern Region since July 2000. He has also served as Senior Vice President of PG&E Corporation since December 16, 1998. Mr. Iribe previously served as President and Chief Operating Officer of PG&E Generating Company, one of our subsidiaries, from November 1998 to January 2000. From September 1997 to November 1998, Mr. Iribe served as Executive Vice President and Chief Executive Officer of PG&E Generating Company (formerly known as U.S. Generating Company). Mr. Iribe held various other executive positions within U.S. Generating Company from 1989 to September 1997. Prior to Mr. Iribe’s joining U.S. Generating Company in 1989, he was senior vice president for planning, state relations and public affairs at ANR Pipeline Company (natural gas pipeline).
Lyn E. Maddox has been our Executive Vice President since December 2002. Prior to that, he had been our President and Chief Operating Officer, Trading since July 2000. He has also served as Senior Vice President of PG&E Corporation since May 12, 1997. Mr. Maddox was President and Chief Operating Officer of PG&E Energy Trading Corporation, one of our subsidiaries, from May 1997 to June 2000. Prior to that, Mr. Maddox was president of PennUnion Energy Services from March 1995 to May 1997 and President and Chief Operating Officer of Brooklyn Interstate Natural Gas Corporation from February 1989 to February 1995.
Thomas E. Legro has been our Vice President, Controller and Chief Accounting Officer since July 2001. From January 1994 to June 2001, Mr. Legro was Vice President and Controller of Edison Mission Energy (independent power producer).
Sanford L. Hartman has been our Vice President and Chief Counsel since December 2002. From March of 1999 until December 2002, Mr. Hartman was Vice President and General Counsel of PG&E Generating, now a subsidiary of ours. From March 1999 until December 2002, he was our Vice President and Associate General Counsel. Mr. Hartman has been employed by our company and its predecessors and subsidiaries since 1990.
G. Brent Stanley has been our Senior Vice President, Human Resources since July 2000 and has been a member of our board of directors since March 2001. He has also served as Senior Vice President, Human Resources of PG&E Corporation since January 1997. He was Vice President of Human Resources of Pacific Gas and Electric Company, one of our affiliates, from February 1996 to January 1997. He previously was Senior Vice President of Human Resources for The Gap Inc. (retail clothing) from August 1992 to November 1994 and served in executive human resources positions with Burlington Air Express, Inc. from May 1989 to August 1992 and Marriott Corporation from March 1980 to May 1989.
Peter A. Darbee has been a member of our board of directors since September 1999. He has been Senior Vice President and Chief Financial Officer of PG&E Corporation since January 1999. He also served as treasurer of PG&E Corporation from September 1999 to July 2001. Prior to January 1999, Mr. Darbee served as Vice President and Chief Financial Officer of Advanced Fibre Communications, Inc. (telecommunications manufacturer of digital loop carrier systems) from June 1997 through January 1999. Prior to that, Mr. Darbee was Vice President, Chief Financial Officer, and Controller of Pacific Bell from May 1994 through June 1997.
Bruce R. Worthington has been a member of our board of directors since January 1999. He has been Senior Vice President and General Counsel of PG&E Corporation since February 1997. Prior to that, Mr. Worthington was Senior Vice President and General Counsel of Pacific Gas and Electric Company, one of our affiliates, from May 1995 to February 1997. Mr. Worthington joined the law department of Pacific Gas and Electric Company in June 1974.
Andrew L. Stidd has been a member of our board of directors since February 2001 and serves as our independent director. On February 27, 2003, Mr. Stidd tendered his resignation from our board of directors, which will become effective once a new independent director is elected to replace Mr. Stidd. He is a co-founder of Global Securitization Services, LLC (owner and manager of special purpose funding vehicles), and has 13 years experience in the securitization industry. From December 1996 to the present, Mr. Stidd has been President of Global Securitization Services, LLC. Between April 1987 and December 1996, Mr. Stidd was Vice President, Chief Operating Officer of Lord Securities Corporation. Prior to joining Lord Securities in 1987, Mr. Stidd was a manager in the Controller’s Department of Goldman Sachs & Co. from 1979 to 1987.
The directors serve until the next annual meeting of stockholders and until their respective successors are elected and qualified. Officers serve at the discretion of the Board of Directors. There are no family relationships between any members of our Board or our executive officers at time of service as a director or executive officer.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Board Structure and Compensation
Our four directors who also are our employees or employees of PG&E Corporation receive no extra compensation for serving as directors or committee members. We pay our other director an annual retainer of $2,500. We also reimburse all directors for their reasonable expenses incurred in attending our board and committee meetings and for other activities they undertake on our behalf or for our benefit.
Compensation Committee Interlocks and Insider Participation
None of our executive officers has served as a member of a compensation committee (or if no committee performs that function, the board of directors) of any other entity that has an executive officer serving as a member of our board of directors.
Compensation of Executive Officers
Summary Compensation Table
[This table summarizes the principal components of compensation paid to the Chief Executive Officers and the other most highly compensated executive officers of PG&E National Energy Group, Inc. during the past year.]
Aggregate PG&E Corporation Option/SAR Exercises in 2002 and Year-End Values
[The following table summarizes exercises in 2002 of PG&E Corporation stock options and tandem stock appreciation rights (granted in prior years) by the executive officers listed in the summary compensation table, as well as the number and value of all unexercised PG&E Corporation options held by those executive officers at the end of 2002.]
