ITEM 1. BUSINESS
GENERAL
We are a Delaware limited liability company with our principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. We and our three principal direct wholly-owned subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) were established to acquire, own and operate the electric generation-related business of our affiliate, Public Service Electric and Gas Company (PSE&G) pursuant to the Final Order issued by the New Jersey Board of Public Utilities (BPU), under the Energy Competition Act discussed below. We also have a finance company subsidiary, PSEG Power Capital Investment Company (Power Capital), which provides certain financing for our subsidiaries.
Unless the context otherwise indicates, all references to "Power," "we," "us" or "our" herein mean PSEG Power LLC, and its consolidated subsidiaries. (For periods prior to August 21, 2000, " Power," "we," "us" or "our" also includes PSE&G). We are a wholly-owned subsidiary of Public Service Enterprise Group Incorporated (PSEG). PSEG is an exempt public utility holding company under the Public Utility Holding Company Act (PUHCA). PSEG has three other direct, wholly-owned subsidiaries: PSE&G, PSEG Energy Holdings Inc. (Energy Holdings) and PSEG Services Corporation (Services). PSE&G is New Jersey's largest public utility and is engaged principally in the transmission, distribution and retail sale of electric energy and gas service in New Jersey. Energy Holdings participates nationally and internationally in energy-related lines of business through its subsidiaries. Services provides corporate support and managerial and administrative services to PSEG and its affiliates.
We are a multi-regional generating and energy trading company that integrates our generating asset operations with our wholesale energy, fuel supply, energy trading and risk management expertise. We currently have two reportable segments, generation and energy trading. The generation segment of our business earns revenues by selling energy on a wholesale basis under contract to our affiliate, PSE&G, and to other power marketers and load serving entities (LSE), and by bidding energy, capacity and ancillary services into the wholesale energy market. We have contracted to sell to BGS suppliers beginning August 1, 2002. The energy trading segment of our business earns revenues by trading energy, capacity, fixed transmission rights, fuel and emission allowances in the spot, forward and futures markets. The energy trading segment also earns revenues through financial transactions, including swaps, options and futures in the energy markets. Our target market, which is referred to herein as the Super Region, extends from Maine to the Carolinas and the Atlantic Coast to Indiana, encompassing 37% of the nation's power consumption. We are the single largest power supplier in our primary market, the Pennsylvania-New Jersey-Maryland Power Pool (PJM), which is one of the nation's largest and most well-developed energy markets.
Our generation portfolio consists of 11,487 megawatts (MW) of installed capacity, which is diversified by fuel source and market segment. In addition, we are currently constructing projects which will increase capacity by over 3,500 MW, net of planned retirements. For additional information, see Item 2
ITEM 2. PROPERTIES
We own or lease several other properties associated with our business activities. We sublease approximately 148,000 square feet of office space in an office tower and other office facilities in Newark, New Jersey. Other leased properties include an emergency media center (9,300 square feet) near Salem, which is designed as an information clearinghouse in the event of a nuclear emergency. We also lease approximately 19,600 square feet of space in the Hadley Road Training Center in South Plainfield, New Jersey from PSE&G. This space is used for fossil system maintenance, procurement and materials management staffs.
Through a subsidiary, we own a 57.41% interest in about 12,000 acres of restored wetlands and conservation facilities in the Delaware Estuary. This subsidiary was formed to acquire and own lands and other conservation facilities required to satisfy the condition of the NJPDES permit issued for the Salem Generating Station. We also own several other facilities including the on-site Nuclear Administration and Processing Center buildings.
We have an ownership interest in the 650-acre Merrill Creek Reservoir (Merrill Creek) in Warren County, New Jersey. The reservoir was constructed to store water for release to the Delaware River during periods of low flow. Merrill Creek is jointly owned by seven entities that have generation facilities along the Delaware River and use the river water in their operations. We also own the Maplewood Test Center in Maplewood, New Jersey and the Central Maintenance Shop at Sewaren, New Jersey.
INSURANCE
We carry insurance coverage consistent with companies engaged in similar commercial operation with similar properties. Our insurance coverage includes risk insurance as well as commercial general public liability insurance, covering liabilities to third parties for bodily injury and property damage resulting from our operations; automobile liability insurance, for all owned, non-owned and hired vehicles, covering liabilities to third parties for bodily injury and property damage, and all risk property insurance, covering the replacement value of all real and personal property, including coverage for boiler and machinery breakdowns and earthquake and flood damage, subject to certain sublimits. We also maintain substantial excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits and deductibles are comparable to those carried by other electric generation companies of similar size. For a discussion of liability and other insurance related to our nuclear generation facilities, see Risk Factors and Note 5. - Commitments and Contingent Liabilities.
The following table provides summary profiles of our fossil and nuclear generation stations and the units that comprise them:
(A) Our share of jointly owned facility.
(B) Operated by Reliant Energy
(C) Operated by Exelon
(D) Operated by Jersey Central Power & Light
(E) Excludes energy for pumping and synchronous condensers.
(F) These assets are scheduled for retirement within the next five years, partially dependent upon new generation going into service discussed below.
As of December 31, 2001, we had 3,764 MW of generating capacity in construction, as shown in the following table:
As of December 31, 2001, we had 900 MW of generating capacity in advanced development, as shown in the following table:
TOTAL CAPACITY PROJECTED CAPACITY (MW) - ------------------------------------------- -------------- Total Owned Operating Generating Plants 11,487 - ------------------------------------------- Under Construction 3,764 Advanced Development 900 Less: Planned Retirements (1,253) -------------- Projected Capacity 14,898 ==============
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
See information on the following proceedings at the pages indicated:
(1) Pages 9 and 47. Proceedings before the BPU in the matter of the Energy Master Plan Phase II Proceeding to investigate the future structure of the Electric Power Industry, Docket Nos. EX94120585Y, EO97070461, EO97070462, EO97070463, and EX01050303.
(2) Pages 15 and 16. Administrative proceedings before the NJDEP under the FWPCA for certain electric generating stations.
(3) Page 18. DOE Overcharges, Docket No. 01-592C.
(4) Pages 17 and 18. DOE not taking possession of spent nuclear fuel, Docket No. 01-551C.
(5) Pages 17 and 52. Investigation and additional investigation by the EPA regarding the Passaic River site, Docket No. EX93060255.
We are involved in the following environmental related matters involving governmental authorities. Based on current information, we do not expect expenditures for any such site, individually or all such current sites in the aggregate, to have a material effect on their financial condition, results of operations and net cash flows.
(1) Claim made in 1985 by U.S. Department of the Interior under CERCLA with respect to the Pennsylvania Avenue and Fountain Avenue municipal landfills in Brooklyn, New York, for damages to natural resources. The U.S. Government alleges damages of approximately $200 million. To our knowledge there has been no action on this matter since 1988.
(2) Duane Marine Salvage Corporation Superfund Site is in Perth Amboy, Middlesex County, New Jersey. The EPA had named PSE&G as one of several potentially responsible parties (PRPs) through a series of administrative orders between December 1984 and March 1985. Following work performed by the PRPs, the EPA declared on May 20, 1987 that all of its administrative orders had been satisfied. The NJDEP, however, named us as a PRP and issued its own directive dated October 21, 1987. Remediation is currently ongoing.
(3) Various Spill Act directives were issued by NJDEP to PRPs, including us with respect to the PJP Landfill in Jersey City, Hudson County, New Jersey, ordering payment of costs associated with operating and maintenance expenses, interim remedial measures and a Remedial Investigation and Feasibility Study (RI/FS) in excess of $25 million. The directives also sought reimbursement of NJDEP's past and future oversight costs and the costs of any future remedial action.
(4) In 1991, the NJDEP issued Directive and Notice to Insurers Number Two (Directive Two) to 24 Insurers and 52 Respondents, including PSE&G, in connection with an investigation and remediation of the Global Landfill Site in Old Bridge Township, Middlesex County, New Jersey seeking recovery of past and anticipated future NJDEP response costs ($37 million). We and other participating PRPs have agreed with NJDEP to a partial settlement of such costs and to perform the remedial design and remedial action. In 1996, 13 of the Directive Two Respondents, including PSE&G, filed a contribution action pursuant to CERCLA and the Spill Act against approximately 190 parties seeking contribution for an equitable share of all liability for response costs incurred and to be incurred in connection with the site. In September 1997, the NJDEP issued a Superfund record of decision with estimated cost of $3.7 million. The Directive Two Respondents' foregoing contribution claims have been resolved by settlement.
(5) The NJDEP assumed control of a former petroleum products blending and mixing operation and waste oil recycling facility in Elizabeth, Union County, New Jersey (Borne Chemical Co. site) and issued various directives to a number of entities including our requiring performance of various remedial actions. Our nexus to the site is based upon the shipment of certain waste oils to the site for recycling. We and certain of the other entities named in NJDEP directives are members of a PRP group that have been working together to satisfy NJDEP requirements including: funding of the site security program, containerized waste removal, and a site remedial investigation program.
(6) The New York State Department of Environmental Conservation (NYSDEC) has named PSE&G as one of many potentially responsible parties for contamination existing at the former Quanta Resources Site in Long Island City, New York. Waste oil storage, processing, management and disposal activities were conducted at the site from approximately 1960 to 1981. It is believed that waste oil from our facilities were taken to the Quanta Resources Site. NYSDEC has requested that the potentially responsible parties reimburse the state for the costs NYSDEC has expended at the site and to conduct an investigation and remediation of the site. Power, PSE&G and the other PRPs are negotiating with NYSDEC the terms of an agreement that will set forth these requirements, and are negotiating among themselves an agreement for the sharing of the associated costs.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
PART II -------
ITEM 5.
ITEM 5. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All of our outstanding limited liability company membership interests are owned by PSEG.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth our summary selected historical consolidated financial data. The historical consolidated financial data as of December 31, 2001 and 2000 and for the three years ended December 31, 2001 have been derived from our audited financial statements included herein. The historical consolidated financial data as of December 31, 1999, 1998 and 1997 and for the two years ended December 1998, has been derived from audited financial statements not included herein. The information set forth below should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) and the Consolidated Financial Statements and accompanying Notes to Consolidated Financial Statements. Data related to periods prior to August 2000 have been derived from PSE&G's financial statements and are not necessarily indicative of the financial condition, results of operations or net cash flows that would have existed had PSE&G's generation-related business been an independent company during those periods.
- -------------------------------------------------------------------------------- (1) Primarily consisting of the write-down of our generating stations (see Note 3. Regulatory Issues and Accounting Impacts of Deregulation) (2) Includes notes payable to an affiliated company in the year 2000. (3) Earnings before Interest, Taxes, Depreciation and Amortization. Information concerning EBITDA is presented here not as a measure of operating results, rather as a measure of ability to service debt. In addition, EBITDA may not be comparable to similarly titled measures by other companies. EBITDA should not be construed as an alternative to operating income or cash flow from operating activities, each as determined according to generally accepted accounting principles. Although we are not required to meet minimum EBITDA to interest charges tests as part of our debt covenants, we use these measures in our financial and business planning process to provide reasonable assurance that our forecasts will provide adequate interest coverage to maintain or improve our target credit ratings.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CORPORATE STRUCTURE
We were formed in June 1999 to acquire, own and operate the electric generation-related assets of PSE&G pursuant to the Final Order issued by the BPU under the New Jersey Energy Master Plan (Energy Master Plan Proceedings) and the New Jersey Electric Discount and Energy Competition Act (Energy Competition Act). We have three principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T) and currently operate in two reportable segments, generation and trading. The generation segment of our business earns revenues by selling energy on a wholesale basis under contract to power marketers and to load serving entities, and by bidding energy, capacity and ancillary services into the market. The energy trading segment of our business earns revenues by trading energy, capacity, fixed transmission rights, fuel and emission allowances in the spot, forward and futures markets. The trading segment also earns revenues through financial transactions, including swaps, options and futures in the electricity and gas markets. We also have a finance company subsidiary, PSEG Power Capital Investment Co. (Power Capital), which provides certain financing for our other subsidiaries.
OVERVIEW OF 2001 AND FUTURE OUTLOOK
We currently operate as an independent power generation and wholesale marketing and trading company in the eastern United States. As of December 31, 2001, we own 11,487 MW of generation capacity. We are currently constructing projects which will increase capacity by over 3,500 MW, net of planned retirements. We derive our revenue and cash flows principally from our electric generation business, energy trading and related activities.
