Participating Equity Preference Securities (consisting of a Purchase Contract and a Preferred Trust Security of PSEG Funding Trust I (Registrant) and registered on the New York Stock Exhange.
Trust Originated Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG’s Debentures), $25 par value at 8.75%, issued by PSEG Funding Trust II (Registrant) and registered on the New York Stock Exchange.
Monthly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G’s Subordinated Debenture), $25 par value at 8.00%, issued by Public Service Electric and Gas Capital, L.P. (Registrant) and registered on the New York Stock Exchange.
Quarterly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G’s Subordinated Debentures), $25 par value at 8.125%, issued by PSE&G Capital Trust II (Registrant) and registered on the New York Stock Exchange.
Securities registered pursuant to Section 12 (g) of the Act:
| Registrant | Title of Class |
| Public Service Enterprise Group Incorporated | Floating Rate Capital Securities (Guaranteed Preferred Beneficial Interest in |
| PSEG’s Debentures), $1,000 par value issued by Enterprise Capital Trust II | |
| (Registrant), LIBOR plus 1.22%. | |
| Trust Originated Preferred Securities (Guaranteed Preferred Beneficial | |
| Interest in PSEG’s Debentures), $25 par value at 7.44%, issued by Enterprise | |
| Capital Trust I (Registrant). | |
| Trust Originated Preferred Securities (Guaranteed Preferred Beneficial | |
| Interest in PSEG’s Debentures), $25 par value at 7.25%, issued by Enterprise | |
| Capital Trust III (Registrant). | |
| Public Service Electric and Gas Company | 6.92% Cumulative Preferred Stock $100 par value |
| Medium-Term Notes, Series A | |
| PSEG Power LLC | Limited Liability Company Membership Interest |
| PSEG Energy Holdings LLC | Limited Liability Company Membership Interest |
The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated as of June 28, 2002 was $8,947,292,512 based upon the New York Stock Exchange Composite Transaction closing price. The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates as of January 31, 2003 was $7,949,509,112 based upon the New York Stock Exchange Composite Transaction closing price.
The number of shares outstanding of Public Service Enterprise Group Incorporated’s sole class of Common Stock, as of the latest practicable date, was as follows:
| Class | Outstanding at January 31, 2003 |
| |
|
| Common Stock, without par value | 225,326,222 |
PSEG Power LLC and PSEG Energy Holdings LLC are wholly-owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and are filing their respective Annual Reports on Form 10-K with the reduced disclosure format authorized by General Instruction I.
As of January 31, 2003, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. Yes |X| No |_|
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. |X|
Indicate by check mark whether any registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes |X| No |_|
DOCUMENTS INCORPORATED BY REFERENCE
| Part of Form 10-K of Public Service Enterprise Group Incorporated | Documents Incorporated by Reference | |
| | ||
| III | Portions of the definitive Proxy Statement for the Annual Meeting of Stockholders of Public Service Enterprise Group | |
| Incorporated to be held April 15, 2003, which definitive Proxy Statement is expected to be filed with the Securities and | ||
| Exchange Commission on or about March 7, 2003, as specified herein. |
| TABLE OF CONTENTS | |||
| |
|||
| Page | |||
| PART I | |||
| Item 1. | Business | 1 | |
| General | 1 | ||
| Competitive Environment | 11 | ||
| Regulatory Issues | 12 | ||
| Customers | 18 | ||
| Employee Relations | 19 | ||
| Segment Information | 19 | ||
| Environmental Matters | 19 | ||
| Item 2. | Properties | 26 | |
| Item 3. | Legal Proceedings | 38 | |
| Item 4. | Submission of Matters to a Vote of Security Holders | 40 | |
| PART II | |||
| Item 5. | Market for Registrant’s Common Equity and Related Stockholder Matters | 41 | |
| Item 6. | Selected Financial Data | 42 | |
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 44 | |
| Overview of 2002 and Future Outlook | 44 | ||
| Results of Operations | 51 | ||
| Liquidity and Capital Resources | 65 | ||
| Capital Requirements | 72 | ||
| Accounting Issues | 75 | ||
| Forward Looking Statements | 82 | ||
| Item 7A. | Qualitative and Quantitative Disclosures About Market Risk | 84 | |
| Item 8. | Financial Statements and Supplementary Data | 90 | |
| Financial Statement Responsibility | 91 | ||
| Independent Auditors’ Report | 95 | ||
| Consolidated Financial Statements | 99 | ||
| Notes to Consolidated Financial Statements | 118 | ||
| Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 193 | |
| PART III | |||
| Item 10. | Directors and Executive Officers | 193 | |
| Item 11. | Executive Compensation | 197 | |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management | 202 | |
| Item 13. | Certain Relationships and Related Transactions | 203 | |
| Item 14. | Disclosure Controls and Procedures | 204 | |
| PART IV | |||
| Item 15. | Exhibits, Financial Statement Schedules and Reports on Form 8-K | 213 | |
| Schedule II—Valuation and Qualifying Accounts | 215 | ||
| Signatures | 217 | ||
| Exhibit Index | 221 | ||
i
PART I
This combined Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and its subsidiaries and makes no other representations whatsoever as to any other company.
ITEM 1. BUSINESS
GENERAL
PSEG, PSE&G, Power and Energy Holdings
PSEG, incorporated under the laws of the State of New Jersey on July 25, 1985, with its principal executive offices located at 80 Park Plaza, Newark, New Jersey 07102, is an exempt public utility holding company under the Public Utility Holding Company Act of 1935 (PUHCA).
PSEG has four principal direct wholly-owned subsidiaries: PSE&G, Power, Energy Holdings and PSEG Services Corporation (Services). The following organization chart shows PSEG and its principal subsidiaries, as well as the principal operating subsidiaries of Power: PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T); and of Energy Holdings: PSEG Global Inc. (Global) and PSEG Resources LLC (Resources):
The regulatory structure which has historically governed the electric and gas utility industries in the United States has changed dramatically in recent years and continues to be in transition. Deregulation is essentially complete in New Jersey and is complete or underway in certain other states in the Northeast and across the United States (US). States have acted independently to deregulate the electric and gas utility industries. Experience in deregulating California, with energy shortages, high costs and financial difficulties of utilities and high profile bankruptcies have caused some states to re-evaluate and, in some cases, stop the move toward deregulation. The deregulation and restructuring of the nation’s energy markets, the unbundling of energy and related services, the diverse strategies within the industry related to holding, building, buying or selling generation capacity and the anticipated resulting industry consolidation have had, and are likely to continue to have, a profound effect on PSEG and its subsidiaries, providing it with new opportunities and exposing it to new risks. For further information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation (MD&A) — Overview of 2002 and Future Outlook.
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The National Energy Policy Act of 1992 (Energy Policy Act) laid the groundwork for competition in the wholesale electricity markets in the United States. This legislation expanded the Federal Energy Regulatory Commission’s (FERC) authority to order electric utilities to open their transmission systems to allow third-party suppliers to transmit, or “wheel,” electricity over their lines. In 1996, FERC initiated regulatory actions that resulted in expanded access to transmission lines, providing eligible third-party wholesale marketers clear transmission access. These actions have afforded power marketers, merchant generators, Exempt Wholesale Generators (EWGs) and utilities the opportunity to compete actively in wholesale energy markets, and afforded consumers the right to choose their energy suppliers.
Worldwide energy industry deregulation, restructuring, privatization and consolidation are creating opportunities and risks for PSEG, PSE&G, Power and Energy Holdings. Over recent years, PSEG has realigned its organizational structure to address the competitive environment brought about by the deregulation of the electric generation industry and has transitioned from primarily being a regulated New Jersey utility to operating as a competitive energy company with operations primarily in the Northeastern US and in other select domestic and international markets. As the unregulated portion of the business continues to grow, financial risks and rewards will be greater, financial requirements will change and the volatility of earnings and cash flows will increase. As of December 31, 2002, Power, PSE&G, and Energy Holdings comprised approximately 27%, 48% and 27% of PSEG’s consolidated assets and contributed approximately 60%, 26% and 18% of PSEG’s results, excluding certain charges. For additional information, see Item 7. MD&A — Overview of 2002 and Future Outlook.
PSE&G and Power
Following the enactment of the New Jersey Electric Discount and Energy Competition Act, as amended (Energy Competition Act), the New Jersey Board of Public Utilities (BPU) rendered its Final Decision and Order (Final Order) in 1999 relating to PSE&G’s rate unbundling, stranded costs and restructuring proceedings providing, among other things, for the transfer to an affiliate of all of PSE&G’s electric generation facilities, plant and equipment for $2.4 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, pursuant to the Final Order, transferred its electric generating facilities and wholesale power contracts to Power and its subsidiaries in August 2000 for $2.8 billion.
Subsequently, Power entered into a BPU approved fixed price requirements contract (Basic Generation Service (BGS) contract) to supply all of PSE&G’s load requirement for its electric customers not choosing an alternative supplier, which terminated on July 31, 2002, under which Power sold energy directly to PSE&G which in turn sold this energy to its customers. Subsequent to July 31, 2002, Power primarily sells its energy and capacity to third parties that supply New Jersey’s electric distribution companies (EDCs) participating in the BPU approved BGS auctions in New Jersey. PSE&G purchases the energy required to meet its customers’ needs from third party suppliers through such auction process.
BGS Supply
PSE&G is required to determine BGS suppliers by competitive bid in accordance with BPU requirements. In February 2002, an internet auction was held to determine who would supply BGS to PSE&G and the other three BPU regulated New Jersey electric utility companies for the period August 1, 2002 to July 31, 2003. As conditions of qualification to participate in this auction, energy suppliers agreed to execute the BGS Master Service Agreement and provide required security bonds within two days of BPU Certification of auction results, in addition to satisfying BPU credit worthiness requirements.
In February 2002 the BPU approved the BGS auction results and PSE&G secured contracts from a number of suppliers for its expected peak load of 9,600 MW through 96 notional tranches of 100 MW each. Under these contracts, the suppliers have the full load serving responsibility and bear the risks of volatility in energy prices due to various factors such as changes in weather, seasonality and transmission constraints. Subsequently, certain BGS suppliers experienced adverse credit issues and therefore, these suppliers assigned contracts to other parties. Under the BPU approved supply contracts, PSE&G is paying $.0511 per kWh to obtain electricity for BGS customers for the period from August 1, 2002 to July 31, 2003. Customers will continue to pay below-market regulated rates (BGS shopping credit) for this one-year period. Under PSE&G’s current rate structure, the difference is being
2
deferred and is expected to be recovered with interest through a future securitization. PSE&G estimates that the underrecovery relating to the BGS for the one-year period ending July 31, 2003 will amount to approximately $241 million.
As a result of the initial New Jersey BGS auction, Power contracted to provide energy to the direct suppliers of New Jersey electric utilities, including PSE&G, commencing August 1, 2002. Subsequently, a portion of the contracts with those bidders was reassigned to Power. Therefore, for a limited portion of the New Jersey retail load, Power will be a direct supplier to one utility, although this utility is not PSE&G.
New Jersey’s EDCs, including PSE&G, will provide two types of BGS service beginning in August 2003. The BPU authorized two concurrent auctions of New Jersey’s Basic Generation Service which were held in February 2003. The first was a general auction to procure approximately 15,500 MW of supply for ten-month and 34-month periods for smaller commercial and residential customers at seasonally-adjusted fixed prices. The other auction was held to procure approximately 2,600 MW of supply for larger customers for a 10-month period at hourly market prices. In total, the EDCs sought and obtained over 18,000 MW of combined full-requirements electric service. In February 2003, the BPU approved the auction results and PSE&G secured contracts from a number of suppliers to meet its requirements. Under the contracts, PSE&G is paying $.05386 and $.05560 per kWh for the ten-month tranche and 34-month tranche, respectively, to obtain electricity for customers for the periods beginning August 1, 2003.
Power was a participant in the BGS auction held in February 2003. Power entered into hourly energy price contracts to be a direct supplier of certain large customers for a ten-month period beginning August 1, 2003. Power also entered into contracts with third parties who are direct suppliers of New Jersey’s EDCs. Through these seasonally-adjusted fixed price contracts, Power will indirectly serve New Jersey’s smaller commercial and residential customers for ten-month and 34-month periods beginning August 1, 2003. Power believes that its obligations under these contracts are reasonably balanced by its available supply.
BGSS
On April 17, 2002, the BPU issued the Final Order approving the transfer of PSE&G’s gas supply business. Pursuant to such order, in May 2002, PSE&G transferred its gas supply contracts and gas inventory to Power for approximately $183 million and similarly, entered into a requirements contract with Power under which Power sells gas supply services directly to PSE&G needed to meet PSE&G’s Basic Gas Supply Service (BGSS) requirements. The contract term ends March 31, 2004, after which PSE&G has a three-year renewal option. As part of the agreement, PSE&G is providing Power the use of its peak shaving facilities at cost.
On May 1, 2002, the New Jersey Ratepayer Advocate filed a motion for the reconsideration of the BPU’s approval of the gas contract transfer. On October 31, 2002, the BPU issued an order denying the motion for reconsideration, except for the issue of valuation. The BPU retains the right to review the valuation of the contracts transferred if FERC modifies the capacity release rules prior to the contract expirations.
PSE&G
PSE&G is a New Jersey corporation, incorporated on July 25, 1924, with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. PSE&G is an operating public utility company engaged principally in the transmission and distribution of electric energy and gas service in New Jersey. PSE&G continues to own and operate its electric and gas transmission and distribution business. PSE&G Transition Funding LLC (Transition Funding), a bankruptcy remote subsidiary of PSE&G, was formed solely to issue $2.525 billion principal amount of transition bonds in connection with the securitization of $2.4 billion of PSE&G’s approved stranded costs approved for recovery by the BPU under the Energy Competition Act.
PSE&G supplies electric and gas service in areas of New Jersey in which approximately 5.5 million people, about 70% of the State’s population, reside. PSE&G’s electric and gas service area is a corridor of approximately 2,600 square miles running diagonally across New Jersey from Bergen County in the northeast to an area below the city of Camden in the southwest. The greater portion of this area is served with both electricity and gas, but some parts are served with electricity only and other parts with gas only. This heavily populated, commercialized and
3
industrialized territory encompasses most of New Jersey’s largest municipalities, including its six largest cities—Newark, Jersey City, Paterson, Elizabeth, Trenton and Camden—in addition to approximately 300 suburban and rural communities. This service territory contains a diversified mix of commerce and industry, including major facilities of many corporations of national prominence. PSE&G’s load requirements are almost evenly split among residential, commercial and industrial customers. PSE&G believes that it has all the franchises (including consents) necessary for its electric and gas distribution operations in the territory it serves. Such franchise rights are not exclusive.
PSE&G distributes electric energy and gas to end-use customers within its designated service territory. All electric and gas customers in New Jersey have the ability to choose an electric energy and/or gas supplier. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric and gas customers within its service territory who do not choose an alternate supplier. PSE&G earns no margin on the commodity portion of its electric and gas sales. PSE&G earns margins through the transmission and distribution of electricity and gas. PSE&G’s revenues are based upon tariffs approved by the BPU and the FERC for these services. The demand for electric energy and gas by PSE&G’s customers is affected by customer conservation, economic conditions, weather and other factors not within its control. Rates for gas sold in interstate commerce are not subject to cost of service ratemaking but are subject to competitive pricing. See Regulatory Issues and Item 7. MD&A, for a further discussion of these matters.
Power
Power is a Delaware limited liability company, formed on June 16, 1999, with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Power is a multi-regional, independent wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management function with three principal direct wholly-owned subsidiaries: Nuclear, which owns and operates nuclear generating stations, Fossil, which develops, owns and operates domestic fossil generating stations and ER&T, which markets the capacity and production of Fossil’s and Nuclear’s stations and manages the commodity price risks or market risks related to generation. Power’s subsidiary, PSEG Power Capital Investment Company (Power Capital), provides certain financing for Power’s subsidiaries.
Power’s target market, which it refers to as the Super Region, extends from Maine to the Carolinas and from the Atlantic Coast to Indiana, encompassing 36% of the nation’s power consumption. Power is the single largest power supplier in its primary market, the PJM Interconnection area, one of the nation’s largest and most well developed energy markets.
Power’s generation portfolio consists of 13,055 MW of installed capacity which is diversified by fuel source and market segment. In addition, Power is currently constructing projects which are expected to increase capacity by over 2,900 MW through 2005, net of planned retirements. For additional information, see Item 2. Properties.
Power participates primarily in the PJM market, where the pricing of energy is based upon the locational marginal price (LMP) set through power providers’ bids. Because of transmission constraints, the LMP tends to be higher in congested areas reflecting the bid prices of the higher cost units that are dispatched to supply demand and alleviate transmission constraints when coordination is sufficient to satisfy demand within PJM. These bids are capped at $1,000 per megawatt-hour (MWh). In the event that available generation within PJM is insufficient to satisfy demand, PJM may institute emergency purchases from adjoining regions for which there is no price cap.
As Exempt Wholesale Generators (EWGs) under FERC, Power’s subsidiaries do not directly serve any retail customers. Power uses its generation facilities primarily for the production of electricity for sale at the wholesale level. For a discussion of BGS Supply in New Jersey, see PSE&G and Power above.
4
Electric Fuel Supply
The following table indicates MWh output of Power’s generating stations by source of energy in 2002 and the estimated MWh output by source for 2003:
| Actual | Estimated | ||||
| Source | 2002 | 2003 (A) | |||
| |
|||||
| Nuclear: | |||||
| New Jersey facilities | 41 | % | 38% | ||
| Pennsylvania facilities | 21 | % | 19% | ||
| Fossil: | |||||
| Coal: | |||||
| New Jersey facilities | 13 | % | 11% | ||
| Pennsylvania facilities | 13 | % | 12% | ||
| Connecticut facilities | — | 5% | |||
| Oil and Natural Gas: | |||||
| New Jersey facilities | 11 | % | 9% | ||
| New York facilities | — | — | |||
| Connecticut facilities | — | 3% | |||
| Mid-West facilities | — | 2% | |||
| Pumped Storage | 1 | % | 1% | ||
| |
|||||
| Total | 100 | % | 100% | ||
| (A) | No assurances can be
given that actual 2003 output by source will match estimates. | |
| Fossil
Fuel Supply | ||
| Fossil
has an ownership interest in twelve fossil generating stations in New Jersey,
one fossil generating station in New York, two fossil generating stations
in Connecticut and two fossil generating stations in Pennsylvania. Fossil
is also in the process of constructing a fossil generating station in Ohio
and another in Indiana. Fossil has an ownership interest in one hydroelectric
pumped storage facility in New Jersey. For additional information, see Item
2. Properties — Power — Electric Generation Properties. | ||
| Fossil
uses coal, natural gas and oil for electric generation. These fuels are
purchased through various contracts and in the spot market. The majority
of Power’s fossil generating stations obtain their fuel supply from
within the US. In order to minimize emissions levels, the Connecticut generating
facilities use a specific type of coal which is obtained from Indonesia.
Fossil does not anticipate any difficulties in obtaining adequate coal,
natural gas and oil supplies for these facilities over the next several
years, however, if the supply of coal from Indonesia or equivalent coal
from other sources was not available for the Connecticut facilities, additional
capital expenditures could be required to modify the existing plants. For
additional information, see Item 2. Properties — Power. | ||
| Nuclear
Fuel Supply | ||
| Nuclear
has an ownership interest in five nuclear generating units and operates
three of them; the Salem Nuclear Generating Station, Units 1 and 2 (Salem
1 and 2) each owned 57.41% by Nuclear and 42.59% by Exelon Generation LLC
(Exelon), and the Hope Creek Nuclear Generating Station (Hope Creek), 100%
owned by Nuclear. Exelon operates the Peach Bottom Atomic Power Station
Units 2 and 3 (Peach Bottom 2 and 3), each of which is 50% owned by Nuclear.
For additional information, see Item 2. Properties. | ||
| Power
has several long-term purchase contracts with uranium suppliers, converters,
enrichers and fabricators to meet the currently projected fuel requirements
for Salem and Hope Creek. On average, Power has various multi-year requirements-based
purchase commitments that total approximately $88 million per year to meet
Salem and Hope Creek fuel needs. Power has been advised by Exelon that it
has similar purchase contracts to satisfy the fuel requirements for Peach
Bottom. Nuclear does not anticipate any difficulties in obtaining adequate
fuel supplies for these facilities over the next several years. | ||
5 | ||
Gas Supply
As described above, Power sells gas to PSE&G. About 40% of the peak daily gas requirements are provided through firm transportation which is available every day of the year. The remainder comes from field storage, liquefied natural gas, seasonal purchases, contract peaking supply, propane and refinery/landfill gas. Following the gas contract transfer in May 2002, Power purchased gas for its gas operations directly from natural gas producers and marketers. These supplies were transported to New Jersey by four interstate pipeline suppliers.
Power has approximately 1.1 billion cubic feet per day of firm transportation capacity under contract to meet the primary needs of the gas consumers of PSE&G. In addition, Power supplements that supply with a total storage capacity of 81 billion cubic feet that provides .94 billion cubic feet per day of gas during the winter season.
Power expects to meet the energy-related demands of its firm customers during the 2002-2003 and 2003-2004 winter seasons. However, the sufficiency of supply could be affected by several factors not within Power’s control, including curtailments of natural gas by its suppliers, the severity of the winter weather and the availability of feedstocks for the production of supplements to its natural gas supply. The adequacy of supply of all types of gas is affected by the nationwide availability of all sources of fuel for energy production.
ER&T
ER&T purchases all of the capacity and energy produced by Fossil and Nuclear. In conjunction with these purchases, ER&T uses commodity and financial instruments designed to cover estimated commitments for BGS and other bilateral contract agreements. ER&T also markets electricity, capacity, ancillary services and natural gas products on a wholesale basis throughout the Super Region. ER&T is a fully integrated wholesale energy marketing and trading organization that is active in the long-term and spot wholesale energy markets.
ER&T’s principal objectives are to sell and deliver physical power from Power’s generating assets, reduce earnings volatility through hedging activities, manage gas supply and BGSS contracts, procure low cost fuel and natural gas supplies and produce net earnings from trading energy-related products around Power’s physical assets. ER&T does not engage in the practice of simultaneous trading for the purpose of increasing trading volume or revenue (also known as round trips). Consistent with its business objectives, ER&T measures performance based on net earnings and overall team performance, not on volume or gross revenues. These are also the metrics used to measure performance under its incentive compensation programs. For further information, see Note 12. Risk Management of the Notes to the Consolidated Financial Statements (Notes).
Energy Holdings
Energy Holdings is a New Jersey limited liability company formed on October 31, 2002, which merged wth PSEG Energy Holdings Inc., which was incorporated on June 20, 1989. Energy Holdings principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. Energy Holdings has two principal direct wholly-owned subsidiaries; Global and Resources. During the second quarter of 2002, Energy Holdings announced its intention to sell the businesses of PSEG Energy Technologies Inc. (Energy Technologies). See Note 5. Discontinued Operations of the Notes.
Global and Resources have more than 100 financial and operating investments. Energy Holdings has pursued investment opportunities in the rapidly changing global energy markets, with Global focusing on the operating segments of the electric industries and Resources primarily making financial investments in these industries.
6
Energy Holdings’ portfolio is diversified by number, type and geographic location of investments. As of December 31, 2002, assets were comprised of the following types:
| December 31, 2002 | ||
| Leveraged Leases (A) | 42 | % |
| International Electric Facilities | 20 | % |
| International Generation Plants | 22 | % |
| Domestic Generation Plants | 10 | % |
| Energy Services | 3 | % |
| Other Passive Financial Investments | 2 | % |
| Other | 1 | % |
(A) Leveraged Leases are primarily in energy related facilities and are discussed further under Resources.
The characteristics of each of these investment types are described in more detail below.
Global
Global is an independent power producer and distributor which develops, acquires, owns and operates electric generation, transmission and distribution facilities and is engaged in power production and distribution, including wholesale and retail sales of electricity, in selected domestic and international markets.
Global realized substantial growth prior to 2002, but has been faced with significant challenges as the electricity privatization model has experienced stress. These challenges include the Argentine economic, political and social crisis, recent issues in India, financial and political pressures in Brazil and Venezuela and the soft power market in Texas. A worldwide recession and a series of disruptive events have slowed privitization in many countries. See Item 7. MD&A — Overview of 2002 and Future Outlook for further details.
Generally, Global has sought to minimize risk in the development and operation of its generation projects by selecting partners with complementary skills, structuring long-term power purchase contracts, arranging financing prior to the commencement of construction and contracting for adequate fuel supply. Historically, Global’s operating affiliates have entered into long-term power purchase contracts, thereby selling the electricity produced for the majority of the project life. However, two plants in Texas and two plants in China operate as merchant plants without long-term power purchase contracts and a plant in Poland will likely do so as well. For a further discussion of the oversupply of energy in the Texas power market, see Item 7. MD&A — Future Outlook.
Fuel supply arrangements are designed to balance long-term supply needs with price considerations. Global’s project affiliates generally utilize long-term contracts and spot market purchases. Energy Holdings believes that there are adequate fuel supplies for the anticipated needs of its generating projects. Energy Holdings also believes that transmission access and capacity are sufficient at this time for its generation projects.
Global, to the extent practical, attempts to limit its financial exposure associated with each project and to mitigate development risk, foreign currency exposure, interest rate risk and operating risk, including exposure to fuel costs, through contracts. For a further discussion of these risks, see Item 7A. Qualitative and Quantitative Disclosures About Market Risk. In addition, project loan agreements are generally structured on a non-recourse basis. Further, Global generally structures project financing so that a default under one project’s loan agreement will have no effect on the loan agreements of other projects or Energy Holdings’ debt.
Global has ownership interests in 34 operating generation projects (excluding those in Argentina which were fully impaired in 2002) totaling 5,384 MW (2,476 MW net) and eight projects totaling 2,329 MW (1,042 MW net) in construction. Of Global’s generation projects in operation or construction, 1,449 MW net or 41% are located in the United States. Global is actively involved, through its joint ventures, in managing the operations of 28 operating generation projects and will be actively involved in managing the operations of 6 projects in construction.
Global has invested in four distribution companies (excluding those in Argentina which were fully impaired in 2002) which serve approximately 2.9 million customers in Brazil, Chile and Peru. Global is actively involved in
7
managing the operations of these distribution companies in accordance with shareholder agreements and/or operating contracts. Rate-regulated distribution assets represented 37% of Global’s assets, or $1.4 billion, as of December 31, 2002.
As of December 31, 2002, Global’s assets, which include consolidated projects and those accounted for under the equity method, and share of project MW, by region are as follows:
| 2002 | MW | |||
| (Millions) | ||||
| Generation | ||||
| North America | $ | 647 | 1,449 | |
| Latin America (1) | 359 | 247 | ||
| Asia Pacific | 148 | 738 | ||
| Europe (2) | 772 | 856 | ||
| India (3) | 200 | 228 | ||
| Distribution | ||||
| Latin America (1) | 1,391 | N/A | ||
| Other | ||||
| Other (4) | 285 | N/A | ||
| | ||||
| Total Assets | $ | 3,802 | 3,518 | |
| | ||||
| (1) | Investments in Argentina were fully impaired in 2002. | |
| (2) | Europe and Africa. | |
| (3) | India and the Middle East. The Tanir Bavi Power Company Ltd. (Tanir Bavi) plant in India was sold in October 2002. | |
| (4) | Assets not allocated
to a specific project, including corporate receivables. | |
| For
additional information, see Item 7. MD&A — Future Outlook. | ||
| Global’s
strategic focus has shifted to one of improving profitability for currently
held investments, from one of significant growth. Near-term emphasis will
be placed on liquidity and completing current projects. Global has developed
or acquired interests in electric generation and/or distribution facilities
in the United States, Brazil, Chile, China, India, Italy, Peru, Poland,
Tunisia and Venezuela. In addition, projects are in construction in the
United States, China, Italy, Oman, Poland, South Korea and Taiwan. While
Energy Holdings still expects certain of its investments in Latin America
to contribute significantly to its earnings in the future, the political
and economic risks associated with this region could have a material adverse
impact on its remaining investments in the region. See Item 7. MD&A
— Future Outlook for additional information. | ||
| For
a discussion of the asset impairments due to the Argentine economic, political
and social crisis, see Note 13. Commitments and Contingent Liabilities and
Note 4. Asset Impairments of the Notes. Also see Note 4. Asset Impairments
and Note 5. Discontinued Operations of the Notes for a discussion of Global’s
sale of Tanir Bavi located in India. | ||
For additional information on Global’s investments in generation and distribution facilities, see Item 2. Properties. Resources Resources invests
in energy-related financial transactions and manages a diversified portfolio
of assets, including leveraged leases, operating leases, leveraged buyout
funds, limited partnerships and marketable securities. Also, the Demand
Side Management (DSM) business previously managed by Energy Technologies
was transferred | ||
8 | ||
to Resources as of December 31, 2002. Since it was established in 1985, Resources has grown its portfolio to include more than 60 separate investments. Resources expects to curtail its investment activity in the near-term.
DSM revenues are earned principally from monthly payments received from utilities, which represent shared electricity savings from the installation of the energy efficient equipment. For further discussion of the transfer of DSM to Resources, see Note 22. Related-Party Transactions of the Notes.
The major components of Resources’ investment portfolio as a percent of its total assets as of December 31, 2002 were:
| As of December 31, 2002 | |||||
| Amount | %
of Resources’ Total Assets |
||||
| (Millions) | |||||
| Leveraged Leases | |||||
| Energy-Related | |||||
| Foreign | $ | 1,181 | 38 | % | |
| Domestic | 1,272 | 41 | % | ||
| Real Estate – Domestic | 192 | 6 | % | ||
| Aircraft | |||||
| Foreign | 44 | 2 | % | ||
| Domestic | 61 | 2 | % | ||
| Commuter Railcars – Foreign | 86 | 3 | % | ||
| Industrial – Domestic | 8 | — | |||
| |
|
||||
| Total Leveraged Leases, net | 2,844 | 92 | % | ||
| |
|
||||
| Limited Partnerships | |||||
| Leveraged Buyout Funds | 93 | 3 | % | ||
| Other | 25 | 1 | % | ||
| |
|
||||
| Total Limited Partnerships | 118 | 4 | % | ||
| |
|
||||
| Marketable Securities | 5 | — | |||
| Other Investments | 33 | 1 | % | ||
| Owned Property | 59 | 2 | % | ||
| Current and Other Assets | 27 | 1 | % | ||
| |
|
||||
| Total Resources’ Assets | $ | 3,086 | 100 | % | |
| |
|
||||
As of December 31, 2002, no single investment represented more than 7.5% of Resources’ total assets.
Leveraged Lease Investments
Resources seeks a portfolio that provides a fixed rate of return, predictable income and cash flow and depreciation and amortization deductions for federal income tax purposes. Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as revenues as these events occur in the ordinary course of business of managing the investment portfolio.
In a leveraged lease, the lessor acquires an asset by investing equity representing approximately 15% to 20% of the cost and incurring non-recourse lease debt for the balance. The lessor acquires economic and tax ownership of the asset and then leases it to the lessee for a period of time no greater than 80% of its remaining useful life. As the owner, the lessor is entitled to depreciate the asset under applicable federal and state tax guidelines. In addition, the lessor receives income from lease payments made by the lessee during the term of the lease and from tax receipts associated with interest and depreciation deductions with respect to the leased property. Lease rental payments are unconditional obligations of the lessee and are set at levels at least sufficient to service the non-recourse lease debt. The lessor is also entitled to any residual value associated with the leased asset at the end of the
9
lease term. An evaluation of the after-tax cash flows to the lessor determines the return on the investment. Under generally accepted accounting principles, the lease investment is recorded on a net basis and income is recognized as a constant return on the net unrecovered investment.
Resources evaluates lease investment opportunities with respect to specific risk factors. Any future leveraged lease investments are expected to be made in energy-related assets. For further information relating to the curtailment of Energy Holdings’ investments in the near term, see Item 7. MD&A – Overview. The assumed residual value risk, if any, is analyzed and verified by third-parties at the time the investment is made. Credit risk is assessed and, if necessary, mitigated or eliminated through various structuring techniques, such as defeasance mechanisms and letters of credit. Resources does not take currency risk in its cross-border lease investments. Transactions are structured with rental payments denominated and payable in US Dollars. Resources, as a passive lessor or investor, does not take operating risk with respect to the assets it owns, so leases are structured with the lessee having an absolute obligation to make rental payments whether or not the assets operate. The assets subject to lease are an integral element in Resources’ overall security and collateral position. If such assets were to be impaired, the rate of return on a particular transaction could be affected. The operating characteristics and the business environment in which the assets operate are, therefore, important and must be understood and periodically evaluated. For this reason, Resources retains experts to conduct regular appraisals on the assets it owns and leases.
The ten largest lease investments for Resources as of December 31, 2002 were as follows:
| Investment | Description | Gross Investment Balances as of December 31, 2002 |
% of Resources’ Total Assets |
||||||||
|
|
|||||||||||
| (Millions) | |||||||||||
| Reliant | Three generating stations | $ | 221 | 7 | % | ||||||
| (Keystone, Conemaugh and | |||||||||||
| Shawville) | |||||||||||
| EME | Collins Electric Generation | 185 | 6 | % | |||||||
| Station | |||||||||||
| Seminole | Seminole Generation Station | 175 | 6 | % | |||||||
| Unit #2 | |||||||||||
| Dynegy | Two electric generating stations | 172 | 6 | % | |||||||
| EME | Two electric generating stations | 170 | 6 | % | |||||||
| (Powerton and Joliet) | |||||||||||
| ENECO | Gas distribution network | 141 | 5 | % | |||||||
| (Netherlands) | |||||||||||
| Grand Gulf | Nuclear generating station | 131 | 4 | % | |||||||
| Merrill Creek | Merrill Creek Reservoir Project | 129 | 4 | % | |||||||
| ESG | Electric distributing system | 108 | 3 | % | |||||||
| (Austria) | |||||||||||
| EZH | Electric generating station | 107 | 3 | % | |||||||
| (Netherlands) | |||||||||||
| $ | 1,539 | 50 | % | ||||||||
For further details on leases, see Item 7A. Qualitative and Quantitative Disclosures About Market Risk-Credit Risk-Energy Holdings.
Energy Technologies
Energy Technologies is an energy management company whose primary objective was to construct, operate and maintain heating, ventilating and air conditioning (HVAC) systems for and provide energy-related engineering, consulting and mechanical contracting services to industrial and commercial customers in the Northeastern and
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Middle Atlantic United States. In June 2002, Energy Holdings adopted a plan to sell its interests in these HVAC/mechanical operating companies. The sale of these companies is expected to be completed by June 30, 2003. For more details, see Note 5. Discontinued Operations of the Notes and Item 7. MD&A — Results of Operations — Discontinued Operations — Energy Technologies.
Other Subsidiaries
Enterprise Group Development Corporation (EGDC), a commercial real estate property management business, has been conducting a controlled exit from the real estate business since 1993. EGDC’s strategy is to preserve the value of its assets to allow for the controlled disposition of its properties as favorable sales opportunities arise. EGDC directly owns a 100% interest in two parcels of land available for development located in New Jersey totaling $19 million. One of these parcels is classified as Assets Held for Sale. EGDC also owns an 80% general partnership interest in four partnerships which own and operate two buildings and land in New Jersey totaling $15 million. EGDC also owns a 100% interest in development land located in Maryland valued at $12 million. Together, the 100% wholly-owned land and the 80% general partnership interests represent 72% of the total assets of EGDC. Additionally, EGDC owns a 50% partnership interest in development land located in Virginia. Total assets of EGDC as of December 31, 2002 and 2001 were $63 million and $65 million, respectively.
PSEG Capital Corporation (PSEG Capital) has served as the financing vehicle, borrowing on the basis of a minimum net worth maintenance agreement with PSEG. As of December 31, 2002 PSEG Capital had debt outstanding of $252 million, which matures in May 2003, at which time the program will be terminated. For additional information including certain restrictions relating to the BPU Focused Audit, see Item 7. MD&A — Liquidity and Capital Resources.
Services
Services is a New Jersey Corporation with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Services provides management and administrative services to PSEG and its subsidiaries. These include accounting, legal, communications, human resources, information technology, treasury and financial, investor relations, stockholder services, real estate, insurance, risk management, tax, library and information services, security, corporate secretarial and certain planning, budgeting and forecasting services. Services charges PSEG, PSE&G, Power and Energy Holdings a fair market rate for services provided.
COMPETITIVE ENVIRONMENT
PSE&G
As a regulated monopoly, PSE&G’s electric and gas transmission and distribution business has minimal risks from competition. Also, there has been minimal financial impact on PSE&G’s transmission and distribution business due to customers choosing alternate electric or gas suppliers.
Power
Power primarily contracts to provide energy to the direct suppliers of New Jersey electric utilities. In recent years Power has expanded into other areas of its target market, the Super Region, with acquisitions in New York and Connecticut and development in the Midwest. As markets continue to evolve, several types of competitors have or will emerge in Power’s target market. These competitors include merchant generators with or without trading capabilities, other utilities that have formed generation and/or trading affiliates, aggregators, wholesale power marketers or combinations thereof. These participants will compete with Power and one another buying and selling in wholesale power pools, entering into bilateral contracts and/or selling to aggregated retail customers. These participants can also be expected to adapt to changing market conditions, including developing new generating stations where a perceived capacity shortfall may exist. Power believes that its asset size and location, regional market knowledge and integrated functions will allow it to compete effectively in its selected markets. However, actions by developers, including Power, to build new generating stations has lead to an overbuild situation, causing energy and capacity prices to be depressed and possibly making some of its units uneconomical. The Midwest
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market is expected to have excess capacity due to recent additions, which will negatively impact the expected returns of Power’s Lawrenceburg, Indiana and Waterford, Ohio facilities, presently under construction.
Additional legislation has been introduced within the last few years to further encourage competition at the retail level (often referred to as customer choice or retail access). No legislative proposal exists at the federal level. However, there is also a risk of re-regulation, if states decide to turn away from deregulation and allow regulated utilities to continue to own or reacquire and operate generating stations in a regulated and potentially uneconomical manner.
Power’s businesses are also under competitive pressure due to technological advances in the power industry and increased efficiency in certain energy markets. It is possible that advances in technology will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production.
Energy Holdings
Energy Holdings and its subsidiaries are subject to substantial competition in the US as well as in the international markets from independent power producers, domestic and multi-national utility generators, fuel supply companies, energy marketers, engineering companies, equipment manufacturers, well capitalized investment and finance companies and affiliates of other industrial companies. Energy Holdings faces competition from companies of all sizes, having varying levels of experience, financial and human capital and differing strategies. Competition can be based on a number of factors, including price, reliability of service, the ability of Energy Holdings’ customers to utilize other sources of energy and credit quality of lease investments and partners.
Many states and countries are considering or implementing different types of regulatory and privatization initiatives that are aimed specifically at increasing competition in the power industry. The increased competition that has resulted from some of these initiatives, combined with certain overbuild situations, has contributed to a reduction in electricity prices in some markets, and puts pressure on Energy Holdings and other electric utilities to lower costs. Achieving and maintaining a lower cost of production will be increasingly important to compete effectively in the energy business. In the Texas market, excess capacity has led to uneconomical energy pricing, negatively effecting two generating stations in Texas. For additional information regarding the Texas power market, see Item 7. MD&A — Future Outlook.
Energy Holdings’ businesses are also under competitive pressure due to technological advances in the power industry and increased efficiency in certain energy markets. It is possible that advances in technology will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production.
REGULATORY ISSUES
State Regulation
PSEG, PSE&G, Power and Energy Holdings
Focused Audit
In 1992, the BPU conducted a Focused Audit of the impact of PSEG’s non-utility businesses, owned by Energy Holdings, on PSE&G. Among other things, the BPU ordered that PSEG not permit Energy Holdings’ investments to exceed 20% of PSEG’s consolidated assets without prior notice to the BPU. In the Final Order issued in 1999, the BPU noted that, due to significant changes in the industry and, in particular PSEG’s corporate structure as a result of the Final Order, modifications to or relief from the BPU’s Focused Audit order might be warranted. PSE&G has notified the BPU that PSEG will eliminate PSEG Capital debt by the end of the second quarter of 2003 and that it believes that the Final Order otherwise supercedes the requirements of the Focused Audit. While, PSE&G and Energy Holdings believe that this issue will be satisfactorily resolved, no assurances can be given.
Affiliate Standards
In February 2000, the BPU approved affiliate standards and fair competition standards which apply to transactions between a public utility and those of its affiliates that provide competitive services to retail customers in New Jersey. In March 2000, the BPU issued a written order related to these matters. PSE&G filed a compliance plan in June 2000 to describe the internal policy and procedures necessary to ensure compliance with such Affiliate Standards. On February 8, 2002 and March 7, 2002, the BPU issued orders adopting the Competitive Service Audit reports on New Jersey’s electric and gas utilities. The audit report generally concluded that PSE&G was in compliance with the BPU’s affiliate standards. On July 1, 2002, PSE&G filed its Affiliate Standards compliance plan in accord with the BPU’s regulations. Also in July 2002, the BPU commenced its next regular audit of the state’s electric and gas utilities’ competitive activities. The objectives of these audits are to assure that neither the utilities nor their related competitive business segments enjoy an unfair competitive advantage over their competitors and to assure that there is no form of cross-subsidization of competitive services by utility operations or affiliates with which they are associated. The audits will be guided by the BPU’s Affiliate Standards requirements. A report is expected to be issued in the first quarter of 2003. The outcome cannot be determined at this time.
PSEG, Power and Energy Holdings
PSEG, Power and Energy Holdings’ affiliates are not subject to direct regulation by the BPU, except potentially with respect to certain asset sales, transfers of control, reporting requirements and affiliate standards.
PSE&G
As a New Jersey public utility, PSE&G is subject to comprehensive regulation by the BPU including, among other matters, regulation of intrastate rates and service and the issuance and sale of securities. As a participant in the ownership of certain transmission facilities in Pennsylvania, PSE&G is subject to regulation by the Pennsylvania Public Utility Commission (PPUC) in limited respects in regard to such facilities.
Electric Base Rate Case
On May 24, 2002, PSE&G filed an electric rate case with the BPU requesting an annual $250 million rate increase for its electric distribution business. The proposed rate increase includes $187 million of increased revenues relating to a $1.7 billion increase in PSE&G’s rate base, which is primarily due to the investment that PSE&G has made in its electric distribution facilities since its last rate case in 1992; $18 million in higher depreciation rates and $45 million to recover various other expenses, such as wages, fringe benefits and enhancements to security and reliability. The requested increase proposes a return on equity of 11.75% for PSE&G’s electric distribution business.
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The proposed rate increase would significantly impact PSE&G’s earnings and operating cash flows. The non-depreciation portion of the noticed rate increase ($232 million) would have a positive effect on PSE&G’s earnings and operating cash flows. The depreciation portion of the rate increase ($18 million) would have no impact on PSE&G’s earnings, as the increased operating cash flows would be offset by higher depreciation charges.
In October 2002, the New Jersey Ratepayer Advocate and other parties filed testimony, with the Ratepayer Advocate recommending rate relief of approximately $87 million. Included in the Ratepayer Advocate’s position is a 9.50% return on equity compared to PSE&G’s requested 11.75% (approximately $45 million), a reduction in electric distribution depreciation expenses (approximately $100 million), and numerous other adjustments to PSE&G’s filing. The BPU has consolidated PSE&G’s service company filing relating to the transfer of certain assets from PSE&G to Services and its Street Lighting Tariff filing, which adjusts tariff levels for electricity for certain street lights, into the base rate proceeding for disposition.
In accordance with BPU’s Final Order implementing parts of the Energy Competition Act, PSE&G was required to provide temporary billing discounts in four steps totaling 13.9% during the four-year transition period ending July 31, 2003. The last step, a 4.9% decrease, took effect August 1, 2002. The combined effects of base rate relief, the BGS auction and amortization of various deferral balances, discussed below, is expected to yield rates comparable to those in effect at the beginning of the deregulation process. Neither PSEG nor PSE&G can predict the outcome of these rate proceedings at the current time. Discussions are continuing and hearings were held with an initial decision scheduled to be issued by May 1, 2003. The new rates are proposed to be effective August 1, 2003, consistent with the Final Order.
Non-Utility Generation (NUG) Contract Amendments
In June 2002, PSE&G announced that it had amended its NUG power purchase agreements with El Paso Corporation (El Paso) for its Camden, Bayonne and Eagle Point cogeneration facilities. El Paso paid PSE&G $167 million for the amendment and agreed to provide specified amounts of electric energy and capacity to PSE&G at a fixed price and obtain this energy and capacity either from existing plants or in the open market. The amended agreement has been approved by the BPU.
Deferral Proceeding
In August 2002, PSE&G filed a petition proposing changes to two components of its rates, the Societal Benefits Clause (SBC) and the Non-Utility Generation Transition Charge (NTC). The proposed result, if adopted, will result in an annual reduction of revenues of approximately $122 million or approximately a 3.4% reduction in amounts paid by customers effective on August 1, 2003. The case has been transferred to the Office of Administrative Law and a pre-hearing conference was held October 24, 2002. PSE&G cannot predict the outcome of this matter.
Deferral Audit
In September 2002, the BPU retained the services of two outside firms to conduct a review of New Jersey’s electric utilities’ deferred costs for compliance with BPU mandates. Audit work has been completed and a final draft report was filed with the BPU on December 16, 2002, with PSEG responding on December 30, 2002. Formal comments on the final report are to be incorporated in the Deferral Proceedings, discussed above.
PSE&G believes that the final report will support its current practices and not impact its financial position or results of operations.
13
Gas Base Rate Case and Commodity Charges
In January 2002, the BPU issued an order approving a settlement of PSE&G’s Gas Base Rate case under which PSE&G is receiving an additional $90 million of gas base rate revenues, approximately $8 million of which results from gas depreciation rate changes. This occurred simultaneously with PSE&G’s implementation of its previously approved Gas Cost Underrecovery Adjustment (GCUA) surcharge to recover the October 31, 2001 gas cost underrecovery balance of approximately $130 million over a three-year period with interest and with PSE&G’s reduction of its 2001-2003 Commodity Charges (formerly LGAC) by approximately $140 million. As a result of the settlement, PSE&G agreed not to request another gas base rate increase that would take effect prior to September 1, 2004.
The $130 million rate increase relating to the recovery of the GCUA over three years has no impact on earnings, however it will increase operating cash flows in a normal business environment. The reduction in PSE&G’s 2001–2003 commodity charges relates to its residential customers and will have no impact on earnings and will decrease operating cash flows assuming current cost levels and a normal business environment.
BGSS Filing
In September 2002, PSE&G filed to increase its Residential BGSS Commodity Charge on November 1, 2002 to recover approximately $89 million in additional revenues ($82 million of which is associated with an underrecovered balance) or a 7.4% rate increase for the typical residential gas heating customer. On January 8, 2003, the BPU approved the increase on a provisional basis, to be effective immediately and the case has been transferred to the Office of Administrative Law for hearings.
BGSS Design
On December 18, 2002, the BPU approved BGSS Commodity filing procedure changes based upon the form of generic settlement negotiated by the parties. An annual filing will be made each year by June 1 for rate relief expected by October 1. That rate relief may be supplemented by two potential self-implementing rate increases to the maximum of 5% of the residential customer’s bill on December 1st and February 1st. All increases will be reconciled in the annual filing. As a result of the delay in the implementation of the BGSS increase discussed above, PSE&G has filed for a 5% self-implementing rate increase to be effective on March 1, 2003 which would reduce the expected underrecovery from $61 million to $37 million. PSE&G cannot predict the outcome of this matter.
Federal Regulation
PSEG, PSE&G, Power and Energy Holdings
Public Utility Holding Company Act of 1935 (PUHCA)
PSEG has claimed an exemption from regulation by the Securities and Exchange Commission (SEC) as a registered holding company under the PUHCA, except for Section 9(a)(2), which relates to the acquisition of 5% or more of the voting securities of an electric or gas utility company. Fossil and Nuclear are (EWGs) and Global’s
14
investments include EWGs and foreign utility companies (FUCOs) under PUHCA. Failure to maintain status of these plants as EWGs or FUCOs could subject PSEG and its subsidiaries to regulation by the SEC under PUHCA.
If PSEG were no longer exempt under PUHCA, PSEG and its subsidiaries would be subject to additional regulation by the SEC with respect to their financing and investing activities, including the amount and type of non-utility investments. PSEG does not believe, however, that this would have a material adverse effect on it and its subsidiaries.
Other
PSE&G’s, Power’s and Energy Holdings’ domestic operations are subject to regulation by FERC with respect to certain matters, including interstate sales and exchanges of electric transmission, capacity and energy. PSE&G, Fossil, Nuclear and Global are also subject to the rules and regulations of the US Environmental Protection Agency (EPA), the US Department of Transportation (DOT) and the US Department of Energy (DOE). For information on environmental regulation, see Environmental Matters.
FERC
Regional Transmission Organization (RTO) Orders
In July 2002, the United States Court of Appeals, D.C. Circuit, issued an opinion in favor of PSE&G and certain other utility petitioners, reversing a previous order of the FERC relating to the restructuring of PJM into an Independent System Operator (ISO). The court ruled that FERC lacked authority to require the utility owners to give up certain statutory rights and should not have required a modification to the PJM ISO Agreement eliminating utility owners rights to file changes to rate design. The Court further noted that FERC lacked authority to require the utility owners to obtain approval of their withdrawal from the PJM ISO, finding that FERC had no jurisdiction to eliminate the withdrawal rights to which the utilities had agreed. Further, in ruling on a specific argument raised by PSE&G, the Court held that PSE&G did not have to modify a contract with Old Dominion Electric Cooperative to accommodate the PJM restructuring. See Note 13. Commitments and Contingent Liabilities of the Notes for additional information.
On remand, in December 2002, FERC refused to disclaim jurisdiction over a transmission owner’s withdrawal from an ISO. In January 2003, PSE&G together with several of the transmission owners filed for rehearing of the FERC decision. The potential outcome of this rehearing could have implications for FERC’s jurisdiction and authority to implement its standard market design, discussed below.
In January 2002, PJM and the Midwest ISO (MISO) announced that it had entered into negotiations to create a virtual uniform seamless market encompassing these two RTOs, shortly after the FERC granted RTO status to the MISO. PSE&G also is participating in a rate investigation by FERC into whether the “regional through-and-out rates” between MISO and PJM should be eliminated. The proceeding could result in lower rates paid by transmission customers. The impact of these developments on PSE&G, Power and Energy Holdings is uncertain because specific rules will not be known for some time and are subject to FERC approval, which cannot be assured.
In April 2002, PJM successfully implemented its “PJM West” expansion. Also, in December 2002, several major utilities in the Midwest and mid-atlantic area petitioned FERC to become transmission owners within PJM. Implementation of this filing would more than double the size of the current PJM region and would result in a market encompassing more than 153,000 MW of generation capacity and more than 128,000 MW of peak load. Portions of this expansion could become effective as early as Spring 2003 although a date for implementation cannot be determined with certainty even if the filing is accepted by FERC.
In December 2002, FERC granted full RTO status to PJM.
Standard Market Design
In July 2002, FERC issued a Notice of Proposed Rulemaking (NOPR) to create a Standard Market Design for the wholesale electricity markets in the United States. The NOPR seeks to improve the consistency of market rules
15
throughout the country, including issues related to reliability, market power concerns, transmission, pricing, congestion, governance and other issues. If adopted, standard market design could significantly affect transmission and generation operations in the various markets in which PSE&G, Power and Energy Holdings operate.
Other
FERC issued an advance NOPR seeking comments to help form the basis for a proposed rule to standardize power-plant interconnection requirements to ease market entry for new generation facilities. As part of the rulemaking, FERC also will reconsider its policy addressing how transmission owners treat the cost of system upgrades necessary to accommodate new generation, potentially resulting in a new methodology. The ultimate outcome of this rulemaking and its impact upon PSEG, PSE&G, Power and Energy Holdings cannot be predicted.
PJM also filed an alternative proposal to standardize its generator interconnection agreement and procedures within PJM. FERC accepted this proposal, which is currently in effect in PJM.
In January 2003, FERC also proposed a new transmission pricing policy that would give rate incentives to engage in certain transactions, including transfer of control of transmission facilities to a FERC-approved RTO; and joining an RTO but maintaining independence from market participants. FERC also proposed to award an incentive for new transmission facilities that are found appropriate pursuant to an RTO transmission planning process. The ultimate outcome of this proposal and its impact upon PSEG, PSE&G, Power and Energy Holdings cannot be predicted.
Power
Nuclear Regulatory Commission (NRC)
Operation of nuclear generating units involves continuous close regulation by the NRC. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstrations to the NRC that plant operations meet requirements are also necessary. The NRC has the ultimate authority to determine whether any nuclear generating unit may operate.
The NRC has issued orders to all nuclear power plants to implement compensatory security measures. Some of the requirements formalize a series of security measures that licensees had taken in response to advisories issued by the NRC in the aftermath of the September 11, 2001 terrorist attacks. Power has evaluated these orders for the Salem and Hope Creek facilities and does not expect the cost of implementation of the NRC measures to be material.
In accordance with NRC requirements, nuclear plants utilize various fire barrier systems to protect equipment necessary for the safe shutdown of the plant in the event of a fire. The NRC has identified certain issues at Salem and Power has made the majority of the necessary modifications to comply with these requirements, the cost of which was approximately $26 million for Power. Minor completion activities remain, the costs of which are not expected to be material.
Exelon has informed Power that, on July 3, 2001, an application was submitted to the NRC to renew the operating licenses for Peach Bottom 2 and 3. If approved, the current licenses would be extended by 20 years, to 2033 and 2034 for Peach Bottom 2 and 3, respectively. NRC review of the application is expected to take approximately two years.
In August 2002, the NRC issued a bulletin requiring that all operators of pressurized water reactor (PWR) nuclear unit submit certain information related to potential degradation of reactor vessel heads. In September 2002, Power provided the requested information for Salem. The response stated that a bare metal visual examination will be performed on the Salem reactor vessel heads during each unit’s next refueling outage, in compliance with the bulletin. If repairs are determined to be necessary, it is estimated that the repair would extend the outage by approximately four weeks. Bare metal visual inspections for Salem 1 and 2 were completed during 2002 and no degradation of the reactor heads was observed. On February 11, 2003 the NRC issued an order to all operators of PWR units concerning reactor vessel head inspections. The order confirms the previous bulletin’s
16
requirements of more intrusive and frequent future inspections, which apply to Salem 1 and 2. Power’s Hope Creek nuclear unit and the Peach Bottom 2 and 3 are unaffected as they are Boiling Water Reactor nuclear units. Power cannot predict what other actions the NRC may take on this issue.
Foreign Regulation
Energy Holdings
Global
Global’s electric distribution facilities in Latin America are rate-regulated enterprises. Rates charged to customers are established by governmental authorities and, excluding those rates at facilities in Argentina, which were fully impaired during 2002, are currently sufficient to cover all operating costs and provide a fair return in local currency terms. Global can give no assurances that future rates will be established at levels sufficient to cover such costs, provide a return on its investments or generate adequate cash flow to pay principal and interest on its debt or to enable it to comply with the terms of its debt agreements.
Brazil
Rio Grande Energia S.A. (RGE) is regulated by Agencia Nacional de Energia Eletrica (ANEEL), the national regulatory authority. ANEEL’s functions include granting and supervising electric utility concessions, approving electricity tariffs, issuing regulations and auditing distribution systems’ performance. The rate setting process for Brazilian distribution companies has two components, an annual adjustment which RGE applies for every April and which is embedded in the concession contract, and a rate revision which will be calculated for RGE in 2003 and every subsequent fifth year anniversary.
The current regulatory regime adjusts consumer electric tariffs based on a multiple-factor formula that includes recovery of wholesale inflation for previous periods, as well as an additional entitlement to pass through deferred US Dollar costs. This current regulatory structure would result in an increase of approximately 40% in the tariffs RGE would charge its customers starting in April 2003. ANEEL has issued a resolution indicating that new distribution tariffs will be calculated based on the replacement value of the electric utility companies’ assets, but has not yet determined the rate of return to be allowed on this asset base. In addition, current electric regulation also allows ANEEL to apply an additional upward or downward adjustment (known as the “X Factor”) to final tariff determinations in order to adjust expected financial returns on the replacement values of utility companies’ assets. The combination of these factors results in considerable uncertainty regarding future revenue and cash flow levels associated with Global’s investment in RGE. No assurances can be given that 2003 tariff increases will be approved on a timely basis or at a sufficient level to support planned levels of revenues and cash flows. For additional information, see Item 7. MD&A — Future Outlook.
ANEEL also monitors service quality by auditing the duration and frequency of outages, as well as several other performance measures. Global is implementing capital improvement budgets which attempt to meet the quality of service standards. Failure to meet required standards would result in penalties which, if assessed, would not be expected to have a material negative impact on RGE’s results of operations, although no assurances can be given.
RGE is currently engaged in a dispute with ANEEL which is seeking to mandate a reduction in RGE’s fixed asset base due to a pre-privatization review of Companhia Estadual de Energia’s (CEEE) asset base. This pre-privatization review was not brought to the attention of the bidders during the RGE privatization process. The result of such a decrease in RGE’s fixed asset base would be a likely reduction in RGE’s tariff of approximately $8 million during the next rate case as RGE’s return on fixed assets would be above the accepted level. RGE is currently contesting the matter.
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Chile
Distribution companies in Chile, including Chilquinta Energia S.A. (Chilquinta) and Sociedad Austral de Electricidad S.A. (SAESA), are subject to rate regulation by the Comision Nacional de Energia (CNE), a national governmental regulatory authority. The Chilean regulatory framework has been in existence since 1982, with rates set every four years based on a model company. The tariff which distribution companies charge to regulated customers consists of two components: the actual cost of energy purchased plus an additional amount to compensate for the value added in distribution (DVA tariff). The DVA tariff considers allowed losses incurred in the distribution of electricity, administrative costs of providing service to customers, costs of maintaining and operating the distribution systems and an annual real return on investment of 6% to 14%, based on the replacement cost of distribution assets. Changes in electricity distribution companies’ cost of energy are passed through to customers, with no impact on the distributors’ margins (equal to the DVA tariff). Therefore, distributors, including SAESA and Chilquinta, are not affected by changes in the generation sector which affect prices.
The most recent tariff adjustments for SAESA and Chilquinta occurred in 2000. The next tariff review is scheduled for 2004. The DVA tariff index provides for monthly adjustments based on variations in certain economic indicators whenever the component costs increase by more than 3% over prior levels. This index provides inflation adjustments and indirect partial devaluation protection. The CNE concluded a profitability review of Chilean distribution companies in January 2002, with no resulting adverse effects to SAESA or Chilquinta’s tariff rates. The CNE is in the process of conducting its annual profitability reviews (similar to the one recently completed) which may result in material adverse effects on tariffs for SAESA and/or Chilquinta.
Chile has implemented service quality standards and penalties; however, specific regulations have not yet been published. Quality of service limits were published in Peru and distribution companies are subject to penalties if these standards are not met. Global is implementing capital improvement budgets which attempt to meet these quality of service standards. Failure to meet required standards could result in penalties, which, if assessed, are not expected to have a material impact on the distribution system, although no assurances can be given.
Peru
Distribution companies in Peru, including Global’s facility, Luz del Sur, are subject to rate regulation by a national governmental regulatory authority. The Peruvian rate setting mechanism was established in 1992 and is similar to the Chilean system described above, except rates of return are between 8% and 16%. Rates are set every four years. The latest rate case was completed in 2001. The next regularly scheduled rate setting for Luz del Sur is in 2005.
CUSTOMERS
PSE&G
As of December 31, 2002, PSE&G provided service to approximately 2.0 million electric customers and approximately 1.6 million gas customers. PSE&G’s service territory contains a diversified mix of commerce and industry, including major facilities of many corporations of national prominence. PSE&G’s load requirements are almost evenly split among residential, commercial and industrial customers.
Power
Power sells energy to the wholesale market in the Super Region, primarily in PJM. In the recent New Jersey BGS auction, Power entered into hourly energy price contracts to be a direct supplier of certain large customers and entered into contracts with third parties who are direct suppliers of New Jersey’s EDCs.
Power currently has over 177 active trading counterparties, which have passed a rigorous credit analysis and contracting process. These include investor owned utilities, retail aggregators and marketers.
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Energy Holdings
Global
Global has ownership interests in four distribution companies (excluding those in Argentina which were fully impaired during 2002) which serve approximately 2.9 million customers and has developed or acquired interests in electric generation facilities which sell energy, capacity and ancillary services to numerous customers through power purchase agreements (PPAs) as well as into the wholesale market. For additional information on distribution customers, see Item 2. Properties—Energy Holdings—Electric Distribution Facilities.
EMPLOYEE RELATIONS
PSE&G, Power, Energy Holdings and Services believe that they maintain satisfactory relationships with their employees. For information concerning employee pension plans and other postretirement benefits, see Note 17. Pension, Other Postretirement Benefit and Savings Plans of the Notes.
PSE&G
As of December 31, 2002, PSE&G had 6,376 employees. PSE&G has three-year collective bargaining agreements in place with four unions, representing 4,927 employees, which expire on April 30, 2005.
Power
As of December 31, 2002, Power had 3,398 employees. Power has collective bargaining agreements, which expire on April 30, 2005, in place with three unions, representing 1,722 employees (901 employees, or approximately 68% of the workforce in Fossil and 821 employees, or approximately 44% of the workforce in Nuclear).
Energy Holdings
As of December 31, 2002, Energy Holdings had 2,109 employees. Energy Holdings had a total of 1,863 employees who are represented by various construction trade unions. Energy Technologies and its operating subsidiaries are parties to agreements with various trade unions through multi-employer associations.
Services
As of December 31, 2002, Services had 1,028 employees, none of which are unionized.
SEGMENT INFORMATION
Financial information with respect to the business segments of PSEG, PSE&G, Power and Energy Holdings is set forth in Note 19. Financial Information by Business Segments of the Notes.
ENVIRONMENTAL MATTERS
PSEG, PSE&G, Power and Energy Holdings
Federal, regional, state and local authorities regulate the environmental impacts of PSEG’s operations within the United States. Environmental impacts associated with PSEG’s operations in foreign countries are governed by laws and regulations particular to the region, country, or locality where these operations are located. For both domestic and foreign operations, areas of regulation may include air quality, water quality, site remediation, land use, waste disposal, aesthetics, impact on global climate, and other matters.
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Power and Energy Holdings
Air Pollution Control
Federal air pollution laws, such as the Federal Clean Air Act (CAA) and the regulations implementing those laws, require controls of emissions from sources of air pollution and also impose record keeping, reporting and permit requirements. Facilities in the US that Power and Energy Holdings operate or in which they have an ownership interest are subject to these Federal requirements, as well as requirements established under state and local air pollution laws applicable where those facilities are located. Except as noted below, capital costs of complying with air pollution control requirements through 2004 are included in Power’s estimate of construction expenditures in Item 7. MD&A.
Sulfur Dioxide (SO2)/Nitrogen Oxide (NOx)
To reduce emissions of SO2, the CAA sets a cap on total SO2emissions from affected units and allocates SO2 “allowances” (each allowance authorizes the emission of one ton of SO2) to those units. Generation units with emissions greater than their allocations can buy allowances from sources that have excess allowances. Similarly, to reduce emissions of NOx, Northeastern states and the District of Columbia have set a cap on total emissions of NOx from affected units and allocated NOx allowances (with each allowance authorizing the emission of one ton of NOx) to those units. The cap applies from May through September. The NOx allowances can be bought and sold through a regional trading program. In 2003, the cap will be reduced to limit NOx emissions further.
The EPA has issued regulations (commonly known as the SIP Call) requiring the 22 states in the eastern half of the United States to make significant NOx emission reductions from utility and industrial sources and subsequently cap these emissions. The EPA has delayed the implementation until May 31, 2004. The NOx reduction requirements are consistent with requirements already in place in New Jersey, New York, Connecticut and Pennsylvania, and therefore are not likely to have an additional impact on or change the capacity available from Power’s existing facilities. New facilities that Power is developing in Ohio and Indiana will be subject to rules that those states are expected to promulgate to comply with the SIP Call.
To comply with the SO2 and NOx requirements, affected units may choose one or more strategies, including installing air pollution control technologies, changing or limiting operations, changing fuels or obtaining additional allowances. At this time, Power does not expect to incur material expenditures to continue complying with the SO2 program. Beginning in 2003, the NOx cap will be reduced in New Jersey, New York, Pennsylvania, and other Northeastern states, which is expected to materially increase the cost of complying with the NOx program in those states. The extent of the increase across the region will depend upon a number of factors that may increase or decrease total NOx emissions from affected units, thus increasing or decreasing demand for a fixed supply of allowances. Power has been implementing measures to reduce NOx emissions at several of its units, which will reduce the impact of anticipated increases to the costs of allowances. For additional information regarding the costs of these credits, see Item 7. MD&A — Future Outlook.
In 1997, the EPA adopted a new air quality standard for fine particulate matter and a revised air quality standard for ozone. To attain the fine particulate matter standard, states may require further reductions in NOx and SO2. In 2002, the EPA announced that it would move forward with the process for identifying and designating areas of the United States that fail to meet the revised federal health standard for ozone or the new federal health standard for fine particulates. Designation of these areas is expected in 2004, with states expected to develop regulatory measures necessary to achieve and maintain the health standards thereafter. Additionally, similar NOx and SO2 reductions may be required to satisfy requirements of an EPA rule protecting visibility in many of the nation’s scenic areas, including some areas near Power’s facilities. States or the federal government may require additional reductions in NOx emissions from electric generating facilities as part of an effort to achieve the revised ozone standard.
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CO2 Emissions
In 2003, it is expected that the Kyoto Protocol will become effective. This treaty will require substantial reductions of CO2 and certain other greenhouse gases between 2008 and 2012. Although the US does not intend to ratify the treaty, Energy Holdings’ assets in Europe will be affected by implementation of the Kyoto Protocol, although the specific impacts will depend upon the regulations adopted by the European Union (EU) and nations looking to accede to the EU, such as Poland. At this juncture, costs or benefits to Energy Holdings’ investments in Europe cannot be quantified with certainty.
On January 11, 2002, Power announced a voluntary agreement that calls for a goal of reducing by December 31, 2005 the annual average CO2 emission rate of its fossil fuel fired electric generating units by 15% below the 1990 average annual CO2 emission rate of its New Jersey fossil fuel fired electric generating units. Fossil also made a $1.5 million grant to the New Jersey Department of Environmental Protection (NJDEP) to assist in the development of landfill gas projects and has pledged to make an additional grant equal to $1 per ton of CO2 emitted greater than the 15% goal, up to $1.5 million, if that reduction is not achieved.
There continues to be a debate within the US over the direction of domestic climate change policy. Congress is currently considering several bills that would impose mandatory limitation of CO2emissions for the domestic power generation sector, and several other states, primarily in the Northeastern US, are considering state-specific or regional legislation initiatives to stimulate CO2 emission reductions in the electric utility industry.
Other Air Pollutants
The CAA directed the EPA to study potential public health impacts of hazardous air pollutants (HAPs) emitted from electric utility steam generating units. In December 2000, the EPA announced its intent to regulate HAP emissions from coal-fired and oil-fired steam units and to develop “Maximum Achievable Control Technology” (MACT) standards for these units. The EPA plans to propose the MACT standards by December 2003 and promulgate a final rule by December 2004, with compliance to be required by December 2007.
Emissions of mercury appear to be a focus of EPA rule-making for regulating HAP’s from coal and oil-fired steam units. Several northeastern states also have expressed an interest in regulating these emissions, including those states in which Power owns and operates generation units. The impact on Power’s operations of federal or state regulation of these emissions is still unknown.
The EPA missed the May 2002 deadline for proposing HAP’s regulations for combustion turbines, triggering a provision of the CAA that requires states to set HAP’s limits on a case-by-case basis. In November 2002, the EPA proposed regulations for combustion turbines, with the stated goal of adopting final standards before companies would be required to fully engage the case-by-case standard setting process with their state environmental agencies. Power and Energy Holdings are currently assessing the impact of this rule proposal on their respective combustion turbines.
Power
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
In November 1999, the federal government announced the filing of lawsuits by several states against seven companies operating power plants in the Midwest and Southeast US, charging that 32 coal-fired plants in ten states violated the PSD/NSR requirements of the CAA. Generally, these regulations require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets in some circumstances when those sources undergo a “major modification,” as defined in the regulations. Various environmental and public interest organizations have given notice of their intent to file similar lawsuits. The Federal government is seeking to order these companies to install the best available air pollution control technology at the affected plants and to pay monetary penalties of up to $27,500 for each day of continued violation.
The EPA and the NJDEP issued a demand in March 2000 under the CAA requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal-fired units were implemented in accordance
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with applicable PSD/NSR regulations. Power completed its response to the information request in November 2000. In January 2002, Power reached an agreement with New Jersey and the federal governments to resolve allegations of noncompliance with federal and State of New Jersey PSD/NSR regulations. Under that agreement, over the course of 10 years, Power must install advanced air pollution controls that are designed to reduce emissions of NOx, SO2, particulate matter and mercury. The estimated cost of the program at the time of the settlement was $337 million to be incurred through 2011. Power also paid a $1.4 million civil penalty and has agreed to spend up to $6 million on supplemental environmental projects. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved the dispute over Bergen 2 regarding the applicability of PSD requirements and allowed construction of the unit to be completed and operation to commence.
Power has recently notified the EPA and the NJDEP that it is evaluating the continued operation of the Hudson coal unit beyond 2006, in light of changes in the energy and capacity markets and increases in the cost of pollution control equipment and other necessary modifications. A decision is expected to be made in 2003 as to the Hudson unit’s continued operation. The related costs associated with these modification have not been included in Power’s capital expenditure projections.
As previously noted, future environmental initiatives are expected to require reduced emissions of NOx, SO2, mercury, and possibly CO2 from electric generating facilities. The emission reductions to be achieved at the Hudson and Mercer coal units are expected to assist in complying with such future requirements.
Water Pollution Control
Power and Energy Holdings
The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to waters of the United States from point sources, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permit issued by the EPA or by a state under a federally authorized state program. The FWPCA authorizes the imposition of technology-based and water quality-based effluent limits to regulate the discharge of pollutants into surface waters and ground waters. The EPA has delegated authority to a number of state agencies, including the NJDEP, to administer the NPDES program through state acts. The New Jersey Water Pollution Control Act (NJWPCA) authorizes the NJDEP to implement regulations and to administer the NPDES program with EPA oversight, and to issue and enforce New Jersey Pollutant Discharge Elimination System (NJPDES) permits. PSEG also has ownership interests in domestic facilities in other jurisdictions that have their own laws and implement regulations to regulate discharges to their surface waters and ground waters that directly regulate Power’s facilities in these jurisdictions.
The EPA is conducting a rulemaking under FWPCA Section 316(b), which requires that cooling water intake structures reflect the best technology available (BTA) for minimizing “adverse environmental impact.” Phase I of the rule became effective on January 17, 2002. None of the projects that Power currently has under construction or in development is subject to the Phase I rule.
EPA published for public comment on April 9, 2002 proposed draft Phase II rules covering large existing power plants and is expected to issue final rules by February 16, 2004. The draft regulations propose to establish three means of demonstrating that a facility has the best technology available at an intake. The content of the final Phase II rules cannot be predicted at this time, although it is reasonable to expect that the rule will apply to all of Power’s steam electric and combined cycle units that use surface waters for cooling purposes. If the Phase II rules require retrofitting of cooling water intake structures at Power’s existing facilities to meet the specific or performance criteria, identified as an option under the draft rule, the retrofit would result in material costs of compliance.
Power
Permit Renewals
In June 2001, the NJDEP issued a renewal permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. Relating to the implementation of the renewal permit,
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Power has also reached a settlement with the Delaware Department of Natural Resources and Environmental Control (DNREC). As part of this agreement, Power deposited approximately $6 million into an escrow account to be used for future costs related to this settlement.
The NJDEP is in the process of reviewing the NJPDES permit renewal application for Power’s Hudson Station. The consultant hired by NJDEP recommended that the Hudson Station be retrofitted to operate with closed cycle cooling to address alleged adverse impacts associated with the thermal discharge and intake structure. Power prepared updated 316(a) and 316(b) demonstrations which proposed certain modifications to the intake structure and resubmitted these demonstrations to the NJDEP in 1998. Power believes that these demonstrations address the issues identified by the NJDEP’s consultant and provide an adequate basis for favorable determinations under the FWPCA without the imposition of closed cycle cooling, although no assurances can be given.
The NJDEP has advised Power that it is reviewing a NJPDES permit renewal application for the Mercer Station and, in connection with that renewal, will be reexamining the effects of the Mercer Station’s cooling water system pursuant to FWPCA. Power has submitted updated 316(a) and 316(b) demonstrations to the NJDEP.
It is impossible to predict the timing and/or outcome of the review of these applications in respect of the Hudson and Mercer Generation Stations. An unfavorable outcome could have a material adverse effect on Power’s financial position, results of operations and net cash flows. Power believes that the current operations of its stations are in compliance with FWPCA and will vigorously prosecute its applications to continue operations of its generating stations with present cooling water intake structures.