PG&E Corporation Long-Term Incentive Plan Compensation
[The following table summarizes long-term incentive awards made in 2002 to the executive officers listed in the summary compensation table. These awards were made in accordance with PG&E Corporation’s Performance Unit Plan and Executive Stock Ownership Program. ]
Long Term Incentive Plan Awards in 2002
(1)
Represents performance units granted under the PG&E Corporation Performance Unit Plan. The units vest one-third in each of the three years following the grant year, and are earned over the vesting period based on PG&E Corporation’s three-year cumulative total shareholder return (dividends plus stock price appreciation) as compared with that achieved by an 11 company comparator group. This performance target may be adjusted during the vesting period, at the sole discretion of the PG&E Corporation Nominating, Compensation, and Governance Committee, to reflect extraordinary events beyond management’s control. Each time a cash dividend is paid on PG&E Corporation common stock, an amount equal to the cash dividend per share multiplied by the number of units held by a recipient will be accrued on behalf of the recipient and, at the end of the year, the amount of accrued dividend equivalents will be increased or decreased by the same percentage used to increase or decrease the recipient’s number of vested performance units for the year. Performance units awarded to Mr. Boren continue to vest over 24 months and performance units awarded to Ms. Barpoulis and Mr. Herman continue to vest over 18 months, as set forth in the Officer Severance Policy and any agreements (see “Employment and Separation Agreements on pages 108 and 109).
(2)
Represents common stock equivalents called Special Incentive Stock Ownership Premiums (SISOPs) earned under the PG&E Corporation Executive Stock Ownership Program. SISOPs are earned by eligible officers who achieve and maintain minimum PG&E Corporation common stock ownership levels as set by PG&E Corporation’s Nominating, Compensation, and Governance Committee. Of the officers named in the Summary Compensation Table, only Messrs. Boren, King, Iribe, Stanley, and Maddox are eligible officers. Each SISOP represents a share of PG&E Corporation common stock that vests at the end of three years. Units can be forfeited prior to vesting if an eligible officer fails to maintain his or her minimum ownership level. Upon retirement or termination, vested SISOPs are distributed in the form of an equivalent number of shares of PG&E Corporation common stock. For SISOPs awarded to Mr. Boren, two-thirds of the units awarded to Mr. Boren vested as set forth in his agreement (see “Employment and Separation Agreements” on pages 108 and 109).
(3)
For units granted pursuant to the Performance Unit Plan, payments are determined by multiplying the number of units earned in a given year by the average market price of PG&E Corporation common stock for the 30 calendar day period prior to the end of the year.
Retirement Benefits
PG&E Corporation provides retirement benefits to some of the executive officers named in the Summary Compensation Table on pages 105 and 106. The benefit formula for eligible executive officers is 1.7 percent of the average of the three highest combined salary and annual incentive awards during the last ten years of service multiplied by years of credited service. During 2002, PG&E Corporation discharged a significant portion of its unfunded corporate retirement obligations through the purchase of individual annuities for those officers whose entire accrued benefit could not be provided under the amended retirement plan due to tax code limits. At retirement, the annuities will provide the executives with an accrued after-tax value comparable to what they would have received from the Supplemental Executive Retirement Plan (SERP) or similar arrangements. In connection with the annuity purchase, a tax restoration payment was made such that the annuitization was tax neutral to the executive. As of December 31, 2002, the estimated pre-tax annual retirement benefits payable under the SERP or similar arrangements, adjusted to reflect the effect of the 2002 annuity purchase were as follows: Mr. Boren $ 613,836 through May 31, 2004, and $ 458,976 thereafter, and Mr. Stanley $ 117,620 (assuming credited service to age 65). The estimated annual retirement benefits are single life annuity benefits and would not be subject to any Social Security offsets.
Employment and Separation Agreements
Thomas B. King’s employment letter entitles him to receive salary, other cash and equity awards as described elsewhere and other standard employee benefits. In connection with his relocation to Bethesda, Maryland, Mr. King received a one-time payment of $150,000 net of taxes, and a one-time taxable payment of $75,000. If Mr. King resigns from his position prior to December 31, 2004 (and is not then an employee of us, PG&E Corporation or its other affiliates), he will be required to repay the gross amount of such payments. Mr. King also received (1) a moving allowance equal to one month’s pay; (2) reimbursement for travel expenses incurred in finding a principal residence in the Bethesda area, and for the reasonable cost of temporary housing; (3) reimbursement of closing costs incurred in the sale of his prior residence and the purchase of a new residence; (4) indemnification for loss suffered on the sale of his prior residence; and (5) reimbursement of certain losses and expenses incurred in placing his children in comparable schools in the Bethesda area. Mr. King also is entitled to receive a mortgage subsidy of $3,500 per month, payable for four years, commencing with the first mortgage payment for his new residence. If Mr. King resigns from employment with us, PG&E Corporation or one of its other subsidiaries or affiliates before December 31, 2004, he will be required to repay all amounts provided under the temporary mortgage subsidy.