The regulatory structure that has historically governed the electric power industry in the United States and in many of the states is in transition. Recent federal and state legislative and regulatory initiatives have been designed to promote competition in the electric power industry. Deregulation is underway throughout the United States and is at a relatively advanced stage in the Northeast, where most of the markets in which we compete are located. The resulting restructuring of energy markets provides us with new opportunities and exposes us to new risks.
In August 1999, following the enactment of the New Jersey Electric Discount and Energy Competition Act, the BPU rendered its Final Order relating to PSE&G's rate unbundling, stranded costs and restructuring proceedings providing, among other things, for the transfer to us of all of PSE&G's electric generation facilities, plant and equipment for $2.443 billion and all other related property, including materials, supplies and fuel at the net book value thereof, together with associated rights and liabilities. PSE&G transferred its electric generating business to us in August 2000 in exchange for a $2.786 billion promissory note, which we repaid on January 31, 2001.
Prior to the issuance of the Final Order, substantially all of the output of PSE&G's electric generation assets was sold to PSE&G's retail customers. To ensure that PSE&G's retail customers who choose not to select or who are not otherwise served by a different supplier continue to receive energy services, the Final Order also requires PSE&G to provide Basic Generation Service (BGS) to its customers through July 31, 2002. PSE&G has entered into a contract with us to supply the energy, capacity and ancillary services required to meet this obligation. As a result, since August 1, 1999, we have been selling substantially all of our output to PSE&G and will continue to do so until July 31, 2002. We currently sell approximately 95% of the output from our generation facilities under bilateral contracts, primarily the BGS contract with PSE&G, and the remaining 5% to customers in the competitive wholesale (spot) market. Within the spot market, we sell into the energy, capacity and ancillary services markets. Ancillary services include operating reserves and area regulation. We have entered into one-year contracts commencing August 1, 2002 with various direct bidders in the New Jersey BGS Auction, which was approved by the BPU on February 15, 2002. We believe that our obligations under these contracts are reasonably balanced by our available supply.
Under the BGS contract, we charge the BGS retail tariff rate on file with the BPU. In addition, PSE&G pays us a price stability charge to compensate us for ensuring the reliability of BGS service and assuming the risk of price volatility. The price stability charge is equal to the full amount collected by PSE&G for its unsecuritized generation-related stranded costs up to $540 million after tax on a net present value basis. The Final Order also provides that rate reductions of up to 13.9% be phased in by PSE&G to its retail customers through August 1, 2002. To date, 9% of rate reductions have been phased in and additional 4.9% will be phased in beginning August 10, 2002. These rate reductions are reflected in the Market Transition Charge (MTC) rate that PSE&G remits to us as part of the BGS contract as provided for by the Final Order.
On January 9, 2002, the BPU approved the transfer of PSE&G's gas supply business, including its transportation and storage contracts to us. As a result, after April 1, 2002, we will provide gas supply to PSE&G to serve its Basic Gas Supply Service (BGSS) customers under a Requirements Contract at market prices.
We are focused on a generation market extending from Maine to the Carolinas and the Atlantic Coast to Indiana (Super Region). The risks of our business are that the competitive wholesale power prices that we are able to obtain are sufficient to provide a profit and sustain the value of its assets. It is also subject to credit risk of the counterparties to whom we sell energy products, the successful operation of our generating facilities, fluctuations in market prices of energy and imbalances between obligations and available supply. These risks are higher than those for a regulated business. Therefore, they provide the opportunity for greater returns, but they also present the greater possibility of business losses and counterparty credit risk.
In addition, we anticipate that we will continue our strong growth in our energy trading segment. In 2001, the energy trading business realized a gross margin of $140 million and forecasts an improvement for 2002, driven in part by the transfer of PSE&G's gas supply business to us, discussed below. We marked to market energy trading contracts with gains and losses included in earnings. The vast majority of these contracts have terms of less than one year and are valued using market exchange prices and broker quotes. The energy trading business provides the opportunity for greater returns and can be adversely impacted by fluctuating energy market prices and by the credit quality of the counterparties with which it does business. Our trading business utilizes a conservative risk management strategy to minimize exposure to long-term and short-term market risk. For further information, see Accounting Issues, Note 1. Organization and Summary of Significant Accounting Policies and Note 4. Financial Instruments, Energy Trading and Risk Management.
Our earnings are exposed to the risks of the competitive wholesale electricity market to the extent that we have to purchase energy and/or capacity or generate energy to meet our fixed price obligations at market prices or costs, respectively, which approach or exceed the stated rates in their long-term supply contracts, such as the BGS contract. To mitigate this risk, our policy is to use derivatives, consistent with our business plans and prudent practices and to build and purchase additional capacity in the PJM and surrounding regions.
RESULTS OF OPERATIONS
Our business consists of two reportable segments which are Generation and Energy Trading. The following is a discussion of the major year-to-year financial statement variances and follows the financial statement presentation as it relates to each of our segments. For a discussion of management's determination of our reportable segments and related disclosures, see Note 9. Financial Reporting by Business Segments. For a discussion of these assumptions and the methodologies used to prepare our financial statements prior to August 2001, see Note 1. - Organization, Basis of Presentation and Summary of Significant Accounting Policies
Prior to April 1999, the discussion that follows reports on business conducted under full monopoly regulation of the utility businesses. It must be understood that such businesses have changed due to the deregulation of the electric generation and natural gas commodity sales businesses, the subsequent transfer of the generation business, and the anticipated transfer of the gas supply business from PSE&G to us. Past results are not an indication of future business prospects or financial results.
RESULTS OF OPERATIONS -- FOR THE YEAR ENDED DECEMBER 31, 2001 COMPARED TO THE YEAR ENDED DECEMBER 31, 2000
Our earnings for the year ended December 31, 2001 increased $81 million from the comparable 2000 period. This increase primarily resulted from the effects of increased BGS sales volumes due to customers returning to PSE&G in 2001 from third party suppliers (TPS) and increased trading margins. This was offset by lower revenues resulting from two 2% rate reductions totaling $100 million as part of PSE&G's deregulation plan and a $52 million increase in Operation and Maintenance expense.
OPERATING REVENUES
GENERATION
Revenues from our generation segment increased $108 million in 2001 as compared to 2000 primarily due to an increase of $180 million in BGS revenue for the year ended December 31, 2001 as compared to 2000 which resulted from customers returning to PSE&G in 2001 from TPS as wholesale market prices exceeded fixed BGS rates. At December 31, 2001, TPS were serving less than 1% of the customer load traditionally served by PSE&G as compared to the December 31, 2000 level of 10.5%. Partially offsetting this increase was a net $40 million decrease in MTC revenues, relating to two 2% rate reductions offset by a pre-tax charge to income related to MTC recovery in 2000. As of December 31, 2001, as required by the Final Order, PSE&G has had rate reductions totaling 9% since August 1, 1999 and will have an additional 4.9% rate reduction effective August 1, 2002, which will be in effect until July 31, 2003.
ENERGY TRADING
Revenues from our energy trading segment decreased by $321 million or 12% for the year ended December 31, 2001 from the comparable period in 2000, due to lower energy trading volumes and lower prices as compared to 2000. For information regarding valuation, term, credit and other issues related to our energy trading segment, see Accounting Issues, Note 1. Organization and Summary of Significant Accounting Policies and Note 4 - Financial Instruments, Energy Trading and Risk Management.
OPERATING EXPENSES
ENERGY COSTS
Energy Costs increased $97 million or 13% for the year ended December 31, 2001 from the comparable period in 2000, primarily due to increased load served under the BGS contract and higher fuel costs for fossil generation resulting from higher natural gas prices, partially offset by increased low-cost nuclear generation compared to 2000.
TRADING COSTS
Trading Costs decreased $391 million or 15% year ended December 31, 2001 from the comparable period in 2000, primarily due to lower trading volumes and lower prices as compared to 2000.
OPERATION AND MAINTENANCE
Operation and Maintenance expense increased $52 million or 8% for year ended December 31, 2001, primarily due to planned generation outage work in the first quarter of 2001 and higher expenses relating to projects going into operation during the second quarter of 2000 for our generation segment.
DEPRECIATION AND AMORTIZATION
Depreciation and Amortization expense decreased $41 million or 30% for the year ended December 31, 2001 from the comparable period in 2000. The decrease was primarily due to a reduction in the accrual for the estimated cost of removal of our generating stations.
INTEREST EXPENSE
Interest Expense decreased $55 million or 28% for the year ended December 31, 2001 from the comparable period in 2000 primarily due to the repayment of the $2.786 billion 14.23% promissory note to PSE&G, issued in August 2000,
used to finance the acquisition of PSE&G's generation business. This loan was repaid on January 31, 2001 and was replaced on an interim basis by loans of $1.084 billion at 14.23% and $536 million at 7.11% from PSE&G from January 2001 to April 2001. These loans were repaid with the proceeds of the $1.8 billion Senior Notes issued in April 2001.
RESULTS OF OPERATIONS -- FOR THE YEAR ENDED DECEMBER 31, 2000 COMPARED TO THE YEAR ENDED DECEMBER 31, 1999
Excluding an extraordinary charge of $3.204 billion related to the deregulation of the energy industry, our earnings for the year ended December 31, 2000 decreased $200 million from the comparable 1999 period. This decrease primarily resulted from the effects of the 5% rate reduction which commenced on August 1, 1999 and a $115 million reduction in MTC revenues which resulted from a cumulative effect of estimated collections in excess of the allowed unsecuritized stranded costs from August 1, 1999 through December 31, 2000. Also contributing to this decrease was higher interest expense associated with the $2.786 billion promissory note to PSE&G.
OPERATING REVENUES
GENERATION
Generation revenues decreased $449 million or 17% for the year ended December 31, 2000 from the comparable period in 1999 primarily due to the 5% rate reduction, which decreased revenues by approximately $120 million, a $115 million deferral of MTC revenues and reduced retail demand as PSE&G lost retail customers to TPS which resulted in an approximately $182 million decrease in generation revenues.
TRADING
Trading revenues increased $882 million or 48% for the year ended December 31, 2000 from the comparable period in 1999 primarily due to increased trading volumes and higher trading prices. These increased revenues were largely offset by the related increase in trading costs discussed below.
OPERATING EXPENSES
ENERGY COSTS
Energy Costs decreased $85 million or 10% for the year ended December 31, 2000 from the comparable 1999 period due to lower prices for power purchases beginning in August 1999 and lower generation costs that were a result of high capacity factors of our nuclear units. Prior to August 1999, Energy Costs included amounts paid under various non-utility generation (NUG) contracts which are at or above market prices. Since August 1999, PSE&G has purchased the energy and capacity under these NUG contracts and sells the energy and capacity to us at market prices.
TRADING COSTS
Trading Costs increased $847 million or 47% for the year ended December 31, 2000 from the comparable 1999 period primarily due to higher trading costs associated with increased trading volumes and higher prices.
DEPRECIATION AND AMORTIZATION
Depreciation and Amortization expense decreased $88 million or 39% for the year ended December 31, 2000 from the comparable 1999 period. The decrease was primarily due to lower net book value balances of PSE&G's generation-related assets that were reduced as of April 1, 1999 as a result of the impairment recorded pursuant to SFAS 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121). For a discussion of Depreciation policies and methods, See Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies and Note 2. Accounting Matters, respectively.
INTEREST EXPENSE
Interest Expense increased $86 million or 77% for the year ended December 31, 2000 from the comparable 1999 period. Prior to the generation business transfer in August 2000, Our Interest Expense was calculated based upon an allocation methodology that charged us with financing from PSE&G in proportion to our share of total net property, plant and
equipment. Following the transfer of the generation business in August 2000, we paid interest on our $2.786 billion promissory note to PSE&G at an annual rate of 14.23%. This rate represented PSE&G's weighted average cost of capital.
LIQUIDITY AND CAPITAL RESOURCES
Our capital requirements and those of our subsidiaries are met and liquidity provided by internally generated cash flow and external financings. From time to time, we make equity contributions to our direct and indirect subsidiaries to provide for part of their capital and cash requirements, generally relating to long-term investments. At times, we utilize inter-company dividends and inter-company loans to satisfy various subsidiary needs and efficiently manage our and our subsidiaries' short-term cash needs. Any excess funds are invested in accordance with guidelines adopted by our Board of Directors.
External funding to meet the majority of our requirements is comprised of corporate finance transactions. The debt incurred is our direct obligation. Some of the proceeds of these debt transactions are used by us to make equity investments in our subsidiaries. External funding is also provided through PSEG which may use proceeds of its financing transactions to make equity contributions or loans to us.