Capital costs of complying with water pollution control requirements through 2004 are included in Power’s estimate of construction expenditures in Item 7. MD&A — Capital Requirements.
Control of Hazardous Substances
PSEG, PSE&G, Power and Energy Holdings
Generators of hazardous substances potentially face joint and several liability, without regard to fault, when they fail to manage these materials properly and when they are required to clean up property affected by the production and discharge of such substances. Certain Federal and state laws authorize the EPA and the NJDEP, among other agencies, to issue orders and bring enforcement actions to compel responsible parties to investigate and take remedial actions at any site that is determined to present an actual or potential threat to human health or the environment because of an actual or threatened release of one or more hazardous substances.
PSE&G and Power
Other liabilities associated with environmental remediation include natural resource damages. The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and the New Jersey Spill Compensation and Control Act (Spill Act) authorize Federal and state trustees for natural resources to assess “damages” against persons who have discharged a hazardous substance, causing an “injury” to natural resources. Pursuant to the Spill Act, the NJDEP requires all persons conducting remediation to characterize “injuries” to natural resources and to address those injuries through restoration or damages. PSE&G and Power cannot assess the magnitude of the potential impact of this regulatory change. Although not currently estimable, these costs could be material.
Because of the nature of PSE&G’s and Power’s businesses, including the production of electricity, the distribution of gas and, formerly, the manufacture of gas, various by-products and substances are or were produced or handled that contain constituents classified by Federal and state authorities as hazardous. For discussions of these hazardous substance issues and a discussion of potential liability for remedial action regarding the Passaic River, see Note 13. Commitments and Contingent Liabilities of the Notes. For a discussion of remediation/clean-up actions involving PSE&G and Power, see Item 3. Legal Proceedings.
Passaic River Site
The EPA has determined that a nine mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under CERCLA and that, to date, at least thirteen corporations, including
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PSE&G, may be potentially liable for performing required remedial actions to address potential environmental pollution in the Passaic River facility.
In a separate matter, PSE&G and certain of its predecessors conducted industrial operations at properties within the Passaic River facility. The operations included one operating electric generating station, one former generating station, and four former MGPs. PSE&G’s costs to clean up former MGPs are recoverable from utility customers through the SBC. PSE&G has sold the site and obtained releases and indemnities for liabilities arising out of the site in connection with the sale. PSE&G cannot predict what action, if any, the EPA or any third party may take against PSE&G with respect to this matter, or in such event, what costs may be incurred to address any such claims. However, such costs may be material.
PSE&G
Spill Prevention Control and Countermeasure (SPCC)
In 1998, PSE&G evaluated SPCC Plan compliance at all of its SPCC substations and identified deficiencies. The necessary upgrades are now in the process of being made, the costs of which are not expected to be material. It is anticipated that these upgrades will take several years to complete. In July 2002, the EPA amended its SPCC regulations to, among other things, confirm the regulations’ applicability to oil-filled electrical equipment.
Manufactured Gas Plant Remediation Program (MGP)
For information regarding PSE&G’s MGP, see Note 13. Commitments and Contingent Liabilities of the Notes.
Power
Hudson and Mercer Generation Stations
Approximately 150,000 tons of fly ash generated by the Hudson and Mercer Generating Stations was taken by the ash marketer, that PSEG then worked with, and sold to the owner and operator of a clay mine. The operator of the clay mine used the fly ash as fill material to return the mine site to grade, without obtaining the necessary approvals from the NJDEP. Upon discovery of this use, PSEG terminated the services of this ash marketer and initiated discussions with NJDEP for the appropriate regulatory approvals to allow this material to remain at the site. Power expects that the NJDEP will likely require a clay cap and other engineering controls to ensure that the ash is isolated from the environment if the ash is left in place. The cost of resolving this matter will depend upon the results of the negotiations with the NJDEP and the property owner. Although the precise extent of liability is not currently estimable, it is not expected to be material.
Kearny Generation Station
A preliminary review of possible mercury contamination at the Kearny Station concluded that additional study and investigations are required. A Remedial Investigation (RI) was conducted and a report was submitted to the NJDEP in 1997. This report is currently under technical review. As currently issued, the RI Report found that the mercury at the site is stable and immobile and should be addressed at the time the Kearny Station is retired, which is expected in the next five years, dependent upon market conditions.
Uranium Enrichment Decontamination and Decommissioning Fund
In accordance with the Energy Policy Act (EPAct), domestic entities that own nuclear generating stations are required to pay into a decontamination and decommissioning fund, based on their past purchases of US government enrichment services. Since these amounts are being collected from PSE&G’s customers over a period of 15 years, this obligation remained with PSE&G following the generation asset transfer to Power in 2000. PSE&G’s obligation for the nuclear generating stations in which it had an interest is $80 million (adjusted for inflation). As of December 31, 2002, PSE&G had paid $58 million, resulting in a balance due of $22 million. As of December 31, 2002, Power had a balance due of approximately $5 million, which related to interests in certain nuclear units Power purchased from Atlantic City Electric Company (ACE) and Delmarva Power and Light Company (DP&L).
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PSE&G and Power believe that they should not be subject to collection of any such fund payments under the EPAct. A number of nuclear generator owners filed in the US Court of Claims and in the US District Court, Southern District of New York to recover these costs. In July 2002, Power and PSE&G withdrew from the lawsuit without prejudice, due to an unfavorable decision against another nuclear generator owner in the lawsuit.
Power
Nuclear Fuel Disposal
After spent fuel is removed from a nuclear reactor, it is placed in temporary storage for cooling in a spent fuel pool at the nuclear station site. Under the Nuclear Waste Policy Act of 1982 (NWPA), as amended, the Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of the spent nuclear fuel. To pay for this service, the nuclear plant owners were required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001) per kWh of nuclear generation ($21 million for 2002), subject to such escalation as may be required to assure full cost recovery by the Federal government. Payments made to the DOE for disposal costs are based on nuclear generation and are included in Energy Costs in the Consolidated Statements of Operations.
Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent fuel storage installations located at reactor or away-from-reactor sites for at least 30 years beyond the licensed life for reactor operation (which may include the term of a revised or renewed license). The availability of adequate spent fuel storage capacity is estimated through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power presently expects to construct an on-site storage facility that would satisfy the spent fuel storage needs of both Salem and Hope Creek through the end of the license life. This construction will require certain regulatory approvals, the timely receipt of which cannot be assured. Exelon has advised Power that it has constructed an on-site dry storage facility at Peach Bottom that is now licensed and operational and can provide storage capacity through the end of the current licenses for the two Peach Bottom units. If a DOE disposal facility is not available for periods subsequent to the current license lives for Salem, Hope Creek and Peach Bottom, construction of additional storage facilities would be necessary.
Under the NWPA, the DOE was required to begin taking possession of the spent nuclear fuel by no later than 1998. The DOE has announced that it does not expect a facility to be available earlier than 2010. Exelon has advised Power that it had signed an agreement with the DOE applicable to Peach Bottom under which Exelon would be reimbursed for costs incurred resulting from the DOE’s delay in accepting spent nuclear fuel. The agreement allows Exelon to reduce the charges paid to the Nuclear Waste Fund to reflect costs reasonably incurred due to the DOE’s delay. Past and future expenditures associated with Peach Bottom’s recently completed on-site dry storage facility would be eligible for this reduction in DOE fees. Under this agreement, Power’s portion of Peach Bottom’s Nuclear Waste Fund fees have been reduced by approximately $18 million through August 31, 2002, at which point the credits were fully utilized and covered the cost of Exelon’s storage facility.
In 2000, a group of eight utilities filed a petition against the DOE in the US Court of Appeal, for the Eleventh Circuit, seeking to set aside the receipt of credits by Exelon out of the Nuclear Waste Fund, as stipulated in the Peach Bottom agreement. On September 24, 2002, the US Court of Appeal, for the Eleventh Circuit, issued an opinion upholding the challenge by the petitioners regarding the settlement agreement’s compensation provisions. Under the terms of the agreement, DOE and Exelon Generation are required to meet and discuss alternative funding sources for the settlement credits. Initial meetings have occurred. The Eleventh Circuit’s opinion suggests that the federal judgment fund should be available as an alternate source. The agreement provides that if such negotiations are unsuccessful, the agreement will be null and void. Any payments required by us resulting from a disallowance of the previously reduced fees would be included in Energy Costs in the Consolidated Statements of Operations.
In September 2001, Nuclear filed a complaint in the US Court of Federal Claims seeking damages caused by the DOE not taking possession of spent nuclear fuel in 1998. No assurances can be given as to any damage recovery or the ultimate availability of a disposal facility.
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In October 2001, Nuclear filed a complaint in the US Court of Federal Claims, along with a number of other plaintiffs, seeking $28.2 million in relief from past overcharges by the DOE for enrichment services. No assurances can be given as to any claimed damage recovery.
In February 2002, President Bush announced that Yucca Mountain in Nevada would be the permanent disposal facility for nuclear wastes. On April 8, 2002, the Governor of Nevada submitted his veto to the siting decision. On July 9, 2002, Congress affirmed the President’s decision. The DOE must still license and construct the facility. No assurances can be given regarding the final outcome of this matter, however it may be several years before a permanent disposal facility is available.
Low Level Radioactive Waste (LLRW)
As a by-product of their operations, nuclear generation units produce LLRW. Such wastes include paper, plastics, protective clothing, water purification materials and other materials. LLRW materials are accumulated on site and disposed of at licensed permanent disposal facilities. New Jersey, Connecticut and South Carolina have formed the Atlantic Compact, which gives New Jersey nuclear generators, including Power, continued access to the Barnwell LLRW disposal facility which is owned by South Carolina. Power believes that the Atlantic Compact will provide for adequate LLRW disposal for Salem and Hope Creek through the end of their current licenses, although no assurances can be given. Both Power and Exelon have on-site LLRW storage facilities for Peach Bottom, Salem and Hope Creek which have the capacity for at least five years of temporary storage for each facility.
Other
Power has reported to NRC and the NJDEP that it has detected the presence of tritium in three on-site groundwater monitoring wells in excess of the applicable analytical method’s detection limit. Power is continuing to investigate the source as well as the extent of the contamination. At this time, it is not possible to determine whether the costs associated with the investigation and/or remediation, if any, would be material.
ITEM 2. PROPERTIES
PSEG
PSEG does not own any property. All property is owned by its subsidiaries.
PSE&G
PSE&G’s First and Refunding Mortgage (Mortgage), securing the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of PSE&G’s property.
The electric lines and gas mains of PSE&G are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by PSE&G or occupied by it under easements or other rights. These easements and rights are deemed by PSE&G to be adequate for the purposes for which they are being used.
PSE&G believes that it maintains adequate insurance coverage against loss or damage to its principal properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost.
Electric Transmission and Distribution Properties
As of December 31, 2002, PSE&G’s transmission and distribution system included approximately 21,873 circuit miles, of which approximately 7,518 circuit miles were underground, and approximately 781,041 poles, of which approximately 536,260 poles were jointly owned. Approximately 99% of this property is located in New Jersey.
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In addition, as of December 31, 2002, PSE&G owned five electric distribution headquarters and four subheadquarters in four operating divisions, all located in New Jersey.
Gas Distribution Properties
As of December 31, 2002, the daily gas capacity of PSE&G’s 100%-owned peaking facilities (the maximum daily gas delivery available during the three peak winter months) consisted of liquid petroleum air gas (LPG) and liquefied natural gas (LNG) and aggregated 2,973,000 therms (approximately 2,886,000 cubic feet on an equivalent basis of 1,030 Btu/cubic foot) as shown in the following table:
| Plant | Location | Daily Capacity (Therms) | |||
| |
|
||||
| Burlington LNG | Burlington, NJ | 773,000 | |||
| Camden LPG | Camden, NJ | 280,000 | |||
| Central LPG | Edison Twp., NJ | 960,000 | |||
| Harrison LPG | Harrison, NJ | 960,000 | |||
| |
|||||
| Total | 2,973,000 | ||||
As of December 31, 2002, PSE&G owned and operated approximately 17,019 miles of gas mains, owned 11 gas distribution headquarters and two subheadquarters, all in two operating regions located in New Jersey and owned one meter shop in New Jersey serving all such areas. In addition, PSE&G operated 61 natural gas metering or regulating stations, all located in New Jersey, of which 28 were located on land owned by customers or natural gas pipeline companies supplying PSE&G with natural gas and were operated under lease, easement or other similar arrangement. In some instances, the pipeline companies owned portions of the metering and regulating facilities.
Office Buildings and Facilities
PSE&G leases substantially all of a 26-story office tower for its corporate headquarters at 80 Park Plaza, Newark, New Jersey, together with an adjoining three-story building. PSE&G also leases other office space at various locations throughout New Jersey for district offices and offices for various corporate groups and services. PSE&G also owns various other sites for training, testing, parking, records storage, research, repair and maintenance, warehouse facilities and for other purposes related to its business.
In addition to the facilities discussed above, as of December 31, 2002, PSE&G owned 41 switching stations in New Jersey with an aggregate installed capacity of 20,934 megavolt-amperes and 241 substations with an aggregate installed capacity of 7,503 megavolt-amperes. In addition, 5 substations in New Jersey having an aggregate installed capacity of 127 megavolt-amperes were operated on leased property.
Power
Power rents approximately 137,000 square feet of office space from PSE&G at its headquarters in Newark, New Jersey. Other leased properties include office, warehouse, classroom and storage space, primarily in New Jersey, used for system maintenance, procurement and materials management staff, training and storage.
Through a subsidiary, Power owns a 57.41% interest in approximately 12,000 acres of restored wetlands and conservation facilities in the Delaware River Estuary that was formed to acquire and own lands and other conservation facilities required to satisfy the condition of the NJPDES permit issued for Salem. Power also owns several other facilities, including the on-site Nuclear Administration and Processing Center buildings.
Power has an 13.91% ownership interest in the 650-acre Merrill Creek Reservoir 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 companies that have generation facilities along the Delaware River or its tributaries and use the river water in their operations. Power also owns the Maplewood Test Services in Maplewood, New Jersey and the Central Maintenance Shop at Sewaren, New Jersey.
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Power believes that it maintains adequate insurance coverage against loss or damage to its principal plants and properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Note 13. Commitments and Contingent Liabilities of the Notes.
As of December 31, 2002, Power’s share of installed generating capacity was 13,055 MW, as shown in the following table:
| OPERATING POWER PLANTS | |||||||||||
| Name | Location | Total Capacity (MW) |
% Owned |
Owned Capacity (MW) |
Principle Fuels Used |
Mission | |||||
| Steam: | |||||||||||
| Hudson, Jersey City | NJ | 991 | 100% | 991 | Coal/Gas | Load Following | |||||
| Mercer, Hamilton | NJ | 648 | 100% | 648 | Coal/Gas | Load Following | |||||
| Sewaren, Woodbridge Twp. | NJ | 453 | 100% | 453 | Gas/Oil | Load Following | |||||
| Linden, Linden (E) | NJ | 430 | 100% | 430 | Oil | Load Following | |||||
| Keystone, Shelocta (A) | PA | 1,700 | 22.84% | 388 | Coal | Base Load | |||||
| Conemaugh, New Florence (A) | PA | 1,700 | 22.50% | 382 | Coal | Base Load | |||||
| Kearny, Kearny (E) | NJ | 300 | 100% | 300 | Oil | Load Following | |||||
| Bethlehem, Albany (E) | NY | 376 | 100% | 376 | Oil | Load Following | |||||
| Bridgeport Harbor, Bridgeport | CT | 534 | 100% | 534 | Coal/Oil | Base Load/Load | |||||
| Following | |||||||||||
| New Haven Harbor, New Haven | CT | 466 | 100% | 466 | Oil/Gas | Load Following | |||||
| |
|
||||||||||
| Total Steam | 7,598 | 4,968 | |||||||||
| |
|
||||||||||
| Nuclear: | |||||||||||
| Hope Creek, Lower Alloways Creek | NJ | 1,049 | 100% | 1,049 | Nuclear | Base Load | |||||
| Salem 1 & 2, Lower Alloways Creek | NJ | 2,221 | 57.41% | 1,275 | Nuclear | Base Load | |||||
| Peach Bottom 2 & 3, Peach Bottom (B) | PA | 2,186 | 50% | 1,093 | Nuclear | Base Load | |||||
| |
|
||||||||||
| Total Nuclear | 5,456 | 3,417 | |||||||||
| |
|
||||||||||
| Combined Cycle: | |||||||||||
| Bergen, Ridgefield | NJ | 1,221 | 100% | 1,221 | Gas | Load Following | |||||
| Burlington, Burlington | NJ | 245 | 100% | 245 | Gas | Load Following | |||||
| |
|
||||||||||
| Total Combined Cycle | 1,466 | 1,466 | |||||||||
| |
|
||||||||||
| Combustion Turbine: | |||||||||||
| Essex, Newark | NJ | 617 | 100% | 617 | Gas/Oil | Peaking | |||||
| Edison, Edison Township | NJ | 504 | 100% | 504 | Gas/Oil | Peaking | |||||
| Kearny, Kearny | NJ | 443 | 100% | 443 | Gas/Oil | Peaking | |||||
| Burlington, Burlington | NJ | 557 | 100% | 557 | Oil | Peaking | |||||
| Linden, Linden | NJ | 324 | 100% | 324 | Gas/Oil | Peaking | |||||
| Hudson, Jersey City | NJ | 129 | 100% | 129 | Oil | Peaking | |||||
| Mercer, Hamilton | NJ | 129 | 100% | 129 | Oil | Peaking | |||||
| Sewaren, Woodbridge Township | NJ | 129 | 100% | 129 | Oil | Peaking | |||||
| Bayonne, Bayonne | NJ | 42 | 100% | 42 | Oil | Peaking | |||||
| Bergen, Ridgefield | NJ | 21 | 100% | 21 | Gas | Peaking | |||||
| National Park, National Park | NJ | 21 | 100% | 21 | Oil | Peaking | |||||
| Kearny, Kearny | NJ | 21 | 100% | 21 | Gas | Peaking | |||||
| Linden, Linden (E) | NJ | 21 | 100% | 21 | Gas/Oil | Peaking | |||||
| Salem, Lower Alloways Creek | NJ | 38 | 57.41% | 22 | Oil | Peaking | |||||
| Bridgeport Harbor, Bridgeport | CT | 19 | 100% | 19 | Oil | Peaking | |||||
| |
|
||||||||||
| Total Combustion Turbine | 3,015 | 2,999 | |||||||||
| |
|
||||||||||
| Internal Combustion: | |||||||||||
| Conemaugh, New Florence (A) | PA | 11 | 22.50% | 2 | Oil | Peaking | |||||
| Keystone, Shelocta (A) | PA | 11 | 22.84% | 3 | Oil | Peaking | |||||
| |
|
||||||||||
| Total Internal Combustion | 22 | 5 | |||||||||
| |
|
||||||||||
| Pumped Storage: | |||||||||||
| Yards Creek, Blairstown (C)(D) | NJ | 400 | 50% | 200 | Peaking | ||||||
| |
|
||||||||||
| Total Operating Generation Plants | 17,957 | 13,055 | |||||||||
| |
|
||||||||||
| (A) | Operated by Reliant Resources |
| (B) | Operated by Exelon Generation LLC |
| (C) | Operated by Jersey Central Power & Light Company |
| (D) | Excludes energy for pumping and synchronous condensers. |
| (E) | These assets are scheduled for
retirement within the next three years, partially dependent upon new generation
going into service discussed below. |
28 | |
As of December 31, 2002, Power had 4,037 MW of generating capacity in construction or advanced development, as shown in the following table:
| POWER PLANTS IN CONSTRUCTION OR ADVANCED DEVELOPMENT | ||||||||||||
| Name | Location | Total Capacity (MW) |
% Owned |
Owned Capacity (MW) |
Principle Fuels Used |
Scheduled In Service Date |
||||||
| Combined Cycle: | ||||||||||||
| Bethlehem | NY | 763 | 100% | 763 | Gas | June 2005 | ||||||
| Lawrenceburg | IN | 1,096 | 100% | 1,096 | Gas | November 2003 | ||||||
| Waterford | OH | 821 | 100% | 821 | Gas | June 2003 | ||||||
| Linden | NJ | 1,218 | 100% | 1,218 | Gas | March 2005 | ||||||
| |
|
|||||||||||
| Total Construction | 3,898 | 3,898 | ||||||||||
| |
|
|||||||||||
| Nuclear Uprates | NJ/PA | 139 | 100% | 139 | Nuclear | 2003-2005 | ||||||
| |
|
|||||||||||
| Total Advanced Development | 139 | 139 | ||||||||||
| Projected Capacity (2002-2005) | Total Capacity (MW) | |
| |
| |
| Total Owned Operating Generating Plants | 13,055 | |
| Under Construction | 3,898 | |
| Advanced Development | 139 | |
| Less: Planned Retirements | (1,127 | ) |
| |
||
| Projected Capacity | 15,965 | |
| |
||
Energy Holdings
Energy Holdings rents office space for its corporate headquarters at 80 Park Plaza, Newark, New Jersey from PSE&G. Energy Holdings’ subsidiaries also lease office space at various locations throughout the world to support business activities. Energy Holdings believes that it maintains adequate insurance coverage for properties in which its subsidiaries have an equity interest, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost.
29
Global has invested in the following generation facilities, which are in operation or under construction as of December 31, 2002:
| OPERATING POWER PLANTS | |||||||||
| Name | Location | Total Capacity (MW) |
% Owned |
Owned Capacity (MW) |
Principle Fuels Used |
||||
| United States (A) | |||||||||
| Texas Independent Energy | |||||||||
| Guadalupe | TX | 1,000 | 50% | 500 | Natural gas | ||||
| Odessa | TX | 1,000 | 50% | 500 | Natural gas | ||||
| Kalaeloa | HI | 180 | 50% | 90 | Oil | ||||
| GWF | |||||||||
| Bay Area I | CA | 21 | 50% | 10 | Petroleum coke | ||||
| Bay Area II | CA | 21 | 50% | 10 | Petroleum coke | ||||
| Bay Area III | CA | 21 | 50% | 10 | Petroleum coke | ||||
| Bay Area IV | CA | 21 | 50% | 10 | Petroleum coke | ||||
| Bay Area V | CA | 21 | 50% | 10 | Petroleum coke | ||||
| Hanford | CA | 27 | 50% | 14 | Petroleum coke | ||||
| GWF Energy: | |||||||||
| Hanford – Peaker Plant | CA | 94 | 76% | 71 | Natural gas | ||||
| Henrietta – Peaker Plant | CA | 96 | 76% | 73 | Natural gas | ||||
| SEGS III | CA | 30 | 9% | 3 | Solar | ||||
| Tracy | CA | 21 | 35% | 7 | Biomass | ||||
| Bridgewater | NH | 16 | 40% | 6 | Biomass | ||||
| Conemaugh | PA | 15 | 50% | 8 | Hydro | ||||
| |
|
||||||||
| Total United States: | 2,584 | 1,322 | |||||||
| |
|
||||||||
| International(B) | |||||||||
| MPC | |||||||||
| Jingyuan – Units 5 and 6 | China | 600 | 15% | 90 | Coal | ||||
| Tongzhou | China | 30 | 40% | 12 | Coal | ||||
| Nantong | China | 30 | 46% | 14 | Coal | ||||
| Jinqiao (Thermal Energy) | China | N/A | 30% | N/A | Coal/Oil | ||||
| Zuojiang – Units 1, 2 and 3 | China | 72 | 30% | 22 | Hydro | ||||
| Fushi – Units 1, 2 and 3 | China | 54 | 35% | 19 | Hydro | ||||
| Shanghai BFG | China | 50 | 33% | 16 | Blast furnace gas | ||||
| Haian (Thermal Energy) | China | N/A | 100% | N/A | Coal | ||||
| Huangshi Unit I | China | 100 | 25% | 25 | Coal | ||||
| PPN | India | 330 | 20% | 66 | Naphtha/Natural gas | ||||
| Prisma (C) | |||||||||
| Crotone | Italy | 20 | 25% | 5 | Biomass | ||||
| Bando D’Argenta I | Italy | 10 | 50% | 5 | Biomass | ||||
| Electroandes | Peru | 183 | 100% | 183 | Hydro | ||||
| Chorzow (Existing Facility) | Poland | 100 | 55% | 55 | Coal | ||||
| Skawina CHP | Poland | 590 | 50% | 295 | Coal | ||||
| Turboven | |||||||||
| Maracay | Venezuela | 60 | 50% | 30 | Natural gas | ||||
| Cagua | Venezuela | 60 | 50% | 30 | Natural gas | ||||
| TGM | Venezuela | 40 | 9% | 4 | Natural gas | ||||
| Rades | Tunisia | 471 | 60% | 283 | Natural gas | ||||
| |
|
||||||||
| Total International: | 2,800 | 1,154 | |||||||
| |
|
||||||||
| Total Operating Power Plants: | 5,384 | 2,476 | |||||||
| |
|
||||||||
30
Global has invested in the following generation facilities which are under construction as of December 31, 2002:
| POWER PLANTS IN CONSTRUCTION | |||||||||||
| Name | Location | Total Capacity (MW) |
% Owned |
Owned Capacity (MW) |
Principle Fuels Used |
Scheduled In Service Date |
|||||
| United States | |||||||||||
| GWF Energy | |||||||||||
| Tracy – Peaker Plant | CA | 167 | 76% | 127 | Natural gas | 2003 | |||||
| International | |||||||||||
| MPC | |||||||||||
| Huangshi Unit II | China | 600 | 25% | 150 | Coal | 2006 | |||||
| Yulchon | South Korea | 612 | 50% | 306 | Natural Gas | 2004 | |||||
| Kuo Kuang | Taiwan | 480 | 18% | 84 | Natural gas | 2003 | |||||
| Prisma (C) | |||||||||||
| Strongoli | Italy | 40 | 25% | 10 | Biomass | 2003 | |||||
| Bando D’Argenta II | Italy | 10 | 50% | 5 | Biomass | 2003 | |||||
| Salalah | Oman | 200 | 81% | 162 | Natural gas | 2003 | |||||
| Chorzow | Poland | 220 | 90% | 198 | Coal | 2003 | |||||
| |
|
||||||||||
| Total Construction: | 2,329 | 1,042 | |||||||||
| |
|
||||||||||
| TOTAL GENERATION FACILITIES: | 7,713 | 3,518 | |||||||||
| (A) | In November 2002, Global sold its
interest in the generating station, Kennebec (Maine) to United American
Energy Corp. |
| (B) | Tanir Bavi (India) was sold in
October 2002 to GMR Vasavi Group. Also during 2002, assets in Argentina
were fully impaired. See Note 4. Asset Impairments and Note 5. Discontinued
Operations of the Notes. |
| (C) | All Prisma assets are currently
held for sale. |
Domestic Generation In Operation Texas Independent
Energy, L.P. (TIE) | |
| In
April 1999, Global and its partner, Panda Energy International, Inc., established
TIE, a 50/50 joint venture, which owns
and operates electric generation facilities in Guadalupe County in south
central Texas (Guadalupe) and Odessa in western Texas (Odessa). | |
| Approximately
37.5% of the Guadalupe plant’s total output for 2003 has been sold
via bilateral power purchase agreements and the remainder will be sold in
the Texas spot market. In 2002, the plant generated approximately $145 million
of gross revenue. | |
| Approximately
9.6% of the Odessa plant’s total output for 2003 has been sold via
bilateral power purchase agreements. The balance of the output will be sold
on a spot or short-term basis into the Texas power market. In 2002, the
plant generated approximately $161 million of gross revenue. For a discussion
of the Texas power market, see Item 7. MD&A — Future Outlook. | |
Kalaeloa Global’s
partner in Kalaeloa is a power fund managed by Harbert Power. All of the
electricity generated by the Kalaeloa power plant is sold to the Hawaiian
Electric Company under a power purchase contract terminating in May 2016.
Under a steam purchase and sale agreement expiring in May 2016, the Kalaeloa
power plant supplies steam to Hawaiian Independent Refinery, Inc. In 2002,
the plant generated approximately $108 million of gross revenue. The plant
availability factor in 2002 was 99%. | |
| 31 | |
GWF Power Systems LP (GWF) and Hanford LP (Hanford)
Global and Harbert Power each own 50% of the GWF plants. Power purchase contracts for the plants’ net output are in place with Pacific Gas and Electric Company (PG&E) ending in 2020 and 2021. In 2002, the plants generated approximately $62 million of gross revenue. The average availability factor of the five plants in 2002 was 95%.
Global and Harbert Power each own 50% of Hanford. A power purchase contract for the plant’s net output is in place with PG&E through 2011. The Hanford plant generated approximately $16 million of gross revenue in 2002 and had an availability factor of 97%.
In July 2001, GWF, Hanford and the Tracy biomass plant entered into an agreement with PG&E and amendments to their power purchase agreements with PG&E that contained the Public Utilities Commission of the State of California approved pricing for a term of five years commencing July 16, 2001.
Hanford and Henrietta Peaker Plants
In May 2001 GWF Energy LLC (GWF Energy), a 50/50 joint venture between Global and Harbinger GWF LLC (an affiliate of Harbert Power), entered into a 10-year power purchase agreement with the California Department of Water Resources (DWR) to provide 340 MW of electric capacity to California from three new natural gas-fired peaking plants. As of December 31, 2002, Global’s ownership interest in this project was 76%. Energy and capacity not scheduled by the DWR is available for sale by GWF Energy. Two of the plants, the Hanford and Henrietta Peaking plants, have commenced commercial operation, and had approximately $25 million and $22 million in gross revenue, respectively, during 2002.
For further information, see Note 13. Commitments and Contingent Liabilities of the Notes.
International Generation in Operation
Global owns interests in operating generation facilities in China, India, Italy, Peru, Poland, Tunisia and Venezuela. In October 2002, a settlement was reached between AES Corporation (AES) and Global under which Global will transfer its minority ownership interests in certain Argentine assets to AES. For more details, see Note 4. Asset Impairments of the Notes.
China
Meiya Power Company Limited (MPC)
Global’s activities in China and surrounding countries are conducted through MPC, a joint venture with the Asian Infrastructure Fund (AIF) and Hydro Quebec International (HQI).
MPC is focused on developing, acquiring, owning and operating electric and thermal heat generation facilities in China, South Korea and Taiwan. MPC seeks to structure long-term power purchase contracts with its customers and to incorporate take-or-pay and minimum take provisions to support debt service and a specified equity return. Pricing terms for energy from its facilities generally include a base price and indexed adjustments to compensate for changes in inflation, foreign currency exchange rates up to the minimum equity return and laws affecting taxes, fees and required reserves. For cogeneration facilities, instead of selling the electricity through long-term power purchase contracts, MPC sells its output through an annually determined quota fixed in accordance with a predetermined formula which essentially determines the amount of electricity to be sold by reference to the amount of steam generated by the cogeneration facilities. The two cogeneration plants in Tongzhou and Nantong operate under this system. MPC’s projects, either under construction or in operation, have obtained all the required approvals to enable issuance of a business license in their respective localities.
Minority investments held by Global in nine generation facilities located in China generated 2% of Global’s total gross revenues in 2002.
32
India
PPN Power Generating Company Limited (PPN)
Global owns a 20% interest in PPN located in Tamil Nadu, India. Global’s partners include Marubeni Corporation, with a 26% interest, El Paso Energy Corporation, with a 26% interest and the Reddy Group, with a 28% interest. PPN has entered into a power purchase contract for the sale of 100% of the output to the State Electricity Board of Tamil Nadu (TNEB) for 30 years, with an agreement to take-or-pay to a plant load factor (PLF) of 85%.
Peru
Empresa de Electricidad de los Andes S.A. (Electroandes)
Electroandes’ main assets include four hydroelectric facilities with a combined installed capacity of 183 MW and 460 miles of transmission lines located in the central Andean region (northeast of Lima). In addition, Electroandes has a temporary concession to develop two greenfield hydroelectric facilities totaling 180 MW and expansion projects on existing stations totaling 100 MW. These concessions expire in March 2003, but are renewable for two additional years. In 2002, 91% of Electroandes revenues were obtained through power purchase agreements with mining companies in the region. Electroandes generated approximately $45 million of gross revenue in 2002.
Venezuela
Turbogeneradores de Maracay (TGM)
Global, with a 9% interest, is in partnership with Corporacion Industrial de Energia (CIE), to own TGM. TGM sells all of the energy produced under contract to Manufacturas del Papel (MANPA), a paper manufacturing concern located in Maracay. MANPA and CIE have common controlling shareholders.
Turboven
The facilities in Cagua and Maracay are owned and operated by Turboven, an entity which is jointly owned by Global and CIE. To date, power purchase contracts have been entered into for the sale of approximately 70% of the output of Maracay and Cagua, to various industrial customers. The power purchase contracts are structured to provide energy only with minimum take provisions. Fuel costs are passed through directly to customers and the energy tariffs are calculated in US Dollars and paid in local currency. In 2002, the plants in Maracay and Cagua generated $20 million of gross revenue.
Poland
Elcho
In October 2000, Global acquired a 55% economic interest in a combined thermal energy and power generation plant in Chorzow, in the Upper Silesia region of Poland, with Elektrownia Chorzow holding the remaining interest. As a part of the acquisition of the existing plant, Global obtained the rights to construct, and is constructing, a 220 MW electrical and 500 MW thermal combined thermal energy and power plant in Chorzow. Global currently holds a 55% economic interest in Elektrocieplownia Chorzow Sp. z.o.o. (ELCHO), including both the old plant and the plant under construction, with the anticipation of expanding such interest to approximately 90% by 2003. Global intends to operate the existing plant until the new plant comes on line in late 2003. Polskie Sieci Elektroenergetyczne SA (PSE), the Polish power grid company, has signed a long-term power purchase agreement with ELCHO and it is planned for all of the power to be delivered into the local distribution system. During 2002, the existing plant generated approximately $21 million of gross revenue. As of December 31, 2002, Energy Holdings’ investment exposure, including contingencies, was $80 million.
33
Skawina CHP Plant (Skawina)
During 2002, Global acquired a 50% interest in Skawina, a combined thermal energy and power generation, for $31 million and will purchase additional shares in 2003 that will bring Global’s aggregate interest in Skawina to approximately 65%. In addition, Global has an obligation to offer to purchase an additional 10% ownership from Skawina’s employees in 2004 for a total potential ownership in Skawina of 75%. Skawina supplies electricity to three local distribution companies and heat mainly to the city of Krakow, under one-year contracts consistent with current practice in Poland. The sale is part of the Polish Government’s energy privatization program. During 2002, the plant generated approximately $49 million of gross revenue. As of December 31, 2002, Energy Holdings, investment exposure, including contingencies, was $90 million.
Tunisia
Rades
Global and its partner Marubeni Corporation own 60% and 40%, respectively, of the Carthage Power facility in Rades, Tunisia for which Global is the operator. A 20-year power purchase contract has been entered into for the sale of 100% of the output to Societe Tunisienne d’Electricite et du Gaz, the national utility. The tariff in the power purchase contract consists of a fixed capacity charge to cover debt and equity return as well as fixed and variable charges to cover fuel, operations and maintenance costs. Each tariff component will be paid in local currency (Dinars). Rades commenced operation in May 2002 and generated approximately $57 million of gross revenue in 2002.
Power Plants Under Construction
Global has eight projects in construction located in the United States, China, Italy, Oman, Poland, South Korea and Taiwan. All of these plants have obtained power purchase contracts for their output. The two projects under construction in Italy are currently held for sale.
United States
Tracy Peaker Plant
The Tracy Peaker Plant is under construction with a commercial operation date deadline of July 1, 2003. Total project cost is expected to be $146 million. For additional information, see Note 13. Commitments and Contingent Liabilities of the Notes.
Oman
Salalah
In March 2001, Global, through Dhofar Power Company (DPCO), signed a 20-year concession with the government of Oman to privatize the electric system of Salalah. A consortium led by Global (81% ownership) and several major Omani investment groups owns DPCO. The project is expected to achieve commercial operation by April 2003. Total project cost is estimated at $256 million. Global’s equity investment, including contingencies and equity guarantees, is expected to be approximately $97 million. As of December 31, 2002, Energy Holdings’ investment exposure, including contingencies, was $39 million.
Poland
Elcho
Global’s 220 MW (electrical) and 500 MW (thermal) facility will replace an existing 100 MW thermal energy and power generation facility. Global’s economic interest in the project is currently 55%, with the anticipation of expanding such interest to approximately 90% by the end of 2003, with the balance held by a local Polish company. Total project cost is estimated at $324 million. Global’s equity investment, including contingencies, is not expected to exceed $105 million. The plant has a targeted commercial operation date in late 2003. PSE, the Polish power grid company, has entered into a 20-year power purchase agreement with ELCHO for 100% of the electrical output. All
34
of the thermal energy will be sold to Przedsiebiorstwo Energetyki Cieplnej, the district heating company for a term of 20 years.
Taiwan
Kuo Kuang
Through MPC, Global owns a 17.5% indirect interest in a gas-fired combined-cycle electric generation facility under construction in Kuo Kuang, Taiwan. MPC has a 35% interest in Kuo Kuang and partners with two local Taiwanese companies, Chinese Petroleum Corporation and CTCI Corporation. Kuo Kuang has entered into a 25-year power purchase contract for the sale of 100% of its electric output to Taiwan Power Company, the national utility. The power purchase contract payments consist of a fixed capacity charge to cover debt and equity return as well as fixed and variable charges to cover fuel, operations and maintenance costs. The tariff will be paid in local currency. Kuo Kuang is expected to be in operation in 2003, with a total cost of approximately $320 million. Global’s equity investment, including contingencies, is expected to be approximately $20 million.
South Korea
Yulchon
Through MPC, Global owns a 50% indirect interest in Yulchon Generation Company, a gas-fired combined-cycle plant under construction in South Korea. Open cycle operation of the plant is scheduled for mid-2004, with conversion to combined-cycle operation scheduled for mid-2005. The power will be purchased by state-owned Korea Electric Power Company under a long-term power purchase contract. The total cost of the project is expected to be $301 million, and will be provided by debt funds from project finance sources and equity funds from MPC.
Electric Distribution Facilities
Global has invested in the following distribution facilities:
| Name | Location | Number of Customers |
Global’s Ownership Interest |
|||||
| Rio Grande Energia | Brazil | 1,020,000 | 32% | |||||
| Chilquinta Energia | Chile | 480,000 | 50% | |||||
| SAESA | Chile | 660,000 | 100% | |||||
| Luz del Sur | Peru | 720,000 | 44% | |||||
| |
||||||||
| Total | 2,880,000 | |||||||
| |
||||||||
Brazil
Rio Grande Energia (RGE)
Together with VBC Energia, a consortium of Brazilian companies formed to invest in electric privatization, and Previ, the largest pension fund in Brazil, Global acquired RGE in 1997. Global is the named operator for the system. A shareholders’ agreement establishes corporate governance, voting rights and key financial provisions. Global has veto rights over certain actions, including approval of the annual budget and financing plan, executive officers, significant investments or acquisitions, sale or encumbrance of assets, establishment of guarantees, amendment of the concession agreement and dividend policies. Day-to-day operations are the responsibility of RGE, subject to partnership oversight. During 2001, VBC Energia and Previ transferred their shares to Companhia Paulista de Forcae Luz (CPFL), an electric distribution company in which each of VBC Energia and Previ have an interest.
35
RGE operates under a non-exclusive territorial concession agreement ending in 2027. The concession is non-exclusive in that the distribution system must provide large consumers the right to choose another provider of energy or to self-generate. Global does not believe this represents a substantial threat to the profitability of the distribution system in Brazil since the tariff structure provides the distribution system the opportunity to recover all costs associated with distribution service plus a return. RGE secures its energy supply through contractual agreements expiring between 2007 and 2020. RGE will also purchase 20% of its energy requirements through 2013 under the terms of contracts, which are denominated in US Dollars. During 2002, RGE generated $430 million in gross revenue.
See Note 4. Asset Impairments of the Notes for a discussion of the goodwill impairment recorded for RGE. For a discussion of the Brazilian regulatory environment, see Item 1. Business — Regulatory Issues and Item 7. MD&A — Future Outlook.
Chile
Chilquinta Energia S.A. (Chilquinta) and Luz del Sur (LDS)
Global together with its partner, Sempra, jointly own 99.99% of the shares of Chilquinta, an energy distribution company with numerous energy holdings, based in Valparaiso, Chile. In addition, Global and Sempra jointly own 87.9% of LDS, which owns electric distribution facilities in Peru.
As equal partners, Global and Sempra share in the management of Chilquinta, however, Sempra has assumed lead operational responsibilities at Chilquinta, while Global has assumed lead operational responsibilities at LDS. The shareholders’ agreement gives Global important veto rights over major partnership decisions including dividend policy, budget approvals, management appointments and indebtedness.
In 2002, Chilquinta generated approximately $132 million in gross revenues. Chilquinta operates under a non-exclusive perpetual franchise within Chile’s Region V which is located just north and west of Santiago. Global believes that direct competition for distribution customers would be uneconomical for potential competitors. LDS operates under an exclusive, perpetual franchise in the southern portion of the city of Lima and in an area just south of the city along the coast serving a population of approximately 3.2 million. In 2002, LDS generated gross revenues of approximately $312 million. Both Chilquinta and LDS purchase energy for distribution from generators in their respective markets on a contract basis.
For a discussion of the regulatory environment in Chile and Peru, see Item 1. Business — Regulatory Issues.
Sociedad Austral de Electricidad S.A. (SAESA)
In 2001, Global purchased a 99.9% equity in SAESA and its subsidiaries from Compañia de Petróleos de Chile S.A. (COPEC). The SAESA group of companies consists of four distribution companies and one transmission company that provide electric service to 390 cities and towns over 900 miles between Bulnes in the VIII Region and Cochrane in the XI Region of southern Chile. Additionally, Global purchased from COPEC approximately 14% of Empresa Eléctrica de la Frontera S.A. (Frontel), not already owned by SAESA, to bring Global’s total interest in Frontel to 95.5%.
Through its affiliated company Sistema de Transmission del Sur S.A. (STS), SAESA provides transmission services to electrical generation facilities that have power purchase arrangements with distributors in Regions VIII, IX and X and has current capacity of 673 MVA.
SAESA also owns a 50% interest in an Argentine distribution company, Empresa de Energia Rio Negro S.A. (EDERSA) which provides generation, transmission and distribution services to 66 communities in the Province of Rio Negro, which is located close to Argentina’s principal oil and gas reserves and has more than 600,000 residents.
SAESA and its Chilean affiliates are organized and administered according to a centralized administrative structure designed to maximize operational synergies. In Argentina, EDERSA has its own independent administrative structure.
36
During 2002, SAESA’s generated revenues of approximately $146 million, serving 660,000 customers.
Argentina
EDEN, EDES and EDELAP
In October 2002, a settlement was reached under which Global will transfer its minority interest in the assets of Empresa Distribuidora de Energia Norte S.A. (EDEN), Empresa Distribuidora de Energia Norte S.A. (EDES) Empresa Distribuidora La Plata S.A. (EDELAP) and other investments to Global’s partner, AES. For more details, see Note 4. Asset Impairments of the Notes.
EDEERSA
Global has an ownership interest in Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA). As of June 30, 2002, Global determined that its investment in EDEERSA was completely impaired under Statement of Financial Accounting Standards (SFAS) No. 144. For a detailed discussion, see Note 4. Asset Impairments and Note 13. Commitments and Contingent Liabilities of the Notes.
37
| ITEM 3. LEGAL
PROCEEDINGS |
|
| PSE&G | |
| On November 15, 2001, Consolidated Edison, Inc. (Con Edison) filed a complaint against PSE&G with the Federal Energy Regulatory Commission (FERC) pursuant to
Section 206 of the Federal Power Act asserting that PSE&G had breached agreements covering 1,000 MW of transmission by curtailing service and failing to maintain sufficient system capacity to satisfy all of its service obligations. PSE&G
denied the allegations set forth in the complaint. While finding that Con Edison’s presentation of evidence failed to demonstrate several of the allegations, on April 26, 2002, FERC found sufficient reason to set the complaint for hearing. An
initial decision issued by an administrative law judge in April 2002 upheld PSE&G’s claim that the contracts do not require the provision of “firm” transmission service to Con Edison but also accepted Con Edison’s contentions
that PSE&G was obligated to provide service to Con Edison utilizing all the facilities comprising its electrical system including generation facilities and that PSE&G was financially responsible for “out-of-merit,” i.e.,
above-market, generation costs needed to effectuate the desired power flows. Following the Initial Decision, PSE&G and Con Edison engaged in extensive settlement discussions in an attempt to settle their differences. This attempt was
unsuccessful. On December 9, 2002, FERC issued a decision modifying the Initial Decision by finding that only 600 MW of the total 1,000 MW power transfers is required to be supported by out-of-merit generation. FERC also made a number of other
findings, on a preliminary basis, including favorable findings to PSE&G that power transfers should be measured on a “net” basis that considers the impacts of third party transactions and that PSE&G’s obligations should be
reduced to the extent that Con Edison has impaired PSE&G’s ability to perform under the contracts. FERC remanded a number of issues to the administrative law judge for additional hearings, mainly related to the development of protocols to
implement the findings of the December 9, 2002 order. In addition, issues related to Phase 2 of the complaint involving the past administration of the contracts and a claim that PSE&G improperly benefited from the purchase of hedging contracts
in New York, is also pending before the administrative law judge. Hearings are scheduled to commence on March 5, 2003 and an initial decision by the administrative law judge is required by April 29, 2003. The nature and cost of any remedy, which is
expected to be prospective only, cannot be predicted, but is not expected to be material. Docket No. EL02-23-000. | |
| Energy Holdings | |
| The
Brazilian Consumer Association of Water and Energy has filed a lawsuit against
RGE, the Brazilian distribution company of which Global is a 32% owner,
and two other utilities, claiming that certain value added taxes and the
residential tariffs that are being charged by such utilities to their respective
customers are illegal. The plaintiff is seeking damages of approximately
$505 million. In August 2002 the Public Treasury Court in Porto Alegre dismissed
the case. The plaintiff filed a Notice of Appeal with the State
Court of Appeals in November 2002. RGE believes that its collection of the
tariffs and value added taxes are in compliance with applicable tax and
utility laws and regulations. While it is the contention of RGE that the
claims are without merit, and that it has valid defenses and potential third
party claims, an adverse determination could have a material adverse effect
on PSEG’s and Energy Holdings’ financial condition, results of
operations and net cash flows. Assobraee-Associacao
Brasileira de Consumidores de Agua e Energia Eletrica v. Rio Grande Energia
S/A –RGE, CEEE and AES Sul, First Public Treasury Court/City of Porto
Alegre. Proceeding No. 101214451. | |
| See information on the following proceedings at the pages indicated for PSEG and each of PSE&G, Power and Energy Holdings as noted: | |
| (1) | Pages 2 and 136. (PSE&G and Power) 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) | Page 3. (PSE&G and Power) Gas Contract transfer filing with the BPU. |
| (3) | Page 12. (PSE&G) PSE&G electric rate case filed with the BPU. |
| (4) | Page 13. Affiliate standards audit at the BPU. |
| (5) | Page 14. (PSE&G) Deferal Proceeding and Deferral Audit at the BPU. |
| (6) | Page 14. (PSE&G) PSE&G’s Gas Base Rate Filings, Docket Nos. GR01050328 and GR01050297. |
| (7) | Page 14. (PSE&G) BGSS filing with the BPU. |
| (8) | Page 14. (PSE&G) BGSS Design filing with BPU. |
| (9) | Page 15. (PSEG, PSE&G, Power and Energy Holdings) FERC proceeding related to PJM Restructuring. |
38 | |
| (10) | Pages 15. (PSE&G) FERC proceeding related to MISO and PJM | |
| (11) | Pages 17, 36 and 50. (Energy Holdings) Global’s rate case in Brazil. | |
| (12) | Pages 22 and 23. (Power and Energy Holdings) Administrative proceedings before the NJDEP under the FWPCA for certain electric generating stations. | |
| (13) | Pages 25, 26 and 163. (Power) DOE not taking possession of spent nuclear fuel, Docket No. 01-551C. | |
| (14) | Pages 48 and 133. (Energy Holdings) AES termination of the Stock Purchase Agreement, relating to the sale of certain Argentine assets. New York State Supreme Court for New York County (Docket
No. 60155/2002) PSEG Global, et al vs. The AES Corporation, et al. | |
| (15) | Page 161. (PSE&G) PSE&G’s MGP Remediation Program. | |
| (16) | Page 161. (PSE&G) Investigation and additional investigation by the EPA regarding the Passaic River site. Docket No. EX93060255. | |
| (17) | Page 164. (Energy Holdings) Complaint filed with the FERC addressing contract terms of certain Sellers of Energy and Capacity under Long-Term Contracts with the California Department of Water
Resources. Public Utilities Commission of the State of California v. Sellers of Long Term Contracts to the California Department of Water Resources FERC Docket No. EL02-60-000. California Electricity Oversight Board v. Sellers of Energy and Capacity
Under Long-Term Contracts with the California Department of Water Resources FERC Docket No. EL02-62-000. | |
| PSE&G and Power | ||
| In addition, see the following environmental related matters involving governmental authorities. Based on current information, PSE&G and Power do not expect
expenditures for any such site, individually or all such current sites in the aggregate, to have a material effect on their respective financial condition, results of operations and net cash flows. | ||
| (1) | Claim made in 1985 by US 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 US Government alleges damages of approximately $200 million. To PSE&G’s 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 PSE&G 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 PSE&G 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) | Claim by the EPA, Region III, under CERCLA with respect to a Cottman Avenue Superfund Site, a former non-ferrous scrap reclamation facility located in Philadelphia, Pennsylvania, owned and formerly
operated by Metal Bank of America, Inc. PSE&G, other utilities and other companies are alleged to be liable for contamination at the site and PSE&G has been named as a PRP. A Final Remedial Design | |
39 | ||
| Report was submitted
to the EPA in September of 2002. This document presents the design details
that will implement the EPA selected remediation remedy. The costs of remedy
implementation are estimated to range from $14 million to $24 million. PSE&G’s
share of the remedy implementation costs are estimated between $4 million
and $8 million. The remedy itself and responsibility for the costs of its
implementation are the subject of litigation currently venued in the United
States District Court for the Eastern District of Pennsylvania entitled
United States of America, et. al., v. Union Corporation, et. al., Civil
Action No. 80-1589. |
||
| (5) | The Klockner Road site
is located in Hamilton Township, Mercer County, New Jersey, and occupies
approximately two acres on PSE&G’s Trenton Switching Station property.
PSE&G has entered into a memorandum of agreement (MOA) with the NJDEP
for the Klockner Road site pursuant to which PSE&G will conduct an RI/FS
and remedial action, if warranted, of the site. Preliminary investigations
indicated the potential presence of soil and groundwater contamination at
the site. |
|
| (6) | The NJDEP issued Directives
to various entities, including PSE&G, seeking payment of NJDEP’s
anticipated costs of remedial action and of administrative oversight at
the Combe Fill South Sanitary Landfill in Washington and Chester Townships,
Morris County, New Jersey (Combe Site) and directing the respondents to
arrange for the operation, maintenance and monitoring of the implemented
remedial action or pay the NJDEP’s future costs of these activities,
estimated to be $39 million and prepare a work plan for the development
and implementation of a Natural Resource Damage Restoration Plan. The NJDEP
and The United States of America filed separate cost recovery actions pursuant
to CERCLA and/or the Spill Act seeking recovery of site investigation and
remediation response and administrative oversight costs. PSE&G was named
defendant in the NJDEP cost recovery action and a named third party defendant
in the contribution action filed in the United States’ lawsuit. All
of the foregoing claims against PSE&G were resolved by settlement in
2002. |
|
| (7) | 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
PSE&G requiring performance of various remedial actions. PSE&G’s
nexus to the site is based upon the shipment of certain waste oils to the
site for recycling. PSE&G 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. |
|
| (8) | 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 PSE&G’s 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 have executed an Order on Consent with NYSDEC for the investigation
of the site and have entered an agreement among the PRPs for the sharing
of the associated costs. |
|
| ITEM 4. | SUBMISSION OF MATTERS
TO A VOTE OF SECURITY HOLDERS |
|
| PSEG — None. |
||
| PSE&G —
None. |
||
| Power — None. |
||
| Energy Holdings
— None. |
||
40 |
||
PART II
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS |
PSEG
PSEG’s Common Stock is listed on the New York Stock Exchange, Inc. As of December 31, 2002, there were 114,473 holders of record.
The following table indicates the high and low sale prices for PSEG’s Common Stock and dividends paid for the periods indicated:
| Common Stock | High | Low | Dividend Per Share |
||||||||
| |
|||||||||||
| 2002: | |||||||||||
| First Quarter | $ | 46.80 | $ | 40.46 | $ | 0.54 | |||||
| Second Quarter | 47.25 | 41.30 | 0.54 | ||||||||
| Third Quarter | 43.50 | 28.00 | 0.54 | ||||||||
| Fourth Quarter | 32.38 | 20.00 | 0.54 | ||||||||
| 2001: | |||||||||||
| First Quarter | $ | 48.50 | $ | 36.88 | $ | 0.54 | |||||
| Second Quarter | 51.55 | 41.80 | 0.54 | ||||||||
| Third Quarter | 50.00 | 40.21 | 0.54 | ||||||||
| Fourth Quarter | 44.20 | 38.70 | 0.54 | ||||||||
For additional information concerning dividend history, policy and potential preferred voting rights, restrictions on payment and common stock repurchase programs, see Item 7. MD&A — Liquidity and Capital Resources and Note 10. Schedule of Consolidated Capital Stock and Other Securities of the Notes.
PSE&G
All of the common stock of PSE&G is owned by PSEG.
Power
All of Power’s outstanding limited liability company membership interests are owned by PSEG.
Energy Holdings
All of Energy Holdings’ outstanding limited liability company membership interests are owned by PSEG.
41
ITEM 6. SELECTED FINANCIAL DATA
PSEG
The information presented below should be read in conjunction with PSEG’s Consolidated Financial Statements and Notes thereto.
| Years Ended December 31, | |||||||||||||||||
| 2002 | 2001 | 2000 | 1999 | 1998 | |||||||||||||
| (Millions, where applicable) | |||||||||||||||||
| Total Operating Revenues | $ | 8,390 | $ | 7,055 | $ | 6,521 | $ | 6,339 | $ | 5,947 | |||||||
| Income Before Discontinued Operations, | |||||||||||||||||
| Extraordinary Item and Cumulative | |||||||||||||||||
| Effect of a Change in Accounting Principle and Excluding | |||||||||||||||||
| Losses from Argentine Investments | $ | 786 | (A) | $ | 776 | $ | 776 | $ | 736 | $ | 656 | ||||||
| Income Before Discontinued Operations, | |||||||||||||||||
| Extraordinary Item and Cumulative | |||||||||||||||||
| Effect of a Change in Accounting Principle | $ | 416 | $ | 776 | $ | 776 | $ | 736 | $ | 656 | |||||||
| Net Income (Loss) | $ | 245 | $ | 770 | $ | 764 | $ | (81 | ) | $ | 644 | ||||||
| Earnings per Share (Basic and Diluted): | |||||||||||||||||
| Before Discontinued Operations, | |||||||||||||||||
| Extraordinary Item and Cumulative | |||||||||||||||||
| Effect of a Change in Accounting Principle and Excluding | |||||||||||||||||
| Losses from Argentine Investments | $ | 3.76 | (A) | $ | 3.73 | $ | 3.61 | $ | 3.35 | $ | 2.84 | ||||||
| Before Discontinued Operations, | |||||||||||||||||
| Extraordinary Item and Cumulative | |||||||||||||||||
| Effect of a Change in Accounting Principle | $ | 1.99 | $ | 3.73 | $ | 3.61 | $ | 3.35 | $ | 2.84 | |||||||
| Net Income (Loss) | $ | 1.17 | $ | 3.70 | $ | 3.55 | $ | (0.37 | ) | $ | 2.79 | ||||||
| Dividends Declared per Share | $ | 2.16 | $ | 2.16 | $ | 2.16 | $ | 2.16 | $ | 2.16 | |||||||
| As of December 31: | |||||||||||||||||
| Total Assets | $25,742 | $25,156 | $ | 21,084 | $ | 19,061 | $ | 17,991 | |||||||||
| Long-Term Obligations (B) | $11,044 | $10,234 | $ | 5,340 | $ | 4,625 | $ | 4,813 | |||||||||
| Preferred Stock With Mandatory Redemption | $ | 460 | $ | — | $ | 75 | $ | 75 | $ | 75 | |||||||
| Monthly Guaranteed Preferred Beneficial
Interest in PSE&G’s Subordinated Debentures |
$ | 60 | $ | 60 | $ | 210 | $ | 210 | $ | 210 | |||||||
| Quarterly Guaranteed Preferred
Beneficial Interest in PSE&G’s Subordinated Debentures |
$ | 95 | $ | 95 | $ | 303 | $ | 303 | $ | 303 | |||||||
| Quarterly Guaranteed Preferred
Beneficial Interest in PSEG’s Subordinated Debentures |
$ | 705 | $ | 525 | $ | 525 | $ | 525 | $ | 525 | |||||||
| (A) | 2002 results exclude after-tax
charges of $370 million, or $1.77 per share, related to losses from Energy
Holdings’ Argentine investments. See MD&A – Results of Operations
and Note 4. Asset Impairments of the Notes for further discussion. |
| (B) | Includes amounts for capital lease obligations. Increase in debt partially related
to $2.5 billion securitization transaction in 2001 and consolidation of
non-recourse debt. |
42 | |
PSE&G
The information presented 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 Notes to the Consolidated Financial Statements.
| Years Ended December 31, | |||||||||||||||
| 2002 | 2001 | 2000 | 1999 | 1998 | |||||||||||
| (Millions, where applicable) | |||||||||||||||
| Total Operating Revenues | $ | 5,919 | $ | 6,091 | $ | 5,887 | $ | 5,840 | $ | 5,568 | |||||
| Income Before Extraordinary Item | $ | 205 | $ | 235 | $ | 587 | $ | 653 | $ | 602 | |||||
| Net Income (Loss) | $ | 205 | $ | 235 | $ | 587 | $ | (151 | ) | $ | 602 | ||||
| As of December 31: | |||||||||||||||
| Total Assets | $ | 12,429 | $ | 12,927 | $ | 15,267 | $ | 14,724 | $ | 14,669 | |||||
| Long-Term Obligations (A) | $ | 4,890 | $ | 5,020 | $ | 3,634 | $ | 3,149 | $ | 4,095 | |||||
| Preferred Stock With Mandatory Redemption | $ | — | $ | — | $ | 75 | $ | 75 | $ | 75 | |||||
| Monthly Guaranteed
Preferred Beneficial Interest in PSE&G’s Subordinated Debentures |
$ | 60 | $ | 60 | $ | 210 | $ | 210 | $ | 210 | |||||
| Quarterly Guaranteed
Preferred Beneficial Interest in PSE&G’s Subordinated Debentures |
$ | 95 | $ | 95 | $ | 303 | $ | 303 | $ | 303 | |||||
| (A) | Includes amounts for capital lease obligations. Increase in debt related to the $2.5 billion securitization transaction in 2001. |
POWER
Omitted pursuant to conditions set forth in General Instruction I of Form 10K.
ENERGY HOLDINGS
Omitted pursuant to conditions set forth in General Instruction I of Form 10K.
43
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A) |
This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), and PSEG Energy Holdings LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no other representations whatsoever as to any other company.
OVERVIEW OF 2002 AND FUTURE OUTLOOK
Overview
PSEG
PSEG’s subsidiaries consist of a mix of energy-related businesses that together are designed to produce a balanced energy market strategy. Because the nature and risks of these businesses are different, and because they operate in different geographic locations, the combined entity is intended to produce consistent earnings growth in a manner that will mitigate the adverse financial effects of business losses or an economic downturn in any one sector or geographic region.
During 2002, PSEG’s strategy to maintain a diverse portfolio of energy-related businesses helped it to achieve results from its ongoing operations that were well within the revised earnings guidance of $3.70 to $3.90 per share provided to investors in July 2002, and within 6% of the original earnings guidance provided at the beginning of 2002. Management believes that this portfolio approach will help to balance changes in the earnings profiles for PSEG’s individual subsidiaries, providing a foundation for PSEG’s earnings in 2003 and supporting PSEG’s attempt to achieve its targeted long-term 7% annual growth rate as market conditions improve. However, even with this portfolio approach to the business, greater volatility in earnings and cash flows will occur due to the continuing evolution of the energy industry, both in the United States (US) and internationally.
Over recent years, PSEG has realigned its organizational structure to address the competitive environment brought about by the deregulation of the electric generation industry and has transitioned from primarily being a regulated New Jersey utility to operating as a competitive energy company with operations primarily in the Northeastern US and in other select domestic and international markets. As the unregulated portion of the business continues to grow, financial risks and rewards will be greater, financial requirements will change and the volatility of earnings and cash flows will increase. As of December 31, 2002, Power, PSE&G, and Energy Holdings comprised approximately 27%, 48% and 27% of PSEG’s consolidated assets and contributed approximately 60%, 26% and 18% of PSEG’s results for the year ended December 31, 2002, excluding the charges discussed below.
During 2002, the financial markets experienced significant pressures, particularly relating to increased credit and liquidity concerns in the energy industry. In response, PSEG took significant steps to strengthen its balance sheet. Early in 2002, PSEG began issuing approximately $80 million of common stock on an annual basis through its dividend reinvestment program. In September 2002, PSEG issued $460 million of participating units. In the fourth quarter, PSEG issued $458 million of common stock and $180 million of preferred securities. Altogether, PSEG issued over $1.1 billion in equity and equity-linked securities since September 2002 and used the proceeds primarily to reduce short-term debt. For further information regarding the issuances of these equity and equity-linked securities, see Note 10. Schedule of Consolidated Capital Stock and Other Securities.
In addition to these equity issuances, PSEG took steps to significantly reduce its capital expenditures, which were at a peak in 2002. Early in 2002, PSEG announced that Energy Holdings is limiting future investments to contractual commitments, primarily those needed to complete the development of generating plants currently under construction, and recently revised the timeline for the completion of several of Power’s generating station construction projects.
44
The equity issuances and revised capital expenditure program discussed above enabled PSEG to accelerate its planned reduction of its leverage ratio in the fourth quarter. Going into 2003, PSEG’s leverage ratio was 0.61 to 1 as calculated under its credit agreements. This ratio included an after-tax charge in Other Comprehensive Income (OCI) of approximately $297 million related to its pension plan, the result of the accumulated benefit obligation of the pension exceeding the value of its pension assets.
PSE&G
PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the New Jersey Board of Public Utilities (BPU) for its distribution operations and by the Federal Energy Regulatory Commission (FERC) for its electric transmission operations. As such, the earnings of PSE&G are largely determined by the regulation of its rates. PSE&G expects stable earnings and cash flows in the future as it continues its transmission and distribution and sale of electric energy and gas service in New Jersey.
PSE&G’s success will be determined by its ability to maintain system reliability and safety, effectively manage costs and obtain timely and adequate rate relief. The risks from this business generally relate to the regulatory treatment of the various rate and other issues by the BPU and the FERC. In 2002, PSE&G obtained a successful outcome to its gas base rate case, its first in ten years, transferred its gas supply contracts and gas inventory to Power and filed for an increase in electric rates to be effective August 1, 2003. That will mark the end of PSE&G’s four-year transition period, completing its transition to a transmission and distribution business.
Power
Power is focused on a generation market extending from Maine to the Carolinas and the Atlantic Coast to Indiana (Super Region). Power’s strategy is to continue to market its capacity through Basic Generation Service (BGS) related contracts and other bilateral contracts in New Jersey and its target market. Utilizing a generation portfolio diversified by fuel source, technology and market segment, Power seeks to balance its generating capacity, fuel requirements and supply obligations through integrated energy marketing and trading, enhance its ability to produce low cost energy through continued strong nuclear operations and pursue modest growth based on market conditions. Power integrates its electric generation production with its wholesale energy marketing and trading activities and risk management function.
During 2002, record capacity factors at its nuclear facilities, coupled with Power’s ability to use energy trading to manage the risk of its obligations, enabled Power to meet its fixed price demands under the BGS related contracts with economic supply. Power also added to its generating capacity in the Northeast and established a foothold in the New England Independent System Operator (ISO) through its acquisition of two power plants totaling approximately 1,000 MW. Also, Power enhanced its portfolio by becoming a gas commodity supplier to PSE&G under a Basic Gas Supply Service (BGSS) contract.
In response to low energy prices, Power has scaled back its new project anticipated growth, shifting its emphasis more towards potential acquisitions, and has adjusted its generating station construction schedules to better align with anticipated market prices.
Power entered into contracts for the period beginning August 1, 2002 and ending July 31, 2003 with various successful bidders in the New Jersey Basic Generation Service (BGS) Auction. Power was also a participant in the recent BGS auction held in February 2003. Power entered into hourly energy price contracts to be a direct supplier of certain large customers for a ten-month period beginning August 1, 2003 and expiring May 30, 2004. Power also entered into contracts with third parties who are direct suppliers of New Jersey’s Electric Distribution Companies (EDCs). Through these seasonally-adjusted fixed price contracts, Power will indirectly serve New Jersey’s smaller commercial and residential customers for ten-month and 34-month periods beginning August 1, 2003 and expiring on May 30, 2004 and May 30, 2006, respectively. Power believes that its obligations under these contracts are reasonably balanced by its available supply.
45
Energy Holdings
During 2002, a merger was consummated at Energy Holdings to change the form of the business from a corporation to a limited liability company. Energy Holdings succeeded to all the assets and liabilities of PSEG Energy Holdings Inc. in accordance with the New Jersey Limited Liability Company Act. As part of the reorganization, PSEG Resources Inc. became a wholly-owned subsidiary of PSEG Resources LLC (Resources), a newly formed New Jersey limited liability company. This reorganization was completed to further improve efficiencies within the tax reporting process.
Energy Holdings, through PSEG Global Inc. (Global), invests in, owns and operates generation and distribution facilities in select international and US markets. The generation plants sell power under long-term agreements as well as on a merchant basis while the distribution companies are rate-regulated enterprises. Through Resources, Energy Holdings invests in energy-related financial transactions, including leveraged leases, which are designed to produce predictable earnings at reasonable levels.
As a result of the worldwide economic downturn and the adverse development of several risks at certain of its investments, in 2002 Energy Holdings refocused its strategy from one of accelerated growth to one that places emphasis on increasing the efficiency and returns of its existing assets, and, going forward, intends to limit its spending to contractual commitments. In 2002, Energy Holdings recorded the financial impact of these events as it wrote-down its investment in Argentina, discontinued the operations of PSEG Energy Technologies Inc. (Energy Technologies) and a generating facility in India, and recorded goodwill impairment charges. Global will also selectively review its portfolio and seek to monetize, at reasonable values, investments which may no longer have a strategic fit. Resources has shifted its focus from new investments to monitoring its current investment portfolio, primarily energy-related leveraged leases. In 2002, the credit profile of several of the lessees deteriorated. In November 2002, Resources terminated its two lease transactions with affiliates of TXU-Europe, recovered its invested capital and recorded a modest gain on the termination. See Item 7A. Qualitative and Quantitative Disclosures About Market Risk — Credit Risk for further discussion.
Future Outlook
PSEG
PSEG develops a long-range growth target by building business plans and financial forecasts for each major business (PSE&G, Power, Global and Resources). These plans and forecasts incorporate specific, rather than generic, project investments. Key factors which influence the performance of each business, such as fuel input costs and forward power prices, are also incorporated. Sensitivity analyses are performed on the key variables that drive the businesses’ financial results in order to understand the impact of these assumptions on PSEG’s projections. Once plans are in place, PSEG management monitors actual results and the key variables and updates the financial projections to reflect changes in the energy markets, the economy and global conditions. Management believes this monitoring and forecasting process enables it to alter operating and investment plans adequately and appropriately as conditions change.
Looking ahead, PSEG forecasts 2003 results of $3.70 to $3.90 per share for continuing operations, comparable to results for 2002, excluding losses from Argentine investments. This earnings per share guidance is expected to be achieved through results from PSEG’s ongoing operations which is expected to offset the effects of the common equity issuance in November 2002 and the use of a more conservative financing structure as PSEG issued more costly common and preferred equity and fixed-rate debt to replace low cost commercial paper, discussed above. Subsequent to 2003, PSEG seeks to attain its 7% long-term annual growth rate target in earnings per share.
Several key assumptions in PSEG’s 2003 business plan are: Power will continue to be successful in securing BGS-related contracts and managing its obligations under such contracts with available supply; PSE&G will have a successful outcome to its recently filed electric rate case seeking an approximately $250 million increase in electric rates beginning in August 2003 and benefit from more normal weather; Global, with significant cost-cutting measures in place and limited spending planned over the five year planning horizon, will experience improvements in earnings through its focus on increasing the return on its existing assets; and Resources, with less exposure to its investment in the KKR Associates L.P. (KKR) leveraged buyout funds, will continue to be a steady contributor to
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earnings and cash flows. In the later years of the business plan, PSEG expects energy and capacity prices to increase as the current overbuild situation dissipates and reserve margins in the Pennsylvania – New Jersey – Maryland power pool (PJM), the Midwest and Texas return to more reasonable levels.
During 2002, the energy segment of the financial markets experienced significant volatility and, in the third quarter, the fair value of Power's and Energy Holdings' long term debt decreased significantly. The fair value of Power's and Energy Holdings' long-term debt rebounded in the fourth quarter of 2002, returning to more reasonable levels. PSEG's business plan assumes that the fair value of its securities and the securities of its subsidiaries will continue to be valued at reasonable levels, enabling PSEG continued access to capital over the long-term. However, even if volatility returns to the marketplace and the value of PSEG's securities or its subsidiaries' securities are negatively affected, PSEG believes that it has sufficient liquidity to continue meet its business plans. PSEG's business plan also assumes a stable financial marketplace and a reasonable return on its pension plan funds and Nuclear Decommissioning Trust (NDT) Funds which have total investments of approximately $3 billion. Changes in the value of these funds will affect PSEG’s earnings, equity balance and the required amount of funding.
As a result of PSEG’s forecasted operating cash flows and the changes in future capital expenditures, PSEG expects to have funds available to maintain its current dividend policy and have positive cash flow for each of the next five years. PSEG expects to use this free cash flow to continue to enhance its financial profile by reducing leverage. PSEG anticipates that its leverage ratio will decline modestly by the end of the year due capital expenditures being primarily funded with cash from operations, earnings for 2003 exceeding dividend requirements and also the required adoption of SFAS 143, “Accounting for Asset Retirement Obligations” (SFAS 143), which will benefit earnings, and therefore equity. The impact of SFAS 143 is not reflected in PSEG’s 2003 earnings guidance and is expected to more than offset the pension related charge to equity discussed above in Overview.
Dividend payments on common stock for the year ended December 31, 2002 were $2.16 per share and totaled approximately $456 million. Although PSEG presently believes it will have adequate earnings and cash flow in the future from its subsidiaries to maintain common stock dividends at the current level, earnings and cash flows required to support the dividend will become more uncertain as its business continues to evolve. Future dividends declared will necessarily be dependent upon PSEG’s future earnings, cash flows, financial requirements, alternate investment opportunities and other factors. PSEG’s payout ratios were 58% in 2002 and 2001, excluding charges discussed above. PSEG would consider increasing the dividend if the payout ratio fell below 50% and could be sustained at that level.
PSE&G
PSE&G’s success will be dependent, in part, on its ability to obtain a reasonable and timely outcome to its recently filed electric rate case, as well as its ability to continue to recover the regulatory assets it has deferred and the investments it plans to make in its electric and gas transmission and distribution systems. The proposed rate increase would significantly impact PSE&G’s earnings and operating cash flows. The non-depreciation portion of the requested rate increase ($232 million) would have a positive effect on PSE&G’s earnings and operating cash flows. The depreciation portion of the requested rate increase ($18 million) would have no impact on PSE&G’s earnings, as the increased operating cash flows would be offset by higher depreciation charges. The outcome of these matters cannot be predicted, but are expected to be material to PSE&G results of operations, financial condition and net cash flows.
Power
A major risk of Power’s business is that the competitive wholesale power prices that it is 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 it sells energy products, the successful operation of its generating facilities, fluctuations in market prices of energy and imbalances between obligations and available supply. Power is currently constructing projects, which will increase capacity from approximately 13,000 MW to 16,000 MW, net of planned retirements through 2005.
Power’s success as a BGS provider will depend, in part, on its ability to meet its obligations under its full requirements contracts with the BGS suppliers profitably. Power expects to accomplish this by producing energy from its own generation and/or energy purchases in the market. Power also enters into trading positions related to its generation assets and supply obligations. To the extent it does not hedge its obligations, whether long or short, Power will be subject to the risk of price fluctuations that could affect its future results, such as changes in the expected price of energy and capacity that Power sells into the market, increases in the price of energy purchased to meet its supply obligations, the cost of fuel to generate electricity, the cost of emission credits needed for environmental compliance, and the cost of congestion credits which are used by Power to transmit electricity and other factors. In addition, Power is subject to the risk of substandard operating performance of its fossil and nuclear generating units. To the extent there are unexpected outages at Power’s generating facilities, changes in environmental or nuclear regulations or other factors that impact the production by such units or the ability to generate and transmit electricity in a cost effective manner, it may cost Power more to acquire or produce electricity. These risks can be exacerbated by, among other things, changes in demand in electricity usage, such as those due to extreme weather and economic conditions.
