ITEM 1. BUSINESS
Corporate Structure and Business Overview
PG&E National Energy Group, Inc. is an integrated energy company with a strategic focus on power generation, natural gas transmission and wholesale energy marketing and trading in North America. PG&E National Energy Group, Inc. and its subsidiaries (collectively, “NEG”, “National Energy Group”, or the “Company”) have integrated their generation, development and energy marketing and trading activities in an effort to create energy products in response to customer needs, increase the returns from operations, and identify and capitalize on opportunities to optimize generating and pipeline capacity. PG&E National Energy Group, Inc. was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation (“Parent”). Shortly thereafter, the Parent contributed various subsidiaries to the NEG. The Company’s principal subsidiaries include: PG&E Generating Company, LLC and its subsidiaries (collectively, “GenLLC”); PG&E Energy Trading Holdings Corporation and its subsidiaries (collectively, “Energy Trading” or “ET”); PG&E Gas Transmission Corporation and its subsidiaries (collectively “GTC”), which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively “GTN”), North Baja Pipeline, LLC (“NBP”), and PG&E Gas Transmission, Texas Corporation and its subsidiaries, and PG&E Gas Transmission Teco, Inc. and its subsidiaries (collectively “GTT”). See Item 6 in this report for a discussion of the sale of GTT. PG&E Energy Services Corporation (“ES”), which was discontinued in 1999, provided retail energy services. NEG also has other less significant subsidiaries.
The consolidated financial statements of NEG included herein include the accounts of 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. Our telephone number is (301) 280-6800.
NEG reports its business in two business segments, interstate pipeline operations (or “Pipeline”) and integrated energy and marketing (or “Energy”). Pipeline is comprised of GTC, which includes GTN and NBP. Energy is comprised of GenLLC and Energy Trading, which owns PG&E Energy Trading-Power, L.P. (“ET-Power”) and PG&E Energy Trading-Gas Corporation and other affiliates. Financial information for each reportable segment is included in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Note 15 of the “Notes to Consolidated Financial Statements.”
Natural Gas Transmission Business
In our Pipeline business segment, we own, operate and develop natural gas pipeline facilities, including our Gas Transmission Northwest, or GTN, pipeline, an interest in the Iroquois pipeline, and the North Baja pipeline.
The following table summarizes our gas transmission pipelines:
Gas Transmission Northwest
Our GTN pipeline consists of over 1,350 miles of natural gas transmission pipeline with a capacity of approximately 2.7 billion cubic feet of natural gas per day. Our GTN pipeline 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. This pipeline commenced commercial operation in 1961 and has subsequently expanded various times through 2001. This pipeline is the largest transporter of Canadian natural gas into the United States and is the only pipeline directly linking the natural gas reserves in western Canada to the gas markets of California and parts of the Pacific Northwest.
The mainline system of our GTN pipeline is composed of two parallel pipelines with 13 compressor stations totaling approximately 415,900 horsepower and ancillary facilities which include metering and regulatory facilities and a communication system. GTN’s dual pipeline system consists of approximately 639 miles of 36-inch mainline pipe and approximately 590 miles of 42-inch mainline pipe. A third parallel line with 21 miles of 42-inch mainline pipe commenced service November 2001. The GTN pipeline includes two pipeline extensions, the Coyote Springs Extension, which supplies natural gas to Portland General Electric Company, and the Medford Extension, which supplies natural gas to Avista Utilities and Pacificorp Power Marketing. GTN’s pipeline facilities interconnect with the facilities owned by the Pacific Gas and Electric Company (the “Utility”) at the Oregon-California border, with the facilities owned by Northwest Pipeline Corporation (Northwest Pipeline) in Northern Oregon and in Eastern Washington, and with the facilities owned by Tuscarora Gas Transmission Company (Tuscarora) in Southern Oregon. It also delivers gas along various mainline delivery points to two local gas distribution companies.
GTN 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. During 2001, 95.2% of GTN’s available long-term capacity was committed to firm transportation services agreements with terms in excess of one year. At December 31, 2001, 99.6% of GTN’s available long-term capacity was held under long-term firm transportation agreements. The terms of these long-term firm contracts range between one and 24 years, with a volume-weighted average remaining term of approximately 12 years, as of December 31, 2001.
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 its pipeline. If weather, maintenance schedules and other conditions allow, additional firm capacity may become available on a short term basis. GTN provides interruptible transportation service when capacity is available. Interruptible capacity 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, GTN allocates discounted and/or negotiated interruptible space on a highest to lowest total revenue basis.
At December 31, 2001, GTN provided transportation services for 88 customers, 44 of which had long-term firm service transportation agreements with GTN. The remaining customers utilize hub services or short-term firm, interruptible or capacity release contracts. Our customers 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, and industrial companies. Our customers are responsible for securing their own gas supplies and delivering them to our pipeline system. We transport our customers’ natural gas supplies either to downstream pipelines and distribution companies or directly to points of consumption.
GTN is in the process of completing its 2002 expansion project, which, when completed, will expand the capacity of its system by approximately 217 million cubic feet (“MMcf”) per day. Approximately 40 MMcf per day of that expansion capacity was placed in service in November 2001 and we expect the remaining capacity will be placed in service by the end of 2002. The total cost of the expansion is estimated to be $122 million. GTN has filed an application with the FERC for approval to complete another expansion of approximately 150 MMcf per day of additional capacity, at a cost of approximately $111 million. GTN expects to fund these expansions from cash provided by operations and, to the extent necessary, external financing and capital contributions from NEG. GTN has also initiated a preliminary assessment of a Washington lateral pipeline that would originate at the GTN mainline system near Spokane, Washington and extend west approximately 260 miles into the Seattle/Tacoma metropolitan area.
Iroquois Pipeline
We own 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, 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 FERC to expand its system capacity, and to extend the pipeline into Eastern Long Island.
North Baja Pipeline
Our subsidiary, NBP, is developing an approximately 80-mile natural gas pipeline, with an initial certificated capacity of 500 MMcf per day, to be located in Arizona and southeastern California and is expected to cost approximately $146 million. This new pipeline will deliver natural gas to a pipeline being developed by Sempra Energy International. The 135-mile Sempra pipeline will interconnect with NBP at the California-Mexico border and transport gas into Northern Mexico and Southern California. We have entered into a joint development agreement with Sempra to coordinate our development activities. On January 16, 2002, the FERC issued a certificate of public convenience and necessity authorizing NBP to construct and operate our proposed pipeline. NBP is projected to be in partial service in the third quarter of 2002 and full service in the fourth quarter of 2002.
The FERC and California State Lands Commission ("CSLC") jointly prepared an Environmental Impact Statement/Environmental Impact Report, which evaluated the environmental impact of the North Baja pipeline. On March 4, 2002, we were served with a complaint filed by Imperial County and the City of El Centro, California, in California Superior Court (Sacramento) against CSLC, NBP, and other parties. This complaint seeks to set aside CSLC's environmental review and to enjoin NBP from proceeding with its pipeline project during the pendency of the litigation. We believe that this litigation is without merit and intend to support the CSLC's environmental review.
We have signed agreements with five customers to transport up to 92% of the initial projected daily capacity in 2002 and 2003 and 100% of the initial capacity in 2004 and beyond. Of this amount, approximately 47 MMcf per day is under a contract with one of our subsidiaries. The weighted average term of these agreements is in excess of 20 years. We are continuing discussions and negotiations with other potential customers and working with Sempra Energy International on the potential for an expansion.
Integrated Energy and Marketing Business
In our Energy business segment, we engage in the generation, transport, marketing and trading of electricity, various fuels and other energy-related commodities throughout North America. During the year ended December 31, 2001, we sold approximately 280 million MW hours of power, 21.5 billion cubic feet per day of natural gas (including financial transactions) and 15 million tons of coal. We aggregate electricity and related products from our owned, leased or controlled generating facilities and our marketing and trading positions, and we manage the fuel supply and sale of electrical output from all these positions in an integrated portfolio. The objective of our integrated approach is to enable us to effectively manage our exposure to commodity price and counterparty credit risk. As of December 31, 2001, NEG had ownership or leasehold interests in 25 operating generating facilities with a net generating capacity of 6,518 megawatts (“MW”), as follows:
In addition, NEG has seven facilities totaling 5,430 MW in construction and controls, through various arrangements, 581 MW in operation and 2,313 MW in construction, with a total owned and controlled generating capacity in operation or construction of 14,842 MW. We may sell selected operating assets and have identified three of our New England facilities for possible sale. We have established a 2002 target of at least $250 million of after-tax proceeds from the sale of operating and development assets. NEG also has approximately 6,000 MW of natural gas-fired projects in development.
We provide operating and/or management services for 23 of our 25 owned and leased generating facilities. Our plant operations are focused on maximizing the availability of a facility to generate power during peak energy price hours, improving operating efficiencies and minimizing operating costs. We place a heavy emphasis on safety standards, environmental compliance and plant flexibility.
Our generating facilities can be divided into two categories based on the method of sale of their electric output. The first category is generating facilities that 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. These generating facilities are generally referred to as “independent power projects.” The second category is generating facilities that sell their electrical output in the competitive wholesale electric market or under contractual arrangements of various terms. These generating facilities are generally referred to as “merchant plants.”
All of the generating facilities we developed or placed in operation prior to 1997 are independent power projects, while almost all those we acquired, placed in operation or acquired control through contracts during or after 1997 are merchant plants. Most of our generating facilities under construction or development are generally expected to be operated as merchant plants.
Independent Power Projects
We hold our interests in independent power projects through wholly owned subsidiaries. We had a net ownership interest of 1,163 MW in independent power projects in operation and one 111 MW plant under construction as of December 31, 2001. Typically, we manage and operate 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 our independent power projects, 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 by our independent power projects 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.
Merchant Plants
We currently own or have committed to lease or acquire 13 merchant plants in operation and six merchant plants under construction in six states that will result in an owned or leased merchant plant portfolio that will have a net generating capacity of approximately 10,701 MW. These projects are expected to be placed in service in 2002 and 2003. We consider a generating facility to be under construction once we or the lessor has acquired the necessary permits to begin construction, executed a construction contract, delivered an unqualified notice to commence construction and broken ground at the project.
We manage the sale of the electric output from our merchant plants through integrated teams that include marketing, trading and plant operating personnel. We have closely linked the personnel on our trading floor with those in our generating facilities’ control rooms through the electronic sharing of both market and operating data. This real-time exchange of market and operating information allows us to make better informed decisions to vary the output of, and fuel used in, our generating facilities in response to constantly changing regional power demand and prices. We coordinate our maintenance decisions to balance maintenance costs against lost profit opportunity from downtime, seeking to carry out our maintenance in periods of low power prices. We generally do not sell the output of a specific merchant plant to a specific customer but rather combine the output of our merchant plants with market purchases of electricity to increase the reliability of, and provide our customers and fuel suppliers with, flexible power products.
Contractual Control of Generating Capacity
We have increased our generating capacity through contractual control of the electric output of generating facilities. We have executed various long-term contracts representing 2,831 MW of generating capacity, which result in control of 581 MW of operating generating capacity and 2,313 MW of generating capacity in construction as of December 31, 2001. These contracts include control of all or a portion of the output of 16 smaller generating facilities through arrangements with New England Power Company (“NEPCo”), directly with the facilities or through other arrangements. In return for our assumption of the purchase obligations under these agreements, NEPCo has agreed to pay to NEG an average of $111 million per year through January 2008 to offset our payment obligations under these contracts.
Apart from the contracts with NEPCo, our primary method of achieving contractual control of generating capacity is through tolling agreements. Tolling agreements establish a contractual relationship that grants us the right to use a third party’s generating facility to convert our fuel, typically natural gas, to electricity. We have the right to decide the timing and amount of electricity production within agreed operating parameters. The owner of the facility receives a fixed capacity payment for the committed availability of its facility and a variable payment for production costs. The fixed payment is generally subject to reduction if the owner fails to meet specified targets for facility availability and other operating factors.
The terms of the five tolling agreements we have in our portfolio as of December 31, 2001 range from 9 to 25 years commencing on the date of initial commercial operations of the generating facility. Most of the generating facilities are under construction with commercial operations expected to commence between 2002 and 2004. These tolling agreements provide us with control of gas-fired plants in the Mid-Atlantic, Midwestern, Southern and Western regions of the United States.
Description of our Generating Facilities in Operation and Construction
The following table provides information regarding each of our owned or controlled operating generating facilities, as well as those under construction as of December 31, 2001:
(1)
Megawatts for our owned facilities are based on nominal MW, defined as typical new and clean output at 59 degrees Fahrenheit at sea level. Megawatts for contract-based output are based on the quantities stated in the contracts.
(2)
Our net interest in the total MW of an independent power project is determined by multiplying our percentage of the project’s expected cash flow by the project’s total MW. Accordingly, the net interest in total MW does not necessarily correspond to our current percentage ownership or leasehold interest in the project affiliate.
(3)
We control all or a portion of the output of these 14 smaller generating facilities, together with the Milford Power Project, the Pawtucket Power Project and 113 MW from the Pittsfield Project under long-term power purchase agreements. In return for our assumption of the purchase
obligations under these agreements from NEPCo, NEPCo had agreed to pay an average of $111 million per year through January 2008 to offset our payment obligations under these contracts. The power purchase agreements terminate between 2009 and 2029. Effective February 1, 2002, our arrangement with the Pawtucket Power Project was replaced with a system power supply arrangement with an affiliate of Pawtucket Power. We have a leased beneficial interest in the Pittsfield Project, 50 MW of which is included in the 113 MW referenced above. An additional 27 MW of our interest are sold under other long-term power purchase agreements.
(4)
We have executed construction contracts for up to 163 MW at two hydroelectric facilities on the Ohio River in Kentucky. The first 16 MW unit is under construction. Our obligation to fund the remaining units is contingent upon the commencement of successful operations of this first unit in 2003.
(5)
We have consolidated the assets and liabilities related to these entities as required under Generally Accepted Accounting Principles (“GAAP”).
The following section describes each of our owned or controlled generating facilities in operation or construction in excess of 250 MW.
New England Region Generating Facilities
Operating Facilities
Brayton Point Station. We own a 100% interest in Brayton Point Station, the largest fossil-fired generating facility in New England with an aggregate generating capacity of 1,599 MW. This facility, located in Somerset, Massachusetts, on a 225-acre waterfront site, has three units of 255 MW, 255 MW and 633 MW which are fueled primarily by coal, one unit of 446 MW which burns either natural gas or heavy fuel oil depending on relative cost and availability, and also includes 10 MW of on-site diesel generators. The first unit at this facility commenced commercial operations in 1963, with all units in operation by 1974. Brayton Point Station sells all of its electrical output in the competitive market.
Deliveries of coal and fuel oil are currently made at a deep-water port located at this facility. We have secured a portion of the shipping requirements for coal to this facility through the long-term charter of the Energy Enterprise, a self-unloading vessel capable of delivering 75% of the normal annual coal requirements of this facility and our Salem Harbor facility. In 1991, Brayton Point was connected to a high-pressure natural gas transmission system and all existing units have some gas firing capability. There is approximately 1.3 million barrels of fuel oil storage capacity in five tanks at this facility.
Salem Harbor Station. We own a 100% interest in the Salem Harbor Station, a 745 MW fossil-fired generating facility located on a 65-acre waterfront site in Salem, Massachusetts. Salem Harbor Station, which commenced commercial operations in 1952, consists of three units of 84 MW, 80 MW and 150 MW that are capable of burning coal, oil or a combination of the two, and one unit of 432 MW which burns only fuel oil. Deliveries of coal and fuel oil are currently made at a deep water port located at this facility. Salem Harbor Station sells all of its electrical output in the competitive market.
Bear Swamp. We hold a 48-year lease, with renewal options, on the Bear Swamp Facility, which consists of Bear Swamp Pumped Storage Station, a 589 MW fully automated pumped storage facility, and Fife Brook Station, a 10 MW conventional hydroelectric facility. This facility commenced commercial operations in 1974 and has an aggregate generating capacity of 599 MW. It occupies approximately 1,300 acres on the Deerfield River located in the towns of Rowe and Florida, Massachusetts. The Bear Swamp facility sells all of its electrical output in the competitive market.
The Bear Swamp Pump Storage Station operates by pumping water up to a holding pond 770 feet above the Deerfield River when electricity is relatively low priced and releasing this water to generate electricity when prices are relatively high. It has a storage capacity equal to five hours of generation at full capacity and typically generates power during weekdays and pumps and stores water during weekends and nights. We believe the flexibility of this facility complements our baseload facilities in the region and allows us to more efficiently supply higher value energy products such as full requirements supply.
Manchester Street Station. We own 100% of Manchester Street Station, a 495 MW combined-cycle gas-fired facility located in Providence, Rhode Island. Previously a coal, oil and gas steam facility, Manchester Street Station was completely repowered in 1995. This facility has three units that burn natural gas as their primary fuel and is capable of firing oil as an emergency back-up fuel to natural gas. Manchester Street Station sells all of its electrical output in the competitive market.
Connecticut River System. We own 100% of the Connecticut River System, a conventional hydroelectric system located along the Connecticut River in New Hampshire and Vermont. The Connecticut River System consists of six stations with 26 generating units that are capable of producing an aggregate generating capacity of 484 MW. Through its series of reservoirs, dams and powerhouses, this system manages the flow of approximately 300 miles of the Connecticut River. Two of the six stations operate mainly during peak periods in order to respond quickly to high prices for electricity. The Connecticut River System sells all of its electrical output in the competitive market.
Millennium. We own 100% of the Millennium Power Project, a 360 MW natural gas-fired combined-cycle generating facility located in Charlton, Massachusetts. It began commercial operations in April 2001. Millennium was constructed by Bechtel Power Corporation. This facility incorporates the second installation from Siemens Westinghouse Power Corporation’s 501G combustion turbine line and the first to be developed in a combined-cycle configuration. It is intended to operate on both natural gas and fuel oil. Millennium sells all of its electrical output in the competitive market.
MASSPOWER. We own a 13% interest in MASSPOWER, a 267 MW gas-fired combined cycle cogeneration facility located in Springfield, Massachusetts. Our net equity interest in this facility’s aggregate generating capacity is approximately 35 MW. 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 provide for capacity and energy payments and have fuel escalation clauses. MASSPOWER sells the balance of its electrical capacity and output, approximately 25%, to ET-Power. 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.
NEPCo Power Purchase Agreements. We control the output of 16 smaller generating facilities under long-term power purchase agreements. The facilities we control in whole or in part through these power purchase agreements include the 171 MW Milford Power Project, the 173 MW Pittsfield Project, and 14 other small generating facilities with a total generation capacity of 193 MW fueled by municipal waste, water, landfill gas or wood. The power purchase agreements terminate between 2005 and 2029.
Generating Facilities Under Construction
Lake Road. The Lake Road facility is an 840 MW natural gas-fired combined-cycle plant located in Killingly, Connecticut. This facility is being constructed by Alstom Power, Inc. (“Alstom”) under a fixed price construction contract. This facility will consist of three Alstom GT24 combustion turbines and is intended to be capable of firing low sulfur distillate fuel oil as an alternative fuel source. Lake Road is anticipated to sell all of its electrical output in the competitive market. Lake Road is expected to commence operations in 2002.
Mid-Atlantic and New York Region Generating Facilities
Operating Facilities
Selkirk. We own an approximately 42% interest in the Selkirk Cogeneration Facility, a 345 MW natural gas-fired combined-cycle cogeneration facility located near Albany, New York. Our net equity interest in this facility’s aggregate generating capacity is approximately 145 MW. 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 QF under 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. We have no reason to believe that General Electric will reduce or cease its steam purchases.
Carneys Point. We own a 50% interest in Carneys Point Generating Facility, a 269 MW pulverized coal cogeneration facility. Our net equity interest in this facility’s aggregate generating capacity is 135 MW. 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 average coal price.
Generating Facilities Under Construction
Athens. The Athens Generating project is an approximately 1,080 MW natural gas-fired combined-cycle project that is currently under construction in Athens, New York. Athens will consist of three advanced Siemens-Westinghouse 501G combustion turbine generators and associated systems and facilities. Bechtel Power Corporation (“Bechtel”) is constructing the facility pursuant to a fixed price construction contract. Bechtel was released to commence construction at the end of May 2001. This project is expected to be the first new merchant power plant in the New York Power Pool since the pool was formed and will sell power primarily into this power pool on a competitive basis. Athens is expected to commence commercial operations in 2003.
Liberty Electric Toll. The Liberty Electric facility is an approximately 568 MW natural gas-fired electric generation facility owned and being constructed by Orion Power Holdings outside Philadelphia, Pennsylvania. This facility will use General Electric 7FA gas turbines and is expected to commence commercial operations in 2002.
Under a tolling agreement to commence on the later of April 1, 2002 or the date the facility commences commercial operations, we will pay Liberty a monthly fee for the right to convert natural gas into electricity at the 568 MW facility for 14 1/2 years. Liberty must provide us with all of the energy, capacity and ancillary services related to the operation of the facility.
Midwest Region Generating Facilities
Generating Facilities Under Construction
Covert. Covert is an approximately 1,170 MW natural gas-fired combined-cycle project currently under construction in Covert, Michigan. This project will consist of three Mitsubishi 501G combustion turbine generators and associated systems and facilities. This project is being constructed by The Shaw Group. The Shaw Group was released to commence construction in June 2001. Covert is anticipated to sell all of its output in the competitive market. Covert is expected to commence commercial operations in 2003.
Southern Region Generating Facilities
Operating Facilities
Attala. The Attala Power Project is a 526 MW natural gas-fired combined-cycle power plant in Attala County, Mississippi, which commenced commercial operation in June 2001. We acquired Attala from Duke Energy North America in September 2000. Attala consists of two General Electric 7FA combustion turbine generators. This facility sells all of its electric output in the competitive market. Attala is directly interconnected into the Entergy wholesale market.
Indiantown. We own a 35% interest in the Indiantown Cogeneration Facility, a 360 MW pulverized coal cogeneration facility located on an approximately 240-acre site in Martin County, Florida. Our net equity interest in this facility’s aggregate generating capacity is approximately 126 MW. 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 Caulkins Indiantown Citrus Company (“Caulkins”) under an energy services agreement with an initial term of 15 years. Under the energy services agreement, Caulkins 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. We have negotiated changes to the coal contract with Lodestar, which has assumed and continues to perform under the contract.
Cedar Bay. We have a 50% economic interest in the Cedar Bay Generating Facility, a 269 MW coal-fired cogeneration facility located in Jacksonville, Florida. Our net equity interest in this facility’s aggregate generating capacity is 135 MW Cedar Bay, which commenced commercial operations in 1994, 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 19 years that expires in 2013. Cedar Bay also sells up to 215,000 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. The former coal supplier to Cedar Bay, Lodestar, is currently in bankruptcy. Lodestar has rejected the coal supply contract and we are now purchasing coal from a new supplier at prices in excess of those which were charged under the Lodestar contract.
Generating Facilities Under Construction
Southaven Toll. Southaven is an approximately 810 MW natural gas-fired combined cycle cogeneration facility being constructed by Cogentrix in Southaven, Mississippi. Cogentrix will use GE 7FA gas turbines at this facility. The project is expected to commence commercial operations in 2003.
Pursuant to a twenty year tolling agreement that will commence upon completion of this facility, we will pay Southaven a monthly fee for the right to deliver natural gas and dispatch up to 810 MW of the electrical output and capacity from this facility.
Caledonia Toll. Caledonia is an approximately 810 MW natural gas-fired combined cycle cogeneration facility owned and being constructed by Cogentrix in Caledonia, Mississippi. Cogentrix will use GE 7FA gas turbines at this facility. The project is expected to commence commercial operations in 2003.
Pursuant to a twenty-five year tolling agreement that will commence upon completion of this facility, we will pay Caledonia a monthly fee for the right to deliver natural gas and dispatch up to 810 MW of the electrical output and capacity from this facility.
Western Region Generating Facilities
Operating Facilities
Hermiston. We own a 50% interest in the Hermiston Generating Facility, a 474 MW natural gas-fired cogeneration facility located in Hermiston, Oregon. Our net equity interest in this facility’s aggregate generating capacity is approximately 237 MW. 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.
We sell our 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.
Generating Facilities Under Construction
La Paloma. The La Paloma Generating Facility is an approximately 1,121 MW natural gas-fired combined-cycle generating facility currently under construction in western Kern County, California. This facility is being constructed by Alstom under a fixed price construction contract. La Paloma will consist of four Alstom GT24 combustion turbines and associated systems and facilities. This facility will be our first gas-fired merchant power plant in the California wholesale electric market. La Paloma is expected to commence commercial operations in late 2002.
Harquahala. Harquahala is an approximately 1,092 MW natural gas-fired combined-cycle generating project near Phoenix, Arizona. We commenced construction in May 2001. Harquahala is being constructed by The Shaw Group. This project will be a combined-cycle power facility using three Siemens Westinghouse 501G advanced combustion turbine generators and will be equipped with a zero liquid discharge system to minimize water consumption and the creation of wastewater. Harquahala is expected to commence commercial operations in 2003. The project is anticipated to sell all of its electrical output into the competitive market.