Lyn E. Maddox’s employment letter entitles him to receive salary, other cash and equity awards described elsewhere and other standard employee benefits. In connection with his relocation to Bethesda, Maryland, Mr. Maddox received a one-time payment of $250,000, net of taxes, and a one-time taxable payment of $75,000. If Mr. Maddox resigns from his position before December 31, 2004 (and is not then an employee of us, PG&E Corporation or its other affiliates), he will be required to repay the gross amount of such payments. Mr. Maddox also received (1) a moving allowance equal to one month’s pay; (2) reimbursement for travel expenses incurred in finding a principal residence in the Bethesda area, and for the reasonable cost of temporary housing; (3) reimbursement of closing costs incurred in the sale of his prior residence and the purchase of a new residence; (4) indemnification for loss suffered on the sale of his prior residence; and (5) reimbursement of certain losses and expenses incurred in placing his children in comparable schools in the Bethesda area. Mr. Maddox also is entitled to receive a mortgage subsidy of $3,500 per month, payable for four years, commencing with the first mortgage payment for his new residence. If Mr. Maddox resigns from employment with us, PG&E Corporation or one of its other subsidiaries or affiliates before December 31, 2004, he will be required to repay all amounts provided under the temporary mortgage subsidy.
Thomas G. Boren ceased to be an executive officer, effective December 1, 2002, at which time Mr. Boren and PG&E Corporation and its affiliates entered into an agreement to implement the provisions of Mr. Boren’s 1999 employment letter. Under the agreement, in lieu of cash severance under the PG&E Corporation Officer Severance Policy, Mr. Boren received additional age and service credit under his supplemental executive retirement arrangement. As provided in the Officer Severance Policy, Mr. Boren’s outstanding awards under the PG&E Corporation Long-Term Incentive Program will continue to vest over 24 months, two-thirds of the units awarded to Mr. Boren in connection with Executive Stock Ownership Program requirements vested, and Mr. Boren remains eligible for any prorated payment earned under the PG&E Corporation Short-Term Incentive Plan. As described elsewhere in this annual report, a substantial portion of Mr. Boren’s benefits under his supplemental executive retirement arrangement as of December 31, 2001 were converted to an annuity with an associated tax restoration benefit such that the annuity purchase tax neutral to him. The agreement also provides for the continuation of certain benefits, including health insurance continuation for up to 18 months.
Steven G. Herman ceased to be an executive officer of PG&E Corporation, effective December 1, 2002. In connection with his resignation, Mr. Herman entered into an agreement with PG&E Corporation and its affiliates. The agreement contains a release of all claims against PG&E Corporation. Under the agreement, Mr. Herman received a cash severance payment. As provided in the Officer Severance Policy, Mr. Herman’s outstanding awards under the Long-Term Incentive Program will continue to vest over 18 months, and Mr. Herman remains eligible for any prorated payment earned under the PG&E Corporation Short-Term Incentive Plan. The agreement also provides for the continuation of certain benefits, including health insurance continuation for up to 18 months.
Termination of Employment and Change in Control Provisions
The PG&E Corporation Officer Severance Policy, which covers most officers of PG&E Corporation and its subsidiaries, including the executive officers listed in the summary compensation table, provides benefits if a covered officer is terminated without cause. In most situations, benefits under the policy include (i) a lump sum payment of one and one-half or two times annual base salary and target PG&E Corporation Short-Term Incentive Plan award (the applicable severance multiple being dependent on an officer’s level), (ii) continued vesting of equity-based awards for 18 months or two years after termination (depending on the applicable severance multiple), (iii) accelerated vesting of up to two-thirds of the common stock equivalents awarded under the PG&E Corporation Executive Stock Ownership Program (depending on an officer’s level), and (iv) payment of health care insurance premiums for 18 months or two years after termination (depending on the applicable severance multiple). Instead of all or part of the lump sum payment, a terminated officer who is covered by PG&E Corporation’s Supplemental Executive Retirement Plan can elect additional years of service and/or age for purposes of calculating pension benefits. Alternative benefits apply upon actual or constructive termination following a change in control or potential change in control of PG&E Corporation. For these purposes, “change in control” has the same definition as under the Long-Term Incentive Program (see below). Constructive termination includes certain changes to a covered officer’s responsibilities. In the event of a change in control or potential change in control, the policy provides for a lump sum payment of the sum of (a) unpaid base salary earned through the termination date, (b) target PG&E Corporation Short-Term Incentive Plan award calculated for the fiscal year in which termination occurs, or the PG&E Corporation Target Bonus, (c) any accrued but unpaid vacation pay and (d) three times the sum of such Target Bonus and the officer’s annual base salary in effect immediately before either the date of termination or the change in control, whichever base salary is greater. Change in control termination benefits also include reimbursement of excise taxes levied upon the severance benefit under Internal Revenue Code Section 4999.