Power’s future revenue stream is uncertain because Power cannot accurately predict revenues beyond the termination of the ten-month BGS contracts. However, this uncertainty has been partially mitigated by a portion of the BGS demand being contracted for a 34-month period. Also, certain of Power’s new projects, such as its
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investments in the Lawrenceburg and Waterford projects under construction in Indiana and Ohio, the plants Power acquired in 2002 from Wisvest Corporation in Connecticut and its development of the Bethlehem Energy Center in New York are also subject to the risk of changes in future energy prices as Power has not entered into forward sale contracts for the majority of the expected generation capacity of these facilities. Power also expects that capacity prices will increase over its five year planning horizon as the overbuild situation in the Super Region dissipates as older, less efficient units are retired in the region. Also, since the majority of Power’s generation facilities are concentrated in the Northeast region, changes in future energy supply and demand and energy-related prices in this region could materially affect Power’s results. Also, changes in the rules and regulation of these markets by FERC, particularly changes in the rules in the power pools in which Power conducts business and ability to maintain market based rates, could have an adverse impact on Power’s results. Lastly, in accordance with the Final Decision and Order (Final Order), issued by the BPU in 1999 relating to PSE&G’s rate unbundling, stranded costs and restructuring proceedings, Power will cease collection of Market Transition Charge (MTC) revenues at the end of the transition period in 2003. Power expects MTC revenues will amount to approximately $115 million in 2003. As a result of these variables and risks, Power cannot predict the impact of these potential future changes on its forecasted results of operations, financial position or net cash flows; however, such impact could be material.
In addition, Power’s earnings projections assume that it will continue to optimize the value of its portfolio of generating assets and supply obligations through its energy trading operations. This will depend, in part, on Power’s, as well as its counterparties’, ability to maintain sufficient creditworthiness and to display a willingness to participate in energy trading activities at anticipated volumes. Potential changes in the mechanisms of conducting trading activity could positively or negatively affect trading volumes and liquidity in these energy trading markets compared to the assumptions of these factors embedded in Power’s business plans. Power marks to market derivative instruments designated as trading activities and includes the resulting unrealized gains and losses in earnings. The vast majority of these contracts have terms of less than two years and are valued using market exchange prices and broker quotes. Energy trading provides the opportunity for greater returns, but it also is more risky than a regulated business and can be adversely impacted by fluctuating energy market prices and other factors. Power utilizes what it believes to be a conservative risk management strategy to minimize exposure to market and credit risk. For further information, see MD&A — Accounting Issues, Note 1. Organization and Summary of Significant Accounting Policies and Note 12. Risk Management of the Notes. As a result of these variables, Power cannot predict the impact of these potential future changes on its forecasted results of operations, financial position or net cash flows; however, such impact could be material.
Energy Holdings
Global will focus on improving the profitability of its generation and distribution investments. Resources, with recent investments and less exposure to its investment in the KKR leveraged buyout funds, expects to continue to be a steady contributor to earnings and cash flows.
Global
While Global realized substantial growth prior to 2002, significant challenges began developing during the fourth quarter of 2001 and continued into 2002. These challenges include the Argentine economic, political and social crisis, the soft power market in Texas, recent developments in India and the worldwide economic downturn. The financial effects of several of these challenges are behind Energy Holdings as a result of the charges recorded in 2002. Global has recently reached a settlement with The AES Corporation (AES) related to certain of Global’s investments held for sale in Argentina. Similarly, Global has completed the sale of its investment in Tanir Bavi Power Company Private Ltd. (Tanir Bavi) in India at its reduced carrying value, receiving proceeds of approximately $45 million in October 2002. Global has refocused its strategy from one of accelerated growth to one that places emphasis on increasing the efficiency and returns of its existing assets and intends to limit its spending to contractual commitments. Global is also selectively reviewing its portfolio and will seek to monetize, at reasonable values, investments which may no longer have a strategic fit. As part of this review, Global recently entered into a memorandum of understanding to sell its interest in Prisma, a generation business in Italy, to its partners for approximately $69 million. The sale is expected to close in the first half of 2003, contingent upon successful project financing.
Energy Holdings’ success will be dependent, in part, on its ability to mitigate risks presented by its international strategy. The economic and political conditions in certain countries where Global has investments present risks that may be different than those found in the US including: unilateral renegotiation or nullification of existing contracts, changes in law or tax policy, interruption of business, risks of nationalization, expropriation, war and other factors.
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Operations in foreign countries also present risks associated with currency exchange and convertibility, inflation and repatriation of earnings. In some countries in which Global has interests, economic, political and monetary conditions and other factors could affect Global’s ability to convert its cash distributions to US Dollars or other freely convertible currencies. Although Global generally seeks to structure power purchase contracts and other project revenue agreements to provide for payments to be made in, or indexed to, US Dollars or a currency freely convertible into US Dollars, its ability to do so in all cases may be limited.
The international risks discussed above can potentially be magnified due to the volatility of foreign currencies. The foreign exchange rates of the Venezuelan Bolivar and Brazilian Real materially weakened in 2002 due to various political and economic factors. This resulted in a reduction in Global’s investment and equity balances and resulted in comparatively lower contributions from Global’s distribution investments in US Dollar terms. While Energy Holdings still expects certain of its investments in Latin America to contribute favorably to its earnings in the future, the political and economic risks associated with this region could have a material adverse impact on its remaining investments in the region.
The table below reflects Energy Holdings’ investment exposure in Latin American countries:
| Investment Exposure | Equity Exposure | ||||||||||
| December 31, | December 31, | ||||||||||
| 2002 | 2001 | 2002 | 2001 | ||||||||
| (Millions) | |||||||||||
| Argentina | $ | — | $ | 632 | $ | — | $ | 632 | |||
| Brazil | 436 | 467 | 234 | 298 | |||||||
| Chile | 578 | 542 | 475 | 465 | |||||||
| Peru | 454 | 387 | 455 | 388 | |||||||
| Venezuela | 51 | 53 | 51 | 53 | |||||||
The investment exposure consists of Global’s invested equity plus equity commitment guarantees. Equity exposure is equal to Global’s investment net of foreign currency translation adjustments, reflected in OCI.
Venezuela
As of December 31, 2002, Global had $49 million, or less than 1%, of its assets invested in the Turboven generation facilities in Maracay and Cagua, Venezuela. This project was fully funded by equity. Venezuela is undergoing a period of significant political instability, as participation in prolonged work stoppages and violent street protests have caused a drastic reduction in economic activity. Following its 45% decline against the US Dollar in 2002, the Venezuelan currency, the Bolivar, has declined further in value in 2003, and additional declines are possible. Turboven’s earnings and cash flows are expected to be affected by the prospects of reduced economic activity and increased exchange rate volatility. Although Turboven’s power purchase contracts are indexed to the US Dollar, the sharp decline in economic activity and in the exchange rate make the local sales price of Turboven’s energy supplies less attractive to local manufacturers. Turboven’s revenues have already declined and are expected to remain below previous levels due to weakening demand for the products manufactured by Turboven’s customers, which includes a utility and certain industrial companies.
Brazil
As of December 31, 2002, Global owns a 32% interest in Rio Grande Energia (RGE), a distribution company in Brazil. The carrying value of this investment as of December 31, 2002 was $211 million, net of pre-tax cumulative translation adjustments of $225 million. For a discussion of the impairment of a portion of the goodwill balance at RGE due to the adoption of SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS 142), see Note 2. New Accounting Standards of the Notes.
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The Brazilian economy is in a period of slowed growth that has resulted from the high public and private sector debt levels, as well as increased interest rates used by the Central Bank of Brazil to control rising inflation and to support the value of the Brazilian Real following its 34% decline in 2002.
In January 2003, a new government administration assumed office and has a stated goal of reducing the effect of currency devaluations and wholesale prices as inputs to final consumer prices for electricity. Additionally, the new administration’s energy industry policy is to cancel future privatizations of state-owned energy companies and increase federal government control and coordination of energy industry policies previously controlled by state and regional entities.
The current regulatory regime adjusts consumer electric tariffs based on a multiple-factor formula that includes recovery of wholesale inflation for previous periods, as well as an additional entitlement to pass through deferred US Dollar costs. This current regulatory structure would result in an increase of approximately 40% in the tariffs RGE would charge its customers starting in April 2003. Failure to receive a reasonable tariff increase, unfavorable developments relating to potential changes in the regulatory structure and/or greater exertion of price controls by the Brazilian government could have a materially adverse impact on Energy Holdings’ ability to earn a reasonable return on its investment and could materially impact its ability to recover its investment balance, including a potential impairment. Other risk factors that could affect future revenues and cash flows from Energy Holdings’ investment in RGE are continued high interest rate levels, currency devaluation, extended recession and slow economic growth.
Texas
As of December 31, 2002, Global had $222 million, net of derivative valuations, invested in a 50/50 joint venture which operates two 1,000 MW gas-fired combined-cycle electric generating facilities in Texas, including approximately $73 million of loans earning an annual interest rate of 12%. The loan structure was put in place to provide Global with a preferential cash and earnings flow from the projects after third-party debt service. Losses from Texas Independent Energy L.P. (TIE) were greater than expected due to lower energy prices resulting from over-supply of energy in the Texas power market for the year ended December 31, 2002. Global expects this trend of lower energy prices to continue until the 2004-2005 time frame when market prices are expected to increase, as older less efficient plants in the Texas power market are expected to be retired and the demand for electricity is expected to increase. However, no assurances can be given as to the accuracy of these estimates.
Continued weakness in the Texas power market will put pressure on TIE’s ability to meet financial covenants in its loan documents. Discussions are underway with the projects’ lenders to improve flexibility in meeting these covenants. Potential remedies may include modest additional equity investments by Global in the Texas facilities. Total project level non-recourse debt of $527 million at the Texas facilities is due over the next five years. These debt maturities include $210 million in 2006 and $213 million in 2007. In the event the project-level debt cannot be repaid or refinanced at the project level, Global may consider certain alternatives including additional equity investments.
Resources
Over the longer term, Resources’ earnings and cash flow streams are dependent upon the availability of suitable transactions and its ability to continue to enter into these transactions. Based on current market conditions and Energy Holdings intent to limit capital expenditures, it is unlikely that Resources will make significant investments in the near term. Resources faces risks with regard to the creditworthiness of its counterparties, as well as the risk of a change in the current tax treatment of its investments in leveraged leases. The manifestation of either of these risks could cause a materially adverse effect on Energy Holdings’ strategy and its forecasted results of operations, financial position, and net cash flows. For discussion of the five counterparties to these leases, including Resources’ aggregate gross investment of $749 million, or $455 million, net of deferred taxes of $294 million, as of December 31, 2002, with those who have been downgraded to below investment grade by at least one of the rating agencies, see Item 7A. Qualitative and Quantitative Disclosures about Market Risk.
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Energy Technologies is a business that principally constructs, installs, and maintains heating, ventilating and air conditioning (HVAC) equipment and related services. Energy Technologies is comprised of 11 HVAC and mechanical operating companies. In June 2002, Energy Holdings adopted a plan to sell its interests in the HVAC/mechanical operating companies which is expected to be completed by June 30, 2003. Also, the Demand Side Management (DSM) business previously conducted by Energy Technologies and which Energy Holdings decided to retain during the third quarter of 2002, was transferred to Resources as of December 31, 2002.
RESULTS OF OPERATIONS
PSEG
PSEG’s business consists of four reportable segments, which are Power, PSE&G, Global and Resources. 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 its segments.
PSEG’s results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power and Energy Holdings. For a more detailed discussion of the changes referenced for PSEG, see the applicable results of operations discussion for each respective subsidiary registrant.
Net income for the period ended December 31, 2002 was $245 million or $1.17 per share of common stock, both basic and diluted, based on approximately 209 million average shares outstanding. Excluding certain after-tax charges of $541 million or $2.59 per share for the year ending December 31, 2002, results were $786 million or $3.76 per share. The charges relate to the asset impairment of investments in Argentina and losses from operations of those impaired assets, discontinued operations of Energy Technologies, and a generating facility in India, and goodwill impairment charges related to the adoption of SFAS 142.
| Earnings (Losses) | |||||||||
| Year Ended December 31, | |||||||||
| 2002 | 2001 | 2000 | |||||||
| (Millions) | |||||||||
| Power | $ | 468 | $ | 394 | $ | 313 | |||
| PSE&G | 201 | 230 | 369 | ||||||
| Energy Holdings: | |||||||||
| Resources | 78 | 71 | 75 | ||||||
| Global | (302 | ) | 100 | 40 | |||||
| Other (A) | (8 | ) | (4 | ) | (13 | ) | |||
| Other (B) | (21 | ) | (15 | ) | (8 | ) | |||
| Subtotal | 416 | 776 | 776 | ||||||
| Loss from Discontinued Operations, including Loss on Disposal |
(51 | ) | (15 | ) | (12 | ) | |||
| Cumulative Effect of a Change in Accounting Principle (C) |
(120 | ) | 9 | — | |||||
| Total PSEG Net Income | $ | 245 | $ | 770 | $ | 764 | |||
| Total PSEG Excluding Charges (D) | $ | 786 | $ | 776 | $ | 776 | |||
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| Contribution
to Earnings Per Share (Basic and Diluted) |
|||||||||
| Year Ended December 31, | |||||||||
| 2002 | 2001 | 2000 | |||||||
| Power | $ | 2.24 | $ | 1.89 | $ | 1.46 | |||
| PSE&G | 0.96 | 1.11 | 1.71 | ||||||
| Energy Holdings: | |||||||||
| Resources | 0.37 | 0.34 | 0.35 | ||||||
| Global | (1.44 | ) | 0.48 | 0.19 | |||||
| Other (A) | (0.04 | ) | (0.02 | ) | (0.06 | ) | |||
| Other (B) | (0.10 | ) | (0.07 | ) | (0.04 | ) | |||
| Subtotal | 1.99 | 3.73 | 3.61 | ||||||
| Loss from Discontinued
Operations, including Loss on Disposal |
(0.24 | ) | (0.07 | ) | (0.06 | ) | |||
| Cumulative Effect
of a Change in Accounting Principle (C) |
(0.58 | ) | 0.04 | — | |||||
| Total PSEG Net Income | $ | 1.17 | $ | 3.70 | $ | 3.55 | |||
| Total PSEG Excluding Charges (D) | $ | 3.76 | $ | 3.73 | $ | 3.61 | |||
| (A) | Other activities include amounts
specific to Energy Holdings, Energy Technologies, Enterprise Group Development
Corporation (EGDC) and intercompany eliminations. Specific amounts include
interest on certain financing transactions and certain other administrative
and general expenses at Energy Holdings. |
| (B) | Other activities include amounts
specific to PSEG and intercompany eliminations. Specific amounts include
interest on certain financing transactions and certain other administrative
and general expenses at PSEG (parent company). |
| (C) | Relates to the adoption of SFAS 142 in 2002 and the adoption of SFAS No.
133 “Accounting for Derivative Instruments and Hedging Activities”
(SFAS 133) in 2001. |
| (D) | Amount for 2002 excludes after-tax
charges presented in the summary table below of $541 million or $2.59 per
share for the year ended December 31, 2002. For 2001 and 2000, these amounts
reflect Income Before Discontinued Operations and Cumulative Effects of
Changes in Accounting Principle. |
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The after-tax charges relating to the items discussed above are summarized in the following table:
Year
Ended December 31, 2002 |
||||||||
| |
||||||||
| (Millions) | Per Share Impact |
|||||||
| |
||||||||
|
Global |
||||||||
| Argentina – EDEERSA (A) and Assets Held for Sale to AES | ||||||||
| Write-down of Project Investments | $ | 370 | $ | 1.77 | ||||
| Goodwill impairment | 36 | 0.18 | ||||||
| Total Argentina | 406 | 1.95 | ||||||
| India – Tanir Bavi | ||||||||
| Discontinued Operations | 9 | 0.04 | ||||||
| Goodwill impairment | 18 | 0.09 | ||||||
| Total Tanir Bavi | 27 | 0.13 | ||||||
| Brazil – RGE | ||||||||
| Goodwill impairment | 34 | 0.16 | ||||||
| Subtotal for Global | 467 | 2.24 | ||||||
| Energy Technologies | ||||||||
| Discontinued Operations | 42 | 0.20 | ||||||
| Goodwill impairment | 32 | 0.15 | ||||||
| Subtotal Energy Technologies | 74 | 0.35 | ||||||
| Total | $ | 541 | $ | 2.59 | ||||
| (A) | Empresa Distribuidora de Electricidad
de Entre Rios S.A. (EDEERSA) |
| Excluding
the charges discussed above, earnings for the year ended December 31, 2002
were largely consistent with the prior year. This is primarily due to higher
margins at Power due to its successful participation as an indirect supplier
of energy to New Jersey’s utilities resulting from the recent BGS auction. The BGS-related contracts, which went
into effect on August 1, 2002 had a meaningful effect on PSEG’s earnings,
particularly during the fourth quarter when Power served its contractual
obligations with low cost energy during the colder months. The strong performance
of Power’s nuclear generation facilities, which operated at a combined
capacity factor of 94% during 2002, accounted for 60% of Power’s generation
output, providing low cost energy to meet its demand and delivering solid
margins. PSE&G also improved earnings, due to stronger margins from
gas rate relief, more favorable weather effects as compared to the prior
year and a cost containment effort which reduced operating expenses during
2002. These positive factors were offset by higher interest costs at PSEG,
Power and Energy Holdings, the absence of certain tax benefits realized by PSE&G
in 2001 and comparatively lower contributions from investments at Energy
Holdings, particularly the loss of earnings from Energy Holdings’ Argentine
investments, continued weakness in the Texas markets and a lower gain from
the Eagle Point Cogeneration Partnership (Eagle Point) transactions. | |
| Basic
and diluted earnings per share of PSEG’s common stock (Common Stock)
was $3.70 for the year ended December 31, 2001, an increase of $0.15 per
share, or 4.2% from the comparable 2000 period, including $0.12 of accretion
as a result of PSEG’s stock repurchase program, discussed in Liquidity
and Capital Resources. In addition, PSEG’s increased earnings for 2001
as compared to 2000 resulted from improved energy trading margins from Power,
Global’s withdrawal and sale of its interest in Eagle Point, acquisitions and expanded operations at Global,
new leveraged lease investments at Resources and strong performance of Power’s
nuclear facilities. These increases more than offset the effects of unfavorable
weather conditions at PSE&G, two BPU mandated 2% rate reductions effective
in February 2001 and August 2001, which reduced Power’s revenues and
the effects of the securitization transaction that occurred on January 31,
2001. | |
53 | |
PSEG
Operating Revenues
For the year ended December 31, 2002, Operating Revenues increased by $1.3 billion or 19%, due primarily to Power’s BGS or commodity revenues subsequent to July 2002 not being eliminated in consolidation by PSEG. Under the BGS contract, which terminated on July 31, 2002, Power sold energy directly to PSE&G, which in turn sold this energy to its customers. These revenues were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s consolidated financial statements. For the new BGS contract period which began on August 1, 2002, Power entered into contracts with third parties who are direct suppliers of New Jersey’s EDCs and PSE&G purchases the energy for its customers’ needs from such direct suppliers. Due to this change in the BGS model, these revenues are no longer intercompany revenues and therefore are not eliminated in consolidation. For the year ended December 31, 2002, PSEG’s elimination related to intercompany BGS and MTC revenues decreased by approximately $798 million as compared to 2001 due to this change. Also related to this change in the BGS model, PSE&G, in 2002, began selling energy purchased under non-utility generation (NUG) contracts, which it had previously sold to Power, to third parties. As a result, for the year ended December 31, 2002, PSEG’s revenues related to NUG contracts increased by approximately $82 million.
The remaining increase was due primarily to a $516 million increase from Power primarily related to the new BGS related revenues from third party wholesale electric suppliers which went into effect August 1, 2002 and revenues from off-system gas sales, partially offset by lower MTC revenues and lower net trading revenues as discussed further under the Power segment discussion. Also contributing to the increase was a $111 million increase at Energy Holdings driven by higher electric revenues at Global, relating to acquisitions and projects going into operation and higher leveraged lease income at Resources, partially offset by lower investment earnings, as discussed below under Energy Holdings’ segment discussion. Additionally, increases were partially offset by a $172 million decrease in revenues from PSE&G primarily due to a decrease in gas distribution revenues, resulting partially from an average cost reduction of more than 10% in the cost of gas, in addition to other items discussed below under the PSE&G segment discussion.
Operating Revenues increased by $534 million or 8% for the year ended December 31, 2001 as compared to 2000 due to a $204 million increase at PSE&G, primarily due to increased gas distribution revenues due to higher gas costs experienced in 2001, discussed further below in PSE&G, a $177 million increase at Power, primarily due to increased BGS revenue which resulted from customers returning to PSE&G in 2001, discussed further below in the Power segment discussion, and a $166 million increase at Energy Holdings primarily due to revenues related to various majority-owned acquisitions and plants going into operation in 2001 at Global, the gain on the withdrawal and sale of Global’s interest in Eagle Point and improved revenues from higher leveraged lease income from new leveraged lease transactions at Resources, partially offset by lower net investment gains at Resources and lower energy supply revenues, discussed further below under the Energy Holdings segment discussion.
Operating Expenses
Energy Costs
For the year ended December 31, 2002, as compared to the prior year, Energy Costs increased approximately $1.1 billion or 41% due primarily to the fact that PSE&G no longer purchases electric energy directly from Power, as discussed above in Operating Revenues, but rather from third party wholesalers. In 2001, and through July 31, 2002, PSE&G incurred energy costs related to electric energy transactions between it and Power. Accordingly, these costs were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s consolidated financial statements. Amounts attributable to this change totaled $880 million between the years ended December 31, 2002 and 2001.
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The remaining increase was due to a $352 million increase at Power primarily related to increased energy purchases and third party wholesale electric supplier contracts, discussed further below in Power, and a $92 million increase at Energy Holdings, relating to acquisitions and projects going into operation at Global, discussed further below in Energy Holdings. These increases were partially offset by a $229 million decrease at PSE&G due primarily to decreased gas costs which resulted from lower demand, discussed further below in PSE&G.
Energy Costs increased $251 million or 10% in 2001 as compared to 2000 due to a $91 million increase at Power, largely due to increased volumes under the BGS-related contracts, discussed further below in Power, and increases at PSE&G, primarily due to a $167 million increase in gas costs related to increased demand and higher prices for gas, as discussed further below in PSE&G. These increases were partially offset by an $11 million decrease at Energy Holdings due to a decision to exit the energy supply business, partially offset by higher costs relating to acquisitions.
Operations and Maintenance
For the year ended December 31, 2002, Operations and Maintenance expense increased $55 million or 3% as compared to 2001 due primarily to increases caused by scheduled outages at certain of Power’s electric generating stations, and an increase at Energy Holdings of $46 million, primarily due to costs associated with acquisitions and projects going into operation. This increase was partially offset by a $14 million decrease at PSE&G primarily due to decreased labor and professional service costs and partially offset by higher DSM amortization, discussed further below in PSE&G, and other charges of $12 million at PSEG.
Operation and Maintenance expense increased $135 million or 8% in 2001 as compared to 2000 due primarily to increases of $56 million at PSE&G, partially relating to the deferral of costs incurred during 2000 in connection with deregulation that PSE&G expects to recover in future rates, $52 million of higher expenses at Power, primarily relating to projects going into operation during the second quarter of 2000, and a $29 million increase at Energy Holdings, primarily related to costs associated with acquisitions late in 2000 and during 2001.
Depreciation and Amortization
For the year ended December 31, 2002, Depreciation and Amortization increased $75 million or 15% as compared to 2001, primarily due to increases of $39 million at PSE&G, mainly due to a full period’s recognition of amortization of the regulatory asset related to stranded costs for securitization, $13 million at Power, primarily due to increases from Bergen 2 being placed into service in 2002 and the absence of a prior year reversal of cost of removal reserves in 2002, and $19 million at Energy Holdings, primarily related to costs associated with acquisitions and projects going into operation.
For the year ended December 31, 2001, Depreciation and Amortization increased $146 million or 42% as compared to 2000 primarily due to the amortization of the regulatory asset recorded for stranded costs, which commenced with the issuance of the transition bonds on January 31, 2001, and $10 million at Energy Holdings related to costs associated with acquisitions late in 2000 and during 2001. These increases were partially offset by a $41 million decrease at Power, primarily due to a reduction in the accrual for the estimated cost of removal of Power’s generating stations. There was an additional increase of $13 million at PSEG primarily due to asset additions made in 2001.
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes is comprised of the Transitional Energy Facility Assessment (TEFA) at PSE&G. Taxes Other Than Income Taxes increased $10 million or 8% in 2002 as compared to 2001. This increase was primarily due to a reduction of $7 million in the prior year’s TEFA recorded in 2001 and an increase of $3 million in the 2002 TEFA due to increased sales. Legislation enacted in January 2002 freezes the TEFA unit rate surcharges at the 2001 levels through 2004 and then reduces the rates over the next three years, phasing out the TEFA by 2007.
Taxes Other Than Income Taxes decreased $14 million or 10% in 2001 as compared to 2000. This decrease was due primarily to a reduction of $7 million in the prior year’s TEFA recorded in 2001 and a reduction of $7 million from lower net taxable sales subject to the TEFA combined with a reduction in the TEFA rate.
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Other Deductions
For the year ended December 31, 2002, Other Deductions increased by $64 million as compared to 2001, primarily due to a $61 million increase in foreign currency transaction losses at Energy Holdings.
For the year ended December 31, 2001, Other Deductions increased by $12 million as compared to 2001, primarily due to a $9 million increase in foreign currency transaction losses at Energy Holdings.
Interest Expense
For the year ended December 31, 2002, Interest Expense increased $61 million or 8% as compared to 2001 primarily due to higher amounts of debt outstanding at PSEG, Power and Energy Holdings used to support various projects and acquisitions and for other general corporate purposes, partially offset by decreases at PSE&G due to lower debt levels.
For the year ended December 31, 2001, Interest Expense increased $151 million or 26% as compared to 2000 due primarily to the securitization debt issued in January 2001 at PSE&G. The increases in Interest Expense were also due to generally higher levels of debt at PSEG, Power and Energy Holdings used to support various projects and acquisitions and for other general corporate purposes.
Preferred Securities Dividends
For the year ended December 31, 2002, Preferred Securities Dividends decreased approximately $15 million primarily due to PSE&G’s redemptions of $448 million of preferred securities in March and June of 2001, partially offset by the issuance of $460 million of participating units and $180 million of trust preferred securities at PSEG in September 2002 and December 2002, respectively.
For the year ended December 31, 2001, Preferred Securities Dividends decreased approximately $22 million primarily due to PSE&G’s redemptions of $448 million of preferred securities in March and June of 2001.
Income Taxes
For the year ended December 31, 2002, Income Taxes decreased $133 million or 35% as compared to 2001 primarily due to lower pre-tax income partially offset by adjustments in 2001 reflecting the conclusion of the 1994-96 IRS audit settlement and the actual filing of the 2000 tax return.
For the year ended December 31, 2001, Income Taxes decreased $115 million or 23% as compared to 2000. The decrease was primarily due to lower pre-tax income, adjustments in 2001 as a result of closing the audit for the 1994-1996 tax years and the actual filing of the tax return for 2000.
PSE&G
Operating Revenues
For the year ended December 31, 2002, PSE&G’s Operating Revenues decreased $172 million or 3%, primarily due to a decrease of $155 million in gas distribution revenues. This decrease was due to lower commodity revenues resulting from an average cost reduction of more than 10% in the cost of gas (approximately $125 million). Also contributing to the decrease were lower sales to interruptible customers resulting from the lower cost of gas (approximately $88 million) and lower off-system sales revenues (approximately $26 million). These decreases were partially offset by increased gas base rates and increased volumes, primarily due to residential usage driven by favorable weather conditions (approximately $75 million) and increased appliance service revenues (approximately $14 million). In addition, electric transmission and distribution revenues decreased $17 million, primarily due to a 4.9% rate reduction implemented in August 2002 under the Final Order and rate reductions in February and August 2001 totaling 4%, (approximately $123 million) which were recorded as reductions in MTC
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revenues. Also affecting 2002 performance were decreases in NUG sales at market prices (approximately $15 million), lower DSM sales due to revenue adjustments in 2001 (approximately $19 million) and lower fiber optic revenues due to unfavorable market conditions (approximately $7 million). These were offset by increased BGS revenues, primarily due to customers returning to PSE&G from third party suppliers (approximately $104 million), and higher distribution volumes for residential and commercial customers (approximately $37 million) due to favorable weather conditions.
For the year ended December 31, 2001, PSE&G’s Operating Revenues increased $204 million or 3%, primarily due to increased gas distribution revenues of $153 million due to higher gas costs experienced in 2001. Customer rates in all classes of business had increased in 2001 to recover a portion of the higher natural gas costs. The commercial and industrial classes fuel recovery rates vary monthly according to the market price of gas. The BPU also approved increases in the fuel component of the residential class rates of 16% in November 2000 and 2% for each month from December 2000 through July 2001. These increased revenues were partially offset by lower sales volumes in the fourth quarter of 2001 than the comparable period in 2000, primarily resulting from warmer weather. Also contributing to the higher revenues were increases in electric distribution and appliance service revenue (approximately $39 million) and increased electric commodity sales volumes (approximately $17 million) offset by rate reductions. The MTC tariff rate decreased 2% in February 2001, effective with the implementation of securitization. Effective August 1, 2001, PSE&G implemented another 2% rate reduction as required by the Final Order, which brought, at that time, the total rate decrease to 9% since August 1, 1999. These rate reductions amounted to approximately $100 million in 2001, an increase of approximately $40 million as compared to 2000, and were funded through the MTC component of rates, which, along with BGS revenues, was remitted to Power through Energy Costs.
Under the BGSS, BGS and Levelized Gas Adjustment Clause (LGAC in 2001), PSE&G’s electric and gas costs in excess of (or below) the amount included in current commodity rates, are probable of being recovered from (returned to) customers through future commodity rates. PSE&G defers (records) costs in excess of (or below) the amount included in current commodity rates. Therefore any increase or decrease in PSE&G’s electric and gas commodity revenue is offset by a corresponding increase or decrease in gas costs on the Consolidated Statements of Operations. PSE&G’s electric and gas commodity revenues consist of BGS revenues, MTC revenues, NUG revenues, gas firm commodity revenues and gas interruptible revenues.
Operating Expenses
Energy Costs
For the year ended December 31, 2002, PSE&G’s Energy Costs decreased $229 million or 6% due primarily to a decrease in gas costs of approximately $230 million which resulted from lower commodity sales volumes (approximately $125 million), lower volumes from interruptible customers due to lower rates (approximately $88 million) and lower off-system sales volumes (approximately $18 million). Also contributing to the decrease were lower electric costs due to the MTC rate reductions discussed above in Operating Revenues (approximately $123 million) and decreased NUG energy sales due to lower rates (approximately $15 million). Offsetting these decreases were increased electric energy costs due to higher commodity sales volumes from customers returning from third party suppliers and a scheduled increase in the shopping credit (approximately $104 million) and higher amounts paid to Power relating to the amortization of the excess electric distribution depreciation reserve, a component of MTC (approximately $30 million).
For the year ended December 31, 2001, Energy Costs increased $1.0 billion as compared to 2000 primarily due to higher electric energy costs (approximately $845 million) resulting from higher sales volumes and from PSE&G purchasing electricity from Power subsequent to August 2000. Also contributing to the increased Energy Costs were increased gas costs primarily due to higher natural gas costs (approximately $167 million). The increase was partially offset by lower natural gas purchases due to lower sales volumes resulting from warmer weather in the fourth quarter of 2001 as compared to the same period in 2000. Due to the LGAC, gas costs are increased or decreased to offset a corresponding increase or decrease in fuel revenues with no impact on income.
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Operations and Maintenance
Operations and Maintenance expense decreased $14 million or 1% in 2002 as compared to 2001 primarily comprised of decreased labor costs (approximately $9 million), decreased use of professional and contract services (approximately $7 million), lower charges for administrative and general services (approximately $7 million) and lower equipment rental (approximately $8 million). These decreases were offset by increased DSM amortization (approximately $14 million) and increased miscellaneous accounts receivable reserves (approximately $3 million).
Operations and Maintenance expense decreased $301 million or 23% in 2001 as compared to 2000 primarily due to the elimination of $357 million in Operations and Maintenance expenses resulting from the transfer of the generation business to Power in August 2000. The decrease was partially offset by the deferral of costs incurred during 2000 in connection with deregulation that PSE&G expects to recover in future rates.
Depreciation and Amortization
Depreciation and Amortization expense increased $39 million or 11% in 2002 as compared to 2001 primarily due to a full period’s recognition of amortization of the regulatory asset related to stranded costs for securitization (approximately $37 million). Also contributing was an increase in depreciable fixed assets (approximately $13 million) and higher depreciation expense recorded in accordance with increased gas base rates for plant assets (approximately $7 million). The increases were partially offset by higher amortization of the excess electric distribution depreciation reserve (approximately $22 million).
Depreciation and Amortization expense increased $84 million or 29% in 2001 as compared to 2000 primarily due to approximately $180 million of amortization of the regulatory asset recorded for stranded costs, which commenced with the issuance of the transition bonds on January 31, 2001. This increase was partially offset by the elimination of $77 million of Depreciation and Amortization expense resulting from the transfer of the generation business to Power in August 2000.
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes increased $10 million or 8% in 2002 as compared to 2001. This increase was primarily due to a reduction of $7 million in the prior year’s TEFA recorded in 2001 and an increase of $3 million in the 2002 TEFA due to increased sales. Legislation enacted in January 2002 freezes the TEFA unit rate surcharges at the 2001 levels through 2004 and then reduces the rates over the next three years, phasing out the TEFA by 2007.
Taxes Other Than Income Taxes decreased $14 million or 10% in 2001 as compared to 2000. This decrease was due primarily to a reduction of $7 million in the prior year’s TEFA recorded in 2001 and a reduction of $7 million from lower net taxable sales subject to the TEFA combined with a reduction in the TEFA rate.
Other Income
Other Income decreased $83 million or 75% in 2002 as compared to 2001, due primarily to PSEG’s settlement of an intercompany loan from PSE&G in 2001 (approximately $65 million) and lower interest income on investments (approximately $16 million). This was offset by a gain on disposal of properties (approximately $6 million).
Other Income decreased $62 million or 36% in 2001 as compared to 2000, due primarily to PSE&G’s intercompany loans to PSEG and Power in 2001 (approximately $65 million) and decreased interest income (approximately $125 million). The intercompany loan was a step in PSE&G’s recapitalization as a result of the transfer of its generation business to Power. This was offset by lower gains on disposal of properties (approximately $3 million).
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Interest Expense
Interest Expense decreased $44 million or 10% for the year ended December 31, 2002 as compared to 2001, due to the redemption of short-term debt in the third quarter of 2001 and lower interest rates in 2002 (approximately $14 million), the redemption of a floating rate note in 2001 (approximately $8 million), the maturity of long-term debt (approximately $14 million), the repurchase of Pollution Control Bonds (approximately $3 million), the carrying costs on the deferred repair allowance (approximately $7 million) and NJ state accrued tax interest adjustments (approximately $2 million). These decreases were partially offset by higher securitization bond interest expense (approximately $7 million) related to Transition Funding’s securitization bonds.
Interest Expense increased $53 million or 13% in 2001 as compared to 2000 primarily due to interest of approximately $176 million on the bonds issued by Transition Funding on January 31, 2001. These were partially offset by $118 million in lower interest resulting from the reduction of short-term and long-term debt with the proceeds from the securitization bonds and the transfer of generation-related assets to Power.
Income Taxes
Income taxes increased $26 million or 29% for the year ended December 31, 2002 as compared to 2001 primarily due to prior period tax adjustments recorded in 2001 reflecting the conclusion of the 1994-96 IRS audit settlement and the actual filing of the 2000 tax return.
Income taxes decreased $318 million or 78% in 2001 as compared to 2000. These decreases were primarily due to lower operating income due to the transfer of the generation business in 2000. In addition, taxes decreased due to normal adjustments as a result of closing the 1994-96 IRS audit and upon filing the actual tax return for the year 2000.
Power
Operating Revenues
For the year ended December 31, 2002, Power’s Operating Revenues increased $1.2 billion or 50% primarily due to the inclusion of $804 million of gas revenues relating to its BGSS contract and off-system gas sales resulting from the operations under the Gas Contracts transferred from PSE&G in May 2002. Also contributing to the increase was a $560 million increase in BGS related revenues, primarily due to the new BGS related revenues from third party wholesale electric suppliers which went into effect August 1, 2002 which was partially offset by lower MTC revenues of $98 million mostly due to a 4.9% rate reduction in August 2002 and two 2% rate reductions in August 2001 and February 2001. Also offsetting the increases were lower net trading revenues of approximately $83 million due to lower trading volumes and prices during 2002 as compared to 2001.
For the year ended December 31, 2001, Power’s Operating Revenues increased $177 million or 8% primarily due to an increase of $180 million in BGS revenue which resulted from customers returning to PSE&G in 2001 from third party suppliers as wholesale market prices exceeded fixed BGS rates. At December 31, 2001, third party suppliers 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%. Also, net revenues from energy trading increased by $57 million or 78% for the year ended December 31, 2001. Partially offsetting this increase was a net $40 million decrease in MTC revenues, relating to two 2% rate reductions, discussed above, offset by a pre-tax charge to income related to the recognition of MTC revenues in 2000.
Operating Expenses
Energy Costs
For the year ended December 31, 2002, Power’s energy costs increased $1.1 billion or 127% compared to 2001 primarily due to increased energy purchase volumes and third party wholesale electric supplier contracts of approximately $297 million and $738 million of increased gas purchases to satisfy Power’s BGSS contract with
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PSE&G. Also contributing to the increase were higher network transmission expenses of $102 million. These higher expenses were partially offset by a $67 million decrease in NUG purchases. Additionally, the record capacity factor of its nuclear units enabled Power to produce low cost generation for much of its supply needs.
For the year ended December 31, 2001, energy costs increased $91 million over the 2000 period. The increase was largely due to increased volumes under the BGS-related contracts. The higher volumes produced, coupled with increased fuel costs, mainly natural gas, contributed to the increase. These increases were partially offset by low cost generation from the continued strong performance of Power’s nuclear generation facilities.
Operations and Maintenance
For the period ended December 31, 2002, Operations and Maintenance expense increased $35 million or 5% as compared to the same period in 2001 due primarily to increases caused by scheduled outage work at electric generating stations.
Operation and Maintenance expense increased $52 million or 8% in 2001 as compared to 2000. Contributing to the increase were higher expenses relating to projects going into operation during the second quarter of 2000.
Depreciation and Amortization
For the period ended December 31, 2002, Depreciation and Amortization expense increased $13 million or 14% as compared to the same period in 2001 due primarily to increases from Bergen 2 being placed into service in 2002 and the absence of a prior year reversal of cost of removal reserves in 2002.
Depreciation and Amortization expense decreased $41 million or 30% in 2001 as compared to 2000. The decrease was primarily due to a reduction in the accrual for the estimated cost of removal of Power’s generating stations.
Interest Expense
Interest Expense decreased $21 million or 15% for the year ended December 31, 2002 from the comparable period in 2001 primarily due to improved financing rates and the repayment of intercompany notes, which resulted in a decrease in expense of $83 million. Offsetting these reductions were $94 million of increased interest expense associated with the issuance of the $2.4 billion of senior notes including $600 million issued in 2002, $124 million of pollution control bonds and increased non-recourse financing associated with Lawrenceburg and Waterford, offset by capitalized interest relating to various construction projects of $32 million.
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 $2.8 billion 14.2% promissory note to PSE&G, issued to finance the acquisition of PSE&G’s generation business.
Income Taxes
Income Taxes increased $63 million or 25% for the year ended December 31, 2002 as compared to 2001, and increased $42 million or 20% for the year ended December 31, 2001 as compared to 2000. The increases for both years were due primarily to increases in pre-tax income.
Energy Holdings
Operating Revenues
Energy Holdings’ revenues increased $111 million, or 17%, to $749 million in 2002 from $638 million in 2001. This increase was driven by higher electric revenues at Global and higher leveraged lease income at Resources, partially offset by lower investment earnings, as discussed below.
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Energy Holdings’ revenues increased $166 million, or 35%, to $638 million in 2001 from $472 million in 2000. Increases totaling $235 million at Global and Resources, described below, were partially offset by $67 million of lower Energy Supply Revenues, as Energy Holdings exited that business in 2000.
Global
For the year ended December 31, 2002, the operating revenues increase of $105 million or 27% at Global was due primarily to the acquisitions in the second half of 2001 of Sociedad Austral de Electricidad S.A. (SAESA) ($79 million), a Chilean distribution company and Empresa de Electricidad de los Andes S.A. (Electroandes) ($46 million), a Peruvian hydroelectric generation and transmission company. Global’s operating revenues also increased $57 million due to the generation facility located in Rades, Tunisia commencing operation in the second quarter of 2002. Also contributing $49 million to the increase in revenues was Skawina CHP Plan (Skawina), a generation facility in Poland, in which Global purchased a majority ownership in the second quarter of 2002. Revenues increased at the GWF Power System LP (GWF) energy peaking plants by $20 million as the Hanford and Henrietta Peaking Plants became operational in the second quarter of 2001 and 2002, respectively. Revenues further increased by $12 million due to improved earnings from RGE as new regulatory changes allowed RGE to recover from customers prior tariff charges previously expensed. Partially offsetting these increases was a decrease of $43 million at Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA) due to the economic crisis in Argentina. Reduced earnings of $21 million at the GWF San Francisco Bay Area facilities and of $26 million at TIE, both as a result of lower energy prices in those markets, partially offset the revenue increases as well. Also partially offsetting the increase in revenues at Global were $31 million of losses at Prisma, including operational losses and an impairment to reduce the investment to its net realizable value, net of $11 million of interest income on a Euro-denominated loan owed by the project. Prisma is currently held for sale to Global’s partner in this joint venture, and the sale is expected to be completed in the first half of 2003. In addition, in 2001, Global recorded $75 million for the gain on the sale and withdrawal from the Eagle Point facility compared to the $47 million recorded for the withdrawal in 2002, resulting in a reduction of approximately $28 million.
For the year ended December 31, 2001, revenues in the Global segment increased $227 million primarily due to $128 million of revenues related to various majority-owned acquisitions and plants going into operation in 2001. Global’s revenues also increased from the gain of $75 million on the withdrawal and sale of Global’s interest in Eagle Point and was partially offset by a loss in equity earnings of $17 million, which was recorded in 2000 and not recorded in 2001, as a result of the withdrawal. In addition, revenues benefited from an increase of $45 million in interest income related to certain loans and notes, and approximately $29 million of increased revenues relating primarily to improved earnings of certain non-consolidated projects. These increases were partially offset by lower revenues due to a reduction in earnings related to the adverse effect of foreign currency exchange rate movements between the US Dollar and Brazilian Real.
Resources
Resources’ operating revenues increased $6 million for the year ended December 31, 2002, as compared to 2001, primarily due to an increase of $44 million from higher leveraged lease income. The increase was mostly offset by lower net investment gains (losses) of $39 million, of which $37 million resulted from other than temporary impairments of non-publicly traded equity securities within certain leveraged buyout funds and other investments, and $8 million resulted from a net decrease in the gains on the sale of properties subject to leveraged leases. For further discussion of other than temporary impairments, see Note 12. Risk Management – Equity Securities. There was also a net increase of $6 million associated with the change in the carrying value of publicly traded equity securities in certain leveraged buyout funds. The decreases in the values of the publicly traded equity securities in 2002 and 2001 were $10 million and $16 million, respectively.
Of the $44 million increase in leveraged lease income in 2002, $29 million resulted from a gain due to a recalculation of certain leveraged leases. A change in an essential assumption which affects the estimated total net income over the life of a leveraged lease requires a recalculation of the leveraged lease, from inception, using the revised information. The change in the net investment in the leveraged leases is recognized as a gain or loss in the year the assumption is changed. The change in assumption which occurred was related to a change in New Jersey tax rates applied in the leveraged lease calculations. This was due to the restructuring of Resources from a corporation to an LLC, which resulted in the ability to more efficiently match state tax expenses of an affiliate company with the state tax benefits associated with Resources’ lease portfolio. The remaining $15 million increase in leveraged lease income was due to additional investments in leveraged lease transactions in 2002 and 2001.
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Revenues in the Resources segment increased by $8 million in 2001 compared to 2000 primarily due to improved revenues of $45 million from higher leveraged lease income from new leveraged lease transactions that was partially offset by lower net investment gains of $37 million.
Operating Expenses
Operating expenses increased $647 million for the year ended December 31, 2002 as compared to the same period in 2001. These operating expenses include a $497 million charge associated with the write-down of all Argentine investments and certain loss contingencies.
Operating expenses, less expenses associated with the $497 million impairment of Global’s Argentine investments, increased $141 million for the year-ended 2002 versus 2001 primarily due to operating expenses incurred at SAESA and Electroandes, two acquisitions that occurred in the second half of 2001.
For the year ended December 31, 2001, operating expenses increased $35 million as compared to the same period in 2000, primarily due to costs at Global increasing by $103 million due to energy costs of $55 million for plant acquisitions and other projects commencing operation in 2001, partially offsetting a decrease in the cost of energy sales as Energy Holdings exited the energy supply business in 2000.
Other Income
Other Income increased $19 million in 2002, as compared to 2001 primarily driven by $12 million of net derivative gains resulting from a gain at SAESA of $11 million, with no comparable amount in 2001, and a $13 million gain on the Early Retirement of Debt.
Other Income increased $3 million in 2001, as compared to 2000.
Other Deductions
Other Deductions increased $61 million in 2002, as compared to 2001 primarily due to the re-measuring of the US Dollar denominated debt at EDEERSA to the devaluing Argentine Peso, which resulted in a loss of $68 million. Foreign exchange currency transaction losses were also impacted by a loss of $7 million related to the Chilean Peso at SAESA and a gain of $9 million related to a Euro-denominated loan. Such loan is expected to be repaid in connection with the sale of Prisma. These net increases were partially offset by a $3 million loss on the Early Retirement of Debt in 2001, with no comparable amount in 2002.
Other Deductions increased by $9 million in 2001, as compared to 2000 as a result of higher foreign exchange currency transaction losses related to the Brazilian Real at Global’s investment in RGE and a loss on the early Retirement of Debt of $3 million in 2001.
Interest Expense
Interest Expense increased $34 million or 19% from $180 million in 2001 to $214 million in 2002. The increase was the result of selling $135 million of 8.625% Senior Notes in July 2002 and an increase in project level debt at Global of $273 million. The increase was partially offset by a decrease in interest expense from the repayments of borrowings under the revolving credit facilities.
Interest Expense increased $46 million or 34% from $134 million to $180 million in 2001 as compared to 2000. Interest Expense associated with recourse financing activities increased $45 million primarily due to additional borrowings incurred as a result of equity investments in distribution and generation facilities.
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Income Taxes
Income taxes were a benefit of $150 million for the year-ended December 31, 2002, a decrease of $215 million as compared to 2001. This is primarily a result of the write-downs and asset impairments recorded during 2002, which resulted in a pre-tax loss, thereby creating a tax benefit.
Income taxes increased $14 million or 27% from $51 million to $65 million in 2001 as compared to 2000, primarily attributable to increased pre-tax income.
Losses From Discontinued Operations
Energy Technologies
Energy Holdings reduced the carrying value of the investments in the 11 HVAC/mechanical operating companies to their fair value less costs to sell, and recorded a loss on disposal for the year ended December 31, 2002 of $21 million, net of $11 million in taxes. Energy Holdings’ remaining investment position in Energy Technologies is approximately $56 million, of which approximately $32 million relates to deferred tax assets from discontinued operations, and $12 million relates to certain intercompany payables included in the current liabilities of Discontinued Operations. Although Energy Holdings believes that it will be able to sell the HVAC/mechanical companies, it can give no assurances that it will be able to realize their total carrying values.
Operating results of Energy Technologies’ HVAC/mechanical operating companies, less certain allocated costs from Energy Holdings, have been reclassified into discontinued operations in the Consolidated Statements of Operations. The results of operations of these discontinued operations for the years ended December 31, 2002, 2001 and 2000 yielded additional losses of $21 million (after-tax), $22 million (after-tax) and $12 million (after-tax), respectively.
Tanir Bavi
In the fourth quarter of 2002, Global sold its 74% interest in Tanir Bavi, a 220 MW barge mounted, combined-cycle generating facility in India. Tanir Bavi meets the criteria for classification as a component of discontinued operations and all prior periods have been reclassified to conform to the current year’s presentation. Global reduced the carrying value of Tanir Bavi to the contracted sales price of $45 million and recorded a loss on disposal of $14 million (after-tax) for the year ended December 31, 2002. The operating results of Tanir Bavi for the year ended December 31, 2002 yielded income of $5 million (after-tax). See Note 5. Discontinued Operations of the Notes.
Cumulative Effect of Change in Accounting Principle
In 2002, Energy Holding finalized the evaluation of the effect of adopting SFAS 142 on the recorded amount of goodwill. Under this standard, PSEG was required to complete an impairment analysis of its recorded goodwill and record any resulting impairment. The total amount of goodwill impairments was $120 million, net of tax of $66 million and was comprised of $36 million (after-tax) at EDEERSA, $34 million (after-tax) at RGE, $32 million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir Bavi. All of the goodwill on these companies, other than RGE, was fully impaired. In accordance with SFAS 142, this impairment charge was recorded as of January 1, 2002 as a component of the Cumulative Effect of a Change in Accounting Principle and is reflected in the Consolidated Statements of Operations for the year ended December 31, 2002. See Note 2. New Accounting Standards of the Notes.
In 2001, Energy Holdings adopted SFAS 133, which established accounting and reporting standards for derivative instruments. Energy Holdings recorded an after-tax gain of $9 million as a result of adopting SFAS 133.
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Other
Global
The following summarizes the net contribution to Operating Income and Other Income and Other Deductions by Global’s projects in the following regions for the years ended December 31, 2002, 2001 and 2000. Certain of these amounts include results from Global’s equity method subsidiaries which are recorded net of taxes and financing costs.
| Years Ended December 31, | |||||||||||
| Operating Income and Other Income (Deductions) (A) | 2002 | 2001 | 2000 | ||||||||
| (Millions) | |||||||||||
| North America | $ | 108 | $ | 159 | $ | 91 | |||||
| Chile | 61 | 39 | 14 | ||||||||
| Peru | 54 | 31 | 26 | ||||||||
| Brazil | 20 | 1 | 21 | ||||||||
| Asia Pacific | 6 | 9 | 6 | ||||||||
| All Other | 16 | 6 | 1 | ||||||||
| Global Unallocated Administrative and General | |||||||||||
| Expenses (B) | (58 | ) |
(58 | ) |
(50 | ) | |||||
| (A) | Operating Income plus Other Income
and Deductions in Argentina for the years ended December 31, 2002, 2001
and 2000 was $(558) million, $45 million and $14 million, respectively. |
| (B) | Includes $9 million of Loss Contingencies and Other expenses recorded in 2002 related to Energy Holdings’ investment in EDEERSA. |
Resources
The following summarizes Resources’ lease revenue for the years ended December 31, 2002, 2001 and 2000 by credit quality of lease counterparties:
| Years Ended December 31 | |||||||||
| 2002 | 2001 | 2000 | |||||||
| (Millions) | |||||||||
| Lease Revenue-Investment Grade(1) | $ | 164 | $ | 199 | $ | 155 | |||
| Lease Revenue-Non-Investment Grade or not rated | 96 | 16 | 15 | ||||||
| Total (2) | $ | 260 | $ | 215 | $ | 170 | |||
| Cash Flow Available From Leveraged Leases (3) (4) | $ | 215 | $ | 209 | $ | 244 | |||
| Proceeds from Sale of Capital Leases (5) | 183 | 104 | 89 | ||||||
| Gross Cash Flow from Leveraged Leases | $ | 398 | $ | 313 | $ | 333 | |||
| (1) | Investment Grade means rated investment grade by both S&P and Moody’s. For S&P, the minimum investment grade rating is BBB–. For Moody’s, the equivalent minimum investment grade rating is Baa3. |
| (2) | Operating lease income does not reflect operating lease expense. |
| (3) | Over 80% of lease cash flow is provided by tax payments from PSEG pursuant to a tax allocation agreement between PSEG and Energy Holdings. |
| (4) | The amounts are equal to Income from Capital and Operating Leases from the Consolidated Statements of Operations plus Leveraged Lease Income, Adjusted for Rents Received from the Consolidated Statements of Cash Flows. |
| (5) | In 2002, Resources received $183 million of cash proceeds associated with the termination of two lease transactions with affiliates of TXU-Europe. As a result of these terminations, Resources will pay income taxes of $115 million in 2003. |
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LIQUIDITY AND CAPITAL RESOURCES
The following discussion of liquidity and capital resources is on a consolidated basis for PSEG, noting the uses and contributions of PSEG’s three direct operating subsidiaries, PSE&G, Power and Energy Holdings.
Financing Methodology
PSEG, PSE&G, Power and Energy Holdings
Capital requirements are met through liquidity provided by internally generated cash flow and external financings. PSEG, Power and Energy Holdings from time to time make equity contributions or otherwise provide credit support to their respective direct and indirect subsidiaries to provide for part of their capital and cash requirements, generally relating to long-term investments.
At times, PSEG utilizes intercompany dividends and intercompany loans (except that PSE&G may not make loans to its parent or to affiliates that are not its direct subsidiaries) to satisfy various subsidiary needs and efficiently manage short-term cash needs. Any excess funds are invested in accordance with guidelines adopted by PSEG’s Board of Directors.
External funding to meet PSEG’s and PSE&G’s needs, the majority of the requirements of Power and a substantial portion of the requirements of Energy Holdings, is comprised of corporate finance transactions. The debt incurred is the direct obligation of those respective entities. Some of the proceeds of these debt transactions are used by the respective obligor to make equity investments in its subsidiaries.
As discussed below, depending on the particular company, external financing may consist of public and private capital market debt and equity transactions, bank revolving credit and term loans, commercial paper and/or project financings. Some of these transactions involve special purpose entities (SPEs), formed in accordance with applicable tax and legal requirements in order to achieve specified beneficial financial advantages, such as favorable tax and legal liability treatment. All SPEs are consolidated where PSEG has controlling interest.
The availability and cost of external capital could be affected by each subsidiary’s performance, as well as by the performance of their respective subsidiaries and affiliates. This could include the degree of structural separation between PSEG and its subsidiaries and the potential impact of affiliate ratings on consolidated and unconsolidated 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.
Over the next several years, PSEG, PSE&G, Power and Energy Holdings will be required to refinance maturing debt and expect to incur additional debt and provide equity to fund investment activities. 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 adversely affect PSEG’s financial condition, results of operations and net cash flows.
From time to time, PSEG, PSE&G, Power and Energy Holdings may repurchase portions of their respective debt securities using funds from operations, asset sales, commercial paper, debt issuances, equity issuances and other sources of funding and may make exchanges of new securities, including common stock, for outstanding securities. Such repurchases may be at variable prices below, at or above prevailing market prices and may be conducted by way of privately negotiated transactions, open-market purchases, tender or exchange offers or other means. PSEG, PSE&G, Power and Energy Holdings may utilize brokers or dealers or effect such repurchases directly. Any such repurchases may be commenced or discontinued at any time without notice.
Power and Energy Holdings
A portion of the financing for Global’s projects and investments is generally provided by non-recourse project financing transactions. These consist of loans from banks and other lenders that are typically secured by project and SPE assets and/or cash flows. Two of Power’s projects currently under construction have similar financing.
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Nonrecourse transactions generally impose no material 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 guaranteed by Global, Energy Holdings and/or Power for their respective subsidiaries. The consequences of permitting a project-level default include loss of any invested equity by the parent. PSEG has not currently provided any guarantees or credit support to PSE&G, Power or Energy Holdings, except for the minimum net worth maintenance support agreement to PSEG Capital Corporation (PSEG Capital), a subsidiary of Energy Holdings, which is planned to be eliminated upon maturity of PSEG Capital Corporation’s debt in May 2003.
Cross Default Provisions
PSEG
The PSEG credit agreements contain default provisions under which a default by it, PSE&G, Power or Energy Holdings in an aggregate amount of $50 million would result in a default and the potential acceleration of payment under those agreements. The $350 million PSEG Credit Agreement which expires in December 2005 contains provisions that will eliminate the cross-default to Energy Holdings, once the $495 million Energy Holdings Credit Agreement expires in May 2004, or is renewed prior to that time. PSEG expects to negotiate similar provisions in PSEG’s other credit agreements.
PSE&G
PSE&G’s First and Refunding Mortgage (Mortgage) and its credit agreements have no cross-defaults. The PSE&G Medium-Term Note Indenture has a cross-default to the PSE&G Mortgage. The credit agreements have cross-defaults under which a default by PSE&G in the aggregate of $50 million would result in a default and the potential acceleration of payment under the credit agreements.
Power
The Power Senior Debt Indenture contains a default provision under which a default by it, Nuclear, Fossil or PSEG Energy Resources & Trade LLC (ER&T) in an aggregate amount of $50 million would result in a default and the potential acceleration of payment under the indenture. There are no cross-defaults within Power’s indenture from PSEG, Energy Holdings or PSE&G.
Energy Holdings
Energy Holdings’ credit agreements contain default provisions under which a default by it, Resources or Global in an aggregate amount of $5 million, or a default by PSEG in an aggregate amount of $75 million would result in an event of default and the potential acceleration of payment under those agreements. The Energy Holdings Senior Note Indenture contains cross-default provisions under which a default by it, Resources or Global in an aggregate amount of $25 million would result in a default and the potential acceleration of payment under the indenture.
Debt Covenants
PSEG, PSE&G, Power and Energy Holdings
The credit agreements generally contain customary provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower’s business or financial condition. In that event, loan funds may not be advanced.
As explained in detail below, some of these credit agreements also contain maximum debt-to-equity ratios, minimum cash flow tests and other restrictive 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.
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PSEG
Financial covenants contained in PSEG’s credit facilities include a ratio of debt (excluding non-recourse project financings and securitization debt and including commercial paper and loans, certain letters of credit and similar instruments) to total capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio not be more than 0.70 to 1. As of December 31, 2002, PSEG’s ratio of debt to capitalization was 0.61 to 1. PSEG’s expects that this ratio will decrease slightly later in 2003 due to earnings exceeding dividends and a onetime benefit due to the adoption of SFAS 143. See Note 2. New Accounting Standards of the Notes.
PSEG has issued Deferrable Interest Subordinated Debentures in connection with the issuance of tax deductible preferred securities. If payments on those Deferrable Interest Subordinated Debentures are deferred, in accordance with their terms, PSEG may not pay any dividends on its common stock until such default is cured. Currently, there has been no deferral or default.
PSE&G
Financial covenants contained in PSE&G’s credit facilities include a ratio of Long-Term Debt (excluding Long-Term Debt Maturing within 1 Year) to Total Capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio will not be more than 0.65 to 1. As of December 31, 2002, PSE&G’s ratio of Long-Term Debt to Total Capitalization was 0.53 to 1.
Under its Mortgage, PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2:1, and/or against retired Mortgage Bonds. At December 31, 2002, PSE&G’s Mortgage coverage ratio was 3.6:1. As of December 31, 2002, the Mortgage would permit up to approximately $1 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements.
PSE&G has issued Deferrable Interest Subordinated Debentures in connection with the issuance of tax deductible preferred securities. If payments on those Deferrable Interest Subordinated Debentures are deferred, in accordance with their terms, PSE&G may not pay any dividends on its common or preferred stock until such default is cured. Currently, there has been no deferral or default.
Energy Holdings
Financial covenants contained in Energy Holdings’ credit facilities include the ratio of cash flow available for debt service (CFADS) to fixed charges. At the end of any quarterly financial period such ratio shall not be less than 1.50x for the 12-month period then ending. As a condition of borrowing, the pro-forma CFADS to fixed charges ratio shall not be less than 1.75x as of the quarterly financial period ending immediately following the first anniversary of each borrowing or letter of credit issuance. CFADS includes, but is not limited to, operating cash before interest and taxes, pre-tax cash distributions from all asset liquidations and equity capital contributions from PSEG to the extent not used to fund investing activity. As of December 31, 2002, Energy Holdings ratio of CFADS to fixed charges was 5.5x. In addition, the ratio of consolidated recourse indebtedness to recourse capitalization, as at the end of any quarterly financial period, shall not be greater than 0.60 to 1.00. This ratio is calculated by dividing the total recourse indebtedness of Energy Holdings by the total recourse capitalization. This ratio excludes the debt of PSEG Capital, which is supported by PSEG. As of December 31, 2002, Energy Holdings’ ratio of consolidated recourse indebtedness to recourse capitalization was 0.43 to 1.00.
PSEG Capital has a Medium-Term Note program which provides for the private placement of Medium-Term Notes. Medium-Term Notes are debt instruments, which may be issued with a maturity of 1 to 30 years. This Medium-Term Note program is supported by a minimum net worth maintenance agreement between PSEG Capital and PSEG which provides, among other things, that PSEG (1) maintain its ownership, directly or indirectly, of all outstanding common stock of PSEG Capital, (2) cause PSEG Capital to have at all times a positive tangible net worth of at least $100,000 and (3) make sufficient contributions of liquid assets to PSEG Capital in order to permit it to pay its debt obligations. PSEG will eliminate its support of PSEG Capital debt by May 2003 at which time the total debt outstanding of $252 million will be repaid and the program will terminate.
Ratings Triggers
PSEG, PSE&G, Power and Energy Holdings
The debt indentures and credit agreements of PSEG, PSE&G, Power and Energy Holdings 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, any one or more of the affected companies may be subject to increased interest costs on certain bank debt.
Power
In connection with its energy marketing and trading activities, Power must meet certain credit quality standards as are required by counterparties. If Power loses its investment grade credit rating, ER&T would have to provide credit support (letters of credit or cash), which would significantly impact the cost of the energy trading activities. Power’s Master Agreements and other supply contracts contain margin and/or other collateral requirements that, as of December 31, 2002, could require Power to post additional collateral of approximately $320
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million if Power were to lose its investment grade credit rating. These same contracts provide reciprocal benefits to Power. Providing this credit support would increase Power’s costs of doing business and limit Power’s ability to successfully conduct its energy trading operations.
In addition, Power may be required by its counterparties to meet margin or other security requirements that may include cash payments. Power may also have to provide credit support for certain of its equity commitments if Power loses its investment grade rating.
Energy Holdings
Global and Energy Holdings may have to provide collateral of approximately $85 million for certain of their equity commitments if Energy Holdings’ ratings should fall below investment grade.
Credit Ratings
The current ratings of securities of PSEG and its subsidiaries 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 by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely effect the market price of PSEG’s, Energy Holdings’, Power’s and PSE&G’s securities and serve to increase those companies’ cost of capital and access to capital.
| Moody’s(1) | Standard & Poor’s(2) | Fitch(3) | |||
| |
|
| |||
| PSEG: | |||||
| Preferred Securities | Baa3 | BB+ | BBB | ||
| Commercial Paper | P2 | A2 | Not Rated | ||
| PSE&G: | |||||
| Mortgage Bonds | A3 | A– | A | ||
| Preferred Securities | Baa2 | BB+ | BBB+ | ||
| Commercial Paper | P2 | A2 | F1 | ||
| Power: | |||||
| Senior Notes | Baa1 | BBB | BBB+ | ||
| Energy Holdings: | |||||
| Senior Notes | Baa3 | BBB- | BBB- | ||
| PSEG Capital: | |||||
| Medium-Term Notes | Baa2 | BBB- | BBB+ |
| (1) | On October 11, 2002 Moody’s
reaffirmed these credit ratings but changed the outlook from stable to negative
for PSEG, Power and Energy Holdings. | |
| (2) | Affirmed in the second quarter
of 2002 and noted an outlook of stable. Standard and Poor’s has established
an overall corporate credit rating of BBB for PSEG and each of its subsidiaries
listed above. | |
| (3) | Affirmed in the second quarter
of 2002 and noted an outlook of stable, except for PSE&G Mortgage Bonds,
which was noted as negative. | |
| Short-Term
Liquidity | ||
| PSEG,
PSE&G, Power and Energy Holdings | ||
| In
order to support its short-term financing requirements as well as those
of Power, PSEG has revolving credit facilities that are used both as a source
of short-term funding and to provide backup liquidity for its $1.0 billion
commercial paper program. As of December 31, 2002, PSEG’s consolidated
total short-term debt outstanding was $762 million consisting of $300 million
of commercial paper and $101 million in loans outstanding under its uncommitted
bilateral agreement and the amounts discussed below in PSE&G, Energy
Holdings and Power. See Note 11. Schedule of Consolidated Debt of the Notes
for a table illustrating the credit facilities, amounts outstanding and
available liquidity as of December 31, 2002. | ||
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PSE&G
PSE&G maintains credit facilities to provide backup for its $400 million commercial paper program. As of December 31, 2002, PSE&G had $183 million in commercial paper and $41 million in loans outstanding under its uncommitted bilateral agreement. See Note 11. Schedule of Consolidated Debt of the Notes for a table illustrating the credit facilities, amounts outstanding and available liquidity as of December 31, 2002.
Power
Power has a $50 million credit facility, but primarily relies on PSEG for its short-term financing needs. As of December 31, 2002, there was $6 million outstanding in letters of credit under the credit facility of Power. See Note 11. Schedule of Consolidated Debt of the Notes for a table illustrating the credit facilities, amounts outstanding and available liquidity as of December 31, 2002.
Energy Holdings
Energy Holdings has credit facilities that are used both as a source of short-term funding and to issue letters of credit. As of December 31, 2002, there was $74 million outstanding in letters of credit under the credit facilities of Energy Holdings and $137 million of non-recourse short-term financing at Global. See Note 11. Schedule of Consolidated Debt of the Notes for a table illustrating the credit facilities, amounts outstanding and available liquidity as of December 31, 2002. For information regarding the refinancing of maturing non-recourse short-term financing at SAESA, see Note 13. Commitments and Contingent Liabilities of the Notes.
External Financings
PSEG
In 2002, PSEG began issuing new shares of its common stock under its Dividend Reinvestment Program (DRASPP) and its Employee Stock Purchase Plan (ESPP), rather than purchasing them on the open market. For the year ended December 31, 2002 PSEG issued approximately 2.2 million shares for approximately $78 million pursuant to these plans.
On May 21, 2002, $275 million of Floating Rate Notes matured.
In September 2002, PSEG issued 9.2 million Participating Units with a stated amount of $50 per unit. Each unit consists of a 6.25% trust preferred security of PSEG Funding Trust I due 2007 having a liquidation value of $50, and a stock purchase contract obligating the purchasers to purchase shares of PSEG common stock in an amount equal to $50 on November 16, 2005. In exchange for the obligations under the purchase contract, the purchasers will receive quarterly contract adjustment payments at the annual rate of 4% until such date. The number of new shares issued on November 16, 2005 will depend upon the average closing price per share of PSEG common stock for the 20 consecutive trading days ending the third trading day immediately preceding November 16, 2005. Based on the formula described in the purchase contract, at that time PSEG will issue between 11,429,139 and 13,714,967 shares of its common stock based on a range of closing prices from $33.54 to $40.25 per share. The net proceeds from the sale of the Participating Units were $446 million and were used primarily to reduce short-term debt.
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In October 2002, PSEG closed on a $245 million private placement debt transaction with a five-year average life and seven-year final maturity. The coupon rate was 6.89% and the proceeds were used to reduce short-term debt.
In November 2002, PSEG issued 17.25 million shares of common stock pursuant to an underwritten public offering at a price of $26.55 per share. The net proceeds from the sale of common stock were $443 million and were used to reduce short-term debt.
In December 2002, PSEG Funding Trust II issued 7.2 million shares of $25 par value trust preferred securities. The net proceeds of $174 million were used to reduce short-term debt.
During 2002, PSEG contributed $400 million of equity to Energy Holdings, $200 million to Power and on January 21, 2003, PSEG contributed $170 million of equity to PSE&G.
PSE&G
PSE&G is required to obtain BPU authorization to issue any financing necessary for its capital program, including refunding of maturing debt and opportunistic refinancing. PSE&G has authorization from the BPU to issue up to an aggregate of $1 billion of long-term debt through December 31, 2003 for the refunding of maturing debt and opportunistic refinancing of debt. PSE&G currently has authority to issue up to $750 million of short-term debt through January 4, 2005. In addition, PSE&G expects to securitize approximately $250 million of deferred BGS costs.
In August 2002, $257 million of 6.125% Series RR Mortgage Bonds matured.
In September 2002, PSE&G issued $300 million of 5.125% Medium-Term Notes due 2012, the proceeds of which were used to repay $290 million of 7.19% Medium-Term Notes that matured.
In January 2003, PSE&G issued $150 million of 5.00% Medium-Term Notes due 2013. The proceeds were used to repay $150 million of 6.875% Series MM Mortgage Bonds which matured in January 2003.
Also in January 2003, PSEG contributed $170 million to PSE&G to offset a minimum pension liability charge to OCI in order to maintain its targeted regulated equity ratio at approximately 42%.
During 2002, PSE&G Transition Funding LLC (Transition Funding), a wholly-owned subsidiary of PSE&G, repaid $121 million of securitization bonds.
Since 1986, PSE&G has made regular cash payments to PSEG in the form of dividends on outstanding shares of its common stock. PSE&G paid common stock dividends of $305 million and $112 million to PSEG for the years ended December 31, 2002 and 2001, respectively.
Power
Power’s short-term financing needs are substantially met using PSEG’s commercial paper program or lines of credit discussed above.
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In June 2002, Power issued $600 million of 6.95% Senior Unsecured Notes due 2012. The proceeds were used to repay short-term funding from PSEG, including amounts related to the gas contract transfer from PSE&G in May 2002.
Energy Holdings
In June 2002, Energy Holdings issued an additional $135 million of its 8.625% Series of Senior Notes due February 2008.
In June 2002, July 2002 and October 2002, $98 million, $100 million and $30 million of PSEG Capital medium-term notes (MTNs) with average borrowing rates of 3.12%, 6.95% and 6.80% matured, respectively. These MTNs were refunded with funds from operations and proceeds from borrowings under Energy Holdings’ credit facilities. The remaining maturity under the PSEG Capital Corporation program is $252 million, which matures in May 2003 and is expected to be refinanced through operating cash flows and existing short-term credit facilities.
During 2002, Energy Holdings repurchased approximately $54 million of its outstanding Senior Notes at prices below par value.
OCI Charge for Pension Liability
PSEG, PSE&G, Power and Energy Holdings
Due to the weak financial markets over the past few years, PSEG’s, PSE&G’s, Power’s and Energy Holdings’ pension plan assets have not experienced the returns necessary to outpace the growth of the related pension liabilities. In accordance with SFAS No. 87, “Employers Accounting for Pensions” (SFAS 87), PSEG, PSE&G, Power and Energy Holdings were required to record a minimum pension liability on their respective Consolidated Balance Sheets as of December 31, 2002. As calculated under SFAS 87, a minimum pension liability exists and must be recorded when the accumulated benefit obligation (ABO) of the plan exceeds the fair value of the plan assets. The excess of the ABO over the fair value of the plan assets is recorded as a charge to OCI within the equity section of the Consolidated Balance Sheets. The offsetting adjustment is recorded as a pension liability or as a reduction of certain pension plan intangible assets as applicable. The minimum pension liability is reduced or reversed when cash funding occurs, or when the fair value of the pension plan assets grow to a level above that of the ABO.
As of December 31, 2002, PSEG, PSE&G, Power and Energy Holdings recorded after-tax charges to OCI as follows:
| (Millions) | ||||
| PSE&G | $ | 172 | ||
| Power | 84 | |||
| Energy Holdings | 6 | |||
| Services | 35 | |||
| Total PSEG | $ | 297 | ||
PSEG funded the pension plan by $250 million in 2002 and plans on contributing $175 million in 2003, but will consider increasing this planned contribution to remove the OCI charge based on market conditions. For additional information, see Note 17. Pension, Other Postretirement Benefit (OPEB) and Savings Plans of the Notes.
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CAPITAL REQUIREMENTS
Forecasted Expenditures
PSEG, PSE&G, Power and Energy Holdings
PSEG, Power and Energy Holdings have substantially reduced their respective capital expenditure forecasts in response to tightening market conditions resulting from market and lender concerns regarding the overall economy and the industry in particular, including an investor and rating agency focus on leverage ratios.