Otay Mesa Toll. The Otay Mesa facility is a 500 MW natural gas-fired combined-cycle facility currently in construction in San Diego County, California. This facility is currently scheduled to commence commercial operations in 2004. We sold this project to Calpine Corporation in 2001. We retained control of 125 MW through a 10-year tolling agreement. We expect to sell the output under this tolling agreement into the competitive market. Calpine will use General Electric 7FA gas turbines at this facility.
Greenfield Development
We have been actively engaged in the development and construction of power generating facilities since 1989. Historically, we have focused principally on the development and construction of natural gas-fired and coal-fired generating facilities. We also have developed facilities that utilize other electric generating technologies, including wind.
Our most mature development projects are natural gas-fired combined-cycle generation facilities and consist of the following:
These projects were all planned for operation in 2004, with construction starting prior to mid 2002. Recent changes in the power markets have caused us to defer these projects. As a result of our review of market conditions for new generation, we expect to delay all of our development projects, and to swap or sell some of our generation projects under development. In the case of projects that we do retain, we intend to manage our permit and equipment commitments to enable us to delay the start of construction until market conditions warrant, generally between 12 and 36 months from the original plan. Delaying our development projects, including Mantua Creek, will result in capital expenditure savings of approximately $1 billion in each of the years 2002 and 2003.
Development has largely been completed for our Mantua Creek project and it is ready to begin construction. We have entered into a construction contract for the facility and released the contractor to perform a limited amount of early construction activities. As of December 31, 2001, we have recorded assets of $168 million for Mantua Creek, representing equipment payments, construction activities and development costs. In light of the current market outlook, we are planning to delay construction of this facility for at least 12 months. We have commenced negotiations with our construction contractor and other parties to the project to address this delay. If we are unable to reach agreement with these parties and we decide to abandon the project we will be required to write-off approximately $110 million of capitalized and termination costs. This amount does not include major equipment costs. If we are able to reach agreement with these parties, we could defer our near-term capital expenditures, including equipment. In either the deferral or cancellation situation, we would not incur capital expenditures of approximately $293 million in 2002 and $140 million in 2003 each of which are included under
Construction Commitments and Turbine and Equipment Purchase Commitments for Construction Projects in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation below.
Equipment Procurement
To support our development program, we have contractual commitments and options for combustion turbines and related equipment representing approximately 14,000 MW of net generating capacity, including the 3,868 MW identified in “Greenfield Development” above. The following table describes the turbines for which we have contractual commitments or options to use in our development projects:
(1)
Approximate baseload and peaking/intermediate capacity based on anticipated configuration of the turbine.
The agreement with Mitsubishi includes steam turbines and heat recovery steam generators. For the GE turbines, we have entered into separate agreements with Hitachi to supply steam turbines and heat recovery steam generators. We also have agreements with Hitachi for long lead-time main step-up transformers for both the Mitsubishi and GE equipment.
As a result of our continuing review of our development program, we may defer, cancel, sell, joint venture or otherwise dispose of some or all of our projects in development and the equipment associated with those projects. In connection with our current revised development plans, we have restructured some of the equipment purchase and option commitments to provide additional flexibility in payment terms and delivery schedules to better accommodate the potential delay, swap or sale of generation projects in development. If we determine to further defer or cancel a project, we may create a mismatch between equipment delivery schedules and our development plans. If equipment delivery schedules cannot be adjusted, we may be compelled to choose between paying for equipment which we would have to store for future use or terminating the commitments to purchase equipment. If we decide to terminate such commitments to purchase, the Company would incur costs to the equipment vendors consisting of amounts shown as assets on our balance sheet plus all additional cash payments, if any, due upon termination (“Termination Costs”). Our exposure for these Termination Costs gradually increases over time. Our cash exposure for Termination Costs would be offset by amounts expended for the equipment through the date of termination.
Generally, each of our equipment supply contracts allows us to cancel any or all of our commitments to purchase the equipment for a predefined cost. To date, we have not cancelled any of our equipment commitments or options. We continue to work with our vendors to defer payments, delay increases of termination fees and revise equipment delivery dates. We have good relationships with our vendors and have, to date, been largely successful in these efforts. However, we cannot assure you that we will continue to be able to modify these agreements to minimize our Termination Costs and match equipment deliveries with our evolving development plans. Our estimates of our exposure for Termination Costs are, in part, based upon current contractual arrangements and amendments thereto.
Without any further delays or agreements with our equipment vendors, our committed costs for equipment related to our entire development program (except Mantua Creek) would be approximately $18 million in 2002 and $160 million in 2003 and are included in Turbine and Equipment Purchase Commitments for Development Projects in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Our aggregate Termination
Costs for our entire development program other than Mantua Creek was $247 million as of December 31, 2001, and is estimated to increase to $254 million at December 31, 2002 and $368 million at December 31, 2003. We have recorded $221 million (excluding Mantua Creek) of prepayments for equipment on our December 31, 2001 balance sheet.
We are currently marketing four of our development projects for potential sale. If we find a buyer that is willing to purchase equipment which may be used with a purchased project, and we are able to comply with the conditions in our equipment contracts, we can avoid paying termination costs. However, we can not assure you that we will be successful in selling any or all of these projects or that the buyers will be able or willing to undertake our equipment purchase obligations.
Turbine Technology
Many of our turbine purchases and commitments use the latest generation of combustion technology, which is commonly known as G technology. These G technology turbines are designed to result in higher capacity utilization, lower cost output and 2% to 4% higher combustion efficiency than the F technology turbines generally being deployed in most new generating facilities in North America. We also have secured rights to twenty-three 7FB turbines from General Electric. These turbines are expected to be slightly less efficient than G technology turbines, but are designed to have 1% to 2% higher combustion efficiency than the more standard F technology turbines. In light of our deployment of advanced technology, we have also arranged with each of our turbine vendors for long-term service agreements. These agreements have predetermined pricing, and cover scheduled major overhauls, parts and associated labor, for at least ten years.
Two of the suppliers of G technology turbines have encountered problems in their initial commercial installations of these turbines. Our Lake Road and La Paloma facilities are being constructed by Alstom Power, Inc. Alstom has advised us that it may take up to three years to develop and implement modifications to its G technology turbines that are necessary to achieve the guaranteed level of efficiency and output. We expect that the Lake Road and La Paloma facilities will begin commercial operations at reduced performance and output levels because of the technology issues with Alstom’s G technology turbines. We also encountered start-up problems with the Siemens Westinghouse G technology installed in our Millennium facility. These problems delayed the original date of commercial operations for this facility, which began commercial operations in April 2001. Commercial operations commenced pursuant to a settlement agreement among Millennium, Bechtel and Siemens which, among other things, deferred fuel oil commissioning and testing. The facility has not yet demonstrated satisfactory performance using fuel oil and availability has been hampered by continuing new technology issues. We do not expect that the start-up and initial operations problems with the Siemens Westinghouse G technology turbine installed at the Millennium facility will result in a long-term reduction of performance below guaranteed levels of efficiency or output. The construction contracts for each of the Millennium, Lake Road and La Paloma projects provide for liquidated damages that we believe could significantly offset the financial impact associated with achieving their expected level of performance.
Construction Issues
Alstom has fallen significantly behind its construction schedule on the Lake Road and La Paloma facilities and is obligated to pay liquidated damages for such delay. Alstom is implementing a recovery plan with a target commercial operations date in the first half of 2002 for Lake Road and the end of 2002 for La Paloma. In addition, we believe that Lake Road will not be able to operate on fuel oil until after commercial operations can commence. The ability to operate on fuel oil is contemplated in Lake Road’s permit from the State of Connecticut and we are keeping the State of Connecticut informed of progress on fuel oil firing capability. La Paloma is designed to use only natural gas.
Energy Marketing and Trading
NEG engages in the marketing and trading of electric energy, capacity and ancillary services, fuel and fuel services such as pipeline transportation and storage, emission credits and other related products through over-the-counter and futures markets across North America. Our marketing and trading team manages the supply of fuel for, and the sale of electric output from, our owned and controlled generating facilities and other trading positions. We also evaluate and implement structured transactions including management of third party energy assets, tolling arrangements, management of the requirements of aggregated customer load through full requirement contracts, restructured independent power project contracts and purchase and sale of transportation, storage and transmission rights through auctions and over-the-counter markets.
We use financial instruments such as futures, options, swaps, exchange for physical, contracts for differences, and other derivatives to provide flexible pricing to our customers and suppliers and manage our purchase and sale commitments, including those related to our owned and controlled generating facilities, gas pipelines and storage facilities. We also use derivative financial instruments to reduce our exposure relative to the volatility of market prices and to hedge weather, interest rate and currency volatility.
Our energy marketing and trading operations provide products and services for our integrated portfolio of assets and our customer base, including, but not limited to, the following energy-related products and services:
Electricity. We aggregate electricity and related products from our owned and controlled generating facilities and from other generators and marketers. We then package and sell such electricity and related products to electric utilities, municipalities, cooperatives, large industrial companies, aggregators and other marketing and retail entities. We also buy, sell and transport power to and from third parties under a variety of short-term contracts. We manage most of our power positions from our owned and controlled generating facilities as an integrated power portfolio. We believe that our energy marketing and trading capabilities allow our integrated portfolio of generating facilities to capitalize on opportunities across regions, time frames and commodity types. In addition to executing transactions through brokers, futures markets and over-the-counter markets, we focus on customer business that leverages our integrated asset and trading skills.
Natural Gas. We purchase natural gas from a variety of suppliers under daily, monthly, seasonal and long-term contracts with pricing, delivery and volume schedules to accommodate the requirements of our owned and controlled generating facilities and various transactions. We buy, sell and arrange transportation and storage logistics to and from third parties under a variety of agreements. Our natural gas marketing activities include contracting to buy natural gas from suppliers at various points of receipt, arranging transportation, negotiating the sale of natural gas and matching natural gas receipt and delivery points to the customer based on geographic logistics and delivery costs. We arrange for transportation of natural gas on interstate and intrastate pipelines through a variety of means, including short-term and long-term firm and interruptible agreements. We also enter into various short-term and long-term firm and interruptible agreements for natural gas storage in order to offer peak delivery services to satisfy winter heating and summer electric generating demands. These services are designed to provide an additional level of performance security, flexibility and risk mitigation to our generating facilities and customers.
Coal, Oil and Emissions. We buy, secure transportation for, and manage the sulfur content of the coal and oil requirements of our owned and controlled generating facilities. We also purchase and sell coal, oil and emissions credits from and to third parties. Our participation in the merchant coal, oil and emissions markets has enabled us to execute transactions which leverage our cross-commodity capability to further increase the effectiveness and reduce the market risk inherent in our portfolio.
Fuel Supply, Fuel Transportation and Electric Transmission Management. We enter into contracts for fuel supply, fuel transportation and electric transmission primarily to meet the needs of our owned and controlled generating facilities and to capitalize on other trading opportunities. We believe that access to long-term fuel supply, fuel transportation and electric transmission allows us to better respond to market cycles and one-time events. As such, we seek to maintain a variety of relationships with large producers and transporters with whom we enter into select long-term commitments.
Load Management or Full Requirements Arrangements. Deregulation of the energy industry has provided many consumers with the ability to seek and receive customized energy services. Consumers are particularly interested in purchasing volumes of fuel and electricity that closely match their specific needs. In order to satisfy consumer demand, an increasing number of companies aggregate blocks of customers, buy power at wholesale prices and deliver it to end-user consumers. These aggregation services are especially critical because electricity is a commodity that generally cannot be stored and therefore the electricity must be generated at the same time as it is needed for consumption. As part of our integrated energy and marketing business, we enter into contracts to supply natural gas and electricity, known as load management or full requirements supply, to these load aggregator companies in the exact amount and quality purchased by their end-user customers.
Our largest load management contracts are the wholesale standard offer service agreements with affiliates of NEPCo, from whom we purchased 4,800 MW of owned and controlled generating capacity in 1998. Under the wholesale standard offer service agreements, we supply a fixed percentage of the full requirements of the retail customers of NEPCo’s affiliates who receive standard offer service in Massachusetts and Rhode Island. These retail customers may select alternative suppliers at any time. We receive a fixed floor price for the electricity we provide under the wholesale standard offer service agreements. The base price increases periodically by specified amounts and also increases if the
prices of natural gas and fuel oil exceed a specified threshold. Our sales volumes and revenues under the wholesale standard offer service agreements totaled 17 million MW hours and $587 million in 1999, 13 million MW hours and $563 million in 2000 and 12 million MW hours and $629 million in 2001. The wholesale standard offer service agreement for Massachusetts terminates on December 31, 2004 and the wholesale standard offer service agreement for Rhode Island terminates on December 31, 2009.
Risk Management
We derive portions of our income from asset ownership and operations and from both asset-based and proprietary trading and marketing activities. We are an active participant in the electric, natural gas, coal, oil and emissions markets. Through our Energy business, we quote bid and offer prices directly to our customers as well as through brokers to other market makers.
NEG conducts its business in accordance with an established, comprehensive risk management policy that governs all business activities subject to market risks including commodity price, volume and credit. PG&E Corporation’s risk policy committee is responsible for the overall approval of the risk management policy and the delegation of approval and authorization levels. Our risk management group is structured as an independent unit in our organization and has unrestricted access to our board of directors. We believe this separate organizational structure enhances our ability to ensure the implementation and management of our risk management policies.
NEG also manages and monitors its credit, currency and interest risks pursuant to its risk management policies. These policies provide processes by which counterparties are assigned credit limits. These procedures 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, NEG seeks to reduce exposure and/or obtain additional collateral.
Market Conditions, Competition and Other Factors Impacting Our Business
Market Conditions
We buy natural gas, fuel oil, and coal to supply the fuel for our generation facilities, and often sell the electricity produced at those facilities, under short- and long-term contracts into competitive markets. The prices of the commodities that we use and sell in our businesses are often subject to extreme volatility. This volatility may result from a variety of factors, many of which are beyond our control, including:
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weather;
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the supply and demand for energy commodities;
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the availability of competitively priced alternative energy sources;
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the level of production, availability and price of natural gas, crude oil, and coal;
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transmission or transportation constraints;
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federal and state energy and environmental regulation and legislation;
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market liquidity; and
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natural disasters, wars, embargoes, and other catastrophic events.
Market conditions for the generation and sale of electricity from merchant plants have deteriorated over the course of 2001. In many regions, new supply additions now under construction, combined with reduced demand associated with the current economic recession, may result in excess electricity supply. The price of electricity minus the cost of fuel, or spark spread, available in most regional wholesale energy markets has declined recently, and prices and spark spreads in the forward markets in which we transact much of our business for our generating portfolio have declined as well. These
conditions will reduce the gross margin we earn from our merchant plants which are not under medium or long-term contracts or hedged.
On December 2, 2001, a major participant in the energy business, Enron Corporation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code (the “Enron Bankruptcy”). The Enron Bankruptcy had little impact on the energy commodity markets which have remained liquid and efficient. Although Enron was a significant participant in the energy trading business, a large portion of Enron’s transactions was purely financial, thereby minimizing impacts on the physical energy markets. In addition, significant reporting in the public press during the months preceding the Enron Bankruptcy enabled many counterparties, including the Company, to reduce their exposure to Enron.
In contrast to the minimal impact on the energy trading markets, the Enron Bankruptcy exacerbated uncertainty in the capital markets for energy companies, which was initially triggered by the California energy crisis and the Utility’s bankruptcy. Analysts are now expecting improved accounting and reporting standards and the rating agencies are reviewing the credit quality and credit ratings of many energy companies. Moody’s Investors Service (“Moody’s”) has particularly focused on ratings triggers and has indicated that it is revising its view of debt to total capitalization levels and other key credit criteria when assigning credit ratings. Continued capital market uncertainty or any lowering of the Company’s credit rating would adversely impact the Company’s access to capital or its cost to access capital and could impede the Company’s growth plans and cash liquidity positions.
Insurance
The Company maintains an insurance program including coverage for power plant construction and operating risks. Recent events have adversely affected the insurance industry generally and the machinery and equipment segment in particular. This effect is especially acute for insurance covering unproven new technology turbines, including many of those we have in construction. As a result, we expect that our insurance policy coverages will be at lower levels than we have historically procured, certain coverages (for example, terrorism insurance) will no longer be available on commercially reasonable terms, deductibles will increase in size and premiums will be significantly higher.
Competition
Competitive factors may also affect the results of our 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.
Our Energy business competes against a number of other participants in the merchant energy industry including Mirant, Dynegy, Calpine, Duke Energy, Reliant, AES and NRG. Competitive factors relevant to this industry include financial resources, credit quality, development expertise, risk management accumen, insight into market prices, conditions and regulatory factors and community relations. Some of our competitors have greater financial resources than we do and may have a lower cost of capital.
Our Energy business also competes with other energy marketers and traders based on the ability to aggregate supplies at competitive prices from different sources and locations and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities. These operations also compete against other energy marketers on the basis of their relative financial position, creditworthiness and access to credit sources. This competitive factor reflects the tendency of energy customers, wholesale energy suppliers and transporters to seek financial guarantees and other assurances that their energy contracts will be satisfied. As pricing information becomes increasingly available in the energy marketing and trading business and as deregulation in the electricity markets continues to evolve, we may experience greater competition and downward pressure or increased volatility on per-unit profit margins.
Our Pipeline business competes with other pipeline companies, marketers and brokers, as well as producers who are able to sell natural gas directly into the wholesale end-user markets, for transportation customers on the basis of transportation rates, access to competitively priced gas supply and growing markets and the quality and reliability of transportation services. The competitiveness of a pipeline’s transportation services to any market is generally determined by the total delivered natural gas price from a particular natural gas supply basin to the market served by the pipeline. Our GTN pipeline accesses suppliers of natural gas from Western Canada and serves markets in California and Nevada, and parts of the Pacific Northwest. GTN competes with other pipelines with access to natural gas supplies in Western Canada, the Rocky Mountains, the Southwest and British Columbia.
Our pipeline transportation volumes are also affected by the availability and economic attractiveness of other energy sources. Hydroelectric generation, for example, may increase with ample snowfall and displace demand for natural gas as a fuel for electric generation. Finally, in providing interruptible and short-term firm transportation service, we compete with released capacity offered by shippers holding firm contracts for our capacity. The ability of our gas transmission business to compete effectively is influenced by numerous factors, including regulatory conditions and the supply of and demand for pipeline and storage capacity.
Regulation
Various aspects of our 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 our business at this time. It is not an exhaustive description of all the laws and regulations which affect us.
Energy Regulation
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 NEG through GenLLC, its subsidiaries and affiliates, and of power contractually controlled by them is subject to FERC jurisdiction under the Federal Power Act. Various 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 the FERC. Recently, 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 FERC asking FERC to rule that certain contracts with market-based rates between the California Department of Water Resources and numerous counterparties (including ET) were unjust and unreasonable. Currently, most of our 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 the Public Utility Holding Company Act of 1935 (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. The previous Congress also introduced legislation that would allow retail customers to choose their energy supplier. In addition, various states have either enacted or are considering legislation designed to deregulate the production and sale of electricity. Deregulation is expected to result in a shift from cost-based rates to market-based rates for electric energy and related services. Although the legislation and regulatory initiatives vary, common themes include the availability of market pricing, retail consumer choice, recovery of stranded costs and separation of generation assets from transmission, distribution and other assets. It is unclear whether or when all power customers will obtain open access to power supplies. Decisions by regulatory agencies may have a significant impact on the future economics of the power marketing business.
FERC also regulates the rates, terms and conditions for electric transmission in interstate commerce. Tariffs established under FERC regulation provide us with access to transmission lines, which enable us to sell the energy we produce 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 our 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. The full effect of these changes on us is uncertain at this time.
The FERC also licenses all of the Company’s hydroelectric and pumped storage projects. These licenses, which are issued for 30 to 50 years, will expire at different times between 2002 and 2020. The relicensing process often involves complex administrative processes that may take as long as 10 years. The 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.
FERC issued a new license for our projects located on the Deerfield River on April 7, 1997 and a new license application for the Fifteen Mile Falls project (located on the Connecticut River) was filed July 30, 1999 and is still pending. This relicensing proceeding is being undertaken through FERC’s alternative collaborative process rather than through its more traditional, formal administrative process. No competing license applications have been filed for this project and there is no indication that FERC will decommission it. Although we expect that FERC will issue us the
new license for the Fifteen Mile Falls project, it did not do so by the July 31, 2001 expiration date. However, it did issue an annual extension of the license and we anticipate that it will issue additional annual extensions until such time that a new license is issued.
The Company’s natural gas transmission business is also subject to FERC jurisdiction. Certificates of public convenience and necessity have been obtained from the FERC for construction and operation of the existing pipelines and related facilities and properties, construction and operation of the North Baja Pipeline and, construction and operation of an expansion on GTN currently underway. An application has also been filed with FERC to construct a further expansion on GTN. The rates, terms and conditions of the transportation and sale (for resale) of natural gas in interstate commerce is subject to FERC jurisdiction. As necessary, NEG subsidiaries and affiliates file applications with the FERC for changes in rates and charges that allow recovery of costs of providing services to transportation customers. An October 1999 order permits individually negotiated rates in certain circumstances.
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, we are 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 our independent power projects. As a result, power sales agreements, which we 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 our facilities.
In addition, the National Energy Board of Canada, or National Energy Board, and Canadian gas-exporting provinces issue various licenses and permits for the removal of gas from Canada, and the Mexican Comisión Reguladoro de Energía, or CRE, issues various licenses and permits for the importation of gas into Mexico. These requirements are similar to the requirements of the U.S. Department of Energy for the importation and exportation of gas.
Environmental Regulation
The Company’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. Our 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.
We believe we are in substantial compliance with applicable environmental laws and applicable health and safety laws. However, we cannot assure you that additional costs will not be incurred or operations at some of our facilities will not 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.
We anticipate spending approximately $337 million, net of insurance proceeds, from 2002 through 2008 for environmental compliance at currently operating facilities, which primarily addresses: (a) Massachusetts air regulations promulgated in May 2001, affecting our Brayton Point and Salem Harbor Stations; (b) wastewater permitting requirements that may apply to our Brayton Point, Salem Harbor and Manchester Street Stations; and (c) requirements, to which we agreed, that are reflected in a consent decree concerning wastewater treatment facilities at our Salem Harbor and Brayton Point Stations (all of which are discussed in the “Air Emissions” and “Water Discharges” sections that follow).
If we do not comply with environmental requirements that apply to our operations, regulatory agencies could seek to impose on us civil, administrative and/or criminal liabilities, as well as seek to curtail our operations. Under some statutes, private parties could also seek to impose civil fines or liabilities for property damage, personal injury and possibly other costs. We cannot assure you that lawsuits or other administrative actions against our generating facilities will not be filed or taken in the future. If an action is filed against us or our generating facilities, this could require
substantial expenditures to bring our generating facilities into compliance and have a material adverse effect on our financial condition, cash flows and results of operations.
Air Emissions
Air Emissions Generally. Our facilities are subject to the Federal Clean Air Act and many state laws and regulations relating to air pollution. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide or SO2, nitrogen oxides or NOx, and particulate matter. As a general matter, our generating facilities emit these pollutants at levels within regulatory requirements. Fossil fuel-fired electric utility plants are usually major sources of air pollutants, and are therefore subject to substantial regulation and enforcement oversight by the applicable governmental agencies. Various multi-pollutant initiatives have been introduced in the U.S. Senate and House of Representatives, including Senate Bill 556 and House Resolutions 1256 and 1335. These initiatives include limits on the emissions of NOx, SO2, mercury and carbon dioxide (CO2). Certain of these proposals would allow the use of trading mechanisms to achieve or maintain compliance with the proposed rules. Described below are the air emissions regulations which we believe have or may have the most significant impact on our business. There are numerous other regulations with which we must comply that are not discussed here.
Nitrogen Oxides. A multi-state memorandum of understanding dealing with the control of NOx air emissions from major emission sources was signed by the Ozone Transport Commission states in the Mid-Atlantic and Northeastern states. The memorandum of understanding and underlying state laws establish a regional three-phase plan for reducing NOx emissions from electric generating units and large industrial boilers within the Ozone Transport Region. Implementation of Phase 1 was the installation of Reasonably Available Control Technology, or RACT, no later than May 31, 1995. This was successfully completed. Phase 2 commenced in 1999 and will continue through 2002. Phase 3 will begin in 2003. Among other things, the rules implementing Phases 2 and 3:
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establish NOx budgets, or emissions caps during the ozone season of May through September;
• establish methodology to allocate the allowances to affected sources within the budget; and
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establish methodology to allocate the allowances to affected sources within the budget; and
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require an affected source to account for ozone season NOx emissions through the surrender of NOx allowances.
The number of NOx allowances available to each facility under the ozone season budget decreases as the program progresses and thus forces an overall reduction in NOx emissions. Under regulatory systems of this type, we may purchase NOx allowances from other sources in the area in addition to those that are allocated to our facilities, instead of installing NOx emission control systems at our facilities. Depending on the market conditions, the purchase of extra allowances for a portion of our NOx budget requirements may minimize the total cost of compliance. During Phase 3, we will receive fewer allowances under a reduced NOx budget. We are currently formulating our Phase 3 strategy. Our plan to meet the Phase 3 budget level for Salem Harbor and Brayton Point will require a combination of allowance purchases and emission control technologies. We expect that the emission reductions to be required under regulations recently issued by the Commonwealth of Massachusetts (described in “State Initiatives” below) significantly reduce our need for allowance purchases.