All of our publicly traded debt has received investment grade ratings from each of the three major credit rating agencies. The changes in the energy industry and the recent bankruptcy of Enron Corp. are attracting increased attention from the rating agencies which regularly assess business and financial matters. Given the changes in the industry, attention to and scrutiny of our performance, capital structure and competitive strategies by rating agencies will likely continue. These changes could affect the bond ratings, cost of capital and market prices of our securities. We will continue to evaluate our capital structure, financing requirements, competitive strategies and future capital expenditures with a goal of maintaining our current credit ratings.
The current ratings of our securities are shown below and reflect the respective views of the rating agencies, from whom an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time or that they will not be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely effect the market price of our securities and serve to increase our cost of capital.
POWER MOODY'S STANDARD & POOR'S FITCH - -------------------------------------------------------------------------------- Senior Notes Baa1 BBB BBB+
The availability and cost of external capital could be affected by our performance as well as by the performance of PSEG and its subsidiaries and affiliates. This could include the degree of structural or regulatory separation between us and our subsidiaries and affiliates and the potential impact of affiliate ratings on our credit quality. Additionally, compliance with applicable financial covenants will depend upon future financial position and levels of earnings and net cash flows, as to which no assurances can be given.
Financing for two of our projects under construction in Lawrenceburg, Indiana and Waterford, Ohio has been provided by non-recourse project financing transactions. These consist of loans from banks and other lenders that are secured by the project and the special purpose subsidiary assets and/or cash flows. Non-recourse transactions generally impose no obligation on the parent-level investor to repay any debt incurred by the project borrower. However, in some cases, certain obligations relating to the investment being financed, including additional equity commitments, are supported by us. Further, the consequences of permitting a project-level default include loss of any invested equity by the parent.
Our debt indenture and the credit agreements of our Lawrenceburg and Waterford subsidiaries contain cross-default provisions under which a default by us involving specified levels of indebtedness in other agreements would result in a default and the potential acceleration of payment under such indenture and credit agreements. For example, a default for a specified amount with respect to specified indebtedness, as set forth in the credit agreements, including our obligations in subsidiaries' non-recourse transactions, could cause a cross-default in our indenture or our subsidiaries' credit agreements.
Such lenders, or the debt holders under our indenture, could determine that debt payment obligations may be accelerated as a result of a cross-default. These occurrences could severely limit our liquidity and restrict our ability to meet our debt, capital and, in extreme cases, operational cash requirements. Any inability to satisfy required covenants and/or borrowing conditions would have a similar impact. This would have a material adverse effect on our financial condition, results of operations and net cash flows, and those of our subsidiaries.
In addition, the credit agreements of PSEG and our Lawrenceburg and Waterford subsidiaries generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower's, and as may be relevant, our business or financial condition. In the event that PSEG, we or the lenders in any of these credit agreements determine that a material adverse change has occurred, loan funds may not be advanced.
PSEG's credit agreements also contain maximum debt to equity ratios and other covenants and conditions to borrowing. Compliance with applicable financial covenants will depend upon PSEG's future financial position and the level of earnings and cash flow, as to which no assurances can be given. As part of PSEG's financial planning forecast, it performs stress tests on its financial covenants. These tests include a consideration of the impacts of potential asset impairments, and other items. PSEG's current analyses and projections indicate that PSEG will be able to meet its financial covenants.
Our debt indenture and such credit agreements do not contain any material "ratings triggers" that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, we and PSEG may be subject to increased interest costs on certain bank debt. Also, in connection with our energy trading business, we must meet certain credit quality standards as are required by counterparties. If we lose our investment grade credit rating, ER&T would have to provide credit support (letters of credit or cash), which would significantly impact our energy trading business. These same contracts provide reciprocal benefits to us. This would increase our costs of doing business and limit our ability to successfully conduct our energy trading operations. In addition, our counterparties may require us to meet margin or other security requirements which may include cash payments.
In addition, if PSEG were no longer to be exempt under the Public Utility Holding Company Act of 1935 (PUHCA), PSEG and its subsidiaries, including us, would be subject to additional regulation by the SEC with respect to financing and investing activities, including the amount and type of non-utility investments. We believe that this would not have a material adverse effect on our financial condition, results of operations and net cash flows.
Over the next several years, we and our Lawrenceburg and Waterford subsidiaries and PSEG will be required to refinance maturing debt, incur additional debt and/or provide equity to fund investment activity. Any inability to obtain required additional external capital or to extend or replace maturing debt and/or existing agreements at current levels and reasonable interest rates may affect our financial condition, results of operations and net cash flows.
Our short-term financing needs will be met using PSEG's commercial paper program or lines of credit. On September 8, 1999, PSEG entered into an uncommitted line of credit with a bank with no stated limit. At December 31, 2001, PSEG had $153 million outstanding under this line of credit. PSEG also has an $850 million commercial paper program to provide funds for general corporate purposes. On December 31, 2001, $475 million of commercial paper was outstanding. To provide liquidity for its commercial paper program, PSEG has the following revolving credit facilities with a group of banks which provide for borrowings with maturities of up to one year:
As of December 31, 2001, letters of credit were issued in the amount of approximately $100 million.
In April 2001, we issued $500 million of 6.875% Senior Notes due 2006, $800 million of 7.75% Senior Notes due 2011 and $500 million of 8.625% Senior Notes due 2031. The net proceeds from the sale of the senior notes were used primarily for the repayment of loans to PSEG.
In August 2001, two of our subsidiaries closed on $800 million of non-recourse project bank financing for projects in Waterford, Ohio and Lawrenceburg, Indiana. The total combined project cost for Waterford and Lawrenceburg is estimated at $1.2 billion. Our required estimated equity investment in these projects is approximately $400 million. In connection with these projects, ER&T has entered into a five-year tolling agreement pursuant to which it is obligated to purchase the output of these facilities at stated prices. As a result, ER&T will bear the price risk related to the output of these generation facilities, which are scheduled to be completed in 2003.
In the fourth quarter of 2001, we issued $124 million of Pollution Control Notes.
CAPITAL REQUIREMENTS
We have substantial commitments as part of our growth strategy and ongoing construction programs. We expect that the majority of our capital requirements over the next five years will come from internally generated funds, with the balance to be provided by the issuance of debt at the subsidiary or project level and equity contributions from PSEG.
For the years ended December 31, 2001 and 2000, we had net plant additions of $1.5 billion and $479 million, respectively, excluding capitalized interest. The majority of these additions are related to developing the Lawrenceburg, Indiana and the Waterford, Ohio sites and adding capacity to the Bergen, Linden, Burlington and Kearny stations in New Jersey.
FORECASTED EXPENDITURES - -----------------------
Projected construction and investment expenditures for our subsidiaries for the next five years are as follows:
2002 2003 2004 2005 2006 ---- ---- ---- ---- ---- (Millions of Dollars) $ 960 $ 700 $ 340 $ 250 $ 230
The expenditures in 2001 and future projections are primarily for developing the Lawrenceburg, Indiana site and the Waterford, Ohio site and increasing capacity to the Bergen, Linden, Burlington and Kearny stations in New Jersey. Our settlement with federal and state governments for PSD/NSR regulations required approximately $337 million of capital expenses through 2010 is also included in the forecasts. For a discussion of new generation and development including our development of the Bethlehem Energy Center, Bergen Generating Station, Waterford and Lawrenceburg projects and other commitments to purchase equipment and services, all of which are included in our forecasts above, see Note 5. Commitments and Contingent Liabilities.
Our capital needs will be dictated by our strategy to continue to develop as a profitable, growth-oriented supplier in the wholesale power market. We will size our fleet of generation assets to take advantage of market opportunities, while seeking to increase our value and manage commodity price risk through our wholesale energy trading activity. A significant portion of our projected investment expenditures in the latter part of this forecast are not yet committed to specific projects.
Factors affecting actual expenditures and investments, including ongoing construction programs, include: availability of capital, suitable investment opportunities, prices of energy and supply in markets in which we participate, economic and political trends, revised load forecasts, business strategies, site changes, cost escalations under construction contracts, and requirements of regulatory authorities and laws.
We have guaranteed certain obligations of affiliates, including the successful completion, performance or other obligations and have contract equity contribution obligations related to certain projects in an aggregate amount of approximately $500 million, as of December 31, 2001. A substantial portion of such guarantees is eliminated upon successful completion, performance and/or refinancing of construction debt with non-recourse project term debt.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The market risk inherent in our market risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices and interest rates as discussed in the notes to the financial statements. Our policy is to use derivatives to manage risk consistent with our business plans and prudent practices. We have a Risk Management Committee comprised of executive officers which utilizes an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices.
Counterparties expose us to credit losses in the event of non-performance or non-payment. We have a credit management process which is used to assess, monitor and mitigate counterparty exposure for us and our subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our and our subsidiaries' financial condition, results of operations or net cash flows.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
COMMODITY CONTRACTS
The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies and other events. To reduce price risk caused by market fluctuations, we enter into derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge our anticipated demand. These contracts, in conjunction with owned electric generation capacity, are designed to cover estimated electric customer commitments.
During 2001, we entered into electric physical forward contracts and gas futures and swaps to hedge our forecasted BGS requirements and gas purchases requirements for generation. These transactions qualified for hedge accounting treatment under SFAS 133 and were settled prior to the end of 2001. Marked-to-market valuations were reclassified from Other Comprehensive Income (OCI) to earnings during the third quarter ended September 30, 2001. As of December 31, 2001, we did not have any outstanding derivatives accounted for under this methodology. However, there was substantial activity during the year ended December 31, 2001. In 2001, the values of these forward contracts, gas futures and swaps as of June 30 and September 30 were $(34.2) million and $(0.4) million.
We use a value-at-risk (VAR) model to assess the market risk of our commodity business. This model includes fixed price sales commitments, owned generation, native load requirements, physical contracts and financial derivative instruments. VAR represents the potential gains or losses for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. PSEG estimates VAR across its commodity business using a model with historical volatilities and correlations.
The Risk Management Committee (RMC) established a VAR threshold of $25 million. If this threshold was reached, the RMC would be notified and the portfolio would be closely monitored to reduce risk and potential adverse movements. In anticipation of the completion of the current BGS contract with PSE&G on July 31, 2002, the VAR threshold was increased to $75 million.
The measured VAR using a variance/co-variance model with a 95% confidence level and assuming a one-week time horizon as of December 31, 2001 was approximately $14 million, compared to the December 31, 2000 level of $19 million. This estimate was driven by A conservative assumption that we would enter into contracts for approximately 50% of its generating capacity during the BGS auction. Since we obtained contracts in excess of this amount, the VAR at December 31, 2001 would have been even lower. This estimate, however, is not necessarily indicative of actual results, which may differ due to the fact that actual market rate fluctuations may differ from forecasted fluctuations and due to the fact that the portfolio of hedging instruments may change over the holding period and due to certain assumptions embedded in the calculation.
Given the absence of a PJM price cap in situations involving emergency purchases and the potential for plant outages, extreme price movements, which have occurred, could have a material adverse impact on our financial condition, results of operations and net cash flows.
INTEREST RATE SWAPS
In October 2001, we entered into three interest rate swaps with an aggregate notional amount of $177.5 million to hedge the variability of interest payments related to the construction on our Waterford, Ohio facility. The swaps qualify for hedge accounting treatment under SFAS 133. As of December 31, 2001, the related fair value of $2.3 million was recorded on the balance sheet and the effective portion of the swaps was recorded in OCI. Management expects to amortize approximately $1.9 million (net of tax of $1.3) from OCI to earnings during the next 12 months. As of December 31, 2001, there was $1.3 million remaining in the OCI account.
In February 2001, we entered into various forward-interest rate swaps, with an aggregate notional amount of $400 million, to hedge the interest rate risk related to the anticipated issuance of debt. These fixed swaps paid a fixed rate of 6%, received 3-month LIBOR, with a maturity date of August 14, 2011. The original effective date of the swaps was August 14, 2001. On April 11, 2001, we issued $1.8 billion in fixed-rate Senior Notes and closed out the forward starting interest rate swaps. The aggregate loss, net of tax, of $3.2 million was classified as Accumulated Other Comprehensive Loss and is being amortized and charged to interest expense over the life of the debt. During the year ended December 31, 2001, approximately $0.6 million was reclassified from OCI to earnings. Management expects to amortize approximately $0.8 million (net of tax of $0.3) from OCI to earnings during the next twelve months. As of December 31, 2001, there was $2.8 million remaining in the OCI account.