The PG&E Corporation Long-Term Incentive Program, or LTIP, permits PG&E Corporation to grant various types of stock-based incentive awards, including awards granted under the PG&E Corporation Stock Option Plan and the PG&E Corporation Performance Unit Plan. The PG&E Corporation LTIP and the component plans provide that, upon a change in control of PG&E Corporation, (1) any time periods relating to the exercise or realization of any incentive award (including common stock equivalents awarded under the PG&E Corporation Executive Stock Ownership Program) will be accelerated so that
such award may be exercised or realized in full immediately upon the change in control, (2) all shares of restricted stock will immediately cease to be forfeitable, and (3) all conditions relating to the realization of any stock-based award will terminate immediately. Under the PG&E Corporation LTIP, a “change in control” will be deemed to have occurred if any of the following occurs: (1) any “person” (as that term is used in Sections 13(d) and 14(d)(2) of the Exchange Act, but excluding any benefit plan for employees or any trustee, agent, or other fiduciary for any such plan acting in such person’s capacity as such fiduciary), directly or indirectly, becomes the beneficial owner of securities of PG&E Corporation representing 20% or more of the combined voting power of PG&E Corporation’s then outstanding securities, (2) during any two consecutive years, individuals who at the beginning of such a period constitute PG&E Corporation’s board of directors cease for any reason to constitute at least a majority of the board of directors, unless the election, or the nomination for election by the shareholders of PG&E Corporation, of each new director was approved by a vote of at least two-thirds of the PG&E Corporation directors then still in office who were directors at the beginning of the period, or (3) the shareholders of PG&E Corporation shall have approved (i) any consolidation or merger of PG&E Corporation other than a merger or consolidation that would result in the voting securities of PG&E Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70% of the combined voting power of PG&E Corporation, such surviving entity, or the parent of such surviving entity outstanding immediately after the merger or consolidation, (ii) any sale, lease, exchange, or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of PG&E Corporation, or (iii) any plan or proposal for the liquidation or dissolution of PG&E Corporation. For this purpose, “combined voting power” means the combined voting power of the then-outstanding voting securities of PG&E Corporation or the other relevant entity.
The Special Senior Executive Retention Grants provide certain senior executive officers with phantom PG&E Corporation restricted stock units. One portion of each officer’s phantom restricted stock units will vest automatically on December 31, 2004, contingent on PG&E Corporation continued service, subject to accelerated vesting if, as of December 31, 2003, the Corporation’s performance as measured by relative total shareholder return on a cumulative basis (TSR) is at or above the 75th percentile of its comparator group. The remainder of each officer’s phantom restricted stock units will vest on December 31, 2004, only if the Corporation’s performance, as measured by TSR over four years, is at or above the 55th percentile of its comparator group and the executive is in service, provided that the units will vest at the end of the third year of the grant, December 31, 2003, if the Corporation’s performance as measured by TSR is at or above the 75th percentile of its comparator group. All units fully vest upon a change in control. For these purposes, a “change in control” has the same definition as under the LTIP.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Security Ownership of Management
We are an indirect wholly owned subsidiary of PG&E Corporation.
The following table provides information as of January 31, 2003 as to the beneficial ownership of PG&E Corporation common stock by each director and each executive officer named in the Summary Compensation Table on page 105, and by all of them and any other executive officers as a group. The number of shares shown for each person (and the total number of shares shown for all of them) constitutes less than 1% of the outstanding shares of PG&E Corporation common stock.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Intercompany Relationships
PG&E NEG is charged for administrative and general costs from PG&E Corporation. These charges are based upon direct assignment of costs and allocations of costs using allocation methods that PG&E NEG and PG&E Corporation believe are reasonable reflections of the utilization of services provided to or for the benefits received by PG&E NEG. For the years ended December 31, 2002, 2001, and 2000, PG&E Corporation allocated costs to PG&E NEG of $30 million, $25 million, and $43 million, respectively. The total amount due PG&E Corporation at December 31, 2002 and 2001, was $19 million and $13 million, respectively. In addition, PG&E NEG bills PG&E Corporation for certain shared costs. For the years ended December 31, 2002, 2001 and 2000, the total charges billed to PG&E Corporation were immaterial.
The amounts above do not include amounts paid to the Utility from which PG&E NEG receives (and to which PG&E NEG provides) limited corporate support services. In 2002, 2001, 2000, the total charges to PG&E NEG for corporate support services were immaterial. CPUC regulations limit PG&E NEG’s ability to share certain types of services and information with the Utility. In addition, PG&E Corporation’s credit agreement, which is described below, includes a covenant that generally restricts certain intercompany transactions to those made on arm’s-length terms.
PG&E NEG accounts for income taxes under the liability method. Deferred tax assets and liabilities are determined based on the differences between financial statement carrying amounts and the tax basis of assets and liabilities, using currently enacted tax rates. PG&E NEG is included in the consolidated tax return of PG&E Corporation. PG&E NEG computes its provision for income taxes on a separate company basis as if it filed its own consolidated or combined tax return separate from PG&E Corporation.
Certain states require that each entity doing business in that state file a separate tax return (the “Separate State Taxes”). Canadian subsidiaries are subject to Canadian Federal and Provincial Income Taxes based on their net income (the “Canadian Taxes”). PG&E NEG separately accounts for the tax consequences of Separate State Taxes and Canadian Taxes.
For certain of the years before 2001, PG&E Corporation made payments to PG&E NEG commensurate with the tax savings achieved through the incorporation of PG&E NEG’s losses and tax credits in PG&E Corporation’s consolidated federal tax return for those years. In tax year 2001, PG&E NEG paid to PG&E Corporation the amount of its federal tax liability. At December 31, 2002, PG&E NEG has reflected a tax liability for amounts owed to PG&E Corporation.
Certain creditors of PG&E NEG have asserted that the aforementioned payments gave rise to an implied tax sharing agreement between PG&E Corporation and PG&E NEG. PG&E Corporation disputes that assertion. On November 12, 2002, PG&E Corporation notified PG&E NEG that to the extent that such an implied tax sharing agreement existed and was not terminated previously, it was terminated effective immediately. On December 24, 2002, PG&E NEG sent a letter to PG&E Corporation reserving all rights against PG&E Corporation with respect to such tax sharing agreement, if such agreement does in fact exist.