Separate and apart from the requirements described above, the U.S. Environmental Protection Agency, or EPA, has initiated several regulatory efforts that are intended to impose limitations on major NOx sources located in the eastern United States and the Midwest in order to reduce the formation and regional transport of ozone. Such regulatory efforts include EPA’s “Section 126 Rule” and the “NOx SIP Rule call,” which together would establish a federal NOx emissions cap-and-trade program that would apply to some existing utilities and large industrial sources located in midwestern and eastern states whose emissions EPA has determined contribute to air quality problems in “downwind” states (generally in the northeast corner of the United States). Aspects of both rules remain the subject of litigation.
On November 6, 2001, Selkirk received its final Title V permit containing conditions that are inconsistent with Selkirk’s existing air permits and the laws and regulations underlying the Title V program. These conditions could be difficult for Selkirk to comply with under certain operating circumstances, and Selkirk filed a request for an adjudicatory hearing to address and resolve these issues. The conditions are stayed pending a decision on this appeal.
Sulfur Dioxide. The Clean Air Act acid rain provisions require substantial reductions in SO2 emissions. Implementation of the acid rain provisions is achieved through a total cap on SO2 emissions from affected units and an allocation of
marketable SO2 allowances to each affected unit. Operators of electric generating units that emit SO2 in excess of their allocations can buy additional allowances from other affected sources.
New Source Review Compliance. EPA also has been conducting a nationwide enforcement investigation regarding the historical compliance of coal-fueled electric generating stations with various permitting requirements of the Clean Air Act. Specifically, EPA and the U.S. Department of Justice have recently initiated enforcement actions against a number of electric utilities, several of which have entered into substantial settlements for alleged Clean Air Act violations related to modifications (sometimes more than 20 years ago) of existing coal-fired generating facilities. In May 2000, the Company received an Information Request from the EPA, pursuant to Section 114 of the Federal Clean Air Act (“CAA”). The Information Request asked the Company to provide certain information relative to the compliance of the Company’s Brayton Point and Salem Harbor Generating Stations with the CAA. No enforcement action has been brought by the EPA to date. The Company has had very 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.
State Initiatives. From time to time various states in which our facilities are located consider the adoption of air emissions standards that may be more stringent than those imposed by EPA. On May 11, 2001, the Massachusetts Department of Environmental Protection (DEP) issued regulations imposing new restrictions on emissions of NOx and SO2, mercury and carbon dioxide from existing coal and oil-fired power plants. These restrictions will impose more stringent annual and monthly limits on NOx and SO2 emissions than currently exist and will take effect in stages, beginning in October 2004 if no permits are needed for the changes necessary to comply, and beginning in 2006 if such permits are needed. DEP has informed USGenNE that, based upon its current understanding of the facilities’ plans for compliance with the new regulations, it believes that permits will be needed and that the initial compliance date will therefore be 2006. However, the need for permits triggers an obligation to meet Best Available Control Technology, or BACT, requirements. We do not believe that compliance with BACT at the facilities requires implementation of controls beyond those otherwise necessary to meet the emissions standards in the new regulations. Mercury emissions are capped as a first step and must be reduced by October 2006 pursuant to standards to be developed. Carbon dioxide emissions are regulated for the first time and must be reduced from recent historical levels. We believe that compliance with the carbon dioxide caps can be achieved through implementation of a number of strategies, including sequestrations and offsite reductions. Various testing and recordkeeping requirements are also imposed. We filed our plans to comply with the new regulations with DEP at the end of 2001.
The new Massachusetts regulations affect primarily our Brayton Point and Salem Harbor generating facilities, representing approximately 2,300 MW. Through 2006, it may be necessary to spend approximately $266 million to comply with these regulations. In addition, with respect to approximately 600 MW (or about 12%) of our New England capacity, we may need to implement fuel conversion, limit operations, or install additional environmental controls. These new regulations require that we achieve specified emission levels earlier than the dates included in a previous Massachusetts initiative to which we had agreed.
Water Discharges
The federal Clean Water Act generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency and/or EPA. All of our facilities that are required to have such permits either have them or have timely applied for extensions of expired permits and are operating in substantial compliance with the prior permit. At this time, three of the fossil-fuel plants owned and operated by USGen New England (Manchester Street, Brayton Point and Salem Harbor stations) are operating pursuant to permits that have expired. For the facilities whose water discharge (NPDES) permits have expired, permit renewal applications are pending, and we anticipate that all three facilities will be able to continue to operate in substantial compliance with prior permits until new permits are issued. It is possible that the new permits may contain more stringent limitations than the prior permit. It is estimated that USGen New England’s cost to comply with new permit conditions could be approximately $67 million through 2005.
At Brayton Point, unlike the Manchester Street and Salem Harbor generating facilities, we have agreed to meet certain restrictions that were not in the expired NPDES permit. In October 1996, EPA announced its intention to seek changes in Brayton Point’s NPDES permit based on a report prepared by the Rhode Island Department of Environmental Management, which alleged a connection between declining fish populations in Mt. Hope Bay and thermal discharges from the Brayton Point once-through cooling system. In April 1997, the former owner of Brayton Point entered into a Memorandum of Agreement, or MOA, with various governmental entities regarding the operation of the Brayton Point
station cooling water systems pending issuance of a renewed NPDES permit. This MOA, which is binding on us, limits on a seasonal basis the total quantity of heated water that may be discharged to Mt. Hope Bay by the plant. While the MOA is expected to remain in effect until a new NPDES permit is issued, it does not in any way preclude the imposition of more stringent discharge limitations for thermal and other pollutants in a new NPDES permit and it is possible that such limitations will in fact be imposed. If such limitations are imposed, we cannot assure you that they will not have a material adverse effect on our financial condition, cash flows and results of operations. In addition, EPA, as well as local environmental groups, have previously expressed concern that the metal vanadium is not addressed at our Brayton Point or Salem Harbor station under the terms of the old NPDES permit and it may raise this issue in upcoming NPDES permit negotiations. Based upon the lack of an identified control technology, we believe it is unlikely that EPA will require that vanadium be addressed pursuant to a NPDES permit. However, if EPA does insist on including vanadium in our NPDES permit, we may have to spend a significant amount to comply with such a provision.
Solid Waste; Toxics
Our facilities are subject to the requirements promulgated by EPA under the Resource Conservation and Recovery Act, or RCRA, and the Comprehensive Environmental Response, Compensation and Liability Act, along with other state hazardous waste laws and other environmental requirements. We, on an on-going basis, assess measures that may need to be taken to comply with federal, state and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. In connection with USGen New England’s purchase of certain electric generating facilities from the New England Electric System, or NEES, in 1998, we have assumed the onsite environmental liability of these acquired facilities. We have obtained pollution liability and environmental remediation insurance coverage to limit, to a certain extent, the financial risks with respect to these onsite liabilities. We did not acquire any offsite liability associated with the past disposal practices of the prior owner. Recently, the EPA indicated that it might begin to regulate fossil fuel combustion materials, including types of coal ash, as hazardous waste under the RCRA. If the EPA implements its initial proposals on this issue, we may be required to change our current waste management practices and expend significant resources on the increased waste management requirements caused by the EPA’s change in policy.
During April 2000, an environmental group served USGen New England and other of the Company’s subsidiaries with a notice of its intent to file a citizen’s suit under the RCRA. In September 2000, the Company signed a series of agreements with the Massachusetts Department of Environmental Protection and the environmental group to resolve these matters that require the Company to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities. The Company began the activities during 2000 and expects to complete them in 2002. The Company incurred expenditures related to these agreements of approximately $2.4 million in 2001 and $5.8 million in 2000. In addition to the costs incurred in 2000 and 2001, at December 31, 2001, the Company maintains a reserve in the amount of $10.0 million relating to its estimate of the remaining environmental expenditures to fulfill obligations under these agreements.
Regulation of Parent
Our Parent and its subsidiaries, including us, 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 the Parent’s exemption. At present, Parent has no expectation of becoming a registered holding company under PUHCA.
Although Parent 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 Pacific Gas and Electric Company (“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, recently has 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 Parent (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. Parent and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders.
On July 7, 2001, the AG filed a petition with the SEC requesting the SEC to review and revoke Parent’s exemption from PUHCA and to begin fully regulating the activities of Parent 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, Parent responded in detail to the AG’s petition demonstrating that Parent met the SEC’s criteria for the intrastate exemption. Parent further contended that registration would not have avoided the dysfunctional energy market in California or the distress of California’s largest utilities, which resulted from a variety of other factors, including rules preventing the Utility from passing power costs through to its customers. To date, the SEC has neither instituted an investigation nor ordered hearings regarding the matters raised in the AG’s petition.
On January 9, 2002, the CPUC voted in favor of 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.
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 could decide expeditiously whether adoption of the Utility’s proposed plan of reorganization would violate the first priority condition.
On January 10, 2002, the AG filed a complaint in the San Francisco Superior Court against Parent 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 unfair or fraudulent business practices or acts. The AG also alleges that the December 2000 and the January and February 2001 ringfencing transactions by which NEG and its subsidiaries complied with credit rating agency criteria to establish independent credit ratings violated the holding company conditions. In a press release issued on January 10, 2002, the CPUC expressed support for the AG’s complaint, noting that the CPUC’s January 9, 2002 decision provided a basis for the AG’s allegations and that the CPUC intends to join in a lawsuit against Parent based on these issues. On February 15, 2002 a motion to dismiss the lawsuit or, in the alternative, to stay the suit was filed.
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 Parent, and alleged use of such money by Parent to subsidize other affiliates of Parent, violated various conditions established by the CPUC in decisions approving the holding company formation. The complaint also alleges that certain ringfencing transactions by which Parent’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, Parent 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. Parent believes that the allegations of the complaint are without merit and will vigorously respond to and defend the litigation.
Parent and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. Neither the Utility nor Parent 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 our results of operations or financial condition.
Corporate Restructuring and Relation to Parent
In December 2000, and in January and February 2001, PG&E Corporation and NEG completed a corporate restructuring of NEG, known as a “ringfencing” transaction. The ringfencing involved the creation or use of limited liability companies (“LLCs”) as intermediate owners between a parent company and its subsidiaries. These LLCs are PG&E National Energy Group, LLC which owns 100% of the stock of NEG, GTN Holdings LLC which owns 100% of the stock of GTN, and PG&E Energy Trading Holdings, LLC which owns 100% of the stock of ET. In addition, NEG’s organizational documents were modified to include the same structural elements as the LLCs. The LLCs 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 LLCs may not declare or pay dividends unless the respective boards of directors have unanimously approved such action, and the company meets specified financial requirements. After the ringfencing structure was implemented, two independent rating agencies, Standard & Poor’s (S&P) and Moody’s Investors Service reaffirmed investment grade ratings for GTN and GenLLC, and issued investment grade ratings for NEG. S&P also issued an investment grade rating for ET.
The FERC issued a letter order granting approval of the corporate restructuring on January 12, 2001. Thereafter, requests for rehearing and requests to vacate that order were filed with the FERC, each of which was denied by the FERC on February 21, 2001. Requests for rehearing of the February 21 order were then filed. On January 30, 2002, the FERC issued an order denying all pending petitions for rehearing. On February 21, 2002, the California Attorney General appealed the FERC’s January 30 order to the United States Court of Appeals for the Ninth Circuit.
On April 6, 2001, the Utility, another wholly-owned subsidiary of Parent, filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. On September 20, 2001, the Utility and Parent jointly filed a plan of reorganization that entails separating the Utility into four distinct businesses. The plan of reorganization does not directly affect the Company or any of its subsidiaries. Subsequent to the bankruptcy filing, the investment grade ratings of the Company and its rated subsidiaries were reaffirmed on April 6 and 9, 2001.
Management believes that the Company and its direct and indirect subsidiaries, as described above, would not be substantively consolidated with the Parent in any insolvency or bankruptcy proceeding involving the Parent or in the Utility’s bankruptcy proceeding.
Employees
As of December 31, 2001, we employed approximately 2,200 people. Of these employees, approximately 400 are covered by collective bargaining agreements.
ITEM 2.
ITEM 2. PROPERTIES
Our corporate offices currently occupy approximately 250,000 square feet of leased office space in several buildings principally in Bethesda and Rockville, Maryland.
In addition to our corporate office space, we lease or own various real property and facilities relating to our generating facilities and development activities. Our principal generating facilities are generally described under the descriptions of our regional asset portfolios. We believe that we have title to our facilities in accordance with standards generally accepted in the energy industry, which, in our opinion, would not have a material adverse effect on the use or value of the facilities. All of our independent power projects and some of our merchant plants are pledged to lenders under non-recourse project loans.
We believe that all of our existing office and generating facilities, including the facilities under construction, are adequate for our needs through calendar year 2002. If we require additional space, we believe that we will be able to secure space on commercially reasonable terms without undue disruption to our operations.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
In addition to the following legal proceedings, we are subject to other litigation incidental to our business.
California Energy Trading Litigation
PG&E Energy Trading Holdings Corporation, and one or more of its affiliates, have been named, along with multiple other defendants, in four class action lawsuits 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. Dynegy 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.
In June, 2001 the federal judicial panel on multi-district litigation assigned all the cases to the United States District Court for the Southern District of California where by order dated July 30, 2001, the district court judge remanded all of the cases to the state courts in which each of the cases was originally filed. Since that time, the cases have been assigned to a coordination trial judge in San Diego County Superior Court.
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, restitution, injunctive relief, and attorneys’ fees.
We believe that the ultimate outcome of this matter will not have a material adverse impact on our 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 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. We believe that the ultimate outcome of the litigation will not have a material adverse effect on our financial condition or results of operations.
ITEM 4.
ITEM 4. SUBMISSON OF MATTERS TO A VOTE OF SECURITY HOLDERS
NEG is a wholly owned subsidiary of PG&E Natural Energy Group, LLC which, in turn, is a direct wholly owned subsidiary of PG&E Corporation. The Company’s Board of Directors was elected in December 2001 and the actions taken by the Board of Directors in 2001 were ratified and confirmed by the shareholder in December 2001.
PART II.
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS
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, 2001, NEG paid no dividends on its common stock. In 2000 and 1999, NEG distributed $284 million and $111 million in dividends on its common stock. The Company is restricted in its ability to declare and distribute dividends. (See “Relationship with PG&E Corporation” contained in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, below and “Corporate Restructuring and Relation to Parent” contained in Item 1, Business).
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following tables present our summary historical financial data. You should read this data together with the section entitled “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 our future performance.
PG&E National Energy Group, Inc. was incorporated on December 18, 1998. Shortly thereafter, PG&E Corporation contributed various subsidiaries to us. Our consolidated financial statements for all periods presented in the tables below 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 by us as of December 31, 2001. For those subsidiaries that were acquired or disposed of during the periods presented by us, or by PG&E Corporation prior to or after our 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 disposed.
In addition, you should read our historical financial data in light of the following:
•
In September 1997, we became the sole owner of PG&E Generating Company, a joint venture which owned, developed and managed independent power projects. This joint venture was formerly known as U.S. Generating Company or USGen. In connection with this transaction, we acquired various ownership interests that gave us full or part ownership of twelve domestic generating facilities. In April 1997, we sold our interest in International Generating Company, Ltd., an international developer of generating facilities, resulting in an after-tax gain of $120 million. Our 1997 results also reflect the write-off of our $87 million investment in two generating facilities that we had developed and constructed in Florida to burn agricultural waste, but only operated for a short period of time because of a dispute with the power purchaser.
•
In January 1997, we acquired Teco Pipeline Company for $378 million and, in July 1997, Valero Energy Corporation’s natural gas business located in Texas for total consideration, including assumption of its debt, of approximately $1.5 billion. These two operations, which we called GTT, made up the bulk of our natural gas operations in Texas. On January 27, 2000, we signed a definitive agreement with El Paso Field Services Company to sell GTT. We completed this sale on December 22, 2000. In 1999, we recognized a $1.3 billion charge against pre-tax earnings ($890 million after tax) to reflect GTT’s assets at their net realizable value. In 2000, prior to the closing of the sale, we recognized income of approximately $33 million.
•
In September 1998, we acquired for approximately $1.8 billion a portfolio of hydroelectric, coal, oil and natural gas generating facilities with an aggregate generating capacity of 4,000 MW located in New England from New England Power Company, or NEPCo, a subsidiary of New England Electric System. We also assumed the purchase obligations under 23 multi-year power purchase agreements representing an additional 800 MW of production capacity. In return for our assumption of these power purchase agreements, we are receiving the benefit of monthly payments from NEPCo through January 2008. As of December 31, 2001, NEPCo owed gross payments of $671 million under this arrangement. In connection with the acquisition, we further agreed to provide electricity to certain retail providers in New England at predetermined rates.
•
In July 1998, we sold our Australian energy holdings for $126 million. We recognized a $23 million loss related to the sale.
•
One of the businesses that PG&E Corporation contributed to us in 1998 provided retail power and gas commodity products and energy management services to end-users. Due to a revised assessment of the market potential for retail energy services, we decided in December 1999 to sell this business and reflected it in the financial statements as a discontinued operation. Our 1999 results include losses aggregating $105 million after-tax, including the write-down of this business to its estimated net realizable value and establishment of a reserve for anticipated losses. We completed the sale of substantially all of this business in two transactions in 2000, recording an additional after-tax loss of $40 million in 2000.
(1)
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.
(2)
The ratio of earnings to fixed charges was negative for the year ended December 31, 1999. The amount of the coverage deficiency was $1,140 million.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The following report includes 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. Actual results could differ materially from those contemplated by the forward-looking statements. Although NEG is not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements include:
•
the volatility of commodity fuel and electricity prices (which may result from a variety of factors, including: weather; the supply and demand for energy commodities; the availability of competitively priced alternative energy sources; the level of production and availability of natural gas, crude oil, and coal; transmission or transportation constraints; federal and state energy and environmental regulation and legislation; the degree of market liquidity; and natural disasters, wars, embargoes, and other catastrophic events); any resulting increases in the cost of producing power and decreases in prices of power sold, and whether our strategies to manage and respond to such volatility are successful;
•
the extent and timing of generating, pipeline, and storage capacity expansion and retirements by others;
•
future sales levels, and general economic and financial market conditions, and changes in interest rates;
•
the extent to which our current or planned development 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 development projects are delayed or prevented because of various development and construction risks such as our 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;
•
the performance of our projects and the success of our efforts to invest in and develop new opportunities;
•
our ability to obtain financing from third parties or from the Parent for our planned development projects and related equipment purchases and to refinance our subsidiaries existing indebtedness as it matures, in each case, on reasonable terms, while preserving our credit quality; which ability could be negatively affected by conditions in the general economy, the energy markets, or the capital markets; and the extent to which the CPUC’s holding company conditions may be interpreted to restrict the Parent’s ability to provide financial support to us;
•
heightened rating agency criteria and the impact of changes in credit ratings on our future financial condition, particularly a downgrade below investment grade which would impair our ability to meet liquidity calls in connection with our trading activities and obtain financing for our planned development projects;
•
volatility resulting from mark-to-market accounting and the extent to which the assumptions underlying our mark-to market accounting and risk management programs are not realized;
•
new accounting pronouncements;
•
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;
•
the effect of compliance with existing and future environmental laws, regulations, and policies, the cost of which could be significant;
•
restrictions imposed upon Parent and us under certain term loans of Parent;
•
the effect of the Utility bankruptcy proceedings upon Parent and upon us; and in particular, the impact a protracted delay in the Utility’s bankruptcy proceedings could have on the Parent’s liquidity and access to capital markets;
•
the outcomes of the CPUC’s pending investigation into whether the California investor-owned utilities and their parent holding companies, including Parent, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations; the outcomes of the lawsuits brought by the California Attorney General, the City and County of San Francisco, and People of the State of California against Parent alleging unfair or fraudulent business acts or practices based on alleged violations of conditions established in the CPUC’s holding company decisions; and the outcome of the California Attorney General’s petition requesting revocation of Parent’s exemption from the Public Utility Holding Company Act of 1935, and the effect of such outcomes, if any, on Parent and us; and
•
The outcome of pending litigation
Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, events, levels of activity, performance or achievements.
We use words like “anticipate,” “estimate,” “intend,” “project,” “plan,” “expect,” “will,” “believe,” “could” and similar expressions to help identify forward-looking statements in this Annual Report.
Overview
PG&E National Energy Group, Inc. is an integrated energy company with a strategic focus on power generation, natural gas transmission and wholesale energy marketing and trading in North America. PG&E National Energy Group, Inc. and its subsidiaries (collectively, “NEG”, “National Energy Group”, or the “Company”) have integrated their generation, development and energy marketing and trading activities in an effort to create energy products in response to customer needs, increase the returns from operations and identify and capitalize on opportunities to optimize generating and pipeline capacity. PG&E National Energy Group, Inc. was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation (“Parent”). Shortly thereafter, the Parent contributed various subsidiaries to the NEG. The Company’s principal subsidiaries include: PG&E Generating Company, LLC and its subsidiaries (collectively, “GenLLC”); PG&E Energy Trading Holdings Corporation and its subsidiaries (collectively, “Energy Trading” or “ET”); PG&E Gas Transmission Corporation and its subsidiaries (collectively “GTC”), which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively “GTN”), North Baja Pipeline, LLC (“NBP”) and PG&E Gas Transmission, Texas Corporation and its subsidiaries, and PG&E Gas Transmission Teco, Inc. and its subsidiaries (collectively “GTT”). See Item 6, “Selected Financial Data”, in this report for a discussion of the sale of GTT. PG&E Energy Services Corporation (“ES”), which was discontinued in 1999, provided retail energy services. NEG also has other less significant subsidiaries.
Subsequent to the issuance of NEG's 2000 and 1999 consolidated financial statements, management determined that the assets and liabilities relating to certain leases should have been consolidated. The facilities associated with the leases were under construction during 2000 and 1999. A summary of the significant effects of the revisions to the Consolidated Statements of Operations, Consolidated Balance Sheets, and Consolidated Statements of Cash Flows is described more fully in Note 1 of the Notes to Consolidated Financial Statements (see Item 8: Financial Statements and Supplementary Data).
NEG reports its business in two business segments, interstate pipeline operations (or “Pipeline”) and integrated energy and marketing (or “Energy”). Pipeline is comprised of GTC, which includes GTN and NBP. Energy is comprised of GenLLC and Energy Trading, which owns PG&E Energy Trading-Power, L.P. and PG&E Energy Trading-Gas Corporation and other affiliates. GTT, when acquired in 1997, included pipeline operations, natural gas processing operations and energy trading activities. GTT’s energy trading activities were reorganized and transferred in two stages to our energy segment in 1998 and 1999. Our sale of GTT, which was completed in December 2000, included the energy trading activities originally acquired in 1997. The activities in our Energy segment that were disposed of as part of the GTT sale provided approximately $1.0 billion and $605 million in operating revenues in 2000 and 1999, respectively. Income from continuing operations contributed by these activities was $13 million in 2000 and negligible in 1999.
Interstate Pipeline Operations: In our Pipeline business segment, we own, operate and develop natural gas pipeline facilities, including our Gas Transmission Northwest, or GTN, pipeline and the North Baja pipeline. GTN consists of over 1,350 miles of natural gas transmission pipeline with a capacity of approximately 2.7 billion cubic feet of natural gas per day. This pipeline is the only interstate pipeline directly linking the natural gas reserves in Western Canada to the gas markets of California and parts of the Pacific Northwest. An expansion of this pipeline currently under construction will, when completed, increase capacity by an additional 217 MMcf per day. Approximately 40 MMcf per day of capacity associated with this expansion was operational in the fourth quarter of 2001. The remaining volumes are expected to be operational in the fourth quarter of 2002. GTN filed in November 2001 to expand capacity further by approximately 150 MMcf per day. We plan to begin construction of the North Baja pipeline, which will run from Arizona to Northern Mexico, in the first quarter of 2002. The North Baja pipeline will have an initial certificated capacity of 500 MMcf per day and is expected to become operational by late 2002.
In addition, we own 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.
Integrated Energy and Marketing Business: In our Energy business segment, we engage in the generation, transport, marketing and trading of electricity, various fuels and other energy-related commodities throughout North America. We aggregate electricity and related products from our owned, leased or controlled generating facilities and our marketing and trading positions, and we manage the fuel supply and sale of electrical output from all these positions in an integrated portfolio. The objective of our integrated approach is to enable us to effectively manage our exposure to commodity price and counterparty credit risk. As of December 31, 2001, NEG had ownership or leasehold interests in 25 operating generating facilities with a net generating capacity of 6,518 megawatts (“MW”), as follows:
In addition, NEG has seven facilities totaling 5,430 MW in construction and controls, through various arrangements, 581 MW in operation and 2,313 MW in construction, with a total owned and controlled generating capacity in operation or construction of 14,842 MW. We may sell selected operating assets and have identified three of our New England facilities for possible sale. We have established a 2002 target of at least $250 million of after-tax proceeds from the sale of operating and development assets. NEG also has approximately 6,000 MW of natural gas-fired projects in development.