It is expected that the majority of each subsidiary’s 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. Projected construction and investment expenditures, excluding nuclear fuel purchases for Power, for PSEG’s subsidiaries for the next five years are as follows:
| 2003 | 2004 | 2005 | 2006 | 2007 | ||||||||||||
| (Millions) | ||||||||||||||||
| PSE&G | $ | 450 | $ | 450 | $ | 450 | $ | 450 | $ | 500 | ||||||
| Power | 500 | 675 | 250 | 75 | 50 | |||||||||||
| Energy Holdings | 100 | — | 50 | 50 | 50 | |||||||||||
|
|
|
| ||||||||||||||
| Total PSEG | $ | 1,050 | $ | 1,125 | $ | 750 | $ | 575 | $ | 600 | ||||||
PSE&G
PSE&G projects future capital needs in order to maintain continuous additions to its transmission and distribution systems to manage reliability. In 2002, PSE&G had net plant additions of $472 million related to improvements in its transmission and distribution system, gas system and common facilities.
Power
Power’s capital needs will be dictated by its strategy to continue to develop as a profitable, growth-oriented supplier in the wholesale power market. Power has revised its schedule for completion of several projects under development to provide better sequencing of its construction program with anticipated market demand. This should allow Power to conserve capital in 2003 and will allow it to take advantage of the expected recovery of the electric markets and its anticipated need for capacity in 2005. Power’s subsidiaries have substantial commitments as part of their ongoing construction programs. Power will continue to evaluate its development and construction requirements in relation to the energy and financial markets.
In 2002, Power made approximately $1.3 billion of capital expenditures, primarily related to developing the Lawrenceburg, Indiana, Waterford, Ohio and Bethlehem, New York (Albany) sites and adding capacity to the Bergen and Linden stations in New Jersey.
Energy Holdings
Energy Holdings’ capital needs in 2003 are limited to fulfilling existing contractual commitments. All of the forecasted expenditures in 2005 through 2007 related to Energy Holdings are discretionary.
In 2002, Energy Holdings’ subsidiaries made net investments totaling approximately $237 million. These investments include a majority interest in a coal-fired generation facility in Poland, additional investments in existing generation and distribution facilities and projects by Global and investments in capital leases by Resources. Partially offsetting these investments was a loan repayment from TIE and proceeds from the termination of two lease transactions with affiliates of TXU-Europe. For further discussion of the loans to TIE and the termination of the two lease transactions, see Note 22. Related-Party Transactions and Note 8. Long-Term Investments of the Notes.
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Disclosures about Long-Term Maturities, Contractual and Commercial Obligations and Certain Investments
The following table summarizes anticipated recourse and non-recourse debt maturities for the years shown. Payments for Transition Funding are based on expected payment dates rather than final maturity dates.
| Long-Term Debt Maturities: | 2003 | 2004 | 2005 | 2006 | Thereafter | ||||||||||
| (Millions) | |||||||||||||||
| PSEG | $ | — | $ | — | $ | — | $ | — | $ | 248 | |||||
| PSE&G | 300 | 286 | 125 | 147 | 2,069 | ||||||||||
| Transition Funding (PSE&G) | 129 | 138 | 146 | 155 | 1,783 | ||||||||||
| Power | — | — | — | 500 | 2,016 | ||||||||||
| Energy Holdings(A) | 252 | 276 | — | — | 1,449 | ||||||||||
| Non-recourse project financing | |||||||||||||||
| Power | — | — | 800 | — | — | ||||||||||
| Energy Holdings | 68 | 42 | 48 | 53 | 710 | ||||||||||
| |
|
|
|
|
|||||||||||
| Total | $ | 749 | $ | 742 | $ | 1,119 | $ | 855 | $ | 8,275 | |||||
| |
|
|
|
|
|||||||||||
| (A) | The $252 million in 2003 for Energy Holdings represents the total remaining maturities under the PSEG Capital Corporation program. |
The following tables, reflect PSEG and its subsidiaries’ contractual cash obligations and other commercial commitments in the respective periods in which they are due.
| Contractual Cash Obligations | Total Amounts Committed |
Less Than 1 Year |
2 - 3 years | 4 - 5 years | Over 5 years | |||||||||||||
| (Millions) | ||||||||||||||||||
| Short - Term Debt Maturities | ||||||||||||||||||
| PSEG | $ | 401 | $ | 401 | $ | — | $ | — | $ | — | ||||||||
| PSE&G | 224 | 224 | — | — | — | |||||||||||||
| Energy Holdings | 137 | 137 | — | — | — | |||||||||||||
| Long - Term Debt Maturities | ||||||||||||||||||
| PSEG | 248 | — | — | — | 248 | |||||||||||||
| PSE&G | 2,927 | 300 | 411 | 260 | 1,956 | |||||||||||||
| Transition Funding (PSE&G) | 2,351 | 129 | 284 | 317 | 1,621 | |||||||||||||
| Power | 3,316 | — | 800 | 500 | 2,016 | |||||||||||||
| Energy Holdings | 2,898 | 320 | 366 | 106 | 2,106 | |||||||||||||
| Preferred Securities Redemptions | ||||||||||||||||||
| PSEG | 705 | — | — | — | 705 | |||||||||||||
| PSE&G | 155 | — | — | — | 155 | |||||||||||||
| Capital Lease Obligations | ||||||||||||||||||
| PSE&G | 80 | 6 | 12 | 12 | 50 | |||||||||||||
| Power | 19 | 1 | 2 | 4 | 12 | |||||||||||||
| Operating Leases | ||||||||||||||||||
| PSE&G | 13 | 3 | 6 | 4 | — | |||||||||||||
| Energy Holdings | 37 | 6 | 9 | 8 | 14 | |||||||||||||
| Services | 8 | 1 | 2 | 2 | 3 | |||||||||||||
| Fuel Purchase Commitments: | ||||||||||||||||||
| Power | 545 | 163 | 140 | 101 | 141 | |||||||||||||
| Total Contractual Cash Obligations | $ | 14,064 | $ | 1,691 | $ | 2,032 | $ | 1,314 | $ | 9,027 | ||||||||
| |
|
|
|
|
||||||||||||||
Power
As of December 31, 2002, Power had guaranteed equity contribution commitments with respect to its subsidiaries of $134 million. Power also issued guarantees with respect to certain energy trading contracts, see Note 13. Commitments and Contingent Liabilities of the Notes for further discussion.
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Energy Holdings
As of December 31, 2002, Energy Holdings had guaranteed equity contribution commitments of $141 million and other guarantees of $167 million.
In the normal course of business, Energy Technologies secures construction obligations with performance bonds issued by insurance companies. As of December 31, 2002, Energy Technologies had performance bonds outstanding of $228 million which were supported by Energy Holdings and of which $45 million was at risk for projects currently under construction. This amount is expected to decrease as Energy Technologies’ construction projects are completed. The performance bonds are not included in the table below. See Note 13. Commitments and Contingent Liabilities of the Notes for further discussion.
| Other Commercial Commitments: | Total Amounts Committed |
Less Than 1 year |
2 - 3 years | 4 - 5 years | Over 5 years | |||||||||||||||||
| |
||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||
| Standby Letters of Credit | ||||||||||||||||||||||
| Power | $ | 73 | $ | 28 | $ | 2 | $ | — | $ | 43 | ||||||||||||
| Energy Holdings | 74 | 70 | — | 4 | — | |||||||||||||||||
| Guarantees and Equity Commitments | ||||||||||||||||||||||
| Power | 134 | 134 | — | — | — | |||||||||||||||||
| Energy Holdings | 265 | 123 | — | 55 | 87 | |||||||||||||||||
| Total Commercial Commitments | $ | 546 | $ | 355 | $ | 2 | $ | 59 | $ | 130 | ||||||||||||
Off Balance Sheet Arrangements
Energy Holdings
Global has certain investments that are accounted for under the equity method in accordance with generally accepted accounting principles (GAAP). Accordingly, amounts recorded on the Consolidated Balance Sheets for such investments represents Global’s equity investment which is increased for Global’s pro-rata share of earnings less any dividend distribution from such investments. The companies in which PSEG invest that are accounted for under the equity method have an aggregate $1.7 billion of debt on their combined, consolidated financial statements. PSEG’s pro-rata share of such debt is $700 million. This debt is non-recourse to PSEG, Energy Holdings, and Global. PSEG is generally not required to support the debt service obligations of these companies. However, default with respect to this nonrecourse debt could result in a loss of invested equity.
Resources has investments in leveraged leases that are accounted for in accordance with SFAS No. 13 “Accounting for Leases.” Leveraged lease investments generally involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease financing, the lessor purchases an asset to be leased. The purchase price is typically financed 80% with debt provided by the creditor and the balance comes from equity funds provided by Resources, as the lessor. The creditor provides long-term financing to the transaction, and is secured by the property subject to the lease. Such long-term financing is non-recourse to Resources. As such, in the event of default, the creditor may only look to the leased asset as security for its loan. As a lessor, Resources has ownership rights to the property and rents the property to the lessee for use in its business operation. As of December 31, 2002, Resources’ equity investment in leased assets was approximately $1.5 billion, net of deferred taxes of approximately $1.3 billion. For additional information, see Note 8. Long-Term Investments of the Notes.
In the event that collectibility of the minimum lease payments to be received by the lessor is no longer reasonably predictable, the accounting treatment for some of the leases may change. In such cases, Resources may deem that a lessee has a high probability of defaulting on the lease obligation. In many instances, Resources has protected its equity investment in such transactions by providing for the direct right to assume the debt obligation under certain circumstances. Debt assumption would be at Resources’ sole discretion and normally only would occur if an appraisal of the leased property yielded a value that exceeds the present value of the debt outstanding.
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Should Resources ever directly assume a debt obligation, the fair value of the underlying asset and the associated debt would be recorded on the Consolidated Balance Sheets instead of the net equity investment in the lease. In 2000, Resources reclassified an investment in a real estate leveraged lease due to the unpredictability of future rent collections, and assumed a debt obligation of $24 million.
ACCOUNTING ISSUES
New Accounting Standards
SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142)
PSEG, PSE&G, Power and Energy Holdings
On January 1, 2002, PSEG, PSE&G, Power and Energy Holdings adopted SFAS 142. Under this standard, PSEG was required to complete an impairment analysis of goodwill by June 30, 2002 and record any required impairment retroactive to January 1, 2002. Under SFAS 142, goodwill is considered a nonamortizable asset and is subject to an annual review for impairment and an interim review when certain events or changes in circumstances occur. The effect of no longer amortizing goodwill on an annual basis was not material to PSEG’s, PSE&G’s, or Power’s financial position and results of operations upon adoption.
Power and Energy Holdings
Power and Energy Holdings evaluated the recoverability of the recorded amount of goodwill based on certain operating and financial factors. Such impairment testing included discounted cash flow tests which require broad assumptions and significant judgment to be exercised by management. As a result of adopting this new standard, in 2002 Energy Holdings recorded after-tax charges to reflect the goodwill impairment of $120 million and such amount has been recognized as a Cumulative Effect of a Change in Accounting Principle in accordance with the new standard. All of these charges related to investments of Energy Holdings. See Note 2. New Accounting Standards of the Notes for additional discussion on the adoption of this standard.
SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143)
PSEG, PSE&G, Power and Energy Holdings
Effective January 1, 2003, PSEG, PSE&G, Power and Energy Holdings will adopt SFAS 143. SFAS 143 addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract.
Under SFAS 143, a company must initially recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred and concurrently capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. A company shall subsequently allocate that asset retirement cost to expense over its useful life. In periods subsequent to the the initial measurement, an entity shall recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either the timing or the amount of the originally estimated cash flows. Changes in the liability due to accretion will be charged to the Consolidated Statements of Operations whereas changes due to the timing or amount of cashflows shall be an adjustment to the carrying amount of the related asset.
PSE&G and Power
Power has performed a review of its potential obligations under SFAS 143 and believes that its quantifiable obligations are primarily related to the decommissioning of its nuclear power plants. Amounts collected from PSE&G customers are remitted to Power and deposited into the Nuclear Decommissioning Trust (NDT) Fund and realized and unrealized gains and losses in the trust were all recorded as changes in the NDT Fund with an offsetting charge to
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the liability. As of December 31, 2002, Power had a $766 million asset and liability recorded on its Consolidated Balance Sheets for nuclear decommissioning.
In addition to the quantifiable obligations, Power identified certain legal obligations that meet the criteria of SFAS 143 which at this time are not quantifiable. These obligations relate to certain industrial establishments subject to the Industrial Site Recovery Act, underground storage tanks subject to the Spill Compensation and Control Act, permits and authorizations, the restoration of an area occupied by a reservoir when the reservoir is no longer needed, an obligation to retire certain plants from operation, prior to the initial burning of fuel from a new plant and the demolition of certain plants and the restoration of the sites on which reside when the plants are no longer in service.
In August 2002, PSE&G filed a petition requesting clarification from the BPU regarding the future cost responsibility for nuclear decommissioning and whether: (a) PSE&G’s customers will continue to pay for such costs; or (b) such customer responsibility will terminate at the end of the four-year transition period on July 31, 2003 and become the sole responsibility of Power. The outcome of this petition will affect the treatment of a material portion of the liability recorded for Power’s nuclear decommissioning obligation. If the BPU determines that PSE&G’s customers will continue to pay for these costs, the majority of the difference between the previously recorded amount of the liability and the liability calculated under SFAS 143 will continue to be deferred on the balance sheet. If the BPU determines that such customer responsibility terminates at the end of the transition period, then the net effect of implementation will be recorded as a one-time benefit as a Cumulative Effect of a Change in Accounting Principle. A decision is expected as part of PSE&G’s electric base rate case, which is expected to be completed prior to July 2003. Although the outcome of this petition cannot be predicted, management believes that the net effect of adopting this accounting standard should be recorded in earnings. Power also has $131 million of liabilities, $7 million of which relates to legal obligations, recorded on its Consolidated Balance Sheets at December 31, 2002 related to the Cost of Removal associated with its fossil generating stations. These potential obligations are required to be reversed upon implementation of SFAS 143.
Therefore, upon adoption of this standard on January 1, 2003, PSEG and Power will record an adjustment for a Cumulative Effect of a Change in Accounting Principle in the Consolidated Statements of Earnings by reducing the existing liabilities to their present value. It is anticipated that the result will be a benefit to net income, and therefore equity, in a range of $300 million to $400 million. Of this amount, $200 million to $300 million relates to interests in certain nuclear units Power purchased from PSE&G which are subject to the BPU issue discussed above, approximately $55 million relates to interests in certain nuclear units Power purchased from Atlantic City Electric Company (ACE) and Delmarva Power and Light Company (DP&L) which are not subject to BPU approval and approximately $70 million relates to the cost of removal liabilities for the fossil units being reversed.
The BPU could decide that the future cost for decommissioning the nuclear units rests with PSE&G’s customers. If that is the case, the portion of the benefit recorded to equity related to the nuclear units Power purchased from PSE&G would be reversed and a regulatory liability would be established. The $55 million related to the nuclear units purchased from ACE and DP&L and the $70 million related to the cost of removal liabilities for the fossil units would be unaffected.
PSE&G
As of December 31, 2002, PSE&G had no legal liabilities, as contemplated under SFAS 143, recorded on the Consolidated Balance Sheets and therefore the effect of adoption will not result in an adjustment to the Consolidated Statement of Operations. PSE&G does, however, have cost of removal liabilities embedded within Accumulated Depreciation pursuant to SFAS 71. Since PSE&G is a regulated enterprise, these amounts will continue to be recorded and presented in Accumulated Depreciation and will be disclosed in accordance with SFAS 143.
PSE&G has identified certain legal obligations that meet the criteria of SFAS 143 which at this time are not quantifiable and therefore unable to be recorded. These obligations relate to certain industrial establishments subject to the Industrial Site Recovery Act, underground storage tanks subject to the Spill Compensation and Control Act, leases and licenses, and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service.
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Energy Holdings
Energy Holdings identified certain legal obligations that met the criteria of SFAS 143 and are not expected to be material to the Consolidated Statement of Operations.
SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144)
PSEG, PSE&G, Power and Energy Holdings
On January 1, 2002, SFAS 144 which provides guidance on the accounting for the impairment or disposal of long-lived assets, became effective. For long-lived assets to be held and used, the new rules are similar to previous guidance which required the recognition of an impairment when the undiscounted cash flows will not recover its carrying amount. The impairment to be recognized will continue to be measured as the difference between the carrying amount and fair value of the asset. The computation of fair value now removes goodwill from consideration and incorporates a probability-weighted cash flow estimation approach if fair value is not readily determinable. The previous guidance provided in SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of”, (SFAS 121) is to be applied to assets that are to be disposed of by sale. Additionally, assets qualifying for discontinued operations treatment have been expanded beyond the former major line of business or class of customer approach. Long-lived assets to be disposed of by other than sale will now recognize impairment at the date of disposal, but will be considered assets to be held and used until that time. There was no impact on the Consolidated Financial Statements due to adoption of these rules.
SFAS No. 145, “Rescission of FASB Statements Nos. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections” (SFAS 145)
PSEG, PSE&G, Power and Energy Holdings
Effective January 1, 2002, PSEG, PSE&G, Power and Energy Holdings adopted SFAS 145. This Statement rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishments of Debt,” (SFAS 4) and an amendment of that Statement, SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking Fund Requirements” (SFAS 64). SFAS 4 required that gains and losses from extinguishments of debt that were included in the determination of net income be aggregated, and if material, classified as an extraordinary item. Since the issuance of SFAS 4, the use of debt extinguishments has become part of the risk management strategy of many companies, representing a type of debt extinguishment that does not meet the criteria for classification as an extraordinary item. Based on this trend, the FASB issued this rescission of SFAS 4 and SFAS 64. Accordingly, under SFAS 145, PSEG, PSE&G, Power and Energy Holdings now record these gains and losses in Other Income and Other Deductions, respectively.
Energy Holdings
Energy Holdings recorded pre-tax gains of $13 million ($8 million after-tax) from the early retirement of debt as a component of Other Income for the period ended December 31, 2002. Also, Energy Holdings reclassified a pre-tax loss of $3 million ($2 million after-tax) from the early retirement of debt to a component of Other Deductions for the period ended December 31, 2001.
Emerging Issues Task Force (EITF) Issue No. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3)
PSEG, PSE&G and Power
EITF 02-3 requires all gains and losses on energy trading contracts to be reported on a net basis. Also, energy trading contracts that do not qualify as derivatives will no longer be marked to market. Instead, accrual accounting will be used. The consensus was effective for all new contracts executed after October 25, 2002, and requires a cumulative effect adjustment to income in the first quarter of 2003 for all contracts executed prior to October 25, 2002. The vast majority of PSEG’s energy contracts qualify as derivatives under SFAS 133 and will therefore continue to be marked to market. Management believes the impact of adopting this consensus will not be material to the Consolidated Financial Statements.
Pursuant to EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19), PSE&G and Power had been recording trading revenues and trading related costs on a gross basis for physical energy and capacity sales and purchases. In accordance with EITF 02-3, beginning in the third quarter of 2002,
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Power started reporting energy trading revenues and energy trading costs on a net basis and have reclassified prior periods to conform with this net presentation. As a result, both Operating Revenues and Energy Costs were reduced by approximately $1.9 billion, $2.3 billion and $2.6 billion for the years ended December 31, 2002, 2001 and 2000, respectively. This change in presentation did not have an effect on trading margins, net income or cash flows.
Financial Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45)
PSEG, PSE&G, Power and Energy Holdings
FIN 45 enhances the disclosures to be made by a guarantor in its interim and annual Financial Statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee, although PSEG does not anticipate the recording of such liabilities will be material to the Consolidated Financial Statements. The initial recognition and initial measurement provisions of this Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. For further information regarding Power’s and Energy Holdings’ respective guarantees, refer to Note 13. Commitments and Contingent Liabilities of the Notes.
FIN No. 46, “Consolidation of Variable Interest Entities (VIE)” (FIN 46)
PSEG, PSE&G, Power and Energy Holdings
FIN 46 clarified the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements”, to certain entities in which equity investors do not have the characteristics of a controlling financial interest. Because a controlling financial interest in an entity may be achieved through arrangements that do not involve voting interests, FIN 46 sets forth specific requirements with respect to consolidation, measurement and disclosure of such relationships. Disclosure requirements for existing qualifying entities are effective for financial statements issued after January 31, 2003. All enterprises with VIEs created after February 1, 2003, shall apply the provisions of FIN 46 no later than the beginning of the first interim period beginning after June 15, 2003. Although, PSEG, PSE&G, Power and Energy Holdings are evaluating the potential impact of this standard, it is not expected to have a material impact.
Other
PSE&G, Power and Energy Holdings
In connection with the January 2003 EITF meeting, the FASB was requested to reconsider an interpretation of SFAS 133. The interpretation, which is contained in the Derivatives Implementation Group’s C-11 guidance, relates to the pricing of contracts that include broad market indices. In particular, that guidance discusses whether the pricing in a contract that contains broad market indices (e.g., Consumer Price Index) could qualify as a normal purchase or sale under SFAS 133. PSEG, PSE&G, Power and Energy Holdings are currently reevaluating which contracts, if any, that have previously been designated as normal purchases or sales, would now not qualify for this exception. PSEG, PSE&G, Power and Energy Holdings are currently evaluating the effects that this guidance will have on their respective results of operations, financial position and net cash flows.
Critical Accounting Estimates
PSEG, PSE&G, Power and Energy Holdings
Under GAAP, there are many accounting standards that require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. The management of PSEG, PSE&G, Power and Energy
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Holdings has each, respectively, determined that the following estimates are considered critical to the application of rules that relate to its business.
Accounting for Pensions
PSEG, PSE&G, Power and Energy Holdings account for pensions under SFAS 87. Under these rules, certain assumptions which are subjective by nature are made. There are many subjective assumptions involved in determining an entity’s pension liabilities and costs each period including demographic information such as life expectancy and pay increases, and financial metrics, such as discount rates used to determine the pension liability and assumed rate of return on the pension assets which affects annual pension costs. PSEG’s assumptions are supported by historical data and reasonable projections and are reviewed with an outside actuary firm and investment advisors. As of December 31, 2002, PSEG used a 6.75% discount rate and a 9% annual rate of return. In selecting an assumed discount rate, PSEG uses a rate based on a blend of the Aa Moody’s Corporate and Utility Indices. The 9% annual rate of return is consistent with PSEG’s cumulative returns on the pension funds since inception and with a study performed late in 2002 of projected returns for PSEG’s pension funds based on their asset allocation, maturities and an active investment manager.
The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase or decrease in the percentage for each assumption, PSEG, PSE&G, Power and Energy Holdings and its actuaries expect that the inverse of this change would impact the projected benefit obligation (PBO), the reported pension liability on the Consolidated Balance Sheets and the reported annual pension cost on the Consolidated Statements of Operations by a similar amount in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption only.
| Actuarial Assumption | Current | Change/ (Decrease) |
Impact on PBO |
Increase to Pension Expense |
|||||||||||
| (Millions) | |||||||||||||||
| Discount Rate | 6.75 | % | (1 | %) | $ | 350 | $ | 26 | |||||||
| Rate of Return on Plan Assets | 9.0 | % | (1 | %) | — | $ | 22 | ||||||||
Accounting for Derivative Instruments and Hedging Activities
SFAS 133 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, such as energy trading contracts, are adjusted to fair value through earnings. PSEG, PSE&G, Power and Energy Holdings have entered into various derivative instruments, including hedges of anticipated electric and gas purchases, interest rate swaps and foreign currency hedges which have been designated as cash flow hedges. Management may choose to designate these contracts as hedges based on its business practices, if such derivatives meet the effectiveness test under SFAS 133.
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, PSEG, PSE&G, Power and Energy Holdings utilize mathematical models
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based on current and historical data. The fair value of most of PSEG’s derivatives is determined based upon quoted market prices.
For additional information regarding Derivative Financial Instruments, see Note 12. Risk Management of the Notes.
Accounting for Deferred Taxes
PSEG, PSE&G, Power and Energy Holdings provide for income taxes based on the asset and liability method required by SFAS No. 109, “Accounting for Income Taxes”. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as well as net operating loss and credit carryforwards.
PSEG, PSE&G, Power and Energy Holdings evaluate the need for a valuation allowance of their respective deferred tax assets based on the likelihood of expected future taxable benefits. PSEG, PSE&G, Power and Energy Holdings do not believe a valuation allowance is necessary; however, if the expected level of future taxable income changes or certain tax planning strategies become unavailable, PSEG, PSE&G, Power and Energy Holdings would record a valuation allowance through income tax expense in the period the valuation allowance is deemed necessary.
Accounting for Long-Lived Assets
SFAS 144, a new standard related to testing long-lived assets for impairment, was adopted on January 1, 2002. Testing under SFAS 144 is essentially the same as the asset impairment tests PSEG, PSE&G, Power and Energy Holdings performed under SFAS 121. This test consisted of an undiscounted cash flow analysis to determine if an impairment existed, and, if an impairment existed, a discounted cash flow test would be performed to quantify it. The new standard is broader in that it includes discontinued operations as part of its scope. This test requires the same judgment to be employed by management in building assumptions related to future earnings of individual assets or an investment as was required in determining potential impairments of goodwill as discussed above.
These tests are required whenever events or circumstances indicate an impairment may exist. Examples of potential events which could require an impairment test are when power prices become depressed for a prolonged period in a market, when a foreign currency significantly devalues, or when an investment generates negative operating cash flows. Any potential impairment of investments under these circumstances is recorded as a component of operating expenses.
PSE&G
Unbilled Revenues
Electric and gas revenues are recorded based on services rendered to customers during each accounting period. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. Unbilled usage is calculated in two steps. The initial step is to apply a base usage per day to the number of unbilled days in the period. The second step estimates seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. The resulting usage is priced at current rate levels and recorded as revenue. A calculation of the associated energy cost for the unbilled usage is recorded as well. Each month the prior month’s unbilled amounts are reversed and the current month’s amounts are accrued. The resulting revenue and expense reflect the billed data less the portion booked in the prior month plus the unbilled portion of the current month.
SFAS 71 - Accounting for the Effects of Certain Types of Regulation
PSE&G prepares its Consolidated Financial Statements in accordance with the provisions of SFAS 71, which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated
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utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs, which will be amortized over various future periods. To the extent that collection of such costs or payment of liabilities is no longer probable as a result of changes in regulation and/or PSE&G’s competitive position, the associated regulatory asset or liability is charged or credited to income. See Note 7. Regulatory Assets and Liabilities of the Notes for further discussion of these and other regulatory issues.
Power and Energy Holdings
Accounting for Goodwill
SFAS 142 requires an entity to evaluate its goodwill for impairment at least annually or when indications of impairment exist. An impairment may exist when the carrying amount of goodwill exceeds its implied fair value.
Accounting estimates related to goodwill fair value are highly susceptible to change from period to period because they require management to make cash flow assumptions about future sales, operating costs, economic conditions and discount rates over an indefinite life and the impact of recognizing an impairment could have a material impact on financial position and results of operations.
Power and Energy Holdings perform annual goodwill impairment tests and continuously monitor the business environment in which they operate for any impairment issues that may arise. As indicated above, certain assumptions are used to arrive at a fair value for goodwill testing. Such assumptions are consistently employed and include, but are not limited to, free cash flow projections, interest rates, tariff adjustments, economic conditions prevalent in the geographic regions in which Power and Energy Holdings do business, local spot market prices for energy, foreign exchange rates and the credit worthiness of customers. If an adverse event were to occur, such an event could materially change the assumptions used to value goodwill and could result in impairments of goodwill. For further information, see Note 2. New Accounting Standards of the Notes.
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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”, “forecast”, “projections” variations of such words and similar expressions are intended to identify forward-looking statements. PSEG, PSE&G, Power and Energy Holdings 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 PSEG, PSE&G, Power and Energy Holdings’ disclosures prior to the effective date of the Private Securities Litigation Reform Act of 1995.
In addition to the risks identified in MD&A — Overview and Future Outlook and in addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements discussed above, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:
PSEG, PSE&G, Power and Energy Holdings
- credit, commodity, interest rate, counterparty and other financial market risks, could have an adverse impact;
- liquidity and the ability to access capital and credit markets, could have an adverse impact;
- acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG, PSE&G, Power and Energy Holdings’ structure; business combinations among competitors and major customers could change financial position, results of operations or net cash flows;
- general economic conditions including inflation;
- changes to accounting standards or generally accepted accounting principles, which may require adjustments to financial statements and may affect future results;
- changes in tax laws and regulations which could affect cash flows and business prospects;
- energy obligations, available supply and trading risks may have an adverse impact;
- changes in the electric industry including changes to power pools could have an adverse impact;
- regulation and availability of power transmission facilities may impact ability to deliver output to customers;
- growth in costs and expenses could have an adverse impact;
- environmental regulation significantly impacts operations;
- changes in rates of return on overall debt and equity markets could have an adverse impact on the value of pension assets and the NDT fund;
- changes in political conditions, recession, acts of war or terrorism could have an adverse impact;
- insurance coverage may not be sufficient;
- involvement in lawsuits, including liability claims and commercial disputes, could affect profits or ability to sell and market products;
- inability to attract and retain management and other key employees could have an adverse impact;
- ability to service debt as a result of any of the aforementioned events could have an adverse impact;
PSE&G & Energy Holdings
- ability to obtain adequate and timely rate relief;
- regulatory issues significantly impact operations;
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Power and Energy Holdings
- low energy prices could adversely affect revenues and cash flows;
- excess supply due to overbuild in the industry may have adverse effects;
- generation operating performance may fall below projected levels;
- the operations are subject to substantial competition from well capitalized participants in the worldwide energy markets;
- inability to effectively manage trading risk could have an adverse impact;
- margin posting requirements could have an adverse effect on cash flows;
- availabililty of fuel at reasonable prices;
- competitive position could be adversely affected by actions involving competitors or major customers;
- changes in product or sourcing mix could have an adverse impact;
- acquisition, construction and development may not be timely or successful;
- changes in technology may make power generation assets less competitive;
Energy Holdings
- because a significant portion of business is conducted outside the United States, adverse international developments could negatively impact its business;
- changes in foreign currency exchange rates;
- unavailability of leveraged lease investments with adequate returns at reasonable risk could have an adverse impact;
- inadequate operating performance or legal protections of leveraged lease investments could have an adverse impact;
- substandard operating performance or cash flow from investments could fall below projected levels, adversely impacting the ability to service its debt; and
- credit of lessees to service the leases.
Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements and PSEG, PSE&G, Power and Energy Holdings cannot assure you that the results or developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on PSEG, PSE&G, Power and Energy Holdings or its business prospects, financial condition or results of operations. Undue reliance should not be placed on these forward-looking statements in making any investment decision. Each PSEG, PSE&G, Power and Energy Holdings expressly disclaim any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or are anticipated to occur or arise after the date hereof. In making any investment decision regarding PSEG, PSE&G, Power and Energy Holdings’ securities, PSEG, PSE&G, Power and Energy Holdings is not making, and you should not infer, any representation about the likely existence of any particular future set of facts or circumstances. The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
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| ITEM 7A. | QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK |
PSEG, PSE&G, Power and Energy Holdings
The market risk inherent in PSEG’s, PSE&G’s, Power’s and Energy Holdings’ market risk sensitive instruments and positions is the potential loss arising from adverse changes in foreign currency exchange rates, commodity prices, equity security prices and interest rates as discussed in the Notes to the Consolidated Financial Statements. Each of PSEG, PSE&G, Power and Energy Holdings’ policy is to use derivatives to manage risk consistent with its respective business plans and prudent practices. PSEG, PSE&G, Power and Energy Holdings utilize the PSEG Risk Management Committee (RMC) comprised of executive officers which utilizes an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices.
Additionally, PSEG, PSE&G, Power and Energy Holdings are exposed to counterparty credit losses in the event of non-performance or non-payment. PSEG has a credit management process which is used to assess, monitor and mitigate counterparty exposure for PSEG and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG and its subsidiaries’ financial condition, results of operations or net cash flows.
Foreign Exchange Rate Risk
Energy Holdings
Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk is that some of its foreign subsidiaries and affiliates utilize currencies other than the consolidated reporting currency, the US Dollar. Additionally, certain of Global’s foreign subsidiaries and affiliates have entered into monetary obligations and maintain receipts/receivables in US Dollars or currencies other than their own functional currencies. Primarily, Global is exposed to changes in the US Dollar to Brazilian Real exchange rate, the US Dollar to Euro exchange rate, the US Dollar to Polish Zloty exchange rate and the US Dollar to Chilean Peso exchange rate. With respect to the foreign currency risk associated with the Brazilian Real and the Chilean Peso, there has already been significant devaluation since the initial acquisition of these investments, which has resulted in reduced US Dollar earnings and cash flows relative to initial projections. Whenever possible, these subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements, wherever possible, to manage risk related to certain foreign currency fluctuations.
As of December 31, 2002, the devaluing Brazilian Real has resulted in a cumulative $225 million loss of value which is recorded as a $202 million after-tax charge to Other Comprehensive Income related to Global’s equity method investments in RGE, a Brazilian distribution company. An additional devaluation in the December 31, 2002 Brazilian Real to the US Dollar exchange rate of 10% would result in a $3 million change in the value of the investment in RGE and an after-tax $3 million impact to Other Comprehensive Income.
Additionally, Global has $52 million of monetary receivables in Euros subject to fluctuations in the US Dollar to Euro exchange rate. If the December 31, 2002 Euro to US Dollar exchange rate were to change by 10%, Global would record a $4 million after-tax foreign currency transaction gain or loss.
Global also has net monetary positions in the Polish Zloty related to its consolidated investments in ELCHO and Skawina, Polish generation companies. If the December 31, 2002 Polish Zloty to US Dollar exchange rate were to change by 10%, Global would record a $4 million after-tax foreign currency transaction gain or loss.
An additional exposure related to foreign currency risk includes the $157 million of monetary obligations in US Dollars subject to fluctuations in the US Dollar to Chilean Peso exchange rate. If the December 31, 2002 exchange rate of the Chilean Peso to the US Dollar were to change by 10%, Energy Holdings would record an after-tax $9 million foreign currency transaction gain or loss. Such gain or loss should be materially offset by gains or
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losses on the Chilean Peso forward exchange contract hedging such exposure. See Note 12. Risk Management of the Notes.
With respect to any other monetary assets or liabilities subject to foreign currency risk, a 10% change in any individual US Dollar to local currency exchange rate would not be material.
Commodity Contracts
Power and Energy Holdings
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, Power and Energy Holdings enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge their respective anticipated supply and demand differential. These contracts, in conjunction with owned electric generation capacity and demand obligations, make up the portfolio.
Power and Energy Holdings use a value-at-risk (VaR) model to assess the market risk of their respective commodity businesses. This model includes fixed price sales commitments, owned generation, load requirements, physical contracts and financial derivative instruments. VaR represents the potential gains or losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. Power and Energy Holdings estimate VaR across their respective commodity businesses.
Power
VaR Model
Power manages its exposure at the portfolio level. Its portfolio consists of owned generation, gas or electric load-serving contracts, gas supply contracts and energy derivatives designed to manage the risk around the differential between generation and load.
The RMC established a VaR threshold of $50 million for a one-week (5 business days) holding period at a 95% (two-tailed) confidence level. The RMC will be notified if the VaR reaches $40 million and the portfolio will be closely monitored. The risk is monitored by area of responsibility. The Board of Directors of PSEG is notified if a VaR threshold of $75 million is reached.
The current modeling process and methodology has been reviewed by a third party consulting firm. This review included analysis and comparison of Power’s current VaR process and methodology to other processes and methodologies used in the energy industry. PSEG believes the evaluation indicates that Power’s methodology to calculate VaR is reasonable.
The model is an augmented variance/covariance model adjusted for the delta of positions with a 95% two-tailed confidence level for a one-week holding period. The model is augmented to incorporate, the non-log-normality of energy-related commodity prices, especially emissions and capacity and the non-stationary nature of energy volatility. The model also assumes no hedging activity throughout the holding period whereas Power actively manages its portfolio.
As of December 31, 2002, VaR was approximately $7 million, compared to the December 31, 2001, level of $18 million. Previous to 2002, Power’s load was considered an indefinite obligation; therefore, for consistency purposes Power decided to model both the cost to serve its load obligation and the value of its generation assets on a rolling 12-month basis. At present, Power’s load obligation is determined by the results of the annual BGS auction. In February 2003, the BPU held two simultaneous auctions for load obligations covering overlapping time periods. Two-thirds of New Jersey’s fixed-price BGS load was auctioned for the 10 months from August 2003 through May 2004 and the remaining one-third was auctioned for the 34 months from August 2003 through May 2006. The combined result is that all of New Jersey’s fixed-price BGS load is auctioned through May 2004, while only one-third is auctioned for the 24 months from June 2004 through May 2006. To maintain an actionable VaR, generation
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and load (based on an assumed success rate in the auction) are both modeled at 100% of their assumed value through May 2004 and at one-third of the assumed value of each from June 2004 through May 2006.
Power’s VaR Associated with Generating Assets and Commodity Contracts
| For the Year Ended December 31, 2002 | Total VaR | |||
| |
||||
| (Millions) | ||||
| 95% Confidence Level, Five-Day Holding Period, Two-Tailed: | ||||
| Period End | $ | 7.5 | ||
| Average for the Period | $ | 18.1 | ||
| High | $ | 33.8 | ||
| Low | $ | 7.5 | ||
| 99% Confidence Level, One-Day Holding Period, Two-Tailed: | ||||
| Period End | $ | 4.4 | ||
| Average for the Period | $ | 10.7 | ||
| High | $ | 19.9 | ||
| Low | $ | 4.4 | ||
Energy Holdings
VaR Model
In general, Energy Holdings manages its commodity exposure through power purchase agreements. One notable exception is its partial ownership of TIE, which owns two merchant energy plants that manage their risk through short-term energy sales.
The model is a variance/covariance model with a two-tailed 95% confidence level for a one-week holding period. Expected energy output and fuel usage are modeled as forward obligations. The Electric Reliability Council of Texas (ERCOT) system is a closed system and is less liquid than PJM. This makes estimates of volatility and correlation less reliable.
As of December 31, 2002 and December 31, 2001, VaR was approximately $4 million.
Energy Holdings’ VaR Associated with Generating Assets and Commodity Contracts
| For the Year Ended December 31, 2002 | Total VaR | |||
| |
||||
| (Millions) | ||||
| 95% Confidence Level, Five-Day Holding Period, Two-Tailed: | ||||
| Period End | $ | 4.2 | ||
| Average for the Period | $ | 4.9 | ||
| High | $ | 8.1 | ||
| Low | $ | 2.5 | ||
| 99% Confidence Level, One-Day Holding Period, Two-Tailed: | ||||
| Period End | $ | 2.5 | ||
| Average for the Period | $ | 2.9 | ||
| High | $ | 4.8 | ||
| Low | $ | 1.5 | ||
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Interest Rates
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s, PSE&G, Power & Energy Holdings’ policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt, interest rate swaps and interest rate lock agreements. PSEG, PSE&G, Power & Energy Holdings’ manages its interest rate exposure by maintaining a targeted ratio of fixed and floating rate debt. As of December 31, 2002, a hypothetical 10% change in market interest rates would result in a $1 million, $4 million, $2 million, and $2 million, change in annual interest costs related to debt at PSEG, PSE&G, Power and Energy Holdings, respectively. In addition, as of December 31, 2002, a hypothetical 10% change in market interest rates would result in a $8 million, $216 million, $122 million, and $50 million change in the fair value of the debt of PSEG, PSE&G, Power and Energy Holdings, respectively.
Debt and Equity Securities
PSEG
PSEG has approximately $2.1 billion invested in its pension plan. Although fluctuations in market prices of securities within this portfolio do not directly affect PSEG’s earnings in the current period, changes in the value of these investments could affect PSEG’s future contributions to these plans, its financial position if the accumulated benefit obligation under its pension plan exceeds the fair value of its pension funds and future earnings as PSEG would earn a lower return on the fund balance and could be required to adjust its assumed rate of return.
Power
Power’s Nuclear Decommissioning Trust (NDT) fund is comprised of both fixed income and equity securities totaling $766 million at December 31, 2002. The equity securities are independently marked-to-market each month by the Trustee. As of December 31, 2002, the portfolio was comprised of approximately $445 million of equity securities and approximately $321 million in fixed income securities. The fair market value of the NDT assets will fluctuate depending on the performance of equity markets. As of December 31, 2002, a hypothetical 10% change in the equity market would impact the value of Power’s equity securities by approximately $45 million.
Power uses duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. Also, it is an essential tool in immunizing portfolios from interest rate risk. The benchmark for the fixed income component of the NDT Fund is the Lehman Brothers Aggregate Bond Index which currently has a duration of 3.79 years and a yield of 3.66%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2002, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $12 million.
Energy Holdings
Resources has investments in equity securities and limited partnerships. Resources carries its investments in equity securities at their approximate fair value as of the reporting date. Consequently, the carrying value of these investments is affected by changes in the fair value of the underlying securities. Fair value is determined by adjusting the market value of the securities for liquidity and market volatility factors, where appropriate.
As of December 31, 2002, Resources had investments in leveraged buyout funds of approximately $93 million, of which $24 million was comprised of public securities with available market prices and $69 million was comprised of non-publicly traded securities. The
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potential change in fair value resulting from a hypothetical 10% change in quoted market prices of the publicly traded investments amounted to $2 million as of December 31, 2002.
Credit Risk
PSEG, PSE&G, Power and Energy Holdings
Credit risk relates to the risk of loss that PSEG, PSE&G, Power and Energy Holdings would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG, PSE&G, Power and Energy Holdings have established credit policies that they believe significantly minimize 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.
Power
Counterparties expose Power to credit losses in the event of non-performance or non-payment. Power has a credit management process which is used to assess, monitor and mitigate counterparty exposure for Power and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power and its subsidiaries’ financial condition, results of operations or net cash flows. As of December 31, 2002 over 89% of the credit exposure (mark-to-market plus net receivables and payables, less cash collateral) for Power’s trading operations was with investment grade counterparties. The majority of the credit exposure with non-investment grade counterparties is with certain companies that supply fuel to Power. Therefore, this exposure relates to the risk of a counterparty performing under its obligations rather than payment risk. As of December 31, 2002, Power’s trading operations had over 177 active counterparties.
As a result of the New Jersey BGS auction, Power contracted to provide energy to the direct suppliers of New Jersey electric utilities, including PSE&G, commencing August 1, 2002. Subsequently certain bidders failed to meet the credit standards required under the BGS auction process and a portion of the contracts with those bidders was reassigned to Power. Therefore, for a limited portion of the New Jersey retail load, Power is a direct supplier to one utility, although this utility is not PSE&G. Power sells electricity to nine direct supplier-counterparties that serve the load of the utilities, and one utility directly. Four of these supplier-counterparties pay Power directly, and one of the four prepays its purchases. The revenue from the remaining five counterparties is paid directly from the utilities that those suppliers serve, and the related margin due to the counterparties is recorded as a liability and will be remitted to those counterparties separately. These bilateral contracts are subject to credit risk. This risk is substantially higher than the risk that was associated with potential nonpayment by PSE&G or any other electric distribution company (EDC) making direct payment under the BGS contract which expired on July 31, 2002, since the EDCs are rate-regulated entities. This credit risk relates to the ability of counterparties to meet their payment obligations for the power delivered under each BGS-related contract. Any failure to collect these payments under the BGS-related contracts could have a material impact on Power’s results of operations, cash flows and financial position. Power expects the credit risk and risk mitigation measures to be similar under the BGS-related contracts commencing August 1, 2003.
In December 2001, Enron Corp. (Enron) and its subsidiaries filed for reorganization under Chapter 11 of the US Bankruptcy Code. Power had entered into a variety of energy trading contracts with Enron and its affiliates as part of its energy trading activities. Enron has guaranteed the obligations of its subsidiaries. Power undertook various measures to mitigate its exposure to Enron and its subsidiaries and other counterparties which could have been affected by the Enron bankruptcy. As of December 31, 2002, Enron has claimed that Power owes Enron North America approximately $52 million and has asserted that payment obligations of Enron Power Marketing to Power in the amount of $14 million may not be offset against this amount. The parties have engaged in settlement discussions. Power believes that it has valid claims and defenses against Enron and its subsidiaries, which it will vigorously pursue. Based on these discussions, rulings in the bankruptcy proceeding and its evaluations of its legal rights and obligations, Power believes the net amount payable in this matter may approximate $30 million.
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Energy Holdings
Leveraged Leases
Resources has credit risk related to its investments in leveraged leases, totaling $1.5 billion, which is net of deferred taxes of $1.3 billion, as of December 31, 2002. These investments are significantly concentrated in the energy related industry and have some exposure to the airline industry. Resources is the lessor of various aircraft to several domestic and foreign airlines. Resources leases a Boeing B767 aircraft to United Airlines (UAL). In December 2002, UAL filed for Chapter 11 bankruptcy protection. UAL has stated that it intends to retain B767 aircraft and use them in place of the Boeing 747. UAL has an additional debt obligation of $53 million associated with this aircraft. Resources will work constructively with UAL to keep the leveraged lease in place. However, if UAL is unable to meet the lease requirements, Energy Holdings could realize an adverse impact to its Consolidated Statements of Operations and net cash flows. The gross invested balance of this investment as of December 31, 2002 was $21 million.
Resources is the lessor of domestic generating facilities in several US energy markets. As a result of recent actions of the rating agencies due to concerns over forward energy prices, the credit of some of the transaction lessees, or ultimate guarantors of the lease obligations, was downgraded. As of December 31, 2002, 65% of counterparties in the lease portfolio were rated investment grade by both S&P and Moody’s. Specifically, the lessees in the following transactions were downgraded below investment grade during 2002 by these rating agencies. Resources’ investment in such transactions was approximately $455 million, net of deferred taxes of $294 million as of December 31, 2002.
Resources leases 1,173 MW of coal-fired generation to Reliant Energy Mid Atlantic Power Holdings LLC (REMA), an indirect wholly-owned subsidiary of Reliant Resources Incorporated (RRI). The leased assets are the Keystone, Conemaugh and Shawville generating facilities located in the PJM West market in Pennsylvania. In addition to the leased assets, REMA also owns and operates another 2,830 MW located within PJM. REMA is capitalized with over $1 billion of equity from RRI and has no debt obligations senior to the lease obligations. REMA is currently rated B– by S&P and B3 by Moody’s. As the lessor/equity participant in the lease, Resources is protected with significant lease covenants that restrict the flow of dividends from REMA to its parent, and by over-collateralization of REMA with an additional 2,830 MWs of non-leased assets, transfer of which is restricted by the financing documents. Restrictive covenants include historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverages are not met, and similar cash flow restrictions if ratings are not maintained at stated levels. The covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a market downturn or degradation in operating performance of the leased assets. The lease capitalization includes approximately $578 million of non-recourse debt. Resources’ investment in the REMA transaction was $128 million, net of deferred taxes of $92 million as of December 31, 2002.
Resources is the lessor of the Collins facility to Midwest Generation LLC (Midwest), an indirect subsidiary of Edison Mission Energy (EME). Collins is comprised of 2,698 MWs of oil and natural gas-fired assets located in the Mid-American Interconnected Network (MAIN) power market located in the mid-western region of the US. Midwest has a contract with Exelon to supply capacity and energy for 1,078 MWs for Collins through December 2003 with an option to extend. Both Midwest and EME are rated BB- by S&P and Ba3 by Moody’s. In addition to the leased assets, Midwest owns and operates an additional 4,459 MWs of generation assets, excluding the Powerton and Joliet generating stations discussed below. The restrictive covenants protecting Resources are similar to those noted above in the REMA transaction. Midwest has a debt obligation of approximately $1.5 billion at a holding company above Midwest. The Collins lease is pari-passu with this debt obligation. The lease capitalization includes approximately $774 million of non-recourse debt. Resources’ investment in the Collins facility was $107 million, net of deferred taxes of $78 million as of December 31, 2002.
Resources also leases the Powerton and Joliet generating stations located in the MAIN market to Midwest. Both Powerton and Joliet are coal-fired stations comprising 2,896 MWs of gross generating capacity. The lease obligations are guaranteed by EME. The guarantee contains certain restrictive covenants including, but not limited to, additional investment, liens and sales of non-leased collateral. In addition, EME is required to maintain a minimum net worth equal to $400 million plus cumulative, consolidated net income earned by it and its subsidiaries since 1992 (without subtracting losses). The lease capitalization includes
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approximately $733 million of non-recourse debt. Resources’ investment in the Powerton and Joliet transaction was $90 million, net of deferred taxes of $80 million as of December 31, 2002.
Resources is the lessor of the 370 MW coal-fired Danskammer plant to Dynegy Danskammer LLC (Danskammer) and the 1,200 MW natural gas/oil fired Roseton plant to Dynegy Roseton LLC (Roseton). Both Danskammer and Roseton are indirect subsidiaries of Dynegy Holdings Inc (DHI). The lease obligations are guaranteed by DHI which is currently rated B by S&P and Caa2 by Moody’s. The lease capitalization includes approximately $800 million of non-recourse debt. Resources’ investment in the Danskammer and Roseton transaction was $129 million, net of deferred taxes of $43 million as of December 31, 2002. The non-recourse debt and Resources’ equity investment in this transaction represented the full acquisition price of the underlying plants.
In the domestic lease transactions described above, Resources has protected its equity investment by providing for the right to assume the debt obligation at its discretion in the event of default by the lessee with the condition that the lease debt is rated at least equal to the rating that existed at the date of the original transaction. If Resources were pursuing a debt assumption, it would first seek to renegotiate all relevant terms of the agreement with the lenders. Debt assumption normally only would occur if an appraisal of the leased property yielded a value that exceeds the present value of the debt outstanding. Should Resources ever directly assume a debt obligation, the fair value of the underlying asset and the associated debt would be recorded on the Consolidated Balance Sheets instead of the net equity investment in the lease. As of December 31, 2002, Resources determined that the collectibility of the minimum lease payments under its leveraged lease investments is still reasonably predictable and therefore continues to account for these investments as leveraged leases.
Other
In 2000, Global withdrew from its interest in the Eagle Point Cogeneration Partnership (EPCP) with El Paso Corp. in exchange for a series of contingent payments over five years. These payments are expected to total $290 million, subject to certain subsequent annual facility performance factors. When such factors are met on an annual basis the earnings are recorded and the payments are ordinarily received in the same period. The payments to date have been received in accordance with the terms of the agreement, including a payment of $44 million in January 2003. Currently under the withdrawal agreement Global is owed in a form of a note from EPCP approximately $81 million, with the last payment anticipated in January 2005. In the event that EPCP operating cash flows are insufficient to make payment, mandatory capital contributions are required from the partners to pay the note to PSEG Global as amounts become due. Additional covenants in the note security package include mandatory restrictions on cash distributions to the partners and performance guaranties of EPCP’s obligations are required. El Paso Corp indirectly owns in excess of 85% of the partnership interests of EPCP. In February 2003, S&P downgraded El Paso Corp long-term corporate credit rating to B+ from BB and Moody’s reduced El Paso Corp. debt rating to Caa1 from Ba2. If El Paso Corp or its subsidiaries or affiliates is required to fulfill an obligation in accordance with the terms of the agreement and is unable to perform, the impact would adversely effect Energy Holdings’ statements of operations and net cash flows in the years 2004 and 2005.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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FINANCIAL STATEMENT RESPONSIBILITY – (PSEG)
PSEG’s management is responsible for the preparation, integrity and objectivity of its consolidated financial statements and related notes. The consolidated financial statements and related notes are prepared in accordance with generally accepted accounting principles. The financial statements reflect estimates based upon the judgment of management where appropriate. Management believes that the consolidated financial statements and related notes present fairly PSEG’s financial position and results of operations. Information in other parts of this Annual Report is also the responsibility of management and is consistent with these consolidated financial statements and related notes.
The firm of Deloitte & Touche LLP, independent auditors, is engaged to audit PSEG’s consolidated financial statements and related notes and issue a report thereon. Deloitte & Touche’s audit is conducted in accordance with generally accepted auditing standards. Management has made available to Deloitte & Touche all of PSEG’s financial records and related data, as well as the minutes of directors’ meetings. Furthermore, management believes that all representations made to Deloitte & Touche during its audit were valid and appropriate.
Management has established and maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded, and that transactions are executed in accordance with management’s authorization and recorded properly for the prevention and detection of fraudulent financial reporting, so as to maintain the integrity and reliability of the financial statements. The system is designed to permit preparation of consolidated financial statements and related notes in accordance with generally accepted accounting principles. The concept of reasonable assurance recognizes that the costs of a system of internal accounting controls should not exceed the related benefits. Management believes the effectiveness of this system is enhanced by an ongoing program of continuous and selective training of employees. In addition, management has communicated to all employees its policies on business conduct, safeguarding assets and internal controls. Management also maintains a system of disclosure controls and procedures to provide reasonable assurance that PSEG is able to collect, process and disclose, within the time periods specified by the Securities and Exchange Commission, the information required to be disclosed in reports under the Securities Exchange Act of 1934.
The Internal Auditing Department of Services conducts audits and appraisals of accounting and other operations of PSEG and its subsidiaries and evaluates the effectiveness of cost and other controls and, where appropriate, recommends to management improvements thereto. Management considers the internal auditors’ and Deloitte & Touche’s recommendations concerning PSEG’s system of internal accounting controls and has taken actions that, in its opinion, are cost-effective in the circumstances to respond appropriately to these recommendations. Management believes that, as of December 31, 2002, PSEG’s system of internal accounting controls was adequate to accomplish the objectives discussed herein.
The Board of Directors carries out its responsibility of financial overview through its Audit Committee, which presently consists of six directors who are not PSEG employees or any employees of its affiliates. The Audit Committee meets periodically with management as well as with representatives of the internal auditors and Deloitte & Touche. The Audit Committee reviews the work of each to ensure that its respective responsibilities are being carried out and discusses related matters. Both the internal auditors and Deloitte & Touche periodically meet alone with the Audit Committee and have free access to the Audit Committee and its individual members at all times.
| E. JAMES FERLAND | THOMAS M. O’FLYNN |
| Chairman of the Board, | Executive Vice President and |
| President and Chief Executive Officer | Chief Financial Officer |
| PATRICIA A. RADO | |
| Vice President and Controller | |
| (Principal Accounting Officer) |
February 25, 2003
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FINANCIAL STATEMENT RESPONSIBILITY – (PSE&G)
PSE&G’s management is responsible for the preparation, integrity and objectivity of its consolidated financial statements and related notes. The consolidated financial statements and related notes are prepared in accordance with generally accepted accounting principles. The financial statements reflect estimates based upon the judgment of management where appropriate. Management believes that the consolidated financial statements and related notes present fairly PSE&G’s financial position and results of operations. Information in other parts of this Annual Report is also the responsibility of management and is consistent with these consolidated financial statements and related notes.
The firm of Deloitte & Touche LLP, independent auditors, is engaged to audit PSE&G’s consolidated financial statements and related notes and issue a report thereon. Deloitte & Touche’s audit is conducted in accordance with generally accepted auditing standards. Management has made available to Deloitte & Touche all of PSE&G’s financial records and related data, as well as the minutes of directors’ meetings. Furthermore, management believes that all representations made to Deloitte & Touche during its audit were valid and appropriate.
Management has established and maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded, and that transactions are executed in accordance with management’s authorization and recorded properly for the prevention and detection of fraudulent financial reporting, so as to maintain the integrity and reliability of the financial statements. The system is designed to permit preparation of consolidated financial statements and related notes in accordance with generally accepted accounting principles. The concept of reasonable assurance recognizes that the costs of a system of internal accounting controls should not exceed the related benefits. Management believes the effectiveness of this system is enhanced by an ongoing program of continuous and selective training of employees. In addition, management has communicated to all employees its policies on business conduct, safeguarding assets and internal controls. Management also maintains a system of disclosure controls and procedures to provide reasonable assurance that PSE&G is able to collect, process and disclose, within the time periods specified by the Securities and Exchange Commission, the information required to be disclosed in reports under the Securities Exchange Act of 1934.
The Internal Auditing Department of Services conducts audits and appraisals of accounting and other operations and evaluates the effectiveness of cost and other controls and, where appropriate, recommends to management improvements thereto. Management has considered the internal auditors’ and Deloitte & Touche’s recommendations concerning PSE&G’s system of internal accounting controls and has taken actions that are cost-effective in the circumstances to respond appropriately to these recommendations. Management believes that, as of December 31, 2002, the PSE&G’s system of internal accounting controls was adequate to accomplish the objectives discussed herein.
The Board of Directors carries out its responsibility of financial overview through the Audit Committee of PSEG, which presently consists of six directors who are not PSEG nor PSE&G employees of or employees of any of their affiliates. The PSEG Audit Committee meets periodically with management as well as with representatives of the internal auditors and Deloitte & Touche. The Audit Committee reviews the work of each to ensure that their respective responsibilities are being carried out and discusses related matters. Both the internal auditors and Deloitte & Touche, periodically meet alone with the Audit Committee and have free access to the Audit Committee and its individual members at all times.
| E. JAMES FERLAND | ALFRED C. KOEPPE |
| Chairman of the Board and | President |
| Chief Executive Officer | and Chief Operating Officer |
| ROBERT E. BUSCH | PATRICIA A. RADO |
| Senior Vice President – Finance | Vice President and Controller |
| and Chief Financial Officer | (Principal Accounting Officer) |
February 25, 2003
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FINANCIAL STATEMENT RESPONSIBILITY — (Power)
Power’s management is responsible for the preparation, integrity and objectivity of its consolidated financial statements and related notes. The consolidated financial statements and related notes are prepared in accordance with generally accepted accounting principles. The financial statements reflect estimates based upon the judgment of management where appropriate. Management believes that the consolidated financial statements and related notes present fairly Power’s financial position and results of operations. Information in other parts of this Annual Report is also the responsibility of management and is consistent with these consolidated financial statements and related notes.
The firm of Deloitte & Touche LLP, independent auditors, is engaged to audit Power’s consolidated financial statements and related notes and issue a report thereon. Deloitte & Touche’s audit is conducted in accordance with generally accepted auditing standards. Management has made available to Deloitte & Touche all of Power’s financial records and related data, as well as the minutes of directors’ meetings. Furthermore, management believes that all representations made to Deloitte & Touche during its audit were valid and appropriate.
Management has established and maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded, and that transactions are executed in accordance with management’s authorization and recorded properly for the prevention and detection of fraudulent financial reporting, so as to maintain the integrity and reliability of the financial statements. The system is designed to permit preparation of consolidated financial statements and related notes in accordance with generally accepted accounting principles. The concept of reasonable assurance recognizes that the costs of a system of internal accounting controls should not exceed the related benefits. Management believes the effectiveness of this system is enhanced by an ongoing program of continuous and selective training of employees. In addition, management has communicated to all employees its policies on business conduct, safeguarding assets and internal controls. Management also maintains a system of disclosure controls and procedures to provide reasonable assurance that Power is able to collect, process and disclose, within the time periods specified by the Securities and Exchange Commission, the information required to be disclosed in reports under the Securities Exchange Act of 1934.
The Internal Auditing Department of Services conducts audits and appraisals of accounting and other operations and evaluates the effectiveness of cost and other controls and, where appropriate, recommends to management improvements thereto. Management has considered the internal auditors’ and Deloitte & Touche’s recommendations concerning Power’s system of internal accounting controls and has taken actions that are cost-effective in the circumstances to respond appropriately to these recommendations. Management believes that, as of December 31, 2002, Power’s system of internal accounting controls was adequate to accomplish the objectives discussed herein.
The Board of Directors carries out its responsibility of financial overview through the Audit Committee of PSEG, which presently consists of six directors who are not PSEG nor Power employees of or employees of any of their affiliates. The PSEG Audit Committee meets periodically with management as well as with representatives of the internal auditors and Deloitte & Touche. The Audit Committee reviews the work of each to ensure that their respective responsibilities are being carried out and discusses related matters. Both the internal auditors and Deloitte & Touche, periodically meet alone with the Audit Committee and have free access to the Audit Committee and its individual members at all times.
| E. JAMES FERLAND | FRANK CASSIDY |
| Chairman of the Board and | President |
| Chief Executive Officer | and Chief Operating Officer |
| THOMAS M. O’FLYNN | PATRICIA A. RADO |
| Executive Vice President | Vice President and Controller |
| and Chief Financial Officer | (Chief Accounting Officer) |
February 25, 2003
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FINANCIAL STATEMENT RESPONSIBILITY — (Energy Holdings)
Energy Holdings’ management is responsible for the preparation, integrity and objectivity of its consolidated financial statements and related notes. The consolidated financial statements and related notes are prepared in accordance with generally accepted accounting principles. The financial statements reflect estimates based upon the judgment of management where appropriate. Management believes that the consolidated financial statements and related notes present fairly Energy Holdings’ financial position and results of operations. Information in other parts of this Annual Report is also the responsibility of management and is consistent with these consolidated financial statements and related notes.
The firm of Deloitte & Touche LLP, independent auditors, is engaged to audit Energy Holdings’ consolidated financial statements and related notes and issue a report thereon. Deloitte & Touche’s audit is conducted in accordance with generally accepted auditing standards. Management has made available to Deloitte & Touche all of Energy Holdings’ financial records and related data, as well as the minutes of directors’ meetings. Furthermore, management believes that all representations made to Deloitte & Touche during its audit were valid and appropriate.
Management has established and maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded, and that transactions are executed in accordance with management’s authorization and recorded properly for the prevention and detection of fraudulent financial reporting, so as to maintain the integrity and reliability of the financial statements. The system is designed to permit preparation of consolidated financial statements and related notes in accordance with generally accepted accounting principles. The concept of reasonable assurance recognizes that the costs of a system of internal accounting controls should not exceed the related benefits. Management believes the effectiveness of this system is enhanced by an ongoing program of continuous and selective training of employees. In addition, management has communicated to all employees its policies on business conduct, safeguarding assets and internal controls. Management also maintains a system of disclosure controls and procedures to provide reasonable assurance that Energy Holdings is able to collect, process and disclose, within the time periods specified by the Securities and Exchange Commission, the information required to be disclosed in reports under the Securities Exchange Act of 1934.
The Internal Auditing Department of Services conducts audits and appraisals of accounting and other operations and evaluates the effectiveness of cost and other controls and, where appropriate, recommends to management improvements thereto. Management has considered the internal auditors’ and Deloitte & Touche’s recommendations concerning Energy Holdings’ system of internal accounting controls and has taken actions that are cost-effective in the circumstances to respond appropriately to these recommendations. Management believes that, as of December 31, 2002, Energy Holdings’ system of internal accounting controls was adequate to accomplish the objectives discussed herein.
The Board of Directors carries out its responsibility of financial overview through the Audit Committee of PSEG, which presently consists of six directors who are not PSEG nor Energy Holdings’ employees or employees of any of their affiliates. The PSEG Audit Committee meets periodically with management as well as with representatives of the internal auditors and Deloitte & Touche. The Audit Committee reviews the work of each to ensure that their respective responsibilities are being carried out and discusses related matters. Both the internal auditors and Deloitte & Touche, periodically meet alone with the Audit Committee and have free access to the Audit Committee and its individual members at all times.
| E. JAMES FERLAND | ROBERT J. DOUGHERTY, JR. |
| Chairman of the Board and | President |
| Chief Executive Officer | and Chief Operating Officer |
| THOMAS M. O’FLYNN | DEREK M. DIRISIO |
| Executive Vice President | Vice President and Controller |
| and Chief Financial Officer | (Principal Accounting Officer) |
February 25, 2003
94
INDEPENDENT AUDITORS’ REPORT
To the Stockholders and Board of Directors of
Public Service Enterprise Group Incorporated:
We have audited the consolidated balance sheets of Public Service Enterprise Group Incorporated and its subsidiaries (the “Company”) as of December 31, 2002 and 2001, and the related consolidated statements of operations, common stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the consolidated financial statement schedule listed in the Index in Item 15. 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, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, 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, 2000, 1999, and 1998, and the related consolidated statements of operations, common stockholders’ equity and cash flows for the years ended December 31, 1999 and 1998 (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 for each of the five years in the period ended December 31, 2002 for the Company, presented in Item 6, is fairly stated in all material respects, in relation to the consolidated financial statements from which it has been derived.
As discussed in Note 2 to the consolidated financial statements, on January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended.
As discussed in Note 2 to the consolidated financial statements, on January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”.
DELOITTE & TOUCHE
Parsippany, New Jersey
February 7, 2003
95
INDEPENDENT AUDITORS’ REPORT
To the Sole Stockholder and Board of Directors of
Public Service Electric and Gas Company:
We have audited the consolidated balance sheets of Public Service Electric and Gas Company and its subsidiaries (the “Company”) as of December 31, 2002 and 2001, and the related consolidated statements of operations, common stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the consolidated financial statement schedule listed in the Index in Item 15. 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, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, 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, 2000, 1999, and 1998, and the related consolidated statements of operations, common stockholder’s equity and cash flows for the years ended December 31, 1999 and 1998 (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 for each of the five years in the period ended December 31, 2002 for the Company, 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
Parsippany, New Jersey
February 7, 2003
96
INDEPENDENT AUDITORS’ REPORT
To the Sole Member and Board of Directors of
PSEG Power LLC:
We have audited the consolidated balance sheets of PSEG Power LLC and its subsidiaries (the “Company”) as of December 31, 2002 and 2001, and the related consolidated statements of operations, member’s equity and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the consolidated financial statement schedule listed in the Index in Item 15. 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, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, 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.
DELOITTE & TOUCHE
Parsippany, New Jersey
February 7, 2003
97
INDEPENDENT AUDITORS’ REPORT
To the Sole Member and Board of Directors of
PSEG Energy Holdings LLC:
We have audited the consolidated balance sheets of PSEG Energy Holdings LLC and its subsidiaries (the “Company”) as of December 31, 2002 and 2001, and the related consolidated statements of operations, member’s equity and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the consolidated financial statement schedule listed in the Index in Item 15. 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, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, 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.
As discussed in Note 2 to the consolidated financial statements, on January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended.
As discussed in Note 2 to the consolidated financial statements, on January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”.