Under the PG&E Credit Agreement, PG&E Corporation agreed among other things not to permit PG&E NEG or any of its subsidiaries to (1) sell or abandon any of their respective assets except in compliance with certain conditions or (2) restructure any of their respective obligations except in compliance with certain conditions. These prohibitions do not apply to a “Qualified Asset Sale,” a “Qualified Bankruptcy Sale,” a “Qualified Abandonment,” or a “Qualified Restructuring,” all as defined in the PG&E Credit Agreement. In general, these definitions permit transactions in which PG&E Corporation (1) is released from existing liabilities related to the assets that are the subject of the transaction, (2) incurs no new liabilities as a result of the transaction, and (3) receives payment at closing for any new liability incurred, including any tax liability that would be payable as a result of the transaction. The PG&E Credit Agreement also restricts (with limited exceptions) PG&E Corporation’s investment in PG&E NEG to an amount that is no more than 75 percent of the net cash tax savings received by PG&E Corporation after October 1, 2002, as a result of a “Qualified Bankruptcy Sale,” a “Qualified Abandonment,” or a “Qualified Restructuring” (as defined in the PG&E Credit Agreement).
PG&E NEG recorded deferred tax assets of $1,403 million resulting from impairments and write-offs during 2002. As a result of such impairments, PG&E NEG has a net deferred tax asset of $1,003 million at December 31, 2002 before valuation allowance. Due to uncertainty in realizing the tax benefits associated with these deferred tax assets, PG&E NEG established valuation allowances for the full amount of the net deferred tax assets. The valuation allowances were determined in accordance with the provisions of SFAS No. 109 “Accounting for Income Taxes.” In assessing the realizability of deferred tax assets, PG&E NEG considered whether it is more likely than not that some portion of all of the deferred tax assets would not be realized. PG&E NEG is currently in default under various debt agreements and guaranteed equity commitments. PG&E NEG and its lenders are in discussions regarding a restructuring of these commitments. At this time, it is uncertain whether PG&E NEG will be able to reach agreement with the lenders regarding restructuring of its financial commitments, or whether it will be forced into proceedings under the Bankruptcy Code.
The Internal Revenue Service (IRS) has completed its audit of PG&E Corporation’s 1997 and 1998 consolidated U.S. federal income tax returns and has assessed additional federal income taxes of $53 million (including interest) related to PG&E NEG. PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and is currently discussing those adjustments with the IRS’s Appeals Office.
The IRS is also auditing PG&E Corporation’s 1999 and 2000 consolidated U.S. federal income tax returns, but has not issued its final report. However, the IRS has proposed adjustments totalling $67 million (including interest) with respect to PG&E NEG. All of PG&E Corporation’s federal income tax returns before 1997 have been closed, including those portions attributable to PG&E NEG. In addition, the State of California’s Franchise Tax Board and certain other state tax authorities are currently auditing various state tax returns.
In addition, in the recent past, the Utility has been PG&E NEG Pipeline’s largest customer and, during 2002, 2001, and 2000, $47 million, $41 million, and $46 million, respectively, of the revenues generated by PG&E GTN’s pipeline have come from the Utility. In addition, the PG&E Energy segment also purchases from and sells to the Utility energy commodities, primarily natural gas. In 2002, 2001, and 2000, PG&E NEG Energy segment had energy commodity sales of approximately $49 million, $120 million, and $136 million, respectively, to the Utility and energy commodity purchases of $11 million, $21 million, and $12 million, respectively. PG&E NEG also has engaged in a limited number of transactions with the Utility involving products and services that are the subject of tariffs filed with the CPUC or FERC. For example, the La Paloma generating facility has an interconnection agreement with the Utility.
Loans, Capital Commitments and Guarantees
Periodically, PG&E NEG and its subsidiaries have borrowed funds from, or loaned money to, PG&E Corporation for specific transactions or other corporate purposes. At December 31, 2002, PG&E NEG had a net outstanding loan balance payable to PG&E Corporation of $327 million, including net amounts payable of $209 million related to Attala Power Corporation, net amounts payable of $118 million in the form of promissory notes to PG&E Corporation related primarily to past funding of generating asset development and acquisition, and a note receivable of $75 million related to PG&E GTN. In addition, until December 28, 2000, funds from operations were managed through net investments or borrowing in a pooled cash management arrangement with PG&E Corporation.
As of December 31, 2001, PG&E NEG had replaced or eliminated all of the previously issued PG&E Corporation guarantees and two guarantees of non-debt obligations of other PG&E NEG subsidiaries (except for a $16 million office lease guarantee relating to PG&E NEG’s San Francisco office, two guarantees of PG&E NEG’s indemnification obligations to purchasers of PG&E NEG’s assets and a guarantee related to PG&E NEG’s obligations to the sellers of assets purchased by PG&E NEG) with a combination of guarantees provided by PG&E NEG or its subsidiaries and letters of credit obtained independently by PG&E NEG. The $16 million office lease guarantee was reduced to $9.7 million as of December 31, 2002.