NEG engages in the marketing and trading of electric energy, capacity and ancillary services, fuel and fuel services such as pipeline transportation and storage, emission credits and other related products through over-the-counter and futures markets across North America. Our marketing and trading team manages the supply of fuel for, and the sale of electric output from, our owned and controlled generating facilities and other trading positions. We also evaluate and implement structured transactions including management of third party energy assets, tolling arrangements, management of the requirements of aggregated customer load through full requirement contracts, restructured independent power project contracts and purchase and sale of transportation, storage and transmission rights through auctions and over-the-counter markets.
We use financial instruments such as futures, options, swaps, exchange for physical, contracts for differences, and other derivatives to provide flexible pricing to our customers and suppliers and manage our purchase and sale commitments, including those related to our owned and controlled generating facilities, gas pipelines and storage facilities. We also use
derivative financial instruments to reduce our exposure to the volatility of market prices and to hedge weather, interest rate and currency volatility.
State of Industry
The national markets in which the Company participates are experiencing the first sustained downturn in the electric power commodity business cycle since electric deregulation began in the mid 1990’s. Price spikes beginning in 1997 and 1998 culminated in peak prices in 2000 and early 2001. New supply additions begun under the high-price period combined with a softening economy have resulted in projected excess energy supply. The price of electricity minus the cost of fuel, or spark spread, available in most regional wholesale energy markets has declined recently, and prices and spark spreads in the forward markets in which we transact much of our business for our generating portfolio have declined as well. Furthermore, the economic slowdown and a number of regulatory events, many of which were consequences of the California energy crisis and the Enron Bankruptcy, have increased uncertainty in the energy sector.
Conditions in the national energy markets will constrain our near-term growth. The U.S. economy has slowed significantly in the last year, and the timing for a recovery is uncertain. A lower level of economic activity may result in a decline in energy consumption and new electric supply additions begun during more robust economic conditions are beginning to commence operation. The combination of decreased consumption and increased supply may result in excess supply and declining operating margins for electric generators. Furthermore, these same factors may result in lower price volatility for energy products, potentially reducing profits from energy trading activities.
In response to these market changes, we may defer, cancel, sell, joint venture or otherwise dispose of some or all of our projects in development and the equipment associated with those projects. In connection with our current revised development plans, we have restructured some of the equipment purchase and option commitments to provide additional flexibility in payment terms and delivery schedules to better accommodate the potential delay, swap or sale of generation projects in development. If we determine to further defer or cancel a project, we may create a mismatch between equipment delivery schedules and our development plans. If equipment delivery schedules can not be adjusted, we may be compelled to choose between paying for equipment which we would have to store for future use or terminating our commitment to purchase such equipment. If we decide to terminate equipment, the Company would incur termination costs (“Termination Costs”) to the equipment vendors consisting of amounts shown on our balance sheet plus additional cash payments, if any. Our exposure for these Termination Costs gradually increases over time. Our cash exposure for Termination Costs would be offset by amounts expended for the equipment through the date of termination.
The Company maintains an insurance program including coverage for power plant construction and operating risks. Recent events have adversely affected the insurance industry generally and the machinery and equipment segment in particular. This effect is especially acute for insurance covering unproven new technology turbines, including many of those we have in construction. As a result, we expect that our insurance coverages will be at lower levels than we have historically procured, certain coverages (for example, terrorism insurance) will no longer be available on commercially reasonable terms, deductibles will increase in size and premiums will be significantly higher.
Results of Operations
The following table sets forth the operating revenues, operating expenses and net income attributable to each of our operating segments as well as cash provided by or used in operating, investing and financing activities:
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Operating Revenues. Our operating revenues were $12.7 billion in 2001, a decrease of $4.3 billion or 25% from 2000. This decline in operating revenues occurred principally within our Energy segment. This decline 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. In our Pipeline segment, the decline in operating revenues of $866 million is primarily due to the sale of GTT in December 2000.
Operating Expenses. Our operating expenses were $12.4 billion in 2001, a decrease of $4.2 billion or 25% from 2000. This decline in operating expenses occurred principally in our energy trading business within our Energy segment. This decline was 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. In our Pipeline segment, the decline in operating expenses of $792 million is primarily due to the sale of GTT in December 2000.
Net Income. Our net income (before cumulative effect of a change in accounting principle of $9 million, net of tax) was $162 million in 2001. This was $30 million lower than our income from continuing operations of $192 million reported for 2000. The year ended 2000 included a loss from discontinued operations of $40 million related to losses on the disposal of PG&E Energy Services. Our operating income declined $113 million in 2001 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 2001 of
$60 million related to our termination of certain contracts resulting from the Enron bankruptcy (principally related to our 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 our integrated energy and marketing segment primarily at our New England region generating facilities. Net interest expense was $23 million lower in 2001 as compared to the prior year, principally due to increased capitalization of interest for projects under construction. Our effective tax rate of 30% for 2001 was lower than the 40% effective tax rate for the prior year mainly due to Federal income tax credits under Section 29 Internal Revenue Code earned in 2001.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Operating Revenues. Our operating revenues were $17.0 billion in 2000, an increase of $5.0 billion, or 41% from 1999. This increase occurred principally within our Energy segment and was primarily the result of the increased volume of electricity and related products and significantly higher prices for both electricity and natural gas. In addition, two of our New England region generating facilities were not in service for a portion of the summer of 1999. There were no comparable unplanned outages in 2000. Operating revenues for our Pipeline segment were $1.1 billion in 2000, a decrease of $279 million, or 20% from 1999. GTT’s revenues decreased $275 million from 1999, resulting from the decrease in natural gas sales resulting from the transfer of certain gas marketing activities conducted by GTT to our integrated energy and marketing segment in the middle of 1999 and resulting from eleven months of revenues in 2000 versus a full year of revenues in 1999. This decrease was partially offset by the significant increase in the price of natural gas liquids in 2000.
Operating Expenses. Our operating expenses were $16.6 billion in 2000, an increase of $3.5 billion, or 26% from 1999. The increase in operating expenses, which occurred principally in our integrated energy and marketing segment, was mainly due to an increased volume of electricity and other related products and the significantly higher prices of electricity in 2000. This increase was partially offset by lower fuel costs at our generating facilities due to reduced fuel consumption. In our pipeline segment, we recognized an impairment charge of $1.3 billion in 1999 to reflect GTT’s assets at their fair value. This impairment was based on a definitive agreement to sell the stock of GTT in January 2000. We recorded no comparable impairment or write-offs in 2000.
Net Income. Our net income (after discontinued operations and cumulative effect of a change in accounting principle) was $152 million for 2000, an increase of $1 billion from 1999. The year ended 1999 included a contribution to net income for the cumulative effect of a change in accounting principle of $12 million reflecting a change in the recording of major plant overhaul costs. The year ended 1999 also included a loss from discontinued operations net of taxes of $105 million related to losses on the disposal of PG&E Energy Services compared to a $40 million loss in 2000. Our operating income increased $1.5 billion in 2000 as compared to 1999 partially due to a $1.3 billion loss recognized in 1999 as the pre-tax impairment charge to reflect GTT’s assets at their fair value. Net interest expense was $12 million lower in 2000 as compared to the prior year, principally due to the reduction of GTT and GTN debt and from eleven months of interest on the GTT debt in 2000 as compared to twelve months in 1999. Our effective tax rate was 40% in 2000. Tax amounts recorded in 1999 in connection with the GTT sale, including a stock sale valuation allowance, contributed to a net income tax benefit of $351 million in 1999. Income from continuing operations increased $982 million for 2000 as compared to the prior year partially due to a $908 million after-tax loss recognized in 1999 as the impairment charge to reflect GTT’s assets at their fair value.
Statement of Cash Flows For 2001, 2000 and 1999
Operating Activities- During 2001, we generated net cash from operating activities of $405 million. Net cash from operating activities before changes in working capital accounts and price risk management assets and liabilities was $125 million. This increase was principally due to the improved results of operations in 2001 offset by the timing of deferred tax benefits and lower distributions from unconsolidated affiliates. Our net cash inflow related to the change in inventories, prepaid expenses, deposits, restricted cash and other was $83 million and the change in accounts receivables, accounts payable and accrued liabilities increased cash flow by $42 million. Change in price risk management assets and liabilities increased cash flow by $155 million. Included in investing activities is a cash flow of
$81 million related to the long-term receivable from NEPCo associated with the assumptions of PPA’s. These cashflows offset cash payments made to NEPCo which are reflected in operating activities.
During 2000, we generated net cash from operating activities of $172 million. Net cash from operating activities before changes in working capital accounts and price risk management assets and liabilities was $267 million. This increase was principally due to the timing of deferred tax benefits and higher distributions from unconsolidated affiliates. Our net cash related to the change in inventories, prepaid expenses, deposits, restricted cash and other was reduced by $139 million while the change in accounts receivables, accounts payable and accrued liabilities increased cash flow by $65 million. Changes in price risk management assets and liabilities decreased cash flow by $21 million. Included in investing activities is a cash flow of $75 million related to the long-term receivable from NEPCo associated with the assumptions of PPA’s. These cashflows offset cash payments made to NEPCo which are reflected in operating activities.
During 1999, we generated net cash from operations of $88 million. Net cash from operating activities before changes in working capital accounts and price risk management assets and liabilities was $198 million. This increase was principally due to improved operations offset by the timing of deferred tax benefits. Our net cash related to the change in inventories, prepaid expenses, deposits, restricted cash and other was an increase of $109 million while the change in accounts receivables, accounts payable and accrued liabilities decreased cash flow by $98 million. Change in price risk management assets and liabilities decreased cash flow by $121 million. Included in investing activities is a cash flow of $66 million related to the long-term receivable from NEPCo associated with the assumptions of PPA’s. These cashflows offset cash payments made to NEPCo which are reflected in operating activities.
Investing Activities- During 2001, we used net cash of $1.6 billion for investing activities which were primarily attributable to capital expenditures associated with generating projects in construction and advanced development and turbine and other equipment commitments.
During 2000, we used net cash of $864 million for investing activities. Our primary cash outflows from investing activities were for capital expenditures associated with generating projects in construction and turbine and other equipment commitments of $1.0 billion and the acquisition of Attala for cash of $311 million. These outflows were partially offset by the receipt of $442 million in proceeds from sales of assets and equity investments.
During 1999, we used net cash of $180 million for investing activities. Our investing activities in 1999 consisted principally of $267 million in capital expenditures, partially offset by proceeds from the sale of assets or equity investments of $90 million.
Financing Activities-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, capital contributions by PG&E Corporation of $608 million, partially offset by distributions of $106 million, and other items.
During 1999, net cash provided by financing activities was $152 million. This amount includes borrowings and debt issuance totaling $463 million. We declared and paid to PG&E Corporation a dividend of $111 million in 1999. During 1999, we also repaid a total of $269 million of long-term debt, including GTT mortgage bonds and senior notes.
Liquidity and Financial Resources
Sources of Liquidity and Financial Resources: Our Energy and Pipeline business segments require substantial amounts of liquidity and capital resources to support construction, working capital, and counterparty credit requirements. Our strategy is to finance our operations using a combination of funds from operations, equity, long-term debt (secured directly by those assets without recourse to other entities), long-term corporate borrowings in the capital markets, and short and medium term bank facilities that provide working capital, letters of credit and other liquidity needs. During 2001, we took steps to enhance our liquidity and therefore at December 31, 2001, we had $725 million in cash and approximately $800 million available in unused credit lines.
Funds From Operations: Our funds from operations come from distributions from our subsidiary companies. Cash flow distributions from subsidiaries are subject to various debt covenants, organizational by-laws, and partner approvals
that can restrict these entities from distributing cash to us unless, among other things, debt service, lease obligations, and any applicable preferred payments are current, the applicable subsidiary or project affiliate meets certain debt service coverage ratios, a majority of the participants approve the distribution and there are no events of default. In addition, the subsidiaries that own our natural gas transmission facilities and our energy trading businesses have been “ringfenced” and cannot pay dividends to us unless the subsidiary’s board of directors or board of control, including its independent director, unanimously approves the dividend payment and the subsidiary has either a specified investment grade credit rating or meets a consolidated interest coverage ratio of greater than or equal to a 2.25 to 1.00 consolidated interest coverage ratio and a consolidated leverage ratio less than or equal to 0.70 to 1.00.
Equity: Neither we nor the Parent require approval of lenders to sell to third parties all or a portion of the equity of a number of lower level subsidiaries, including those holding our advanced development projects, so long as we retain the proceeds as cash, use the proceeds to pay down debt or reinvest the proceeds in our business. Options we are currently evaluating for raising equity include: a private placement of our common or preferred equity, the sale of all or a portion of certain projects in operation or development and the issuance of equity in an entity that holds a selected group of generating projects, primarily including projects currently in construction. At present, we are unable to sell equity securities in the SEC registered public markets due to market conditions or circumstances of the Utility or our Parent. In addition, our Parent is currently restricted from making equity contributions.
Long-Term Debt ( secured directly by those assets without recourse to other entities): In December 2001 we closed on a new $1.075 billion 5-year non-recourse project financing for the GenHoldings I, LLC portfolio of projects secured by the Millennium, Harquahala and Athens projects. The Company has provided a guarantee of the equity commitment for these projects of $701 million of which $251 million remains to be contributed. The equity is scheduled to be funded pro-rata with the debt at a 60/40 debt/equity ratio, although equity infusions could be triggered earlier by a downgrade of NEG below investment grade by both S&P and Moody’s, or the failure to meet certain debt covenants of the portfolio. This financing was used to reimburse the Company and repay debt to pay for a portion of the construction costs already incurred on these projects and will be used to fund a portion of the balance of the construction costs through completion. As of December 31, 2001, there was $449.5 million outstanding under this financing. NEG has contributed $450 million of equity-in-kind in the form of the Millennium project and partial construction of the Athens and Harquahala projects to GenHoldings I LLC and is committed to contribute an additional $251 million during the construction period, which is projected to be completed in the third quarter of 2003.
In September 2001 we closed on a $69.4 million non-recourse secured 5-year project financing for the construction of the Plains End generating project in Colorado. As of December 31, 2001, there was $23.3 million outstanding under this financing. As of December 31, 2001, we had invested $16.2 million in the Plains End project and have a payment guarantee to our construction contractor of $5 million. The emissions guarantee for particulate matter provided by our construction contractor on the Plains End facility does not use the same test method as required by our air permit. We are currently seeking to modify our air permit emissions rates to address this issue. Pending the receipt of such modification, and demonstration or guarantee from the construction contractor that the facility can comply with the particulate matter emissions rates as modified, our lenders have withheld funding for construction of the facility. Our construction contractor has agreed to continue work and defer pay until March 15, 2002, which is the date we expect our requested air permit modification will be issued.
The Pittsfield Generating Company, L.P. ("Pittsfield") facility previously qualified as a qualified cogeneration facility (“QF”) under PURPA. The facility failed to meet the “efficiency standard” required to maintain QF status for calendar years 2001, 2000 and 1999. Pittsfield obtained from the FERC a waiver of the efficiency standard for 2000 and 1999 and has pending before the FERC a waiver request for 2001. Failure to maintain QF status is a default under the Pittsfield lease documents. By letter dated February 13, 2002, GE Capital Corporation informed Pittsfield that it will waive to January 1, 2003 any default arising under the lease documents from failure to maintain QF status so long as Pittsfield continues to be an Exempt Wholesale Generator under PUHCA, retains its market based rate authority under the Federal Power Act (“FPA”), and maintains in effect at the FERC its long term power purchase agreements as rate schedules under Section 205 of the FPA.
Non-recourse debt at subsidiaries in which we have ownership interests but do not have control is not consolidated and not recorded on the balance sheet of the Company since these entities are accounted for on the equity method of accounting and we have no liability for the repayment of that debt. The total amount of non-recourse debt borrowed by unconsolidated investment entities was approximately $1.1 billion. We have no contingent liabilities nor funding obligations to cover these loans, which are secured by the assets of the project entities that incurred the debts and are serviced from the cash flows of these entities.
Long-Term Borrowings in the Capital Markets: On May 22, 2001, we 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. The Company has used a portion of the net proceeds and intends to use the balance of the net proceeds to pay down existing revolving debt, fund investment in generating facilities and pipeline assets, working capital requirements and other general corporate requirements. These Senior Notes bear interest at 10.375% per annum and mature on May 16, 2011.
Short and Medium Term Bank Facilities: In August 2001 we arranged a $1.25 billion working capital and letter of credit facility consisting of $500 million with a 2-year term and $750 million with a 364 day term maturing in August 2003 and August 2002, respectively. We use this facility to provide working capital and liquidity to our businesses, for letters of credit, to fund development and early phase construction expenditures and for other general corporate purposes. Outstanding loans under this facility are charged LIBOR-based interest rates and an interest rate spread over LIBOR tied to our credit ratings. On December 31, 2001, $115 million of letters of credit were outstanding under this facility (with a maximum capacity to issue $650 million) and borrowings of $330 million were outstanding under this facility.
In 2000, we entered into agreements with two master turbine trusts, special purpose entities created to own and facilitate the development, construction financing and leasing of generating facilities that would use turbines to be manufactured by General Electric and Mitsubishi. Parent and we committed to provide up to $314 million in equity to meet our obligations to the trusts. In May 2001, we established a revolving credit facility of up to $280 million to fund turbine payments and equipment. As of May 29, 2001, the trusts had incurred $216 million of expenditures. On May 29, 2001, we used $216 million of our new $280 million revolving credit facility to purchase the turbines from the master turbine trusts. This facility is due to be fully repaid on December 31, 2003. As of December 31, 2001, we had borrowed $221 million against this total borrowing capacity. We have guaranteed repayment of this credit facility.
In addition, we maintain various revolving credit facilities at subsidiary levels which currently are available to fund our capital and liquidity needs. Our Energy segment maintains a $100 million revolving credit facility which expires in September 2003. Our Pipeline segment maintains a $100 million revolving credit facility that expires in May 2002 (but may be extended for successive one-year periods). Outstanding loans on these two facilities are charged LIBOR-based interest rates with an interest rate spread over LIBOR tied to the credit rating of the applicable subsidiary and the amount drawn on the facility. As of December 31, 2001, we had borrowed $160 million against our total $200 million borrowing capacity under these facilities.
Credit Ratings and Rating Triggers
The credit ratings as of December 31, 2001 of the various debt instruments of NEG are as follows:
We have provisions in some of our financial arrangements that require us or a specified affiliate to maintain certain ratings from S&P and/or Moody’s. These provisions are referred to as “ratings triggers”. While the specifics of the ratings we are required to maintain, the remedy and cure period in the event of a downgrade, and the result if we do not take certain actions as a result of a downgrade differ with each agreement, these provisions generally require us to provide cash to meet outstanding obligations or post cash or a letter of credit as collateral in the event that we could not provide other acceptable replacement security.
Our most significant ratings triggers related to our loans include the following:
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The NEG guarantee backing our $280 million equipment revolving credit facility requires us to maintain a BBB- or Baa3 rating from either S&P or Moody’s respectively. In the event of a downgrade, we have 30 days to post acceptable replacement security, or, following receipt of a payment demand from the lenders, we have 5 days to repay all outstanding borrowings under the facility.
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Our $609 million equity commitments for Lake Road and La Paloma require us to maintain BBB- or Baa3 ratings from either S&P or Moody’s. These ratings triggers provide for a 30 day period to post replacement security after which lenders could request equity funding within 5 days.
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The NEG guarantee backing our $701 million equity commitment for the GenHoldings I LLC portfolio financing requires us to maintain a BBB- or Baa3 rating from S & P or Moody’s respectively. In the event of a downgrade we have 30 days to fund the balance of the outstanding equity commitment. The subsidiary is in the process of attempting to amend these ratings trigger provisions.
We also have rating triggers in certain of our energy trading related guarantees and guarantees to third parties. These are discussed under “Other Guarantees and Letters of Credit” below.
Commitments and Capital Expenditures:
Fuel Supply and Transportation Agreements - The Company, through its subsidiaries GenLLC and ET, has entered into various gas supply and firm transportation agreements with various pipelines and transporters to provide fuel transportation services to our own power plants and other customers. Under these agreements, the Company must make specified minimum payments each month.
Power Purchase Agreements - Through its indirect subsidiary USGenNE, GenLLC assumed rights and duties under several power purchase contracts with third party independent power producers as part of the acquisition of the NEES assets. As of December 31, 2001, these agreements provided for an aggregate of 800 MW of capacity. Under the transfer agreement, the Company is required to pay to NEES amounts due to third-party producers under the power purchase contracts.
Operating Leases - We have entered into several operating lease agreements for generating facilities and office space. Lease terms vary between 3 and 48 years. In November 1999, a subsidiary of the Company entered into a $479 million sale-leaseback transaction whereby the subsidiary sold and leased back a pumped storage station under an operating lease. Operating lease expense amounted to $54 million, $70 million, and $70 million in 2001, 2000, and 1999, respectively.
Long Term Service Agreements - The Company has 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.
Construction Commitments: We currently have six projects (Athens, Covert, Lake Road, La Paloma, Harquahala and Plains End) under construction. Development has largely been completed for our Mantua Creek project and it is ready to begin construction. We have entered into a construction contract for the facility and released the contractor to perform a limited amount of early construction activities and therefore the construction commitments associated with Mantua Creek are included above. Our construction commitments are generally related to the major construction agreements including the facility engineering, procurement and construction (EPC), and other related contracts. Certain EPC contracts also contain the commitment for turbines and related equipment.
Turbine and Equipment Purchase Commitment for Construction Projects: These commitments relate to those constructions projects for which we are directly procuring turbines and other related equipment directly from vendors and not as a portion of the relevant EPC contract.
Turbine and Equipment Purchase Commitment for Development Projects: To support our development program, we have contractual commitments and options for turbines and related equipment. In connection with our current revised development plans, we have restructured some of the equipment purchase and option commitments to provide additional flexibility in payment terms and delivery schedules to better accommodate the potential delay, swap or sale of generation projects in development. The amounts set forth in the table are based on the current contractual
provisions assuming all development projects enter construction on the schedule set forth in such contracts. These schedules remain subject to change and our commitments may be deferred or even cancelled as permitted by contract terms.
Tolling Agreements - In 2001 and 2000, the Company, through ET, entered into tolling agreements with several counterparties allowing the Company the right to sell electricity generated by facilities owned and operated by other parties. Under the tolling agreements, the Company, 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 criteria. At December 31, 2001, the annual estimated committed payments under such contracts ranged from approximately $33 million to $211 million, resulting in total committed payments over the next 27 years of approximately $4 billion, commencing at the completion of construction. During 2001, the Company paid total committed payments of approximately $13 million under tolling arrangements.
Payments in Lieu of Property Taxes - The Company has entered into certain agreements with local governments that provide for payments in lieu of property taxes for some of its generating facilities.
Other Commitments:
Commitment for GTN Pipeline Expansion: GTN is in the process of completing its 2002 Expansion Project which, when completed, will expand the capacity of its system by approximately 217 MMcf per day. Approximately 40 MMcf per day of that expansion capacity was placed in service in November 2001, and we expect the remaining capacity is scheduled to be placed in service by the end of 2002. Total cost of the expansion is estimated to be $122 million. GTN has filed an application with the FERC for approval to complete a second expansion of approximately 150 MMcf per day of additional capacity, at a cost of approximately $111 million. GTN expects to fund these expansions from cash provided by operations and, to the extent necessary, external financing and capital contributions from the Company. GTN has also initiated a preliminary assessment of a Washington lateral pipeline that would originate at the GTN mainline system near Spokane, Washington and extend west approximately 260 miles into the Seattle/Tacoma metropolitan area.
Commitment for North Baja Pipeline: We have entered into a joint development agreement for the development of a new 500 MMcf per day gas pipeline, North Baja, to deliver natural gas to Northern Mexico and Southern California. The North Baja project is expected to be completed by the end of 2002. We own all of the United States section of this cross-border project. Our share of the costs to develop this project will be approximately $146 million. We expect to fund this project from the issuance of non-recourse debt, and available cash or draws on available lines of credit.
Commitment for Environmental Compliance: We anticipate spending approximately $337 million, net of insurance proceeds, from 2002 through 2008 for environmental compliance at currently operating facilities, which primarily addresses: (a) Massachusetts air regulations promulgated in May 2001 affecting our Brayton Point and Salem Harbor Stations; (b) wastewater permitting requirements that may apply to our Brayton Point, Salem Harbor and Manchester Street Stations; and (c) requirements, to which we agreed, that are reflected in a consent decree concerning wastewater treatment facilities at our Salem Harbor and Brayton Point Stations. To date, we have spent approximately $8.2 million of this amount. We believe that a substantial portion of this amount will be funded from our operating cash flow. This amount may change, however, and the timing of any necessary capital expenditures could be accelerated in the event of changes in environmental regulations or the commencement of any enforcement proceeding against us.