CREDIT RISK
Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties, pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize our exposure to credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which may allow for the netting of positive and negative exposures associated with a single counterparty. We also established credit reserves for our energy trading contracts based on various factors, including individual counterparty's position, credit rating, default possibility and recovery rates.
As a result of the BGS auction, we have contracted to provide generating capacity to the direct suppliers of the four New Jersey electric utilities, including PSE&G, commencing August 1, 2002. These bilateral contracts are subject to credit risk. This credit risk relates to the ability of counterparties to meet their payment obligations for the power delivered under each BGS contract. This risk is substantially higher than the risk associated with potential nonpayment by PSE&G under the BGS contract expiring July 31, 2002. Any failure to collect these payments under the new BGS contracts could have a material impact on our results of operations, cash flows, and financial position.
In December 2001, Enron Corp. (Enron) filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We entered into a variety of energy trading contracts with Enron in the PJM area as part of our energy trading activities. With the first signs of Enron's financial problems, we took steps to mitigate our exposure to both Enron and other counterparties who had significant exposures with Enron. As of December 31, 2001, we owed Enron approximately $23 million, net, and Enron held a letter of credit from us for approximately $40 million.
Two major California utilities, including Pacific Gas & Electric Company (PG&E), have significantly underrecovered from customers costs paid for power. As a consequence, these utilities have defaulted under a variety of contractual obligations and on April 6, 2001, PG&E filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Affiliates of these California utilities have entered into physical forward and swap contracts with us for delivery in PJM. These counterparties have met their obligations to date and are still investment grade entities. We have entered into a limited number of additional contracts since May 2001 with one of these counterparties, but no additional contracts have been entered into with the other counterparty since December 2000. Our exposure to these entities under these contracts is not material and management does not believe that a specific reserve related to receivables for these counterparties is presently necessary.
ACCOUNTING ISSUES
CRITICAL ACCOUNTING POLICIES AND OTHER ACCOUNTING MATTERS
Our most critical accounting policies include the application of: Emerging Issues Task Force (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10) and EITF 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent" (EITF 99-19), for our Energy Trading business; and SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended (SFAS 133), to account for our various hedging transactions.
ACCOUNTING, VALUATION AND PRESENTATION OF OUR ENERGY TRADING BUSINESS
ACCOUNTING - We account for our energy trading business in accordance with the provisions of EITF 98-10, which requires that energy trading contracts be marked to market with gains and losses included in current earnings.
VALUATION - Since the vast majority of our energy trading contracts have terms of less than one year, valuations for these contracts are readily obtainable from the market exchanges, such as PJM, and over the counter quotations. The valuations also include a credit reserve and a liquidity reserve, which is determined using financial quotation systems, monthly bid-ask prices and spread percentages. We have consistently applied this valuation methodology for each reporting period presented. The fair values of these contracts and a more detailed discussion of credit risk are reflected in Note 4 - - Financial Instruments, Energy Trading and Risk Management.
PRESENTATION - EITF 99-19 provided guidance on the issue of whether a company should report revenue based on the gross amount billed to the customer or the net amount retained. The guidance states that whether a company should recognize revenue based on the gross amount billed or the net retained requires significant judgment, which depends on the relevant facts and circumstances. Based on the analysis and interpretation of EITF 99-19, we report all of the energy trading revenues and energy trading-related costs on a gross basis for physical bilateral energy and capacity sales and purchases. We report swaps, futures, option premiums, firm transmission rights, transmission congestion credits, and purchases and sales of emission allowances on a net basis. The prior year financial statements have been reclassified accordingly. One of the primary drivers of our determination that these contracts should be presented on a gross basis was that we retain counterparty risk.
SFAS 133 - ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
SFAS 133 established accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize the fair value of derivative instruments held as assets or liabilities on the balance sheet. In accordance with SFAS 133, the effective portion of the change in the fair value of a derivative instrument designated as a cash flow hedge is reported in OCI, net of tax, or as a Regulatory Asset (Liability). Amounts in accumulated OCI are ultimately recognized in earnings when the related hedged forecasted transaction occurs. The change in the fair value of the ineffective portion of the derivative instrument designated as a cash flow hedge is recorded in earnings. Derivative instruments that have not been designated as hedges are adjusted to fair value through earnings. We have entered into several derivative instruments, including hedges of anticipated electric and gas purchases and interest rate swaps which have been designated as cash flow hedges. The fair value of the derivative instruments is determined by reference to quoted market prices, listed contracts, published quotations or quotations from counterparties.
For additional information regarding Derivative Financial Instruments, See Note 4 - Financial Instruments, Energy Trading and Risk Management - Derivative Instruments and Hedging Activities.
OTHER ACCOUNTING POLICIES AND ISSUES
For additional information on our accounting policies and the implementation of recently issued accounting standards, see Note 1. - Organization, Basis of Presentation and Summary of Significant Accounting Policies and Note 2 -Accounting Matters, respectively.
FORWARD LOOKING STATEMENTS
Except for the historical information contained herein, certain of the matters discussed in this report constitute "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties which could cause actual results to differ materially from those anticipated. Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used herein, the words "will", "anticipate", "intend", "estimate", "believe", "expect", "plan", "hypothetical", "potential", variations of such words and similar expressions are intended to identify forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of
new information, future events or otherwise. The following review of factors should not be construed as exhaustive or as any admission regarding the adequacy of our disclosures prior to the effective date of the Private Securities Litigation Reform Act of 1995.
In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:
o Credit, Commodity, and Financial Market Risks May Have an Adverse Impact o Energy Obligations, Available Supply and Trading Risks May Have an Adverse Impact o The Electric Utility Industry is Undergoing Substantial Change o Generation Operating Performance May Fall Below Projected Levels o We are subject to Substantial Competition From Well Capitalized Participants in the Worldwide Energy Markets o Our Ability to Service Our Debt Could Be Limited o Power Transmission Facilities May Impact Our Ability to Deliver Our Output to Customers o Regulatory Issues Significantly Impact Our Operations o Environmental Regulation May Limit Our Operations o We Are Subject to More Stringent Environmental Regulation than Many of Our Competitors o Insurance Coverage May Not Be Sufficient o Acquisition, Construction and Development Activities May Not Be Successful o Changes in Technology May Make our Power Generation Assets Less Competitive o We are subject to control by PSEG o Recession, Acts of War, Terrorism Could Have an Adverse Impact
ITEM 7A.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
Information relating to quantitative and qualitative disclosures about market risk is set forth under the caption "Qualitative and Quantitative Disclosures About Market Risk" in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Such information is incorporated herein by reference.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PSEG POWER LLC CONSOLIDATED STATEMENTS OF INCOME (Millions of Dollars)
See Notes to Consolidated Financial Statements.
PSEG POWER LLC CONSOLIDATED BALANCE SHEETS ASSETS (Millions of Dollars)
See Notes to Consolidated Financial Statements.
PSEG POWER LLC CONSOLIDATED BALANCE SHEETS LIABILITIES AND MEMBER'S EQUITY (Millions of Dollars)
See Notes to Consolidated Financial Statements.
PSEG POWER LLC CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of Dollars)
See Notes to Consolidated Financial Statements.
PSEG POWER LLC CONSOLIDATED STATEMENTS OF CAPITALIZATION AND MEMBER'S EQUITY (Millions of Dollars)
(1) Net Income included in retained earnings reflects earnings from the legal operations of PSEG Power LLC during 2000. Net Income/Loss included in Capitalization for 2000 and 1999 reflects the Net Income/Loss allocated from Public Service Electric and Gas Company's generation business.
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION, BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
We have three principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T) and currently operate in two reportable segments, generation and energy trading. The generation segment of our business earns revenues by selling energy on a wholesale basis under contract to our affiliate, Public Service Electric and Gas Company (PSE&G) and other power marketers and to load serving entities, and by bidding energy, capacity and ancillary services into the market. The energy trading segment of our business earns revenues by trading energy, capacity, fixed transmission rights, fuel and emission allowances in the spot, forward and futures markets. The energy trading segment also earns revenues through financial transactions, including swaps, options and futures in the electricity markets. We and our subsidiaries were established to acquire, own and operate the electric generation-related business of PSE&G pursuant to the Final Decision and Order (Final Order) issued by the New Jersey Board of Public Utilities (BPU) under the New Jersey Electric Discount and Energy Competition Act (Energy Competition Act) discussed below. We also have a finance company subsidiary, PSEG Power Capital Investment Co. (Power Capital), which provides certain financing for our subsidiaries.
PURCHASE OF GENERATION-RELATED BUSINESS FROM PSE&G
In August 2000, pursuant to the Final Order, we purchased PSE&G's generation-related property, plant and equipment for $2.443 billion, as specified in the Final Order, plus $343 million for other generation-related assets and liabilities (Transaction) in exchange for a $2.786 billion promissory note with an interest rate of 14.23%, representing PSE&G's weighted average cost of capital. We repaid the promissory note on January 31, 2001, with funds provided from PSEG in the form of equity and loans.
Because the assets were purchased from an affiliate, we recorded the assets at PSE&G's carrying value. The difference between the total purchase price and the net book value of the generation-related assets and liabilities was recorded as a Basis Adjustment reducing our equity.
BASIS OF PRESENTATION
Our consolidated financial statements present the historical financial position, results of operations and net cash flows of the generation-related business of PSE&G prior to the Transaction in August 2000, and are not necessarily indicative of the financial position, results of operations or net cash flows that would have existed had the generation-related business been an independent company during the periods presented. For periods prior to the Transaction, any references to us contained herein refer to our business and the generation-related business of PSE&G prior to the purchase of the generation-related business from PSE&G.
Certain information in these consolidated financial statements relating to the results of operations and financial condition prior to the Transaction was derived from the historical financial statements of PSE&G which have been prepared in accordance with generally accepted accounting principles (GAAP). Various allocation methodologies were employed to separate the results of operations and financial condition of the generation-related portion of PSE&G's business from PSE&G's historical financial statements prior to the Transaction. Prior to the Transaction, revenues included the generation segment of revenue from PSE&G's operations and any generation-related revenues, such as ancillary services and wholesale energy activity. Expenses, such as energy costs, operations and maintenance and depreciation and amortization, and assets, such as property, plant and equipment, materials and supplies and fuel, were specifically identified by function and reported accordingly for our operations. Various allocations were used to disaggregate other common expenses, assets and liabilities between us and PSE&G's regulated transmission and distribution operations. Interest and preferred stock dividends were calculated based upon an allocation methodology that charged us with financing and equity costs from PSE&G in proportion to our share of total net property, plant and equipment prior to the effects of deregulation discussed below. These methodologies use the assumption that we had operated as a separate, regulated company prior to April 1, 1999, the date we
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
discontinued the application of Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). On the date of the Transaction, certain of the assets and liabilities which were allocated in the historical consolidated financial statements, such as other postretirement employee benefits (OPEB) and working capital, remained with PSE&G. For additional information, see - Accounting for the Effects of Regulation, below.
Management believes that these allocation methodologies are reasonable. Had we existed as a separate company, our results could have significantly differed from those presented herein. In addition, future results of operations, financial position and net cash flows could materially differ from the historical results presented.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION
The consolidated statements include our accounts and those of our subsidiaries. We consolidate those entities in which we have a controlling interest, with the exception of the Salem Peach Bottom, Keystone, Conemaugh and Yards Creek Generation facilities, which are accounted for on a pro-rata consolidated basis. All significant intercompany accounts and transactions are eliminated in consolidation.
ACCOUNTING FOR THE EFFECTS OF REGULATION
Prior to April 1999, our financial statements were prepared in accordance with the provisions of SFAS 71. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the relationship of costs and revenues as determined by regulators. Under SFAS 71, a regulated entity must defer recognition of costs (a regulatory asset) or recognize obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future revenues.
Effective April 1, 1999, we discontinued the application of SFAS 71 and recorded an extraordinary charge consistent with the requirements of Emerging Issues Task Force (EITF) Issue No. 97-4, "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and No. 101" (EITF 97-4) and SFAS 101, "Regulated Enterprises--Accounting for the Discontinuation of Application of FASB Statement No. 71" (SFAS 101). The extraordinary charge consisted primarily of the write-down of our nuclear and fossil generating stations in accordance with SFAS 121. A discounted cash flow analysis was performed on a unit-by-unit basis to determine the amount of the impairment. As a result of this impairment analysis, the net book value of the generating stations was reduced by approximately $5.0 billion (pre-tax) or approximately $3.1 billion (after-tax).