PG&E Corporation Credit Agreement
On October 18, 2002, PG&E Corporation entered into a Second Amended and Restated Credit Agreement with certain lenders (the “PG&E Credit Agreement”). All obligations of PG&E Corporation under the PG&E Credit Agreement are secured by, among other things, a perfected first priority security interest in 100 percent of the equity interests in PG&E NEG LLC and 100 percent of the common stock of PG&E NEG, and all proceeds thereof.
Under the PG&E Credit Agreement, PG&E Corporation agreed among other things not to permit PG&E NEG or any of its subsidiaries to (1) sell or abandon any of their respective assets except in compliance with certain conditions or (2) restructure any of their respective obligations except in compliance with certain conditions. These prohibitions do not apply to a “Qualified Asset Sale,” a “Qualified Bankruptcy Sale,” a “Qualified Abandonment,” or a “Qualified Restructuring,” all as defined in the PG&E Credit Agreement. In general, these definitions permit transactions in which PG&E Corporation (1) is released from existing liabilities related to the assets that are the subject of the transaction, (2) incurs no new liabilities as a result of the transaction, and (3) receives payment at closing for any new liability incurred, including any tax liability that would be payable as a result of the transaction. The PG&E Credit Agreement also restricts (with limited exceptions) PG&E Corporation’s investment in PG&E NEG to an amount that is no more than 75 percent of the net cash tax savings received by PG&E Corporation after October 1, 2002, as a result of a “Qualified Bankruptcy Sale,” a “Qualified Abandonment,” or a “Qualified Restructuring” (as defined in the PG&E Credit Agreement).
PG&E NEG, LLC previously granted to certain lenders of PG&E Corporation options to purchase shares of PG&E NEG. On September 3, 2002, a lender gave PG&E Corporation notice that it was exercising its right to sell (put) to PG&E Corporation its options representing 1.8 percent of the shares of PG&E NEG. Under the terms of the Option Agreement, PG&E Corporation and the lender entered into an appraisal process to determine the value of the PG&E NEG options. On October 30, 2002 before completion of the appraisal process, the lender cancelled by giving notice of cancellation of its put notice, which was accepted by PG&E Corporation. The lender no longer has the right to put those options to PG&E Corporation. On February 25, 2003, the lender exercised the options which otherwise would have expired on March 1, 2003. Similar options representing 1.2 percent of PG&E NEG expired on March 1, 2003.
CPUC Proceedings and Litigation Involving PG&E Corporation
PG&E Corporation and its subsidiaries, including PG&E NEG, are exempt from all provisions, except Section 9(a)(2), of PUHCA. At present, PG&E Corporation has no expectation of becoming a registered holding company under PUHCA. On July 7, 2001, the California Attorney General (AG) filed a petition with the Securities and Exchange Commission (SEC) requesting the SEC to review and revoke PG&E Corporation’s exemption from PUHCA and to begin fully regulating the activities of PG&E Corporation and its affiliates. The AG’s petition requested the SEC to hold a hearing on the matter as soon as possible, and requesting a response from the SEC no later than September 5, 2001. On August 7, 2001, PG&E Corporation responded in detail to the AG’s petition demonstrating that PG&E Corporation met the SEC’s criteria for the intrastate exemption. On October 4, 2001, the AG filed a “supplement” to its petition requesting that the SEC consider additional issues and to set the matter for hearing. PG&E Corporation responded to the supplement on October 30, 2001, and once again demonstrated that there was no basis for action by the SEC. In comments filed on November 14, 2002 on PG&E Corporation’s 9(a)(2) filing made with the SEC in connection with the implementation of the Utility Plan, the AG reiterated the arguments made in its July 7, 2001 and October 4, 2001 filings with the SEC. In its response filed with the SEC on January 24, 2003, PG&E Corporation responded to those arguments and demonstrated that there was no basis for SEC action with respect to those issues. To date, the SEC has neither instituted an investigation nor ordered hearings regarding the matters raised in the AG’s petition.
Although PG&E Corporation is not a public utility under the laws of California and is not subject to regulation as such by the CPUC, the CPUC approval authorizing the Utility to form a holding company was granted subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The CPUC, as discussed below, issued a decision asserting that it maintains jurisdiction to enforce the conditions against the holding companies and to modify, clarify or add to the conditions. The financial conditions provide, among other things, that the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s service obligation to serve or to operate the Utility in a prudent and efficient manner, shall be given first priority by the Board of Directors of PG&E Corporation (the “first priority condition”).
The CPUC also has adopted complex and detailed rules governing transactions between California’s natural gas local distribution and electric utility companies and their non-regulated affiliates. The rules permit non-regulated affiliates of regulated utilities to compete in the affiliated utility’s service territory, and also to use the name and
logo of their affiliated utility, provided that in California the affiliate includes certain designated disclaimer language which emphasizes the separateness of the entities and that the affiliate is not regulated by the CPUC. The rules also address the separation of regulated utilities and their non-regulated affiliates and information exchange among the affiliates. The rules prohibit the utilities from engaging in certain practices that would discriminate against energy service providers that compete with the Utility’s non-regulated affiliates. The CPUC has also established specific penalties and enforcement procedures for affiliate rules violations.