Commitments to Parent: As of December 31, 2001, the Company had replaced or eliminated all of the previously issued Parent guarantees except for an office lease guarantee of $16.3 million relating to the Company’s San Francisco office, with a combination of guarantees provided by the Company or its subsidiaries and letters of credit obtained independently by the Company. In addition, the Company has negotiated substitute equity commitments with certain lenders under construction financing agreements, replacing all Parent equity commitments required by those agreements.
As of December 31, 2001, Attala Power Corporation (“APC”), an indirect, wholly-owned subsidiary of the Company, had a non-recourse demand note payable to the Parent of $309 million and GTN had a note receivable from the Parent of $75 million. The APC note is classified as short-term and the GTN note is classified as long-term on the consolidated balance sheet as of December 31, 2001, reflecting Company expectations about the timing of repayment. The demand
note between APC and the Parent is recourse only to the assets of APC and not to the Company. We expect to fund this project from the issuance of non-recourse financing, and available cash or draws on available lines of credit.
In addition, as of December 31, 2001, other wholly-owned subsidiaries of the Company had net amounts payable in the amount of $122 million in the form of promissory notes to the Parent related primarily to past funding of generating asset development and acquisition, of which $118 million was classified as long-term on the consolidated balance sheet. Furthermore, as of December 31, 2001, the Company has recorded a $99 million amount receivable from the Parent related to the intercompany tax-sharing arrangement; this amount is included in “Long-term receivables from Parent”, as of December 31, 2001, in the accompanying consolidated balance sheet. With the exception of these intercompany balances, the Company has terminated its intercompany borrowing and cash management programs with the Parent and settled its outstanding balances due to or from the Parent.
Other Guarantees and Letters of Credit
The following table provides the various credit facilities which have the capacity to issue letters of credit (amounts in millions):
(*) This credit facility consists of a $500 million tranche with a two year term and a $750 million tranche with a 364 day term maturing in August 2003 and August 2002 respectively. Borrowings under the $750 million tranche were $330 million at December 31, 2001 and are reported as Short-Term Borrowings.
Guarantees Supporting Tolling Agreements: A subsidiary of the NEG has entered into five long-term tolling transactions with third parties. Each tolling agreement is supported by a separate guarantee backing the NEG affiliate’s payment obligations over the term of these long-term contracts (9-25 years). NEG has extended about $600 million of such guarantees with the initial face value varying from $20 million to $250 million declining over time as the future obligation declines. Each of these guarantees contains a trigger event provision that requires the guarantor to replace the guarantee or provide alternative collateral in the event that the NEG credit rating drops (as measured by one or two major agencies as identified in the agreement) below the prescribed grade (generally BBB or Baa2). Although the face value of these guarantees is significant, our exposure in the event of a default is generally limited to payment of the difference between the value of the current tolling agreement and the value of a substitute tolling agreement the counterparty could enter into at market terms. As of December 31, 2001, our net exposure under our guarantees supporting tolling agreements was approximately 3% or $20 million. We intend to work with our counterparties to amend existing agreements to replace the ratings triggers with various covenant packages. Any success in these efforts will depend on the unanimous cooperation of multiple parties.
Guarantees Supporting Agreements with Third Parties: We have issued in excess of $800 million of guarantees from NEG and its subsidiaries in support of various performance and payment obligations under agreements with third parties. Of our guarantees supporting other agreements with third parties, $485 million have investment grade ratings maintenance requirements. In addition, a number of other agreements have specific security provisions requiring maintenance of investment grade ratings. In the event of a downgrade below the trigger level and exhaustion of any cure period, some of these agreements would allow the counterparty to demand payment for any outstanding obligations or of any contract termination penalties. Others simply provide the counterparty with a right to terminate the contract.
Guarantees Supporting Trading Related Agreements: Our Energy business is primarily conducted with counterparties under various master agreements that govern business done between Energy and the counterparty. These agreements typically provide for reciprocal extension of credit lines based on creditworthiness standards. Positions governed by these master agreements are marked to market on a routine basis and if the net exposed position including receivables and payables falls outside of the established credit lines, then additional collateral must be provided. Therefore, key components of a successful energy business consist of creditworthiness, liquidity resources, risk management systems that provide current mark to market of all open positions, and a strong credit department to evaluate and manage counter-party credit risk.
In addition to guarantees supporting tolling agreements, as of December 31, 2001, the Company and our subsidiaries provided $2.3 billion of guarantees to third party counterparties in support of our Energy operations. This amount included provision of fuel and pipeline capacity to, and sale of energy products from our power plants. These guarantees were provided in favor of approximately 200 counterparties to permit and facilitate physical and financial transactions in gas, pipeline capacity, power, coal and related commodities and services with these entities. Typically, the overall exposure under these guarantees is only a fraction of the face value of the guarantees, since not all counterparty credit lines are fully utilized at any time and there may be no outstanding transactions or financial exposure underlying an outstanding guarantee. Many of our counterparties are exposed to us under lines of credit (both unsecured and secured) we extend to them. These offsetting exposures can often be netted in lieu of posting alternative collateral. As of December 31, 2001 our net exposure under our guarantees was approximately 8% of the face value of our guarantees, or about $190 million. This exposure is a contingent obligation that could only be called if we or one of our subsidiaries fail to meet and cure a payment obligation.
The continued acceptability of many of these guarantees is dependent on our maintaining various standards of creditworthiness. As a result, maintenance of investment grade ratings by the Company and several of our principal subsidiaries by one or more rating agencies is an important business objective. If we are downgraded by one or more of the rating agencies, we may be required to provide alternative collateral to replace guarantees that no longer meet the creditworthiness standards of our agreements. Therefore, the Company and its trading subsidiaries maintain substantial cash balances and credit capacity to provide liquidity to our businesses in the event that open credit limits are exceeded through volatility, or in the event of a credit downgrade.
As of December 31, 2001, the amount of exposure under master agreements subject to securitization requirements in the event of a credit downgrade of the Company or its subsidiaries to below investment grade by one or more rating agencies was approximately 5% of the outstanding guarantees or $106 million. We manage this risk through maintenance of investment grade credit ratings at several principal operating subsidiaries, including PG&E Energy Trading Holdings Corporation, so that the guarantee of one entity could be substituted for another in the event of a credit downgrade by one entity.
Price Risk Management Activities
Risk Management Activities
NEG has established risk management policies that allow the use of energy, financial, credit and weather derivative instruments (a derivative is a contract whose value is dependent on or derived from the value of some underlying asset) and other instruments and agreements to be used to manage its exposure to market, credit, volumetric, regulatory and operational risks. NEG uses derivatives for both trading (for profit) and non-trading (hedging) purposes. Trading activities may be done for purposes of gathering market intelligence, creating liquidity, maintaining a market presence, and taking a market view. Non-trading activities may be done for purposes of mitigating the risks associated with an asset (natural position embedded in asset ownership and regulatory requirements), liability, committed transaction or probable forecasted transaction. Such derivatives include forward contracts, futures, swaps, options, and other contracts.
NEG may engage in the trading of derivatives only in accordance with policies set forth by the PG&E Corporation’s risk policy committee. Trading is permitted only after PG&E Corporation’s risk policy committee approves appropriate limits for such activity and it is successfully demonstrated that there is a business need for such activity and the market risks will be adequately measured, monitored, and controlled. PG&E Corporation’s risk policy committee is responsible for the overall approval of the risk management policy and the delegation of approval and authorization levels.
NEG applies mark-to-market accounting for all of its trading activities, under the guidance in EITF Issue No. 98-10, “Accounting for Contracts Involving Energy Trading and Risk Management Activities,” which are recorded at fair value with realized and unrealized gains (losses) in earnings. The recognized but unrealized balances are recorded on the consolidated balance sheets as price risk management assets and liabilities. Non-trading contracts that meet the definition of derivative instruments under Statement of Financial Accounting Standards ("SFAS") No. 133, “Accounting for Derivative Instruments and Hedging Activities,” may be classified as normal purchases and sales or cash flow hedges. Those derivatives that qualify for normal purchases and sales treatment are exempt from the fair value requirements of SFAS No. 133. Derivatives that are designated and qualify for cash flow hedge treatment are tested for their effectiveness in hedging the underlying position. Gains and losses associated with the effective portion of such hedges are recorded on the balance sheet in other comprehensive income (“OCI”) and are reclassified into earnings in the period in which the underlying transaction affects earnings. Gains and losses associated with the ineffective portion of such hedges are recognized immediately in earnings.
The activities affecting the estimated fair value of trading activities for the year ended December 31, are presented below (in millions of dollars):
NEG estimated the gross mark-to-market value of its trading contracts as of December 31, 2001, using the mid-point of quoted bid and ask prices where available and other valuation techniques when market data is not available (e.g. illiquid markets or products). In such instances, NEG uses alternative pricing methodologies, including, but not limited to, independent third party price curves, extrapolation of forward pricing curves using historically reported data or by interpolating between existing data points. Most of our risk management models are reviewed by or purchased from third party experts with extensive experience in specific derivative applications. Fair value contemplates the effects of credit risk, liquidity risk, and time value of money on gross mark-to-market positions through the applications of reserves.
The following table shows the sources of prices used to calculate the fair value of trading contracts at December 31, 2001. In many cases these prices are fed into option models that calculate a gross mark-to-market value from which fair value is derived after considering reserves for liquidity, credit, time value and model confidence.
The amounts disclosed above are not indicative of likely future cash flows, as these positions may be changed by new transactions in the trading portfolio at any time in response to changing market conditions, market liquidity and NEG’s risk management portfolio needs and strategies.
Market Risk
To the extent that NEG has an open position (an open position is a position that is either not hedged or only partially hedged), it is exposed to the risk that fluctuations in commodity, futures and basis prices may impact financial results. Such risks include any and all change in value whether caused by trading positions, asset ownership/availability, debt covenants, exposure concentration, currency and weather, regardless of accounting method. Market risk is also affected by changes in volatility, correlation and liquidity. We manage our exposure to market fluctuations within the risk limits provided for in the PG&E Corporation’s risk management policy and minimize forward value fluctuations through hedging (i.e., selling plant output, buying fuel, utilizing transportation and transmission capacity) and portfolio management.
Commodity Price Risk
Commodity price risk is the risk that changes in market prices of a commodity for physical delivery will adversely affect earnings and cash flows. NEG is exposed to commodity price risk of its portfolio of electric generation assets and supply contracts that serve wholesale and industrial customers, in addition to various merchant plants currently in development. NEG manages such risks using a cost-effective risk management program that primarily includes the buying and selling of fixed price commodity commitments to lock in future cash flows of their forecasted generation. NEG is also exposed to commodity price risk of net open positions within their trading portfolio due to the assessment of and response to changing market conditions.
Value-at-Risk (VaR)
NEG measures commodity price risk exposure using value-at-risk and other methodologies that simulate future price movements in the energy markets to estimate the size and probability of future potential losses. Market risk is quantified using a variance/co-variance value-at-risk model that provides a consistent measure of risk across diverse energy markets and products. The use of this methodology requires a number of important assumptions, including the selection of a confidence level for losses, volatility of prices, market liquidity, and a holding period.
NEG uses historical data for calculating the price volatility of its contractual positions and how likely the prices of those positions will move together. The model includes all derivatives and commodity instruments in the trading and non-trading portfolios. NEG expresses value-at-risk as a dollar amount of the potential loss in the fair value of the portfolios based on a 95 percent confidence level using a one-day liquidation period. Therefore, there is a five percent probability that NEG portfolios will incur a loss in one day greater than its value-at-risk. For example, if the value-at-risk is
calculated at $5.0 million, there is a 95 percent confidence level 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 $5.0 million.
The following table compares NEG’s daily value-at-risk exposure for commodity price risk at December 31, 2001 and December 31, 2000.
* Non-trading risk includes all hedges associated with our owned assets, but excludes the related underlying position associated with our owned assets.
** Portfolio VaR includes a rolling 3 year position reflecting the underlying position associated with our owned assets, the full tenor of our asset-hedges and trading positions.
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.
Interest Rate Risk
Interest rate risk is the risk that changes in interest rates could adversely affect earnings and cash flows. Specific interest rate risks for NEG include the risk of increasing interest rates on short-term and long-term floating rate debt, the risk of decreasing rates on floating rate assets which have been financed with fixed rate debt, the risk of increasing interest rates for planned new fixed long-term financing, and the risk of increasing interest rates for planned refinancings using long-term fixed rate debt.
NEG uses the following interest rate instruments to manage its interest rate exposure: interest rate swaps, interest rate caps, floors, or collars, swaptions, or interest rate forwards and futures contracts. Interest rate risk sensitivity analysis is used to measure our interest rate price risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. Based on variable rate debt and derivatives and other interest rate sensitive instruments outstanding at December 31, 2001, a 1% change in interest rates would be immaterial to NEG’s consolidated financial statements.
Foreign Currency Risk
Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the US dollar. The NEG is exposed to foreign currency risk associated with foreign currency exchange variations related to Canadian-dollar denominated purchase and swap agreements. In addition, NEG has translation exposure resulting from the need to translate Canadian-dollar denominated financial statements of a subsidiary of Energy, PG&E Energy Trading, Canada Corporation into U.S. dollars for NEG consolidated financial statements. NEG uses forwards, swaps, and options to hedge foreign currency exposure.
NEG uses sensitivity analyses to measure its foreign currency exchange rate exposure to the Canadian dollar. As of December 31, 2001, if the Canadian dollar experienced 10% devaluation, estimated losses would not have had a material impact on the NEG’s consolidated financial statements.
Credit Risk
Credit risk is the risk of loss that NEG would incur if counterparties fail to perform their contractual obligations. NEG primarily conducts business with customers in the energy industry, and this concentration of counterparties may impact
the overall exposure to credit risk in that its counterparties may be similarly affected by changes in economic, regulatory, or other conditions. NEG manages credit risk pursuant to its risk management policies, which provide processes by which counterparties are assigned credit limits in advance of entering into significant exposure. These procedures 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, NEG seeks to reduce exposure and/or obtain additional collateral. Further, NEG relies heavily on master agreements that allow for the netting of positive and negative exposures associated with a counterparty. The fair value of all claims against these counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange provides that every contract is settled on a daily basis), as of December 31, 2001, amount to the following:
*Gross credit exposure equals mark-to-market value plus net (payables) receivables where netting is allowed.
**Net exposure is the gross exposure minus credit collateral (cash deposits and letters of credit). Amounts are not adjusted for probability of default.
The majority of counterparties to which the NEG is exposed are considered to be of investment grade, determined using publicly available information including a Standard & Poor’s rating of at least BBB-. Approximately $259 million or 27 percent of the Company’s gross credit exposure is below investment grade. The NEG has one counterparty, Southern California Edison, that represents 11% of its gross exposure and as such is reportable as a concentration. The NEG has offsetting cash collateral in the amount of $22.1 million. The NEG has a 40% regional concentration with counterparties that primarily do business throughout the western United States and a 33% concentration with counterparties that primarily do business throughout the United States and Canada.
Inflation
Financial statements, which are prepared in accordance with accounting principles generally accepted in the United States of America, report operating results in terms of historical costs and do not evaluate the impact of inflation. Inflation affects our construction costs, operating expenses and interest charges. However, inflation at current levels is not expected to have a material adverse impact on NEG’s financial position or results of operations.
Critical Accounting Policies
Effective 2001, we adopted SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138, which required all financial instruments to be recognized in the financial statements at market value. See further discussion in Price Risk Management Activities beginning on page 50 and Note 5 to the Consolidated Financial Statements. We account for our energy trading activities in accordance with 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. EITF 98-10 also allows two methods of recognizing energy trading contracts in the income statement. The “gross” method provides that the contracts are recognized at their full value in revenue and expenses. The other method is the “net” method in which revenues and expenses are netted and only the trading margin (or sometimes trading loss) is reflected in revenues. We have used the gross method for those energy trading contracts for which we have a choice.
We apply SFAS No 71 Accounting for the Effects of Certain Types of Regulation to GTN’s regulated natural gas transportation business. This standard allows a cost to be capitalized, that otherwise would be charged to expense if it is probable that the cost is recoverable through regulated rates. This standard also allows a regulator to create a liability that is recognized in GTN’s financial statements. GTN’s regulatory assets and liabilities are discussed further in Note 3 in the Notes to the Consolidated Financial Statements.
We also used the guidance included in SFAS No. 121 Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, when we wrote down the investment in GTT and the Energy Services unit.
New Accounting Standards
We adopted SFAS No. 133, on January 1, 2001. This standard requires us to recognize all derivatives, as defined in SFAS No. 133, on our balance sheet at fair value. Effective January 1, 2001, derivatives are classified as price risk management assets and liabilities. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will offset the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income, a component of stockholder’s equity, until the hedged items are recognized in earnings. The transition adjustment to implement the new standard was an immaterial adjustment to net income and a negative adjustment of approximately $333 million (after tax) to other comprehensive income. This transition adjustment, which relates to hedges of interest rate, foreign currency and commodity price risk exposure, was recognized as of January 1, 2001, as a cumulative effect of a change in accounting principle.
We also have certain 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 purchases and sales exception, and thus are not reflected on the balance sheet at fair value. In June 2001 (as amended in October 2001 and December 2001), the Financial Accounting Standards Board (“FASB”) approved an interpretation issued by the Derivatives Implementation Group (“DIG”) that changed the definition of normal purchases and sales for certain power contracts. We must implement this interpretation on April 1, 2002, and are currently assessing the impact of these new rules. We anticipate that implementation of this interpretation will result in several contracts failing to continue qualifying for the normal purchases and sales exception, possibly resulting in these contracts being marked to market through earnings. The FASB has also approved another DIG interpretation that disallows normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. Certain of our derivative commodity contracts may no longer be exempt from the requirements of SFAS No. 133. We are evaluating the impact of the implementation guidance on our consolidated financial statements and will implement this guidance, as appropriate, at the implementation deadline of April 1, 2002.
To qualify for the normal purchases and sales exception 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 applies to certain commodity contracts. In applying this new DIG guidance, we determined that one of our derivative commodity contracts no longer qualifies for normal purchases 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).
In June 2001, the FASB issued SFAS No. 141, Business Combinations. This standard prohibits the use of pooling-of-interests method of accounting for business combinations initiated after June 30, 2001 and applies to all business combinations accounted for under the purchase method that are completed after June 30, 2001. The implementation of this standard has no current impact on our consolidated financial statements. We will apply this standard to any prospective acquisitions.
We will adopt SFAS No. 142, Goodwill and Other Intangible Assets, on January 1, 2002. This standard eliminates the amortization of goodwill, and requires goodwill to be reviewed periodically for impairment. Testing for the impairment of goodwill is to be performed on a two-step basis. The initial test is to determine if the fair value of reporting units that contain goodwill exceeds the book value of those units. If the initial impairment test fails, the amount of goodwill impairment loss is deemed to be the excess of book value over fair value of goodwill in the reporting units. This standard also requires the useful lives of previously recognized intangible assets to be reassessed and the remaining amortization periods to be adjusted accordingly. In addition, previously recognized intangible assets that do not meet the definition of intangible asset, as defined in the standard, will be reclassified to goodwill and subject to the impairment provisions of the standard.
This standard is effective for fiscal years beginning after December 15, 2001, for all the goodwill and other intangible assets recognized on our statement of financial position at that date, regardless of when the assets were initially recognized. The transition impairment test is to be performed as of January 1, 2002, and subsequently, at a minimum, on an annual basis. Impairment recognized at implementation of the standard will be recorded as a change in accounting principle on the consolidated statement of operations. We anticipate that the transition impairment test will be completed by March 31, 2002. We do not expect that any impairment will be recorded or any reclassifications will be necessary
upon adoption of SFAS No. 142. Prospective elimination of goodwill amortization will not have a significant impact on our consolidated financial statements.
In August 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This standard is effective for fiscal years beginning after June 15, 2002, and provides accounting requirements for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Under the standard, 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. The liability is accreted to its present value in each subsequent period and the capitalized cost is depreciated over the useful life of the related assets. We have not yet determined the effects of this standard on our consolidated financial statements.
In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 supercedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, but retains its fundamental provisions for recognizing and measuring impairment of long-lived assets to be held and used. This standard also requires that all long-lived assets to be disposed of by sale are carried at the lower of carrying amount or fair value less cost to sell, and that depreciation should cease to be recorded on such assets. SFAS 144 standardizes the accounting and presentation requirements for all long-lived assets to be disposed of by sale, superceding previous guidance for discontinued operations of business segments. This standard is effective for fiscal years beginning after December 15, 2001. The Company anticipates that implementation of this standard will have no immediate impact on our consolidated financial statements. The Company will apply this guidance prospectively.
Legal Matters
In the course of business, NEG is named as a party in a number of claims and lawsuits. See Part I, Item 3 of this report and Note 13 of the Notes to the Consolidated Financial Statements for further discussion of significant pending litigation.
Environmental Matters
We anticipate spending approximately $337 million, net of insurance proceeds, from 2002 through 2008 for environmental compliance at currently operating facilities, which primarily addresses: (a) Massachusetts air regulations promulgated in May 2001, affecting our Brayton Point and Salem Harbor Stations; (b) wastewater permitting requirements that may apply to our Brayton Point, Salem Harbor and Manchester Street Stations; and (c) requirements, to which we agreed, that are reflected in a consent decree concerning wastewater treatment facilities at our Salem Harbor and Brayton Point Stations. To date we have spent approximately $8.2 million of this amount. We believe that a substantial portion of this amount will be funded from our operating cash flow. This amount may change, however, and the timing of any necessary capital expenditures could be accelerated in the event of changes in environmental regulations or the commencement of any enforcement proceeding against us.
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 5 of the “Notes to the Consolidated Financial Statements”.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999
(In Millions)
The accompanying notes are an integral part of these consolidated financial statements.
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2001 AND 2000
(In Millions)
The accompanying notes are an integral part of these consolidated financial statements.
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2001 AND 2000
(In Millions)
The accompanying notes are an integral part of these consolidated financial statements.
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(In Millions, Except for Shares)
The accompanying notes are an integral part of these consolidated financial statements.
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(In Millions)
The accompanying notes are an integral part of these consolidated financial statements.
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999
1. ORGANIZATION AND BASIS OF PRESENTATION
PG&E National Energy Group, Inc., is a wholly owned subsidiary of PG&E Corporation (“Parent”). PG&E National Energy Group, Inc., and its subsidiaries (collectively, “NEG”, “National Energy Group”, or the “Company”) are principally located in the United States and Canada and are engaged in power generation and development, natural gas transmission and wholesale energy marketing and trading, The Company’s principal subsidiaries include PG&E Generating Company, LLC, and its subsidiaries (collectively, “GenLLC”), PG&E Energy Trading Holdings Corporation and its subsidiaries (collectively, “Energy Trading” or “ET”), PG&E Gas Transmission Corporation and its subsidiaries (collectively “GTC”), which includes PG&E Gas Transmission, Northwest Corporation and subsidiaries (collectively, “GTN”), North Baja Pipeline, LLC (“NBP”) and PG&E Gas Transmission, Texas Corporation and subsidiaries, and PG&E Gas Transmission Teco, Inc. and subsidiaries (collectively “GTT”). See Note 4 for discussion of the sale of GTT. PG&E Energy Services Corporation (“ES”), whose activities were discontinued and subsidiary sold in 1999, provided retail energy services. NEG also has other less significant subsidiaries.
PG&E National Energy Group, Inc. was incorporated on December 18, 1998 as a wholly owned subsidiary of Parent. Shortly thereafter, Parent contributed various subsidiaries to NEG. The consolidated financial statements of NEG for the years ended December 31, 2001, 2000 and 1999, 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, 2001. For those subsidiaries that were acquired or disposed of during the periods presented by NEG, or by Parent prior to or after 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.
All significant intercompany accounts and transactions have been eliminated in consolidation. Investments in affiliates in which the Company 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 the Company, including costs for functions and services performed by centralized Parent organizations and directly charged to the Company based on usage or other allocation factors. The results of operations in these consolidated financial statements also include general corporate expenses allocated by Parent to the Company 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 the Company had operated as a separate entity.
Revision footnote
Subsequent to the issuance of NEG’s 2000 consolidated financial statements, management determined that the assets and liabilities relating to certain leases should have been consolidated. The facilities associated with the leases were under construction during 2000 and 1999. A summary of the significant effects of the revisions to the Consolidated Statements of Operations and Cash Flows for 2000 and 1999, and the Consolidated Balance Sheets as of December 31, 2000 is as follows (in millions):
2. RELATIONSHIP WITH PARENT AND THE CALIFORNIA ENERGY CRISIS
For periods prior to 2001, Parent provided financial support in the form of direct lending activities with the Company and provision of collateral to third parties to support the Company’s contractual commitments and daily operations. Funds from operations were managed through net investments or borrowings in a pooled cash management arrangement, and Parent provided credit support for trading activities through Parent guarantees and surety bonds. Certain development and construction activities were funded in part through Parent equity contributions or secured using instruments such as Parent guarantees or equity commitments. As of December 31, 2000, Parent guarantees to third parties for trading and structured tolling arrangements totaled $2.4 billion and Parent equity funding commitments for construction activities totaled $1 billion. Parent also assisted with financing activities through short-term demand borrowings and long-term notes between the Parent and the Company and Parent guarantees of certain minor credit facilities. Furthermore, the Company, the Parent and another affiliate of Parent share the costs of certain administrative and general functions.