In addition to the impairment of our generating stations, the extraordinary charge consisted of various accounting adjustments to reflect the absence of cost of service regulation for electric generation in the future. The adjustments related primarily to materials and supplies, general plant items and liabilities for certain contractual and environmental obligations.
Other accounting impacts of the discontinuation of SFAS 71 included reclassifying the Accrued Nuclear Decommissioning Reserve and the Accrued Cost of Removal for generation-related assets from Accumulated Depreciation to Long-Term Liabilities.
DERIVATIVE FINANCIAL INSTRUMENTS
We use derivative financial instruments to manage risk from changes in interest rates and commodity prices, pursuant to business plans and prudent practices.
On January 1, 2001, we adopted SFAS 133, as amended (SFAS 133). SFAS 133 established accounting and reporting standards for derivative instruments, including certain derivative instruments included in other contracts, and for hedging activities. It requires an entity to recognize the fair value of derivative instruments held as assets or liabilities on the balance sheet. For cash flow hedging purposes, changes in the fair value of the effective portion of the gain or loss on the derivative are reported in Other Comprehensive Income (OCI), net of tax. Amounts in accumulated OCI are ultimately recognized in earnings when the related hedged forecasted transaction occurs. The change in the fair value of the ineffective portion of the gain or loss on a derivative instrument designated as a cash
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
flow hedge is recorded in earnings. Derivative instruments that have not been designated as hedges are adjusted to fair value through earnings.
We did not have a transition adjustment upon adoption. Subsequent to December 31, 2000, we entered into certain derivative instruments, which have been designated as cash flow hedges. We have not utilized any derivative instruments for fair value hedging purposes.
The fair value of the derivative instruments is determined by reference to quoted market prices, listed contracts, published quotations or quotations from counterparties. In the absence thereof, we utilize mathematical models based on current and historical data.
Prior to the adoption of SFAS 133, we accounted for the results of our derivative activities for hedging purposes utilizing the settlement method. The settlement method provided for recognizing the gains or losses from derivatives when the related underlying transaction was completed. Derivatives that were not entered into for hedging purposes were recorded at fair value and changes in the fair value were recorded in earnings.
For additional information regarding Derivative Financial Instruments, See Note 4 - Financial Instruments, Energy Trading and Risk Management - Derivative Instruments and Hedging Activities.
COMMODITY CONTRACTS
We enter into electricity forward purchases and natural gas commodity futures and swaps with counterparties to manage exposure to electricity and natural gas price risk. These contracts, in conjunction with owned electric generating capacity, are designed to manage price risk exposure for electric customer commitments. In accordance with SFAS 133, such energy contracts are recognized at fair value as derivative assets or liabilities on the balance sheet and the effective portion of the gain or loss on the contracts is reported in OCI, net of tax. Amounts in accumulated other comprehensive income are ultimately recognized in earnings when the related hedged forecasted transaction occurs.
We also enter into forwards, futures, swaps and options as part of our energy trading operations. Effective January 1, 1999, we adopted Emerging Issues Task Force (EITF) Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10). EITF 98-10 requires that energy trading contracts be marked to market with gains and losses included in current earnings.
The vast majority of these commodity-related contracts have terms of less than one year. Valuations for these contracts are readily obtainable from the market exchanges, such as the PJM ISO, and over the counter quotations. The fair value of the financial instruments that are marked to market are based on management's best estimates. The valuations also take into account a liquidity reserve, which is determined by using financial quotation systems, monthly bid-ask prices and spread percentages. The valuations also take into account credit reserves, discussed in Note 4. - Financial Instruments, Energy Trading and Risk Management - Credit Risk. We have consistently applied this valuation methodology for each reporting period presented.
In July 2000, EITF 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent" (EITF 99-19), provided guidance on the issue of whether a company should report revenue based on the gross amount billed to the customer or the net amount retained. The guidance states that whether a company should recognize revenue based on the gross amount billed or the net retained requires significant judgement, which depends on the relevant facts and circumstances. Based on the analysis and interpretation of EITF 99-19, we report all trading revenues and trading-related costs on a gross basis for physical bilateral energy and capacity sales and purchases. We report swaps, futures, option premiums, firm transmission rights, transmission congestion credits, and purchases and sales of emission allowances on a net basis. The prior year financial statements have been reclassified accordingly.
For additional information regarding commodity-related contracts, See Note 4 - Financial Instruments, Energy Trading and Risk Management
GENERATION REVENUES AND ENERGY COSTS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Revenues are recorded based on energy and capacity sold and services rendered to customers during each accounting period. Prior to August 1, 1999, revenue was calculated by unbundling the generation component of revenue from PSE&G's bundled rate for the generation, transmission and distribution of energy and adding any other generation-related revenues, such as ancillary services and wholesale energy trading activity. Also, prior to August 1, 1999, we recorded unbilled revenues representing the estimated amount customers would be billed for services rendered from the time meters were last read to the end of the respective accounting period. Beginning on August 1, 1999, electric rates charged to customers were unbundled and the generation, transmission, distribution and other components of the total rate became separate charges. Effective with that date, revenue represents the amount recorded for the energy and capacity provided to meet the BGS requirements to PSE&G combined with other generation-related revenues, such as ancillary services, wholesale trading activity and amounts recorded for the market transition charge (MTC) (see Note 3. - Regulatory Issues and Accounting Impacts of Deregulation). Following the Transaction, we bill, and periodically settle with, PSE&G for BGS requirements and MTC.
Prior to August 1, 1999, fuel revenues and expenses and purchased power costs flowed through the Electric Levelized Energy Adjustment Clause (LEAC) mechanism and variances in fuel revenues and expenses and purchased power costs were subject to deferral accounting and thus had no direct effect on earnings. Any LEAC underrecoveries or overrecoveries, together with interest (in the case of net overrecoveries), were deferred and included in the results of operations in the period in which they were reflected in rates. Effective January 1, 1998, the amount included for LEAC under/overrecovery represented the difference between fuel-related revenues and fuel-related expenses which included electricity purchases at the PJM market clearing price. Effective April 1, 1998, PJM, as an independent system operator (ISO), replaced the PJM uniform market clearing price with LMP for determining the market clearing price to energy providers. Due to the effects of congestion and constraints in the PJM market, LMP may be different for the various delivery points in PJM. Due to the discontinuation of the LEAC mechanism on August 1, 1999, earnings volatility increased since the unregulated electric generation business ceased to follow deferral accounting. We now bear the full risk and reward of managing the fixed price BGS contract and the changes in nuclear and fossil generating fuel costs and purchased power costs.
DEPRECIATION AND AMORTIZATION
We calculate depreciation on generation-related assets based on the assets' estimated useful lives determined based on planned operations, rather than using depreciation rates prescribed by the BPU in rate proceedings. Prior to April 1999, depreciation rates were reviewed periodically and adjustments were made as approved by the BPU. Depreciation rates stated in percentages of original cost of depreciable property in 1999 (prior to April 1, 1999) were 3.52%. Prior to April 1999, we had certain regulatory assets embedded in property, plant and equipment as a result of the use of a level of depreciation expense in the rate-making process that differed from the amount that would have been recorded under GAAP for non-regulated companies.
The estimated useful lives are from 3 years to 20 years for general plant. The estimated useful lives for buildings and generating stations are as follows:
Class of Property Estimated Useful Life (In Years) --------------- -------------------------------- Fossil Production 25-55 Nuclear Generation 30 Pumped Storage 45
Nuclear fuel burnup costs are charged to fuel expense on a units-of-production basis over the estimated life of the fuel. Rates for the recovery of fuel used at all nuclear units include a provision of one mill per kilowatt-hour (kWh) of nuclear generation for spent fuel disposal costs.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC) AND INTEREST CAPITALIZED DURING CONSTRUCTION (IDC)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
AFDC represented the cost of debt and equity funds used to finance the construction of new facilities. The amount of AFDC capitalized was reported in the Consolidated Statements of Income as a reduction of interest charges. The rates used for calculating AFDC in 1999 (prior to April 1, 1999) was 5.29%. Effective April 1, 1999, we no longer calculate AFDC. Interest related to capital projects is now capitalized in accordance with SFAS No. 34, "Capitalization of Interest Cost." In 1999, AFDC amounted to $1 million.
IDC represents the cost of debt used to finance the construction of non-utility facilities. The amount of IDC capitalized is reported in the Consolidated Statements of Income as a reduction of interest expense. The weighted average rates used for calculating IDC in 2001 and 2000 were 7.98% and 9.98%, respectively. In 2001, 2000 and 1999, IDC amounted to $63 million, $14 million and $3 million, respectively.
INCOME TAXES
We file a consolidated federal income tax return through PSEG. We record our tax liabilities as though we were filing separate returns and will record tax benefits to the extent that PSEG is able to receive those benefits. Deferred income taxes are provided for the temporary differences between book and taxable income, resulting primarily from the use of accelerated depreciation for tax purposes and the recognition of unrealized gains for book purposes. We defer and amortize investment and energy tax credits over the lives of the related properties.
CASH AND CASH EQUIVALENTS
The December 31, 2001 and 2000 cash balances consist primarily of working funds and highly liquid marketable securities (commercial paper and money market funds) with an original maturity of three months or less.
MATERIALS AND SUPPLIES AND FUEL
The carrying value of the materials and supplies and fuel is recorded at lower of cost or market.
PROPERTY, PLANT AND EQUIPMENT
We capitalize costs to acquire new assets or costs which increase either the capacity or the useful life of an asset or costs which represent the replacement of a retired asset. All other costs are expensed as incurred. Also, under our revised policy, the remaining net carrying amount of a retired asset is charged to earnings.
Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets' environmental safety or efficiency. All other environmental expenditures are expensed.
IMPAIRMENT OF LONG-LIVED ASSETS
We review long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In the event that facts and circumstances indicate that the carrying amount of long-lived assets may be impaired, an evaluation of recoverability would be performed. If an evaluation is required, the estimated future undiscounted cash flows associated with the asset would be compared to the asset's carrying amount to determine if a writedown is required. If this review indicates that the assets will not be recoverable, the carrying value of our assets would be reduced to their estimated market value. For the impact of the application of SFAS 121, see Note 1. - Organization, Basis of Presentation and Summary of Significant Accounting Policies - Accounting for the Effects of Regulation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
USE OF ESTIMATES
The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Also, such estimates relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts. In addition to these estimates, see Basis of Presentation for a discussion of the estimates used and methodologies employed to prepare our historical financial statements for the periods prior to August 2000.
RECLASSIFICATIONS
Certain reclassifications of amounts reported in prior periods have been made to conform with the current presentation.
CURRENT ASSETS AND CURRENT LIABILITIES
The fair value of current assets and current liabilities approximate their carrying amounts.
NOTE 2. ACCOUNTING MATTERS
In July 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS 141). SFAS 141 was effective July 1, 2001 and requires that all business combinations on or after that date be accounted for under the purchase method. Upon implementation of this standard, there was no impact on our financial position or results of operations and we do not believe it will have a substantial effect on our growth strategy.
Also in July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). Under SFAS 142, goodwill is considered a nonamortizable asset and will be subject to an annual review for impairment and an interim review when events or circumstances occur. SFAS 142 is effective for all fiscal years beginning after December 15, 2001. At December 31, 2001, we had recorded goodwill of approximately $22 million as a result of our acquisition of the Albany Steam Station from Niagara Mohawk Power Corporation (Niagara Mohawk) in May 2000. This amount was being amortized over 40 years in accordance with current accounting guidance yielding approximately $0.5 million of amortization per year. The impact of adopting SFAS 142 is not likely to be material to our financial position and statement of operations. For additional information relating to potential asset impairments, see Note 5. Commitments and Contingent Liabilities.
Also in July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). Upon adoption of SFAS 143, the fair value of a liability for an asset retirement obligation is required to be recorded. Upon settlement of the liability, an entity either settles the obligation for our recorded amount or incurs a gain or loss upon settlement. SFAS 143 is effective for fiscal years beginning after June 15, 2002. We are currently evaluating the effect of this guidance and cannot predict the impact on our financial position or results of operations, however, such impact could be material.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
In August 2001, FASB issued SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets" (SFAS 144). Under SFAS 144 long-lived assets to be disposed of should be measured at the lower of the carrying amount or fair value less cost to sell, whether reported in continued operations or in discontinued operations. Discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operations. SFAS 144 is effective for fiscal years beginning after December 15, 2001. We are currently evaluating this guidance and do not believe that it will have a material impact on our financial position or results of operations.