DELOITTE & TOUCHE
Parsippany, New Jersey
February 7, 2003
98
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions, except for Share Data)
For The Years Ended December 31,
-----------------------------------
2002 2001 2000
--------- --------- ---------
OPERATING REVENUES $ 8,390 $ 7,055 $ 6,521
OPERATING EXPENSES
Energy Costs 3,769 2,674 2,423
Operation and Maintenance 1,896 1,841 1,706
Write-down of Project Investments 497 7 --
Depreciation and Amortization 571 496 350
Taxes Other Than Income Taxes 131 121 135
--------- --------- ---------
Total Operating Expenses 6,864 5,139 4,614
--------- --------- ---------
OPERATING INCOME 1,526 1,916 1,907
Other Income 57 50 33
Other Deductions (79) (15) (3)
Interest Expense (783) (722) (571)
Preferred Securities Dividends (57) (72) (94)
--------- --------- ---------
INCOME BEFORE INCOME TAXES,
DISCONTINUED OPERATIONS AND
CUMULATIVE EFFECT OF A CHANGE
IN ACCOUNTING PRINCIPLE 664 1,157 1,272
Income Taxes (248) (381) (496)
--------- --------- ---------
INCOME BEFORE DISCONTINUED OPERATIONS
AND CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE 416 776 776
Loss from Discontinued Operations,
net of tax of $9, $8 and $5 in 2002, 2001 and 2000,respectively
(including $35 Loss on Disposal, net of tax of $18 in 2002) (51) (15) (12)
--------- --------- ---------
INCOME BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE 365 761 764
Cumulative Effect of a Change in Accounting Principle,
net of tax of $66 and $8 in 2002 and 2001, respectively (120) 9 --
--------- --------- ---------
NET INCOME $ 245 $ 770 $ 764
========= ========= =========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING (000s) 208,813 208,226 215,121
========= ========= =========
EARNINGS PER SHARE (BASIC AND DILUTED):
INCOME BEFORE DISCONTINUED OPERATIONS
AND CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE $ 1.99 $ 3.73 $ 3.61
Loss from Discontinued Operations, net of tax (0.24) (0.07) (0.06)
(including Loss on Disposal, net of tax)
Cumulative Effect of a Change in Accounting Principle, net of tax (0.58) 0.04 --
--------- --------- ---------
NET INCOME $ 1.17 $ 3.70 $ 3.55
========= ========= =========
DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 2.16 $ 2.16 $ 2.16
========= ========= =========
99
CONSOLIDATED BALANCE SHEETS ASSETS
(Millions)
December 31,
--------------------
2002 2001
-------- --------
CURRENT ASSETS
Cash and Cash Equivalents $ 165 $ 167
Accounts Receivable 1,404 1,032
Allowance for Doubtful Accounts (34) (40)
Unbilled Electric and Gas Revenues 275 291
Fuel 412 506
Materials and Supplies 208 175
Energy Trading Contracts 179 148
Restricted Cash 32 12
Assets Held for Sale 83 422
Current Assets of Discontinued Operations 107 483
Other 135 93
-------- --------
Total Current Assets 2,966 3,289
-------- --------
PROPERTY, PLANT AND EQUIPMENT 16,562 14,700
Less: Accumulated Depreciation and Amortization (5,113) (4,789)
-------- --------
Net Property, Plant and Equipment 11,449 9,911
-------- --------
NONCURRENT ASSETS
Regulatory Assets 4,992 5,242
Long-Term Investments 4,581 4,768
Nuclear Decommissioning Trust Funds 766 817
Other Special Funds 72 222
Goodwill 452 569
Energy Trading Contracts 22 29
Other Intangibles 206 63
Other 236 246
-------- --------
Total Noncurrent Assets 11,327 11,956
-------- --------
TOTAL ASSETS $ 25,742 $ 25,156
======== ========
100
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions)
December 31,
--------------------
2002 2001
-------- --------
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 749 $ 1,186
Commercial Paper and Loans 762 1,337
Accounts Payable 1,115 871
Energy Trading Contracts 123 279
Accrued Taxes 229 243
Current Liabilities of Discontinued Operations 83 251
Other 755 379
-------- --------
Total Current Liabilities 3,816 4,546
-------- --------
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC) 2,924 3,205
Regulatory Liabilities 252 368
Nuclear Decommissioning 766 817
OPEB Costs 501 476
Accrued Pension Costs 336 42
Cost of Removal 131 146
Other 638 467
-------- --------
Total Noncurrent Liabilities 5,548 5,521
-------- --------
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt 7,116 6,437
Securitization Debt 2,222 2,351
Project Level, Non-Recourse Debt 1,653 1,404
-------- --------
Total Long-Term Debt 10,991 10,192
-------- --------
SUBSIDIARIES' PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption 80 80
Preferred Stock With Mandatory Redemption 460 --
Guaranteed Preferred Beneficial Interest in Subordinated Debentures 860 680
-------- --------
Total Subsidiaries' Preferred Securities 1,400 760
-------- --------
COMMON STOCKHOLDERS' EQUITY
Common Stock, issued; 2002 - 251,385,937 shares
2001 - 231,957,608 shares 4,056 3,599
Treasury Stock, at cost; 2002 and 2001 - 26,118,590 shares (981) (981)
Retained Earnings 1,601 1,809
Accumulated Other Comprehensive Loss (689) (290)
-------- --------
Total Common Stockholders' Equity 3,987 4,137
-------- --------
Total Capitalization 16,378 15,089
-------- --------
TOTAL LIABILITIES AND CAPITALIZATION $ 25,742 $ 25,156
======== ========
101
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
For The Years Ended December 31,
-------------------------------
2002 2001 2000
------- ------- -------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 245 $ 770 $ 764
Adjustments to reconcile net income to net cash flows from
operating activities:
Write-down of Project Investments 497 7 --
Loss on Disposal of Discontinued Operations, net of tax 35 2 --
Cumulative Effect of a Change in Accounting Principle, net of tax 120 (9) --
Depreciation and Amortization 571 496 350
Amortization of Nuclear Fuel 89 101 96
Provision for Deferred Income Taxes (Other than Leases) and ITC (117) (118) (5)
Non-Cash Employee Benefit Plan Costs 193 158 147
Leveraged Lease Income, Adjusted for Rents Received (45) (6) 74
Undistributed Earnings from Affiliates (59) (111) (28)
Foreign Currency Transaction Loss (Gain) 70 9 (3)
Unrealized (Gains) Losses on Energy Contracts and Other Derivatives (36) 22 (13)
(Under) Over Recovery of Electric Energy Costs (BGS and NTC) and MTC (1) 110 116
(Under) Over Recovery of Gas Costs (41) (143) 11
Other Non-Cash Charges (Credits) 54 (68) (20)
Net Change in Certain Current Assets and Liabilities 279 183 (170)
Employee Benefit Plan Funding and Related Payments (308) (210) (35)
Proceeds from the Withdrawal of Partnership Interests and Other Distributions 63 124 51
Other (81) (88) (145)
------- ------- -------
Net Cash Provided By Operating Activities 1,528 1,229 1,190
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (1,814) (2,111) (815)
Investments in Joint Ventures, Partnerships and Capital Leases (222) (596) (821)
Proceeds from the Sale of Investments and Return of Capital from Partnerships 380 132 177
Acquisitions, net of Cash Provided (289) (832) (88)
Other (42) (195) (84)
------- ------- -------
Net Cash Used In Investing Activities (1,987) (3,602) (1,631)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt (552) (1,511) 929
Issuance of Long-Term Debt 1,542 6,509 1,200
Issuance of Preferred Securities 180 -- --
Issuance of Participating Units 460 -- --
Issuance of Common Stock 536 -- --
Deferred Issuance Costs (44) (228) (39)
Redemptions of Long-Term Debt (1,212) (1,292) (1,052)
Redemptions of Preferred Securities -- (448) --
Purchase of Treasury Stock -- (91) (298)
Cash Dividends Paid on Common Stock (456) (448) (464)
Other 5 (47) 2
------- ------- -------
Net Cash Provided By Financing Activities 459 2,444 278
------- ------- -------
Effect of Exhange Rate Change (2) -- --
------- ------- -------
Net Change In Cash And Cash Equivalents (2) 71 (163)
Cash And Cash Equivalents At Beginning Of Period 167 96 259
------- ------- -------
Cash And Cash Equivalents At End Of Period $ 165 $ 167 $ 96
======= ======= =======
Income Taxes Paid $ 145 $ 87 $ 485
Interest Paid $ 843 $ 713 $ 548
Non-Cash Financing and Investing Activities:
Property, Plant and Equipment Assumed from Acquisitions $ 538 $ 749 $ 213
Debt Assumed from Acquisitions $ -- $ 256 $ 161
Reduction in Equity and Increase in Debt From Issuance of Participating Units $ 54 $ -- $ --
102
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(Millions)
Common Treasury
Stock Stock
----------------- ------------------ Retained
Shs. Amount Shs. Amount Earnings
------- ------- ------- ------- --------
Balance as of January 1, 2000 232 3,604 (16) (597) 1,193
Net Income -- -- -- -- 764
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(0) -- -- -- -- --
Other Comprehensive Loss -- -- -- -- --
Comprehensive Income -- -- -- -- --
Cash Dividends on Common Stock -- -- -- -- (464)
Purchase of Treasury Stock -- -- (8) (298) --
------- ------- ------- ------- -------
Balance as of December 31, 2000 232 $ 3,604 (24) $ (895) $ 1,493
------- ------- ------- ------- -------
Net Income -- -- -- -- 770
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax $(12) -- -- -- -- --
Change in Fair Value of Derivative Instruments, net of tax $(31) -- -- -- -- --
Cumulative Effect of a Change in Accounting Principle,
net of tax $(14) -- -- -- -- --
Reclassification Adjustments for Net Amounts included in
net income, net of tax of $19 -- -- -- -- --
Pension Adjustments, net of tax $(1) -- -- -- -- --
Change in Fair Value of Equity Investments, net of tax $(1) -- -- -- -- --
Other Comprehensive Loss -- -- -- -- --
Comprehensive Income -- -- -- -- --
Cash Dividends on Common Stock -- -- -- -- (449)
Purchase of Treasury Stock -- -- (2) (92) --
Other -- (5) -- 6 (5)
------- ------- ------- ------- -------
Balance as of December 31, 2001 232 $ 3,599 (26) $ (981) $ 1,809
------- ------- ------- ------- -------
Net Income -- -- -- -- 245
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax $(63) -- -- -- -- --
Reclassification Adjustment for Losses Included in Net Income
Change in Fair Value of Derivative Instruments, net of tax $(38) -- -- -- -- --
Reclassification Adjustments for Net Amounts included in
Net Income, net of tax of $10 -- -- -- -- --
Minimum Pension Liability, net of tax $(204) -- -- -- -- --
Change in Fair Value of Equity Investments -- -- -- -- --
Other Comprehensive Loss -- -- -- -- --
Comprehensive Income -- -- -- -- --
Cash Dividends on Common Stock -- -- -- -- (456)
Issuance of Equity 19 536 -- -- --
Issuance Costs and Other -- (79) -- -- 3
------- ------- ------- ------- -------
Balance as of December 31, 2002 251 $ 4,056 (26) $ (981) $ 1,601
======= ======= ======= ======= =======
Accumulated
Other
Comprehensive
Income (Loss) Total
-------------- -------
Balance as of January 1, 2000 (204) $ 3,996
Net Income -- 764
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(0) (2) (2)
-------
Other Comprehensive Loss -- (2)
-------
Comprehensive Income -- 762
Cash Dividends on Common Stock -- (464)
Purchase of Treasury Stock -- (298)
------- -------
Balance as of December 31, 2000 $ (206) $ 3,996
------- -------
Net Income -- 770
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax $(12) (34) (34)
Change in Fair Value of Derivative Instruments, net of tax $(31) (57) (57)
Cumulative Effect of a Change in Accounting Principle, net of tax $(14) (15) (15)
Reclassification Adjustments for Net Amounts included in
net income, net of tax of $19 26 26
Pension Adjustments, net of tax $(1) (2) (2)
Change in Fair Value of Equity Investments, net of tax $(1) (2) (2)
-------
Other Comprehensive Loss -- (84)
-------
Comprehensive Income -- 686
Cash Dividends on Common Stock -- (449)
Purchase of Treasury Stock -- (92)
Other -- (4)
------- -------
Balance as of December 31, 2001 $ (290) $ 4,137
------- -------
Net Income -- 245
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax $(63) (117) (117)
Reclassification Adjustment for Losses Included in Net Income 68 68
Change in Fair Value of Derivative Instruments, net of tax $(38) (67) (67)
Reclassification Adjustments for Net Amounts included in
Net Income, net of tax of $10 15 15
Minimum Pension Liability, net of tax $(204) (297) (297)
Change in Fair Value of Equity Investments (1) (1)
-------
Other Comprehensive Loss -- (399)
-------
Comprehensive Income -- (154)
Cash Dividends on Common Stock -- (456)
Issuance of Equity -- 536
Issuance Costs and Other -- (76)
------- -------
Balance as of December 31, 2002 $ (689) $ 3,987
======= =======
103
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
For The Years Ended December 31,
--------------------------------
2002 2001 2000
------- ------- -------
OPERATING REVENUES $ 5,919 $ 6,091 $ 5,887
OPERATING EXPENSES
Energy Costs 3,684 3,913 2,901
Operation and Maintenance 982 996 1,297
Depreciation and Amortization 409 370 286
Taxes Other Than Income Taxes 131 121 135
------- ------- -------
Total Operating Expenses 5,206 5,400 4,619
------- ------- -------
OPERATING INCOME 713 691 1,268
Other Income 28 111 173
Other Deductions (2) (4) (4)
Interest Expense (406) (450) (397)
Preferred Securities Dividends (13) (24) (46)
------- ------- -------
INCOME BEFORE INCOME TAXES 320 324 994
Income Taxes (115) (89) (407)
------- ------- -------
NET INCOME 205 235 587
Preferred Stock Dividends (4) (5) (9)
------- ------- -------
EARNINGS AVAILABLE TO PUBLIC
SERVICE ENTERPRISE GROUP INCORPORATED $ 201 $ 230 $ 578
======= ======= =======
104
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions)
December 31,
--------------------
2002 2001
-------- --------
CURRENT ASSETS
Cash and Cash Equivalents $ 35 $ 102
Accounts Receivable 787 623
Allowance for Doubtful Accounts (32) (38)
Unbilled Revenues 275 291
Natural Gas -- 415
Materials and Supplies 45 50
Prepayments 25 40
Restricted Cash 14 12
Other 16 23
-------- --------
Total Current Assets 1,165 1,518
-------- --------
PROPERTY, PLANT AND EQUIPMENT 9,581 9,170
Less: Accumulated Depreciation and Amortization (3,604) (3,329)
-------- --------
Net Property, Plant and Equipment 5,977 5,841
-------- --------
NONCURRENT ASSETS
Regulatory Assets 4,992 5,242
Long-Term Investments 123 112
Other Special Funds 44 130
Intangibles 60 7
Other 68 77
-------- --------
Total Noncurrent Assets 5,287 5,568
-------- --------
TOTAL ASSETS $ 12,429 $ 12,927
======== ========
105
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions)
December 31,
--------------------
2002 2001
-------- --------
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 429 $ 668
Commercial Paper and Loans 224 --
Accounts Payable 724 642
Energy Contracts -- 133
Other 315 307
-------- --------
Total Current Liabilities 1,692 1,750
-------- --------
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credit (ITC) 2,436 2,551
Regulatory Liabilities 252 368
Other Postemployment Benefit (OPEB) Costs 486 466
Accrued Pension Costs 175 13
Other 209 197
-------- --------
Total Noncurrent Liabilities 3,558 3,595
-------- --------
COMMITMENTS AND CONTINGENT LIABILITIES (see Note 13)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt 2,627 2,626
Securitization Debt 2,222 2,351
-------- --------
Total Long-Term Debt 4,849 4,977
-------- --------
PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption 80 80
Subsidiaries' Preferred Securities:
Guaranteed Preferred Beneficial Interest in Subordinated
Debentures 155 155
-------- --------
Total Preferred Securities 235 235
-------- --------
COMMON STOCKHOLDER'S EQUITY
Common Stock; 150,000,000 shares authorized,
132,450,344 shares issued and outstanding 892 892
Basis Adjustment 986 986
Retained Earnings 389 493
Accumulated Other Comprehensive Loss (172) (1)
-------- --------
Total Common Stockholder's Equity 2,095 2,370
-------- --------
Total Capitalization 7,179 7,582
-------- --------
TOTAL LIABILITIES AND CAPITALIZATION $ 12,429 $ 12,927
======== ========
106
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
For The Years Ended December 31,
--------------------------------
2002 2001 2000
------- ------- -------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 205 $ 235 $ 587
Adjustments to reconcile net income to net cash flows from
operating activities:
Depreciation and Amortization 409 370 286
Amortization of Nuclear Fuel -- -- 57
Provision for Deferred Income Taxes and ITC (23) (203) (4)
Non-Cash Employee Benefit Plan Costs 141 125 131
Non-Cash Interest Expense (Income) 21 (7) (19)
Overrecovery of Electric Energy Costs and Market Transition Charge (1) 110 116
Underrecovery/Overrecovery of Gas Costs (41) (143) 11
Net Changes in certain current assets and liabilities:
Accounts Receivable and Unbilled Revenues (154) 127 (268)
Natural Gas 415 (43) (105)
Inventory - Materials and Supplies 5 (2) (6)
Prepayments 15 (35) 27
Restricted Cash (2) (11) --
Accrued Taxes (22) 5 44
Accrued Interest (13) 11 --
Accounts Payable 82 56 252
Other Current Assets and Liabilities 2 20 (63)
Employee Benefit Plan Funding and Related Payments (198) (139) (18)
Other 24 (17) (55)
------- ------- -------
Net Cash Provided By Operating Activities 865 459 973
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (472) (395) (437)
Other -- -- (17)
------- ------- -------
Net Cash Used In Investing Activities (472) (395) (454)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt 224 (1,543) 68
Issuance of Long-Term Debt 300 2,525 590
Redemption of Long-Term Debt (667) (570) (622)
Deferred Issuance Costs (2) (201) (36)
Capital Lease Payments (6) (6) (6)
Redemption of Preferred Stock -- (448) --
Return of Capital -- (2,265) --
Collection of Notes Receivable-Affiliated Company -- 2,786 --
Cash Dividends Paid on Common Stock (305) (274) (638)
Preferred Stock Dividends (4) (5) (9)
------- ------- -------
Net Cash Used In Financing Activities (460) (1) (653)
------- ------- -------
Net Change In Cash And Cash Equivalents (67) 63 (134)
Cash And Cash Equivalents At Beginning Of Period 102 39 173
------- ------- -------
Cash And Cash Equivalents At End Of Period $ 35 $ 102 $ 39
======= ======= =======
Income Taxes Paid $ 161 $ 264 $ 593
Interest Paid $ 428 $ 427 $ 406
107
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
(Millions)
Accumulated
Contributed Other
Common Capital from Basis Retained Comprehensive
Stock PSEG Adjustment Earnings Loss Total
------- ------------ ---------- -------- ------------- -------
Balance as of January 1, 2000 $ 2,563 $ 594 $ -- $ 597 $ (3) $ 3,751
Net Income -- -- -- 587 -- 587
Other Comprehensive Income, net of tax:
-------
Comprehensive Income -- -- -- -- -- 587
-------
Cash Dividends on Common Stock -- -- -- (800) -- (800)
Cash Dividends on Preferred Stock -- -- -- (9) -- (9)
Basis Adjustment -- -- 986 -- -- 986
------- ------- ------- ------- ------- -------
Balance as of December 31, 2000 $ 2,563 $ 594 $ 986 $ 375 $ (3) $ 4,515
------- ------- ------- ------- ------- -------
Net Income -- -- -- 235 -- 235
Other Comprehensive Income , net of tax:
Pension Adjustments, net of tax $(1) -- -- -- -- 2 2
-------
Comprehensive Income -- -- -- -- -- 237
-------
Cash Dividends on Common Stock -- -- -- (112) -- (112)
Cash Dividends on Preferred Stock -- -- -- (5) -- (5)
Return of Capital (1,671) (594) -- -- -- (2,265)
------- ------- ------- ------- ------- -------
Balance as of December 31, 2001 $ 892 $ -- $ 986 $ 493 $ (1) $ 2,370
------- ------- ------- ------- ------- -------
Net Income -- -- -- 205 -- 205
Other Comprehensive Loss , net of tax:
Minimum Pension Liability,
net of tax $(104) -- -- -- -- (171) (171)
-------
Comprehensive Income -- -- -- -- -- 34
-------
Cash Dividends on Common Stock -- -- -- (305) -- (305)
Cash Dividends on Preferred Stock -- -- -- (4) -- (4)
Return of Capital -- -- -- -- -- --
------- ------- ------- ------- ------- -------
Balance as of December 31, 2002 $ 892 $ -- $ 986 $ 389 $ (172) $ 2,095
======= ======= ======= ======= ======= =======
108
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
For the Years Ended December 31,
--------------------------------
2002 2001 2000
------- ------- -------
OPERATING REVENUES $ 3,670 $ 2,452 $ 2,275
OPERATING EXPENSES
Energy Costs 1,886 832 741
Operation and Maintenance 773 738 686
Depreciation and Amortization 108 95 136
------- ------- -------
Total Operating Expenses 2,767 1,665 1,563
------- ------- -------
OPERATING INCOME 903 787 712
Other Income -- -- 7
Interest Expense (122) (143) (198)
------- ------- -------
INCOME BEFORE INCOME TAXES 781 644 521
Income Taxes (313) (250) (208)
------- ------- -------
EARNINGS AVAILABLE TO PUBLIC
SERVICE ENTERPRISE GROUP INCORPORATED $ 468 $ 394 $ 313
======= ======= =======
109
CONSOLIDATED BALANCE SHEETS
(Millions)
December 31,
-----------------
2002 2001
------- -------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 26 $ 9
Accounts Receivable - net 499 287
Fuel 406 76
Materials and Supplies 148 124
Energy Trading Contracts 179 147
Other 44 13
------- -------
Total Current Assets 1,302 656
------- -------
PROPERTY, PLANT AND EQUIPMENT 5,347 4,238
Less: Accumulated Depreciation and Amortization (1,302) (1,253)
------- -------
Net Property, Plant and Equipment 4,045 2,985
------- -------
NONCURRENT ASSETS
Deferred Income Taxes and Investment Tax Credits (ITC) 545 572
Nuclear Decommissioning Trust Funds 766 817
Goodwill 16 21
Intangibles 125 47
Other 165 141
------- -------
Total Noncurrent Assets 1,617 1,598
------- -------
TOTAL ASSETS $ 6,964 $ 5,239
======= =======
LIABILITIES AND MEMBER'S EQUITY
CURRENT LIABILITIES
Accounts Payable $ 671 $ 333
Energy Trading Contracts 123 146
Other 283 111
------- -------
Total Current Liabilities 1,077 590
------- -------
NONCURRENT LIABILITIES
Nuclear Decommissioning 766 817
Cost of Removal 131 146
Accrued Pension Costs 101 10
Other 131 131
------- -------
Total Noncurrent Liabilities 1,129 1,104
------- -------
COMMITMENTS AND CONTINGENT LIABILITIES (see Note 13)
LONG-TERM DEBT
Project Level, Non-Recourse Debt 800 770
Long-Term Debt 2,516 1,915
------- -------
Total Long-Term Debt 3,316 2,685
------- -------
MEMBER'S EQUITY
Contributed Capital 1,550 1,350
Basis Adjustment (986) (986)
Retained Earnings 966 498
Accumulated Other Comprehensive Loss (88) (2)
------- -------
Total Member's Equity 1,442 860
------- -------
TOTAL LIABILITIES AND MEMBER'S EQUITY $ 6,964 $ 5,239
======= =======
110
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
For the Years Ended December 31,
--------------------------------
2002 2001 2000
------- ------- -------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 468 $ 394 $ 313
Adjustments to reconcile net income to net cash flows
from operating activities:
Depreciation and Amortization 108 95 136
Amortization of Nuclear Fuel 89 101 96
Provision for Deferred Income Taxes 88 94 (69)
Unrealized (Gains) Losses on Energy Trading Contracts (23) 22 (55)
Non-Cash Employee Benefit Plan Costs 32 20 11
Net changes in certain current assets and liabilities:
Inventory, Materials and Supplies (329) (35) (30)
Accounts Receivable (212) 2 161
Accrued Taxes (17) 6 13
Accounts Payable 338 (140) 195
Other Current Assets and Liabilities 111 74 11
Employee Benefit Plan Funding Payments (76) (34) --
Other (84) (80) (75)
------- ------- -------
Net Cash Provided By Operating Activities 493 519 707
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (1,046) (1,592) (411)
Proceeds from the Sale of Property, Plant and Equipment 47 30 --
Acquisition of Generation Businesses, net of cash provided (272) (22) (74)
Contribution to Decommissioning Funds and Other Special Funds (29) (29) (29)
Other -- -- (34)
------- ------- -------
Net Cash Used In Investing Activities (1,300) (1,613) (548)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans -- -- (685)
Issuance of Long-Term Debt 630 2,685 --
Repayment of Note Payable - Affiliated Company -- (2,786) --
Net Change in Capitalization Activity -- -- 319
Proceeds from Contributed Capital 200 1,200 150
Deferred Issuance Costs (6) (16) --
------- ------- -------
Net Cash Provided By (Used In) Financing Activities 824 1,083 (216)
------- ------- -------
Net Change In Cash And Cash Equivalents 17 (11) (57)
Cash And Cash Equivalents At Beginning Of Year 9 20 77
------- ------- -------
Cash And Cash Equivalents At End Of Year $ 26 $ 9 $ 20
======= ======= =======
Property, Plant and Equipment Assumed from Acquisitions $ 237 $ 22 $ 31
Income Taxes Paid $ 91 $ 166 $ 242
Interest Paid $ 200 $ 197 $ 118
111
CONSOLIDATED STATEMENTS OF CAPITALIZATION AND MEMBER'S EQUITY
(Millions)
Accumulated
Other Total
Contributed Basis Retained Comprehensive Member's
Capital Adjustment Earnings Loss Equity
----------- ---------- -------- ------------- --------
Balance as of January 1, 2000 $ -- $ -- $ -- $ -- $ --
Net Income (1) -- -- 104 -- 104
Contributed Capital 150 -- -- -- 150
Net Transfers to PSEG -- -- -- -- --
Transfer of Generation Business -- (986) -- -- (986)
------- ------- ------- ------- -------
Balance as of December 31, 2000 $ 150 $ (986) $ 104 $ -- $ (732)
------- ------- ------- ------- -------
Net Income (1) -- -- 394 -- 394
Change in Fair Value of Derivative Instruments,
(net of tax $(16)) -- -- -- (23) (23)
Reclassification Adjustments for Net Amount --
included in Net Income (net of tax of $14) -- -- -- 21 21
-------
Other Comprehensive Income (Loss) -- -- -- -- (2)
-------
Comprehensive Income 392
Contributed Capital 1,200 -- -- -- 1,200
------- ------- ------- ------- -------
Balance as of December 31, 2001 $ 1,350 $ (986) $ 498 $ (2) $ 860
------- ------- ------- ------- -------
Net Income (1) -- -- 468 -- 468
Other Comprehensive Income (Loss), net of tax:
Change in Fair Value of Derivative Instruments,
(net of tax $(1)) -- -- -- (2) (2)
Pension Adjustments, net of tax $(50) -- -- -- (84) (84)
-------
Other Comprehensive Income (Loss) -- -- -- -- (86)
-------
Comprehensive Income -- -- 468 -- 382
Contributed Capital 200 -- -- -- 200
------- ------- ------- ------- -------
Balance as of December 31, 2002 $ 1,550 $ (986) $ 966 $ (88) $ 1,442
======= ======= ======= ======= =======
Total
Capitalization
and Member's
Capitalization Equity
-------------- --------------
Balance as of January 1, 2000 $ 1,272 $ 1,272
Net Income (1) 209 313
Contributed Capital -- 150
Net Transfers to PSEG (1,481) (1,481)
Transfer of Generation Business (986)
------- -------
Balance as of December 31, 2000 $ -- $ (732)
------- -------
Net Income (1) -- 394
Change in Fair Value of Derivative Instruments,
(net of tax $(16)) -- (23)
Reclassification Adjustments for Net Amount --
included in Net Income (net of tax of $14) -- 21
-------
Other Comprehensive Income (Loss) -- (2)
-------
Comprehensive Income 392
Contributed Capital -- 1,200
------- -------
Balance as of December 31, 2001 $ -- $ 860
------- -------
Net Income (1) -- 468
Other Comprehensive Income (Loss), net of tax:
Change in Fair Value of Derivative Instruments,
(net of tax $(1)) -- (2)
Pension Adjustments, net of tax $(50) -- (84)
-------
Other Comprehensive Income (Loss) -- (86)
-------
Comprehensive Income -- 382
Contributed Capital -- 200
------- -------
Balance as of December 31, 2002 $ -- $ 1,442
======= =======
(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 reflects the Net Income/Loss
allocated from Public Service Electric and Gas Company.
112
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
For The Years Ended December 31,
--------------------------------
2002 2001 2000
------- ------- -------
OPERATING REVENUES
Electric Generation and Distribution Revenues $ 364 $ 128 $ --
Income from Capital and Operating Leases 260 215 170
Income from Joint Ventures and Partnerships 58 144 157
Interest and Dividend Income 46 48 3
Gain on Withdrawal from/Sale of Partnerships 32 75 --
Other 30 30 40
Net Investment (Losses) Gains (41) (2) 35
Energy Supply Revenues -- -- 67
------- ------- -------
Total Operating Revenues 749 638 472
------- ------- -------
OPERATING EXPENSES
Write-down of Project Investments 497 7 --
Energy Costs 147 55 66
Administrative and General 111 79 76
Operation and Maintenance 54 40 14
Depreciation and Amortization 35 16 6
------- ------- -------
Total Operating Expenses 844 197 162
------- ------- -------
OPERATING (LOSS) INCOME (95) 441 310
Other Income 25 6 3
Other Deductions (73) (12) (3)
Interest Expense (214) (180) (134)
------- ------- -------
(LOSS) INCOME BEFORE INCOME TAXES,
DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE (357) 255 176
Income Tax Benefit (Expense) 150 (65) (51)
Minority Interests in (Earnings) Losses of Subsidiaries (2) (1) 1
------- ------- -------
(LOSS) INCOME BEFORE DISCONTINUED OPERATIONS
AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE (209) 189 126
DISCONTINUED OPERATIONS
Loss From Discontinued Operations, net of tax of
$9, $8 and $5 in 2002, 2001 and 2000, respectively (16) (15) (12)
Loss on Disposal of Discontinued Operations, net of tax of $18 (35) -- --
------- ------- -------
(LOSS) INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE
IN ACCOUNTING PRINCIPLE (260) 174 114
Cumulative Effect of a Change in Accounting Principle,
net of tax of $66 and $8 in 2002 and 2001, respectively (120) 9 --
------- ------- -------
NET (LOSS) INCOME (380) 183 114
Preference Units Distributions/Preferred Stock Dividends (23) (22) (24)
------- ------- -------
(LOSS) EARNINGS AVAILABLE TO PUBLIC SERVICE
ENTERPRISE GROUP $ (403) $ 161 $ 90
======= ======= =======
113
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions)
December 31,
------------------
2002 2001
------- -------
CURRENT ASSETS
Cash and Cash Equivalents $ 104 $ 54
Accounts Receivable:
Trade - Net 91 108
Other Accounts Receivable - Net 24 17
Assets Held for Sale 83 422
Notes Receivable 73 --
Inventory 22 15
Prepayments 4 2
Restricted Cash 18 --
Current Assets of Discontinued Operations 107 483
------- -------
Total Current Assets 526 1,101
------- -------
PROPERTY, PLANT AND EQUIPMENT 1,534 1,181
Less: Accumulated Depreciation and Amortization (139) (157)
------- -------
Net Property, Plant and Equipment 1,395 1,024
------- -------
INVESTMENTS
Capital Leases-Net 2,844 2,784
Corporate Joint Ventures 1,004 1,115
Partnership Interests 484 659
Other Investments 38 56
------- -------
Total Investments 4,370 4,614
------- -------
OTHER ASSETS
Goodwill 436 548
Other 111 152
------- -------
Total Other Assets 547 700
------- -------
TOTAL ASSETS $ 6,838 $ 7,439
======= =======
114
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER'S/STOCKHOLDER'S EQUITY
(Millions)
December 31,
------------------
2002 2001
------- -------
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 320 $ 243
Short-Term Borrowings Due to Public Service Enterprise Group Incorporated -- 38
Accounts Payable 257 211
Borrowings Under Lines of Credit -- 300
Notes Payable 137 285
Current Liabilities of Discontinued Operations 95 251
------- -------
Total Current Liabilities 809 1,328
------- -------
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment and Energy Tax Credits 1,042 1,211
Other Noncurrent Liabilities 179 99
------- -------
Total Noncurrent Liabilities 1,221 1,310
------- -------
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
MINORITY INTERESTS 106 47
------- -------
LONG-TERM DEBT
Project Level, Non-Recourse Long-Term Debt 853 634
Senior Notes 1,725 1,644
Medium-Term Notes -- 252
------- -------
Total Long-Term Debt 2,578 2,530
------- -------
MEMBER'S/STOCKHOLDER'S EQUITY
Ordinary Unit 1,888 --
Preference Units 509 --
Preferred Stock -- 509
Additional Paid-in Capital -- 1,490
Retained Earnings 107 510
Accumulated Other Comprehensive Loss (380) (285)
------- -------
Total Member's/Stockholder's Equity 2,124 2,224
------- -------
TOTAL LIABILITIES AND MEMBER'S/STOCKHOLDER'S EQUITY $ 6,838 $ 7,439
======= =======
115
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
For The Years Ended December 31,
--------------------------------
2002 2001 2000
------- ------- -------
CASH FLOWS FROM OPERATING ACTIVITIES
Net (Loss) Income $ (380) $ 183 $ 114
Adjustments to reconcile net income to net cash flows from
operating activities:
Depreciation and Amortization 54 28 25
Deferred Income Taxes (Other than Leases) (188) (20) (11)
Leveraged Lease Income, Adjusted for Rents Received (45) (6) 74
Investment Distributions 7 74 51
Investment in Securities (5) (14) (7)
Undistributed Earnings from Affiliates (59) (111) (28)
Net Gains on Investments 7 (74) (35)
Write-down of Project Investments 497 7 --
Loss on Disposal of Discontinued Operations, net of tax 35 -- --
Foreign Currency Transaction Loss 70 9 (3)
Proceeds on Withdrawal from Partnership 47 50 --
Cumulative Effect of a Change in Accounting Principle, net of tax 120 (9) --
Net Changes in certain current assets and liabilities:
Accounts Receivable 2 (56) (112)
Accounts Payable (2) 109 46
Other Current Assets and Liabilities 42 51 16
Other (3) 13 10
------- ------- -------
Net Cash Provided By Operating Activities 199 234 140
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (353) (169) (56)
Investments in Joint Ventures and Partnerships (191) (137) (361)
Investments in Capital Leases (31) (460) (460)
Proceeds from Sale of Capital Leases 183 104 89
Acquisitions, net of Cash Acquired (17) (810) (14)
Proceeds from sale of Discontinued Operations 45 -- --
Return of Capital from Partnerships 147 2 87
Other (20) (104) (43)
------- ------- -------
Net Cash Used In Investing Activities (237) (1,574) (758)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Capital Contributions 400 400 300
Net (Decrease) Increase in Short-Term Debt (424) 139 146
Cash Dividends Paid (23) (26) (37)
Restricted Cash (Increase) Decrease (18) 2 3
Net Increase in Short-Term Affiiliate Borrowings 31 40 --
Proceeds from Sale of Senior Notes 133 939 297
Early Retirement of Senior Notes (41) -- --
Proceeds from Project-Level Non-Recourse Debt 228 348 34
Repayment of Medium-Term and Project-Level Non-Recourse Debt (229) (422) (155)
Other 33 (42) 4
------- ------- -------
Net Cash Provided By Financing Activities 90 1,378 592
------- ------- -------
Effect of Exchange Rate Changes on Cash (2) -- --
Net Change In Cash And Cash Equivalents 50 38 (26)
Cash And Cash Equivalents At Beginning Of Year 54 16 42
------- ------- -------
Cash And Cash Equivalents At End Of Year $ 104 $ 54 $ 16
======= ======= =======
Supplemental Disclosure of Cash Flow Information
Cash Payments (Receipts) for:
Income Taxes (Benefits) $ (126) $ (178) $ (105)
Interest Paid $ 193 $ 155 $ 87
Non-Cash Investing and Financing Activities:
Fair Value of Property, Plant and Equipment Acquired $ 301 $ 727 $ 182
Debt Assumed from Companies Acquired $ -- $ 256 $ 161
116
CONSOLIDATED STATEMENTS OF MEMBER'S/STOCKHOLDER'S EQUITY
(Millions)
Additional
Ordinary Preference Preferred Paid-In Retained
Unit Units Stock Capital Earnings
-------- ---------- ---------- ------- --------
Balance as of January 1, 2000 $ -- $ -- $ 509 $ 790 $ 276
Net Income -- -- -- -- 114
Other Comprehensive Loss, net of tax:
Currency Translation Adjustment, net of tax of $0 -- -- -- -- --
Other Comprehensive Loss -- -- -- -- --
Comprehensive Income -- -- -- -- --
Additional Contributed Capital -- -- -- 300 --
Preferred Stock Dividends -- -- -- -- (24)
Common Stock Dividends -- -- -- -- (13)
------- ------- ------- ------- -------
Balance as of December 31, 2000 -- -- 509 1,090 353
------- ------- ------- ------- -------
Net Income -- -- -- -- 183
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(6) -- -- -- -- --
Cumulative Effect of a Change in Accounting Principle,
net of tax of $14 -- -- -- -- --
Current Period Declines in Fair Value of Derivative
Instruments-Net -- -- -- -- --
Reclassification Adjustments for Net Amounts Included
in Net Income -- -- -- -- --
Other Comprehensive Loss -- -- -- -- --
Comprehensive Income -- -- -- -- --
Additional Contributed Capital -- -- -- 400 --
Preferred Stock Dividends -- -- -- -- (22)
Common Stock Dividends -- -- -- -- (4)
------- ------- ------- ------- -------
Balance as of December 31, 2001 -- -- 509 1,490 510
------- ------- ------- ------- -------
Net Income -- -- -- -- (380)
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(43) -- -- -- -- --
Reclassification Adjustment for Losses Included in Net Income,
net of tax of $37 -- -- -- -- --
Current Period Declines in Fair Value of Derivative
Instruments, net of tax of $(12) -- -- -- -- --
Reclassification Adjustments for Net Amounts Included
in Net Income, net of tax of $6 -- -- -- -- --
Minimum Pension Liability Adjustment -- -- -- -- --
Other Comprehensive Loss -- -- -- -- --
Comprehensive Loss -- -- -- -- --
Additional Contributed Capital 100 -- -- 300 --
Recapitalization of Energy Holdings' Assets and Liabilities 1,790 509 (509) (1,790) --
Preference Units/Preferred Stock Dividends -- -- -- -- (23)
Dividend of Pantellos Corporation to PSEG (2) -- -- -- --
------- ------- ------- ------- -------
Balance as of December 31, 2002 $ 1,888 $ 509 $ -- $ -- $ 107
------- ------- ------- ------- -------
Accumulated
Other Total Member's/
OComprehensive Stockholder's
Income (Loss) Equity
-------------- ---------------
Balance as of January 1, 2000 $ (200) $ 1,375
Net Income -- 114
Other Comprehensive Loss, net of tax:
Currency Translation Adjustment, net of tax of $0 (3) (3)
-------
Other Comprehensive Loss -- (3)
-------
Comprehensive Income -- 111
Additional Contributed Capital -- 300
Preferred Stock Dividends -- (24)
Common Stock Dividends -- (13)
------- -------
Balance as of December 31, 2000 (203) 1,749
------- -------
Net Income -- 183
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(6) (55) (55)
Cumulative Effect of a Change in Accounting Principle,
net of tax of $14 (15) (15)
Current Period Declines in Fair Value of Derivative
Instruments-Net (16) (16)
Reclassification Adjustments for Net Amounts Included
in Net Income 4 4
-------
Other Comprehensive Loss -- (82)
-------
Comprehensive Income -- 101
Additional Contributed Capital -- 400
Preferred Stock Dividends -- (22)
Common Stock Dividends -- (4)
------- -------
Balance as of December 31, 2001 (285) 2,224
------- -------
Net Income -- (380)
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(43) (117) (117)
Reclassification Adjustment for Losses Included in Net Income,
net of tax of $37 68 68
Current Period Declines in Fair Value of Derivative
Instruments, net of tax of $(12) (52) (52)
Reclassification Adjustments for Net Amounts Included
in Net Income, net of tax of $6 12 12
Minimum Pension Liability Adjustment (6) (6)
-------
Other Comprehensive Loss -- (95)
-------
Comprehensive Loss -- (475)
Additional Contributed Capital -- 400
Recapitalization of Energy Holdings' Assets and Liabilities --
Preference Units/Preferred Stock Dividends -- (23)
Dividend of Pantellos Corporation to PSEG -- (2)
------- -------
Balance as of December 31, 2002 $ (380) $ 2,124
------- -------
117
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
This combined Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), and PSEG Energy Holdings LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each makes representations only as to itself and make no other representations whatsoever as to any other company.
Note 1. Organization and Summary of Significant Accounting Policies
Organization
PSEG
PSEG has four principal direct wholly-owned subsidiaries: PSE&G, Power, Energy Holdings and PSEG Services Corporation (Services).
PSE&G
PSE&G is an operating public utility providing electric and gas service in certain areas within the State of New Jersey. Following the transfer of its generation-related assets and liabilities to Power in August 2000 and gas supply business to Power in May 2002, PSE&G continues to own and operate its transmission and distribution business.
Power
Power is a multi-regional wholesale energy supply business that uses energy trading to optimize the value of its portfolio of electric generating and gas capacity and its supply obligations. Power has three principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Power and its subsidiaries were initially 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. Power also has a finance company subsidiary, PSEG Power Capital Investment Co. (Power Capital), which provides certain financing for Power’s subsidiaries.
Energy Holdings
Energy Holdings is the parent of PSEG Global Inc. (Global), which invests and participates in the development and operation of international and domestic projects in the generation and distribution of energy, which include cogeneration and independent power production facilities and electric distribution companies; PSEG Resources LLC (Resources), which makes investments primarily in energy-related leveraged leases; PSEG Energy Technologies Inc. (Energy Technologies), which provides energy-related services and construction to industrial and commercial customers; Enterprise Group Development Corporation (EGDC), a commercial real estate property management business; PSEG Capital Corporation (PSEG Capital), which serves as a financing vehicle for Energy Holdings’ subsidiaries, and borrows on the basis of a minimum net worth maintenance agreement with PSEG; and Enterprise Capital Funding Corporation (Funding), which is currently inactive and formerly served as the financing vehicle on the basis of Energy Holdings’ consolidated financial position. EGDC has been conducting a controlled exit from the real estate business since 1993. The businesses of Energy Technologies are presented as discontinued operations and are expected to be sold in 2003. PSEG Capital’s final maturity is in 2003, at which point it will no longer be utilized.
Energy Holdings, a New Jersey limited liability company, is the successor to PSEG Energy Holdings Inc. pursuant to a merger consummated in October 2002 which changed the legal form of the business from a corporation to a limited liability company. Energy Holdings succeeded to all the assets and liabilities of PSEG Energy Holdings Inc. in accordance with the New Jersey Limited Liability Company Act. Energy Holdings has succeeded to PSEG Energy Holdings Inc.’s reporting obligations under the Securities Exchange Act of 1934, as amended. As part of the
118
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Energy Holdings reorganization, PSEG Resources Inc. became a wholly-owned subsidiary of Resources, a newly formed New Jersey limited liability company. Resources is wholly-owned by Energy Holdings. This reorganization was completed to further improve efficiencies within PSEG’s tax reporting process.
Other
Services provides management and administrative services such as accounting, legal, communications, human resources, information technology, treasury and financial, investor relations, stockholder services and risk management to PSEG and its subsidiaries. Services charges PSEG and its subsidiaries for the cost of work performed and services provided by it.
Summary of Significant Accounting Policies
Consolidation
PSEG, PSE&G, Power and Energy Holdings
PSEG’s, PSE&G’s, Power’s and Energy Holdings’ consolidated financial statements include their respective accounts and those of their respective subsidiaries. PSEG, PSE&G, Power and Energy Holdings and their respective subsidiaries consolidate those entities in which they have a controlling interest. Those entities in which PSEG, PSE&G, Power and Energy Holdings and their respective subsidiaries do not have a controlling interest are being accounted for under the equity method of accounting. For investments in which significant influence does not exist, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation. No gains or losses are recorded on any intercompany transactions.
PSE&G and Power
In addition, Power and PSE&G each has undivided interests in certain jointly owned facilities. Power and PSE&G are responsible to pay for their respective ownership share of additional construction costs, fuel inventory purchases and operating expenses. All revenues and expenses related to these facilities are consolidated at their respective pro-rata ownership share in the appropriate revenue and expense categories on the Consolidated Statements of Operations.
Accounting for the Effects of Regulation
PSE&G
PSE&G prepares its financial statements in accordance with the provisions of Statement of Financial Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which will be amortized over various future periods. To the extent that collection of such costs or payment of liabilities is no longer probable as a result of changes in regulation and/or PSE&G’s competitive position, the associated regulatory asset or liability is charged or credited to income. PSE&G’s transmission and distribution business continues to meet the requirements for application of SFAS 71.
Derivative Financial Instruments
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings use derivative financial instruments to manage risk from changes in interest rates, congestion credits, emission credits, commodity prices and foreign currency exchange rates, pursuant to its business plans and prudent practices.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
PSEG, PSE&G, Power and Energy Holdings recognize all derivative instruments on the balance sheet at their fair value. Changes in the fair value of a derivative that is highly effective as, and that is designated and qualifies as, a fair-value hedge (including foreign currency fair-value hedges), along with changes of the fair value of the hedged asset or liability that are attributable to the hedged risk, are recorded in current-period earnings. Changes in the fair value of a derivative that is highly effective as and that is designated and qualifies as a cash flow hedge (including foreign currency cash flow hedges), are recorded in Other Comprehensive Income (OCI) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current-period earnings. In certain circumstances, PSEG, PSE&G, Power and/or Energy Holdings enter into derivative contracts and do not designate them as fair value or cash flow hedges, in such cases, changes in fair value are recorded in earnings.
Power
Additionally, Power has certain energy trading contracts that do not meet the definition of a derivative. Those contracts are also carried at fair market value with changes recorded in current-period earnings. Upon adoption of Emerging Issues Task Force (EITF) Issue No. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3) on January 1, 2003, Power will record these contracts at historical cost. See Note 2. New Accounting Standards.
For additional information regarding Derivative Financial Instruments, see Note 12. Risk Management.
Revenue Recognition
PSE&G
PSE&G’s Operating Revenues are recorded based on services rendered to customers during each accounting period. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on weather factors, line losses and unaccounted for gas factors, estimated customer usage by class and applicable customer rates based on regression analyses reflecting significant historical trends and experience.
Power
The majority of Power’s revenues relate to the Basic Generation Service (BGS), Basic Gas Supply Service (BGSS) and other bilateral contracts which are accounted for on the accrual basis, as the energy is delivered. Power also records revenues and energy costs for physical energy delivered to and received from the power pool. Power also records margins from energy trading on a net basis as revenues pursuant to EITF 02-3 and SFAS 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). See Note 12. Risk Management for further discussion.
Energy Holdings
The majority of Resources’ revenues relate to its investments in leveraged leases and are accounted for under SFAS 13 “Accounting for Leases” (SFAS 13). Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as revenues as these events occur in the ordinary course of business of managing the investment portfolio. In accordance with specialized accounting practices, Resources records revenue from the changes in share prices of publicly-traded equity securities held within its leveraged buyout funds. See Note 8. Long-Term Investments for further discussion.
Global records revenues from its investments in generation and distribution facilities. Certain of Global’s investments are majority owned and controlled by Global and the revenues from these projects are recorded as Global’s revenues. Other investments are less than majority owned and are accounted for under the equity or cost methods as appropriate. Revenues for many of these investments are estimated on a monthly basis and trued up to actual results in the next accounting month. Gains or losses incurred as a result of exiting one of these businesses are typically recorded as a component of Operating Income.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Depreciation and Amortization
PSE&G
PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU. The depreciation rate stated as a percentage of original cost of depreciable property was 3.37% for 2002, 3.32% for 2001 and 3.52% for 2000.
Power
Power calculates depreciation on generation-related assets based on the assets’ estimated useful lives determined based on planned operations. 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 |
| Fossil Production | 30-55 years |
| Nuclear Generation | 30-40 years |
| Pumped Storage | 45 years |
Energy Holdings
Energy Holdings calculates depreciation on property, plant and equipment under the straight-line method with estimated useful lives from 3 years to 40 years.
Taxes Other than Income Taxes
PSE&G
Taxes Other than Income Taxes is comprised of the transitional energy facilities assessment (TEFA). TEFA is collected from PSE&G customers and presented gross on PSE&G’s Consolidated Statement of Operations.
Allowance for Funds Used During Construction (AFDC) and Interest Capitalized During Construction (IDC)
PSE&G
AFDC represents the cost of debt and equity funds used to finance the construction of new utility assets under the guidance of SFAS 71. The amount of AFDC capitalized was reported in the Consolidated Statements of Operations as a reduction of interest charges. The rates used for calculating AFDC in 2002, 2001, and 2000 were 8.80%, 6.71%, and 6.45%, respectively. In 2002, 2001, and 2000, PSE&G’s AFDC amounted to $1 million, $2 million, and $1 million, respectively.
Power and Energy Holdings
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 Operations as a reduction of interest charges. Power’s weighted average rates used for calculating IDC in 2002, 2001 and 2000 were 7.01%, 7.98% and 9.98%, respectively. In 2002, 2001, and 2000, Power’s IDC amounted to $95 million, $63 million, and $14 million, respectively. Energy Holdings’ weighted average rates used for calculating IDC in 2002, 2001 and 2000 were 9.06%, 8.05% and 7.93%, respectively. In 2002, 2001, and 2000, Energy Holdings’ IDC amounted to $13 million, $16 million, and $21 million, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Income Taxes
PSEG, PSE&G, Power and Energy Holdings
PSEG and its subsidiaries file a consolidated Federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary. Investment tax credits were deferred in prior years and are being amortized over the useful lives of the related property.
Foreign Currency Translation/Transactions
Energy Holdings
Revenues and expenses are translated at average exchange rates for the year. Transaction gains and losses that arise from exchange rate fluctuations on normal operating transactions denominated in a currency other than the functional currency are included in earnings as incurred.
The assets and liabilities of foreign operations are translated into US Dollars at current exchange rates. Resulting translation adjustments are reflected in OCI, net of taxes, as a separate component of member’s/stockholders’ equity.
Cash and Cash Equivalents
PSEG, PSE&G, Power and Energy Holdings
Cash and cash equivalents consists 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
PSE&G
PSE&G’s materials and supplies are carried at average cost in accordance with rate-based regulation.
Power and Energy Holdings
The carrying value of the materials and supplies and fuel for Power and Energy Holdings is valued at lower of cost or market.
Property, Plant and Equipment
PSE&G
PSE&G’s additions to plant, property and equipment and replacements that are either retirement units or property record units are capitalized at original cost. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation.
Power and Energy Holdings
Power and Energy Holdings only capitalize costs which increase the capacity or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed.
Unamortized Loss on Reacquired Debt and Debt Expense
PSE&G
PSE&G’s bond issuance costs and associated premiums and discounts are generally amortized over the life of the debt issuance. In accordance with New Jersey Board of Public Utility (BPU) and Federal Energy Regulatory Commission (FERC) regulations, PSE&G’s costs to reacquire debt are deferred and amortized over the remaining original life of the retired debt. When refinancing debt, the unamortized portion of the original debt issuance costs of the debt being retired must be amortized over the life of the replacement debt. Gains and losses on reacquired debt associated with PSE&G’s regulated operations will continue to be deferred and amortized to interest expense over the period approved for ratemaking purposes.
Nuclear Decommissioning Trust Funds
Power
Funds in Power’s Nuclear Decommissioning Trust are stated at fair value. Changes in the fair value of the trust funds are also reflected in the accrued liability for nuclear decommissioning. See Note 2. New Accounting Standards for a discussion of SFAS 143.
Investments in Corporate Joint Ventures and Partnerships
Energy Holdings
Global’s and Resources’ interests in active joint ventures and partnerships are accounted for under the equity method of accounting where their respective ownership interests are 50% or less and significant influence over joint venture or partnership operating and management decisions exists. For investments in which significant influence does not exist, the cost method of accounting is applied. Interest is capitalized on investments during the construction and development of qualifying assets.
Resources carries its partnership investments in certain venture capital and leveraged buyout funds investing in securities at fair value where market quotations and an established liquid market of underlying securities in the portfolio are available. Fair value is determined based on the review of market price and volume data in conjunction with PSEG’s invested liquid position in such securities. Changes in fair value are recorded in Operating Revenues in the Consolidated Statements of Operations.
Goodwill
PSEG, Power and Energy Holdings
PSEG, Power and Energy Holdings record the cost in excess of fair value of net assets (including tax attributes) of companies acquired in purchase business transactions as goodwill.
PSEG, Power and Energy Holdings annually evaluate the recoverability of goodwill by estimating the fair value of the businesses to which goodwill relates. PSEG, Power and Energy Holdings typically determine fair value by estimating the future discounted cash flows. The discount rate used in determining discounted cash flows is a rate corresponding to the cost of capital of the business to which the goodwill relates. Estimated cash flows are then determined by disaggregating PSEG’s, Power’s and Energy Holdings’ respective business segments to an operational and organizational level for which meaningful identifiable cash flows can be determined. When estimated future discounted cash flows are less than the carrying value of the net assets (tangible or identifiable intangibles) and related goodwill, impairment losses of goodwill are charged to operations. Impairment losses, limited to the carrying value of goodwill, represent the excess sum of the fair value of the net assets (tangible or identifiable intangibles) and goodwill over the discounted cash flows of the business being evaluated. In
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
determining the estimated future cash flows, PSEG, Power and Energy Holdings consider current and projected future levels of income, as well as business trends, prospects and economic conditions.
For a discussion of business combinations and goodwill, see Note 2. New Accounting Standards and Note 9. Purchase Business Combinations/Asset Acquisitions.
Capital Leases as Lessor
Energy Holdings
Resources, as lessor, leases property and equipment, through leveraged leases, with terms ranging from 4 to 45 years. The lease investments are recorded on a net basis by totaling the lease rents receivable over the lease term and adding the residual value, if any, less unearned income and deferred taxes to be recognized over the lease term. Leveraged leases are recorded net of non-recourse debt.
Deferred Project Costs
Power and Energy Holdings
Power and Energy Holdings capitalize all direct external and direct incremental internal costs related to project development once a project reaches certain milestones. Once the project reaches financial closing, the deferred project balance is transferred to the investment account. These costs are amortized on a straight-line basis over the lives of the related project assets. Such amortization commences upon the date of commercial operation. Development costs related to unsuccessful projects are charged to expense. Deferred project costs are recorded in Other Assets on the Consolidated Balance Sheets.
Use of Estimates
PSEG, PSE&G, Power and Energy Holdings
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. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.
Reclassifications
PSEG, PSE&G, Power and Energy Holdings
Certain reclassifications of amounts reported in prior periods have been made to conform with the current presentation.
Note 2. New Accounting Standards
SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142)
PSEG, PSE&G, Power and Energy Holdings
On January 1, 2002, PSEG, PSE&G, Power and Energy Holdings adopted SFAS 142. Under this standard, PSEG, PSE&G, Power and Energy Holdings were required to complete an impairment analysis of goodwill before June 30, 2002 and record any required impairment retroactive to January 1, 2002. Under SFAS 142, goodwill is considered a nonamortizable asset and is subject to an annual review for impairment and an interim review when certain events or changes in circumstances occur. The effect of no longer amortizing goodwill on an annual basis was not material to PSEG’s, PSE&G’s or Power’s financial position and results of operations upon adoption.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
In addition to goodwill, PSEG has consolidated intangible assets related to its defined benefit pension plans, which is not subject to amortization for Power’s emissions allowances and for various access rights at Power’s Albany station. PSEG’s total intangible assets were $206 million, including $114 million, $52 million and $40 million related to defined benefit plans, emissions allowances and various access rights, respectively, as of December 31, 2002.
Power and Energy Holdings
Power and Energy Holdings evaluated the recoverability of the recorded amount of goodwill based on certain operating and financial factors. Such impairment testing included discounted cash flow tests which require broad assumptions and significant judgment to be exercised by management.
Energy Holdings
During the second quarter of 2002, Energy Holdings finalized its evaluation of the effect of SFAS 142 on the recorded amount of goodwill. The total amount of goodwill impairments was $120 million, net of tax of $66 million and was comprised of $36 million (after-tax) at Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), an Argentine distribution company, $34 million (after-tax) at Rio Grande Energia (RGE), a Brazilian distribution company of which Global owns 32%, $32 million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir Bavi, a generating facility in India, which was 74% owned by Global. All of the goodwill related to these companies, other than RGE, was fully impaired.
As of December 31, 2002, the remaining carrying value of Energy Holdings’ goodwill was $436 million, of which $430 million was recorded in connection with Global’s acquisitions of Sociedad Austral de Electricidad S.A. (SAESA), a distribution company in Chile, and Empresa de Electricidad de los Andes S.A. (Electroandes), a generation company in Peru in August and December of 2001, respectively. For the year ended December 31, 2001, amortization expense related to goodwill was $3 million.
As of December 31, 2002, Energy Holdings’ pro-rata share of the remaining goodwill included on the balance sheets of its equity method investees totaled $282 million. In accordance with generally accepted accounting principles, such goodwill is not consolidated on the balance sheet. Energy Holdings’ share of the amortization expense related to such goodwill was $8 million for the year ended December 31, 2001.
In addition to goodwill, Energy Holdings has an intangible asset related to its defined benefit pension plans, which is not subject to amortization. This intangible asset totaled $5 million as of December 31, 2002.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Power and Energy Holdings
As of December 31, 2002 and 2001, Power and Energy Holdings’ goodwill and pro-rata share of goodwill in consolidated equity method projects was as follows:
| As of December 31, | ||||||
| 2002 | 2001 | |||||
| Consolidated Investments | (Millions) | |||||
| |
||||||
| Energy Holdings (1) | ||||||
| SAESA(2) | $ | 290 | $ | 315 | ||
| EDEERSA(3) | — | 63 | ||||
| Electroandes(4) | 140 | 164 | ||||
| Elektrocieplownia Chorzow Sp. Z o.o. (ELCHO) | 6 | 6 | ||||
| Total Energy Holdings-Global | 436 | 548 | ||||
| Power – Albany Steam Station (5) | 16 | 21 | ||||
| Total PSEG Consolidated Goodwill | 452 | 569 | ||||
| Pro-Rata Share of Equity Method Investments | ||||||
| |
||||||
| Energy Holdings | ||||||
| RGE (6) | 60 | 142 | ||||
| Chilquinta Energia S.A. (Chilquinta) (7) | 163 | 174 | ||||
| Luz del Sur S.A.A. | 34 | 34 | ||||
| Kalaeloa | 25 | 25 | ||||
| Pro-Rata Share of Equity Investment Goodwill | 282 | 375 | ||||
| Total PSEG Goodwill | $ | 734 | $ | 944 | ||
| (1) | Goodwill for Tanir Bavi and Energy Technologies was fully impaired in 2002. For 2001, goodwill for Tanir Bavi and Energy Technologies of $27 million and $53 million, respectively, was reclassed to Current Assets of Discontinued Operations. See Note 5. Discontinued Operations for additional information. | |
| (2) | The decrease at SAESA relates to final purchase price adjustments that resulted in higher value allocated to fixed assets. | |
| (3) | The decrease at EDEERSA relates to an impairment of $56 million under SFAS 142 and to purchase price adjustments of $7 million made subsequent to December 31, 2001. | |
| (4) | The decrease at Electroandes relates to purchase price adjustments made subsequent to December 31, 2001 which resulted in higher value allocated to Property, Plant and Equipment. | |
| (5) | The decrease at Albany relates to a purchase price adjustment related to a contingent liability. | |
| (6) | The decrease at RGE relates to an impairment under SFAS 142 totaling $50 million and the devaluation of the Brazilian Real amounting to $32 million. | |
| (7) | The decrease at Chilquinta relates to the devaluation of the Chilean Peso. | |
| Power |
||
| In
addition to goodwill associated with Power’s Albany Station (see table
above), Power has intangible assets relating to its defined benefit pension
plans, for its emissions allowances and for various access rights at the
Albany station, all of which are not subject to amortization. Power’s
intangible asset relating to its defined benefit pension plans totaled $33
and $5 million as of December 31, 2002 and 2001, respectively. Power’s
intangible assets relating to its emissions allowances totaled $52 million
and $2 million as of December 31, 2002 and 2001, respectively. Power’s
intangible assets relating to various access rights at its Albany Station
totaled approximately $40 million as of December 31, 2002 and 2001. |
||
126 |
||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
PSE&G
PSE&G has intangible assets relating to its defined benefit pension plans totaling $60 million and $7 million as of December 31, 2002 and December 31, 2001, respectively. These intangible assets are not subject to amortization.
SFAS No. 144. “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144)
PSEG, PSE&G, Power and Energy Holdings
On January 1, 2002, (SFAS 144) which provides guidance on the accounting for the impairment or disposal of long-lived assets, became effective. For long-lived assets to be held and used, the new rules are similar to previous guidance which required the recognition of an impairment when the undiscounted cash flows will not recover its carrying amount. The impairment to be recognized is measured as the difference between the carrying amount and fair value of the asset. The computation of fair value now removes goodwill from consideration and incorporates a probability-weighted cash flow estimation approach. The previous guidance provided in SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of ” (SFAS 121) is to be applied to assets that are to be disposed of by sale. Additionally, assets qualifying for discontinued operations treatment have been expanded beyond the former major line of business or class of customer approach. Long-lived assets to be disposed of by other than sale now recognize impairment at the date of disposal, but are considered assets to be held and used until that time. There was no impact on the Consolidated Financial Statements of PSEG, PSE&G, Power or Energy Holdings upon adoption of these rules. For additional information, see Note 4. Asset Impairments.
SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143)
PSEG, PSE&G, Power and Energy Holdings
Effective January 1, 2003, PSEG, PSE&G, Power and Energy Holdings will adopt SFAS 143. SFAS 143 addresses accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract.
Under SFAS 143, a company must initially recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred and concurrently capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. A company shall subsequently allocate that asset retirement cost to expense over its useful life. In periods subsequent to initial measurement, an entity shall recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either the timing or the amount of the originally estimated cash flows. Changes in the liability due to accretion will be charged to the Consolidated Statements of Operations, whereas changes due to the timing or amount of cashflows shall be an adjustment to the carrying amount of the related asset.
PSE&G and Power
Power has performed a review of its potential obligations under SFAS 143 and believes that its quantifiable obligations are primarily related to the decommissioning of its nuclear power plants. Prior to the adoption of SFAS 143, amounts collected from PSE&G customers that have been deposited into the Nuclear Decommissioning Trust and realized and unrealized gains and losses in the trust were all recorded as changes in the NDT Fund with an offsetting charge to the liability. Beginning January 1, 2003, amounts will be recorded in earnings or in OCI, as appropriate. As of December 31, 2002, Power had a $766 million asset and liability recorded on its Consolidated Balance Sheets for nuclear decommissioning.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
In addition to the quantifiable obligations, Power identified certain legal obligations that meet the criteria of SFAS 143, which at this time are not quantifiable. These obligations relate to certain industrial establishments subject to the Industrial Site Recovery Act, underground storage tanks subject to the Spill Compensation and Control Act, permits and authorizations, the restoration of an area occupied by a reservoir when the reservoir is no longer needed, an obligation to retire from operation, certain plants prior to the initial burning of fuel from a new plant and the demolition of certain plants and the restoration of the sites when the plants are no longer in service.
In August 2002, PSE&G filed a petition requesting clarification from the BPU regarding the future cost responsibility for nuclear decommissioning and whether: (a) PSE&G’s customers will continue to pay for such costs; or (b) such customer responsibility will terminate at the end of the four-year transition period on July 31, 2003 and become the sole responsibility of Power. The outcome of this petition will affect the treatment of a material portion of the liability recorded for Power’s nuclear decommissioning obligation. If the BPU determines that PSE&G’s customers will continue to pay for these costs, the majority of the difference between the previously recorded amount of the liability and the liability calculated under SFAS 143 will continue to be deferred on the balance sheet. If the BPU determines that such customer responsibility terminates at the end of the transition period, then the net effect of implementation will be recorded as a one-time benefit as a Cumulative Effect of a Change in Accounting Principle. A decision is expected as part of PSE&G’s electric base rate case, which is expected to be completed prior to July 2003. Although the outcome of this petition cannot be predicted, management believes that the net effect of adopting this accounting standard should be recorded in earnings. Power also has $131 million of liabilities, $7 million of which relates to legal obligations, recorded on its Consolidated Balance Sheets at December 31, 2002 related to the Cost of Removal associated with its fossil generating stations. These potential obligations are required to be reversed upon implementation of SFAS 143.
Therefore, upon adoption of this standard on January 1, 2003, PSEG and Power will record an adjustment for a Cumulative Effect of a Change in Accounting Principle in the Consolidated Statements of Operations by reducing the existing liabilities to their present value. It is anticipated that the result will be a benefit to net income, and therefore equity, in a range of $300 million to $400 million. Of this amount, $200 million to $300 million relates to interests in certain nuclear units Power purchased from PSE&G which is subject to the BPU issue discussed above, approximately $55 million relates to interests in certain nuclear units Power purchased from Atlantic City Electric Company (ACE) and Delmarva Power and Light Company (DP&L) which is not subject to BPU approval and approximately $70 million relates to the cost of removal liabilities for the fossil units being reversed.
The BPU could decide that the future cost for decommissioning the nuclear units rests with PSE&G’s customers. If that is the case, the portion of the benefit to equity related to the nuclear units Power purchased from PSE&G would be reversed and a regulatory liability would be established. The $55 million related to the nuclear units purchased from ACE and DP&L and the $70 million related to the cost of removal liabilities for the fossil units would be unaffected.
PSE&G
At December 31, 2002, PSE&G had no legal liabilities, as contemplated under SFAS 143, recorded on the consolidated balance sheets and therefore the effect of adoption will not result in an adjustment to the consolidated statement of earnings. PSE&G does, however, have cost of removal liabilities embedded within Accumulated Depreciation pursuant to SFAS 71. Since PSE&G is a regulated enterprise, these amounts will continue to be recorded and presented in Accumulated Depreciation and will be disclosed in accordance with SFAS 143.
PSE&G has identified certain legal obligations that meet the criteria of SFAS 143 which at this time are not quantifiable and therefore unable to be recorded. These obligations relate to certain industrial establishments subject to the Industrial Site Recovery Act, underground storage tanks subject to the Spill Compensation and Control Act, leases and licenses, and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Energy Holdings
Energy Holdings identified certain legal obligations that met the criteria of SFAS 143 and are not expected to be material to the Consolidated Statement of Operations.
SFAS No. 145, “Rescission of FASB Statements Nos. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections” (SFAS 145)
PSEG, PSE&G, Power and Energy Holdings
Effective January 1, 2002, PSEG, PSE&G, Power and Energy Holdings adopted SFAS 145. This Statement rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishments of Debt,” (SFAS 4) and an amendment of that Statement, SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking Fund Requirements” (SFAS 64). SFAS 4 required that gains and losses from extinguishments of debt that were included in the determination of net income be aggregated, and if material, classified as an extraordinary item. Since the issuance of SFAS 4, the use of debt extinguishments has become part of the risk management strategy of many companies, representing a type of debt extinguishment that does not meet the criteria for classification as an extraordinary item. Based on this trend, the FASB issued this rescission of SFAS 4 and SFAS 64. Accordingly, under SFAS 145, PSEG now records these gains and losses in Other Income and Other Deductions, respectively. PSEG recorded pre-tax gains of $13 million ($8 million after-tax) from the early retirement of debt as a component of Other Income for the period ended December 31, 2002. Also, PSEG reclassified a pre-tax loss of $3 million ($2 million after-tax) from the early retirement of debt to a component of Other Deductions for the period ended December 31, 2001.
SFAS 133
PSEG, PSE&G, Power and Energy Holdings
On January 1, 2001, PSE&G, Power and Energy Holdings adopted 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) or as a Regulatory Asset (Liability), 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 flow hedge is recorded in earnings. Derivative instruments that have not been designated as hedges are adjusted to fair value through earnings.
Energy Holdings
Upon adoption, Energy Holdings recorded a cumulative effect of a change in accounting principle of $9 million, net of tax and a decrease to OCI of $15 million, respectively.
EITF 02-3
PSE&G and Power
EITF 02-3 requires all gains and losses on energy trading derivatives to be reported on a net basis. Also, energy trading contracts that are not derivatives will no longer be marked to market. Instead, settlement accounting will be used. EITF 02-3 was effective for all new contracts executed after October 25, 2002 and will require a cumulative effect adjustment to income in the first quarter of 2003 for all contracts executed prior to October 25, 2002. The vast majority of Power’s energy contracts qualify as derivatives under SFAS 133 and will therefore continue to be marked to market. Management believes the impact of adopting this EITF 02-3 will not be material to the financial statements.
129
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Pursuant to EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19), PSE&G (prior to the generation-related asset transfer in August 2000) and Power had been recording trading revenues and trading related costs on a gross basis for physical energy and capacity sales and purchases. In accordance with EITF 02-3, beginning in the third quarter of 2002, Power started reporting energy trading revenues and energy trading costs on a net basis and have reclassified prior periods to conform with this net presentation. As a result, both Operating Revenues and Energy Costs were reduced by approximately $1.9 billion, $2.3 billion and $2.6 billion for the years ended December 31, 2002, 2001 and 2000, respectively. This change in presentation did not have an effect on trading margins, net income or cash flows.
Financial Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45)
PSEG, PSE&G, Power and Energy Holdings
FIN 45 enhances the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee, although PSEG, PSE&G, Power and Energy Holdings do not anticipate the recording of such liabilities will be material to their respective Consolidated Financial Statements. The initial recognition and initial measurement provisions of this Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. For further information regarding Power’s and Energy Holdings’ respective guarantees, refer to Note 13. Commitments and Contingent Liabilities.
FIN No. 46, “Consolidation of Variable Interest Entities (VIE)” (FIN 46)
PSEG, PSE&G, Power and Energy Holdings
FIN 46 clarified the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements”, to certain entities in which equity investors do not have the characteristics of a controlling financial interest. Because a controlling financial interest in an entity may be achieved through arrangements that do not involve voting interests, FIN 46 sets forth specific requirements with respect to consolidation, measurement and disclosure of such relationships. Disclosure requirements for existing qualifying entities are effective for financial statements issued after January 31, 2003. All enterprises with VIEs created after February 1, 2003, shall apply the provisions of FIN 46 no later than the beginning of the first interim period beginning after June 15, 2003.
Other
PSE&G, Power and Energy Holdings
In connection with the January 2003 EITF meeting, the FASB was requested to reconsider an interpretation of SFAS 133. The interpretation, which is contained in the Derivatives Implementation Group’s C-11 guidance, relates to the pricing of contracts that include broad market indices. In particular, that guidance discusses whether the pricing in a contract that contains broad market indices (e.g., CPI) could qualify as a normal purchase or sale under SFAS 133. PSEG, PSE&G, Power and Energy Holdings are currently reevaluating which contracts, if any, that have previously been designated as normal purchases or sales would now not qualify for this exception. PSEG, PSE&G, Power and Energy Holdings are currently evaluating the effects that this guidance will have on their respective results of operations, financial position and net cash flows.
130
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS — Continued | ||
| Note
3. Change in Accounting Principle | ||
| PSE&G
and Power | ||
| PSE&G
and Power has each changed its method of accounting for the classification
of assets and liabilities arising from transactions related to energy trading
contracts when the right of set-off exists, from a separate presentation
of assets and liabilities to a net presentation. PSE&G and Power believe
that the right of set-off exists when all of the following conditions are
met: | ||
| · | PSE&G or Power and its respective counterparty owes the other determinable amounts; | |
| · | PSE&G or Power have the right to set off the amount owed with the amount owed by its respective counterparty; | |
| · | PSE&G or Power intend to set off; and | |
| · | the right of set-off is enforceable
by law. |
|
| PSE&G
and Power each believe that this change in method of accounting and classification
is preferable and more closely represents the economic substance of such
transactions. Additionally, the new method reflects PSE&G’s and
Power’s existing practice of settling amounts net, and is consistent
with the classification of trading revenues and trading costs on a net basis
on the Consolidated Statements of Operations. | ||
| As
of and for the year ended December 31, 2002, there was no effect on revenues,
expenses, net income or cash flows as a result of this change. Affected
amounts on the Consolidated Balance Sheets have been reclassified for all
periods presented. The impact of this reclassification was a decrease as
of December 31, 2001 in PSEG’s current assets, noncurrent assets, current
liabilities and noncurrent liabilities by approximately $266 million ($240
million related to Power and $26 million related to PSE&G), $17 million
(primarily all related to Power), $271 million ($240 million related to
Power and $31 million related to PSE&G) and $12 million (a $17 million
decrease related to Power and a $5 million increase related to PSE&G),
respectively. | ||
| Note 4. Asset Impairments | ||
| Energy
Holdings | ||
| As
of December 31, 2001, Energy Holdings’ aggregate investment exposure
in Argentina was $632 million, including certain loss contingencies. These
investments included a 90% owned distribution company, Empresa Distribuidora
de Electricidad de Entre Rios S.A. (EDEERSA); minority interests in three
distribution companies, Empresa Distribuidora de Energia Norte S.A. (EDEN),
Empresa Distribuidora de Energia Sur S.A. (EDES) and Empresa Distribuidora
La Plata S.A. (EDELAP); and two generating companies, Central Termica San
Nicolas S.A. (CTSN), and AES Parana S.C.A. (Parana) which were under contract
for sale to certain subsidiaries of The AES Corporation (AES). In June 2002,
Energy Holdings determined that the carrying value of its Argentine investments
was impaired. The combination of the year-to-date operating losses, goodwill
impairment at EDEERSA, write-down of $497 million for all Argentine assets,
and certain loss contingencies resulted in a pre-tax charge to earnings
of $623 million ($406 million after-tax). In connection with the write-down
of Energy Holdings’ Argentine assets, Energy Holdings recorded a net
deferred tax asset of $217 million. Energy Holdings has reviewed this deferred
tax asset for recoverability and no reserve is required. For a discussion
of certain contingencies related to Argentine investments, see Note 13.
Commitments and Contingent Liabilities. | ||
131 | ||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
The tables below provide pre-tax and after-tax impacts of the various impairment charges, results of operations and accruals of loss contingencies recorded with respect to Energy Holdings’ investments in Argentina for the periods ended December 31, 2002 and 2001.
| (Pre-Tax) December 31, |
(After-Tax) December 31, | |||||||||||
| 2002 | 2001 | 2002 | 2001 | |||||||||
| (Millions) | ||||||||||||
| (Losses) Earnings Before Local Taxes-EDEERSA | $ | (59 | ) | $ | 21 | $ | (40 | ) | $ | 13 | ||
| Write-down of EDEERSA | (94 | ) | — | (61 | ) | — | ||||||
| Write-down of Assets Held for Sale to AES | (403 | ) | — | (262 | ) | — | ||||||
| Loss Contingencies and Other | (11 | ) | — | (7 | ) | — | ||||||
| Goodwill Impairment-EDEERSA | (56 | ) | — | (36 | ) | — | ||||||
| Total | $ | (623 | ) | $ | 21 | $ | (406 | ) | $ | 13 | ||
The asset impairments are described in more detail below.
EDEERSA
In January 2002, the Argentine Federal government enacted a temporary emergency law that imposed various changes to the concession contracts in effect between electric distributors and local and federal regulators. The Province of Entre Rios enjoined in the emergency law impacting operations at EDEERSA. The Argentine government and regulators made unilateral decisions to abrogate key components of the tariff concessions related to public utilities. In addition to the emergency law, the Province of Entre Rios unilaterally enacted other laws which forced EDEERSA to accept provincial bonds, known as “federales”, as payment for electric service in lieu of Argentine Pesos. Federales cannot be exchanged outside of the Entre Rios Province. In addition, restrictions were imposed on EDEERSA’s ability to terminate service to a majority of customers in the event of nonpayment.
Such laws significantly restricted Global’s ability to control the operations of EDEERSA, as unilateral changes enacted by the government restricted Global’s ability to manage its operations to reduce the financial losses incurred as a result of such actions. In the second quarter of 2002, Global believed such temporary measures were likely to be permanent in nature as a credible solution to the economic crisis in Argentina, including International Monetary Fund (IMF) support, was not probable. The more significant provisions included in the initial emergency law remain in effect. As a result of a loss of control of the financial and operational management of EDEERSA, the investment is recorded in accordance with the equity method of accounting as of December 31, 2002. Global has no significant exposure remaining related to EDEERSA as of December 31, 2002.
As of January 1, 2002, goodwill related to Energy Holdings’ investment in EDEERSA was approximately $56 million and was included in Energy Holdings’ previously disclosed investment exposure. As part of the adoption of SFAS 142, Energy Holdings determined that this goodwill was impaired and all of the goodwill was written-off as of January 1, 2002. See Note 2. New Accounting Standards for a further discussion of the goodwill analysis.
Based on actual and projected operating losses at EDEERSA and the continued economic uncertainty in Argentina, Energy Holdings determined that it was necessary to test these assets for impairment. Such impairment analyses were completed as of June 30, 2002. As a result of these analyses, Energy Holdings determined that these assets were completely impaired under SFAS 144. Energy Holdings recorded total charges and losses of $213 million, pre-tax, related to this investment for the year ended December 31, 2002. These pre-tax charges consisted of goodwill impairment charges (calculated under SFAS 142) of $56 million, operating losses of $59 million, of which $45 million was recorded in the first quarter of 2002, a write-off of the remaining $94 million net asset balance pursuant to the SFAS 144 impairment analysis and loss contingencies and other items of $4 million. The total after-tax charges and losses related to this investment were $139 million for the period ended December 31, 2002.
132
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Energy Holdings’ share of the pre-tax (Losses) Earnings for EDEERSA are included in the Consolidated Statements of Operations as indicated in the following table:
| December 31, | |||||||
| 2002(A) | 2001(B) | ||||||
| (Millions) | |||||||
| Operating Revenues | $ | 19 | $ | 63 | |||
| Operating Expenses | 14 | 41 | |||||
| Operating Income | 5 | 22 | |||||
| Other Losses – Foreign Currency Transaction Loss | (68 | ) | — | ||||
| Minority Interest and Other | 4 | ( 1 | ) | ||||
| (Loss) Earnings before Taxes | $ | (59 | ) | $ | 21 | ||
| (A) | In the second quarter of 2002,
as a result of a loss of control of EDEERSA, Energy Holdings accounted for
this investment in accordance with the equity method of accounting. | |
| (B) | Operating results for EDEERSA included
$7 million of revenues recorded in accordance with the equity method of
accounting for the six months ended June 30, 2001. In the third quarter
of 2001, Global recorded EDEERSA as a consolidated entity as it was a majority-owned
investment. | |
| Stock
Purchase Agreement | ||
| On
August 24, 2001, Global entered into a Stock Purchase Agreement with AES
to sell its minority interests in EDEN, EDES, EDELAP, CTSN and Parana, to
certain subsidiaries of AES. In connection with the terms of the Stock Purchase
Agreement, Global accrued interest and other receivables of $17 million
through February 6, 2002, which were direct obligations of AES. On February
6, 2002, AES notified Global that it was terminating the Stock Purchase
Agreement. In the Notice of Termination, AES alleged that a Political Risk
Event, within the meaning of the Stock Purchase Agreement, had occurred
by virtue of certain decrees of the Government of Argentina, thereby giving
AES the right to terminate the Stock Purchase Agreement. As discussed previously,
Energy Holdings recorded a Write-Down of Project Investments of $403 million,
pre-tax, net of the reduction discussed below, for the year ended December
31, 2002. Global filed suit in New York State Supreme Court for New York
County against AES to enforce its rights under the Stock Purchase Agreement.