In December 2000, and in January and February 2001, PG&E Corporation and NEG completed a corporate restructuring of NEG, known as a “ringfencing” transaction. The ringfencing involved the use or creation of limited liability companies (“LLCs”) as intermediate owners between a parent company and its subsidiaries. These LLCs are PG&E National Energy Group, LLC which owns 100% of the stock of NEG, GTN Holdings LLC which owns 100% of the stock of GTN, and PG&E Energy Trading Holdings, LLC which owns 100% of the stock of ET. In addition, NEG’s organizational documents were modified to include the same structural elements as the LLCs. The LLCs 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 LLCs may not declare or pay dividends unless the respective boards of directors have unanimously approved such action, and the company meets specified financial requirements. After the ringfencing structure was implemented, two independent rating agencies, Standard & Poor’s (S&P) and Moody’s Investor Services reaffirmed investment grade ratings for GTN and GenLLC, and issued investment grade ratings for NEG. S&P also issued an investment grade rating for ET.
The FERC issued a letter order granting approval of the corporate restructuring on January 12, 2001. Thereafter, requests for rehearing and requests to vacate that order were filed with the FERC, each of which was denied by the FERC on February 21, 2001. Requests for rehearing of the February 21 order were filed. On January 30, 2002 the FERC issued an order denying all pending petitions for rehearing. On February 21, 2002, the California Attorney General appealed the FERC’s January 30 order to the United States Court of Appeals for the Ninth Circuit.
On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. On September 20, 2001, the Utility and Parent jointly filed a plan of reorganization that entails separating the Utility into four distinct businesses. The plan of reorganization does not directly affect the Company or any of its subsidiaries. Subsequent to the bankruptcy filing, the investment grade ratings of the Company and its rated subsidiaries were reaffirmed on April 6 and 9, 2001.
Management believes that the Company and its direct and indirect subsidiaries, as described above, would not be substantively consolidated with Parent in any insolvency or bankruptcy proceeding involving Parent or the Utility.
As of December 31, 2001, the Company had replaced or eliminated all of the previously issued Parent guarantees except for an office lease guarantee relating to the Company’s San Francisco office, of approximately $16 million, with a combination of guarantees provided by the Company or its subsidiaries and letters of credit obtained independently by the Company.
3. 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.
Accounting for Price Risk Management Activities - The Company engages in price risk management activities for both trading and non-trading purposes. Trading activities are conducted to generate profit, create liquidity, and maintain a market presence. Net open positions often exist or are established due to the Company’s assessment of and response to
changing market conditions. Non-trading activities are conducted to optimize and secure the return on risk capital deployed within the Company’s existing asset and contractual portfolio.
Derivatives and other financial instruments associated with trading activities in electric power, natural gas, natural gas liquids, fuel oil, coal, gas transportation, storage and emissions are accounted for using the mark-to-market method of accounting in accordance with Emerging Issues Task Force (“EITF”) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” Under mark-to-market accounting, the Company’s trading contracts, including both physical contracts and financial instruments, are recorded at market value, which approximates fair value. The methodology used to value these transactions reflects management’s best estimates considering various factors including market quotes, forward price curves, time value, and volatility factors of the underlying commitments. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions and to reflect creditworthiness of individual counterparties.
Changes in the market value of the Company’s trading contracts, resulting primarily from the impact of commodity price and interest rate movements, are recognized in operating income in the period of change. Unrealized gains and losses of these trading contracts are recorded as operating revenues and as assets and liabilities, respectively, from price risk management. On a realized basis, the Company recognizes trading contracts on a gross basis in the income statement. Sales are recognized in operating revenues and purchases are recognized in operating expenses as costs of commodity sales and fuel.
In addition to the trading activities, as discussed previously, the Company engages in non-trading activities using futures, forward contracts, options, swaps and other contracts to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies when there is a high degree of correlation between price movements in the derivative and the item designated as being hedged. Before the implementation date of Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as described below, the Company accounted for hedging activities under the deferral method, whereby unrealized gains and losses on hedging transactions were deferred. When the underlying item settled, the Company 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, the Company adopted SFAS No. 133, as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (collectively, “SFAS No. 133”). SFAS No. 133 requires the Company to recognize all derivatives, as defined, on the balance sheet at fair value. The Company’s transition adjustment to implement SFAS No. 133 was an immaterial adjustment to net income and an after tax decrease of $333 million to accumulated other comprehensive income. This transition adjustment, which relates to hedges of interest rate, foreign currency and commodity price risk exposure, was recognized as of January 1, 2001, as a cumulative effect of a change in accounting principle.
Derivatives are classified as price risk management assets and price risk management liabilities on the balance sheet. Derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. For derivatives that are effective hedges, depending on the nature of the hedges, changes in the fair value are either offset by change in fair value of the hedged assets or liabilities through earnings or recognized in other comprehensive income (loss) until the hedged items are recognized in earnings. Net gains or losses on derivative instruments recognized for the year ended December 31, 2001, were included in various lines of the consolidated statements of operations, including operating revenues, cost of commodity sales and fuel and interest expense.
The Company 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 purchases and sales exception, and thus are not reflected on the balance sheet at fair value. In June 2001 (as amended in October 2001 and December 2001), the FASB approved an interpretation issued by the Derivatives Implementation Group (“DIG”) that changed the definition of normal purchases and sales for certain power contracts. The Company must implement this interpretation on April 1, 2002, and is currently assessing the impact of these new rules. The Company anticipates that implementation of this interpretation will result in several contracts failing to continue qualifying for the normal purchases and sales exemption, possibly resulting in these contracts being marked
to market through earnings. The FASB has also approved another DIG interpretation that disallows normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. Certain of the Company’s derivative commodity contracts may no longer be exempt from the requirements of SFAS No. 133. The Company is evaluating the impact of this implementation guidance on its consolidated financial statements, and will implement this guidance, as appropriate, by the implementation deadline of April 1, 2002.
To qualify for the normal purchases and sales exception 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 applies to certain commodity contracts. In applying this new DIG guidance, the Company determined that one of its derivative commodity contracts no longer qualifies for normal purchases 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).
As of December 31, 2001, the maximum length of time over which the Company has hedged its exposure to the variability in future cash flows associated with commodity price risk is through December 2006. The maximum length of time over which the Company has hedged its exposure to the variability in future cash flows associated with interest rate risk is through March 2014.
Regulation - 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 the FERC in conformity with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. This standard allows 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.
The Company’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 GTN associated with certain costs to be collected from or refunded to customers as a result of the ratemaking process. 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. Regulatory assets are included in other noncurrent assets on the
consolidated balance sheets. GTN does not earn a return on regulatory assets on which it does not incur a carrying cost. GTN does not earn a return nor does it incur a carrying cost on regulatory assets related to income taxes, pension costs, postretirement benefit costs, or fuel tracker. Regulatory liabilities are included in other noncurrent liabilities on the consolidated balance sheets.
Cash and Cash Equivalents - Cash and cash equivalents consist of highly liquid investments with maturities of 90 days or less at date of acquisition.
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 fair value. Coal and fuel oil are primarily valued using the LIFO method.
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:
Interest is capitalized as a component of projects under construction and is amortized over the projects’ estimated useful lives. During 2001, 2000, and 1999, the Company capitalized interest of approximately $119 million, $48 million, and $10 million, respectively.
GTN utility plant also includes an allowance for funds used during construction (“AFUDC”). AFUDC 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 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.
Also included in property, plant, and equipment as of December 31, 2000 is a GTN capital lease for an office building of approximately $18 million. During 2001, GTN sold its interest in this lease. As a result the leased asset and the associated long-term debt were removed from the balance sheet as of December 31, 2001. A pre-tax gain of approximately $1.9 million was recognized.
Depreciation expense, including amortization expense under capital leases, was $141 million, $123 million, and $180 million for the years ended December 31, 2001, 2000, and 1999, respectively.
Included in Other noncurrent assets as of December 31, 2001 and 2000, are $221 million and $132 million, respectively, related to turbine prepayments and capitalized interest on these prepayments. The capitalized interest associated with the turbines are $7 million and $3 million as of December 31, 2001 and 2000.
In August 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This standard is effective for fiscal years beginning after June 15, 2002, and provides accounting requirements for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Under the standard, 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. The liability is accreted to its present value in each subsequent period and the capitalized cost is depreciated over the useful life of the related assets. The Company has not yet determined the effects of this standard on its consolidated financial statements.
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. The Company periodically assesses project development costs for impairment. Project development costs are included in other noncurrent assets in the consolidated balance sheets.
Prepaid Expenses and Deposits - Prepaid expenses and deposits consist principally of margin cash for commodities futures and over-the-counter financial instruments, cash on deposit with counterparties and option premiums paid at the inception of a contract. Option premiums are recorded as expense upon exercise or expiration of the option. Deposits will be refunded to the Company at the time at which all obligations have been fulfilled.
Goodwill and Other Intangible Assets - The Company currently amortizes the excess of purchase price over fair value of net assets of businesses acquired (goodwill) using the straight-line method over periods ranging from 3 to 35 years and periodically assesses goodwill for impairment.
Intangible assets include the value assigned, based on the expected benefits to be received, to acquired management service agreements, operations and maintenance agreements (collectively, the “Service 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. Intangible assets are included in other noncurrent assets in the accompanying consolidated balance sheets.
Amortization expense related to goodwill and other intangible assets was $19 million, $13 million, and $26 million for the years ended December 31, 2001, 2000, and 1999, respectively, of which goodwill amortization expense amounted to $5 million, $5 million and $10 million, for the respective years.
The Company will adopt SFAS No. 142, Goodwill and Other Intangible Assets, on January 1, 2002. This standard eliminates the amortization of goodwill, and requires goodwill to be reviewed periodically for impairment. Testing for the impairment of goodwill is to be performed on a two-step basis. The initial test is to determine if the fair value of reporting units that contain goodwill exceeds the book value of those units. If the initial impairment test fails, the amount of goodwill impairment loss is deemed to be the excess of book value over fair value of goodwill in the reporting units. This standard also requires the useful lives of previously recognized intangible assets to be reassessed and the remaining amortization periods to be adjusted accordingly. In addition, previously recognized intangible assets that do not meet the definition of intangible asset, as defined in the standard, will be reclassified to goodwill and subject to the impairment provisions of the standard.
This standard is effective for fiscal years beginning after December 15, 2001, for all the goodwill and other intangible assets recognized on our statement of financial position at the date, regardless of when the assets were initially recognized. The transition impairment test is to be performed as of January 1, 2002, and subsequently, at a minimum, on an annual basis. Impairment recognized at implementation of the standard will be recorded as a change in accounting principle on the consolidated statement of operations. The Company anticipates that the transition impairment test will be completed by March 31, 2002. The Company does not expect that any impairment will be recorded or any reclassifications will be necessary upon adoption of SFAS No. 142. Prospective elimination of goodwill amortization will not have a significant impact on its consolidated financial statements.
Out-of-Market Contractual Obligations - Commitments contained in the underlying Power Purchase Agreements (“PPAs”), gas commodity and transportation agreements (collectively, the “Gas Agreements”), and Standard Offer Agreements, acquired 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 New England Electric System (“NEES”) 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. The carrying value of the out of market obligations is as follows (in millions):
Other Liabilities - Other current liabilities consist primarily of cash received by the Company at the time option contracts are sold and cash collateral on deposit from counterparties. Option premiums are recorded as income upon exercise or expiration of the option. Deposits will be returned by the Company at the time in which all obligations under the forward contracts have been fulfilled.
Asset Impairment - The Company periodically evaluates long-lived assets, including property, plant, and equipment, goodwill, and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an
estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. Asset impairment is then measured using a fair market value or discounted cash flows method.
In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 supercedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, but retains its fundamental provisions for recognizing and measuring impairment of long-lived assets to be held and used. This standard also requires that all long-lived assets to be disposed of by sale are carried at the lower of carrying amount or fair value less cost to sell, and that depreciation should cease to be recorded on such assets. SFAS 144 standardizes the accounting and presentation requirements for all long-lived assets to be disposed of by sale, superceding previous guidance for discontinued operations of business segments. This standard is effective for fiscal years beginning after December 15, 2001. The Company anticipates that implementation of this standard will have no immediate impact on our consolidated financial statements. The Company will apply this guidance prospectively.
Revenue Recognition - For the Company’s non-derivative contracts, revenues derived from power generation are recognized upon output, product delivery, or satisfaction of specific targets, all as specified by contractual terms. Regulated gas transmission revenues, including the reservation and the volumetric charge components, are recorded as services are provided, based on rate schedules approved by the FERC. The reservation charge component is recorded in the month in which it applies. The volumetric charge component is recorded when volumes are delivered. The Company also has certain trading contracts that, while they do not meet the definition of derivative instruments under SFAS No. 133, constitute energy trading activities as defined in EITF 98-10. These energy trading contracts are accounted for using the mark to market method of accounting as was described previously in Accounting for Price Risk Management Activities.
Revenue on the Company’s derivative contracts is recognized in accordance with the requirements of SFAS No. 133. As described previously, derivative contracts used for trading purposes are accounted for under the mark to market method of accounting. Derivative contracts used for non-trading purposes are accounted for as cash flow hedges or as normal purchases and sales. See Accounting for Price Risk Management Activities for further discussion of the method and timing of income recognition for derivative contracts.
Income Taxes-The Company accounts for income taxes under the liability method. Deferred tax assets and liabilities are determined based on the difference between financial statement carrying amounts and tax basis of assets and liabilities, using currently enacted tax rates.
The Company and its subsidiaries are included in the federal consolidated tax return of Parent. The Company and its subsidiaries have a tax-sharing arrangement with Parent that provides for the allocation of federal and certain state income taxes. In consideration of the Company’s participation in such consolidated return and the tax-sharing arrangement, the Company recognized its pro rata share of consolidated income tax expenses and benefits. For years prior to 2001, the Company was allowed to use the tax benefits generated as long as these benefits could be used on a consolidated basis. Beginning with the 2001 calendar year, the Company will pay to Parent the amount of income taxes that the Company would be liable for if the Company filed its own consolidated combined or unitary return separate from Parent, subject to certain consolidated adjustments.
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 net income (the “Canadian Taxes”). Tax consequences of the Separate State Taxes and the Canadian Taxes are excluded from the tax-sharing arrangement and thus are separately accounted for by the Company.
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 $8 million, $2 million and zero, for the years ended December 31, 2001, 2000 and 1999, respectively.
Foreign Currency Translation - The asset and liability accounts of the Company’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.
Stock-Based Compensation - The Company accounts for stock-based employee compensation arrangements in Parent stock using the intrinsic value method in accordance with provisions of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issues to Employees, and complies with the disclosure provisions of SFAS No. 123, Accounting for Stock-Based Compensation. Under APB Opinion No. 25, compensation cost is generally recognized based on the difference, if any, on the date of grant between the fair value of the Company’s stock and the amount an employee must pay to acquire the stock.
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. The Company’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.
Accounting for Major Maintenance - Effective January 1, 1999, the Company changed its method of accounting for major maintenance and overhauls of generating assets. Beginning January 1, 1999, the cost of major maintenance and overhauls of generating assets were accounted for as incurred. Previously, the estimated cost of major maintenance and overhauls was accrued in advance in a systematic and rational manner over the period between major maintenance and overhauls. The change resulted in the recording of income of $12 million, net of income taxes of $8 million, as of December 31, 1999.
Reclassifications - Certain amounts in the 2000 and 1999 financial statements have been reclassified to conform to the 2001 presentation.
4. ACQUISITIONS AND SALES
In December 1999, Parent’s Board of Directors approved a plan to dispose of ES, its wholly owned subsidiary, through a sale. The disposal has been accounted for as a discontinued operation and the Company’s investment in ES was written down to its estimated net realizable value. In addition, the Company provided a reserve for anticipated losses through the date of sale. The total provision for discontinued operations was $58 million, net of income taxes of $36 million at December 31, 1999. Of this amount, $33 million (net of taxes) was allocated toward operating losses for the period leading up to the intended disposal date. In 2000, $31 million (net of taxes) of actual operating losses was charged against this reserve. During the second quarter of 2000, the Company finalized the transactions related to the disposal of the energy commodity portion of ES for $20 million, plus net working capital of approximately $65 million, for a total of $85 million. In addition, a portion of the 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.
On January 27, 2000, the Company signed a definitive agreement with El Paso Field Services Company (“El Paso”) providing for the sale to El Paso, a subsidiary of El Paso Energy Corporation, of the stock of GTT. Given the terms of the sales agreement, in 1999 the Company recognized a charge against pre-tax earnings of $1.3 billion, to reflect GTT’s assets at their fair value. The composition of the pre-tax charge is as follows: (1) an $819 million write-down of net property, plant, and equipment, (2) the elimination of the unamortized portion of goodwill in the amount of $446 million, and (3) an accrual of $10 million representing selling costs. On December 22, 2000, after receipt of governmental approvals, the Company 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 long-term debt having a book value of $564 million.
The following table reflects GTT’s results of operations included in the Company’s consolidated statements of operations for the years ended December 31, 2000 and 1999 (in millions):
On September 28, 2000, the Company purchased for $311 million the Attala Generating Company, LLC, which owns a gas-fired power plant that was under construction. Under the purchase agreement, the Company 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, the Company also assumed industrial revenue bonds 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.
On June 29, 2001, the Company contracted to supply the full service power requirements of the city of Denton, Texas, for a period of five years beginning July 1, 2001. The city of Denton’s peak load forecast is 272 megawatts in 2001, increasing to 314 megawatts over the contract term. The Company’s supply obligation to the city is net of approximately 97 megawatts of generation entitlements retained by the city, plus 40 megawatts of purchased power that the city has assigned to the Company for the summer of 2001. In connection with the power supply agreement, the Company acquired a 178 megawatt generating station and two small hydroelectric facilities from the city. The total consideration was approximately $12 million for this transaction.
On July 10, 2001, the Company completed the sale of certain development assets, resulting in a pre-tax gain of $23 million.
On September 17 and 28, 2001, the Company purchased Mountain View Power Partners, LLC and Mountain View Power Partners II, LLC, respectively. These companies own 44 and 22 megawatt wind energy projects, respectively, near Palm Springs, California. The Company has contracted with SeaWest for the operation and maintenance of the wind units and will sell the entire output of the two wind projects, under a long-term contract. Total consideration for these two companies was $92 million.
5. PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
The Company’s net gains (losses) on trading activities, recognized on a fair value basis, were as follows for years ended December 31, 2001, 2000 and 1999, respectively, (in millions).
The Company’s ineffective portion of changes in fair values of cash flow hedges is immaterial for the year ended December 31, 2001. The Company’s estimated net derivative gains or losses included in accumulated other
comprehensive income as of December 31, 2001, that are expected to be reclassified into earnings within the next twelve months are a net loss of $3 million. The actual amounts reclassified from accumulated other comprehensive income to earnings can differ as a result of market price changes.
The schedule below summarizes the activities affecting accumulated other comprehensive income, net of tax, from derivative instruments for the year ended December 31, 2001 (in millions):
Credit Risk - Credit risk is the risk of loss that the Company would incur if counterparties fail to perform their contractual obligations. The Company primarily conducts business with customers in the energy industry, such as investor-owned and 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 the Company’s overall exposure to credit risk in that its counterparties may be similarly affected by changes in economic, regulatory or other conditions. The Company mitigates potential credit losses in accordance with established credit approval practices and limits by dealing primarily with creditworthy counterparties (counterparties considered investment grade or higher). The Company reviews credit exposure in relation to specified counterparty limits daily and to the maximum extent possible, requires that all derivative contracts take the form of a master agreement which contain credit support provisions that require the counterparty to post security 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.
The Company calculates gross credit exposure as the current mark-to-market value (what would be lost if the counterparty defaulted today) plus any outstanding net receivables, prior to the application of credit collateral. In the past year, the Company’s credit risk has increased partially due to credit rating downgrades of some of our counterparties in the energy industry to below investment grade. Other than discussed below, the Company did not experience any significant losses due to the non-performance of counterparties during the year ended December 31, 2001.
The fair value of claims against counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange guarantees that every contract is properly settled on a daily basis) as of December 31, 2001, amount to the following:
*Gross credit exposure equals mark to market value plus net (payables) receivables where netting is allowed.
**Net exposure is the gross exposure minus credit collateral (cash deposits and letters of credit). Amounts are not adjusted for probability of default.
The majority of counterparties to which the Company is exposed are considered to be of investment grade, determined using publicly available information including a Standard & Poor’s rating of at least BBB-. $259 million or 27 percent of the Company’s gross credit exposure is below investment grade. The Company has one counterparty, Southern California Edison, that represents 11% of its gross exposure and as such is reportable as a concentration. The Company has offsetting cash collateral in the amount of $22.1 million. The Company has a 40% regional concentration with counterparties that primarily do business throughout the western United States and a 33% concentration with counterparties that primarily do business throughout the United States and Canada.
During 2001, the Company had transacted a significant volume of business with certain subsidiaries of Enron Corporation (“Enron”). Enron filed for bankruptcy protection on December 2, 2001.
At December 3, 2001, Energy Trading terminated its contracts with Enron. The Company recorded pre-tax charges of $48 million and $12 million related to trading and non-trading activities, respectively, in the fourth quarter of 2001. These charges reflect the write-off through earnings of net price risk management assets related to Enron contracts, net of collateral held and net accounts payable. Included as part of the non-trading charge to earnings was the write-off of a net price risk management asset of $18 million related to certain cash flow hedge contracts. As required by SFAS No. 133, the offsetting balance recorded in accumulated other comprehensive income (“OCI”) for these cash flow hedges was retained on the balance sheet at its fair value of $18 million as of December 3, 2001. This amount in OCI will be reclassified into earnings during the future periods in which the original hedged transactions will impact earnings (through 2006).
The Company also held other cash flow hedge contracts with Enron that were in a net gain position of $39 million as of December 3, 2001. The write-off of the net price risk management assets related to these contracts through earnings was offset entirely by the reclassification of the related OCI balances into earnings. This reclassification of OCI into earnings was made in accordance with SFAS No. 133 for hedges for which it was deemed probable that the original hedged forecasted transactions will not occur. The write-offs related to these contracts had no net effect on earnings.
Other than discussed above, the Company experienced minimal operations issues related to the Enron bankruptcy and energy trading markets did not experience any significant or sustained decline in liquidity.
Financial Instruments - The Company’s financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and certain accrued liabilities, long-term receivables, notes payable, commercial paper, capital leases, long-term debt, interest rate swap agreements, and other contracts that are used in commodity price risk management. The fair values of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and certain accrued liabilities, notes payable, commercial paper and capital lease approximate their carrying values as of December 31, 2001 and 2000, due to their short-term nature or due to the fact that interest on the instruments varies with the market.
The fair value of long-term debt was estimated using discounted cash flows analysis, based on the Company’s current incremental borrowing rate and the approximate carrying value based on currently quoted market prices for similar types of borrowing arrangements. Similarly, the fair values of long-term receivables were calculated using a discounted cash flows analysis.
The carrying amount and fair value of long-term receivables and long-term debt as of December 31, 2001 and 2000, is summarized as follows (in millions):
At December 31, 2001 and 2000, the Company had entered into interest rate swap agreements with aggregate notional amounts of $1.6 billion and $1.7 billion, respectively, to manage interest rate exposure on construction and term loan debt. These agreements expire through 2014. Before the Company adopted SFAS No. 133 on January 1, 2001, the Company did not carry its interest rate swaps on its consolidated balance sheets. The fair value of the Company’s interest rate swaps at December 31, 2000 was a $74 million liability. This fair value was estimated by calculating the present value of the difference between the total estimated payments to be made and received under the interest rate swap agreements, using appropriate current market rates.
Beginning January 1, 2001, the Company accounts for its interest rate swaps as derivatives under SFAS No. 133. The fair values of these contracts are carried at fair value as a component of price risk management assets and liabilities on the accompanying consolidated balance sheet, at December 31, 2001. Similarly, the Company’s other non-trading derivative contracts designated as hedges in accordance with SFAS No. 133 and the Company’s trading contracts are also carried at fair value as price risk management assets and liabilities on the accompanying consolidated balance sheet at December 31, 2001.
6. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
The Company has investments in various power generation and other energy projects. The equity method of accounting is applied to such investments in affiliated entities, which include corporations, joint ventures and partnerships, due to the ownership structure preventing the Company from exercising control. Under this method, the Company’s share of equity income or losses of these entities is reflected as equity in earnings of affiliates.
Operating entities which the Company does not control are as follows ($ in millions):
Net gains from the sale of interests in unconsolidated affiliates were $21 million and $19 million during 2000 and 1999, respectively, excluding the Company’s pipeline interests that were sold as part of the GTT disposition. Amounts are included in other operating expenses. There were no sales of unconsolidated affiliates in 2001.
The following table sets forth summarized financial information of the Company’s investments in affiliates accounted for under the equity method for the years ended December 31, 2001, 2000, and 1999 (in millions):
The reconciliation of the Company’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 purchase premium amortization expenses were $7 million, $7 million, and $8 million for the years ended December 31, 2001, 2000, and 1999, respectively.