NOTE 3. REGULATORY ISSUES AND ACCOUNTING IMPACTS OF DEREGULATION
NEW JERSEY ENERGY MASTER PLAN PROCEEDINGS AND RELATED ORDERS
Following the enactment of the Energy Competition Act, the BPU rendered a Final Order relating to PSE&G's rate unbundling, stranded costs and restructuring proceedings (Final Order). PSE&G, pursuant to the Final Order, transferred our electric generating facilities and wholesale power contracts to us and our subsidiaries on August 21, 2000 in exchange for a promissory note in an amount equal to the purchase price.
The generation assets were transferred at the price specified in the BPU order - $2.443 billion plus the net book value of $343 million for other generation related assets and liabilities. Because the transfer was between affiliates, PSE&G and us, we recorded the sale at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities was recorded as an equity adjustment on PSE&G's and our Consolidated Balance Sheets. These amounts are eliminated on our consolidated financial statements. We settled the promissory note on January 31, 2001, with equity contributions and loans provided by PSEG.
Also in the Final Order, the BPU concluded that PSE&G should recover up to $2.94 billion (net of tax) of its generation-related stranded costs, through securitization of $2.4 billion, plus an estimated $125 million of transaction costs, and an opportunity to recover up to $540 million (net of tax) of its unsecuritized generation-related stranded costs on a net present value basis. The $540 million is subject to recovery through the MTC, which is to be collected over a four year period ending on July 31, 2003 and is remitted to us along with BGS revenues as part of PSE&G's BGS contract with us. Upon expiration of the BGS contract on July 31, 2002, PSE&G will continue to remit the MTC revenues to us through July 31, 2003.
NOTE 4. FINANCIAL INSTRUMENTS, ENERGY TRADING AND RISK MANAGEMENT
Our operations are exposed to market risks from changes in commodity prices and interest rates that could affect our results of operations and financial conditions. We manage our exposure to these market risks through our regular operating and financing activities and, when deemed appropriate, hedge these risks through the use of derivative financial instruments. We use the term hedge to mean a strategy designed to manage risks of volatility in prices or rate movements on certain assets, liabilities or anticipated transactions and by creating a relationship in which gains or losses on derivative instruments are expected to counterbalance the losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. We use derivative instruments as risk management tools consistent with our business plans and prudent business practices and for energy trading purposes.
ENERGY TRADING
Effective January 1, 1999, we adopted EITF 98-10, which requires that energy trading contracts be recognized on the balance sheet at fair value with resulting realized and unrealized gains and losses included in current earnings. In 2001, we recorded $147 million of gains from our Energy Trading segment, including realized gains of $169 million and unrealized losses of $22 million. In 2000, we recorded gains of $77 million, including $22 million of realized gains and $55 million of unrealized gains and in 1999 recorded gains of $42 million,
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
including $37 million of realized gains and $5 million of unrealized gains. Net of broker fees and other trading related expenses, our energy trading business earned margins of $140 million, $72 million and $39 million for the years ended December 31, 2001, 2000 and 1999, respectively. As of December 31, 2001, we had a total of $9 million of net unrealized gains on our balance sheet, over 90% of which related to contracts with terms of less than two years.
(MILLIONS OF DOLLARS) Fair Value December 31, 2000................. $ 72 Realized Gains............................... (169) Unrealized Losses............................ (22) Fair Value of New Contracts.................. 128 --------------------- Fair Value December 31, 2001................. $ 9 =====================
We engage in physical and financial transactions in the electricity wholesale markets and execute an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. We actively trade energy, capacity, fixed transmission rights and emissions allowances in the spot, forward and futures markets primarily in PJM, but also throughout the Super Region. We are also involved in the financial transactions that include swaps, options and futures in the electricity markets.
The fair values as of December 31, 2001 and December 31, 2000 and the average fair values for the periods then ended of our financial instruments related to the energy commodities in the energy trading segment are summarized in the following table:
We routinely enter into exchange traded futures and options transactions for electricity and natural gas as part of our energy trading operations. Generally, exchange-traded futures contracts require deposit of margin cash, the amount of which is subject to change based on market movement and in accordance with exchange rules. The amount of the margin deposits as of December 31, 2001 and 2000 were approximately $2.7 million and $5.8 million, respectively. For further information regarding our energy trading contracts, see Note 9. - Financial Information by Business Segments.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
COMMODITY CONTRACTS
During 2001, we entered into electric physical forward contracts and gas futures and swaps to hedge our forecasted BGS requirements and gas purchases requirements for generation. These transactions qualified for hedge accounting treatment under SFAS 133 and were settled prior to the end of 2001. Marked-to-market valuations were reclassified from OCI to earnings during the third quarter ended September 30, 2001. As of December 31, 2001, we
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
did not have any outstanding derivatives accounted for under this methodology. However, there was substantial activity during the year ended December 31, 2001. In 2001, the values of these forward contracts, gas futures and swaps as of June 30 and September 30 were $(34.2) million and $(0.4) million.
The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies and other events. To reduce price risk caused by market fluctuations, we enter into derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge our anticipated demand. These contracts, in conjunction with owned electric generation capacity, are designed to cover estimated electric customer commitments.
We use a value-at-risk (VAR) model to assess the market risk of our commodity business. This model includes fixed price sales commitments, owned generation, native load requirements, physical contracts and financial derivative instruments. VAR represents the potential gains or losses for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. PSEG estimates VAR across its commodity business using a model with historical volatilities and correlations.
The Risk Management Committee (RMC) established a VAR threshold of $25 million. If this threshold was reached, the RMC would be notified and the portfolio would be closely monitored to reduce risk and potential adverse movements. In anticipation of the completion of the current BGS contract with PSE&G on July 31, 2002, the VAR threshold was increased to $75 million.
The measured VAR using a variance/co-variance model with a 95% confidence level and assuming a one-week time horizon as of December 31, 2001 was approximately $14 million, compared to the December 31, 2000 level of $19 million. This estimate was driven by a conservative assumption that we would enter into contracts for approximately 50% of its generating capacity during the BGS auction. Since we obtained contracts in excess of this amount, the VAR at December 31, 2001 would have been even lower. This estimate, however, is not necessarily indicative of actual results, which may differ due to the fact that actual market rate fluctuations may differ from forecasted fluctuations and due to the fact that the portfolio of hedging instruments may change over the holding period and due to certain assumptions embedded in the calculation.
Given the absence of a PJM price cap in situations involving emergency purchases and the potential for plant outages, extreme price movements, which have occurred, could have a material adverse impact on our financial condition, results of operations and net cash flows.
INTEREST RATE SWAPS
In October 2001, we entered into three interest rate swaps with an aggregate notional amount of $177.5 million to hedge the variability of interest payments related to the construction on our Waterford, Ohio facility. The swaps qualify for hedge accounting treatment under SFAS 133. As of December 31, 2001, the related fair value of $2.3 million was recorded on the balance sheet and the effective portion of the swaps was recorded in OCI. Management expects to amortize approximately $1.9 million (net of tax of $1.3) from OCI to earnings during the next 12 months. As of December 31, 2001, there was $1.3 million remaining in the OCI account.
In February 2001, we entered into various forward-interest rate swaps, with an aggregate notional amount of $400 million, to hedge the interest rate risk related to the anticipated issuance of debt. These fixed swaps paid a fixed rate of 6%, received 3-month LIBOR, with a maturity date of August 14, 2011. The original effective date of the swaps was August 14, 2001. On April 11, 2001, we issued $1.8 billion in fixed-rate Senior Notes and closed out the forward starting interest rate swaps. The aggregate loss, net of tax, of $3.2 million was classified as Accumulated Other Comprehensive Loss and is being amortized and charged to interest expense over the life of the debt. During the year ended December 31, 2001, approximately $0.6 million was reclassified from OCI to earnings. Management expects to amortize approximately $0.8 million (net of tax of $0.3) from OCI to earnings during the next twelve months.
CREDIT RISK
Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties, pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize our exposure to credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which may allow for the netting of positive and negative exposures associated with a single
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
counterparty. We also established credit reserves for our energy trading contracts based on various factors, including individual counterparty's position, credit rating, default possibility and recovery rates.
As a result of the BGS auction, we have contracted to provide generating capacity to the direct suppliers of New Jersey electric utilities, including PSE&G, commencing August 1, 2002. These bilateral contracts are subject to credit risk. This credit risk relates to the ability of counterparties to meet their payment obligations for the power delivered under each BGS contract. This risk is substantially higher than the risk associated with potential nonpayment by PSE&G under the BGS contract expiring July 31, 2002. Any failure to collect these payments under the new BGS contracts could have a material impact on our results of operations, cash flows, and financial position.
In December 2001, Enron Corp. (Enron) filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We entered into a variety of energy trading contracts with Enron in the PJM area as part of our energy trading activities. With the first signs of Enron's financial problems, we took steps to mitigate our exposure to both Enron and other counterparties who had significant exposures with Enron. As of December 31, 2001, we owed Enron approximately $23 million, net, and Enron held a letter of credit from us for approximately $40 million.
Two major California utilities, including Pacific Gas & Electric Company (PG&E), have significantly underrecovered from customers costs paid for power. As a consequence, these utilities have defaulted under a variety of contractual obligations and on April 6, 2001, PG&E filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Affiliates of these California utilities have entered into physical forward and swap contracts with us for delivery in PJM. These counterparties have met their obligations to date and are still investment grade entities. We have entered into a limited number of additional contracts since May 2001 with one of these counterparties, but no additional contracts have been entered into with the other counterparty since December 2000. Our exposure to these entities under these contracts is not material and management does not believe that a specific reserve related to receivables for these counterparties is presently necessary.
NOTE 5. COMMITMENTS AND CONTINGENT LIABILITIES
NUCLEAR INSURANCE COVERAGES AND ASSESSMENTS
At December 31, 2001, our insurance coverages and maximum retrospective assessments for our nuclear operations are as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
(A) The primary limit for Public Liability is a per site aggregate limit with no potential for assessment. The Nuclear Worker Liability represents the potential liability from workers claiming exposure to the hazard of nuclear radiation. This coverage is subject to an industry aggregate limit, includes annual automatic reinstatement if the Industry Credit Rating Plan (ICRP) Reserve Fund exceeds $400 million, and has an assessment potential under former canceled policies. (B) Retrospective premium program under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. Nuclear is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the United States. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of August 20, 1998. This retrospective program is in excess of the Public and Nuclear Worker Liability primary layers. (C) Limit of liability under the Price-Anderson Act for each nuclear incident. (D) For property limits excess of $1.75 billion, we participate in a Blanket Limit policy where the $1 billion limit is shared by Amergen, Exelon, and us among the Clinton, Oyster Creek, TMI-1, Peach Bottom, Salem and Hope Creek sites. This limit is not subject to reinstatement in the event of a loss. Participation in this program significantly reduces our premium and the associated potential assessment. (E) Effective January 1, 2002, NEIL II coverage was reduced to $600 million. (F) Peach Bottom has an aggregate indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Salem has an aggregate indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 75 weeks. Hope Creek has an aggregate indemnity limit based on a weekly indemnity of $3.5 million for 52 weeks followed by 80% of the weekly indemnity for 110 weeks.
The Price-Anderson Act sets the "limit of liability" for claims that could arise from an incident involving any licensed nuclear facility in the nation. The "limit of liability" is based on the number of licensed nuclear reactors and is adjusted at least every five years based on the Consumer Price Index. The current "limit of liability" is $9.5 billion. All utilities owning a nuclear reactor, including us, have provided for this exposure through a combination of private insurance and mandatory participation in a financial protection pool as established by the Price-Anderson Act. Under the Price-Anderson Act, each party with an ownership interest in a nuclear reactor can be assessed its share of $88.1 million per reactor per incident, payable at $10 million per reactor per incident per year. If the damages exceed the "limit of liability," the President is to submit to Congress a plan for providing additional compensation to the injured parties. Congress could impose further revenue raising measures on the nuclear industry to pay claims. Our maximum aggregate assessment per incident is $277.3 million (based on our ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $31.5 million. This does not include the $10.7 million that could be assessed under the nuclear worker policies.
Additionally, a decision by the U.S. Supreme Court, not involving Nuclear, has held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damages.
We are a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL). NEIL provides the primary property and decontamination liability insurance at Salem/Hope Creek and Peach Bottom. NEIL also provides excess property insurance through its decontamination liability, decommissioning liability, and excess property policy and replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in case of adverse loss experience. Our maximum potential liabilities under these assessments are included in the table and notes above. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on a site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.