A settlement was reached in October 2002 between the parties under which
Global will transfer its minority ownership interest in EDEN, EDES, EDELAP,
Parana and CTSN to AES. AES paid Global $15 million under the settlement
and, in addition, has issued promissory notes which should yield an additional
$15 million, plus interest at 12%, maturing through July 2003. In the fourth
quarter of 2002, Energy Holdings assessed the collectibility of the notes
receivable and recognized $9 million of Operating Income. This amount was
recorded as a reduction in the Write-Down of Project Investments. In February
2003, Energy Holdings received the first note installment totaling $5 million,
plus interest. | ||
133 | ||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 5. Discontinued Operations
Energy Holdings
Energy Technologies’ Investments
Energy Technologies is primarily comprised of 11 heating, ventilating and air conditioning (HVAC) and mechanical operating companies. In June 2002, Energy Holdings adopted a plan to sell its interests in the HVAC/mechanical operating companies. The sale of these companies is expected to be completed by June 30, 2003. Energy Holdings has retained the services of an investment-banking firm to market these companies to interested parties. The HVAC/mechanical operating companies meet the criteria for classification as components of discontinued operations and all prior periods have been reclassified to conform to the current year’s presentation.
In addition to the pre-tax goodwill impairment of $53 million recorded in accordance with the adoption of SFAS 142, Energy Holdings reviewed this investment for impairment in accordance with SFAS 144 and has further reduced the carrying value of the 11 HVAC/mechanical operating companies to their fair value less costs to sell and recorded a loss on disposal for the year ended December 31, 2002 of $21 million, net of $11 million in taxes. Energy Holdings’ remaining investment position in Energy Technologies is approximately $56 million, of which $32 million relates to deferred tax assets from discontinued operations and $12 million relates to certain intercompany payables included in Current Liabilities of Discontinued Operations. For a discussion of these intercompany payables included in the Current Liabilities of Discontinued Operations, see Note 22. Related-Party Transactions.
Operating results of the HVAC/mechanical operating companies, less certain allocated costs from Energy Holdings, have been reclassified into discontinued operations in the Consolidated Statements of Operations. The results of operations of these discontinued operations for the periods ended December 31, 2002, 2001 and 2000, respectively, are displayed below:
| Years Ended December 31, | |||||||||
| 2002 | 2001 | 2000 | |||||||
| (Millions) | |||||||||
| Operating Revenues | $ | 378 | $ | 441 | $ | 316 | |||
| Operating Loss | $ | (30 | ) | $ | (31 | ) | $ | (20 | ) |
| Loss Before Income Taxes | $ | (32 | ) | $ | (34 | ) | $ | (17 | ) |
| Net Loss | $ | (21 | ) | $ | (22 | ) | $ | (12 | ) |
The carrying amounts of the assets and liabilities of the HVAC/mechanical operating companies, as of December 31, 2002 and 2001, have been reclassified into Current Assets of Discontinued Operations and Current Liabilities of Discontinued Operations, respectively, on the Consolidated Balance Sheets and are summarized in the following table:
| As of December 31, | ||||||
| 2002 | 2001 | |||||
| (Millions) | ||||||
| Current Assets | $ | 82 | $ | 152 | ||
| Noncurrent Assets | 25 | 74 | ||||
| Total Assets | $ | 107 | $ | 226 | ||
| Current Liabilities | $ | 85 | $ | 76 | ||
| Noncurrent Liabilities | 5 | 2 | ||||
| Long-Term Debt | 5 | 1 | ||||
| Total Liabilities | $ | 95 | 79 | |||
134
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Tanir Bavi
In the fourth quarter of 2002, Global sold its 74% interest in Tanir Bavi, a 220 MW barge mounted, combined-cycle generating facility in India. Tanir Bavi meets the criteria for classification as a component of discontinued operations and all prior periods have been reclassified to conform to the current year’s presentation. Global reduced the carrying value of Tanir Bavi to the contracted sales price of $45 million and recorded a loss on disposal of $14 million (after-tax) for the year-ended December 31, 2002. The operating results of Tanir Bavi for the years ended December 31, 2002 and 2001 yielded income of $5 million and $7 million (after-tax), respectively.
For information regarding the goodwill impairment associated with Tanir Bavi, see Note 2. New Accounting Standards.
Global’s share of operating results of this discontinued operation are summarized in the following table:
| Years Ended December 31, | ||||||
| 2002 | 2001 (A) | |||||
| (Millions) | ||||||
| Operating Revenues | $ | 61 | $ | 56 | ||
| Operating Income | $ | 23 | $ | 16 | ||
| Income Before Income Taxes | $ | 7 | $ | 14 | ||
| Net Income | $ | 5 | $ | 7 | ||
(A) Commerical operations at Tanir Bavi began in 2001.
The carrying amounts
of the assets and liabilities of Tanir Bavi, as of December 31, 2001, have been
reclassified into Current Assets of Discontinued Operations and Current Liabilities
of Discontinued Operations, respectively, in the Consolidated Balance Sheets.
The carrying amounts of the major classes of assets and liabilities of Tanir
Bavi, as of December 31, 2001, are summarized in the following tables:
| As of December 31, 2001 |
||||
| (Millions) | ||||
| Current Assets | $ | 37 | ||
| Net Property, Plant and Equipment | 190 | |||
| Noncurrent Assets | 30 | |||
| Total Assets | $ | 257 | ||
| Current Liabilities | $ | 45 | ||
| Noncurrent Liabilities | 19 | |||
| Long-Term Debt | 108 | |||
| Total Liabilities | $ | 172 | ||
| |
||||
135
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 6. Regulatory Issues and Accounting Impacts of Deregulation
New Jersey Energy Master Plan Proceedings and Related Orders
PSE&G and Power
Following the enactment of the New Jersey Electric Discount and Energy Competition Act (Energy Competition Act), the BPU issued its Final Order in 1999 relating to PSE&G’s rate unbundling, stranded costs and restructuring proceedings (Final Order). This Final Order deregulated the electric generation business and set the stage to deregulate the gas supply business in New Jersey. As a result of this process, PSE&G transferred its generation business to Power in August 2000 and the gas supply business to Power in May 2002. The electric business was transferred at the BPU prescribed price of $2.4 billion, plus $343 million for the book value of the related materials and supplies. PSE&G transferred its gas inventories and contracts to Power and its subsidiaries in May 2002 for approximately $183 million.
Also in the Final Order, the BPU concluded that PSE&G should recover up to $2.9 billion (net of tax) of its electric 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 a market transition charge (MTC) included in Operating Revenues through the transition period ending July 31, 2003. PSE&G remits the MTC revenues to Power as part of the BGS contract as provided for by the Final Order which is included in operating revenues.
On January 31, 2001, $2.5 billion of securitization bonds (non-recourse asset backed securities) were issued by PSE&G Transition Funding LLC (Transition Funding), in eight classes with maturities ranging from 1 year to 15 years. Also on January 31, 2001, PSE&G received payment from Power on its $2.8 billion promissory note used to finance the transfer of PSE&G’s generation business. The proceeds from these transactions were used to pay for certain debt issuance and related costs for securitization, retire a portion of PSE&G’s outstanding short-term debt, reduce PSE&G common equity, loan funds to PSEG and make various short-term investments in accordance with the Final Order.
In order to properly recognize the recovery of the allowed unsecuritized stranded costs over the transition period, PSE&G recorded a charge to net income of $88 million, pre-tax, or $52 million, after tax, in the third quarter of 2000 for the cumulative amount of estimated collections in excess of the allowed unsecuritized stranded costs from August 1, 1999 through September 30, 2000. As of December 31, 2002, the amount of estimated collections in excess of the allowed unsecuritized stranded costs was $189 million. For additional information, see Note 7. Regulatory Assets and Liabilities. After deferrals, pre-tax MTC revenues recognized were $221 million in 1999, $239 million in 2000, $196 million in 2001 and $98 million in 2002. In 2003, PSE&G expects to record approximately $115 million in pre-tax MTC revenues.
Note 7. Regulatory Assets and Liabilities
PSE&G
PSE&G prepares its financial statements in accordance with the provisions of SFAS 71. A regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs, which will be amortized over various future periods. These costs are deferred based on rate orders issued by the BPU or the FERC and PSE&G’s experience with prior rate cases. As of December 31, 2002, approximately 87% of PSE&G’s regulatory assets were deferred based on written rate orders. Regulatory assets recorded on a basis other than by an issued rate order have less certainty of recovery
136
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
since they can be disallowed in the future by regulatory authorities. However, PSE&G has experienced no material disallowances in the past. PSE&G believes that all of its regulatory assets are probable of recovery.
As of December 31, 2002 and 2001, respectively, PSE&G had deferred the following regulatory assets and liabilities on the Consolidated Balance Sheets:
| As of December 31, |
||||||||
| 2002 | 2001 | Recovery/Refund Period | ||||||
| (Millions) | ||||||||
| Regulatory Assets | ||||||||
|
|
||||||||
| Stranded Costs To Be Recovered | $ | 3,885 | $ | 4,105 | Through December 2015 | (1)(2) | ||
| Deferred Income Taxes | 328 | 302 | Various | |||||
| OPEB-Related Costs | 193 | 212 | Through December 2012 | (2) | ||||
| Societal Benefits Charges (SBC) | — | 4 | ||||||
| Manufactured Gas Plant Remediation Costs | 115 | 87 | Various | (2) | ||||
| Unamortized Loss on Reacquired Debt and Debt Expense | 86 | 92 | Over remaining debt life | (1) | ||||
| Underrecovered Gas Costs | 154 | 117 | Through September 2004 | (1) | ||||
| Unrealized Losses on Gas Contracts | — | 137 | ||||||
| Unrealized Losses on Interest Rate Swap | 66 | 18 | Through December 2015 | (2) | ||||
| Repair Allowance Taxes | 93 | 84 | Through August 2004 | (2)(3) | ||||
| Decontamination and Decommissioning Costs | 21 | 25 | Through December 2007 | |||||
| Plant and Regulatory Study Costs | 25 | 32 | Through December 2021 | (2) | ||||
| Regulatory Restructuring Costs | 26 | 27 | Through July 2007 | (1)(3) | ||||
| Total Regulatory Assets | $ | 4,992 | $ | 5,242 | ||||
| Regulatory Liabilities | ||||||||
|
|
||||||||
| Excess Depreciation Reserve | $ | 171 | $ | 319 | Through July 31, 2003 | (2) | ||
| Non-Utility Generation Transition Charge (NTC) | 27 | 46 | Through August 2004 | (1)(3) | ||||
| SBC | 50 | — | Through August 2004 | (1)(2)(3) | ||||
| Other | 4 | 3 | Various | (1) | ||||
| Total Regulatory Liabilities | $ | 252 | $ | 368 | ||||
| (1) | Recovered/Refunded with interest |
| (2) | Recoverable/Refundable per specific rate order |
| (3) | Recovery/Refunding is pending the
outcome of the current electric base rate or deferral case |
| All
regulatory assets and liabilities are excluded from PSE&G’s rate
base unless otherwise noted. The descriptions below define certain regulatory
items. | |
| Stranded
Costs To Be Recovered: This reflects
deferred costs to be recovered through the securitization transition charge
that was authorized by the BPU. Funds collected through the securitization
transition charge will be used to make the future interest and principal
payments on the transition bonds. | |
| Deferred
Income Taxes: This amount represents
the portion of deferred income taxes that will be recovered through future
rates, based upon established regulatory practices, which permit the recovery
of current taxes. Accordingly, this regulatory asset is offset by a deferred
tax liability and is expected to be recovered, without interest, over the
period the underlying book-tax timing differences reverse and become current
taxes. | |
137 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
OPEB-Related Costs: Includes costs associated with the adoption of SFAS No. 106. “Employers’ Accounting for Benefits Other Than Pensions” which were deferred in accordance with EITF Issue 92-12, “Accounting for OPEB Costs by Rate Regulated Enterprises.”
SBC: The SBC, as authorized by the BPU and the Energy Competition Act, includes costs related to PSE&G’s electric and gas business as follows: 1) the universal service fund; 2) nuclear plant decommissioning; 3) demand side management (DSM) programs; 4) social programs which include consumer education; 5) electric bad debt expenses; and 6) MTC overrecovery. All components except for MTC accrue interest.
Manufactured Gas Plant Remediation Costs: Represents a three-year estimate of the environmental investigation and remediation program costs that are probable of recovery in future rates.
Unamortized Loss on Reacquired Debt and Debt Expense: Represents bond issuance costs, premiums, discounts and losses on reacquired long-term debt.
Underrecovered Gas Costs: Represents PSE&G’s gas costs in excess of the amount included in rates and probable of recovery in the future. The current portion of the balance does not accrue interest.
NTC: This clause was established by the Energy Competition Act to account for above market costs related to non-utility generation (NUG) contracts, as approved by the BPU. Costs or benefits associated with the restructuring of these contracts are deferred. This clause also includes BGS costs in excess of current rates, as approved by the BPU.
Unrealized Losses on Gas Contracts: This represents the recoverable portion of unrealized losses associated with contracts used in PSE&G’s gas distribution business.
Unrealized Losses on Interest Rate Swap: This represents the costs related to Transition Funding’s interest rate swap that will be recovered without interest over the life of Transition Funding’s transition bonds. This asset is offset by a derivative liability on the balance sheet.
Repair Allowance Taxes: This represents tax, interest and carrying charges relating to disallowed tax deductions for repair allowance as authorized by the BPU.
Decontamination and Decommissioning Costs: These costs are related to PSE&G’s portion of the obligation for nuclear decontamination and decommissioning costs of US Department of Energy nuclear sites dating back prior to the generation asset transfer to Power in 2000.
Plant and Regulatory Study Costs: These are costs incurred by PSE&G required by the BPU related to current and future operations, including safety, planning, management and construction.
Regulatory Restructuring Costs: These are costs related to the restructuring of the energy industry in New Jersey through the Energy Competition Act and include such items as the system design work necessary to transition PSE&G to a transmission and distribution only company, as well as costs incurred to transfer and establish the generation function as a separate corporate entity.
Excess Depreciation Reserve: As required by the BPU, PSE&G reduced its depreciation reserve for its electric distribution assets and recorded such amount as a regulatory liability.
Other Regulatory Liabilities: This includes the following: 1) amounts collected from customers in order for Transition Funding to obtain a AAA rating on its transition bonds; and 2) amounts available to fund consumer education discounts.
138
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 8. Long-Term Investments
| December 31, | ||||||
| 2002 | 2001 | |||||
| Energy Holdings: | (Millions) | |||||
| Leveraged Leases | $ | 2,844 | $ | 2,784 | ||
| Partnerships: | ||||||
| General Partnerships | 43 | 44 | ||||
| Limited Partnerships | 441 | 615 | ||||
| Total Partnerships | 484 | 659 | ||||
| Corporate Joint Ventures | 1,004 | 1,115 | ||||
| Securities | 6 | 6 | ||||
| Other Investments (A) | 32 | 50 | ||||
| Total Long-Term Investments of Energy Holdings | 4,370 | 4,614 | ||||
| PSE&G (B) | 123 | 112 | ||||
| Power (C) | 78 | 36 | ||||
| Other Investments (D) | 10 | 6 | ||||
| Total Long-Term Investments | $ | 4,581 | $ | 4,768 | ||
| (A) | Primarily relates to Demand Side Management (DSM) investments at Resources. | |
| (B) | Primarily relates to life insurance and supplemental benefits of $113 million and $102 million as of December 31, 2002 and 2001 respectively. | |
| (C) | Amounts represent Sulfur Dioxide (SO2) and Nitrogen Oxide (NOx)emission credits held for future use. | |
| (D) | Amounts represent investments at
PSEG (parent company). | |
| Energy Holdings | ||
| Leveraged
Leases |
||
| Energy
Holdings’ net investment, through Resources, in leveraged leases is
comprised of the following elements: | ||
| December 31, | |||||||
| 2002 | 2001 | ||||||
| (Millions) | |||||||
| Lease rents receivable | $ | 3,429 | $ | 3,644 | |||
| Estimated residual value of leased assets | 1,414 | 1,414 | |||||
| 4,843 | 5,058 | ||||||
| Unearned and deferred income | (1,999 | ) | (2,274 | ) | |||
| Total investments in leveraged leases | 2,844 | 2,784 | |||||
| Deferred taxes | (1,325 | ) | (1,175 | ) | |||
| Net investment in leveraged leases | $ | 1,519 | $ | 1,609 | |||
Resources’ pre-tax income and income tax effects related to investments in leveraged leases are as follows:
| Years Ended December 31, | |||||||||
| 2002 | 2001 | 2000 | |||||||
| (Millions) | |||||||||
| Pre-tax income | $ | 251 | $ | 206 | $ | 163 | |||
| Income tax effect on pre-tax income | $ | 92 | $ | 62 | $ | 58 | |||
| Amortization of investment tax credits | $ | (1 | ) | $(1 | ) | $ | (1 | ) | |
139
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Resources’ initial investment in leveraged leases represents approximately 15% to 20% of the purchase price of the leveraged leased property. The balance is provided by third-party financing in the form of non-recourse long-term debt which is secured by the property.
In 2002, Resources invested $31 million in a leveraged lease financing of a district heating network leased to Linz Gas/Warme GmbH, a district heating utility providing service to the residents of Linz, Austria, and the surrounding area.
In November 2002, Resources terminated its two lease transactions with affiliates of TXU-Europe, the Peterborough and Kings Lynn facilities due to an uncured default under the lease financial covenants. Resources received cash proceeds of $183 million, recognizing an after-tax gain of $4 million. As a result of these lease terminations, Resources will pay income taxes of $115 million in 2003.
In 2001, Resources negotiated the early termination of nine leveraged leases and received cash proceeds of $104 million, recognizing an after-tax gain of $10 million. As a result of these lease terminations, Resources paid income taxes of $87 million in 2002.
In 2000, Resources negotiated the early termination of four leveraged leases and received cash proceeds of $89 million, recognizing an after-tax gain of $24 million. As a result of these lease terminations, Resources paid income taxes of $24 million in 2001.
Partnership Investments and Corporate Joint Ventures
Energy Holdings’ partnership investments of $484 million and corporate joint ventures of approximately $1 billion are those of Resources, Global and EGDC.
Investments in and Advances to Affiliates
Investments in net assets of affiliated companies accounted for under the equity method of accounting by Global amounted to $1.3 billion and $1.5 billion at December 31, 2002 and December 31, 2001, respectively. During the three years ended December 31, 2002, 2001 and 2000, the amount of dividends from these investments was $64 million, $51 million, and $107 million respectively. Global’s share of income and cash flow distribution percentages currently range from 16% to 50%. Interest is earned on loans made to various projects. Such loans earned rates of interest ranging from 7.5% to 20% during 2002 and 2001.
140
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Summarized results of operations and financial position of all affiliates in which Global uses the equity method of accounting are presented below:
| Foreign | Domestic | Total | |||||||
| (Millions) | |||||||||
| For the Year Ended December 31, 2002 | |||||||||
| |
|||||||||
| Condensed Statement of Operations Information | |||||||||
| Revenue | $ | 1,125 | $ | 492 | $ | 1,617 | |||
| Gross Profit | $ | 413 | $ | 149 | 562 | ||||
| Minority Interest | $ | (10 | ) | $ | — | $ | (10 | ) | |
| Net Income | $ | 148 | $ | 6 | $ | 154 | |||
| As of December 31, 2002 | |||||||||
| |
|||||||||
| Condensed Balance Sheet Information | |||||||||
| Assets: | |||||||||
| Current Assets | $ | 494 | $ | 110 | $ | 604 | |||
| Property, Plant and Equipment | 1,597 | 1,193 | 2,790 | ||||||
| Goodwill | 586 | 50 | 636 | ||||||
| Other Noncurrent Assets | 489 | 24 | 513 | ||||||
| Total Assets | $ | 3,166 | $ | 1,377 | $ | 4,543 | |||
| Liabilities: | |||||||||
| Current Liabilities | $ | 464 | $ | 56 | $ | 520 | |||
| Debt* | 868 | 641 | 1,509 | ||||||
| Other Noncurrent Liabilities | 183 | 72 | 255 | ||||||
| Minority Interest | — | 43 | 43 | ||||||
| Total Liabilities | 1,558 | 769 | 2,327 | ||||||
| Equity | 1,608 | 608 | 2,216 | ||||||
| Total Liabilities and Equity | $ | 3,166 | $ | 1,377 | $ | 4,543 | |||
| Foreign | Domestic | Total | |||||||
| (Millions) | |||||||||
| For the Year Ended December 31, 2001 | |||||||||
| Condensed Statement of Operations Information | |||||||||
| Revenue | $ | 1,099 | $ | 473 | $ | 1,572 | |||
| Gross Profit | $ | 416 | $ | 165 | $ | 581 | |||
| Minority Interest | $ | (20 | ) | $ | — | $ | (20 | ) | |
| Net Income | $ | 180 | $ | 91 | $ | 271 | |||
| As of December 31, 2001 | |||||||||
| Condensed Balance Sheet Information | |||||||||
| Assets: | |||||||||
| Current Assets | $ | 366 | $ | 131 | $ | 497 | |||
| Property, Plant and Equipment | 1,625 | 1,406 | 3,031 | ||||||
| Goodwill | 863 | 50 | 913 | ||||||
| Other Noncurrent Assets | 481 | 23 | 504 | ||||||
| Total Assets | $ | 3,335 | $ | 1,610 | $ | 4,945 | |||
| Liabilities: | |||||||||
| Current Liabilities | $ | 487 | $ | 109 | $ | 596 | |||
| Debt* | 802 | 658 | 1,460 | ||||||
| Other Noncurrent Liabilities | 245 | 212 | 457 | ||||||
| Minority Interest | 25 | — | 25 | ||||||
| Total Liabilities | 1,559 | 979 | 2,538 | ||||||
| Equity | 1,776 | 631 | 2,407 | ||||||
| Total Liabilities and Equity | $ | 3,335 | $ | 1,610 | $ | 4,945 | |||
141
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
| Foreign | Domestic | Total | |||||||
| (Millions) | |||||||||
| For the Year Ended December 31, 2000 | |||||||||
| |
|||||||||
| Condensed Statement of Operations Information | |||||||||
| Revenue | $ | 1,334 | $ | 452 | $ | 1,786 | |||
| Gross Profit | $ | 532 | $ | 256 | $ | 788 | |||
| Minority Interest | $ | (24 | ) | $ | — | $ | (24 | ) | |
| Net Income | $ | 190 | $ | 162 | $ | 352 | |||
* Debt is non-recourse to PSEG, Energy Holdings and Global
Other Investments
Resources also has limited partnership investments in two leveraged buyout funds, a collateralized bond obligation structure, a clean air facility and solar electric generating systems. Resources’ total investment in limited partnerships was $118 million, and $163 million as of December 31, 2002 and 2001, respectively.
Included in the limited partnership amounts above are interests in two leveraged buyout funds that hold publicly traded securities, which are managed by KKR Associates L.P., (KKR). The book value of the investment in the leveraged buyout funds was $93 million and $130 million as of December 31, 2002 and December 31, 2001, respectively. The largest single investment in the funds held indirectly by Resources is the investment in approximately 16,847,000 shares of common stock of Borden, Inc., having a book value of $48 million and $81 million as of December 31, 2002 and 2001, respectively.
Resources applies fair value accounting to investments in the funds where publicly traded market prices are available as described in Note 1. Organization and Summary of Significant Accounting Policies. Approximately $24 million and $34 million represent the fair value of Resources’ share of the publicly traded securities in the funds as of December 31, 2002 and 2001, respectively. For a discussion of other than temporary impairments of non-publicly traded equity securities within certain leveraged buyout funds at Resources, see Note 12. Risk Management.
During January and February 2001, KKR sold its interest in FleetBoston Financial Corporation. Resources received cash proceeds of $35 million and recorded a $4 million pre-tax gain as a result of this transaction. In August 2001, KKR sold its interest in Gillette Corporation. Resources received cash proceeds of $30 million from the sale, which had a book value of $31 million.
142
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 9. Purchase Business Combinations/Asset Acquisitions
Power
On December 6, 2002, Power purchased Wisvest Connecticut LLC, which owns the Bridgeport Harbor Station (BHS), the New Haven Harbor Station (NHHS) and the related assets and liabilities, from Wisvest Corporation (Wisvest), a subsidiary of Wisconsin Energy Corporation. The name of Wisvest Connecticut LLC was subsequently changed to PSEG Power Connecticut LLC.
The aggregate purchase price was approximately $272 million, which consisted of approximately $269 million of cash paid to Wisvest and approximately $3 million of direct acquisition costs necessary to conduct the transaction, which were paid to third parties.
Power has not finalized the allocation of the purchase price as of December 31, 2002. As shown in the table below, an estimation of this allocation was prepared and recorded as of December 6, 2002. Power Connecticut’s results of operations were reflected in the Consolidated Statements of Operations from December 6, 2002 through December 31, 2002.
| As of December 6, 2002 | ||||
| | ||||
| (Millions) | ||||
| Current Assets | $ | 26 | ||
| Property, Plant and Equipment | 237 | |||
| Intangible Assets | 44 | |||
| Total Assets Acquired | 307 | |||
| Current Liabilities | 16 | |||
| Noncurrent Liabilities | 19 | |||
| Total Liabilities Assumed | 35 | |||
| Net Assets Acquired | $ | 272 | ||
Approximately $42 million of the intangible assets consisted of SO2 allowances, which can be sold on the open market or used to offset plant emissions. These allowances have an indefinite life.
Energy Holdings
In June 2002, Global completed a 35% acquisition of the 590MW (electric) and 618 MW (thermal) coal-fired Skawina CHP Plant (Skawina), located in Poland, and purchased an additional approximate 15%, increasing its ownership to approximately 50%. The purchase price of this ownership interest was $31 million and was allocated $18 million to Current Assets, $51 million to Property, Plant and Equipment, $14 million to Current Liabilities, $9 million to Noncurrent Liabilities and $15 million to minority interest.
During the fourth quarter of 2002, Global increased its interest in GWF Energy LLC (GWF Energy), which includes three new gas-fired peaking plants located in California, to 76%. The partnership agreement stipulates that the condition for control is indicated at 75% or greater ownership interest of the voting stock. Global’s investment in GWF Energy was recorded in accordance with the equity method of accounting as of September 30, 2002. Global’s investment in GWF Energy is recorded as a consolidated entity as of December 31, 2002 and for the three months ended December 31, 2002. The partner in this investment, Harbinger GWF LLC, has the right to buy back from Global up to one-half of the reduction of its equity ownership in GWF Energy from the 50% ownership level. This right terminates at the earlier of project financing or September 30, 2003.
143
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 10. Schedule of Consolidated Capital Stock and Other Securities
| Outstanding Shares At December 31, 2002 |
Current Redemption Price Per Share |
December
31, 2002 |
December
31, 2001 | ||||||||
| (Millions) | |||||||||||
| PSEG Common Stock (no par) (A) | |||||||||||
| Authorized 500,000,000 shares; issued and outstanding (at | |||||||||||
| December 31, 2001, 205,839,018 shares) | 225,267,347 | $ | 3,075 | $ | 2,618 | ||||||
| PSEG Preferred Securities (B) | |||||||||||
| PSEG Quarterly Guaranteed Preferred Beneficial Interest in | |||||||||||
| PSEG’s Subordinated Debentures (D) (F) | |||||||||||
| 7.44% | 9,000,000 | — | $ | 225 | $ | 225 | |||||
| Floating Rate (LIBOR + 1.22%) | 150,000 | — | 150 | 150 | |||||||
| 7.25% | 6,000,000 | — | 150 | 150 | |||||||
| 8.75% (F) | 7,200,000 | — | 180 | — | |||||||
| Total Quarterly Guaranteed Preferred Beneficial Interest in | |||||||||||
| PSEG’s Subordinated Debentures | $ | 705 | $ | 525 | |||||||
| PSEG Participating Units | |||||||||||
| 10.25% (G) | 9,200,000 | — | $ | 460 | $ | — | |||||
| PSE&G Preferred Securities | |||||||||||
| PSE&G Cumulative Preferred Stock (C) without Mandatory | |||||||||||
| Redemption (D) $100 par value series | |||||||||||
| 4.08% | 146,221 | 103.00 | $ | 15 | $ | 15 | |||||
| 4.18% | 116,958 | 103.00 | 12 | 12 | |||||||
| 4.30% | 149,478 | 102.75 | 15 | 15 | |||||||
| 5.05% | 104,002 | 103.00 | 10 | 10 | |||||||
| 5.28% | 117,864 | 103.00 | 12 | 12 | |||||||
| 6.92% | 160,711 | — | 16 | 16 | |||||||
| Total Preferred Stock without Mandatory Redemption | $ | 80 | $ | 80 | |||||||
| PSE&G 8.00% Monthly Guaranteed Preferred Beneficial | |||||||||||
| Interest in Subordinated Debentures (D)(E) | 2,400,000 | 25.00 | $ | 60 | $ | 60 | |||||
| PSE&G 8.125% Quarterly Guaranteed Preferred Beneficial Interest in | |||||||||||
| PSE&G’s Subordinated Debentures (D)(E) | 3,800,000 | — | $ | 95 | $ | 95 | |||||
| (A) | In 1999, PSEG’s Board of Directors
authorized the repurchase of up to 30 million shares of its common stock
in the open market. As of December 31, 2001, PSEG repurchased approximately
26.5 million shares of common stock at a cost of approximately $997 million.
No shares were repurchased in 2002. The repurchased shares have been held
as treasury stock or used for other corporate purposes. |
| In November 2002, PSEG issued 17.25
million shares of common stock for approximately $458 million, with net
proceeds of $443 million. In addition, in 2002, PSEG began issuing new shares
under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) and the
Employee Stock Purchase Plan (ESPP), rather than purchasing them on the
open market. For the year ended December 31, 2002, PSEG issued approximately
2.2 million shares for approximately $78 million under these plans. Total
authorized and unissued shares of common stock available for issuance through
PSEG’s DRASPP, ESPP and various employee benefit plans amounted to
5,663,081. | |
| (B) | PSEG has authorized a class of
50,000,000 shares of Preferred Stock without par value, none of which is
outstanding. |
| 144 | |
| NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS — Continued | |
| (C) | At December 31, 2002, there were
an aggregate of 6,704,766 shares of $100 par value and 10,000,000 shares
of $25 par value Cumulative Preferred Stock which were authorized and unissued
and which, upon issuance, may or may not provide for mandatory sinking fund
redemption. If dividends upon any shares of Preferred Stock are in arrears
in an amount equal to the annual dividend thereon, voting rights for the
election of a majority of PSE&G’s Board of Directors become operative
and continue until all accumulated and unpaid dividends thereon have been
paid, whereupon all such voting rights cease, subject to being revived from
time to time. |
| There are no arrearages in cumulative preferred stock and no
voting rights for preferred shares. No preferred stock agreement contains any liquidation preferences
in excess of par or stated values or any “deemed” liquidation events. | |
| (D) | At December 31, 2002 and 2001,
the annual dividend requirement of PSEG’s Trust Preferred Securities
(Guaranteed Preferred Beneficial Interest in PSEG’s Subordinated Debentures)
including those issued in connection with the Participating Units and their
embedded costs was $101,330,00 and 5.99% and $38,433,000 and 4.91%, respectively. |
|
At December 31, 2002 and 2001,
the annual dividend requirement and embedded dividend rate for PSE&G’s
Preferred Stock without mandatory redemption was $3,987,867 and 5.03%, $10,127,383
and 5.03%, respectively. | |
| At December 31, 2002 and 2001,
the annual dividend requirement and embedded cost of the Monthly Income
Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G’s
Subordinated Debentures) was $4,800,000 and 4.90%, $7,768,750 and 4.90%,
respectively. | |
| At December 31, 2002 and 2001,
the annual dividend requirement of the Quarterly Income Preferred Securities
(Guaranteed Preferred Beneficial Interest in PSE&G’s Subordinated
Debentures) and their embedded costs were $7,718,750 and 4.97%, $16,439,584
and 4.97%, respectively. | |
| (E) | PSE&G Capital L.P., PSE&G
Capital Trust I and PSE&G Capital Trust II were formed and are controlled
by PSE&G for the purpose of issuing Monthly and Quarterly Income Preferred
Securities (Monthly and Quarterly Guaranteed Preferred Beneficial Interest
in PSE&G’s Subordinated Debentures). The proceeds were loaned to
PSE&G and are evidenced by PSE&G’s Deferrable Interest Subordinated
Debentures. If and for as long as payments on PSE&G’s Deferrable
Interest Subordinated Debentures have been deferred, or PSE&G has defaulted
on the indentures related thereto or its guarantees thereof, PSE&G may
not pay any dividends on its common and preferred stock. The Subordinated
Debentures and the indentures constitute a full and unconditional guarantee
by PSE&G of the Preferred Securities issued by the partnership and the
trusts. |
| (F) | Enterprise Capital Trust I, Enterprise
Capital Trust II, Enterprise Capital Trust III, Enterprise Capital Trust
IV and PSEG Funding Trust II were formed and are controlled by PSEG for
the purpose of issuing Quarterly Trust Preferred Securities (Quarterly Guaranteed
Preferred Beneficial Interest in PSEG’s Subordinated Debentures). The
proceeds were loaned to PSEG and are evidenced by Deferrable Interest Subordinated
Debentures. If and for as long as payments on the Deferrable Interest Subordinated
Debentures have been deferred, or PSEG had defaulted on the indentures related
thereto or its guarantees thereof, PSEG may not pay any dividends on its
common and preferred stock. The Subordinated Debentures constitute PSEG’s
full and unconditional guarantee of the Preferred Securities issued by the
trusts. |
| In December 2002, PSEG Funding Trust II issued $180 million of 8.75% Trust Preferred Securities. | |
| (G) | In September 2002, PSEG Funding
Trust I issued 9.2 million Participating Units with a stated amount of $50
per unit. Each unit consists of a 6.25% trust preferred security due 2007
having a liquidation value of $50, and a stock purchase contract obligating
the purchasers to purchase shares of PSEG common stock in an amount equal
to $50 on November 16, 2005. In exchange for the obligations under the purchase
contract, the purchasers will receive quarterly contract adjustment payments
at the annual rate of 4.00% until such date. The number of new shares issued
on November 16, 2005 will depend upon the average closing price per share
of PSEG common stock for the 20 consecutive trading days ending the third
trading day immediately preceding November 16, 2005. Based on the formula
described in the purchase contract, at that time PSEG |
145 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
| will issue between 11,429,139 and 13,714,967
shares of its common stock. The net proceeds from the sale of the Participating
Units was $446.2 million. In connection with the issuance of the Participating Units,
PSEG recorded a $54 million reduction to equity associated with the stock purchase
contracts. | |
| PSEG applies SFAS No. 128, “Earnings Per
Share”, specifically the treasury stock method, when accounting for
the forward purchase contract associated with these participating units.
If PSEG’s common stock price were to exceed $40.25 per share, shares
would be added to the diluted earnings per share calculation. For additional
information, see Note 18. Stock Options and Employee Stock Purchase Plan. |
Fair Value of Preferred Securities
The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of December 31, 2002 and 2001, respectively.
| As
of December 31, 2002 |
As
of December 31, 2001 | ||||||||||||||
| |
|||||||||||||||
| Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
||||||||||||
| (Millions) | |||||||||||||||
| PSE&G Cumulative Preferred Stock | $ | 80 | $ | 59 | $ | 80 | $ | 66 | |||||||
| Monthly Guaranteed Preferred Beneficial Interest in | |||||||||||||||
| PSE&G’s Subordinated Debentures | 60 | 62 | 60 | 60 | |||||||||||
| Quarterly Guaranteed Preferred Beneficial Interest in | |||||||||||||||
| PSE&G’s Subordinated Debentures | 95 | 97 | 95 | 96 | |||||||||||
| Quarterly Guaranteed Preferred Beneficial Interest in | |||||||||||||||
| PSEG’s Subordinated Debentures | 705 | 673 | 525 | 520 | |||||||||||
| Participating Units in | |||||||||||||||
| PSEG’s Subordinated Debentures | 460 | 459 | — | — | |||||||||||
146
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 11. Schedule of Consolidated Debt
Long-Term Debt
| December 31, | ||||||||
| Maturity | 2002 | 2001 | ||||||
| PSEG | (Millions) | |||||||
| |
||||||||
| Senior Note-6.89% (A) | 2009 | $ | 245 | $ | — | |||
| Floating Rate Notes-LIBOR plus 0.875% | 2002 | — | 275 | |||||
| Other | 3 | — | ||||||
| Principal Amount Outstanding | 248 | 275 | ||||||
| Amounts Due Within One Year (B) | — | (275 | ) | |||||
| Total Long-Term Debt of PSEG (Parent) | 248 | $ | — | |||||
| PSE&G | ||||||||
| |
||||||||
| First and Refunding Mortgage Bonds: | ||||||||
| 6.125% | 2002 | $ | — | $ | 258 | |||
| 6.875%-8.875% | 2003 | 300 | 300 | |||||
| 6.50% | 2004 | 286 | 286 | |||||
| 9.125% | 2005 | 125 | 125 | |||||
| 6.75% | 2006 | 147 | 147 | |||||
| 6.25% | 2007 | 113 | 113 | |||||
| 6.75%–7.375% | 2013-2017 | 330 | 330 | |||||
| 6.45%–9.25% | 2018-2022 | 139 | 139 | |||||
| 5.20%–7.50% | 2023-2027 | 434 | 434 | |||||
| 5.45%–6.55% | 2028-2032 | 499 | 499 | |||||
| 5.00%–8.00% | 2033-2037 | 160 | 160 | |||||
| Medium-Term Notes: | ||||||||
| 5.125% (C) | 2012 | 300 | — | |||||
| 7.19% | 2002 | — | 290 | |||||
| 8.10%–8.16% | 2008-2012 | 60 | 60 | |||||
| 7.04% | 2018-2022 | 9 | 9 | |||||
| 7.15%–7.18% | 2023-2027 | 39 | 39 | |||||
| Principal Amount Outstanding | 2,941 | 3,189 | ||||||
| Amounts Due Within One Year (B) | (300 | ) | (547 | ) | ||||
| Net Unamortized Discount | (14 | ) | (16 | ) | ||||
| Total Long-Term Debt of PSE&G (Parent) | $ | 2,627 | $ | 2,626 | ||||
147
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
| December 31, | ||||||||
| Maturity | 2002 | 2001 | ||||||
| Transition Funding (PSE&G) | (Millions) | |||||||
| |
||||||||
| Securitization Bonds: | ||||||||
| 5.46% | 2004 | $ | — | $ | 52 | |||
| 5.74% | 2007 | 300 | 369 | |||||
| 5.98% | 2008 | 183 | 183 | |||||
| LIBOR plus 0.30% | 2011 | 496 | 496 | |||||
| 6.45% | 2013 | 328 | 328 | |||||
| 6.61% | 2015 | 454 | 454 | |||||
| 6.75% | 2016 | 220 | 220 | |||||
| 6.89% | 2017 | 370 | 370 | |||||
| Principal Amount Outstanding | 2,351 | 2,472 | ||||||
| Amounts Due Within One Year (B) | (129 | ) | (121 | ) | ||||
| Total Securitization Debt of Transition Funding | $ | 2,222 | $ | 2,351 | ||||
| Total PSE&G | $ | 4,849 | $ | 4,977 | ||||
| Power | ||||||||
| |
||||||||
| Senior Notes: | ||||||||
| 6.88% | 2006 | $ | 500 | $ | 500 | |||
| 6.95% (D) | 2012 | 600 | — | |||||
| 7.75% | 2011 | 800 | 800 | |||||
| 8.63% | 2031 | 500 | 500 | |||||
| Total Senior Notes | 2,400 | $ | 1,800 | |||||
| Pollution Control Notes: | ||||||||
| 5.00% | 2012 | $ | 66 | $ | 66 | |||
| 5.50% | 2020 | 14 | 14 | |||||
| 5.85% | 2027 | 19 | 19 | |||||
| 5.75% | 2031 | 25 | 25 | |||||
| Total Pollution Control Notes | $ | 124 | $ | 124 | ||||
| Non-recourse debt : | ||||||||
| Variable (3.00% to 5.00%) | 2005 | $ | 800 | $ | 770 | |||
| Principal Amount Outstanding | 3,324 | 2,694 | ||||||
| Amounts Due Within One Year (B) | — | — | ||||||
| Net Unamortized Discount | (8 | ) | (9 | ) | ||||
| Total Long-Term Debt of Power | $ | 3,316 | $ | 2,685 | ||||
148
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
| December 31, | ||||||||
| Maturity | 2002 | 2001 | ||||||
| Energy Holdings | (Millions) | |||||||
| |
||||||||
| Senior Notes: | ||||||||
| 9.125% (E) | 2004 | $ | 279 | $ | 300 | |||
| 8.625% (E)(F) | 2008 | 507 | 400 | |||||
| 10.00% | 2009 | 400 | 400 | |||||
| 8.50%(E) | 2011 | 544 | 550 | |||||
| Principal Amount Outstanding | 1,730 | 1,650 | ||||||
| Net Unamortized Discount | (5 | ) | (6 | ) | ||||
| Total Long-Term Debt of Energy Holdings (Parent) | $ | 1,725 | $ | 1,644 | ||||
| PSEG Capital (Energy Holdings) | ||||||||
| |
||||||||
| Medium-Term Notes: | ||||||||
| 3.12% – 7.72% | 2002 | $ | — | $ | 228 | |||
| 6.25% | 2003 | 252 | 252 | |||||
| Principal Amount Outstanding | 252 | 480 | ||||||
| Amounts Due Within One Year (B) | (252 | ) | (228 | ) | ||||
| Total Long-Term Debt of PSEG Capital | $ | — | $ | 252 | ||||
| Global (Energy Holdings) | ||||||||
| |
||||||||
| Non-recourse Debt: | ||||||||
| 5.47% – 10.385% | 2002 | $ | — | $ | 14 | |||
| 5.19% – 6.96% | 2003 | 67 | 38 | |||||
| 5.19% – 13.22% | 2004-2019 |
832 | 564 | |||||
| 14.00% – Minority Shareholder Loan | 2027 | — | 10 | |||||
| Principal Amount Outstanding | 899 | 626 | ||||||
| Amounts Due Within One Year (B) | (67 | ) | (14 | ) | ||||
| Total Long-Term Debt of Global | $ | 832 | $ | 612 | ||||
| Resources (Energy Holdings) | ||||||||
| |
||||||||
| 8.60% – Bank Loan | 2001-2020 | $ | 22 | $ | 23 | |||
| Principal Amount Outstanding | 22 | 23 | ||||||
| Amounts Due Within One Year (B) | (1 | ) | (1 | ) | ||||
| Total Long-Term Debt of Resources | 21 | 22 | ||||||
| Total Long-Term Debt of Energy Holdings | $ | 2,578 | $ | 2,530 | ||||
| Total PSEG Consolidated Long-Term Debt | 10,991 | $ | 10,192 | |||||
149
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS — Continued | |
| (A) | In October 2002, PSEG closed on
a $245 million private placement debt transaction with a five-year average
life, with the proceeds being used to reduce short-term debt. |
| (B) | The aggregate principal amounts
of mandatory requirements for sinking funds and maturities for each of the
five years following December 31, 2002 are as follows: |
| PSE&G | Energy Holdings | |||||||||||||||||||||||||||
| Year | PSEG | PSE&G | Transition Funding |
PSEG Power |
Energy Holdings |
PSEG Capital |
Global | Resources | Total | |||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||
| 2003 | $ | — | $ | 300 | $ | — | $ | — | $ | — | $ | 252 | $ | 67 | $ | 1 | $ | 620 | ||||||||||
| 2004 | — | 286 | — | — | 276 | — | 41 | 1 | 604 | |||||||||||||||||||
| 2005 | — | 125 | — | 800 | — | — | 47 | 1 | 973 | |||||||||||||||||||
| 2006 | — | 147 | — | 500 | — | — | 52 | 1 | 700 | |||||||||||||||||||
| 2007 | — | 113 | 300 | — | — | — | 52 | 1 | 466 | |||||||||||||||||||
| $ | — | $ | 971 | $ | 300 | $ | 1,300 | $ | 276 | $ | 252 | $ | 259 | $ | 5 | $ | 3,363 | |||||||||||
| (C) | In September 2002, PSE&G issued
$300 million of 5.125% Medium-Term Notes due 2012, the proceeds of which
were used to repay $290 million of 7.19% Medium-Term Notes that matured. | |
| (D) | In June 2002, Power issued $600
million of 6.95% Senior Unsecured Notes due 2012. The proceeds were used
to repay short-term funding from PSEG, including amounts related to the
Gas Contract Transfer from PSE&G in May 2002. | |
| (E) | In 2002, Energy Holdings repurchased
a combined total of $54 million of Senior Notes. | |
| (F) | In 2002, Energy Holdings, in a
private placement, sold $135 million of 8.625% Senior Notes due in 2008
and subsequently completed an exchange offer for these Senior Notes. | |
| Short-Term Liquidity | ||
| PSEG | ||
| In
order to support its short-term financing requirements, as well as those
of Power and Services, PSEG has revolving credit facilities that are used
both as a source of short-term funding and to provide backup liquidity for
its $1 billion commercial paper program. | ||
| PSE&G | ||
| PSE&G
maintains credit facilities to backup its $400 million commercial paper
program. | ||
| Power | ||
| Power
has a $50 million credit facility, but primarily relies on PSEG for its short-term
financing needs. | ||
| Energy
Holdings | ||
| Energy
Holdings has credit facilities that are used both as a source of short-term
funding and to issue letters of credit. | ||
| 150 | ||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
PSEG, PSE&G, Power and Energy Holdings
As of December 31, 2002, PSEG had a total of approximately $2.5 billion of committed credit facilities, with approximately $600 million drawn against such facilities resulting in $1.9 billion in available liquidity. In addition to this amount, PSEG had access to certain uncommitted credit facilities. The following table summarizes the various revolving credit facilities of PSEG and its subsidiaries and the liquidity available as of December 31, 2002.
| Company | Expiration Date |
Total Facility |
Primary Purpose |
Usage at 12/31/02 |
Available Liquidity at 12/31/02 |
|||||||||
| |
||||||||||||||
| (Millions) | ||||||||||||||
| PSEG: | ||||||||||||||
| |
||||||||||||||
| 364-day Credit Facility | March 2003 | $ | 620 | CP Support | $ | 300 | $ | 320 | ||||||
| 364-day Bilateral | ||||||||||||||
| Facility | March 2003 | $ | 75 | CP Support | $ | — | 75 | |||||||
| 5-year Credit Facility | March 2005 | $ | 280 | CP Support | $ | — | $ | 280 | ||||||
| 3-year Credit Facility | December 2005 | $ | 350 | CP Support /Funding |
$ | — | $ | 350 | ||||||
| Uncommitted Bilateral | ||||||||||||||
| Agreement | N/A | * | Funding | $ | 101 | N/A | ||||||||
| PSE&G: | ||||||||||||||
| |
||||||||||||||
| 364-day Credit Facility | June 2003 | $ | 200 | CP Support | $ | 183 | $ | 17 | ||||||
| 3-year Credit Facility | June 2005 | $ | 200 | CP Support | $ | — | $ | 200 | ||||||
| Uncommitted Bilateral | ||||||||||||||
| Agreement | N/A | * | Funding | $ | 41 | N/A | ||||||||
| Energy Holdings: | ||||||||||||||
| |
||||||||||||||
| 364-day Credit Facility | May 2003 | $ | 200 | Funding | $ | — | $ | 200 | ||||||
| 5-year Credit Facility | May 2004 | $ | 495 | Funding | $ | 74 | $ | 421 | ||||||
| Uncommitted Bilateral | ||||||||||||||
| Agreement | N/A | * | Funding | $ | — | N/A | ||||||||
| Power: | ||||||||||||||
| |
||||||||||||||
| 3-year Credit Facility | August 2005 | $ | 50 | Funding | $ | 6 | $ | 44 | ||||||
* Availability varies based on market conditions.
As of December 31, 2002, PSEG’s consolidated total short-term debt outstanding was $762 million, including $300 million of commercial paper and $101 million in loans outstanding under PSEG’s uncommitted bilateral agreement, $183 million in commercial paper and $41 million in loans outstanding under PSE&G’s uncommitted bilateral agreement and $137 million of non-recourse short-term financing at Global with various rates, primarily consisting of amounts related to its investment in Electroandes.
In addition, as shown in the above table, there was $74 million and $6 million outstanding in letters of credit under the credit facilities of Energy Holdings and Power, respectively.
151
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Fair Value of Debt
The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of December 31, 2002 and December 31, 2001, respectively.
| December 31, 2002 | December 31, 2001 | ||||||||
| Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
||||||
| (Millions) | |||||||||
| Long-Term Debt: | |||||||||
| PSEG | $ | 248 | $ 249 | $ 275 | $ 275 | ||||
| Energy Holdings | $ | 2,898 | $2,730 | $2,773 | $2,834 | ||||
| PSE&G | $ | 2,927 | $3,211 | $3,173 | $3,290 | ||||
| Transition Funding (PSE&G) | $ | 2,351 | $2,543 | $2,472 | $2,575 | ||||
| Power | $ | 3,316 | $3,372 | $2,685 | $2,835 | ||||
Because their maturities are less than one year, fair values approximate carrying amounts for cash and cash equivalents, short-term debt and accounts payable.
Note 12. Risk Management
PSEG, PSE&G, Power and Energy Holdings
The operations of PSEG, PSE&G, Power, and Energy Holdings are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could affect the results of operations and financial conditions. PSEG manages its exposure to these market risks through its regular operating and financing activities and, when deemed appropriate, hedges these risks through the use of derivative financial instruments. PSEG, PSE&G, Power and Energy Holdings 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. Each of PSEG, PSE&G, Power and Energy Holdings use derivative instruments as risk management tools consistent with its respective business plans and prudent business practices.
Energy Trading Contracts
Power
Power maintains a strategy of entering into trading positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. Power does not engage in the practice of simultaneous trading for the purpose of increasing trading volume or revenue. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy to
152
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
mitigate the effects of adverse movements in the fuel and electricity markets. Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, fixed transmission rights, coal and emission allowances, in the spot, forward and futures markets, primarily in Pennsylvania-New Jersey-Maryland Power Pool (PJM), and electricity in the Super Region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana and natural gas in the producing region, the Henry Hub Basin, as well as the Super Region. These contracts also involve financial transactions including swaps, options and futures.
For the year ended December 31, 2002, Power marked to market its energy trading contracts in accordance with EITF 02-3 and SFAS 133, see Note 1. Organization and Summary of Significant Accounting Policies. As of December 31, 2002 and 2001, substantially all of these contracts had terms of two years or less. Wherever possible, market values for these contracts were obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques were employed using assumptions reflective of current market rates, yield curves and forward prices as applicable. Only one such contract which expires in 2003, is marked to a model and has an effect on earnings. The effects on earnings of the contract that was marked to a model was immaterial.
In prior periods, Power disclosed gains and losses related to certain activities within its trading segment. Commencing with its change in segment reporting discussed in Note 19. Financial Information by Business Segments, Power has excluded certain transactions, such as firm transmission rights and Basic Gas Supply Service (BGSS) results, from this table and solely report gains and losses on transactions accounted for pursuant to EITF 02-3. There was no change in margins, net income or cash flows as a result of this change in presentation. Prior periods have been reclassified to conform to this presentation.
For the years ended December 31, 2002, 2001 and 2000, Power recorded net margins of $47 million, $130 million and $73 million, respectively, as shown below:
| For the Year Ended December 31, | |||||||||
| 2002 | 2001 | 2000 | |||||||
| (Millions) | |||||||||
| Realized Gains | $ | 38 | $ | 163 | $ | 23 | |||
| Unrealized Gains (Losses) | 17 | (26 | ) | 55 | |||||
| Gross Margin | 55 | 137 | 78 | ||||||
| Broker Fees and Other Trading-Related | |||||||||
| Expense | 8 | 7 | 5 | ||||||
| Net Margin | $ | 47 | $ | 130 | $ | 73 | |||
As of December 31, 2002 and 2001, the cumulative unrealized gains related to these energy trading contracts were approximately $24 million and $7 million, respectively. The contracts related to the majority of these gains had terms of less than two years.
Power routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, exchange-traded futures contracts require a 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 Power’s margin deposits as of December 31, 2002 was approximately $9 million.
Derivative Instruments and Hedging Activities
Commodity Contracts
Power
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.
In order to hedge a portion of Power’s forecasted energy purchases to meet its electric supply requirements, Power enters into forward purchase contracts, futures, options and swaps. These contracts, in conjunction with
153
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
owned electric generation capacity, are designed to cover estimated wholesale electric customer commitments. Power has also forecasted the energy delivery from its generating stations based on the forward price curve movement of energy and, as a result, entered into swaps, options and futures transactions to hedge the price of gas to meet its gas purchases requirements for generation. These transactions qualified as cash flow hedges under SFAS 133. As of December 31, 2002 the fair value of these hedges was $5 million. Unrealized gains and losses associated with these hedges of $3 million, net of tax, was charged to OCI for the year ended December 31, 2002. There was no ineffectiveness associated with these hedges. These hedges will mature through 2003.
Also, prior to May 2002, PSE&G had entered into gas forwards, futures, options and swaps to hedge its forecasted requirements for natural gas, which was required under an agreement with the BPU in 2001. Effective with the transfer of PSE&G’s gas contracts to Power on May 1, 2002, Power acquired all of the derivatives entered into by PSE&G. The use of derivatives to hedge the forecasted purchase of natural gas qualifed as a cash flow hedge. Gains or losses from these derivatives is recovered from customers as part of the monthly billing to PSE&G. Derivatives relating to commercial and industrial customers is accounted for in accordance with SFAS 133 where appropriate. Gains or losses on these derivatives are deferred and reported as a component of OCI. There was no ineffectiveness or excluded ineffectiveness realized on these hedges. As of December 31, 2002 Power had gas forwards, futures, options and swaps to hedge forecasted requirements with a fair value of approximately $1.4 million. The maximum term of these contracts is approximately one year. As of December 31, 2001, PSE&G had gas forwards, futures, options and swaps to hedge forecasted requirements with a fair value of approximately $(137) million.
Power also enters into certain other contracts which are derivatives, but do not qualify for hedge accounting under SFAS 133, which was adopted effective January 1, 2001. Most of these contracts are option contracts on gas purchases for generation requirements. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs on the Consolidated Statement of Operations at the end of each reporting period. For the years ended December 31, 2002 and 2001, Power recorded gains on these contracts of $20 million and $12 million, respectively, as shown below:
| For the Year Ended December 31, | |||||||||
| 2002 | 2001 | ||||||||
| (Millions) | |||||||||
| Realized Gains (Losses) | $ | (1 | ) | $ | 23 | ||||
| Unrealized Gains (Losses) | 21 | (11 | ) | ||||||
| Gross Margin | $ | 20 | $ | 12 | |||||
As of December 31, 2002 and 2001, the cumulative unrealized gains and (losses) related to these contracts were approximately $20 million and $(7) million, respectively. The contracts related to the majority of these gains and losses had terms of less than two years.
As of December 31, 2002 and 2001, substantially all of these contracts had terms of two years or less and were valued through market exchanges and, where necessary, broker quotes.
Interest Rates
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt and interest rate derivatives.
The fair value of interest rate swaps, designated and effective as cash flow hedges, are initially recorded in OCI. Reclassification of unrealized gains or losses on cash flow hedges of variable-rate debt instruments from OCI into earnings occurs as interest payments are accrued on the debt instrument and generally offsets the change in the interest accrued on the underlying variable rate debt. In order to test the effectiveness of such swaps, a hypothetical
154
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
swap is used to mirror all the critical terms of the underlying debt and utilize regression analysis to assess the effectiveness of the actual swap at inception and on an ongoing basis. The assessment is done periodically to ensure the swaps continue to be effective. PSEG, PSE&G, Power and Energy Holdings determine the fair value of interest rate swaps through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented. There is minimal impact of counterparty credit risk on the fair value of the hedges since each of PSEG, PSE&G, Power and Energy Holdings’ policies require that its respective counterparties have investment grade credit ratings.
Ineffectiveness may occur if the actual draw down of the debt and the notional amount of the swap during the construction phase are different. The amount of ineffectiveness, if any, is recorded in earnings at the end of the reporting period. The impact of ineffectiveness on net income should be minimal because the interest rate swaps and the underlying debt are indexed to the same benchmark interest rate. Therefore, interest rate fluctuations should be offset.
The table below displays fair value, ineffectiveness and OCI information relating to PSEG, PSE&G, Power and Energy Holdings’ interest rate swaps as of December 31, 2002 and 2001:
| OCI | ||||||||||||||||||
| OCI | Losses | Maturity | ||||||||||||||||
| Fair Market Value | Ineffectiveness | Losses | to be | of Longest |
||||||||||||||
| |
|
Reclassed |
Reclassed | Cash Flow | ||||||||||||||
| 2002 | 2001 | 2002 | 2001 | in 2002 | in 2003 | Hedge | ||||||||||||
| (Millions) | ||||||||||||||||||
| PSEG | $ | (21 | ) | $ | (5 | ) | $ — | $ — | $ 6 | $ 6 | 2008 | |||||||
| PSE&G (A) | (66 | ) | (19 | ) | — | — | — | — | 2011 | |||||||||
| Power | (9 | ) | 2 | — | — | (3 | ) | — | 2005 | |||||||||
| Energy Holdings | (138 | ) | (73 | ) | — | — | 12 | 16 | 2018 | |||||||||
| |
|
|||||||||||||||||
| $ | (234 | ) | $ | (95 | ) | $ — | $ — | $15 | $22 | |||||||||
| |
|
|
|
|
||||||||||||||
| (A) | Amounts at PSE&G relate to an interest rate swap at Transition Funding, which is offset by a Regulatory Asset of $66 million. |
Equity Securities
Energy Holdings
During 2002, Resources recognized a $38 million (pre-tax) loss from other than temporary impairments of non-publicly traded equity securities within certain leveraged buyout funds and other investments, which is included in Operating Revenues in the Consolidated Statements of Operations. As of December 31, 2002, Resources had investments in leveraged buyout funds of approximately $93 million, of which $24 million was comprised of public securities with available market prices and $69 million was comprised of non-publicly traded securities. Comparably, as of December 31, 2001, Resources had investments in leveraged buyout funds of approximately $130 million, of which $34 million was comprised of public securities with available market prices and $96 million was comprised of non-publicly traded securities.
Foreign Currencies
Energy Holdings
As of December 31, 2002, net foreign currency devaluations have reduced the reported amount of Energy Holdings’ total Member’s Equity by $307 million, of which $202 million and $103 million were caused by
155
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
the devaluation of the Brazilian Real and the Chilean Peso, respectively. For the net foreign currency devaluations for the period ended December 31, 2002 and 2001, see Energy Holdings’ Consolidated Statements of Member’s Equity.
Global holds a 60% ownership interest in Carthage Power Company (CPC), a Tunisian generation facility. The Power Purchase Agreement (PPA), signed in 1999 and extending through 2022, contains an embedded derivative that indexes the fixed Tunisian Dinar payments to US Dollar exchange rates. This embedded derivative is the longest standing foreign currency hedge that is outstanding. The indexation portion of the PPA is considered an embedded derivative and has been recognized and valued separately as a derivative instrument. As currencies devalue/revalue in relation to the US Dollar, the derivative increases/decreases in value equal to the discounted present value of additional units of foreign currency (measured in US Dollars) over the life of the PPA. This increased/decreased value is reported on the Consolidated Balance Sheets as an asset/liability. To the extent that such indexation is provided to hedge foreign currency debt exposure, the offsetting amount is recorded in OCI. Amounts will be reclassified from OCI to earnings over the life of the debt. To the extent such indexation is provided to hedge an equity return in US Dollars, the offsetting amount is recorded in earnings. As of December 31, 2002 and 2001, Global has recorded a derivative asset of $26 million and $35 million, respectively. For the year ended December 31, 2002, Global recorded a loss of $7 million, after taxes and minority interest, related to this embedded derivative, offsetting $8 million in foreign currency gains from the US Dollar debt at CPC. This was the only ineffectiveness that was present for the year ended December 31, 2002 and was immaterial to earnings. As of December 31, 2001, Global recorded a loss of $10 million to earnings, after tax and minority interest, of which $9 million was recorded as a Cumulative Effect of a Change in Accounting Principle.
In May 2002, Energy Holdings purchased foreign currency call options in order to hedge its average 2002 earnings denominated in Brazilian Reais and in Peruvian Nuevo Soles for the remainder of 2002. These options are not considered hedges for accounting purposes under SFAS 133 and, as a result, changes in their fair value are recorded directly to earnings. Global recorded a gain of $1 million related to Brazilian and Peruvian option contracts that expired during 2002. In December 2002, Energy Holdings purchased foreign currency call options in order to hedge its average 2003 earnings denominated in Chilean Pesos and Peruvian Nuevo Soles for the entire 2003 year. Changes in the fair value of these options are recorded directly to earnings. As of December 31, 2002, Energy Holdings had recorded a derivative asset of $2 million related to these assets. For the year ended December 31, 2002, the impact on earnings as a result of changes in fair value of these instruments was immaterial.
During 2001, Global purchased approximately 100% of a Chilean distribution company, Sociedad Austral de Electricidad S.A. (SAESA). As a requirement to obtain certain debt financing necessary to fund the acquisition, and in order to hedge against fluctuations in the US Dollar to Chilean Peso foreign exchange rates, Global entered into two forward contracts with notional values of $75 million each to exchange Chilean Pesos for US Dollars. These transactions expired in October 2002 but were renewed through January 2003. For accounting purposes, these transactions were considered hedges, whereby changes in fair value were recorded to OCI, until July 2002, when SAESA and its’ holding companies were restructured. Subsequent to July 2002, the changes in fair value of these instruments were recorded to earnings, and serve to offset currency gains or losses on SAESA’s US Dollar denominated debt. As of December 31, 2002 and 2001, Global had recorded a derivative asset of $3 million and $4 million, respectively, and a permanent OCI balance related to the hedge of $6 million. For the period from July 2002 through December 2002, Global recorded an after-tax loss of $7 million related to this hedge, offset by after-tax currency gains on the debt of approximately $8 million.
Global holds a 32% ownership interest in a Brazilian distribution company, Rio Grande Energia (RGE), whose debt is denominated in US Dollars. As of December 31, 2002 and 2001, Global’s pro-rata share of such debt was approximately $49.3 million and $60 million, respectively. In order to hedge the risk of fluctuations in the exchange rate between the Brazilian Real and US Dollar associated with the principal payments due in May, June and July of 2003 through 2005, RGE entered into a series of nine cross currency interest rate swaps in January 2002. The instruments convert the variable LIBOR-based principal payments to a variable CDI (the Brazilian inter-bank offered rate) based payments. As a result, RGE has hedged its foreign currency exposure but is still at risk for variability in the Brazilian CDI interest rate during the term of the instruments. Global’s share of the notional value of these instruments totals approximately $15 million per year for the instruments maturing in 2003 and 2004 and totals approximately $19 million per year for the instruments maturing in 2005. For accounting purposes,
156
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
fluctuations in the fair value of the interest rate component of these cross currency swaps is recorded directly to earnings.
The fair value of foreign currency derivatives, designated and effective as cash flow hedges, are initially recorded in OCI. Reclassification of unrealized gains or losses on cash flow hedges from OCI into earnings generally occurs when the hedged transaction is recorded in earnings and generally offsets the change in the value of the hedged item. Energy Holdings estimates reclassifying less than $1 million of foreign exchange gains from foreign currency cash flow hedges, including Energy Holdings’ pro-rata share from its equity method investees, from OCI to the Consolidated Statements of Operations over the next 12 months. For the period ended December 31, 2002 and 2001, losses transferred from OCI to the Consolidated Statements of Operations were less than $1 million.
Credit Risk
PSEG, PSE&G, Power and Energy Holdings
Credit risk relates to the risk of loss that would occur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG, PSE&G, Power and Energy Holdings have established credit policies to minimize 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.
Power
Through the BGS auctions, Power contracted to provide generating capacity to the direct suppliers of New Jersey electric utilities 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 that expired July 31, 2002. Any failure to collect these payments under the BGS contracts could have a material impact on Power’s results of operations, cash flows and financial position.
Note 13. Commitments and Contingent Liabilities
Nuclear Insurance Coverages and Assessments
Power
Power is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL). NEIL provides the primary property and decontamination liability insurance at the Salem, Hope Creek and Peach Bottom nuclear facilities. 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. Power’s maximum potential liabilities under these assessments are included in the table and notes below. 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 Nuclear Regulatory Commission (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 shut down.
The American Nuclear Insurers (ANI) and NEIL policies both include coverage for claims arising out of acts of terrorism. The ANI policies are subject to an industry aggregate limit of $200 million, subject to one reinstatement provided the reinstatement does not exceed the balance in the Industry Credit Rating Plan reserve fund. The NEIL Policies are subject to an industry aggregate limit of $3.24 billion plus any amounts available through reinsurance or indemnity.
157
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
The Price-Anderson Act sets the “limit of liability” for claims that could arise from an incident involving any licensed nuclear facility in the United States. 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 $9.45 billion. All utilities owning a nuclear reactor, including Power, 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. Power’s maximum aggregate assessment per incident is $277 million (based on Power’s ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is approximately $32 million. This does not include the $11 million that could be assessed under the nuclear worker policies. Further, a decision by the US Supreme Court, not involving Power, has held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damages.
Power’s insurance coverages and maximum retrospective assessments for its nuclear operations are as follows:
| Type and Source of Coverages | Total Site Coverage |
PSEG Power LLC Assessments |
||||||||
| |
||||||||||
| (Millions) | ||||||||||
| Public and Nuclear Worker Liability (Primary Layer): | ||||||||||
| American Nuclear Insurers (ANI) | $ | 200 | (A) | $ | 11 | |||||
| Nuclear Liability (Excess Layer): | ||||||||||
| Price-Anderson Act | 9,249 | (B) | 277 | |||||||
| Nuclear Liability Total | $ | 9,449 | (C) | $ | 288 | |||||
| Property Damage (Primary Layer): | ||||||||||
| Nuclear Electric Insurance Limited (NEIL) Primary | ||||||||||
| (Salem/Hope Creek/Peach Bottom) | $ | 500 | $ | 20 | ||||||
| Property Damage (Excess Layers): | ||||||||||
| NEIL II (Salem/Hope Creek/Peach Bottom) | 600 | 8 | ||||||||
| NEIL Blanket Excess | ||||||||||
| (Salem/Hope Creek/Peach Bottom) | 1,000 | (D) | 3 | |||||||
| Property Damage Total (Per Site) | $ | 2,100 | $ | 31 | ||||||
| Accidental Outage: | ||||||||||
| NEIL I (Peach Bottom) | $ | 245 | (E) | $ | 9 | |||||
| NEIL I (Salem) | 281 | 11 | ||||||||
| NEIL I (Hope Creek) | 490 | 9 | ||||||||
| Replacement Power Total | $ | 1,016 | $ | 29 | ||||||
| (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. |
| Effective January 1, 2003, the Nuclear Worker
Liability and the Primary Layer of American Nuclear Insurers was increased
to $300 million. | |
| (B) | Retrospective premium program under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. Power 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 |
158
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
| five years. The last adjustment was effective
as of August 20, 1998. This retrospective program is in excess over 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 $1.1 billion,
Power participates in a Blanket Limit policy where the $1 billion limit
is shared by Amergen, Exelon, and Power among the Braidwood, Byron, Clinton,
Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 facilities
owned by Amergen and Exelon and the Peach Bottom, Salem and Hope Creek facilities.
This limit is not subject to reinstatement in the event of a loss. Participation
in this program significantly reduces Power’s premium and the associated
potential assessment. |
| (E) | 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 $4.5 million for 52 weeks followed
by 80% of the weekly indemnity for 71 weeks. |
Old Dominion Electric Cooperative (ODEC)
PSE&G and Power
In 1995, PSE&G entered into a ten-year wholesale power contract with ODEC. The contract was transferred to Power in conjunction with the generation asset transfer in 2000. The contract provides for PSE&G to supply ODEC with capacity and energy for a bundled rate that includes a component to recover multiple transmission charges (referred to as “pancaked transmission rates”).
In November 1997, FERC issued the PJM Restructuring Order, which required PSE&G to modify its contract with ODEC to remove pancaked transmission rates. While PSE&G sought rehearing of this order, it was nonetheless required to reduce its rate to ODEC by approximately $6 million per year, effective April 1, 1998. In 2000, FERC issued its order denying PSE&G’s request for rehearing. Thereafter, PSE&G appealed to the US Court of Appeals for judicial review of the matter.
In July 2002, the Court ruled that FERC had not met its burden to justify modification of the ODEC contract. On December 19, 2002, based on the Court ruling, FERC reversed its November 1997 order thereby reinstating the original contract terms. This allows Power to collect amounts for April 1998 through December 2002 that would not have otherwise been collected over the contract term. The difference in revenues between the contracted rate and the FERC-ordered reduced rate is approximately $30 million, inclusive of back interest and represents a gain contingency to Power. Power billed ODEC for this amount in January 2003 and will record this gain when realized.
Guaranteed Obligations
Power
Power has guaranteed certain commodity related transactions for its subsidiary, ER&T, which is involved in energy marketing activities. These guarantees were provided to counterparties in order to facilitate physical and financial agreements in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. These Power guarantees support the current exposure (net billed and unbilled energy plus mark-to-market value on open positions), interest and other costs on sums due and payable by ER&T under these agreements. Guarantees
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
offered for trading and marketing cover the granting of lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can go either direction. If the exposure were one directional at year-end with all contracts “out-of-the-money” for Power, then the maximum liability (face value) of the guarantees on December 31, 2002 and 2001 would be $1.1 billion and $506 million, respectively. The probability of all contracts at ER&T being simultaneously “out-of-the-money” given the nature of ER&T’s asset backed transactions is highly unlikely. For this reason, the current exposure at any point in time is a more meaningful representation of the liability under these guarantees. The current exposure from such liabilities was $268 million and $153 million as of December 31, 2002, and 2001, respectively. To the extent liabilities exist under the commodity related contracts subject to these guarantees, such liabilities are included in the Consolidated Balance Sheets.
In addition, all Master Agreements and other supply contracts contain margin and/or other collateral requirements that, as of December 31, 2002, could require Power to post additional collateral of approximately $320 million if Power were to lose its investment grade credit rating.
As of December 31, 2002, letters of credit issued by Power were outstanding in the amount of approximately $73 million in support of various contractual obligations.
Energy Holdings
Energy Holdings and/or Global have guaranteed certain obligations of Global’s subsidiaries or affiliates, including the successful completion, performance or other obligations related to certain projects in an aggregate amount of approximately $339 million as of December 31, 2002. The guarantees include a $61 million equity commitment for ELCHO in Poland, a $55 million standby equity commitment for Skawina in Poland, $56 million of various guarantees for Dhofar Power Company in Oman and a $25 million contingent guarantee related to debt service obligations of Chilquinta Energia Finance L.L.C. in connection with electric distribution companies in Chile and Peru. Additional guarantees consist of a $35 million leasing agreement guarantee for Prisma in Italy, $27 million in standby letters of credit for SAESA (which were eliminated upon the refinancing at SAESA in January 2003) and various other guarantees comprising the remaining $49 million. A substantial portion of such guarantees will be cancelled upon successful completion, performance and/or refinancing of construction debt with non-recourse project debt.
In the normal course of business, Energy Technologies secures construction obligations with performance bonds issued by insurance companies. Prior to January 2003, in the event that Energy Technologies’ tangible equity was reduced to an amount less than $100 million, Energy Holdings would have been required to provide additional support for the performance bonds. Tangible equity is defined as net equity less goodwill. As of December 31, 2002, Energy Technologies’ tangible equity was $105 million. As of December 31, 2002, Energy Technologies had $228 million of such bonds outstanding, of which $45 million was at risk in ongoing construction projects. The performance bonds are not included in the $339 million of guaranteed obligations discussed above. In January 2003, Energy Holdings provided an indemnification agreement and $31 million of letters of credit to replace the $100 million capital retention agreement referred to above. These amounts are expected to decrease over time as Energy Technologies completes the work in process or transfers ownership to other companies.
Environmental Matters
PSE&G and Power
Hazardous Waste
The New Jersey Department of Environmental Protection (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 is presently working with the energy 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. PSE&G, Power and predecessor companies own or owned and/or operate or operated certain facilities situated on surface water bodies, certain of which are currently the subject of remedial activities. The financial impact of these regulations on these projects is not currently estimable. PSEG does not anticipate that the compliance with these regulations will have a material adverse effect on its financial position, results of operations or net cash flows.