On April 3, 2001, the CPUC issued an order instituting an investigation into whether the California investor-owned utilities, including the Utility, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC will investigate (1) the utilities’ transfer of money to their holding companies, including times when their utility subsidiaries were experiencing financial difficulties, (2) the failure of the holding companies to financially assist the utilities when needed, (3) the transfer by the holding companies of assets to unregulated subsidiaries, and (4) the holding companies’ actions to “ringfence” their unregulated subsidiaries. The CPUC will also determine whether additional rules, conditions, or changes are needed to adequately protect ratepayers and the public from dangers of abuse stemming from the holding company structure. The CPUC will investigate whether it should modify, change, or add conditions to the holding company decisions, make further changes to the holding company structure, alter the standards under which the CPUC determines whether to authorize the formation of holding companies, otherwise modify the decisions, or recommend statutory changes to the California Legislature. As a result of the investigation, the CPUC may impose remedies, prospective rules, or conditions, as appropriate. PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders.
On January 9, 2002, the CPUC issued two decisions in its pending investigation. In one decision, the CPUC interpreted the first priority condition and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies “infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve.” The CPUC also interpreted the first priority condition as prohibiting a holding company from (1) acquiring assets of its utility subsidiary for inadequate consideration, and (2) acquiring assets of its utility subsidiary at any price, if such acquisition would impair the utility’s ability to fulfill its obligation to serve or to operate in a prudent and efficient manner. The utilities’ applications for rehearing were denied on July 17, 2002.
In the other decision, the CPUC denied the motions filed by the California utility holding companies to dismiss the holding companies from the pending investigation on the basis that the CPUC lacks jurisdiction over the holding companies. However, in the decision interpreting the first priority condition discussed above, the CPUC separately dismissed PG&E Corporation (but no other utility holding company) as a respondent to the proceeding. In its written decision mailed on January 11, 2002, the CPUC stated that PG&E Corporation was being dismissed so that an appropriate legal forum; i.e., the state court action discussed below, could decide expeditiously whether adoption of the Utility’s proposed plan of reorganization would violate the first priority condition. The utilities’ applications for rehearing were denied on July 17, 2002.
The holding companies filed petitions for review of both the CPUC’s capital requirements and jurisdiction decisions in several state appellate courts, and the utilities also filed petitions for review of the capital requirements decision with the California appellate courts. The CPUC moved to consolidate all proceedings in the San Francisco state appellate court and requested that the court extend the deadline by which the CPUC must file its responses to the petitions for review until after the consolidation occurred. The CPUC’s request for consolidation was granted and all of the petitions are now before the First Appellate District in San Francisco, California.
On January 10, 2002, the AG filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against the directors of the Utility, alleging PG&E Corporation violated various conditions established by the CPUC and engaged in of unfair or fraudulent business practices or acts. The AG also alleges that the December 2000 and the January and February 2001 restructuring transactions by which NEG and its subsidiaries complied with credit rating agency criteria to establish independent credit ratings violated the holding company conditions.
In PG&E Corporation’s view, the U.S. Bankruptcy Court for the Northern District of California (Bankruptcy Court) has original and exclusive jurisdiction of these claims. Therefore, on February 8, 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Court to transfer the AG’s complaint to the Bankruptcy Court. On February 15, 2002, a motion to dismiss the lawsuit or, in the alternative, to stay the suit was filed. Subsequently, the California AG filed a motion to remand the action to state court. In June 2002, the Bankruptcy Court held that federal law preempted the AG’s allegations concerning PG&E Corporation’s participation in the Utility’s bankruptcy proceedings. The Bankruptcy Court directed the AG to file an amended complaint omitting these allegations and remanded the amended complaint to the San Francisco Superior Court. Both parties have appealed the Bankruptcy Court’s remand order. The appeal and cross-appeal are pending in the U.S. District Court for the Northern District of California. On August 9, 2002, the AG filed its amended complaint in the San Francisco Superior Court, omitting the allegations concerning PG&E Corporation’s participation in the Utility’s bankruptcy proceedings. PG&E Corporation and the directors named in the complaint have filed motions to strike certain allegations of the amended complaint. These motions are pending. PG&E Corporation believes that the allegations of the complaint are without merit and will vigorously respond to and defend the litigation.
On February 11, 2002, a complaint entitled, City and County of San Francisco, People of the State of California v. PG&E Corporation and Does 1-150, was filed in San Francisco Superior Court. The complaint contains some of the same allegations contained in the AG’s complaint including allegations of unfair competition in violation of California Business and Professions Code Section 17200. In addition, the complaint alleges causes of action
for conversion, claiming that Parent “took at least $5.2 billion from PG&E,” and for unjust enrichment. Among other allegations, plaintiffs allege that past transfers of money from the Utility to PG&E Corporation, and alleged use of such money by PG&E Corporation to subsidize other affiliates of PG&E Corporation, violated various conditions established by the CPUC in decisions approving the holding company formation. The complaint also alleges that certain restructuring transactions by which PG&E Corporation’s subsidiaries complied with credit rating agency criteria to establish independent credit ratings violated the holding company conditions. Plaintiffs also allege that by agreeing to certain covenants in certain financing agreements, PG&E Corporation also violated a holding company condition. Plaintiffs seek injunctive relief, the appointment of a receiver, restitution, disgorgement, the imposition of a constructive trust, civil penalties, and costs of suit. After removing the City’s action to the Bankruptcy Court on February 8, 2002, PG&E Corporation filed a motion to dismiss the complaint. Subsequently, the City filed a motion to remand the action to state court. In June 2002, the Bankruptcy Court issued an Amended Order on Motion to Remand stating that the Bankruptcy Court retained jurisdiction over the causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by the City and County, but remanding the Section 17200 cause of action to the San Francisco Superior Court. Both parties have appealed the Bankruptcy Court’s remand order. The appeal and cross-appeal are pending in the United States District Court for the Northern District of California. Following remand, PG&E Corporation brought a motion to strike. The motion is pending. PG&E Corporation believes that the allegations of the complaint are without merit and will vigorously respond to and defend the litigation.