GUARANTEED OBLIGATIONS
We have guaranteed certain energy trading contracts of our wholly-owned subsidiary ER&T. As of December 31, 2001 we have issued or primarily executed $506 million of guarantees on behalf of ER&T, of which our exposure is $153 million.
HAZARDOUS WASTE
The NJDEP regulations concerning site investigation and remediation require an ecological evaluation of potential injuries to natural resources in connection with a remedial investigation of contaminated sites. The NJDEP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
is presently working with industry to develop procedures for implementing these regulations. These regulations may substantially increase the costs of remedial investigations and remediations, where necessary, particularly at sites situated on surface water bodies. We and our predecessor companies owned and/or operated certain facilities situated on surface water bodies, certain of which are currently the subject of remedial activities. We do not anticipate that the compliance with these regulations will have a material adverse effect on our financial position, results of operations or net cash flows.
PASSAIC RIVER SITE
The EPA has determined that a six mile stretch of the Passaic River in Newark, New Jersey is a "facility" within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and that, to date, at least thirteen corporations, including us, may be potentially liable for performing required remedial actions to address potential environmental pollution at the Passaic River "facility". In a separate matter, we and certain of our predecessors operated industrial facilities at properties within the Passaic River "facility", including the Essex Generating Station. We cannot predict what action, if any, the EPA or any third party may take against us with respect to these matters, or in such event, what costs we may incur to address any such claims. However, such costs may be material.
PREVENTION OF SIGNIFICANT DETERIORATION (PSD)/NEW SOURCE REVIEW(NSR)
In a response to a demand by the EPA and NJDEP under Section 114 of the Federal Clean Air Act (CAA) requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal burning units were implemented in accordance with applicable NSR regulations, we provided certain data in November 2000. In January 2002, we reached an agreement with the state and federal governments to resolve allegations of noncompliance with federal and State of New Jersey NSR regulations. Under that agreement, we will install advanced air pollution controls over 10 years that are expected to dramatically reduce emissions of NOx, SO2, particulate matter, and mercury from these units. The estimated cost of the program is $337 million. We also will pay a $1.4 million civil penalty and spend up to $6 million on supplemental environmental projects.
The EPA had also asserted that PSD requirements are applicable to Bergen 2, such that we were required to have obtained a permit before beginning actual on-site construction. We disputed that PSD requirements were applicable to Bergen 2. The agreement resolving the NSR allegations concerning Hudson and Mercer also resolved the dispute over Bergen 2, and allowed construction of the unit to be completed and operation to commence.
NEW GENERATION AND DEVELOPMENT
PSEG Power New York Inc., an indirect subsidiary of ours, is in the process developing the Bethlehem Energy Center, a 750 MW combined-cycle power plant that will replace the 400 MW Albany Steam Station, which was acquired from Niagara Mohawk Power Corporation (Niagara Mohawk) in May 2000. Pending a final project certification decision that is expected within 12 months, we will be obligated to pay Niagara Mohawk up to $9 million. However, we expect this payment will be reduced based on conditions related to the service date and regulatory requirements.
We are constructing a 546 MW natural gas-fired, combined cycle electric generation plant at Bergen Generation Station at a cost of approximately $290 million with completion expected in June 2002. We are also constructing a 1,218 MW combined cycle generation plant at Linden for approximately $590 million expected to be completed in May 2003.
In August 2001, our subsidiaries closed with a group of banks on $800 million of non-recourse project financing for projects in Waterford, Ohio and Lawrenceburg, Indiana. The total combined project cost for Waterford and Lawrenceburg is estimated at $1.2 billion. Our required estimated equity investments for these projects is approximately $400 million. In connection with these projects, ER&T has entered into a five-year tolling agreement pursuant to which it is obligated to purchase the output of these facilities at stated prices. As a result, ER&T will bear the price risk related to the output of these generation facilities, which are scheduled to be completed in 2003.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
We filed an application with the New York State Public Service Commission for permission to construct and operate a direct generator lead (dedicated transmission line) that would deliver up to 1,200 MW of electricity to the West Side of Manhattan from the Bergen Generating Station. Applications for New Jersey and Federal approvals are expected to be filed in the near future. Estimated costs are not expected to exceed $100 million for one 500 MW line.
In addition, we have other commitments to purchase equipment and services to meet our current plans to develop additional generating capacity. The aggregate amount due under these commitments is approximately $500 million.
MINIMUM LEASE PAYMENTS
We lease administrative office space under various operating leases. As of December 31, 2001, our rental expense under these leases was approximately $1 million. Total future minimum lease payments as of December 31, 2001 are:
(Millions of Dollars)
2002 $1 2003 1 2004 3 2005 1 2006 1 Thereafter 14 ----------- Total minimum lease payments $21 ===========
NOTE 6. NUCLEAR DECOMMISSIONING TRUST
In accordance with Federal regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. PSE&G currently recovers from its customers the amounts paid into the trust fund each year and remits the amounts collected to us for deposit in our Nuclear Decommissioning Trust (NDT) Fund.
We have an ownership interest in five nuclear units. In accordance with rate orders received from the BPU, PSE&G had established an external master nuclear decommissioning trust for all our nuclear units that were transferred to us. This trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a "qualified" fund. Contributions made into a qualified fund are tax deductible. In the most recent study, the total cost of decommissioning its share of these five nuclear units was estimated at $986 million in year end 1995, excluding contingencies.
Pursuant to the Final Order, PSE&G will collect $29.6 million annually through the SBC and will remit to us an equivalent amount solely to fund the trust. The fair market value of these funds as of December 31, 2001 and 2000 was $817 million and $716 million, respectively.
Contributions made into the Nuclear Decommissioning Trust Funds are invested in debt and equity securities. These marketable debt and equity securities are recorded at amounts that approximate their fair market value. Those securities have exposure to market price risk. The potential change in fair value, resulting from a hypothetical 10% change in quoted market prices of these securities amounts to $82 million. The ownership of the Nuclear Decommissioning Trust Funds was transferred to us with the transfer of the generation-related assets from PSE&G.
With the purchase of Atlantic City Electric Company (ACE)'s interests in Salem, Peach Bottom and Hope Creek and Delmarva Power and Light Company (DP&L)'s interest in Salem and Peach Bottom, we received a transfer of $86 million and $50 million representing those companies respective NDT's related to the stations in 2001 and 2000, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
NOTE 7. INCOME TAXES
The following are the components of income tax expense:
2001 2000 1999 ---- ---- ---- (Millions of Dollars) Income Taxes: ------------- Current provision--Federal and State $167 $209 $311 Provision for deferred income taxes 94 (1) 5 Purchased State Tax Benefits....... (11) -- (21) Investment tax credits--net......... -- -- (4) ----- ----- ----- Total income tax provision......... $250 $208 $291 ===== ===== =====
Reconciliation between total income tax provision and tax computed at the statutory tax rate on pretax income follows:
DEFERRED INCOME TAXES
We provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities.
2001 2000 (Millions of Dollars) Assets: Nuclear Decommissioning $25 $ 26 New Jersey Corporate Business Tax 137 149 Plant Related Items 341 407 Cost of Removal 54 55 Contractual & Environmental Liabilities 35 35 Other 9 9 ----- ------ Total Assets $601 $681
Liabilities: Pension Costs $15 $ -- Other 7 5 ----- ------ Total Liabilities 22 5 ----- ------ Total Deferred Income Tax Asset $579 $676 ==== ======
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
NOTE 8. PENSION, OTHER POSTRETIREMENT BENEFIT AND SAVINGS PLANS
Our employees participate in non-contributory pension and other postretirement benefit plans (OPEB) sponsored by PSEG and administered by PSEG Services Corporation. In addition, PSEG sponsors two defined contribution plans. Our represented employees are eligible for participation in the PSEG Employee Savings Plan (Savings Plan), while our non-represented employees are eligible for participation in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). These plans are 401(k) plans to which eligible employees may contribute up to 25% of their compensation. Employee contributions up to 7% for Savings Plan participants and up to 8% for Thrift Plan participants are matched with employer contributions of cash equal to 50% of such employee contributions related to employee contributions. Thrift and Savings Plan matching costs amounted to approximately $8 million for each of the three years ended December 31, 2001. Also, Pension costs amounted to $16 million, $9 million and $24 million for the years ended December 31, 2001, 2000 and 1999, respectively.
SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106), requires that the expected cost of employees' postretirement health care and life insurance benefits be charged to income during the years in which employees render service. Such costs were deferred through December 31, 1997, pursuant to an order from the BPU. In concert with the discontinuance of SFAS 71, the portion of the resulting regulatory asset allocated to us prior to the Transaction remained with PSE&G as recovery of these previously incurred costs will be through PSE&G's regulated transmission and distribution operations. OPEB costs amounted to $4 million, $2 million and $30 million for the years ended December 31, 2001, 2000 and 1999, respectively.
NOTE 9. FINANCIAL INFORMATION BY BUSINESS SEGMENTS
BASIS OF ORGANIZATION
The reportable segments were determined by Management in accordance with SFAS 131, "Disclosures About Segments of an Enterprise and Related Information" (SFAS 131). These segments were determined based on how Management measures the performance based on segment net income, as illustrated in the following table, and how it allocates resources to our businesses. Our organizational structure supports these segments.
GENERATION
The generation segment of our business earns revenues by selling energy on a wholesale basis under contract to power marketers and to load serving entities (LSEs) and by bidding our energy, capacity and ancillary services into the market.
Electrical energy is produced by generation plants and is ultimately delivered to customers for use in lighting, heating and air conditioning and operation of other electrical equipment. Energy is our principal product and is priced on a usage basis, typically in cents per thousand Watt-hours (kWh) or dollars per million Watt-hours (mWh). Capacity, as a product that is distinct from energy, is a commitment to the ISO that a given unit will be available for dispatch if it is needed to meet system demand. Capacity is typically priced in dollars per MW for a given sale period (e.g., mW-day or mW-year). Capacity generally refers to the power output rating of a generation plant, measured on an instantaneous basis. Ancillary services constitutes another category of energy-related activities supplied by generation unit owners to the ISO.
ENERGY TRADING
The energy trading segment of our business earns revenues by trading energy, capacity, fixed transmission rights, fuel and emission allowances in the spot, forward and futures markets. Our energy trading segment also earns revenues through financial transactions, including swaps, options and futures in the electricity markets.
We engage in physical and financial transactions in the electricity wholesale markets and execute an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. We actively trade energy, capacity, fixed transmission rights, fuel and emission allowances in the spot, forward and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
futures markets primarily within PJM, but also throughout the Super Region. We are also involved in financial transactions that include swaps, options and futures in the electricity markets. In addition to participating in each of the major electricity supply and capacity markets in the Super Region, we also market and trade a broad spectrum of other energy and energy-related products. These products include coal, oil, natural gas, sulfur dioxide and nitrous oxide emissions allowances and financial instruments including fixed transmission rights. Our marketing and energy trading activity for these products extends throughout the United States and involves physical and financially settled transactions, futures, options, swaps and basis contracts. None of our trading revenue with any individual counterparty exceeds 10%.
We have developed a hedging and overall risk management strategy to limit our risk exposure and to track our positions in the wholesale markets. Hedging is used as the primary method for protecting against adverse price fluctuations and involves taking a position in a related financial instrument that is designed to offset the risk associated with the original position. We only use hedging instruments that correspond to the generation, purchase or sale of electricity and the purchase or sale of fuel.
Information related to the segments of our business is detailed below:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
NOTE 10. PROPERTY, PLANT AND EQUIPMENT
Information related to Property, Plant and Equipment is detailed below:
We have ownership interests in and are responsible for providing our share of the necessary financing for the following jointly owned facilities. All amounts reflect the share of our jointly owned projects and the corresponding direct expenses are included in Consolidated Statements of Income as operating expenses.
(A) The remaining 5% interest in Hope Creek was acquired in 2001. (B) An additional 7.41% interest in Salem was acquired in 2001.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
NOTE 11. SCHEDULE OF LONG-TERM DEBT
(A) On November 20, 2001 and December 5, 2001, we issued a total of $124 million of Pollution Control Notes in four series with maturities ranging from 11 years to 30 years.
(B) In August 2001, certain of our subsidiaries closed with a group of banks on $800 million of non-recourse project financing for projects in Waterford, Ohio and Lawrenceburg, Indiana. The total combined project cost for Waterford and Lawrenceburg is estimated at $1.2 billion. Our required estimated equity investment in these projects is approximately $400 million. In connection with these projects, ER&T has entered into a five-year tolling agreement pursuant to which it is obligated to purchase the output of these facilities at stated prices. As a result, ER&T will bear the price risk related to the output of these generation facilities which are scheduled to be completed in 2003.