160
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
PSE&G
PSE&G Manufactured Gas Plant Remediation Program
PSE&G is currently working with the NJDEP under a program (Remediation Program) to assess, investigate and, if necessary, remediate environmental conditions at PSE&G’s former manufactured gas plant (MGP) sites. To date, 38 sites have been identified. The Remediation Program is periodically reviewed and revised by PSE&G based on regulatory requirements, experience with the Remediation Program and available remediation technologies. The long-term costs of the Remediation Program cannot be reasonably estimated, but experience to date indicates that at least $20 million per year could be incurred over a period of about 30 years since inception of the program in 1988 and that the overall cost could be material. The costs for this remediation effort are recovered through the SBC.
As of December 31, 2002, PSE&G’s estimated liability for remediation costs through 2004 aggregated $115 million. Expenditures beyond 2004 cannot be reasonably estimated.
Passaic River Site
The United States Environmental Protection Agency (EPA) has determined that a nine mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 and that, to date, at least thirteen corporations, including PSE&G, may be potentially liable for performing required remedial actions to address potential environmental pollution in the Passaic River “facility.”
In a separate matter, PSE&G and certain of its predecessors conducted industrial operations at properties within the Passaic River facility. The operations included one operating electric generating station one former generating station, and four former MGPs. PSE&G’s costs to clean up former MGPs are recoverable from utility customers through the SBC. PSE&G has sold the site and obtained releases and indemnities for liabilities arising out of the site in connection with the sale. PSE&G cannot predict what action, if any, the EPA or any third party may take against PSE&G with respect to this matter, or in such an event, what costs may be incurred to address any such claims. However, such costs may be material.
Power
Prevention of Significant Deterioration (PSD)/New Source Review(NSR)
The EPA and the NJDEP issued a demand in March 2000 under 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 PSD/NSR regulations. Power completed its response to the information request in November 2000. In January 2002, Power reached an agreement with New Jersey and the federal governments to resolve allegations of noncompliance with federal and State of New Jersey PSD/NSR regulations. Under that agreement, over the course of 10 years, Power must install advanced air pollution controls that are designed to reduce emissions of NOx, SO2, particulate matter and mercury. The estimated cost of the program at the time of the settlement was $337 million to be incurred through 2011. Power also paid a $1.4 million civil penalty and has agreed to spend up to $6 million on supplemental environmental projects. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved the dispute over Bergen 2 regarding the applicability of PSD requirements, and allowed construction of the unit to be completed and operation to commence.
Power has recently notified the EPA and the NJDEP that it is evaluating the continued operation of the Hudson coal unit beyond 2006, in light of changes in the energy and capacity markets and increases in the cost of pollution control equipment and other necessary modifications. A decision is expected to be made in 2003 as to the Hudson unit’s continued operation. The related costs associated with these modification have not been included in Power’s capital expenditure projections.
Industrial Site Recovery Act
Potential environmental liabilities related to subsurface contamination at certain generating stations have been identified. The New Jersey statute that led to the identification is the Industrial Site Recovery Act (ISRA) that applies to the sale of certain assets. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted to identify potential environmental liabilities and PSEG recorded a $53 million liability related to these obligations, which is represented on the Consolidated Balance Sheets.
161
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
New Generation and Development
Power
Power has revised its schedules for completion of several of its projects under development to provide better sequencing of its construction program with anticipated market demand. This delay will allow Power to conserve capital in 2003 and will allow it to take advantage of the expected recovery of the electric markets and their need for capacity in 2005.
Through an indirect, wholly-owned subsidiary, Power is developing the Bethlehem Energy Center, a 763 MW combined-cycle power plant that will replace the 376 MW Albany, NY Steam Station. Total costs for this project are expected to be approximately $483 million with expenditures to date of approximately $170 million. Construction began in 2002 with the expected completion date in 2005, at which time the existing station will be retired.
Power is constructing a 1,218 MW combined-cycle generation plant at Linden, New Jersey with costs estimated at approximately $711 million and expenditures to date of approximately $564 million. Completion is expected in 2005, at which time 451 MW of existing generating capacity at the site will be retired.
Power is constructing through indirect, wholly-owned subsidiaries, two natural gas-fired combined cycle electric generation plants in Waterford, Ohio (821 MW) and Lawrenceburg, Indiana (1,096 MW) at an estimated aggregate total cost of $1.2 billion. Total expenditures to date on these projects have been approximately $1.0 billion. The required estimated equity investment in these projects is approximately $400 million, with the remainder being financed with non-recourse bank financing. As of December 31, 2002, approximately $275 million of equity has been invested in these projects. 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. Based on current prices, the purchase price under this contract is currently above market. ER&T may terminate the agreement upon repayment of the current financing scheduled for August 2005. Additional equity investments may be required if the proceeds received from ER&T under this tolling agreement are not sufficient to cover the required payments under the bank financing. The Waterford facility is currently scheduled to achieve commercial operation in June 2003. The Lawrenceburg facility is currently scheduled to achieve commercial operation in November 2003.
Power also has contracts with outside parties to purchase upgraded turbines for the Salem Nuclear Generating Station Units 1 and 2 and to purchase upgraded turbines and to purchase a power uprate for Hope Creek Generating Station to increase its generating capacity. The contracts are subject to regulatory approval and the projects are currently scheduled to be completed by 2004 for Salem Unit 1 and Hope Creek and 2006 for Salem Unit 2. Power’s aggregate estimated costs for these projects are $210 million, with expenditures to date of approximately $40 million.
Power has commitments to purchase gas turbines and/or other services to meet its current plans to develop additional generating capacity. The aggregate amount due under these commitments is approximately $480 million, approximately $370 million of which is included in estimated costs for the projects discussed above. The approximate $110 million remaining relates to obligations to purchase hardware and services that have not been designated to any specific projects. If Power does not contract to satisfy its commitment relating to the $110 million in obligations by July 2003, it will be subject to penalties of up to $24 million.
162
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Minimum Fuel Purchase Requirements
Power
Power uses coal for its fossil electric generation stations. Power purchases coal through various contracts and in the spot market. The total minimum purchase requirements included in these contracts amount to approximately $75 million through 2003.
Power has several long-term purchase contracts with uranium suppliers, converters, enrichers and fabricators to meet the currently projected fuel requirements for Salem and Hope Creek. On average, Power has various multi-year requirements-based purchase commitments that total approximately $88 million per year to meet Salem and Hope Creek fuel needs. Power has been advised by Exelon, the co-owner and operator of the Peach Bottom that it has similar purchase contracts to satisfy the fuel requirements for Peach Bottom.
Nuclear Fuel Disposal
Power
After spent fuel is removed from a nuclear reactor, it is placed in temporary storage for cooling in a spent fuel pool at the nuclear station site. Under the Nuclear Waste Policy Act of 1982 (NWPA), as amended, the Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of the spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001) per Kilowatt-hour (kWh) of nuclear generation ($21 million for 2002), subject to such escalation as may be required to assure full cost recovery by the Federal government. Payments made to the United States Department of Energy (DOE) for disposal costs are based on nuclear generation and are included in Energy Costs in the Consolidated Statements of Operations.
Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent fuel storage installations located at reactor or away-from-reactor sites for at least 30 years beyond the licensed life for reactor operation (which may include the term of a revised or renewed license). The availability of adequate spent fuel storage capacity is estimated through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power presently expects to construct an on-site storage facility that would satisfy the spent fuel storage needs of both Salem and Hope Creek through the end of the license life. This construction will require certain regulatory approvals, the timely receipt of which cannot be assured. Exelon has advised us that it has constructed an on-site storage facility at Peach Bottom that is now licensed and operational and can provide storage capacity through the end of the current licenses for the two Peach Bottom units. Additional storage facilities will need to be constructed if the licenses for these facilities are extended. If the DOE begins to take possession of spent nuclear fuel, as discussed below, the need for additional storage capacity would be reduced.
Under the NWPA, the DOE was required to begin taking possession of the spent nuclear fuel by no later than 1998. The DOE has announced that it does not expect a facility to be available earlier than 2010. Exelon has advised us that it had signed an agreement with the DOE applicable to Peach Bottom under which Exelon would be reimbursed for costs incurred resulting from the DOE’s delay in accepting spent nuclear fuel. The agreement allows Exelon to reduce the charges paid to the Nuclear Waste Fund to reflect costs reasonably incurred due to the DOE’s delay. Past and future expenditures associated with Peach Bottom’s recently completed on-site dry storage facility would be eligible for this reduction in DOE fees. Under this agreement, Power’s portion of Peach Bottom’s Nuclear Waste Fund fees have been reduced by approximately $18 million through August 31, 2002, at which point the credits were fully utilized and covered the cost of Exelon’s storage facility.
In 2000, a group of eight utilities filed a petition against the DOE in the US Court of Appeal for the Eleventh Circuit, seeking to set aside the receipt of credits by Exelon out of the Nuclear Waste Fund, as stipulated in the Peach Bottom agreement. On September 24, 2002, the Court issued an opinion upholding the challenge by the petitioners regarding the settlement agreement’s compensation provisions. Under the terms of the agreement, DOE and Exelon are required to meet and discuss alternative funding sources for the settlement credits. Initial meetings have occurred. The Eleventh Circuit’s opinion suggests that the federal judgment fund should be available as an alternate source. The agreement provides that if such negotiations are unsuccessful, the agreement will be null and void. Any payments required by Power resulting from a disallowance of the previously reduced fees would be included in Energy Costs in the Consolidated Statements of Operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
On September 26, 2001, Nuclear filed a complaint in the US Court of Federal Claims seeking damages caused by the DOE not taking possession of spent nuclear fuel in 1998. No assurances can be given as to any damage recovery or the ultimate availability of a disposal facility.
In October 2001, Power filed a complaint in the US Court of Federal Claims, along with a number of other plaintiffs, seeking $28.2 million in relief from past overcharges by the DOE for enrichment services. No assurances can be given as to any damage recovery.
In February 2002, President Bush announced that Yucca Mountain in Nevada would be the permanent disposal facility for nuclear wastes. In April 2002, the Governor of Nevada submitted his veto to the siting decision and in July 2002, Congress affirmed the President’s decision. The DOE must still license and construct the facility. No assurances can be given regarding the final outcome of this matter.
Energy Holdings
Argentina
Global has certain contingent obligations that are likely to occur if certain projects in Argentina continue to default on their debt and performance obligations. The estimated amount to cover this exposure is $7 million and has been recorded as a component of Operating Expenses in the Consolidated Statements of Operations.
Under certain circumstances, Global could be obligated to settle its share (approximately $26 million) of a project loan for EDELAP should it or the majority owner of the project, take certain actions including forcing or permitting certain loan parties to declare bankruptcy. In addition, the guarantee can be triggered by transferring the shares of certain loan parties without lender consent. Breach of this transfer covenant can be cured by delivering certain pledge agreements relating to the ownership of loan parties to the lenders. Global could also be liable for any incremental direct damages arising from the breach of these covenants. Given the likely cure of any breach by the project sponsors, such a contingent obligation has a low probability of being triggered and, therefore, no provision has been made in Global’s Consolidated Financial Statements. Under the terms of the settlement of Global’s litigation with AES, AES is required to deliver pledge agreements that may be required under the loan documents. For further information, see Note 4. Asset Impairments.
California
In May 2001, GWF Energy LLC (GWF Energy), a joint venture between Global and Harbinger GWF LLC entered into a 10-year power purchase agreement (PPA) with the California Department of Water Resources (CDWR) to provide approximately 340 MW of electric capacity to California from three new natural gas-fired peaking plants, the Hanford, Henrietta and Tracy Peaker Plants. Total project cost for these plants is estimated at approximately $345 million.
In 2002, GWF Energy entered into negotiations with the California Public Utilities Commission (CPUC) and the California Electricity Oversight Board (collectively the California Parties) resulting in the execution of (i) an amended and restated PPA that has been affirmed by the CPUC as “just and reasonable” and (ii) a settlement agreement with the California Parties, the CDWR, the Governor of the State of California and the People of California by and through the Attorney General.
The Hanford and Henrietta Peaker Plants were completed in August 2001 and in June 2002, respectively, and the Tracy Peaker Plant, a 167 MW facility, is now under construction. The commercial operations date deadline of the Tracy Peaker Plant is July 1, 2003 under the amended and restated PPA discussed above. As of December 31, 2002, Global’s equity investment in these plants was $228 million. Upon successful completion of project financing, which is currently expected to occur in the second quarter of 2003, Global’s permanent equity investment in the plants, including contingencies, is not expected to exceed $150 million. In the event financing does not occur, Global’s investment in these plants could increase to approximately $293 million.
164
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Global’s ownership interest in this project was 76% as of December 31, 2002. For a description of turbine loans and working capital loans from Global to GWF Energy pending completion of project financing, see Note 22. Related-Party Transactions.
Chile
Global owns SAESA, a group of companies that consists of four distribution companies and one transmission company that provide electric service to customers in southern Chile. SAESA had a $150 million loan facility in place that had an original maturity date of October 18, 2002 and is recorded as a component of Notes Payable and Project Level Non-Recourse Debt on Energy Holdings’ Consolidated Balance Sheets as of December 31, 2002. The principal payment was not made as scheduled and the lending group agreed not to declare any payment defaults or exercise any remedies with regard to that loan and accordingly a term sheet for an extension of the loan to April 2003 was agreed to. On January 17, 2003, SAESA issued bonds worth $114 million in the Chilean market. SAESA divided the debt issue into a $61 million, 7-year bond with a coupon rate of 5.39% and another $54 million bond maturing in 21 years at a rate of 6.6%. SAESA also signed a syndicated bank loan for $58 million. These funds were used to repay the $150 million loan scheduled to mature in April 2003. In January 2003, Global contributed an additional $55 million in equity and increased its investment in SAESA to $466 million.
Peru
In December 2001, Global acquired an interest in Electroandes, a 183 MW hydroelectric generation and distribution company in Peru. Part of the purchase price was financed with a $100 million one year bridge loan which matured in December 2002. The loan facility provided that the maturity date could be extended for six months if certain conditions were met. The loan was extended to June 2003 and a refinancing plan is underway.
India
Energy Holdings has a 20% interest in a 330 MW Naphtha/natural gas fired plant (PPN) in the Indian State of Tamil Nadu. Energy Holdings’ investment exposure (investment less non-recourse debt) in this facility is approximately $40 million. Power from the facility is sold under a long-term power purchase agreement with the Tamil Nadu Electricity Board (TNEB) which sells the power to retail end-user customers. The TNEB has not been able to make full payment to the plant for the purchase of energy under contract due to its overall poor liquidity situation. The past due receivable at PPN as of December 31, 2002 at the project company is approximately $57 million, Energy Holdings’ share of which is approximately $8 million, net of a $3 million reserve.
Poland
In January 2002, Global acquired a 35% interest in the 590 MW (electric) and 618 MW (thermal) coal-fired Skawina CHP Plant (Skawina), located in Poland and in June 2002 increased its ownership interest to approximately 50%. The transaction includes the obligation to purchase additional shares in 2003 that will bring Global’s aggregate interest in Skawina to approximately 65% and the obligation to offer to purchase an additional 10% from Skawina’s employees, increasing Global’s potential ownership interest to 75%. Global expended $31 million during 2002 for its approximate 50% ownership interest and the total equity investment is expected to be approximately $105 million, including contingencies and equity commitment guarantees.
Tunisia
Global owns a 60% interest in Carthage Power Company (CPC), a 471 MW gas-fired combined-cycle electric generation facility located in Rades, Tunisia. CPC has entered into a 20-year power purchase contract for the sale of 100% of the output to Societe Tunisienne de l’ Electricite et du Gaz (STEG). The contract called for the plant to be operational by November 24, 2001, however, due to delays in construction, this deadline was not met. STEG has declared that it is entitled to liquidated damages at the rate of $67 thousand a day since November 24, 2001 in accordance with the terms of the power purchase contract. CPC is contesting STEG’s claim and the two parties are currently in negotiations to settle this dispute. The facility was built by Alstom Centrales Energetiques S.A.,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(Alstom) an independent contractor, who was also obligated to complete construction by September 3, 2001. The facility commenced operation on May 14, 2002. CPC believes it is entitled to liquidated damages from Alstom in amounts greater than the claims by STEG. Such liquidated damages are secured by letters of credit totaling $30 million.
Minimum Lease Payments
PSEG, PSE&G and Energy Holdings
PSE&G, Services and Energy Holdings lease administrative office space under various operating leases. In addition, PSE&G, Services and Energy Holdings expense the costs of renting various facilities for an immaterial amount. Total future minimum lease payments as of December 31, 2002 are:
| 2003 | 2004 | 2005 | 2006 | 2007 | After 2007 |
Total | |||||||||||||||
| (Millions) | |||||||||||||||||||||
| PSE&G | $ | 3 | $ | 3 | $ | 3 | $ | 2 | $ | 2 | $ | — | $ | 13 | |||||||
| Services | 1 | 1 | 1 | 1 | 1 | 3 | 8 | ||||||||||||||
| Energy Holdings | 6 | 5 | 4 | 4 | 4 | 14 | 37 | ||||||||||||||
| Total PSEG | $ | 10 | $ | 9 | $ | 8 | $ | 7 | $ | 7 | $ | 17 | $ | 58 | |||||||
Power and PSE&G have entered into capital leases for administrative office space. The total future minimum payments and present value of these capital leases as of December 31, 2002 are:
| PSE&G | Power | |||||||
| (Millions) | ||||||||
| 2003 | $ | 6 | $ | 1 | ||||
| 2004 | 6 | 1 | ||||||
| 2005 | 6 | 1 | ||||||
| 2006 | 6 | 2 | ||||||
| 2007 | 6 | 2 | ||||||
| Thereafter | 50 | 12 | ||||||
| Total minimum lease payments | $ | 80 | $ | 19 | ||||
| Less: Imputed Interest | (38 | ) | (7 | ) | ||||
| Present Value of net minimum lease payments | $ | 42 | $ | 12 | ||||
166
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 14. Nuclear Decommissioning Trust
Power
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.
The ownership of the Nuclear Decommissioning Trust Funds was transferred to Nuclear with the transfer of the generation-related assets from PSE&G to Power. Pursuant to the Final Order, PSE&G will collect approximately $30 million annually through the SBC and will remit to Power an equivalent amount solely to fund the trust through at least the end of the transition period, July 31, 2003. For information relating to cost responsibility for nuclear decommissioning subsequent to July 31, 2003, see Note 2. New Accounting Standards. The fair market value of these funds as of December 31, 2002 and 2001 was $766 million and $817 million, respectively.
Power maintains the external master nuclear decommissioning trust previously established by PSE&G. 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, Power’s share of its five nuclear units was estimated at approximately $1.8 billion in year-end 2002 dollars, excluding contingencies.
Note 15. Other Income and Deductions
Other Income
| PSE&G | Power | Energy Holdings |
Other (A) | Consolidated Total | ||||||||||||
| For the Year Ended December 31, 2002: | (Millions) | |||||||||||||||
| |
||||||||||||||||
| Interest Income | $ | 17 | $ | — | $ | — | $ | 2 | $ | 19 | ||||||
| Gain on Disposition of Property | 10 | — | — | — | 10 | |||||||||||
| Change in Derivative Fair Value | — | — | 12 | — | 12 | |||||||||||
| Gain on Early Retirement of Debt | — | — | 13 | — | 13 | |||||||||||
| Other | 1 | — | — | 2 | 3 | |||||||||||
| Total Other Income | $ | 28 | $ | — | $ | 25 | $ | 4 | $ | 57 | ||||||
| For the Year Ended December 31, 2001: | ||||||||||||||||
| |
||||||||||||||||
| Interest Income | $ | 104 | $ | — | $ | — | $ | (67 | ) | $ | 37 | |||||
| Gain on Disposition of Property | 4 | — | — | — | 4 | |||||||||||
| Other | 3 | — | 6 | — | 9 | |||||||||||
| Total Other Income | $ | 111 | $ | — | $ | 6 | $ | (67 | ) | $ | 50 | |||||
| For the Year Ended December 31, 2000: | ||||||||||||||||
| |
||||||||||||||||
| Interest Income | $ | 164 | $ | 1 | $ | — | $ | (143 | ) | $ | 22 | |||||
| Litigation Settlement | 6 | 6 | — | (6 | ) | 6 | ||||||||||
| Minority Interest | — | — | — | 1 | 1 | |||||||||||
| Foreign Currency Gains | — | — | 3 | — | 3 | |||||||||||
| Other | 3 | — | — | (2 | ) | 1 | ||||||||||
| Total Other Income | $ | 173 | $ | 7 | $ | 3 | $ | (150 | ) | $ | 33 | |||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Other Deductions
| PSE&G | Power | Energy Holdings |
Other (A) | Consolidated Total | ||||||||||
| For the Year Ended December 31, 2002: | (Millions) | |||||||||||||
| |
||||||||||||||
| Donations | $ | 2 | $ | — | $ | — | $— | $ | 2 | |||||
| Minority Interest | — | — | — | 2 | 2 | |||||||||
| Foreign Currency Losses | — | — | 70 | — | 70 | |||||||||
| Other | — | — | 3 | 2 | 5 | |||||||||
| Total Other Deductions | $ | 2 | $ | — | $ | 73 | $4 | $ | 79 | |||||
| For the Year Ended December 31, 2001: | ||||||||||||||
| |
||||||||||||||
| Donations | $ | 3 | $ | — | $ | — | $— | $ | 3 | |||||
| Minority Interest | — | — | — | 1 | 1 | |||||||||
| Foreign Currency Losses | — | — | 9 | — | 9 | |||||||||
| Loss on Early Retirement of Debt | — | — | 3 | — | 3 | |||||||||
| Other | 1 | — | — | (2 | ) | (1 | ) | |||||||
| Total Other Deductions | $ | 4 | $ | — | $ | 12 | $(1 | ) | $ | 15 | ||||
| For the Year Ended December 31, 2000: | ||||||||||||||
| |
||||||||||||||
| Donations | $ | 3 | $ | — | $ | — | $(3 | ) | $ | — | ||||
| Other | 1 | — | 3 | (1 | ) | 3 | ||||||||
| Total Other Deductions | $ | 4 | $ | — | $ | 3 | $(4 | ) | $ | 3 | ||||
(A) Other primarily consists of activity at PSEG (parent company), Services and intercompany eliminations.
168
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 16. Income Taxes
A reconciliation of reported income tax expense with the amount computed by multiplying pre-tax income by the statutory Federal income tax rate of 35% is as follows:
| PSE&G | Power | Energy Holdings |
Other | Consolidated Total |
|||||||||||||||
| 2002 | (Millions) | ||||||||||||||||||
| |
|||||||||||||||||||
| Net Income (Loss) | $ | 201 | $ | 468 | $ | (403 | ) | $ | (21 | ) | $ | 245 | |||||||
| Loss from Discontinued Operations, | |||||||||||||||||||
| (Including Loss on Disposal, Net of Tax— $27) | –– | –– | (51 | ) | –– | (51 | ) | ||||||||||||
| Cumulative Effect of a Change in | |||||||||||||||||||
| Accounting Principle, (Net of Tax— $66) | –– | –– | (120 | ) | –– | (120 | ) | ||||||||||||
| Minority Interest in Earnings of Subsidiaries | –– | –– | (2 | ) | 2 | –– | |||||||||||||
| Net Income before Retained Earnings | |||||||||||||||||||
| Adjustment and Minority Interests | 201 | 468 | (230 | ) | (23 | ) | 416 | ||||||||||||
| Preferred Dividends (net) | (4 | ) | –– | (23 | ) | 20 | (7 | ) | |||||||||||
| Net Income before Retained Earnings | |||||||||||||||||||
| Adjustment and Preferred Dividends | 205 | 468 | (207 | ) | (43 | ) | 423 | ||||||||||||
| Income Taxes: | |||||||||||||||||||
| Federal – Current | 121 | 184 | (108 | ) | (29 | ) | 168 | ||||||||||||
| Deferred | (44 | ) | 69 | (23 | ) | 6 | 8 | ||||||||||||
| ITC | (2 | ) | –– | (2 | ) | –– | (4 | ) | |||||||||||
| Total Federal | 75 | 253 | (133 | ) | (23 | ) | 172 | ||||||||||||
| State – Current | 17 | 41 | (1 | ) | (7 | ) | 50 | ||||||||||||
| Deferred | 23 | 19 | (27 | ) | –– | 15 | |||||||||||||
| Total State | 40 | 60 | (28 | ) | (7 | ) | 65 | ||||||||||||
| Foreign – Current | –– | –– | 1 | –– | 1 | ||||||||||||||
| Deferred | –– | –– | 10 | –– | 10 | ||||||||||||||
| Total Foreign | –– | –– | 11 | –– | 11 | ||||||||||||||
| Total | 115 | 313 | (150 | ) | (30 | ) | 248 | ||||||||||||
| Pre-tax Income | $ | 320 | $ | 781 | $ | (357 | ) | $ | (73 | ) | $ | 671 | |||||||
| Tax computed at the statutory rate | $ | 112 | $ | 273 | $ | (125 | ) | $ | (25 | ) | $ | 235 | |||||||
| Increase (decrease) attributable
to flow through of certain tax adjustments: |
|||||||||||||||||||
| Plant Related Items | (15 | ) | –– | –– | –– | (15 | ) | ||||||||||||
| Amortization of investment tax credits | (2 | ) | –– | (2 | ) | –– | (4 | ) | |||||||||||
| Other | (6 | ) | 1 | 2 | (1 | ) | (4 | ) | |||||||||||
| Tax Effects Attributable to Foreign | |||||||||||||||||||
| Operations | –– | –– | (11 | ) | –– | (11 | ) | ||||||||||||
| New Jersey Corporate Business Tax | 26 | 39 | (14 | ) | (4 | ) | 47 | ||||||||||||
| Subtotal | 3 | 40 | (25 | ) | (5 | ) | 13 | ||||||||||||
| Total income tax provisions | $ | 115 | $ | 313 | $ | (150 | ) | $ | (30 | ) | $ | 248 | |||||||
| Effective income tax rate | 35.9 | % | 40.1 | % | 42.0 | % | 41.1 | % | 37.0 | % | |||||||||
169
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
| PSE&G | Power | Energy Holdings |
Other | Consolidated Total |
||||||||||||||
| (Millions) | ||||||||||||||||||
| 2001 | ||||||||||||||||||
| |
||||||||||||||||||
| Net Income (Loss) | $ | 230 | $ | 394 | $ | 161 | $ | (15 | ) | $ | 770 | |||||||
| Loss from Discontinued
Operations, (Net of Tax— $8) |
–– | –– | (15 | ) | –– | (15 | ) | |||||||||||
| Cumulative Effect of a Change in Accounting | ||||||||||||||||||
| Principle, (Net of Tax— $8) | –– | –– | 9 | –– | 9 | |||||||||||||
| Minority Interest in Earnings of Subsidiaries | –– | –– | (1 | ) | 1 | –– | ||||||||||||
| Net Income before Retained Earnings | ||||||||||||||||||
| Adjustment and Minority Interests | 230 | 394 | 168 | (16 | ) | 776 | ||||||||||||
| Preferred Dividends (net) | (5 | ) | –– | (22 | ) | –– | (27 | ) | ||||||||||
| Net Income before Retained Earnings | ||||||||||||||||||
| Adjustment and Preferred Dividends | 235 | 394 | 190 | (16 | ) | 803 | ||||||||||||
| Income Taxes: | ||||||||||||||||||
| Federal – Current | 250 | 139 | (100 | ) | (31 | ) | 258 | |||||||||||
| Deferred | (192 | ) | 74 | 161 | 13 | 56 | ||||||||||||
| ITC | (2 | ) | –– | (1 | ) | –– | (3 | ) | ||||||||||
| Total Federal | 56 | 213 | 60 | (18 | ) | 311 | ||||||||||||
| State – Current | 42 | 17 | 9 | (4 | ) | 64 | ||||||||||||
| Deferred | (9 | ) | 20 | (11 | ) | (1 | ) | (1 | ) | |||||||||
| Total State | 33 | 37 | (2 | ) | (5 | ) | 63 | |||||||||||
| Foreign – Current | –– | –– | 1 | –– | 1 | |||||||||||||
| Deferred | –– | –– | 6 | –– | 6 | |||||||||||||
| Total Foreign | –– | –– | 7 | –– | 7 | |||||||||||||
| Total | 89 | 250 | 65 | (23 | ) | 381 | ||||||||||||
| Pre-tax Income | $ | 324 | $ | 644 | $ | 255 | $ | (39 | ) | $ | 1,184 | |||||||
| Tax computed at the statutory rate | $ | 113 | $ | 225 | $ | 89 | $ | (13 | ) | $ | 414 | |||||||
| Increase (decrease) attributable to flow through of certain tax adjustments: |
||||||||||||||||||
| Plant Related Items | (41 | ) | –– | –– | –– | (41 | ) | |||||||||||
| Amortization of investment and energy tax credits | (2 | ) | –– | (1 | ) | –– | (3 | ) | ||||||||||
| Other | (2 | ) | 1 | (2 | ) | (1 | ) | (4 | ) | |||||||||
| Tax Effects Attributable to Foreign Operations | –– | –– | (18 | ) | –– | (18 | ) | |||||||||||
| New Jersey Corporate Business Tax | 21 | 24 | (3 | ) | (9 | ) | 33 | |||||||||||
| Subtotal | (24 | ) | 25 | (24 | ) | (10 | ) | (33 | ) | |||||||||
| Total income tax provisions | $ | 89 | $ | 250 | $ | 65 | $ | (23 | ) | $ | 381 | |||||||
| Effective income tax rate | 27.4 | % | 38.8 | % | 25.4 | % | 59.0 | % | 32.2 | % | ||||||||
170
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
| PSE&G (A) | Power (A) | Energy Holdings |
Other (A) | Consolidated Total |
||||||||||||||||
| 2000 | (Millions) | |||||||||||||||||||
| |
||||||||||||||||||||
| Net Income (Loss) | $ | 578 | $ | 313 | $ | 90 | $ | (217 | ) | $ | 764 | |||||||||
| Loss from Discontinued
Operations, (Net of Tax— $ 5) |
–– | –– | (12 | ) | –– | (12 | ) | |||||||||||||
| Minority Interest in Earnings of Subsidiaries | –– | –– | 1 | (1 | ) | –– | ||||||||||||||
| Net Income before Retained Earnings | ||||||||||||||||||||
| Adjustment and Minority Interests | 578 | 313 | 101 | (216 | ) | 776 | ||||||||||||||
| Preferred securities (net) | (9 | ) | –– | (24 | ) | 24 | (9 | ) | ||||||||||||
| Net Income before Retained Earnings | ||||||||||||||||||||
| Adjustment and Preferred Dividends | 587 | 313 | 125 | (240 | ) | 785 | ||||||||||||||
| Income Taxes: | ||||||||||||||||||||
| Federal – Current | 261 | 139 | (127 | ) | (116 | ) | 157 | |||||||||||||
| Deferred | 50 | 25 | 169 | (16 | ) | 228 | ||||||||||||||
| ITC | (1 | ) | –– | (1 | ) | –– | (2 | ) | ||||||||||||
| Total Federal | 310 | 164 | 41 | (132 | ) | 383 | ||||||||||||||
| State – Current | 150 | 114 | 4 | (109 | ) | 159 | ||||||||||||||
| Deferred | (53 | ) | (70 | ) | 2 | 71 | (50 | ) | ||||||||||||
| Total State | 97 | 44 | 6 | (38 | ) | 109 | ||||||||||||||
| Foreign – Current | –– | –– | –– | –– | –– | |||||||||||||||
| Deferred | –– | –– | 4 | –– | 4 | |||||||||||||||
| Total Foreign | –– | –– | 4 | –– | 4 | |||||||||||||||
| Total | 407 | 208 | 51 | (170 | ) | 496 | ||||||||||||||
| Pre-tax Income | $ | 994 | $ | 521 | $ | 176 | $ | (410 | ) | $ | 1,281 | |||||||||
| Tax computed at the statutory rate | $ | 348 | $ | 182 | $ | 61 | $ | (143 | ) | $ | 448 | |||||||||
| Increase (decrease) attributable
to flow through of certain tax adjustments: |
||||||||||||||||||||
| Plant Related Items | (15 | ) | –– | –– | –– | (15 | ) | |||||||||||||
| Amortization of investment tax credits | (1 | ) | –– | (1 | ) | –– | (2 | ) | ||||||||||||
| Other | 17 | (4 | ) | 1 | (9 | ) | 5 | |||||||||||||
| Tax Effects Attributable to Foreign | ||||||||||||||||||||
| Operations | –– | –– | (14 | ) | –– | (14 | ) | |||||||||||||
| New Jersey Corporate Business Tax | 58 | 30 | 4 | (18 | ) | 74 | ||||||||||||||
| Subtotal | 59 | 26 | (10 | ) | (27 | ) | 48 | |||||||||||||
| Total income tax provisions | $ | 407 | $ | 208 | $ | 51 | $ | (170 | ) | $ | 496 | |||||||||
| Effective income tax rate | 40.9 | % | 39.9 | % | 29.0 | % | 41.5 | % | 38.7 | % | ||||||||||
(A) Included in Power’s results for 2000 are the results of PSE&G’s generation business prior to the generation-related asset transfer in August 2000. For additional information see Note 19. Financial Information by Business Segments.
PSEG, PSE&G, Power and Energy Holdings
Each of PSEG, PSE&G, Power and Energy Holdings 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 irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from PSE&G’s customers in the future. Accordingly, an offsetting regulatory asset was established. As of December 31, 2002, PSE&G had a deferred tax liability and an offsetting regulatory asset of $328 million representing the tax costs expected to be recovered through rates based upon established regulatory practices which permit recovery of current taxes payable. This amount was determined using the enacted Federal income tax rate of 35% and State income tax rate of 9%.
Energy Holdings
Energy Holdings’ effective tax rate differs from the statutory Federal income tax rate of 35% primarily due to the imposition of state taxes and the fact that Global accounts for many of its foreign investments using the equity method of accounting. Under such accounting method, Global reflects in revenues its pro-rata share of the investment’ s net income. The foreign income taxes are a component of each PSEG and Energy Holdings’ equity in earnings rather than included as a component of the income tax provision.
171
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
The following is an analysis of deferred income taxes:
| PSE&G | Power | Energy Holdings |
Other | Consolidated | ||||||||||||||||||||||||||||||
| |
||||||||||||||||||||||||||||||||||
| 2002 | 2001 | 2002 | 2001 | 2002 | 2001 | 2002 | 2001 | 2002 | 2001 | |||||||||||||||||||||||||
| Deferred Income Taxes | (Millions) | |||||||||||||||||||||||||||||||||
| |
||||||||||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||||||||||
| Current (net) | $ | 16 | $ | 21 | $ –– | $ –– | $ –– | $ –– | $ –– | $ –– | $ | 16 | $ | 21 | ||||||||||||||||||||
| Non-current: | ||||||||||||||||||||||||||||||||||
| Unrecovered Investment Tax Credits | 19 | 19 | –– | –– | –– | –– | –– | –– | 19 | 19 | ||||||||||||||||||||||||
| Nuclear Decommissioning | –– | –– | 26 | 25 | –– | –– | –– | –– | 26 | 25 | ||||||||||||||||||||||||
| SFAS 133 | –– | –– | 2 | 3 | 45 | 14 | 9 | 2 | 56 | 19 | ||||||||||||||||||||||||
| Other Comprehensive Income | 122 | –– | 58 | –– | 3 | –– | 24 | –– | 207 | –– | ||||||||||||||||||||||||
| New Jersey Corporate Business Tax | 380 | 407 | 125 | 137 | (5 | ) | (13 | ) | –– | –– | 500 | 531 | ||||||||||||||||||||||
| OPEB | 99 | 83 | –– | –– | –– | –– | –– | –– | 99 | 83 | ||||||||||||||||||||||||
| Cost of Removal | –– | –– | 51 | 54 | –– | –– | –– | –– | 51 | 54 | ||||||||||||||||||||||||
| Investment Related Adjustments | –– | –– | –– | –– | 270 | –– | –– | –– | 270 | –– | ||||||||||||||||||||||||
| Development Fees | –– | –– | –– | –– | 22 | 21 | –– | –– | 22 | 21 | ||||||||||||||||||||||||
| Foreign Currency Translation | –– | –– | –– | –– | 34 | 29 | –– | –– | 34 | 29 | ||||||||||||||||||||||||
| Contractual Liabilities and | ||||||||||||||||||||||||||||||||||
| Environmental Costs | –– | –– | 35 | 35 | –– | –– | –– | –– | 35 | 35 | ||||||||||||||||||||||||
| Market Transition Charge | 64 | 56 | –– | –– | –– | –– | –– | –– | 64 | 56 | ||||||||||||||||||||||||
| Total Non-current | 684 | 565 | 297 | 254 | 369 | 51 | 33 | 2 | 1,383 | 872 | ||||||||||||||||||||||||
| Total Assets | 700 | 586 | 297 | 254 | 369 | 51 | 33 | 2 | 1,399 | 893 | ||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||||
| Non-current: | ||||||||||||||||||||||||||||||||||
| Plant Related Items | 1,244 | 1,228 | (276 | ) | (341 | ) | –– | –– | 5 | 3 | 973 | 890 | ||||||||||||||||||||||
| Securitization | 1,545 | 1,594 | –– | –– | –– | –– | –– | –– | 1,545 | 1,594 | ||||||||||||||||||||||||
| Leasing Activities | –– | –– | –– | –– | 1,298 | 1,146 | –– | –– | 1,298 | 1,146 | ||||||||||||||||||||||||
| Partnership Activities | –– | –– | –– | –– | 66 | 73 | –– | –– | 66 | 73 | ||||||||||||||||||||||||
| Conservation Costs | 10 | 24 | –– | –– | –– | –– | –– | –– | 10 | 24 | ||||||||||||||||||||||||
| Pension Costs | 84 | 70 | 25 | 15 | (3) | –– | 15 | 9 | 121 | 94 | ||||||||||||||||||||||||
| Taxes Recoverable Through | ||||||||||||||||||||||||||||||||||
| Future Rates (net) | 145 | 130 | –– | –– | –– | –– | –– | –– | 145 | 130 | ||||||||||||||||||||||||
| Income from Foreign Operation | –– | –– | –– | –– | 42 | 41 | –– | –– | 42 | 41 | ||||||||||||||||||||||||
| Other | 38 | 14 | (4 | ) | 1 | 1 | (6 | ) | 4 | 6 | 39 | 15 | ||||||||||||||||||||||
| Total Non-current | 3,066 | 3,060 | (255 | ) | (325 | ) | 1,404 | 1,254 | 24 | 18 | 4,239 | 4,007 | ||||||||||||||||||||||
| Total Liabilities | 3,066 | 3,060 | (255 | ) | (325 | ) | 1,404 | 1,254 | 24 | 18 | 4,239 | 4,007 | ||||||||||||||||||||||
| Summary — Accumulated | ||||||||||||||||||||||||||||||||||
| Deferred Income Taxes: | ||||||||||||||||||||||||||||||||||
| Net Current Assets | 16 | 21 | –– | –– | –– | –– | –– | –– | 16 | 21 | ||||||||||||||||||||||||
| Net Non-current Liability | 2,382 | 2,495 | (552 | ) | (579 | ) | 1,035 | 1,203 | (9 | ) | 16 | 2,856 | 3,135 | |||||||||||||||||||||
| Total | $ | 2,366 | $ | 2,474 | $ | (552 | ) | $ | (579 | ) | $ | 1,035 | $ | 1,203 | $ | (9 | ) | $ | 16 | $ | 2,840 | $ | 3,114 | |||||||||||
172 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 17. Pension, Other Postretirement Benefit (OPEB) and Savings Plans
PSEG sponsors several qualified and nonqualified pension plans and other postretirement benefit plans covering PSEG, as well as its participating affiliates, current and former employees who meet certain eligibility criteria. The following table provides a reconciliation of the changes in the fair value of plan assets over each of the two years in the period ended December 31, 2002 and a reconciliation of the funded status at the end of both years.
Pension and Other Postretirement Benefit Plans
| Pension Benefits | Other Benefits | |||||||||||
| 2002 | 2001 | 2002 | 2001 | |||||||||
| (Millions) | (Millions) | |||||||||||
| Change in Benefit Obligation: | ||||||||||||
| Benefit Obligation at Beginning of Year | $ | 2,676 | $ | 2,494 | $ | 674 | $ | 703 | ||||
| Service Cost | 69 | 63 | 18 | 16 | ||||||||
| Interest Cost | 188 | 182 | 47 | 47 | ||||||||
| Actuarial (Gain)/Loss | 162 | 90 | 84 | 8 | ||||||||
| Benefits Paid | (156 | ) | (153 | ) | (48 | ) | (40 | ) | ||||
| Plan Amendments | 7 | –– | –– | (60 | ) | |||||||
| Business Combinations | 22 | –– | 2 | –– | ||||||||
| Benefit Obligation at End of Year | 2,968 | 2,676 | 777 | 674 | ||||||||
| Change in Plan Assets: | ||||||||||||
| Fair Value of Assets at Beginning of Year | 2,228 | 2,376 | 40 | 28 | ||||||||
| Actual Return on Plan Assets | (192 | ) | (85 | ) | (3 | ) | (1 | ) | ||||
| Employer Contributions | 240 | 90 | 61 | 53 | ||||||||
| Benefits Paid | (156 | ) | (153 | ) | (48 | ) | (40 | ) | ||||
| Business Combinations | 11 | –– | 1 | –– | ||||||||
| Fair Value of Assets at End of Year | 2,131 | 2,228 | 51 | 40 | ||||||||
| Reconciliation of Funded Status: | ||||||||||||
| Funded Status | (837 | ) | (448 | ) | (726 | ) | (634 | ) | ||||
| Unrecognized Net | ||||||||||||
| Transition Obligation | 5 | 12 | 248 | 276 | ||||||||
| Prior Service Cost | 104 | 114 | –– | –– | ||||||||
| (Gain) Loss | 1,003 | 456 | (25 | ) | (120 | ) | ||||||
| Net Amount Recognized | $ | 275 | $ | 134 | $ | (503 | ) | $ | (478 | ) | ||
| Amounts Recognized in Statement of | ||||||||||||
| Financial Position: | ||||||||||||
| Prepaid Benefit Cost | $ | 3 | $ | 160 | $ –– | $ –– | ||||||
| Accrued Cost | (343 | ) | (53 | ) | (503 | ) | (478 | ) | ||||
| Intangible Asset | 114 | 20 | N/A | N/A | ||||||||
| Accumulated Other Comprehensive Income (pre-tax) | 501 | 7 | N/A | N/A | ||||||||
| Net Amount Recognized | $ | 275 | $ | 134 | $ | (503 | ) | $ | (478 | ) | ||
| Separate Disclosure for Pension Plans With | ||||||||||||
| Accumulated Benefit Obligation in Excess of | ||||||||||||
| Plan Assets: | ||||||||||||
| Projected Benefit Obligation at End of Year | $ | 2,946 | $ | 76 | ||||||||
| Accumulated Benefit Obligation at End of Year | $ | 2,451 | $ | 61 | ||||||||
| Fair Value of Assets at End of Year | $ | 2,113 | $ | 8 | ||||||||
173
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
The pension benefits table above provides information relating to the funded status of all qualified and nonqualified pension plans and other postretirement benefit plans on an aggregate basis.
| Pension Benefits | Other Benefits | |||||||||||||||||
| 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |||||||||||||
| (Millions) | (Millions) | |||||||||||||||||
| Components of Net Periodic Benefit Cost: | ||||||||||||||||||
| Service Cost | $ | 69 | $ | 63 | $ | 60 | $ | 19 | $ | 16 | $ | 12 | ||||||
| Interest Cost | 188 | 182 | 173 | 47 | 47 | 54 | ||||||||||||
| Expected Return on Plan Assets | (206 | ) | (211 | ) | (221 | ) | (4 | ) | (3 | ) | (3 | ) | ||||||
| Amortization of Net | ||||||||||||||||||
| Transition Obligation | 8 | 8 | 8 | 27 | 27 | 31 | ||||||||||||
| Prior Service Cost | 17 | 16 | 14 | –– | –– | 2 | ||||||||||||
| (Gain)/Loss | 13 | –– | 1 | (4 | ) | (6 | ) | (3 | ) | |||||||||
| Net Periodic Benefit Cost | $ | 89 | $ | 58 | $ | 35 | $ | 85 | $ | 81 | $ | 93 | ||||||
| Components of Total Benefit Expense: | ||||||||||||||||||
| Net Periodic Benefit Cost | $ | 89 | $ | 58 | $ | 35 | $ | 85 | $ | 81 | $ | 93 | ||||||
| Effect of Regulatory Asset | –– | –– | –– | 19 | 19 | 19 | ||||||||||||
| Total Benefit Expense Including Effect of | ||||||||||||||||||
| Regulatory Asset | $ | 89 | $ | 58 | $ | 35 | $ | 104 | $ | 100 | $ | 112 | ||||||
| Components of Other Comprehensive Income: | ||||||||||||||||||
| Decrease in Intangible Asset | $ | (95 | ) | $ | 3 | $ | 1 | |||||||||||
| Increase in Additional Minimum Liability | 589 | 1 | (2 | ) | ||||||||||||||
| Other Comprehensive Income (pre-tax) | $ | 494 | $ | 4 | $ | (1 | ) | N/A | N/A | N/A | ||||||||
| Weighted-Average Assumptions as of December 31: | ||||||||||||||||||
| Discount Rate | 6.75 | % | 7.25 | % | 7.50 | % | 6.75 | % | 7.25 | % | 7.50 | % | ||||||
| Expected Return on Plan Assets | 9.00 | % | 9.00 | % | 9.00 | % | 9.00 | % | 9.00 | % | 9.00 | % | ||||||
| Rate of Compensation Increase | 4.69 | % | 4.69 | % | 4.69 | % | 4.69 | % | 4.69 | % | 4.69 | % | ||||||
| Rate of Increase in Health Benefit Costs | ||||||||||||||||||
| Administrative Expense | 5.00 | % | 5.00 | % | 5.00 | % | ||||||||||||
| Dental Costs | 6.00 | % | 6.00 | % | 6.00 | % | ||||||||||||
| Pre-65 Medical Costs | ||||||||||||||||||
| Immediate Rate | 9.00 | % | 9.50 | % | 10.00 | % | ||||||||||||
| Ultimate Rate | 6.00 | % | 6.00 | % | 6.00 | % | ||||||||||||
| Year Ultimate Rate Reached | 2008 | 2008 | 2008 | |||||||||||||||
| Post-65 Medical Costs | ||||||||||||||||||
| Immediate Rate | 7.00 | % | 7.50 | % | 8.00 | % | ||||||||||||
| Ultimate Rate | 6.00 | % | 6.00 | % | 6.00 | % | ||||||||||||
| Year Ultimate Rate Reached | 2004 | 2004 | 2004 | |||||||||||||||
| Effect of a Change in the Assumed Rate of | ||||||||||||||||||
| Increase in Health Benefit Costs: | ||||||||||||||||||
| Effect of a 1% Increase On | ||||||||||||||||||
| Total of Service Cost and Interest Cost | 4.7 | 4.6 | 4.5 | |||||||||||||||
| Postretirement Benefit Obligation | 45.7 | 45.4 | 48.5 | |||||||||||||||
| Effect of a 1% Decrease On | ||||||||||||||||||
| Total of Service Cost and Interest Cost | (4.0 | ) | (3.9 | ) | (3.8 | ) | ||||||||||||
| Postretirement Benefit Obligation | (38.9 | ) | (39.1 | ) | (41.4 | ) | ||||||||||||
174
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
401K Plans
PSEG sponsors two defined contribution plans. Eligible represented employees of PSE&G, Power and Services participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSE&G, Power, Energy Holdings and Services participate 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 50% 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 or PSEG common stock equal to 50% of such employee contributions. For periods prior to March 1, 2002, employer contributions, related to participant contributions in excess of 5% and up to 7%, were made in shares of PSEG common stock for Savings Plan participants. For periods prior to March 1, 2002, Employer contributions, related to participant contributions in excess of 6% and up to 8%, were made in shares of PSEG common stock for Thrift Plan participants. The shares for these contributions were purchased in the open market. Beginning on March 1, 2002, and thereafter, all Employer contributions will be made in cash to each plan. The amount expensed for Employer matching contributions to the plans was approximately $25 million, $24 million, and $22 million in 2002, 2001 and 2000, respectively.
PSE&G, Power, Energy Holdings and Services eligible employees participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described above.
PSE&G
PSE&G’s pension costs amounted to $46 million, $30 million and $17 million for the years ended December 31, 2002, 2001 and 2000, respectively. For 2002, this amount represented approximately 52% of PSEG’s total consolidated pension costs. PSE&G’s Thrift Plan and Savings Plan matching costs amounted to approximately $13 million, $12 million and $11 million for the years ended December 31, 2002, 2001 and 2000, respectively. PSE&G’s OPEB costs amounted to $95 million, $95 million, and $109 million for the years ended December 31, 2002, 2001, and 2000, respectively. For 2002, this amount represented approximately 92% of PSEG’s total consolidated OPEB costs.
Power
Power’s pension costs amounted to $26 million, $16 million and $9 million for the years ended December 31, 2002, 2001 and 2000, respectively. For 2002, this amount represented approximately 29% of PSEG’s total consolidated pension costs. Power’s Thrift Plan and Savings Plan matching costs amounted to approximately $8 million, $8 million and $8 million for the years ended December 31, 2002, 2001 and 2000, respectively. Power’s OPEB costs amounted to $6 million, $4 million, and $2 million for the years ended December 31, 2002, 2001, and 2000, respectively. For 2002, this amount represented approximately 6% of PSEG’s total consolidated OPEB costs.
Energy Holdings
Energy Holdings’ pension costs amounted to $2 million and $1 million for the years ended December 31, 2002 and 2001, respectively. For 2002, this amount represented approximately 4% of PSEG’s total consolidated pension costs. Energy Holdings’ Thrift Plan and Savings Plan matching costs amounted to approximately $1 million for each of the years ended December 31, 2002, 2001 and 2000. Energy Holdings OPEB costs amounted to less than $1 million for each of the years ended December 31, 2002, 2001 and 2000.
175
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 18. Stock Options and Employee Stock Purchase Plan
PSEG
Stock Options
Under PSEG’s 1989 Long-Term Incentive Plan (1989 LTIP) and its 2001 Long-Term Incentive Plan (2001 LTIP), non-qualified options to acquire shares of common stock may be granted to officers and other key employees of PSEG, PSE&G, Power, Energy Holdings and Services selected by the Organization and Compensation Committee of PSEG’s Board of Directors, the plan’s administrative committee (Committee). In addition, certain key executives have received option grants under the 1989 LTIP in connection with their employment agreements. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the Committee, by delivering previously acquired shares of PSEG common stock. In instances where an optionee tenders shares acquired from a grant previously exercised that were held for a period of less than six months, an expense will be recorded for the difference between the fair market value at exercise date and the option price. Options are exercisable over a period of time designated by the Committee (but not prior to one year from the date of grant) and are subject to such other terms and conditions as the Committee determines. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change in control. Options may not be transferred during the lifetime of a holder.
The 1989 LTIP currently provides for the issuance of up to 8,000,000 options to purchase shares of common stock. At December 31, 2002, there were 3,817,717 options available for future grants under the 1989 LTIP.
The 2001 LTIP currently provides for the issuance of up to 15,000,000 options to purchase shares of common stock. At December 31, 2002, there were 9,241,500 options available for future grants under the 2001 LTIP.
PSEG purchases shares on the open market to meet the exercise of stock options. The difference between the cost of the shares (generally purchased on the date of exercise) and the exercise price of the options has been reflected in Stockholders’ Equity except where otherwise discussed.
Changes in common shares under option for the three fiscal years in the period ended December 31, 2002 are summarized as follows:
| 2002 | 2001 | 2000 | |||||||||||||||
| |
|
| |||||||||||||||
| Options | Weighted Average Exercise Price |
Options | Weighted Average Exercise Price |
Options | Weighted Average Exercise Price | ||||||||||||
| Beginning of year | 7,652,463 | $ | 41.22 | 5,186,099 | $ | 40.38 | 2,561,883 | $ | 34.60 | ||||||||
| Granted | 1,890,000 | 31.62 | 2,833,000 | 41.84 | 2,745,500 | 45.33 | |||||||||||
| Exercised | (157,332 | ) | 36.28 | (303,135 | ) | 32.83 | (110,684 | ) | 29.87 | ||||||||
| Canceled | (192,500 | ) | 41.94 | (63,501 | ) | 41.27 | (10,600 | ) | 31.23 | ||||||||
| End of year | 9,192,631 | 39.32 | 7,652,463 | 41.22 | 5,186,099 | 40.38 | |||||||||||
| Exercisable at end of year | 4,542,165 | $ | 40.24 | 2,767,830 | $ | 39.19 | 1,170,278 | $ | 34.91 | ||||||||
| Weighted average fair | |||||||||||||||||
| value of options granted | |||||||||||||||||
| during the year | $ | 4.37 | $ | 7.22 | $ | 8.73 | |||||||||||
176
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
The following table provides information about options outstanding at December 31, 2002:
| Options Outstanding | Options Exercisable | |||||||||||||
| Range of
Exercise Prices |
Outstanding
at December 31, 2002 |
Weighted Average Remaining Contractual Life |
Weighted Average Exercise Price |
Exercisable
at December 31, 2002 |
Weighted Average Exercise Price | |||||||||
| $ | 25.03— $ 30.02 | 173,300 | 5.0 years | $ | 29.56 | 173,300 | $ | 29.56 | ||||||
| $ | 30.03— $ 35.03 | 2,930,331 | 8.9 years | 32.05 | 1,070,331 | 33.13 | ||||||||
| $ | 35.04— $ 40.03 | 690,500 | 6.0 years | 39.31 | 690,500 | 39.31 | ||||||||
| $ | 40.04— $ 45.04 | 3,169,000 | 8.6 years | 41.83 | 1,306,716 | 42.16 | ||||||||
| $ | 45.05— $ 50.05 | 2,229,500 | 8.1 years | 46.06 | 1,301,318 | 46.07 | ||||||||
| $ | 25.03— $ 50.05 | 9,192,631 | 8.3 years | $ | 39.32 | 4,542,165 | $ | 40.24 | ||||||
For this purpose, the fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for grants in 2002, 2001, and 2000, respectively: expected volatility of 30.24%, 28.22% and 26.63%, risk free interest rates of 2.82%, 4.40% and 6.06%, expected lives of 4.0 years, 4.2 years and 4.4 years, respectively. There was a dividend yield of 6.84% in 2002, 5.18% in 2001 and 4.77% in 2000.
PSEG applies APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for stock-based compensation plans, which are described below. Accordingly, no compensation cost has been recognized for fixed stock option grants since the exercise price of the stock options equaled the market price of the underlying stock on the date of grant. Had compensation costs for stock option grants been determined based on the fair value at the grant dates for awards under these plans in accordance with SFAS No. 123 “Accounting for Stock-Based Compensation,” there would have been a charge to net income of approximately $10.4 million, $9.6 million and $3.6 million in 2002, 2001 and 2000, respectively, with a $(0.05), $(0.05) and $(0.02) impact on earnings per share in 2002, 2001 and 2000, respectively.
The following table illustrates the effect on net income and earnings per share if PSEG had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation:
| Year Ended December 31, | |||||||||
| 2002 | 2001 | 2000 | |||||||
| (Millions) | |||||||||
| Net Income, as reported | $ | 245 | $ | 770 | $ | 764 | |||
| Deduct: Total stock-based employee | |||||||||
| compensation expense determined | |||||||||
| under fair value based method for | |||||||||
| all awards, net of related tax effects | (10 | ) | (10 | ) | (4 | ) | |||
| Pro forma Net Income | $ | 235 | $ | 760 | $ | 760 | |||
| Earnings per share: | |||||||||
| Basic and Diluted – as reported | $ | 1.17 | $ | 3.70 | $ | 3.55 | |||
| Basic and Diluted – pro forma | $ | 1.12 | $ | 3.65 | $ | 3.53 | |||
Diluted Earning Per Share
Diluted earning per share assumes the issuance of potentially dilutive common shares outstanding during the period and the repurchase of common shares that would have occurred with proceeds from the assumed issuance.
177
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
These potentially dilutive instruments include stock options, vesting of non-vested stock awards, and certain convertible preferred securities.
As shown in the tables above, as of December 31, 2002, options to purchase approximately 9.2 million shares of common stock at an average price of $39.32 per share were outstanding during 2002. These securities were not included in the computation of diluted EPS because these options’ exercise price was greater than the average market price of common shares, thus making these securities anti-dilutive.
Stock Compensation
Executive Officers
In June 1998, the Committee granted 150,000 shares of restricted common stock to a key executive. An additional 60,000 shares of restricted stock was granted to this executive in November 2001. These shares are subject to restrictions on transfer and subject to risk of forfeiture until earned by continued employment. The shares vest on a staggered schedule beginning on March 31, 2002 and become fully vested on March 31, 2007. The unearned compensation related to this restricted stock grant as of December 31, 2002 is approximately $4 million and is included in retained earnings on the consolidated balance sheets.
In addition, in July 2001, the Committee granted 100,000 shares of restricted common stock to another key executive. These shares are subject to restrictions on transfer and subject to risk of forfeiture until earned by continued employment. The shares vest at one-third per year and become fully vested on July 1, 2004. The unearned compensation related to this restricted stock grant as of December 31, 2002 is approximately $2 million and is included in retained earnings on the consolidated balance sheets.
Outside Directors
During 2002, a director who was not an officer of PSEG or its subsidiaries and affiliates was paid an annual retainer of $30,000 and a fee of $1,500 for attendance at any Board or committee meeting, inspection trip, conference or other similar activity relating to PSEG or PSE&G. This amount was raised to $40,000 effective for 2003. Pursuant to the Compensation Plan for Outside Directors, a certain percentage, currently fifty percent, of the annual retainer is paid in PSEG Common Stock. No additional retainer is paid for service as a director of PSE&G. Each Committee Chair received an additional annual retainer of $3,000, increased for 2003 to $5,000 except for the Chair of the Audit Committee, who will receive $10,000. In addition, beginning in 2003, each member of the Audit Committee will receive an annual retainer of $5,000. In January 2003, PSEG amended the Compensation Plan for Outside Directors pursuant to which 100,000 shares of Common Stock may be awarded to directors of PSEG who are not employees of PSEG or its subsidiaries.
PSEG also maintains a Stock Plan for Outside Directors pursuant to which directors of PSEG who are not employees of PSEG or its subsidiaries receive shares of restricted stock for each year of service as a director. For 2002, this amount was 600 shares, increased to 800 shares for 2003. The restrictions on the stock granted under the Stock Plan for Outside Directors provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director’s service were terminated after a “change in control” as defined in the Plan or if the director were to die in office. PSEG also has the ability to waive these restrictions for good cause shown. Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director, and the director has the right to vote the shares. The fair value of these shares is recorded as compensation expense in the Consolidated Statements of Operations. In January 2003, PSEG adopted the Stock Plan for Outside Directors pursuant to which 100,000 shares of Common Stock may be awarded as restricted stock to directors of PSEG who are not employees of PSEG or its subsidiaries.
178
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Employee Stock Purchase Plan
PSEG maintains an employee stock purchase plan for all eligible employees of PSEG, PSE&G, Power, Energy Holdings and Services. Under the plan, shares of the common stock may be purchased at 95% of the fair market value through payroll deductions. Employees may purchase shares having a value not exceeding 10% of their base pay. During 2002, 2001, and 2000, employees purchased 104,627, 85,552, and 101,986 shares at an average price of $36.41, $44.02, and $37.06 per share, respectively. At December 31, 2002, 169,456 shares were available for future issuance under this plan. In January 2003, an additional 2,000,000 shares were authorized for this plan.
Note 19. Financial Information by Business Segments
Basis of Organization
PSEG, PSE&G, Power and Energy Holdings
The reportable segments were determined by management in accordance with SFAS No. 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 each business.
The majority of operations within the business segment Energy Technologies were reclassified into discontinued operations during 2002. The DSM investments, which were the only remaining continuing operations of Energy Technologies, were transferred to Resources effective December 31, 2002. Therefore, Energy Technologies is no longer reported as a separate segment. The amounts related to Energy Technologies are included in Energy Holdings’ Other Activities and all prior periods have been restated to conform to the current year’s presentation.
Power
Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load serving entities (LSEs) and by bidding the energy, capacity and ancillary services of Power into the market. Power also enters into trading contracts for energy capacity, firm transmission rights, gas, emission allowances and other energy related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations.
Power’s business has evolved during 2002. With the transfer of the BGSS contract to Power and the commencement of the new BGS contracts with wholesale electric suppliers, Power’s business has become a fully integrated wholesale energy supply business. As a result of that evolution of Power’s business, trading activities changed from a stand-alone operation to a function that has become fully integrated with the wholesale energy supply business and primarily serves to optimize the value of that business. Therefore, upon review and in accordance with SFAS 131, PSEG determined that Power’s generation and trading components no longer meet the definition of separate operating segments for financial reporting purposes and PSEG has reported Power’s financial position and results of operations as one segment. All prior periods have been reclassified to conform to the current presentation.
PSE&G
PSE&G earns revenue from its tariffs under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from a variety of other activities such as sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.
179
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Energy Holdings
Global
Global earns revenues from its investment in and operation of projects in the generation and distribution of energy, both domestically and internationally. Global has ownership interests in four distribution companies (excluding those in Argentina which were fully impaired during 2002) which serve approximately 2.9 million customers and has developed or acquired interests in electric generation facilities which sell energy, capacity and ancillary services to numerous customers. The generation plants sell power under long-term agreements as well as on a merchant basis while the distribution companies are rate-regulated enterprises.
Resources
Resources earns revenues from its passive investments in leveraged leases, limited partnerships, leveraged buyout funds and marketable securities. Over 75% of Resources’ investments are in energy industry related leveraged leases. DSM Investments were transferred to Resources on December 31, 2002 and earn revenues primarily from monthly payments from utilities, representing shared electricity savings from the installation of energy efficient equipment. Resources operates both domestically and internationally, however, revenues from all international investments are denominated in US dollars.
Other
Energy Holdings’ other activities include amounts applicable to Energy Holdings (parent company), the HVAC/operating companies of Energy Technologies, which were reclassified into discontinued operations in 2002, and EGDC. The net losses primarily relate to financing and certain administrative and general costs at the Energy Holdings parent corporation.
Other
PSEG’s other activities include amounts applicable to PSEG (parent corporation), and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions, rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 22. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at the PSEG parent corporation.
180
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Information related to the segments of PSEG’s and its subsidiaries is detailed below:
| Energy Holdings | |||||||||||||||||||||
| Power | PSE&G | Resources | Global | Other | Other | Consolidated Total |
|||||||||||||||
| (Millions) | |||||||||||||||||||||
| For the Year Ended December 31, 2002: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Total Operating Revenues | $ | 3,670 | $ | 5,919 | $ | 247 | $ | 501 | $ | 1 | $ | (1,948 | ) | $ | 8,390 | ||||||
| Depreciation and Amortization | 108 | 409 | 5 | 29 | 1 | 19 | 571 | ||||||||||||||
| Operating Income (Loss) | 903 | 713 | 213 | (296 | ) | (12 | ) | 5 | 1,526 | ||||||||||||
| Interest Income | — | 17 | — | — | — | 2 | 19 | ||||||||||||||
| Net Interest Charges | 122 | 406 | 99 | 115 | — | 41 | 783 | ||||||||||||||
| Income (Loss) Before Income Taxes | 781 | 320 | 121 | (465 | ) | (13 | ) | (80 | ) | 664 | |||||||||||
| Income Taxes | 313 | 115 | 37 | (184 | ) | (3 | ) | (30 | ) | 248 | |||||||||||
| Equity in Earnings
of Unconsolidated Subsidiaries |
— | — | 1 | 58 | — | — | 59 | ||||||||||||||
| Income (Loss) Before Discontinued | |||||||||||||||||||||
| Operations and Cumulative Effect of a | |||||||||||||||||||||
| Change in Accounting Principle | 468 | 201 | 84 | (285 | ) | (8 | ) | (44 | ) | 416 | |||||||||||
| Income (Loss) from Discontinued Operations | — | — | — | (9 | ) | (42 | ) | — | (51 | ) | |||||||||||
| Cumulative Effect of a Change in Accounting Principle | — | — | — | (88 | ) | (32 | ) | — | (120 | ) | |||||||||||
| Segment Earnings (Loss) | 468 | 201 | 78 | (399 | ) | (82 | ) | (21 | ) | 245 | |||||||||||
| As of December 31, 2002: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Total Assets | $ | 6,964 | $ | 12,429 | $ | 3,086 | $ | 3,802 | $ | (50 | ) | $ | (489 | ) | $ | 25,742 | |||||
| Investments in Equity Method Subsidiaries | $ | — | $ | — | $ | 118 | $ | 1,300 | $ | 20 | $ | — | $ | 1,438 | |||||||
| For the Year Ended December 31, 2002: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Gross Additions to Long-Lived Assets | $ | 1,318 | $ | 472 | $ | 37 | $ | 579 | $ | (4 | ) | $ | (64 | ) | $ | 2,338 | |||||
| For the Year Ended December 31, 2001: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Total Operating Revenues | $ | 2,452 | $ | 6,091 | $ | 241 | $ | 396 | $ | 1 | $ | (2,126 | ) | $ | 7,055 | ||||||
| Depreciation and Amortization | 95 | 370 | 4 | 11 | 1 | 15 | 496 | ||||||||||||||
| Operating Income | 787 | 691 | 211 | 243 | (13 | ) | (3 | ) | 1,916 | ||||||||||||
| Interest Income | — | 104 | — | — | — | (67 | ) | 37 | |||||||||||||
| Net Interest Charges | 143 | 450 | 100 | 78 | 2 | (51 | ) | 722 | |||||||||||||
| Income Before Income Taxes | 644 | 324 | 111 | 153 | (9 | ) | (66 | ) | 1,157 | ||||||||||||
| Income Taxes | 250 | 89 | 34 | 35 | (4 | ) | (23 | ) | 381 | ||||||||||||
| Equity in Earnings of Unconsolidated Subsidiaries | — | — | 55 | 143 | — | — | 198 | ||||||||||||||
| Income
(Loss) Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principle |
394 | 230 | 77 | 117 | (5 | ) | (37 | ) | 776 | ||||||||||||
| Income (Loss) from Discontinued | |||||||||||||||||||||
| Operations | — | — | — | 7 | (22 | ) | — | (15 | ) | ||||||||||||
| Cumulative Effect of a Change in Accounting Principle |
— | — | — | 9 | — | — | 9 | ||||||||||||||
| Segment Earnings (Loss) | 394 | 230 | 71 | 116 | (26 | ) | (15 | ) | 770 | ||||||||||||
| As of December 31, 2001: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Total Assets | $ | 5,239 | $ | 12,927 | $ | 3,085 | $ | 4,074 | $ | 280 | $ | (449 | ) | $ | 25,156 | ||||||
| Investments in Equity Method Subsidiaries | $ | — | $ | — | $ | 163 | $ | 1,541 | $ | 19 | $ | — | $ | 1,723 | |||||||
| For the Year Ended December 31, 2001: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Gross Additions to Long-Lived Assets | $ | 1,614 | $ | 395 | $ | 462 | $ | 1,249 | $ | (31 | ) | $ | 16 | $ | 3,705 | ||||||
181
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
| Energy Holdings | |||||||||||||||||||||
| Power (A) | (A) PSE&G |
Resources | Global | Other | Other | Consolidated Total |
|||||||||||||||
| For the Year Ended December 31, 2000: | (Millions) | ||||||||||||||||||||
| |
|||||||||||||||||||||
| Total Operating Revenues | $ | 2,275 | $ | 4,644 | $ | 233 | $ | 169 | $ | 70 | $ | (870 | ) | $ | 6,521 | ||||||
| Depreciation and Amortization | 136 | 209 | 5 | 1 | — | (1 | ) | 350 | |||||||||||||
| Operating Income | 712 | 869 | 207 | 120 | (17 | ) | 16 | 1,907 | |||||||||||||
| Interest Income | 1 | 164 | — | — | — | (143 | ) | 22 | |||||||||||||
| Net Interest Charges | 198 | 348 | 79 | 54 | 1 | (109) | 571 | ||||||||||||||
| Income Before Income Taxes | 521 | 638 | 128 | 69 | (21 | ) | (63 | ) | 1,272 | ||||||||||||
| Income Taxes | 208 | 260 | 47 | 12 | (8 | ) | (23 | ) | 496 | ||||||||||||
| Equity in Earnings of Unconsolidated | |||||||||||||||||||||
| Subsidiaries | — | — | 13 | 157 | — | — | 170 | ||||||||||||||
| Income (Loss) Before Discontinued | |||||||||||||||||||||
| Operations | 313 | 369 | 81 | 58 | (13 | ) | (32 | ) | 776 | ||||||||||||
| Loss from Discontinued Operations | — | — | — | — | (12 | ) | — | (12 | ) | ||||||||||||
| Segment Earnings (Loss) | 313 | 369 | 75 | 40 | (25 | ) | (8 | ) | 764 | ||||||||||||
| (A) | Included in the Power segment for 2000 are the results of the generation business of PSE&G prior to the asset transfer in August 2000. These results through July 31, 2000 are included in PSE&G’s Consolidated Statement of Operations for the year ended December 31, 2000. Because Power’s historical information was derived from historical financial statements of PSE&G, these amounts are also included on Power’s Consolidated Statement of Operations for the year ended December 31, 2000. For segment reporting purposes, these amounts are appropriately classified as Power. Amounts relating to the generation business of PSE&G prior to the asset transfer to Power in August 2000 were as follows: |
| (Millions) | |||
| Operating Revenues | $ | 1,243 | |
| Operating Expenses | |||
| Energy Costs | 410 | ||
| Operations and Maintenance | 357 | ||
| Depreciation and Amortization | 77 | ||
| Total Operating Expenses | 844 | ||
| Operating Income | 399 | ||
| Other Income | 6 | ||
| Interest Expense | (49 | ) | |
| Income Taxes | (147 | ) | |
| Net Income | $ | 209 | |
182
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Geographic information for PSEG is disclosed below. The foreign assets and operations noted below were made solely through Energy Holdings.
| Revenues (A) | Assets (B) | ||||||||||||||
| December 31, | December 31, | ||||||||||||||
| 2002 | 2001 | 2000 | 2002 | 2001 | |||||||||||
| (Millions) | (Millions) | ||||||||||||||
| United States | $ | 7,864 | $ | 6,687 | $ | 6,333 | $ | 21,556 | $ | 20,392 | |||||
| Foreign Countries | 526 | 368 | 188 | 4,186 | 4,764 | ||||||||||
| Total | $ | 8,390 | $ | 7,055 | $ | 6,521 | $ | 25,742 | $ | 25,156 | |||||
| Identifiable assets in foreign countries include: | |||||||||||||||
| Chile | $ | 1,060 | $ | 880 | |||||||||||
| Netherlands | 988 | 911 | |||||||||||||
| Argentina | — | 737 | |||||||||||||
| Peru | 429 | 520 | |||||||||||||
| Tunisia | 322 | 245 | |||||||||||||
| India (C) | 38 | 288 | |||||||||||||
| Poland | 380 | 166 | |||||||||||||
| Brazil | 211 | 282 | |||||||||||||
| Other | 758 | 735 | |||||||||||||
| Total | $ | 4,186 | $ | 4,764 | |||||||||||
| (A) | Revenues are attributed to countries
based on the locations of the investments. Global’s revenue includes
its share of the net income from joint ventures recorded under the equity
method of accounting. |
| (B) | Total assets are net of foreign
currency translation adjustment of $(340) million (pre-tax) as of December
31, 2002 and $(285) million (pre-tax) as of December 31, 2001. |
| (C) | Approximately $257 million at December
31, 2001 relates to Tanir Bavi, which was discontinued as of June 30, 2002
and was sold in October 2002. |
| As
of December 31, 2002, Global and Resources had approximately $2.9 billion
and $1.3 billion, respectively of international assets. As of December 31,
2002, foreign assets represented 16% and 61% of PSEG’s and Energy Holdings’
consolidated assets, respectively, and the revenues related to those foreign
assets contributed 6% and 70% to PSEG’s and Energy Holdings’ consolidated
revenues, respectively, for the year ended December 31, 2002. | |
183 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 20. Property, Plant and Equipment and Jointly Owned Facilities
Information related to Property, Plant and Equipment as of December 31, 2002 and 2001 is detailed below:
| PSE&G | Power | Energy Holdings |
Other | PSEG Consolidated |
|||||||||||||
| 2002 | (Millions) | ||||||||||||||||
| |
|||||||||||||||||
| Generation: | |||||||||||||||||
| Fossil Production | $ | — | $ | 2,467 | $ | 599 | $ | — | $ | 3,066 | |||||||
| Nuclear Production | — | 215 | — | — | 215 | ||||||||||||
| Nuclear Fuel in Service | — | 527 | — | — | 527 | ||||||||||||
| Construction Work in Progress | — | 2,062 | 466 | — | 2,528 | ||||||||||||
| Total Generation | — | 5,271 | 1,065 | — | 6,336 | ||||||||||||
| Transmission and Distribution: | |||||||||||||||||
| Electric Transmission | 1,243 | — | — | — | 1,243 | ||||||||||||
| Electric Distribution | 4,446 | — | 329 | — | 4,775 | ||||||||||||
| Gas Transmission | 74 | — | — | — | 74 | ||||||||||||
| Gas Distribution | 3,271 | — | — | — | 3,271 | ||||||||||||
| Construction Work in Progress | 20 | — | 27 | — | 47 | ||||||||||||
| Plant Held for Future Use | 18 | — | — | — | 18 | ||||||||||||
| Other | 91 | — | — | — | 91 | ||||||||||||
| Total Transmission and Distribution | 9,163 | — | 356 | — | 9,519 | ||||||||||||
| Other | 418 | 76 | 113 | 100 | 707 | ||||||||||||
| Total | $ | 9,581 | $ | 5,347 | $ | 1,534 | $ | 100 | $ | 16,562 | |||||||
| 2001 | |||||||||||||||||
| |
|||||||||||||||||
| Generation: | |||||||||||||||||
| Fossil Production | $ | — | $ | 1,856 | $ | 88 | $ | — | $ | 1,944 | |||||||
| Nuclear Production | — | 154 | — | — | 154 | ||||||||||||
| Nuclear Fuel in Service | — | 486 | — | — | 486 | ||||||||||||
| Construction Work in Progress | — | 1,687 | 312 | — | 1,999 | ||||||||||||
| Total Generation | — | 4,183 | 400 | — | 4,583 | ||||||||||||
| Transmission and Distribution: | |||||||||||||||||
| Electric Transmission | 1,201 | — | — | — | 1,201 | ||||||||||||
| Electric Distribution | 4,254 | — | 577 | — | 4,831 | ||||||||||||
| Gas Transmission | 74 | — | — | — | 74 | ||||||||||||
| Gas Distribution | 3,121 | — | — | — | 3,121 | ||||||||||||
| Construction Work in Progress | 26 | — | 32 | — | 58 | ||||||||||||
| Plant Held for Future Use | 20 | — | — | — | 20 | ||||||||||||
| Other | 89 | — | — | — | 89 | ||||||||||||
| Total Transmission and Distribution | 8,785 | — | 609 | — | 9,394 | ||||||||||||
| Other | 385 | 55 | 172 | 111 | 723 | ||||||||||||
| Total | $ | 9,170 | $ | 4,238 | $ | 1,181 | $ | 111 | $ | 14,700 | |||||||
184
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
PSE&G and Power
PSE&G and Power have ownership interests in and are responsible for providing their share of the necessary financing for the following jointly owned facilities. All amounts reflect the share of PSE&G’s and Power’s jointly owned projects and the corresponding direct expenses are included in Consolidated Statements of Operations as operating expenses.
| December 31, 2002 | Ownership Interest |
Plant | Accumulated Depreciation | |||||||
| |
||||||||||
| Power: | (Millions, where Applicable) | |||||||||
| Coal Generating | ||||||||||
| Conemaugh | 22.50 | % | $ | 203 | $ | 76 | ||||
| Keystone | 22.84 | % | $ | 155 | $ | 56 | ||||
| Nuclear Generating | ||||||||||
| Peach Bottom | 50.00 | % | $ | 225 | $ | 105 | ||||
| Salem | 57.41 | % | $ | 324 | $ | 177 | ||||
| Nuclear Support Facilities | Various | $ | 34 | $ | 13 | |||||
| Pumped Storage Facilities | ||||||||||
| Yards Creek | 50.00 | % | $ | 28 | $ | 16 | ||||
| Merrill Creek Reservoir | 13.91 | % | $ | 2 | $ | — | ||||
| PSE&G: | ||||||||||
| Transmission Facilities | Various | $ | 80 | $ | 33 | |||||
| Linden SNG Plant | 90.00 | % | $ | 5 | $ | 5 | ||||
| December 31, 2001 | ||||||||||
| |
||||||||||
| Power: | ||||||||||
| Coal Generating | ||||||||||
| Conemaugh | 22.50 | % | $ | 199 | $ | 70 | ||||
| Keystone | 22.84 | % | $ | 128 | $ | 51 | ||||
| Nuclear Generating | ||||||||||
| Peach Bottom | 50.00 | % | $ | 263 | $ | 156 | ||||
| Salem | 57.41 | % | $ | 257 | $ | 161 | ||||
| Nuclear Support Facilities | Various | $ | 32 | $ | 9 | |||||
| Pumped Storage Facilities | ||||||||||
| Yards Creek | 50.00 | % | $ | 28 | $ | 12 | ||||
| Merrill Creek Reservoir | 13.91 | % | $ | 2 | $ | — | ||||
| PSE&G: | ||||||||||
| Transmission Facilities | Various | $ | 80 | $ | 30 | |||||
| Linden SNG Plant | 90.00 | % | $ | 5 | $ | 4 | ||||
Power
Power holds undivided ownership interests in the jointly owned facilities above, excluding related nuclear fuel and inventories. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power’s share of expenses for the jointly owned facilities is included in the appropriate expense category.