7. LONG-TERM RECEIVABLES
The Company receives payments from a wholly owned subsidiary of NEES, related to the assumption of power supply agreements, which are payable monthly through January 2008. As of December 31, 2001, future cash receipts under this arrangement are as follows (in millions):
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. The current portion is included in prepaid expenses, deposits, and other in the consolidated balance sheets.
8. SHORT-TERM BORROWINGS
In August 2001, the Company arranged a $1.25 billion working capital and letter of credit facility consisting of $500 million with a 2-year term and $750 million with a 364 day term maturing in August 2003 and August 2002, respectively. NEG uses this facility to provide working capital and liquidity to its businesses, for letters of credit, to fund development and early phase construction expenditures and for other general corporate purposes. At December 31, 2001, the Company had total outstanding balances related to such borrowings of $330 million. As of December 31, 2001, the weighted average interest rate on the borrowings outstanding was 3.78%.
A $500 million 364-day facility and a $550 million five-year facility were repaid and cancelled on August 23, 2001.
Certain credit agreements contain, among other restrictions, customary affirmative covenants, representations and warranties and have cross-default provisions with respect to the Company’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 Company’s property or assets; incurrence of indebtedness; entering into agreements limiting the right of any subsidiary of the Company to make payments to its shareholders; and certain transactions with affiliates. Certain credit agreements also require that the company maintain a minimum ratio of cash flow available for fixed charges to fixed charges and a maximum ratio of funded indebtedness to total capitalization.
9. LONG-TERM DEBT
Long-term debt consists of the following (in millions):
Senior Unsecured Notes and Debentures - On May 22, 2001, the Company 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. The Company has used a portion of the net proceeds and intends to use the balance of the net proceeds to pay down existing revolving debt, fund investment in generating facilities and pipeline assets, working capital requirements and other general corporate requirements. These Senior Notes bear interest at 10.375% per annum and mature on May 16, 2011.
Outstanding Credit Facilities - The Company maintains various revolving credit facilities at subsidiary levels which currently are available to fund our capital and liquidity needs. A subsidiary of the Company maintains one $100 million revolving credit facility which expires in September 2003. GTN maintains a $100 million revolving credit facility that expires in May 2002 (but may be extended for successive one-year periods). Outstanding loans on these two facilities are charged LIBOR-based interest rates with an interest rate spread over LIBOR tied to the credit rating of the applicable subsidiary and the amount drawn on the facility. As of December 31, 2001, we had borrowed $160 million against our total $200 million borrowing capacity under these facilities.
Term Loans - In May 2001, the Company established a revolving credit facility of up to $280 million to fund turbine payments and equipment purchases associated with our generation facilities. This facility is amortizing and is due to be fully repaid on December 31, 2003. The facility provides for borrowings that bear interest based on LIBOR plus credit spread. As of December 31, 2001, the Company had borrowed $221 million against this total borrowing capacity at an average weighted interest rate of approximately 3.3%.
In September 2001, the Company established a facility for $69.4 million. The debt facility will be 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 has been declared or September, 2007. As of December 31, 2001, there was approximately $23 million outstanding under this facility at an interest rate of approximately 3.2%.
In December 2001, the Company entered into a new $1.075 billion 5-year non-recourse credit facility for the GenHoldings I, LLC portfolio of projects secured by the Millennium, Harquahala and Athens projects. The facility was used to reimburse the Company and lenders for a portion of the construction costs already incurred on these projects and
will be used to fund a portion of the balance of the construction costs through completion. The facility provides for borrowings that bear interest based on LIBOR plus a credit spread. As of December 31, 2001, there was approximately $450 million outstanding under this facility at an average interest rate of 4.6%.
APC, a wholly owned indirect subsidiary of the Company, assumed the Industrial Development Revenue Bonds (Series 2000) issued by the Mississippi Business Finance Corporation (bonds payable) through the acquisition of the Attala Generating Company, LLC. The Industrial Development Revenue Bonds mature on January 2010, bear a fixed interest of 10 percent and are redeemable at the option of the Company prior to maturity. In accordance with the purchase agreement, the seller paid off the outstanding bonds, in December 2001.
Subsequent to the issuance of the Company's 1999 and 2000 consolidated financial statements, management determined that the assets and liabilities relating to certain leased facilities should have been consolidated. The credit facilities outstanding as of December 31, 2001, were approximately $1 billion at an average weighted interest rate of approximately 6%, relating the Lake Road and the La Paloma projects. These nonrecourse facilities have terms through 2018 and 2022 for Lake Road and La Paloma, respectively. The Company has committed to project lenders to contribute equity of up to $230 million for Lake Road and $379 million for La Paloma through the purchase of the portion of project loans no later than March 31, 2003. The equity infusions could be triggered earlier by a downgrade of NEG below investment grade from both S&P and Moodys or the failure to meet certain debt covenants of either project.
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 the Company’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 Company’s property or assets; incurrence of indebtedness; entering into agreements limiting the right of any subsidiary of the Company to make payments to its shareholders; and certain transactions with affiliates. Certain credit agreements also require that the company maintain a minimum ratio of cash flow available for fixed charges to fixed charges and a maximum ratio of funded indebtedness to total capitalization.
At December 31, 2001, annual scheduled maturities of long-term debt during the next five years were as follows (in millions):
Interest expense, net of capitalized interest, for the years ended December 31, 2001, 2000, and 1999, was $138 million, $155 million, and $162 million, respectively.
10. PREFERRED STOCK OF SUBSIDIARY
Preferred stock consists of $58 million of preferred stock issued by a subsidiary of the Company 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, 2001 and 2000.
11. EMPLOYEE BENEFIT PLANS
Certain subsidiaries of the Company 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, 2001 and 2000 (in millions):
As of December 31, 2001 and 2000, the defined benefit pension plan for the employees of GTN had plan assets in excess of benefit obligations of $3 million and $11 million, respectively. The unrecognized net actuarial gains 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 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 2002 assumed health care cost trend rate for benefits prior to age 65 and for benefits at age 65 and later, is approximately 7.5% and 7.2%, respectively, grading down to an ultimate rate in 2005 of approximately 6.0% 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 the Company 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 $13 million, $14 million, and $15 million for 2001, 2000, and 1999, respectively.
Regulatory Matters - In conformity with SFAS No. 71, regulatory adjustments for 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. The 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 the FERC’s policy, 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, GTN had over collected $8 million at December 31, 2001 and $6 million at December 31, 2000. Plan assets consist primarily of common stock, fixed-income securities, and cash equivalents.
Long-term Incentive Program - Employees of the Company participate in the Parent’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 Company employees’ share of benefits under the program. Options granted in 2001 were measured using two sets of assumptions under the Black-Scholes valuation method deriving weighted average fair values of $6.01 per share for 2,670,700 options granted and $5.80 per share for 2,452,800 options granted at their respective date of grant, while options granted in 2000, and 1999, of 3,712,218, and 2,378,341, respectively, had weighted average fair value at date of grant of approximately $3.26, and $4.19, respectively, using the Black-Scholes valuation method. Significant assumptions used in the Black-Scholes valuation method for shares granted in 2001 (two sets of assumptions used for 2001), 2000, and 1999 were: expected stock price volatility of 33.00% and 29.05% (2001), 20.19%, 16.79%, respectively; expected dividend yield of zero% and 4.35% (2001), 5.18%, and 3.77%, respectively; risk-free interest rate of 5.24% and 5.95% (2001), 6.10%, and 4.69%, respectively; and an expected 10-year life for all periods.
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 31,2001, 11,523,336 options were outstanding of which 3,844,356 were exercisable.
In addition, certain employees of the Company also participate in the Parent’s Performance Unit Plan (another component of the Program) that provides incentive compensation to participants based upon the year-end stock price of the Parent and a predetermined comparison group. For the years ended December 31, 2001, 2000, and 1999, the compensation expense under this program for Company employees was $0.3 million, $0.3 million, and $0.8 million, respectively.
Stock-Based Compensation
The company accounts for stock-based compensation arrangements in Parent stock using the intrinsic value method in accordance with the provision of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation.” Under the intrinsic value method, the Company 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, the Company’s pro forma consolidated net earnings (loss) would have been as follows (in millions):
12. INCOME TAXES
The significant components of income tax expense (benefit) from continuing operations were as follows (in millions):
The Company owns two facilities that produce synthetic fuel from coal which qualifies for tax credits under Section 29 of the Internal Revenue Code (the “Code”). The Company also owns a number of renewable resource facilities that generate electricity using wind which qualifies for tax credits under Section 45 of the Code. These facilities all began operations in 2001, and as result, produced tax credits that reduced current federal income tax expense in 2001.
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):
The Company has $78 million in permanently invested funds that relate to foreign undistributed earnings.
13. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
Firm Commitments - The Company, through its subsidiaries, has entered into various long-term firm commitments with an approximate dollar obligations as follows (in millions):
Fuel Supply and Transportation Agreements - The Company, through its subsidiaries GenLLC and ET, has entered into various gas supply and firm transportation agreements with various pipelines and transporters to provide fuel transportation services to our own power plants and other customers. Under these agreements, the Company must make specified minimum payments each month.
Power Purchase Agreements - Through its indirect subsidiary, USGen New England, GenLLC assumed rights and duties under several power purchase contracts with third party independent power producers as part of the acquisition of the NEES assets. As of December 31, 2001, these agreements provided for an aggregate of 800 MW of capacity. Under the transfer agreement, the Company is required to pay to NEES amounts due to third-party producers under the power purchase contracts.
Operating Leases - The Company has entered into several operating lease agreements for generating facilities and office space. Lease terms vary between 3 and 48 years. In November 1999, a subsidiary of the Company entered into a $479 million sale-leaseback transaction whereby the subsidiary sold and leased back a pumped storage station under an operating lease. Operating lease expense amounted to $54 million, $70 million, and $70 million in 2001, 2000, and 1999, respectively.
The Pittsfield Generating Company, L.P. ("Pittsfield") facility previously qualified as a qualified cogeneration facility (“QF”) under PURPA. The facility failed to meet the “efficiency standard” required to maintain QF status for calendar years 2001, 2000 and 1999. Pittsfield obtained from the FERC a waiver of the efficiency standard for 2000 and 1999 and has pending before the FERC a waiver request for 2001. Failure to maintain QF status is a default under the Pittsfield lease documents. By letter dated February 13, 2002, GE Capital Corporation informed Pittsfield that it will waive to January 1, 2003 any default arising under the lease documents from failure to maintain QF status so long as Pittsfield continues to be an Exempt Wholesale Generator under PUHCA, retains its market based rate authority under the Federal Power Act (“FPA”), and maintains in effect at the FERC its long term power purchase agreements as rate schedules under Section 205 of the FPA.
Long Term Service Agreements - The Company has 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.
Construction Commitments - The Company currently has six projects (Athens, Covert, Lake Road, La Paloma, Harquahala and Plains End) under construction. Development has been largely completed for the Mantua Creek project and it is ready to begin construction. The Company has entered into a construction contract for the facility and released the contractor under a notice to proceed to perform a limited amount of early construction activities and therefore the construction commitments associated with Mantua Creek are included above. The Company's construction commitments are generally related to the major construction agreements including the EPC and other related contracts. Certain EPC contracts also contain the commitment for turbines and related equipment.
Turbine and Equipment Purchase Commitment for Construction Projects - These commitments relate to those constructions projects which are directly procuring their turbines and other related equipment directly from vendors and not as a portion of their EPC contract.
Turbine and Equipment Purchase Commitment for Development Projects - To support the Company's development program, NEG has contractual commitments and options for turbines and related equipment. In connection with NEG's current revised development plans, the Company has restructured some of the equipment purchase and option commitments to provide additional flexibility in payment terms and delivery schedules to better accommodate the potential delay, swap or sale of generation projects in development.
Tolling Agreements - In 2000 and 2001, the Company, through ET, entered into tolling agreements with several counterparties allowing the Company the right to sell electricity generated by facilities owned and operated by other parties. Under the tolling agreements, the Company, 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 criteria. At December 31, 2001, the annual estimated committed payments under such contracts ranged from approximately $33 million to $211 million, resulting in total committed payments over the next 27 years of approximately $4 billion, commencing at the completion of construction. During 2001, the Company paid total committed payments of approximately $13 million under tolling arrangements.
Payments in Lieu of Property Taxes - The Company has entered into certain agreements with local governments that provide for payments in lieu of property taxes for some of its generating facilities.
CONTINGENCIES
Guarantees Supporting Tolling Agreements - A subsidiary of the NEG has entered into five long-term tolling transactions with third parties. Each tolling agreement is supported by a separate guarantee backing the NEG affiliate’s payment obligations over the term of these long-term contracts (9-25 years). NEG has extended about $600 million of such guarantees with the initial face value varying from $20 million to $250 million declining over time as the future obligation declines. Each of these guarantees contains a trigger event provision that requires the guarantor to replace the guarantee or provide alternative collateral in the event that the NEG credit rating drops (as measured by one or two major agencies as identified in the agreement) below the prescribed grade (generally BBB or Baa2). As of December 31, 2001, our net exposure under our guarantees supporting tolling agreements was approximately 3% or $20 million.
Guarantees Supporting Agreements with Third Parties - The Company has issued in excess of $800 million of guarantees from NEG and its subsidiaries in support of various performance and payment obligations under agreements with third parties. Of the Company's guarantees supporting other agreements with third parties, $485 million have investment grade ratings maintenance requirements. In addition, a number of other agreements have specific security provisions requiring maintenance of investment grade ratings. In the event of a downgrade below the trigger level and exhaustion of any cure period, some of these agreements would allow the counterparty to demand payment for any outstanding obligations or of any contract termination penalties. Others simply provide the counterparty with a right to terminate the contract.
Guarantees Supporting Trading Related Agreements - The Company’s Energy business is primarily conducted with counterparties under various master agreements that govern business done between Energy and the counterparty. These agreements typically provide for reciprocal extension of credit lines based on creditworthiness standards. Positions governed by these master agreements are marked to market on a routine basis and if the net exposed position including receivables and payables falls outside of the established credit lines, then additional collateral must be provided.
In addition to our guarantees supporting tolling agreements, as of December 31, 2001, the Company and its subsidiaries provided $2.3 billion of guarantees to third party counterparties in support of our Energy operations. This amount included provision of fuel and pipeline capacity to, and sale of energy products from the Company’s power plants. These guarantees are provided in favor of approximately 200 counterparties to permit and facilitate physical and financial transactions in gas, pipeline capacity, power, coal and related commodities and services with these entities. As of December 31, 2001, our net exposure under our guarantees was approximately 8% of the face value of our guarantees, or about $190 million. This exposure is a contingent obligation that could only be called if the Company or one of its subsidiaries fail to meet and cure a payment obligation.
The continued acceptability of many of these guarantees is dependent on the Company maintaining various standards of creditworthiness. As a result, maintenance of investment grade ratings by the Company and several of its principal subsidiaries by one or more rating agencies is an important business objective. If the Company or its subsidiaries are downgraded by one or more of the rating agencies, the Company may be required to provide alternative collateral to replace guarantees that no longer meet the creditworthiness standards of our agreements.
The amount of exposure under master agreements subject to securitization requirements in the event of a credit downgrade of the Company or its subsidiaries to below investment grade by one or more rating agencies was approximately 5% of the outstanding guarantees or $106 million. The Company manages this risk through maintenance of investment grade credit ratings at several principal operating subsidiaries, including PG&E Energy Trading Holdings Corporation, so that the guarantee of one entity could be substituted for another in the event of a credit downgrade by one entity.
Letters of Credit: The following table provides the various letter of credit facilities and credit facilities which have the capacity to issue letters of credit (in millions):
(*) This credit facility consists of a $500 million tranche with a two year term and a $750 million tranche with a 364 day term maturing in August 2003 and August 2002 respectively. Borrowings under the $750 million tranche were $330 million at December 31, 2001 and are reported as Short-Term Borrowings.
Legal Matters - In addition to the following legal proceedings, the Company is subject to routine litigation incidental to our business.
NSTAR Electric & Gas Corporation - On May 14, 2001, NSTAR Electric & Gas Corporation, or NSTAR, the Boston-area retail electric distribution utility holding company, filed a complaint at FERC contesting the market-based rate authority of ET-Power and affiliates of Sithe Energies, Inc., or Sithe. In support of its complaint, NSTAR argues that the Northeastern Massachusetts Area, or NEMA, at times suffers transmission constraints which limit the delivery of power into NEMA and that 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 ISO-New England, the independent system operator for the New England control area, or NEPOOL. Under the NEPOOL market rules and procedures, ISO-New England is empowered to monitor and mitigate bids during periods of transmission congestion. The Company believes that ISO-New England has actively mitigated bids and has used its authority to minimize the impact of transmission constraints on costs within NEMA and that ET-Power has operated its resources in compliance with NEPOOL market rules and procedures and applicable law. In addition, ET-Power and its affiliate, USGen New England, 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 of a 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”). The FERC has ordered ISO-New England to file by February 25, 2002 all agreements entered into pursuant to MRP 17. In addition, the FERC has ruled that no refunds will be required with respect to the agreements for periods prior to 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. 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 and 2001 that sets forth terms on which bids from Salem Harbor Station Unit 4 may be mitigated without challenge by ET-Power. To date, bid amounts collected subject to the mitigation agreements are approximately $34.1 million. ET-Power expects to enter into a mitigation agreement for 2002.
The Company believes that the ultimate outcome of this litigation will not have a material adverse effect on the Company’s financial condition or results of operations.
FERC California Refunds Proceeds - 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. 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 the Commission 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 the 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 ET-Power. The FERC indicated that ET-Power may be required to refund approximately $26 million. On December 19, 2001 FERC issued a decision purporting to clarify its earlier orders. The California ISO is scheduled to provide an update of its August 17, 2001 data on or before March 1, 2002. Using what we believe to be the same methodology (including pricing information provided by the California ISO), the amount of the refund owed by ET-Power, excluding offsets, could be significantly less. In addition, FERC has indicated that unpaid amounts owed by the California ISO and California Power Exchange may be used as offsets to any refund obligations. The Company estimates that ET-Power is currently owed approximately $22 million that could be used as offsets to certain potential refund obligations. Finalization of all these amounts will be subject to the on-going FERC proceeding. The Company believes that the ultimate outcome of this matter will not have a material adverse affect on the Company’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 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. The Company believes that the ultimate outcome of the litigation will not have a material adverse effect on its financial condition or results of operations.
Absestos Litigation - Pursuant to an Asset Purchase Agreement dated as of August 5, 1997, USGen New England agreed to indemnify NEPCo for certain losses. Such losses included claims arising from certain conditions on the site of the generation assets USGen New England 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 USGen New England purchased from NEPCo. Under the Asset Purchase Agreement USGen New England may be required to indemnify NEPCo for some or all of these claims. The Company believes that the ultimate outcome of this litigation will not have a material adverse effect on the Company’s financial condition or results of operations.
Wholesale Standard Offer Service- USGen New England acquired from NEPCo and Narragansett Electric Company (“Narragansett”) certain generation assets in New England. As part of the acquisition, USGen New England 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 expenses, uplift charges and congestion costs. NEPCo and Narragansett are currently paying the charges under a Tolling Agreement which expires by its terms on April 30, 2002, unless extended by mutual agreement. The Tolling Agreement does not prohibit either party from undertaking proceedings to decide on 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 USGen New England that they are invoking the dispute resolution provisions of the WSOS Agreements and that they will seek reimbursement of $27 million for amounts incurred to date along with a ruling that under the WSOS Agreements these costs should be imposed on USGen New England going forward. These going forward costs are estimated to be $1.8 million. The Company believes that the ultimate outcome of this litigation will not have a material adverse effect on the Company’s financial condition or results of operations.
In accordance with SFAS No. 5, Accounting for Contingencies, the Company makes a provision for a liability when both it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. In 1999, the Company reduced the amount of the recorded liability for legal matters related to pending litigation at GTT, by approximately $55 million. The remaining liability is assumed by the buyer of GTT. This adjustment is reflected in Other income (expenses) - net in the Company’s consolidated statements of operations.
Environmental Matters - In May 2000, the Company 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 the Company to provide certain information, relative to the compliance of the Company’s Brayton Point and Salem Harbor Generating Stations with the CAA. No enforcement action has been brought by the EPA to date. The Company has had very preliminary discussions with the EPA to explore a potential settlement of this matter. As a result of this and related regulatory initiatives by the Commonwealth of Massachusetts, the Company is exploring initiatives that would assist the Company to achieve significant reductions of sulfur dioxide and nitrogen oxide and thermal emissions by 2006. Management believes that the Company 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 approximate $266 million over the next five years. The Massachusetts Department of Environmental Protection (“DEP”) may require earlier compliance, which the Company believes may not be feasible and would require the use of credit allowances it currently owns or the purchase of additional credit allowances. 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.
The Company’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 USGen New England are operating pursuant to NPDES permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and it is anticipated that all three facilities will be able to continue to operate under existing terms and conditions until new permits are issued. It is estimated that USGen New England’s cost to comply with the new permit conditions could be as much as $67 million through 2005. It is possible that the new permits may contain more stringent limitations than prior permits.
During April 2000, an environmental group served USGen New England and other of the Company’s subsidiaries with a notice of its intent to file a citizen’s suit under RCRA. In September 2000, the Company signed a series of agreements with the DEP and the environmental group to resolve these matters that require the Company to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities. The Company began the activities during 2000, and is expected to complete them in 2002. The Company incurred expenditures related to these agreements of approximately $5.8 million in 2000 and $2.4 million in 2001. In addition to the costs incurred in 2000 and 2001, at December 31, 2001, the Company maintains a reserve in the amount of $10.0 million relating to its estimate of the remaining environmental expenditures to fulfill its obligations under these agreements. The Company has deferred costs associated with capital expenditures and has set up a receivable for amounts it believes are probable of recovery from insurance proceeds.
14. RELATED-PARTY TRANSACTIONS
The Parent - The Company and its affiliates are charged for administrative and general costs from Parent. These charges are based upon direct assignment of costs and allocations of costs using allocation methods that the Company and Parent believe are reasonable reflections of the utilization of services provided to or for the benefits received by the Company. For the years ended December 31, 2001, 2000, and 1999, allocated costs totaled $61 million, $43 million, and $31 million, respectively. The total amount due Parent at December 31, 2001 and 2000, was $26 million and $21 million, respectively. In addition, the Company bills Parent for certain shared costs. For the years ended December 31, 2001, 2000 and 1999, the total charges billed to Parent were $0.5 million, $0.8 million, and $0.3 million, respectively. The amounts receivable from Parent at December 31, 2001 and 2000, were $1.6 million, and $1.3 million, respectively.
During the periods covered by these financial statements, the Company invested its available cash balances with, or borrowed from, Parent on an interim basis pursuant to a pooled cash management arrangement. The balance advanced to Parent under this cash management program was $2.0 million at an interest rate of 5.4% as of December 31, 2000. The interest rate on these cash investments or borrowings averaged 6.2% in 2000 and the related interest income was $0.3 million. As described in Note 2, the Company terminated its intercompany borrowing and cash management programs with Parent in 2000.
On October 26, 2000, the Company loaned $75 million to Parent pursuant to a promissory note. The principal amount of this investment is payable upon demand and is reflected as Long-Term Note receivable from Parent on the consolidated balance sheets. The balance at December 31, 2001, is $75 million at an interest rate of 7.6%. The interest rate on this cash investment averaged 7.7% in 2001 and 6.8% in 2000.
Also, through the periods covered by these financial statements, Parent issued guarantees, surety bonds, and letters of credit on behalf of the Company to support its energy trading activities and structured tolling activities. As of December 31, 2001 and 2000, Parent had issued $16 million and $2.4 billion in these types of instruments. As described in Note 2, the Company replaced these Parent-backed security mechanisms with other means of credit support (including guarantees provided by the Company and its subsidiaries and credit facilities negotiated with third parties) during 2001, except for a guarantee for leased office space.
As of December 31, 2001, Attala Power Corporation (“APC”), an indirect, wholly-owned subsidiary of the Company, has a non-recourse demand note payable to the Parent of $309 million. The APC note is classified as short-term on the consolidated balance sheet, as of December 31, 2001 reflecting the Company’s expectations about the timing of repayment. The demand note between APC and the Parent is recourse only to the assets of APC and not to the Company.
In addition, as of December 31, 2001, other wholly-owned subsidiaries of the Company had net amounts payable in the amount of $122 million in the form of promissory notes to Parent related primarily to past funding of generating asset development and acquisition, of which $118 million was classified as long-term on the consolidated balance sheet. Furthermore, as of December 31, 2001, the Company has recorded a $99 million amount receivable from Parent related to the intercompany tax-sharing arrangement; this amount is included in “Long-term receivables from Parent”, as of December 31, 2001, in the accompanying consolidated balance sheet.
Pacific Gas and Electric Company - The Company incurs and bills direct charges from and to the Utility for shared services. For the years ended December 31, 2001, 2000, and 1999, the total charges were $0 million, $0.9 million, and $5.5 million, respectively. At December 31, 2001 and 2000, the total amounts payable to the Utility were $2 million and $1.9 million, respectively. In addition, the amounts receivable from the Utility related to shared services at December 31, 2001 and 2000, were $1 million and $1 million, respectively.