NOTE 12. SELECTED QUARTERLY DATA (UNAUDITED)
The information shown below, in the opinion of management, includes all adjustments, consisting only of normal recurring accruals, necessary to a fair presentation of such amounts. Due to the seasonal nature of the generation business, quarterly amounts can vary significantly during the year.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONCLUDED
NOTE 13. RELATED PARTY TRANSACTIONS
PSEG & PSE&G
In August 2000, PSE&G transferred its electric generating assets to us in exchange for a $2.786 billion promissory note. Interest on the promissory note was payable at an annual rate of 14.23%, which represented PSE&G's weighted average cost of capital. For the period from January 1, 2001 to January 31, 2001, we recorded interest expense of approximately $34 million relating to the promissory note. We repaid the promissory note on January 31, 2001, with funds provided from PSEG in the form of equity and loans, including loans of $1.620 billion at various rates for which we recorded interest expense of approximately $40 million for the period from February 2001 to April 2001, when the loan was repaid.
As of December 31, 2001, we also had a payable to PSEG of approximately $164 million for short term funding needs. Our interest expense related to these borrowings was $23 million for the year ended December 31, 2001.
Effective with the asset transfer, we charge PSE&G for a MTC and the energy and capacity provided to meet PSE&G's BGS requirements. These rates were established by the BPU. For the years ended December 31, 2001 and 2000, we have charged PSE&G approximately $2.0 and $0.8 billion, respectively for MTC and BGS. As of December 31, 2001 and 2000, our receivable from PSE&G relating to these costs was approximately $159 million and $159 million, respectively. For the year ended December 31, 2001 and 2000, we purchased energy and capacity from PSE&G at the market price of approximately $158 million and $78 million, respectively, which PSE&G purchased under various non-utility generation (NUG) contracts. As of December 31, 2001 and 2000, our payable to PSE&G relating to these purchases was approximately $7 million and $17 million, respectively.
PSEG SERVICES CORPORATION
PSEG Services Corporation provides and bills administrative services to us on a monthly basis. Our costs related to such services amounted to approximately $191 million for the year ended December 31, 2001. As of December 31, 2001, our payable related to these costs was approximately $21 million.
TAX SHARING AGREEMENT
We are a single member limited liability company, wholly owned by PSEG. PSEG files a consolidated Federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and us and between PSEG and each of our subsidiaries. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.
THIRD PARTY CONTRACTS
We enter into a number of contracts with various suppliers, customers and other counterparties in the ordinary course of business. Certain contracts were entered into with subsidiaries of Foster Wheeler Ltd. E. James Ferland, our Chairman of the Board and Chief Executive Officer, serves on the Board of Directors of Foster Wheeler. Richard J. Swift, who serves on the Board of Directors of our parent, PSEG, was President and Chief Executive Officer of Foster Wheeler Ltd. at the time the contracts were entered into. The aggregate open commitment under the contracts is for approximately $100 million of engineering, procurement and construction services related to the development of certain generating facilities for us. We believe that the contracts were entered into on commercial terms no more favorable than those available in an arms-length transaction from other parties and the pricing is consistent with that available from other third parties.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONCLUDED
NOTE 14. GUARANTEES OF DEBT
In April 2001, we issued $500 million of 6.875% Senior Notes due 2006, $800 million of 7.75% Senior Notes due 2011 and $500 million of 8.625% Senior Notes due 2031. The net proceeds from the sale of the Senior Notes were used primarily for the repayment of the loans from PSEG. Each series of the Senior Notes is fully and unconditionally and jointly and severally guaranteed by Fossil, Nuclear and ER&T. The following table presents condensed financial information for the the guarantor subsidiaries as well as our non-guarantor subsidiaries as of December 31, 2001 and 2000 and for the two years then ended. Prior to the transfer of the generation-related assets in August 2000, all of our operations were included with PSE&G. Due to the nature of this transfer, all financial information as of and for the year ended December 31, 1999, and cash flow information for the year ended December 31, 2000, is not meaningful disclosure and therefore has been omitted.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONCLUDED
There are no restrictions on the ability of our subsidiaries to transfer funds in the form of dividends, loans or advances to us for the periods noted above.
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of PSEG Power LLC:
We have audited the consolidated balance sheets of PSEG Power LLC and subsidiaries (the "Company") as of December 31, 2001 and 2000, and the related consolidated statements of income, capitalization and member's equity and cash flows for each of the three years in the period ended December 31, 2001. Our audits also included the consolidated financial statement schedule listed in the Index in Item 14(B)(a). These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2001 and 2000, and the results of its operations and its 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, such consolidated 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.
We have also previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheets of the Company as of December 31, 1999, 1998, and 1997, and the related consolidated statements of income, capitalization and member's equity and cash flows for the years ended December 31, 1998 and 1997 (none of which are presented herein) and we expressed unqualified opinions on those consolidated financial statements.
In our opinion, the information set forth in the Selected Financial Data under the caption "Income Statement Data", "Balance Sheet Data", and Capital Expenditures under the caption "Other Data", for each of the five years in the period ended December 31, 2001, presented in Item 6, is fairly stated in all material respects, in relation to the consolidated financial statements from which it has been derived.
Deloitte & Touche LLP Parsippany, New Jersey February 15, 2002
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None
PART III --------
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
PSEG is the sole member of Power's limited liability company and, as such, has the power to control the election of Power's board of directors and all other matters submitted for member approval and has control over Power's management and affairs. Currently, all of Power's directors are officers and employees of or consultants to PSEG or one of its subsidiaries.
Power's executive officers and members of Power's board of directors and their ages as of December 31, 2001 are as follows:
EXECUTIVE OFFICERS
E. JAMES FERLAND has been Chairman of the Board and Chief Executive Officer of Power since its formation. Age 59. Mr. Ferland has been Chairman of the Board, President and Chief Executive Officer of Public Service Enterprise Group Incorporated since July 1986, Chairman of the Board and Chief Executive Officer of PSEG Energy Holdings Inc. since June 1989 and Chairman of the Board and Chief Executive Officer of Public Service Electric and Gas Company since September 1991.
FRANK CASSIDY has been President, Chief Operating Officer and a director of Power since its formation. Age 55. Mr. Cassidy is also a member of the board of directors of Fossil, Nuclear and ER&T. He served as President and Chief Operating Officer of PSEG Energy Technologies Inc. from November 1996 to July 1999. Mr. Cassidy was Senior Vice President -- Fossil Generation of Public Service Electric and Gas Company from February 1995 to November 1996 and Vice President -- Transmission Systems of Public Service Electric and Gas Company from November 1989 to February 1995.
THOMAS R. SMITH has been Executive Vice President-- Operations and Development of Power since October 2000. Age 41. Mr. Smith also serves as President of Fossil and is a member of the board of directors of Fossil, Nuclear and ER&T. He had been Executive Vice President and Chief Operating Officer of PSEG Global Inc. from January 2000. Prior to that, he was President of PSEG Americas, a subsidiary of Global, from November 1996. Before that, he was Senior Vice President and Regional Executive for Latin America for the International Generating Company.
THOMAS M. O'FLYNN has been Executive Vice President and Chief Financial Officer of Power since March 2002. Age 41. Mr. O'Flynn is also a member of the board of directors of Power. Mr. O'Flynn has been Executive Vice President Finance and Chief Financial Officer of Public Service Enterprise Group Incorporated since July 1, 2001. From December 1997 to May 2001, Mr. O'Flynn was a Managing Director of Morgan Stanley's Global Power and Utility Investment Banking Division Group. From January 1994 through December 1997, he was a Principal of Morgan Stanley's Global Power and Utility Investment Banking Division Group.
HAROLD W. BORDEN, JR. has been Vice President and General Counsel of Power since its formation. Age 57. Mr. Borden is also General Counsel of Fossil, Nuclear and ER&T. Mr. Borden had been Vice President-- Law of Public Service Electric and Gas Company from April 1995 to July 1999.
PATRICIA A. RADO has been Vice President and Controller of Power since its formation. Age 59. Ms Rado is also Controller of Fossil, Nuclear and ER&T. Ms. Rado has been Vice President and Controller of Public Service Enterprise Group and Public Service Electric and Gas Company since April 1993.
MORTON A. PLAWNER has been Vice President and Treasurer of Power since its formation. Age 54. Mr. Plawner is also Treasurer of Fossil, Nuclear and ER&T. Mr. Plawner has been Treasurer of Public Service Enterprise Group and Vice President and Treasurer of Public Service Electric and Gas Company since January 1,
1998. Prior to that, Mr. Plawner had been General Manager-- Property and Risk Management of Public Service Electric and Gas Company since 1994 and Risk Manager since 1989.
DIRECTORS
ROBERT E. BUSCH has been a director of Power since December 2000. Age 55. Mr. Busch has been President of PSEG Services Corporation since April 2001 and Senior Vice President and Chief Financial Officer of Public Service Electric and Gas Company since March 1998. From 1997, he was the National Director of the Hay Group Utility Consulting Practice. From 1996 to 1997, he was a Senior Consultant for Cambridge Energy Research Associates. Prior to that time, he was President of the Energy Resources Group of Northeast Utilities.
ROBERT J. DOUGHERTY, JR. has been a director of Power since its formation. Age 50. Mr. Dougherty has been President and Chief Operating Officer of PSEG Energy Holdings Inc. since January 1997. Prior to that, Mr. Dougherty was president of Enterprise Ventures and Services Corporation.
ROBERT C. MURRAY has been a director of Power since its formation. Age 55. Mr. Murray is a consultant to Public Service Enterprise Group Incorporated and was Vice President and Chief Financial Officer of Public Service Enterprise Group Incorporated from January 1992 through June 2001. Mr. Murray was Executive Vice President-- Finance of Public Service Electric and Gas Company from June 1997 to June 2000. Mr. Murray was Senior Vice President and Chief Financial Officer of Public Service Electric and Gas Company from January 1992 to June 1997.
R. EDWIN SELOVER has been a director of Power since its formation. Age 56. Mr. Selover has been Vice President and General Counsel of Public Service Enterprise Group since April 1988. Mr. Selover has also been Senior Vice President and General Counsel of Public Service Electric and Gas Company since January 1988.
MICHAEL J. THOMSON has been a director of Power since January 2000. Age 42. Mr. Thomson has been President and Chief Executive Officer of PSEG Global Inc. since January 1997. Prior to that time he was Senior Vice President, from July 1993, and Chief Operating Officer, from February 1994, of PSEG Global Inc.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
PART IV -------
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A) Financial Statements:
a. Consolidated Statements of Income for the years ended December 31, 2001, 2000 and 1999 on page 36.
Consolidated Balance Sheets for the years ended December 31, 2001 and 2000 on pages 37 and 38.
Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999 on page 39.
Statements of Common Stockholders' Equity for the years ended December 31, 2001, 2000 and 1999 on page 40.
Notes to Consolidated Financial Statements on pages 41 to 61.
(B) The following documents are filed as a part of this report:
a. Financial Statement Schedules:
Schedule II--Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2001 (page 66)
Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
The following exhibits are filed herewith:
Exhibit 12: Computation of Ratios of Earnings to Fixed Charges Exhibit 21: Subsidiaries of Registrant
(See Exhibit Index on page 68)
(C) There were no reports on Form 8-K filed during the last quarter of 2001 and the 2002 period covered by this report under Item 5:
SCHEDULE II
PSEG POWER LLC SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2000 -- DECEMBER 31, 1998
(A) Reduced reserve to appropriate level and remove obsolete inventory. (B) Accounts Receivable write off.
SIGNATURES
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.
PSEG Power LLC
By E. JAMES FERLAND ----------------------------- E. James Ferland Chairman of the Board and Chief Executive Officer
Date: March 7, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
EXHIBIT INDEX
Certain Exhibits previously filed with the Commission and the appropriate securities exchanges are indicated as set forth below. Such Exhibits are not being refiled, but are included because inclusion is desirable for convenient reference.
3.1* Certificate of Formation of PSEG Power LLC
3.2* PSEG Power LLC Limited Liability Company Agreement
4.1* Indenture dated April 16, 2001 between Registrants and The Bank of New York and form of Subsidiary Guaranty included therein
10* Basic Generation Service Contract with PSE&G
12 Computation of Ratio of Earnings to Fixed Charges
21 Subsidiaries of the Registrants
* Filed by Power with Registration Statement No. 333-69228 on Form S-4.