In addition, a third case, entitled Cynthia Behr v. PG&E Corporation, et al., was filed on February 14, 2002 by a private plaintiff in Santa Clara Superior Court against PG&E Corporation and its directors, Pacific Gas and Electric Company’s directors, and other parties, also alleging a violation of California Business and Professions Code Section 17200. The allegations of the complaint are similar to the allegations contained in the Attorney General’s complaint but also include allegations of fraudulent transfer and violation of the California bulk sales laws. Plaintiff requests the same remedies as the Attorney General’s case and in addition requests damages, attachment, and restraints upon the transfer of defendants’ property. On March 8, 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Court to transfer the complaint to the Bankruptcy Court. Subsequently, the plaintiff filed a motion to remand the action to state court.
In its June 2002 ruling referred to above as to the Attorney General’s case, the Bankruptcy Court retained jurisdiction over Behr’s fraudulent transfer claim and bulk sales claim, finding them to belong to Pacific Gas and Electric Company’s estate. The Bankruptcy Court remanded Behr’s Section 17200 claim to the Santa Clara Superior Court. Both parties have appealed the Bankruptcy Court’s remand order. The appeal and cross-appeal are pending in the United States District Court for the Northern District of California. PG&E Corporation believes that the allegations of the complaint are without merit and will vigorously respond to and defend the litigation.
PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders, but neither has informed PG&E NEG that PG&E Corporation or the Utility can predict what the outcomes of the CPUC’s investigation, the AG’s petition to the SEC, and the related litigation will be or whether the outcomes will have a material adverse effect on their or PG&E NEG’s results of operations or financial condition.
ITEM 14.
ITEM 14. Controls and Procedures.
Based on an evaluation of PG&E NEG’s disclosure controls and procedures conducted on February 3, 2003, PG&E NEG’s principal executive officer and principal financial officer have concluded that such controls and procedures effectively ensure that information required to be disclosed by PG&E NEG in reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported, within the time periods specified in the SEC rules and forms.
There were no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.
PART IV.
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
* Incorporated by reference from the Registration Statement on Form S-4, as amended, file no. 333-66032 filed by the Registrant with the SEC on July 27, 2001.
 Management contract or compensatory plan.
PG&E NEG filed a Current Report on Form 8-K on November 18, 2002, disclosing various defaults under PG&E NEG’s financing arrangements.
PG&E NEG filed a Current Report on Form 8-K on January 16, 2003, disclosing arrangements made under various financing arrangements, recent litigation, termination of certain agreements and the disposition of various assets.
Supplemental information to be furnished with the reports filed pursuant to Section 15(d) of the Act by registrants which have not registered securities pursuant to section 12 of the Act.
NONE
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PG&E NATIONAL ENERGY GROUP, INC.
Date: March 5, 2003
/s/ Thomas E. Legro
Name: Thomas E. Legro
Title: Vice President, Controller and Chief Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
I, Thomas B. King, certify that:
1. I have reviewed this Annual Report on Form 10-K of PG&E National Energy Group, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
•
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
•
evaluated the effectiveness of the registrant’s disclosure controls and procedures within 90 days prior to the filing date of this annual report (the Evaluation Date); and
•
presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
•
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
•
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 5, 2003
/s/ Thomas B. King
THOMAS B. KING
PG&E National Energy Group, Inc.
I, Thomas Legro, certify that:
1. I have reviewed this Annual Report on Form 10-K of PG&E National Energy Group, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
•
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
•
evaluated the effectiveness of the registrant’s disclosure controls and procedures within 90 days prior to the filing date of this annual report (the Evaluation Date); and
•
presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
•
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
•
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 5, 2003
/s/ Thomas E. Legro
THOMAS E. LEGRO
Vice President, Controller, and Acting Principal Financial Officer
PG&E National Energy Group, Inc.
EXHIBIT INDEX
* Incorporated by reference from the Registration Statement on Form S-4, as amended, file no. 333-66032 filed by the Registrant with the SEC on July 27, 2001.
 Management contract or compensatory plan.
PG&E NEG filed a Current Report on Form 8-K on November 18, 2002, disclosing various defaults under PG&E NEG’s financing arrangements.
PG&E NEG filed a Current Report on Form 8-K on January 16, 2003, disclosing arrangements made under various financing arrangements, recent litigation, termination of certain agreements and the disposition of various assets.
Supplemental information to be furnished with the reports filed pursuant to Section 15(d) of the Act by registrants which have not registered securities pursuant to section 12 of the Act.
NONE
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2002, 2001, and 2000
(in millions)
(1)
The allowance for uncollectable accounts is deducted from “accounts receivable, trade” in the consolidated balance sheet. Deductions consist principally of write-offs, net of collections of accounts receivable previously written off.