ET enters into transactions with related parties, including the Utility. The nature of these transactions is the purchasing and selling of energy commodities and general corporate business items. For the years ended December 31, 2001, 2000, and 1999, ET had energy commodity sales of approximately $120 million, $136 million, and $30 million to the Utility and energy commodity purchases of $21 million, $12 million, and $7 million, respectively. As of December 31, 2001 and 2000, ET had trade receivables relating to energy commodity transactions from the Utility of $30 million and $1.2
million, respectively, and trade payables relating to energy commodity transactions to the Utility of $1.1 million and $1.2 million, respectively.
In 2001, 2000 and 1999, the Utility accounted for approximately $41 million, $46 million and $47 million, respectively, of GTN’s transportation revenues. In accordance with GTN’s FERC tariff provisions, the Utility has provided assurances in the form of cash to support its position as a shipper on the GTN pipeline. As a result of the April 6, 2001, filing with the Bankruptcy Court all $2.9 million due from the Utility to GTN on that date remains outstanding. The Utility is current on all subsequent obligations incurred for transportation services by GTN and has indicated its intention to remain current. We have also 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, our La Paloma generating facility has an interconnection agreement with the Utility.
15. SEGMENT INFORMATION
The Company is currently managed under 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 key decision makers. The first business segment is composed of Integrated Energy and Marketing Activities, principally the generation and energy trading operations which are managed and operated in a highly integrated manner. The second business segment is Interstate Pipeline Operations. See Note 4 for more discussion of the sale of GTT from the Interstate Pipeline Operations. Segment information for the years 2001, 2000 and 1999 was as follows (in millions):
16. 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, 2001 and 2000, and the related consolidated statements of operations, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2001. Our audits also included the financial statement schedule listed in Item 14, 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 the financial statements and financial statement schedule based on our audits. We did not audit the financial statements of certain partnerships (the Partnerships) which are accounted for by the Company using the equity method. The Company’s equity of $46 million in the net assets of the Partnerships at December 31, 2001 and of $154 million in the Partnerships’ net income for the year ended December 31, 2001 are included in the accompanying financial statements. The financial statements of the Partnerships were audited by other auditors 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 and the reports of the other auditors 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, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, 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, the Company has revised its consolidated balance sheet as of December 31, 2000, and its consolidated statements of operations and cash flows for the years ended December 31, 2000 and 1999, to consolidate the assets and liabilities of certain leased facilities.
See Note 2 of the consolidated financial statements for discussion of the bankruptcy of an affiliated company.
As discussed in Note 3 of the Notes to the Consolidated Financial Statements, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by Statement of Financial Accounting Standards No. 138, “Accounting for Certain Derivatives and Hedging Activities”, effective January 1, 2001 and interpretations issued by the Derivatives Implementation Group of the Financial Accounting Standards Board during 2001, and in 1999 the Company changed its method of accounting for major maintenance and overhauls.
February 26, 2002
McLean, Virginia
/s/ DELOITTE & TOUCHE LLP
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
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
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
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
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
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
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 December 31, 2001:
Name
Age
Position
Thomas G. Boren
President, Chief Executive Officer and Director
P. Chrisman Iribe
President and Chief Operating Officer, Eastern Region
Thomas B. King
President and Chief Operating Officer, Western Region
Lyn Maddox
President and Chief Operating Officer, Trading
Stephen A. Herman
Senior Vice President and General Counsel
John R. Cooper
Senior Vice President, Finance
Thomas E. Legro
Vice President, Controller and Chief Accounting Officer
Sarah M. Barpoulis
Senior Vice President, Commercial Operations, Trading
G. Brent Stanley
Senior Vice President, Human Resources and Director
Peter A. Darbee
Director
Bruce R. Worthington
Director
Andrew L. Stidd
Director
Thomas G. Boren has been our President and Chief Executive Officer since August 1999, and was elected to our board of directors in July 2000. He has also served as Executive Vice President of PG&E Corporation since August 1999. Mr. Boren was President and Chief Executive Officer of Southern Energy Inc., Southern Company’s worldwide power plant, energy trading, and energy services business from February 1992 to July 1999. He served as Senior Vice President and later Executive Vice President of Southern Company from 1992 to July 1999. Mr. Boren held senior management positions with Southern Company’s utility unit, Georgia Power Company, from 1981 to 1992.
P. Chrisman Iribe has 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).
Thomas B. King has 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 and Chief Operating Officer of PG&E Gas Transmission, Northwest Corporation, one of our subsidiaries, since November 1998. 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.
Lyn Maddox has 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.
Stephen A. Herman has been our Senior Vice President and General Counsel since July 2000. From April 1999 to April 2000, he was a partner in the law firm of Latham & Watkins. He was Senior Vice President and General Counsel of U.S. Generating Company (now PG&E Generating Company), one of our subsidiaries, from August 1990 to April 1999. Prior to that, he was a partner with the law firm of Kirkland & Ellis.
John R. Cooper has been our Senior Vice President, Finance since July 2000. He served as Senior Vice President Finance and Chief Financial Officer of PG&E Generating Company, one of our subsidiaries, from August 1997 to June 2000. Prior to that time, Mr. Cooper served as Senior Vice President, Finance for U.S. Generating Company from March 1993 to August 1997.
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).
Sarah M. Barpoulis has been our Senior Vice President, Commercial Operations, Trading since July 2000. She served as Senior Vice President of PG&E Energy Trading - Power, L.P., one of our subsidiaries, from May 1998 to June 2000. Prior to that time, Ms. Barpoulis served as Vice President, Trading Operations for USGen Power Services, L.P., a predecessor to PG&E Energy Trading, from June 1996 to May 1998 and held various positions at U.S. Generating Company from July 1991 to June 1996.
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, Chief Financial Officer, and Treasurer of PG&E Corporation since January 1999. 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. 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.
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
The following table summarizes the principal components of compensation paid to our chief executive officer and our four other most highly compensated executive officers by PG&E Corporation or its subsidiaries during 2001.
Summary Compensation Table
(1)
Represents payments received or deferred for achievement of corporate and organizational objectives in 2001 under the PG&E Corporation Short-Term Incentive Plan.
Grants of PG&E Corporation Options in 2001
The following table shows all grants in 2001 of options to acquire PG&E Corporation common stock made to the executive officers listed in the summary compensation table.
PG&E Corporation Option Grants In 2001
(1) All options granted to executive officers in 2001 are exercisable as follows: one-third of the options may be exercised on or after the second anniversary of the date of grant, two-thirds on or after the third
Anniversary, and 100 percent on or after the fourth anniversary, provided that options will vest immediately upon the occurrence of certain events. No options were accompanied by tandem dividend equivalents.
(2) The exercise price is equal to the closing price of PG&E Corporation common stock on the date of grant.
(3) All options granted to executive officers in 2001 expire 10 years and one day from the date of grant, subject to earlier expiration in the event of the officer’s termination of employment with PG&E Corporation or one of its subsidiaries.
(4) Estimated present values are based on the Black-Scholes Model, a mathematical formula used to value options traded on stock exchanges. The Black-Scholes Model considers a number of factors, including the expected volatility and dividend rate of the stock, interest rates, and time of exercise of the option. The following Assumptions were used in applying the Black-Scholes Model to the 2001 option grants shown in the table above: volatility of 29.05% for the January 5, 2001 grant and 33.0% for the August 15, 2001 grant, risk-free rate of return of 5.95% for the January 5, 2001 grant and 5.24% for the August 15, 2001 grant, dividend yield of $1.20 for the January 5, 2001 grant and $0.00 for the August 15, 2001 grant, (the annual dividend rate on the grant date), and an exercise date five years after the date of grant. The ultimate value of the options will depend on the future market price of PG&E Corporation common stock, which cannot be forecast with reasonable accuracy. That value will depend on the future success achieved by employees for the benefit of all shareholders. The estimated grant date present value for the options shown in the table was $5.80 per share for the January 5, 2001 grant and $6.01 per share for the August 15, 2001 grant.
Aggregate PG&E Corporation Option Exercises in 2001 and Year-End Option Values
The following table summarizes exercises in 2001 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 2001.
Aggregate PG&E Corporation Option/SAR Exercises in 2001 and Year-End Values
PG&E Corporation Long-Term Incentive Plan Compensation
The following table summarizes long-term incentive awards made in 2001 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 2001
(1)
Represents performance units granted under the 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 the 11 company comparator group. This performance target may be adjusted during the vesting period, at the sole discretion of the Nominating and Compensation 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.
(2)
Represents common stock equivalents called Special Incentive Stock Ownership Premiums (SISOPs) earned under the 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 the Nominating and Compensation Committee. Of the officers named in the Summary Compensation Table, only Messrs. Boren, Iribe, King, and Maddox are eligible officers. Each SISOP represents a share of PG&E Corporation common stock 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.
(3)
Represents phantom restricted stock units awarded to the named executive. These units vest on December 31, 2004 only if the Corporation’s performance, as measured by relative Total Shareholder Return (TSR) on a cumulative basis over four years, is at or above the 55th percentile of its comparator group and the executive is in service. However, if at the end of the third year of the grant, December 31, 2003, the Corporation’s performance as measured
by relative TSR on a cumulative basis is at or above the 75th percentile of its comparator group, the units will vest at that time. Eligible executives may elect to defer award payments under the PG&E Corporation Supplemental Retirement Savings Plan before vesting. Such deferrals will be made in PG&E Corporation phantom stock units on the first business day of January of the year following vesting. Awards not deferred will be paid in cash in January of the year following vesting.
(4)
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. For grants of phantom restricted stock units, payments will be determined by multiplying the number of units by the closing market price of PG&E Corporation common stock on the date of vesting.
Employment Contracts/Arrangements
Thomas G. Boren’s employment letter entitles him to receive salary, other cash and equity awards as described elsewhere and other standard employee benefits. Mr. Boren’s participation in the supplemental defined benefit executive retirement plan includes recognition of credited years with his former employer, Southern Company, although benefits will be reduced by benefits payable from Southern Company’s plan, excluding special enhancements payable as part of his separation from Southern Company. Under his employment letter, Mr. Boren was entitled to receive credit to his account to the parent’s deferred contribution plan of $1,000,000 in three annual installments, upon satisfaction of annual general business goals. Mr. Boren’s last installment was credited December 31, 2001. Mr. Boren also is eligible to receive a mortgage subsidy equal to $26,667 per $100,000 of loan value, limited to a loan amount of $1,500,000 through July 2004, with a maximum subsidy of $400,000 ($80,000 per year). Mr. Boren also will be compensated for the loss of mortgage tax deduction in excess of the $1,000,000 maximum allowed by law, up to the stated maximum mortgage loan amount of $1,500,000.
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 or 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 in this prospectus, 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.
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. According to the policy, a “change in control” of PG&E Corporation occurs upon (A) the acquisition of 20% or more of PG&E Corporation’s outstanding voting securities by a single entity or person, (B) a change in the directors who constitute a majority of PG&E Corporation’s board of directors over a two-year period, unless the new directors were nominated by at least two-thirds of PG&E Corporation’s board of directors who were directors at the beginning of the two-year period, or (C) approval by PG&E Corporation’s shareholders of certain corporate transactions. 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 (w) unpaid base salary earned through the termination date, (x) 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, (y) any accrued but unpaid vacation pay and (z) 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.
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, 2001 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 the following page, 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
We are 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 we and Parent believe are reasonable
reflections of the utilization of services provided to or for the benefits received by the Company. For the years ended December 31, 2001, 2000, and 1999, allocated costs totaled $61 million, $43 million, and $31 million, respectively. The total amount due Parent at December 31, 2001 and 2000, was $26 million and $21 million, respectively. In addition, the Company bills Parent for certain shared costs. For the years ended December 31, 2001, 2000 and 1999, the total charges billed to Parent were $0.5 million, $0.8 million, and $0.3 million, respectively. The amounts receivable from Parent at December 31, 2001 and 2000, were $1.6 million, and $1.3 million, respectively.
The amounts above do not include amounts paid to Utility from which we receive (and to which we provide) limited corporate support services. In 2001, 2000, 1999 the total charges $0 million, $0.9 million and $5.5 million. California Public Utilities Commission regulations limit our ability to share certain types of services and information with the Utility. In addition, PG&E Corporation’s new credit agreement, which is described below, includes a covenant that generally restricts certain intercompany transactions to those made on arm’s-length terms.
We are included in the consolidated tax return of PG&E Corporation. Through our tax-sharing arrangement with PG&E Corporation, we have recognized tax expense or benefit based upon our share of consolidated income or loss through an allocation of income taxes from PG&E Corporation which allowed us to utilize the tax benefits we generated so long as they could be used on a consolidated basis. In 2001 calendar year, we paid to PG&E Corporation the amount of income taxes that we were liable for if we filed our own consolidated combined or unitary return separate from PG&E Corporation subject to certain consolidated adjustments.
In addition, in the recent past the Utility has been Pipeline’s largest customer and, during 2001, 2000 and 1999, $41 million, $46 million and $47 million, respectively, of the revenues generated by our GTN pipeline have come from the Utility. In addition, our Energy segment also purchases from and sells to the Utility energy commodities, primarily natural gas. In 2001, 2000 and 1999 our Energy segment had energy commodity sales of approximately $120 million, $136 million and $30 million, respectively, to the Utility and energy commodity purchases of $21 million, $12 million and $7 million, respectively. We have also 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, our La Paloma generating facility has an interconnection agreement with the Utility.
Loans, Capital Commitments and Guarantees
Periodically we and our subsidiaries have borrowed funds from, or loaned money to, PG&E Corporation for specific transactions or other corporate purposes. At December 31, 2001, we had a net outstanding loan balance payable to PG&E Corporation of $356 million, including net amounts payable of $309 million related to Attala Power Corporation, net amounts payable of $122 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 GTN. In addition, until December 28, 2000, funds from our operations were managed through net investments or borrowing in a pooled cash management arrangement with PG&E Corporation.
PG&E Corporation also has historically provided us with collateral for a range of contractual commitments. This collateral has included: agreements to infuse equity into specific projects when projects begin operations or when we purchase a project that we have leased, support of letter of credit facilities, guarantees of our obligations under long-term tolling arrangements and security for our commitments under various contracts. As of December 31, 2001, the Company had replaced or eliminated all of the previously issued Parent guarantees, except for an office lease guarantee in the amount of $16.3 million, relating to the Company’s San Francisco office, with a combination of guarantees provided by the Company or its subsidiaries and letters of credit obtained independently by the Company.
Ringfencing Transaction
In December 2000, and in January and February 2001, PG&E Corporation and NEG completed a corporate restructuring of NEG, known as a “ringfencing” transaction. The ringfencing involved the creation or use of limited liability companies (“LLCs”) as intermediate owners between a parent company and its subsidiaries. These LLCs are PG&E National Energy Group, LLC which owns 100% of the stock of NEG, GTN Holdings LLC which owns 100% of the stock of GTN, and PG&E Energy Trading Holdings, LLC which owns 100% of the stock of ET. In addition, NEG’s organizational documents were modified to include the same structural elements as the LLCs. The LLCs 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 LLCs may not declare or pay dividends unless the respective boards of directors have unanimously approved such action, and the company meets specified financial requirements. After the ringfencing structure was implemented, two independent rating agencies, Standard & Poor’s (S&P) and Moody’s Investors Service reaffirmed investment grade ratings for GTN and GenLLC, and issued investment grade ratings for NEG. S&P also issued an investment grade rating for ET.
The FERC issued a letter order granting approval of the corporate restructuring on January 12, 2001. Thereafter, requests for rehearing and requests to vacate that order were filed with the FERC, each of which was denied by the FERC on February 21, 2001. Requests for rehearing of the February 21 order were then filed. On January 30, 2002, the FERC issued an order denying all pending petitions for rehearing. On February 21, 2002, the California Attorney General appealed the FERC’s January 30 order to the United States Court of Appeals for the Ninth Circuit.
On April 6, 2001, the Utility, another wholly-owned subsidiary of Parent, filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. On September 20, 2001, the Utility and Parent jointly filed a plan of reorganization that entails separating the Utility into four distinct businesses. The plan of reorganization does not directly affect the Company or any of its subsidiaries. Subsequent to the bankruptcy filing, the investment grade ratings of the Company and its rated subsidiaries were reaffirmed on April 6 and 9, 2001.
Management believes that the Company and its direct and indirect subsidiaries, as described above, would not be substantively consolidated with the Parent in any insolvency or bankruptcy proceeding involving the Parent or in the Utility’s bankruptcy proceeding.
PG&E Corporation’s Financing
On March 1, 2001, Parent refinanced its debt obligations with $1 billion in aggregate proceeds from two term loans under a common credit agreement with General Electric Capital Corporation (GECC) and Lehman Commercial Paper Inc. (LCPI), maturing on March 1, 2003.
On November 19, 2001, and March 4, 2002, Parent signed agreements to amend its $1 billion aggregate term loan credit facility. The original debt obligations entered into on March 1, 2001, permitted Parent to extend the term of the credit facility, which would otherwise expire on March 1, 2003, for an additional year. The amendments provide for two additional one-year extensions to the term of the credit facility, contingent on Parent making a principal payment of $308 million by June 3, 2002, so that the termination date could be extended to March 2, 2006. Nevertheless, the loan would be due and payable if a spin-off of the shares of NEG were to occur. As a condition to exercise of each of the new one-year extensions, Parent is required to have reduced the loan balance by $308 million by March 2, 2002, pay a fee of three percent of the then-outstanding balance of the loans, and also issue to the lenders additional options equal to approximately one percent of the common stock of NEG. If Parent extends the term from March 1, 2003, using the initial extension, the fee will be two percent of the then-outstanding balances for each six-month period.
Further, as required by the credit agreement, NEG has granted to affiliates of the lenders options that entitle these affiliates to purchase up to 5 percent of the shares of the NEG at an exercise price of $1.00 based on the following schedule:
The option becomes exercisable on the date of full repayment or earlier, if an initial public offering of the shares of the NEG (“IPO”) were to occur. NEG has the right to call the option in cash at a purchase price equal to the fair market value of the underlying shares, which right is exercisable at any time following the repayment of the loans. If an IPO has not occurred, the holders of the option have the right to require NEG or Parent to repurchase the option at a purchase price equal to the fair market value of the underlying shares, which right is exercisable at any time after the earlier of full repayment of the loans or 45 days after the maturity of the loans. The fair value of the options granted are recorded as a debt issuance cost and amortized over the expected life of the loans. The options will be marked to market through an increase or decrease in earnings.
Under the credit agreement, NEG is permitted to make investments, incur indebtedness, sell assets, and operate its businesses pursuant to its business plan. Mandatory repayment of the loans will be required from the net after-tax proceeds received by NEG or any subsidiary of NEG from (1) the issuance of indebtedness, (2) the issuance or sale of any equity (except for cash proceeds from an IPO), (3) asset sales, and (4) casualty insurance, condemnation awards, or other recoveries. However, if such proceeds are retained as cash, used to pay indebtedness, or reinvested in NEG’s businesses, mandatory repayment will not be required.
The credit agreement contains certain covenants, including requirements that (1) the NEG’s unsecured long-term debt have a credit rating of at least BBB- by S&P or Baa3 by Moody’s, (2) the ratio of fair market value of NEG to the aggregate amount of principal then outstanding under the loans is not less than two to one, and (3) Parent maintains a cash or cash equivalent reserve of at least 15 percent of the total principal amount of the loans outstanding until March 2, 2004, and 10 percent thereafter, unless Parent prepays the interest attributable to the then applicable extension period. A breach of covenants entitles the lenders to declare the loans to be due and payable. In addition, failure of NEG to maintain at least a 1.25:1 ratio of fair market value to loan balance constitutes an immediate event of default and results in acceleration of the loan.
CPUC Proceedings and Litigation Involving PG&E Corporation
Our Parent and its subsidiaries, including us, 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 Parent’s exemption. At present, Parent has no expectation of becoming a registered holding company under PUHCA.
Although Parent 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 Pacific Gas and Electric Company (“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, recently has 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 Parent (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. Parent and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders.
On July 7, 2001, the AG filed a petition with the SEC requesting the SEC to review and revoke Parent’s exemption from PUHCA and to begin fully regulating the activities of Parent 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, Parent responded in detail to the AG’s petition demonstrating that Parent met the SEC’s criteria for the intrastate exemption. Parent further contended that registration would not have avoided the dysfunctional energy market in California or the distress of California’s largest utilities, which resulted from a variety of other factors, including rules preventing the Utility from passing power costs through to its customers. To date, the SEC has neither instituted an investigation nor ordered hearings regarding the matters raised in the AG’s petition.
On January 9, 2002, the CPUC voted in favor of 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.
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 could decide expeditiously whether adoption of the Utility’s proposed plan of reorganization would violate the first priority condition.
On January 10, 2002, the AG filed a complaint in the San Francisco Superior Court against Parent 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 ringfencing transactions by which NEG and its subsidiaries complied with credit rating agency criteria to establish independent credit ratings violated the holding company conditions. In a press release issued on January 10, 2002, the CPUC expressed support for the AG’s complaint, noting that the CPUC’s January 9, 2002 decision provided a basis for the AG’s allegations and that the CPUC intends to join in a lawsuit against Parent based on these issues. On February 15, 2002, a motion to dismiss the lawsuit or, in the alternative, to stay the suit was filed.
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 Parent, and alleged use of such money by Parent to subsidize other affiliates of Parent, violated various conditions established by the CPUC in decisions approving the holding company formation. The complaint also alleges that certain ring fencing transactions by which Parent’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, Parent 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. Parent believes that the allegations of the complaint are without merit and will vigorously respond to and defend the litigation.
Parent and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. Neither the Utility nor Parent 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 our results of operations or financial condition.
PART IV.
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
10.8*
Letter regarding retention award to Lyn E. Maddox dated February 27, 2001 (incorporated by reference to PG&E Corporation’s 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.12)
10.9*
Letter regarding retention award to P. Chrisman Iribe dated February 27, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.13)
10.10*
Letter regarding retention award to Thomas B. King dated February 27, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.14)
10.11.1
Letter regarding retention award to Stephen A. Herman dated February 27, 2001.
10.11.2
Letter regarding retention award to John Robert Cooper dated February 27, 2001.
10.12*
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2000 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.7)
10.14*
PG&E Corporation Long-Term Incentive Program, as amended May 16, 2001, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non-Employee Director Stock Incentive Plan.
10.15*
PG&E Corporation Executive Stock Ownership Program, amended as of September 19, 2000 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.20)
10.16*
PG&E Corporation Officer Severance Policy, amended as of July 21, 1999 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.1)
10.17*
PG&E Corporation Supplemental Retirement Savings Plan dated as of January 1, 2000 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2001 (File No. 1-12609), Exhibit 10.2)
10.18*
PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.2)
10.19*
Second Amended and Restated Wholesale Standard Offer Service Agreement between the Narragansett Electric Company and USGen New England, Inc., dated as of September 1, 1998.
10.20*
Second Amended and Restated Wholesale Standard Offer Service Agreement among Massachusetts Electric Company, Nantucket Electric Company and USGen New England, Inc., dated as of September 1, 1998.
10.21
Amended and Restated Credit Agreement among National Energy Group, Inc., the Chase Manhattan Bank and the other lenders party thereto dated as of August 22, 2001.
12.1
Statement re Computation of Ratios.
21.1
Subsidiaries of PG&E National Energy Group, Inc.
* 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.
The Company filed a Current Report on Form 8-K on November 30, 2001, disclosing the Company’s preliminary estimate of its financial exposure to Enron Corporation.
The Company filed a Current Report on Form 8-K on February 28, 2002, disclosing that certain synthetic lease financing arrangements entered into by the Company would be consolidated on the Company’s balance sheet and that the Company would reissue its consolidated financial statements for the quarter ending September 30, 2001.
Supplemental information to be furnished with the reports filed pursuant to Section 15(d) of theis 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, 2002
/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.
EXHIBIT INDEX
10.14*
PG&E Corporation Long-Term Incentive Program, as amended May 16, 2001, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non-Employee Director Stock Incentive Plan.
10.15*
PG&E Corporation Executive Stock Ownership Program, amended as of September 19, 2000 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.20)
10.16*
PG&E Corporation Officer Severance Policy, amended as of July 21, 1999 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.1)
10.17*
PG&E Corporation Supplemental Retirement Savings Plan dated as of January 1, 2000 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2001 (File No. 1-12609), Exhibit 10.2)
10.18*
PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.2)
10.19*
Second Amended and Restated Wholesale Standard Offer Service Agreement between the Narragansett Electric Company and USGen New England, Inc., dated as of September 1, 1998.
10.20*
Second Amended and Restated Wholesale Standard Offer Service Agreement among Massachusetts Electric Company, Nantucket Electric Company and USGen New England, Inc., dated as of September 1, 1998.
10.21
Amended and Restated Credit Agreement among National Energy Group, Inc., the Chase Manhattan Bank and the other lenders party thereto dated as of August 22, 2001.
12.1
Statement re Computation of Ratios.
21.1
Subsidiaries of PG&E National Energy Group, Inc.
* 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 NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2001, 2000, and 1999
(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.