Power’s subsidiary, PSEG Nuclear LLC (Nuclear) co-owns Salem and Peach Bottom with Exelon Generation Company, LLC. Nuclear is the owner-operator of Salem and Exelon Generation Company, LLC is the operator of Peach Bottom. A committee appointed by the co-owners reviews/approves major planning, financing and budgetary (capital and operating) decisions. Operating decisions within the above guidelines are made by the owner-operator.
Reliant Resources is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by all co-owners makes all planning, financing and budgetary (capital and operating) decisions. Operating decisions within the above guidelines are made by Reliant Resources.
185
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. First Energy is also a co-owner and the operator of this facility. First Energy submits separate capital and Operations and Maintenance budgets, subject to the approval of Power.
Power is a minority owner in the Merrill Creek Reservoir. Merrill Creek Reservoir is the owner-operator of this facility. The operator submits separate capital and Operations and Maintenance budgets, subject to the approval of the non-operating owners.
All owners receive revenues, Operations and Maintenance and capital allocations based on their ownership percentages. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.
Note 21. Selected Quarterly Data (Unaudited)
The information shown below, in the opinion of PSEG, PSE&G, Power and Energy Holdings, includes all adjustments, consisting only of normal recurring accruals, necessary to a fair presentation of such amounts.
| Calendar Quarter Ended | ||||||||||||||||||||||||||||||
| March 31, | June 30, | September 30, | December 31, | |||||||||||||||||||||||||||
| 2002 | 2001 | 2002 | 2001 | 2002 | 2001 | 2002 | 2001 | |||||||||||||||||||||||
| PSEG Consolidated: | (Millions, where Applicable) | |||||||||||||||||||||||||||||
| Operating Revenues | $ | 1,914 | $ | 2,186 | $ | 1,469 | $ | 1,216 | $ | 2,328 | $ | 1,615 | $ | 2,679 | $ | 2,038 | ||||||||||||||
| Operating Income | 538 | 586 | (129 | ) | 415 | 529 | 429 | 588 | 486 | |||||||||||||||||||||
| Income
before Discontinued Operations and Cumulative Effect of a Change in Accounting Principle |
181 | 256 | (227 | ) | 153 | 207 | 175 | 255 | 192 | |||||||||||||||||||||
| Income (loss) from Discontinued Operations |
(1 | ) | (4 | ) | (37 | ) | (10 | ) | (3 | ) | (3 | ) | (10 | ) | 2 | |||||||||||||||
| Cumulative Effect
of a Change in Accounting Principle |
(120 | ) | 9 | –– | –– | –– | –– | –– | –– | |||||||||||||||||||||
| Net Income (Loss) | 60 | 261 | (264 | ) | 143 | 204 | 172 | 245 | 194 | |||||||||||||||||||||
| Earnings per Share | ||||||||||||||||||||||||||||||
| (Basic and Diluted) | 0.29 | 1.25 | (1.28 | ) | 0.68 | 0.99 | 0.83 | 1.14 | 0.95 | |||||||||||||||||||||
| Weighted Average
Common Shares and Potential Dilutive Effect of Stock Options Outstanding |
206 | 208 | 207 | 209 | 207 | 208 | 216 | 208 | ||||||||||||||||||||||
| PSE&G: | ||||||||||||||||||||||||||||||
| Operating Revenues | $ | 1,659 | $ | 1,952 | $ | 1,230 | $ | 1,311 | $ | 1,405 | $ | 1,395 | $ | 1,625 | $ | 1,433 | ||||||||||||||
| Operating Income | 210 | 247 | 107 | 146 | 184 | 159 | 212 | 139 | ||||||||||||||||||||||
| Net Income | 68 | 112 | 8 | 32 | 56 | 65 | 73 | 26 | ||||||||||||||||||||||
| Earnings Available to PSEG | 67 | 109 | 7 | 31 | 55 | 65 | 72 | 25 | ||||||||||||||||||||||
| Power: | ||||||||||||||||||||||||||||||
| Operating Revenues | $ | 577 | $ | 612 | $ | 693 | $ | 322 | $ | 1,092 | $ | 685 | $ | 1,308 | $ | 833 | ||||||||||||||
| Operating Income | 228 | 236 | 172 | 201 | 241 | 173 | 262 | 177 | ||||||||||||||||||||||
| Net Income | 120 | 102 | 83 | 104 | 121 | 87 | 144 | 101 | ||||||||||||||||||||||
| Energy Holdings: | ||||||||||||||||||||||||||||||
| Operating Revenues | $ | 166 | $ | 128 | $ | 166 | $ | 94 | $ | 212 | $ | 159 | $ | 205 | $ | 257 | ||||||||||||||
| Operating Income | 101 | 104 | (411 | ) | 70 | 103 | 94 | 112 | 173 | |||||||||||||||||||||
| Income before Discontinued
Operations and Cumulative Effect of a Change in Accounting Principle |
6 | 55 | (310 | ) | 27 | 43 | 32 | 52 | 75 | |||||||||||||||||||||
| (Loss) Income from Discontinued Operations |
(1 | ) | (4 | ) | (37 | ) | (10 | ) | (3 | ) | (3 | ) | (10 | ) | 2 | |||||||||||||||
| Cumulative Effect of a Change in | ||||||||||||||||||||||||||||||
| Accounting Principle | (120 | ) | 9 | –– | –– | –– | –– | –– | –– | |||||||||||||||||||||
| Net (Loss) Income | (115 | ) | 60 | (347 | ) | 17 | 40 | 29 | 42 | 77 | ||||||||||||||||||||
| (Loss) Earnings Available to PSEG | (121 | ) | 54 | (352 | ) | 12 | 34 | 23 | 36 | 72 | ||||||||||||||||||||
186
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 22. Related-Party Transactions
Affiliate Loans
These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s consolidated financial statements.
PSEG and PSE&G
On January 31, 2001, PSE&G loaned approximately $1.1 billion to PSEG at 14.23% per annum and recorded interest income of approximately $33 million relating to the loan in 2001. PSEG repaid the loan on April 16, 2001. PSE&G also returned approximately $2.3 billion of capital to PSEG on January 31, 2001 utilizing proceeds from the $2.5 billion securitization transaction and the generation asset transfer, as required by the Final Order, as part of the recapitalization. For additional information, see Note 6. Regulatory Issues and Accounting Impacts of Deregulation.
PSEG and Power
As of December 31, 2002 and 2001, Power had a payable to PSEG of approximately $239 million and $164 million, respectively, for short-term funding needs. Interest expense related to these borrowings was $4 million and $23 million for the year ended December 31, 2002 and 2001, respectively.
PSEG and Energy Holdings
As of December 31, 2002, Energy Holdings had a receivable due from PSEG of $62 million. Interest Income related to this borrowing was immaterial.
Changes in Capitalization
PSE&G
PSE&G paid a common stock dividend of approximately $305 million to PSEG in 2002.
Power
During 2002, PSEG invested $200 million of additional equity in Power, the proceeds of which were used to repay short-term debt and fund additional investments.
Energy Holdings
During 2002, PSEG invested $400 million of additional equity in Energy Holdings, the proceeds of which were used to repay short-term debt and fund additional investments.
Tax Sharing Agreement
PSEG, PSE&G, Power and Energy Holdings
PSEG files a consolidated Federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and its affiliated companies. 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.
Power and Energy Holdings
Foster Wheeler Ltd.
Certain contracts were entered into with subsidiaries of Foster Wheeler Ltd. E. James Ferland, PSEG Chairman of the Board, President and Chief Executive Officer, serves on the Board of Directors of Foster Wheeler Ltd. Richard J. Swift, who serves on PSEG’s Board of Directors, was the President and Chief Executive Officer of Foster Wheeler Ltd. at the time the contracts were entered into. The original contracts were for approximately $369 million of engineering, procurement and construction services related to the development of certain generating facilities for Power, Global and Services, $129 million of which was rendered in 2002. As of December 31, 2002, the aggregate open commitment under the contracts is approximately $69 million, of which $6 million, $62 million and $1 million relates to Power, Global and Services, respectively. PSEG believes that the contracts were entered
187
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
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.
Equipment Purchases and Sales
Global purchased equipment from Power totaling $47 million and $30 million in 2002 and 2001, respectively. These amounts were sold at book value, thus no gain or loss was recorded on these transactions. As of December 31, 2002 and 2001, there were no outstanding receivables or payables related to such sales.
PSE&G and Power
Transfer of Electric Generating Assets
In August 2000, PSE&G transferred its electric generating assets to Power 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 year ended, December 31, 2000, PSE&G recorded interest income of approximately $143 million relating to the Promissory Note. For the period from January 1, 2001 to January 31, 2001, PSE&G recorded interest income of approximately $34 million relating to the Promissory Note. Power repaid the Promissory Note on January 31, 2001.
Effective with the transfer of the electric generation business, Power charges PSE&G for the MTC and the energy and capacity provided to meet its BGS requirements. For the years ended December 31, 2002, 2001 and 2000, PSE&G was charged by Power approximately $1.2 billion, $2 billion and $0.8 billion, respectively, for the MTC and BGS. As of December 31, 2002, and 2001, PSE&G’s payable to Power (or Power’s receivable) relating to these costs was approximately $2 million and $158 million, respectively.
For the years ended December 31, 2002, 2001 and 2000, PSE&G sold energy and capacity to Power at the market price of approximately $77 million, $158 million and $78 million, which PSE&G purchased under various NUG contracts at costs above market prices. As of December 31, 2002 PSE&G had no receivable (or Power’s payable) related to these purchases as compared to the $7 million receivable as of December 31, 2001. As a result of the Final Order, PSE&G has established an NTC to recover the above market costs related to these NUG contracts. The difference between PSE&G’s costs and recovery of costs through the NTC and sales to Power, which are priced at the locational marginal price (LMP) set by the PJM ISO for energy and at wholesale market prices for capacity, is deferred as a regulatory asset.
These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s consolidated financial statements. No gains or losses are recorded on any intercompany transactions, rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU.
Under the BGS contract, which terminated on July 31, 2002, Power sold energy directly to PSE&G, which in turn sold this energy to its customers. For the new BGS contract period beginning August 1, 2002, Power entered into contracts with third parties who are direct suppliers of New Jersey’s EDCs and PSE&G purchases the energy for its customers’ needs from such direct suppliers. Due to this change in the BGS model, these revenues and expenses were no longer recorded as intercompany revenues and expenses and were no longer eliminated in consolidation after August 1, 2002.
Transfer of Gas Supply Contracts and Gas Inventory
Effective May 1, 2002, PSE&G transferred its gas supply contracts and gas inventory requirements to Power for approximately $183 million. On the same date, PSE&G entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS requirements. The contract term ends March 31, 2004 and PSE&G has a three-year renewal option. As part of the agreement, PSE&G is providing Power the use of its peak shaving facilities at cost.
From May 1, 2002 through December 31, 2002, Power billed PSE&G approximately $703 million for BGSS. As of December 31, 2002, PSE&G’s payable to Power related to the BGSS contract was approximately $241 million.
188
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
PSEG, PSE&G, Power and Energy Holdings
Services provides and bills administrative services to PSEG, PSE&G, Power and Energy Holdings as follows:
| Services
billed for the Year Ended December 31, |
Payable to
Services as of December 31, |
|||||||||||
| 2002 | 2001 | 2002 | 2001 | |||||||||
| (Millions) | ||||||||||||
| PSEG | $ | 13 | $ | –– | $ | 1 | $ | –– |
||||
| PSE&G | $ | 200 | $ | 235 | $ | 16 | $ | 26 | ||||
| Power | $ | 119 | $ | 130 | $ | 2 | $ | 14 | ||||
| Energy Holdings | $ | 22 | $ | 23 | $ | 3 | $ | 3 | ||||
These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s consolidated financial statements. PSEG, PSE&G, Power and Energy Holdings believe that the costs of services provided by Services approximates market value for such services.
Energy Holdings
Operation and Maintenance and Development Fees
Global provides operating, maintenance and other services to and receives management and guaranty fees from various joint ventures and partnerships in which it is an investor. Fees related to the development and construction of certain projects are deferred and recognized when earned. Income from these services of $3 million, $3 million, and $12 million, were included in Operating Revenues in the Consolidated Statements of Operations for the years ended December 31, 2002, 2001, and 2000, respectively.
Affiliate Payables due to PSEG from Energy Technologies
As of December 31, 2002 and December 31, 2001, Energy Technologies had recorded affiliate payables due to PSEG and its associated companies, other than Energy Holdings, of $12 million and $6 million, respectively. The amounts are recorded as a component of Current Liabilities of Discontinued Operations on the Consolidated Balance Sheets. Energy Technologies will repay the balance of the intercompany payable of $12 million prior to or upon the sale of the HVAC/mechanical operating companies.
Loans to TIE
Global and its partner, Panda Energy International, Inc., through Texas Independent Energy, L.P. (TIE), a 50/50 joint venture, owns and operates two electric generation facilities in Texas. As of December 31, 2002 and 2001, Global’s investments in the TIE partnership include $73 million and $165 million, respectively, of loans that earn interest at an annual rate of 12% that are expected to be repaid over the next 10 years. The loan structure was put in place to provide Global with a preferential cash and earnings flow from the projects after third-party debt service. Global received $101 million of loan repayments, including interest, and invested $51 million of equity in the TIE investments for the year ended December 31, 2002. Global’s share of interest earned was $10 million. However, only 50% of the interest received is being recorded as income as the interest related to Global’s 50% ownership share is being eliminated in consolidation.
189
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Loans to GWF Energy
Global provided GWF Energy approximately $98 million of secured loans to finance the purchase of turbines. The turbine loans were interest bearing and the rates ranged from 12% to 15% per annum. The first installment payment began May 31, 2002 and as of December 31, 2002, the loans were repaid in accordance with the loan agreement.
Global had also provided GWF Energy up to $74 million of working capital loans to fund construction costs pending completion of project financing. Such loans earned interest at 20% per annum and were convertible into equity at Global’s option. During 2002, Global converted $71 million of such working capital loans to equity, which increased Global’s ownership of GWF Energy to 76%. The partnership agreement stipulates that the condition for control is indicated at 75% or greater ownership interest of the voting stock. Accordingly, Global’s investment in GWF Energy is recorded as a consolidated entity as of December 31, 2002 and for the three months ended December 31, 2002. Harbinger GWF LLC has the right to buy back from Global up to one-half of the reduction of its equity ownership in GWF Energy from the 50% ownership level. Such right terminates at the earlier of project financing or September 30, 2003. The loan structures were put in place to provide Global with a preferential cash and earnings distribution from GWF Energy similar to Global’s subordinated loans from TIE. For a discussion of the commercial dates of operation and issues of the construction process with respect to these three plants, see Note 13. Commitments and Contingent Liabilities.
Transfer of Asset Management Group (AMG) from Energy Technologies to Resources
As of December 31, 2002, Energy Technologies contributed its equity investment in the capital stock of AMG, which includes various DSM investments, to Resources. The aggregate book value, which approximated fair value, of the stock contributed was $42 million. As of December 31, 2002, AMG has total assets of $45 million and earnings of $7 million for the year ended December 31, 2002.
190
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note 23. Guarantees of Debt
Power
In April 2001, Power 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. Additionally, in June 2002, Power issued $600 million of 6.95% Senior Notes due 2012. 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 guarantor subsidiaries as well as Power’s non-guarantor subsidiaries as of December 31, 2002 and 2001:
| For the Year Ended December 31, 2002: | Power | Guarantor Subsidiaries |
Other Subsidiaries |
Consolidating Adjustments |
Total | |||||||||||
| |
||||||||||||||||
| (Millions) | ||||||||||||||||
| Revenues | $ | 2 | $ | 5,041 | $ | 43 | $ | (1,416 | ) | $ | 3,670 | |||||
| Operating Expenses | — | 4,140 | 43 | (1,416 | ) | 2,767 | ||||||||||
| Operating Income (Loss) | 2 | 901 | — | — | 903 | |||||||||||
| Other Income | 616 | — | — | (616 | ) | — | ||||||||||
| Interest Expense | (180 | ) | (60 | ) | 118 | — | (122 | ) | ||||||||
| Income Taxes | 78 | (350 | ) | (41 | ) | — | (313 | ) | ||||||||
| Net Income (Loss) | $ | 516 | $ | 491 | $ | 77 | $ | (616 | ) | $ | 468 | |||||
| As of December 31, 2002: | ||||||||||||||||
| |
||||||||||||||||
| Current Assets | $ | 1,068 | $ | 1,283 | $ | 89 | $ | (1,138 | ) | $ | 1,302 | |||||
| Property, Plant and Equipment, net | 42 | 2,430 | 1,573 | — | 4,045 | |||||||||||
| Noncurrent Assets | 3,196 | 1,777 | 1,355 | (4,711 | ) | 1,617 | ||||||||||
| Total Assets | $ | 4,306 | $ | 5,490 | $ | 3,017 | $ | (5,849 | ) | $ | 6,964 | |||||
| Current Liabilities | $ | 128 | $ | 1,571 | $ | 504 | $ | (1,126 | ) | $ | 1,077 | |||||
| Noncurrent Liabilities | 125 | 984 | 28 | (8 | ) | 1,129 | ||||||||||
| Note Payable — Affiliated Company | 97 | 1,150 | — | (1,247 | ) | — | ||||||||||
| Long-Term Debt | 2,516 | — | 800 | — | 3,316 | |||||||||||
| Member’s Equity | 1,440 | 1,785 | 1,685 | (3,468 | ) | 1,442 | ||||||||||
| Total Liabilities and Member’s Equity | $ | 4,306 | $ | 5,490 | $ | 3, 017 | $ | (5,849 | ) | $ | 6,964 | |||||
| For the Year Ended December 31, 2002: | ||||||||||||||||
| |
||||||||||||||||
| Net Cash Provided By (Used In) Operating Activities | $ | (182 | ) | $ | 617 | $ | 298 | $ | (240 | ) | $ | 493 | ||||
| Net Cash Provided By (Used In) Investing Activities | $ | (695 | ) | $ | (749 | ) | $ | (625 | ) | $ | 769 | $ | (1,300 | ) | ||
| Net Cash Provided By (Used In) Financing Activities | $ | 877 | $ | 150 | $ | 328 | $ | (531 | ) | $ | 824 | |||||
191
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Concluded
| Power | Guarantor Subsidiaries |
Other Subsidiaries |
Consolidating Adjustments |
Total | |||||||||||
| (Millions) | |||||||||||||||
| For the Year Ended December 31, 2001: | |||||||||||||||
| |
|||||||||||||||
| Revenues | $ | 2 | $ | 3,965 | $ | 24 | $ | (1,539 | ) | $ | 2,452 | ||||
| Operating Expenses | — | 3,164 | 40 | $ | (1,539 | ) | 1,665 | ||||||||
| Operating Income (Loss) | 2 | 801 | (16 | ) | — | 787 | |||||||||
| Other Income (Loss) | 584 | — | — | (584 | ) | — | |||||||||
| Interest Expense | (182 | ) | (69 | ) | 108 | — | (143 | ) | |||||||
| Income Taxes | 74 | (292 | ) | (32 | ) | — | (250 | ) | |||||||
| Net Income (Loss) | $ | 478 | $ | 440 | $ | 60 | $ | (584 | ) | $ | 394 | ||||
| As of December 31, 2001: | |||||||||||||||
| |
|||||||||||||||
| Current Assets | $ | 399 | $ | 1,195 | $ | 64 | $ | (1,002 | ) | $ | 656 | ||||
| Property, Plant and Equipment, net | 40 | 1,992 | 953 | — | 2,985 | ||||||||||
| Noncurrent Assets | 2,454 | 1,475 | 1,230 | (3,561 | ) | 1,598 | |||||||||
| Total Assets | $ | 2,893 | $ | 4,662 | $ | 2,247 | $ | (4,563 | ) | $ | 5,239 | ||||
| Current Liabilities | $ | 81 | $ | 1,284 | $ | 215 | $ | (990 | ) | $ | 590 | ||||
| Noncurrent Liabilities | 16 | 1,094 | 16 | (22 | ) | 1,104 | |||||||||
| Note Payable — Affiliated Company | 21 | 1,150 | — | (1,171 | ) | — | |||||||||
| Long-Term Debt | 1,915 | — | 770 | — | 2,685 | ||||||||||
| Member’s Equity | 860 | 1,134 | 1,246 | (2,380 | ) | 860 | |||||||||
| Total Liabilities and Member’s Equity | $ | 2,893 | $ | 4,662 | $ | 2,247 | $ | (4,563 | ) | $ | 5,239 | ||||
| For the Year Ended December 31, 2001: | |||||||||||||||
| |
|||||||||||||||
| Net Cash Provided By (Used In) Operating Activities | $ | 313 | $ | 830 | $ | (989 | ) | $ | 365 | $ | 519 | ||||
| Net Cash Provided By (Used In) Investing Activities | $ | 41 | $ | (1,544 | ) | $ | (947 | ) | $ | 837 | $ | (1,613 | ) | ||
| Net Cash Provided By (Used In) Financing Activities | $ | 329 | $ | 704 | $ | 1,936 | $ | (1,886 | ) | $ | 1,083 | ||||
There are no restrictions on the ability of Power’s subsidiaries to transfer funds in the form of dividends, loans or advances to Power for the periods noted above.
192
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
PSEG
None.
PSE&G
None.
Power
None.
Energy Holdings
None.
PART III
| ITEM 10. | ITEM DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS |
Executive Officers
The Executive Officers of each of PSEG, PSE&G, Power and Energy Holdings, respectively, are set forth below, as indicated for each individual.
| | |||
| NAME | AGE DECEMBER 31, 2002 |
OFFICE | EFFECTIVE DATE FIRST ELECTED TO PRESENT POSITION |
| E. James Ferland | 60 | Chairman of the Board, President and | July 1986 to present |
| (1)(2)(3)(4) | Chief Executive Officer (PSEG) | ||
| Chairman of the Board and Chief | July 1986 to present | ||
| Executive Officer (PSE&G) | |||
| Chairman of the Board and Chief | June 1989 to present | ||
| Executive Officer (Energy Holdings) | |||
| Chairman of the Board and Chief | June 1999 to present | ||
| Executive Officer (Power) | |||
| Chairman of the Board and | November 1999 to present | ||
| Chief Executive Officer (Services) | |||
| | |||
| Thomas M. O’Flynn | 42 | Executive Vice President and Chief | July 2001 to present |
| (1)(3)(4) | Financial Officer (PSEG) | ||
| Executive Vice President – Finance | July 2001 to present | ||
| (Services) | |||
| Executive Vice President and Chief | August 2002 to present | ||
| Financial Officer (Energy Holdings) | |||
| Executive Vice President and Chief | February 2002 to present | ||
| Financial Officer (Power) | |||
| Managing Director | December 1997 to May 2001 | ||
| (Morgan Stanley) | |||
193
| Robert J. Dougherty, Jr. | 51 | Vice President | March 1995 to present |
| (1)(4) | (PSEG) | ||
| President and Chief Operating Officer | January 1997 to present | ||
| (Energy Holdings) | |||
| | |||
| Alfred C. Koeppe | 56 | President and Chief Operating | February 2000 to present |
| (1)(2) | Officer (PSE&G) | ||
| Senior Vice President – Corporate | October 1996 to February 2000 | ||
| Services and External Affairs (PSE&G) | |||
| | |||
| R. Edwin Selover | 57 | Senior Vice President | April 2002 to present |
| (1)(2) | and General Counsel | ||
| (PSEG) | |||
| Vice President and General Counsel | |||
| (PSEG) | April 1988 to April 2002 | ||
| Senior Vice President and General | January 1988 to present | ||
| Counsel (PSE&G) | |||
| Senior Vice President and General | November 1999 to present | ||
| Counsel (Services) | |||
| | |||
| Patricia A. Rado | 60 | Vice President and Controller | April 1993 to present |
| (1)(2)(3) | (PSEG) | ||
| Vice President and Controller | April 1993 to present | ||
| (PSE&G) | |||
| Vice President and Controller | June 1999 to present | ||
| (Power) | |||
| Vice President and Controller | November 1999 to present | ||
| (Services) | |||
| | |||
| Robert E. Busch | 56 | President & Chief Operating Officer | April 2001 to present |
| (1)(2) | (Services) | ||
| Senior Vice President – Finance and | November 1999 to April 2001 | ||
| Chief Financial Officer (Services) | |||
| Senior Vice President and | March 1998 to present | ||
| Chief Financial Officer (PSE&G) | |||
| | |||
| Thomas R. Smith | 42 | Executive Vice President – Operations & | September 2000 to present |
| (3) | Development (Power) | ||
| President – Fossil | September 2000 to present | ||
| Generation (Power) | |||
| Executive Vice President and | January 2000 to September 2000 | ||
| Chief Operating Officer (Global) | |||
| | |||
| Harold W. Borden Jr. | 58 | Vice President and General | June 1999 to present |
| (3) | Counsel (Power) | ||
| 74 | |||
| Vice President – Law (PSE&G) | April 1995 to July 1999 | ||
| | |||
| Morton A. Plawner | 55 | Treasurer (PSEG) | January 1998 to present |
| (3) | |||
| Vice President and | January 1998 to present | ||
| Treasurer (PSE&G) | |||
| Vice President and | June 1999 to present | ||
| Treasurer (Power) | |||
194
| | |||
| Frank Cassidy | 56 | President and Chief Operating Officer | July 1999 to present |
| (1)(3) | (Power) | ||
| President (Energy Technologies) | November 1996 to June 1999 | ||
| | |||
| Michael J. Thomson | 44 | President and Chief Executive | January 1997 to present |
| (4) | Officer (Global) | ||
| | |||
| Eileen A. Moran | 48 | President and Chief Executive | May 1990 to present |
| (4) | Officer (Resources) | ||
| President and Chief Executive | January 1997 to present | ||
| Officer (EGDC) | |||
| | |||
| Stanley M. | 50 | President and Chief Executive Officer | June 1999 to present |
| Kosierowski | (Energy Technologies) | ||
| (4) | |||
| Executive Vice President and | February 1999 to June 1999 | ||
| Chief Operating Officer | |||
| (Energy Technologies) | |||
| Vice President – Customer Operations | January 1997 to February 1999 | ||
| (PSE&G) | |||
| | |||
| Miriam E. Gilligan | 51 | Vice President – Finance and | December 2001 to present |
| (4) | Treasurer (Energy Holdings) | ||
| Treasurer (Energy Holdings) | 1997 to December 2001 | ||
| | |||
| Derek M. DiRisio | 38 | Vice President and Controller | June 1998 to present |
| (4) | (Energy Holdings) | ||
| Director – Accounting Services | November 1997 to June 1998 | ||
| (Energy Holdings) | |||
| | |||
| (1) | Executive Officer of PSEG |
| (2); | Executive Officer of PSE&G |
| (3) | Executive Officer of Power |
| (4) | Executive Officer of Energy Holdings |
| Directors | |
| PSEG | |
| The
information required by Item 10 of Form 10-K with respect to (i) present
directors of PSEG who are nominees for election as directors at PSEG’s
Annual Meeting of Stockholders to be held on April 15, 2003, and directors
whose terms will continue beyond the meeting, and (ii) compliance with Section
16 (a) of the Securities Exchange Act of 1934, as amended, is set forth
under the headings "Election of Directors" and Section 16 (a) “Beneficial
Ownership Reporting Compliance” in PSEG’s definitive Proxy Statement
for such Annual Meeting of Stockholders, which definitive Proxy Statement
is expected to be filed with the Securities and Exchange Commission on or
about March 7, 2003 and which information set forth under said heading is
incorporated herein by this reference thereto. | |
| PSE&G | |
| E.
JAMES FERLAND has been a director since 1986. Age 61. Chairman of Executive Committee. For additional information, see Executive Officers table above. | |
| 195 | |
ALBERT R. GAMPER, JR. has been a director since December 2000. Age 60. Director of PSEG. He has been Chairman of the Board, President and Chief Executive Officer of The CIT Group, Inc., Livingston, New Jersey (commercial finance company) since July 2002. Was President and Chief Executive Officer of The CIT Group, Inc., from February 2002 to June 2002. Was President and Chief Executive Officer of Tyco Capital Corporation from June 2001 to February 2002. Was Chairman of the Board, President and Chief Executive Officer of The CIT Group, Inc., from January 2000 to June 2001. Was President and Chief Executive Officer of The CIT Group, Inc. from December 1989 to December 1999.
CONRAD K. HARPER has been a director since May 1997. Age 62. Director of PSEG. Has been of counsel to the law firm of Simpson Thacher & Bartlett, New York, New York since January 2003. Was a partner from October 1996 to December 2002 and from 1974 to May 1993. Was Legal Adviser, US Department of State from May 1993 to June 1996. Director of New York Life Insurance Company.
MARILYN M. PFALTZ has been a director since 1980. Age 70. Director of PSEG. Has been a partner of P and R Associates, Summit, New Jersey (communications specialists) since 1968. Director of AAA National Association, AAA Investment Company, AAA Life Re Ltd. and Beacon Trust Company.
Power
ROBERT E. BUSCH has been a director since December 2000. Age 56. For additional information, see Executive Officers table above.
FRANK CASSIDY has been a director since 1999. Age 56. For additional information, see Executive Officers table above.
ROBERT J. DOUGHERTY, JR. has been a director since 1999. Age 51. For additional information, see Executive Officers table above.
E. JAMES FERLAND has been a director since 1999. For additional information see Executive Officers table above.
R. EDWIN SELOVER has been a director since 1999, Age 57. For additional information, see Executive Officers table above.
MICHAEL J. THOMSON has been a director since January 2000. Age 44. For additional information, see Executive Officers table above.
Energy Holdings
ROBERT E. BUSCH has been a director since December 2000. For additional information, see Executive Officers table above.
FRANK CASSIDY has been a director since January 2000. For additional information, see Executive Officers table above.
ROBERT J. DOUGHERTY, JR. has been a director since January 2000. For additional information, see Executive Officers table above.
E. JAMES FERLAND has been a director since 1989. For additional information, see Executive Officers table above.
THOMAS M. O’FLYNN has been a director since July 2001. For additional information, see Executive Officers table above.
R. EDWIN SELOVER has been a director since January 2000, For additional information, see Executive Officers table above.
196
ITEM 11. EXECUTIVE COMPENSATION
PSEG
The information required by Item 11 of Form 10-K is set forth under the heading "Executive Compensation" in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 15, 2003 which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 7, 2003 and such information set forth under such heading is incorporated herein by this reference thereto.
PSE&G
Information regarding the compensation of the Chief Executive Officer and the four most highly compensated executive officers of PSE&G as of December 31, 2002 is set forth below. Amounts shown were paid or awarded for all services rendered to PSEG and its subsidiaries and affiliates including PSE&G.
| Long TermCompensation | |||||||||||||||
| | |||||||||||||||
| Annual Compensation | Awards | Payouts | |||||||||||||
| |
|||||||||||||||
| Name and Principal Position | Year | Salary $ | Bonus/Annual Incentive Award ($)(1) |
Restricted Stock ($) |
Options (#) (2) |
LTIP Payouts ($) (3) |
All Other Compensation ($) (4) |
||||||||
| E. James Ferland | 2002 | 975,000 | 713,000 | 0 | 350,000 | 0 | 6,002 | ||||||||
| Chairman of the Board and | 2001 | 962,525 | 1,023,000 | 2,248,000 | (5) | 350,000 | 400,800 | 51,152 | |||||||
| Chief Executive Officer | 2000 | 890,000 | 1,001,300 | 0 | 300,000 | 361,440 | 59,037 | ||||||||
| Alfred C. Koeppe | 2002 | 374,000 | 143,200 | 0 | 75,000 | 0 | 8,004 | ||||||||
| President and Chief | 2001 | 358,654 | 270,000 | 0 | 75,000 | 100,200 | 6,803 | ||||||||
| Operating Officer | 2000 | 340,000 | 255,000 | 0 | 310,000 | 90,360 | 6,805 | ||||||||
| R. Edwin Selover | 2002 | 390,000 | 125,000 | 0 | 80,000 | 0 | 8,004 | ||||||||
| Senior Vice President and | 2001 | 367,852 | 225,000 | 0 | 70,000 | 100,200 | 6,867 | ||||||||
| General Counsel | 2000 | 325,000 | 170,600 | 0 | 40,000 | 81,324 | 17,280 | ||||||||
| Robert E. Busch | 2002 | 360,000 | 153,200 | 0 | 65,000 | 0 | 8,006 | ||||||||
| Senior Vice President and | 2001 | 335,482 | 262,500 | 0 | 315,000 | 60,120 | 6,803 | ||||||||
| Chief Financial Officer | 2000 | 300,000 | 157,500 | 0 | 40,000 | 0 | 6,805 | ||||||||
| Patricia A. Rado | 2002 | 220,000 | 53,600 | 0 | 25,000 | 0 | 5,593 | ||||||||
| Vice President and | 2001 | 209,835 | 94,500 | 0 | 25,000 | 24,048 | 6,449 | ||||||||
| Controller | 2000 | 200,000 | 90,000 | 0 | 15,000 | 18,072 | 7,289 | ||||||||
| (1) | Amount awarded in 2002 and 2001 were earned
under the Restated and Amended Management Incentive Compensation Plan and
in 2000 was earned under the Management Incentive Compensation
Plan and determined and was paid in the following year based on individual
performance and financial and operating performance of PSEG and PSE&G,
including comparison to other companies. |
| (2) | All grants of options to purchase
shares of PSEG Common Stock were non-qualified options made under the 1989
Long-Term Incentive Plan (1989 LTIP) and/or the 2001 Long-Term Incentive Plan
(2001 LTIP). All options granted were non-tandem. Non-tandem grants are
made without performance units and dividend equivalents. |
| (3) | Amount paid in proportion to options
exercised, if any, based on value of previously granted performance units
and dividend equivalents under the 1989 LTIP, each as measured during three-year
period ending the year prior to the year in which payment is made. Under
the 1989 LTIP, tandem grants were made with an equal number of performance
units and dividend equivalents which may provide cash payments, dependent
upon future financial performance of PSEG in comparison to other companies
and dividend payments by PSEG, to assist recipients in exercising options
granted. The tandem grant was made at the beginning of a |
197 | |
| three-year performance period and cash payment
of the value of such performance units and dividend equivalents is made
following such period in proportion to the options, if any, exercised at
such time. | |
| (4) | Includes employer contribution to the Thrift
and Tax-Deferred Savings Plan: |
| Year | Ferland ($) |
Koeppe ($) |
Selover ($) |
Busch ($) |
Rado ($) |
||||||
| 2002 | 6,002 | 8,004 | 8,004 | 8,006 | 5,593 | ||||||
| 2001 | 5,102 | 6,803 | 5,104 | 6,803 | 6,449 | ||||||
| 2000 | 5,102 | 6,805 | 4,747 | 6,805 | 6,422 | ||||||
| In addition, 2001 and 2000 amounts include for
Mr. Ferland $46,050, and $53,935; for Mr. Selover $10,493, and $12,533;
and for Mrs. Rado $1,093 and $867, respectively, representing earnings credited
on compensation deferred under PSE&G’s Deferred Compensation Plan
in excess of 120% of the applicable Federal long-term interest rate as prescribed
under Section 1274(d) of the Internal Revenue Code. Prior to January 1,
2000, under PSEG’s Deferred Compensation Plan, interest was paid at
prime rate plus 1/2%, adjusted quarterly. Effective January 1, 2000, the
Plan was amended to permit participants to select from among four additional
investment options for compensation that is deferred. | |
| (5) | Value as of original grant date, based on the
closing price of $40.80 on the New York Stock Exchange on November 20, 2001,
with respect to an award to Mr. Ferland of 60,000 shares of restricted stock,
with 30,000 shares vesting in 2006 and 30,000 shares vesting in 2007. Dividends
on the entire grant are paid in cash from the date of award. |
198
| OPTION GRANTS IN LAST FISCAL YEAR (2002) | |||||||||||
| Name | Number
of Securities Underlying Options Granted (1) |
% of Total Options Granted to Employees in Fiscal Year |
Exercise or Base Price ($/Sh) |
Expiration Date |
Grant Date Present Value ($) (2) |
||||||
| E. James Ferland | 350,000 | 18.5 | 31.43 | 12/17/12 | 1,536,500 | ||||||
| Alfred C. Koeppe | 75,000 | 4.0 | 31.43 | 12/17/12 | 329,250 | ||||||
| R. Edwin Selover | 80,000 | 4.2 | 31.43 | 12/17/12 | 351,200 | ||||||
| Robert E. Busch | 65,000 | 3.4 | 31.43 | 12/17/12 | 285,350 | ||||||
| Patricia A. Rado | 25,000 | 1.3 | 31.43 | 12/17/12 | 109,750 | ||||||
| (1) |
Granted under the 2001 LTIP with exercisability
commencing December 17, 2003, December 17, 2004 and December 17, 2005, respectively,
with respect to one-third of the options at each such date. |
| (2) |
Determined using the Black-Scholes
model, incorporating the following material assumptions and adjustments:
(a) exercise price of $31.43, equal to the fair market value of the underlying
PSEG Common Stock on the date of grant; (b) an option term of ten years
on all grants; (c) interest rate of 4.03% that represent the interest rates
on US Treasury securities on the date of grant with a maturity date corresponding
to that of the option terms; (d) volatility of 31.67% calculated using daily
PSEG Common Stock prices for the one-year period prior to the grant date;
(e) dividend yield of 6.87% and (f) reductions of approximately 7.83% to
reflect the probability of forfeiture due to termination prior to vesting,
and approximately 6.96% to reflect the probability of a shortened option
term due to termination of employment prior to the option expiration dates.
Actual values which may be realized, if any, upon any exercise of such options,
will be based on the market price of PSEG Common Stock at the time of any
such exercise and thus are dependent upon future performance of PSEG Common
Stock. There is no assurance that any such value realized will be at or
near the value estimated by the Black-Scholes model utilized. |
| AGGREGATED OPTION EXERCISES IN
LAST FISCAL YEAR (2002) AND FISCAL YEAR ENDOPTION VALUES (12/31/02) | ||||||||||||
| Number of Unexercised Options at FY-End (#) (1) |
Value of Unexercised In-the-Money Options At FY-End ($) (3) | |||||||||||
| Name | SharesAcquired on Exercise (#)(1) |
ValueRealized ($)(2) |
Exercisable (#) |
Unexercisable (#) |
Exercisable ($) (3) |
Unexercisable ($) (3) | ||||||
| E. James Ferland | 0 | 0 | 781,667 | 683,333 | 253,750 | 234,500 | ||||||
|
| ||||||||||||
| Alfred C. Koeppe | 0 | 0 | 275,000 | 295,000 | 25,375 | 50,250 | ||||||
|
| ||||||||||||
| R. Edwin Selover | 0 | 0 | 120,001 | 139,999 | 25,375 | 53,600 | ||||||
|
| ||||||||||||
| Robert E. Busch | 0 | 0 | 138,334 | 321,666 | 0 | 43,550 | ||||||
|
| ||||||||||||
| Patricia A. Rado | 0 | 0 | 41,334 | 46,666 | 0 | 16,750 | ||||||
| (1) |
Does not reflect any options granted
and/or exercised after year-end (12/31/02). The net effect of any such grants
and exercises is reflected in the table appearing under Security Ownership
of Directors, Management and Certain Beneficial Owners. |
| (2) |
Represents difference between exercise
price and market price of PSEG Common Stock on date of exercise. |
199 | |
| (3) | Represents difference between market price of
PSEG Common Stock and the respective exercise prices of the options at fiscal
year end (12/31/02). Such amounts may not necessarily be realized. Actual
values which may be realized, if any, upon any exercise of such options
will be based on the market price of PSEG Common Stock at the time of any
such exercise and thus are dependent upon future performance of PSEG Common
Stock. |
Employment Contracts and Arrangements
PSEG has entered into an employment agreement dated as of June 16, 1998 and amended as of November 20, 2001 with Mr. Ferland covering his employment as Chief Executive Officer through March 31, 2007. The Agreement provides that Mr. Ferland will be re-nominated for election as a Director during his employment under the Agreement. The Agreement provides that Mr. Ferland’s base salary, target annual incentive bonus and long term incentive bonus will be determined based on compensation practices for CEO’s of similar companies and that his annual salary will not be reduced during the term of the Agreement. The Agreement also provided for an award to him of 150,000 shares of restricted PSEG Stock as of June 16, 1998 and 60,000 shares of restricted PSEG Common Stock as of November 20, 2001, with 60,000 shares vesting in 2002; 20,000 shares vesting in 2003; 30,000 shares vesting in 2004; 40,000 shares vesting in 2005; 30,000 shares vesting in 2006; and 30,000 shares vesting in 2007. Any non-vested shares are forfeited upon his retirement unless the Board of Directors, in its discretion, determines to waive the forfeiture. The Agreement provides for the granting of 22 years of pension credit for Mr. Ferland’s prior service, which was awarded at the time of his initial employment.
PSE&G has entered into an employment agreement with Mr. Koeppe dated as of October 17, 2000 and Mr. Busch dated as of April 24, 2001, covering the respective employment of each in the position listed in the Summary Compensation Table through October 16, 2005 for Mr. Koeppe and April 24, 2006 for Mr. Busch. The agreements are essentially identical and provide that the base salary, target annual incentive bonus and long-term incentive bonus will be determined based on compensation practices of similar companies and that their annual salary will not be reduced during the term of the Agreement, and awarded to Mr. Koeppe 250,000 options on PSEG Common Stock, 50,000 of which vest each October 17 and expire on October 17, 2010 and awarded to Mr. Busch 250,000 options on PSEG Common Stock, 50,000 of which vest each April 24 and expire on April 24, 2011 in each case provided that the individual has remained continuously employed by PSEG through such date. The agreement for Messrs. Busch and Koeppe also provide for the grant of additional years of credited service for retirement purposes in light of allied work experience of fifteen years and twenty-five years, respectively.
The Agreements further provide that if the individual is terminated without “Cause” or resigns for “Good Reason” (as those terms are defined in each Agreement) during the term of the Agreement, the respective entire restricted stock award or the entire option award becomes vested, the individual will be paid a benefit of two times base salary and target bonus, and his welfare benefits will be continued for two years unless he is sooner employed. In the event such a termination occurs after a “Change in Control” (also as defined in the Agreement), the payment to the individual becomes three times the sum of salary and target bonus, continuation of welfare benefits for three years unless sooner reemployed, payment of the net present value of providing three years additional service under PSEG’s retirement plans, and a gross-up for excise taxes on any termination payments due under the Internal Revenue Code. The respective Agreements provide that Mr. Ferland is prohibited for two years and Messrs. Koeppe and Busch are prohibited for one year from competing with and each is prohibited for two years from recruiting employees from, PSEG or its subsidiaries or affiliates, after termination of employment. Violation of these provisions requires a forfeiture of the respective restricted stock grant and option and certain benefits.
Compensation Committee Interlocks and Insider Participation
PSE&G does not have a compensation committee. Decisions regarding compensation of PSE&G’s executive officers are made by the Organization and Compensation Committee of PSEG. Hence, during 2002 the PSE&G Board of Directors did not have, and no officer, employee or former officer of PSE&G participated in any deliberations of such Board, concerning executive officer compensation.
200
Compensation of Directors and Certain Business Relationships
During 2002, a director who was not an officer of PSEG or its subsidiaries and affiliates, including PSE&G, was paid an annual retainer of $30,000 and a fee of $1,500 for attendance at any Board or committee meeting, inspection trip, conference or other similar activity relating to PSEG or PSE&G. This amount was raised to $40,000 effective for 2003. Pursuant to the Compensation Plan for Outside Directors, a certain percentage, currently fifty percent, of the annual retainer is paid in PSEG Common Stock. No additional retainer is paid for service as a director of PSE&G. Each PSEG Committee Chair received an additional annual retainer of $3,000, increased for 2003 to $5,000 except for the Chair of the Audit Committee, who will receive $10,000. In addition, beginning in 2003, each member of the Audit Committee will receive an annual retainer of $5,000.
PSEG also maintains a Stock Plan for Outside Directors pursuant to which directors who are not employees of PSEG or its subsidiaries receive shares of restricted stock for each year of service as a director. For 2002, this amount was 600 shares, increased to 800 shares for 2003. Such shares held by each non-employee director are included in the table above under the heading Security Ownership of Directors, Management and Certain Beneficial Owners.
The restrictions on the stock granted under the Stock Plan for Outside Directors provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director’s service were terminated after a “change in control” as defined in the Plan or if the director were to die in office. PSEG also has the ability to waive these restrictions for good cause shown. Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director, and the director has the right to vote the shares.
Compensation Pursuant to Pension Plans
The table below illustrates annual retirement benefits for executive officers expressed in terms of single life annuities based on the average final compensation and service shown and retirement at age 65. A person’s annual retirement benefit is based upon a percentage that is equal to years of credited service plus 30, but not more than 75%, times average final compensation at the earlier of retirement, attainment of age 65 or death. These amounts are reduced by Social Security benefits and certain retirement benefits from other employers. Pensions in the form of joint and survivor annuities are also available.
| PENSION PLAN TABLE | |||||||||||||
| | |||||||||||||
| Length of Service | |||||||||||||
| | |||||||||||||
| Average
Final Compensation |
30 Years | 35 Years | 40 Years | 45 Years | |||||||||
| $ | 400,000 | $ | 240,000 | $ | 260,000 | $ | 280,000 | $ | 300,000 | ||||
| 500,000 | 300,000 | 325,000 | 350,000 | 375,000 | |||||||||
| 600,000 | 360,000 | 390,000 | 420,000 | 450,000 | |||||||||
| 700,000 | 420,000 | 455,000 | 490,000 | 525,000 | |||||||||
| 800,000 | 480,000 | 520,000 | 560,000 | 600,000 | |||||||||
| 900,000 | 540,000 | 585,000 | 630,000 | 675,000 | |||||||||
| 1,000,000 | 600,000 | 650,000 | 700,000 | 750,000 | |||||||||
| 1,100,000 | 660,000 | 715,000 | 770,000 | 825,000 | |||||||||
| 1,200,000 | 720,000 | 780,000 | 840,000 | 900,000 | |||||||||
| 1,300,000 | 780,000 | 845,000 | 910,000 | 975,000 | |||||||||
| 1,400,000 | 840,000 | 910,000 | 980,000 | 1,050,000 | |||||||||
| 1,500,000 | 900,000 | 975,000 | 1,050,000 | 1,125,000 | |||||||||
Average final compensation, for purposes of retirement benefits of executive officers, is generally equivalent to the average of the aggregate of the salary and bonus amounts reported in the Summary Compensation Table above under ’Annual Compensation’ for the five years preceding retirement, not to exceed 150% of the average annual salary for such five year period. Messrs. Ferland, Koeppe, Selover, Busch and Mrs. Rado will have accrued approximately 48, 46, 43, 34, and 29 years of credited service, respectively, as of age 65.
201
Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Energy Holdings
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT |
PSEG
The information required by Item 12 of Form 10-K with respect to directors, executive officers and certain beneficial owners is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners” in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 15, 2003 which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 7, 2003, and such information set forth under such heading is incorporated herein by this reference thereto.
The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2002:
| Plan category | Number of securities
to be issued upon exercise of outstanding options, warrants and rights (A) |
Weighted-average exercise price of outstanding options, warrants and rights |
Number of securities remaining available for future issuance under equity compensation plans | ||||||
| |
|||||||||
| Equity Compensation | |||||||||
| plans approved by | |||||||||
| security holders | 5,758,500 | $ | 39.35 | 9,241,500 | |||||
| Equity compensation | |||||||||
| plans not approved by | |||||||||
| security holders | 3,744,131 | $ | 39.25 | 3,987,173 | |||||
| Total: | 9,502,631 | $ | 39.32 | 13,228,673 | |||||
(A) Includes 310,000 shares granted under restricted stock agreements of certain key employees.
For additional discussion of specific plans concerning equity-based compensation, see Note 18. Stock Options and Employee Stock Purchase Plan of the Notes, Item 11. Executive Compensation for PSE&G, above, and the information set forth under the heading “Executive Compensation” in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders.
PSE&G
All of PSE&G’s, 132,450,344 outstanding shares of Common Stock are owned beneficially and of record by PSE&G’s parent, PSEG, 80 Park Plaza, P.O. Box 1171, Newark, New Jersey.
The following table sets forth beneficial ownership of PSEG Common Stock, including options, by the directors and executive officers named below as of February 21, 2003. None of these amounts exceed 1% of the PSEG Common Stock outstanding at such date, except for the amount for all directors and executive officers as a
202
group which constitutes approximately 1.41%. No director or executive officer owns any of PSE&G’s Preferred Stock of any class.
| Name | Amount
and Nature of Beneficial Ownership | |
| E. James Ferland | 1,761,252 | (1) |
| R. Edwin Selover | 275,489 | (2) |
| Alfred C. Koeppe | 578,952 | (3) |
| Robert E. Busch | 461,823 | (4) |
| Patricia A. Rado | 90,854 | (5) |
| Albert R. Gamper, Jr. | 3,404 | (6) |
| Conrad K. Harper | 4,954 | (7) |
| Marilyn M. Pfaltz | 13,518 | (8) |
| All directors and executive officers as a group (8 persons) | 3,190,246 | (9) |
| (1) | Includes the equivalent of 14,205 shares held under PSE&G Thrift and Tax-Deferred Savings Plan. Includes options to purchase 1,465,000 shares, 781,667 of which are currently exercisable. Includes 210,000 shares of restricted stock, which vest as described in the Summary Compensation Table Note 5. |
| (2) | Includes the equivalent of 10 shares of PSE&G Thrift and Tax-Deferred Savings Plan. Includes options to purchase 260,000 shares, 120,001 of which are currently exercisable. |
| (3) | Includes the equivalent of 2,852 shares held under the PSE&G Thrift and Tax-Deferred Savings Plan. Includes options to purchase 570,000 shares, 275,000 of which are currently exercisable. |
| (4) | Includes the equivalent of 173 shares held under PSE&G Thrift and Tax-Deferred Savings Plan. Includes options to purchase 460,000 shares, 138,334 of which are currently exercisable. |
| (5) | Includes options to purchase 88,000 shares, 41,334 of which are currently exercisable. |
| (6) | Includes 1,200 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors described below. |
| (7) | Includes 3,000 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors described below. |
| (8) | Includes 6,355 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors described below. |
| (9) | Includes the equivalent of 17,241
shares held under PSE&G Thrift and Tax-Deferred Savings Plan. Includes
options to purchase 2,843,000 shares, 1,356,336 of which are currently exercisable.
Includes 210,000 shares of restricted stock. |
Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Energy Holdings
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS |
PSEG
The information required by Item 13 of Form 10-K is set forth under the heading “Executive Compensation” in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 15, 2003, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 7, 2003. Such information set forth under such heading is incorporated herein by this reference thereto.
203
PSE&G
None.
Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Energy Holdings
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
| ITEM 14. | DISCLOSURE CONTROLS AND PROCEDURES |
PSEG, PSE&G, Power and Energy Holdings
Each of PSEG, PSE&G, Power and Energy Holdings has established and maintain disclosure controls and procedures which are designed to provide reasonable assurance that material information relating to each company, including its respective consolidated subsidiaries, is made known to the Chief Executive Officer and Chief Financial Officer of each company, by others within those entities, particularly during the period in which its annual report is being prepared. Each of PSEG, PSE&G, Power and Energy Holdings has established a Disclosure Committee which is made up of several key management employees and reports directly to the Chief Financial Officer and Chief Executive Officer of each company, to monitor and evaluate these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of these annual reports (the “Evaluation Date”) and based on this evaluation, it was concluded that the disclosure controls and procedures were effective in providing reasonable assurance during the period covered in the respective annual reports. There were no significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of each company’s most recent evaluation.
204
Certification
Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act | ||
| I certify that: | ||
| 1. |
I have reviewed this annual report
on Form 10-K of Public Service Enterprise Group Incorporated (the registrant); | |
| 2. | Based on my knowledge, this annual
report does not contain any untrue statement of a material fact or omit
to state a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not misleading
with respect to the period covered by this annual report; | |
| 3. | Based on my knowledge, the financial
statements, and other financial information included in this annual report,
fairly present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the periods
presented in this annual report; | |
| 4. | The registrant’s other certifying
officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have: | |
| a) | designed such disclosure controls
and procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual report
is being prepared; | |
| b) | evaluated the effectiveness of
the registrant’s disclosure controls and procedures as of a date within
90 days prior to the filing date of this annual report (the “Evaluation
Date”); and | |
| c) |
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; | |
| 5. | The registrant’s other certifying
officer and I have disclosed, based on our most recent evaluation, to the
registrant’s auditors and the audit committee of the registrant’s
board of directors: | |
| a) | all significant deficiencies in
the design or operation of internal controls which could adversely affect
the registrant’s ability to record, process, summarize and report financial
data and have identified any material weaknesses in internal controls; and | |
| b) | any fraud, whether or not material,
that involves management or other employees who have a significant role
in the registrant’s internal controls; and | |
| 6. |
The registrant’s other certifying
officer and I have indicated in this annual report whether or not there
were significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of our most
recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses. | |
| Date: February 25, 2003 | /s/ E. James Ferland |
| E. James Ferland Public Service Enterprise Group Incorporated Chief Executive Officer |
205
Certification
Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act | ||
| I certify that: | ||
| 1. |
I have reviewed this annual report
on Form 10-K of Public Service Enterprise Group Incorporated (the registrant); | |
| 2. | Based on my knowledge, this annual
report does not contain any untrue statement of a material fact or omit
to state a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not misleading
with respect to the period covered by this annual report; | |
| 3. | Based on my knowledge, the financial
statements, and other financial information included in this annual report,
fairly present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the periods
presented in this annual report; | |
| 4. | The registrant’s other certifying
officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have: | |
| a) | designed such disclosure controls
and procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual report
is being prepared; | |
| b) | evaluated the effectiveness of
the registrant’s disclosure controls and procedures as of a date within
90 days prior to the filing date of this annual report (the “Evaluation
Date”); and | |
| c) |
presented in this annual report
our conclusions about the effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date; | |
| 5. | The registrant’s other certifying
officer and I have disclosed, based on our most recent evaluation, to the
registrant’s auditors and the audit committee of the registrant’s
board of directors: | |
| a) | all significant deficiencies in
the design or operation of internal controls which could adversely affect
the registrant’s ability to record, process, summarize and report financial
data and have identified any material weaknesses in internal controls; and | |
| b) | any fraud, whether or not material,
that involves management or other employees who have a significant role
in the registrant’s internal controls; and | |
| 6. |
The registrant’s other certifying
officer and I have indicated in this annual report whether or not there
were significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of our most
recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses. | |
| Date: February 25, 2003 | /s/ Thomas M. O’Flynn |
| Thomas M. O’Flynn Public Service Enterprise Group Incorporated Chief Financial Officer |
206
Certification
Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act | ||
| I certify that: | ||
| 1. |
I have reviewed this annual report
on Form 10-K of Public Service Electric and Gas Company (the registrant); | |
| 2. | Based on my knowledge, this annual
report does not contain any untrue statement of a material fact or omit
to state a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not misleading
with respect to the period covered by this annual report; | |
| 3. | Based on my knowledge, the financial
statements, and other financial information included in this annual report,
fairly present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the periods
presented in this annual report; | |
| 4. | The registrant’s other certifying
officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have: | |
| a) | designed such disclosure controls
and procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual report
is being prepared; | |
| b) | evaluated the effectiveness of
the registrant’s disclosure controls and procedures as of a date within
90 days prior to the filing date of this annual report (the “Evaluation
Date”); and | |
| c) |
presented in this annual report
our conclusions about the effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date; | |
| 5. | The registrant’s other certifying
officer and I have disclosed, based on our most recent evaluation, to the
registrant’s auditors and the audit committee of the registrant’s
board of directors: | |
| a) | all significant deficiencies in
the design or operation of internal controls which could adversely affect
the registrant’s ability to record, process, summarize and report financial
data and have identified any material weaknesses in internal controls; and | |
| b) | any fraud, whether or not material,
that involves management or other employees who have a significant role
in the registrant’s internal controls; and | |
| 6. |
The registrant’s other certifying
officer and I have indicated in this annual report whether or not there
were significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of our most
recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses. | |
| Date: February 25, 2003 | /s/ E. James Ferland |
| E. James Ferland Public Service Electric and Gas Company Chief Executive Officer |
207
Certification
Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act | ||
| I certify that: | ||
| 1. |
I have reviewed this annual report
on Form 10-K of Public Service Electric and Gas Company (the registrant); | |
| 2. | Based on my knowledge, this annual
report does not contain any untrue statement of a material fact or omit
to state a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not misleading
with respect to the period covered by this annual report; | |
| 3. | Based on my knowledge, the financial
statements, and other financial information included in this annual report,
fairly present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the periods
presented in this annual report; | |
| 4. | The registrant’s other certifying
officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have: | |
| a) | designed such disclosure controls
and procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual report
is being prepared; | |
| b) | evaluated the effectiveness of
the registrant’s disclosure controls and procedures as of a date within
90 days prior to the filing date of this annual report (the “Evaluation
Date”); and | |
| c) |
presented in this annual report
our conclusions about the effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date; | |
| 5. | The registrant’s other certifying
officer and I have disclosed, based on our most recent evaluation, to the
registrant’s auditors and the audit committee of the registrant’s
board of directors: | |
| a) | all significant deficiencies in
the design or operation of internal controls which could adversely affect
the registrant’s ability to record, process, summarize and report financial
data and have identified any material weaknesses in internal controls; and | |
| b) | any fraud, whether or not material,
that involves management or other employees who have a significant role
in the registrant’s internal controls; and | |
| 6. |
The registrant’s other certifying
officer and I have indicated in this annual report whether or not there
were significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of our most
recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses. | |
| Date: February 25, 2003 | /s/ Robert E. Busch |
| Robert E. Busch Public Service Electric and Gas Company Senior Vice President and Chief Financial Officer |
208
Certification
Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act | ||
| I certify that: | ||
| 1. |
I have reviewed this annual report
on Form 10-K of PSEG Power LLC (the registrant); | |
| 2. | Based on my knowledge, this annual
report does not contain any untrue statement of a material fact or omit
to state a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not misleading
with respect to the period covered by this annual report; | |
| 3. | Based on my knowledge, the financial
statements, and other financial information included in this annual report,
fairly present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the periods
presented in this annual report; | |
| 4. | The registrant’s other certifying
officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have: | |
| a) | designed such disclosure controls
and procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual report
is being prepared; | |
| b) | evaluated the effectiveness of
the registrant’s disclosure controls and procedures as of a date within
90 days prior to the filing date of this annual report (the “Evaluation
Date”); and | |
| c) |
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; | |
| 5. | The registrant’s other certifying
officer and I have disclosed, based on our most recent evaluation, to the
registrant’s auditors and the audit committee of the registrant’s
board of directors: | |
| a) | all significant deficiencies in
the design or operation of internal controls which could adversely affect
the registrant’s ability to record, process, summarize and report financial
data and have identified any material weaknesses in internal controls; and | |
| b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and | |
| 6. |
The registrant’s other certifying
officer and I have indicated in this annual report whether or not there
were significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of our most
recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses. | |
| Date: February 25, 2003 | /s/ E. James Ferland |
| E. James Ferland PSEG Power LLC Chief Executive Officer |
209
Certification
Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act | ||
| I certify that: | ||
| 1. |
I have reviewed this annual report
on Form 10-K of PSEG Power LLC (the registrant); | |
| 2. | Based on my knowledge, this annual
report does not contain any untrue statement of a material fact or omit
to state a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not misleading
with respect to the period covered by this annual report; | |
| 3. | Based on my knowledge, the financial
statements, and other financial information included in this annual report,
fairly present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the periods
presented in this annual report; | |
| 4. | The registrant’s other certifying
officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have: | |
| a) | designed such disclosure controls
and procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual report
is being prepared; | |
| b) | evaluated the effectiveness of
the registrant’s disclosure controls and procedures as of a date within
90 days prior to the filing date of this annual report (the “Evaluation
Date”); and | |
| c) |
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; | |
| 5. | The registrant’s other certifying
officer and I have disclosed, based on our most recent evaluation, to the
registrant’s auditors and the audit committee of the registrant’s
board of directors: | |
| a) | all significant deficiencies in
the design or operation of internal controls which could adversely affect
the registrant’s ability to record, process, summarize and report financial
data and have identified any material weaknesses in internal controls; and | |
| b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and | |
| 6. |
The registrant’s other certifying
officer and I have indicated in this annual report whether or not there
were significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of our most
recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses. | |
| Date: February 25, 2003 | /s/ Thomas M. O’Flynn |
| Thomas M. O’Flynn PSEG Power LLC Chief Financial Officer |
210
Certification
Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act | ||
| I certify that: | ||
| 1. |
I have reviewed this annual report
on Form 10-K of PSEG Energy Holdings LLC (the registrant); | |
| 2. | Based on my knowledge, this annual
report does not contain any untrue statement of a material fact or omit
to state a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not misleading
with respect to the period covered by this annual report; | |
| 3. | Based on my knowledge, the financial
statements, and other financial information included in this annual report,
fairly present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the periods
presented in this annual report; | |
| 4. | The registrant’s other certifying
officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have: | |
| a) | designed such disclosure controls
and procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual report
is being prepared; | |
| b) | evaluated the effectiveness of
the registrant’s disclosure controls and procedures as of a date within
90 days prior to the filing date of this annual report (the “Evaluation
Date”); and | |
| c) |
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; | |
| 5. | The registrant’s other certifying
officer and I have disclosed, based on our most recent evaluation, to the
registrant’s auditors and the audit committee of the registrant’s
board of directors: | |
| a) | all significant deficiencies in
the design or operation of internal controls which could adversely affect
the registrant’s ability to record, process, summarize and report financial
data and have identified any material weaknesses in internal controls; and | |
| b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and | |
| 6. |
The registrant’s other certifying
officer and I have indicated in this annual report whether or not there
were significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of our most
recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses. | |
| Date: February 25, 2003 | /s/ E. James Ferland |
| E. James Ferland PSEG Energy Holdings LLC Chief Executive Officer |
211
Certification
Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act | ||
| I certify that: | ||
| 1. |
I have reviewed this annual report
on Form 10-K of PSEG Energy Holdings LLC (the registrant); | |
| 2. | Based on my knowledge, this annual
report does not contain any untrue statement of a material fact or omit
to state a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not misleading
with respect to the period covered by this annual report; | |
| 3. | Based on my knowledge, the financial
statements, and other financial information included in this annual report,
fairly present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the periods
presented in this annual report; | |
| 4. | The registrant’s other certifying
officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have: | |
| a) | designed such disclosure controls
and procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual report
is being prepared; | |
| b) | evaluated the effectiveness of
the registrant’s disclosure controls and procedures as of a date within
90 days prior to the filing date of this annual report (the “Evaluation
Date”); and | |
| c) |
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; | |
| 5. | The registrant’s other certifying
officer and I have disclosed, based on our most recent evaluation, to the
registrant’s auditors and the audit committee of the registrant’s
board of directors: | |
| a) | all significant deficiencies in
the design or operation of internal controls which could adversely affect
the registrant’s ability to record, process, summarize and report financial
data and have identified any material weaknesses in internal controls; and | |
| b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and | |
| 6. |
The registrant’s other certifying
officer and I have indicated in this annual report whether or not there
were significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of our most
recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses. | |
| Date: February 25, 2003 | /s/ Thomas M. O’Flynn |
| Thomas M. O’Flynn PSEG Energy Holdings LLC Chief Financial Officer |
212
PART
IV | ||
| ITEM 15. |
EXHIBITS, FINANCIAL STATEMENT
SCHEDULES AND REPORTS ON FORM 8-K | |
| (A) |
The following Financial
Statements are filed as a part of this report: | |
| a. |
PSEG’s Consolidated Balance
Sheets as of December 31, 2002 and 2001 and the related Consolidated Statements
of Operations, Cash Flows and Common Stockholders’ Equity for the three
years ended December 31, 2002 on pages 100 and 101, 99, 102 and 103, respectively. | |
| b. |
PSE&G’s Consolidated Balance
Sheets as of December 31, 2002 and 2001 and the related Consolidated Statements
of Operations, Cash Flows and Common Stockholder’s Equity for the three
years ended December 31, 2002 on pages 105 and 106, 104, 107 and 108, respectively. | |
| c. |
PSEG Power LLC Consolidated Balance
Sheets as of December 31, 2002 and 2001 and the related Consolidated Statements
of Operations, Cash Flows and Capitalization and Member’s Equity for
the three years ended December 31, 2002 on pages 110, 109, 111 and 112,
respectively. | |
| d. |
PSEG Energy Holdings LLC Consolidated
Balance Sheets as of December 31, 2002 and 2001 and the related Consolidated
Statements of Operations, Cash Flows and Member’s/Common Stockholder’s
Equity for the three years ended December 31, 2002 on pages 114 and 115,
113, 116 and 117, respectively. | |
| (B) |
The following documents
are filed as a part of this report: | |
| a. |
PSEG Financial Statement Schedules: | |
| Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2002 (page 215). | ||
| b. |
PSE&G Financial Statement Schedules: | |
| Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2002 (page 215). | ||
| c. |
Power’s Financial Statement
Schedules: | |
| Schedule II—Valuation and
Qualifying Accounts for each of the three years in the period ended December
31, 2002 (page 216). | ||
| d. |
Energy Holdings’ Financial
Statement Schedules: | |
| Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2002 (page 216). | ||
| 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. | ||
| (C) |
The following documents
are filed as a part of this report: | |
| a. |
PSEG: | |
|
Exhibit 3d: Amended and Restated Trust Agreement for Enterprise Capital Trust I Exhibit 3f: Amended and Restated Trust Agreement for Enterprise Capital Trust III Exhibit 3g: Amended and Restated Trust Agreement for PSEG Funding Trust I Exhibit 3h: Amended and Restated Trust Agreement for PSEG Funding Trust II Exhibit 4c: First Supplemental Indenture to Indenture dated January 1, 1998, dated July 1, 1998 Exhibit 4d: Indenture dated as of December 17, 2002 Exhibit 10a(17): Stock Plan for Outside Directors, as amended Exhibit 10a(20): Compensation Plan for Outside Directors Exhibit 12: Computation of Ratios of Earnings to Fixed Charges Exhibit 18: Independent Auditors' Preferability Letter dated February 7, 2003 Exhibit 21: Subsidiaries of Registrant Exhibit 23: Independent Auditors’ Consent | ||
213 | ||
| Exhibit 99: Certification
by E. James Ferland Exhibit 99a: Certification by Thomas M. O’Flynn (See Exhibit Index on pages 221 to 224) |
||
| b. |
PSE&G: |
|
|
Exhibit 3c Amended and Restated Trust Agreement for PSE&G Capital Trust I Exhibit 3d Amended and Restated Trust Agreement for PSE&G Capital Trust II Exhibit 4a(97): Supplemental Indenture between PSE&G and Wachovia Bank dated September 1, 2002 Exhibit 12a: Computation of Ratios of Earnings to Fixed Charges Exhibit 12b: Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements Exhibit 18a Independent Auditors' Preferability Letter dated February 7, 2003 Exhibit 21: Subsidiaries of Registrant Exhibit 23: Independent Auditors’ Consent Exhibit 99b: Certification by E. James Ferland Exhibit 99c: Certification by Robert E. Busch (See Exhibit Index on pages 225 to 231) |
||
| c. |
Power: |
|
|
Exhibit 12c: Computation of Ratios of Earnings to Fixed Charges Exhibit 18b Independent Auditors' Preferability Letter dated February 7, 2003 Exhibit 99d: Certification by E. James Ferland Exhibit 99e: Certification by Thomas M. O’Flynn (See Exhibit Index on page 232) |
||
| d. |
Energy Holdings: |
|
| Exhibit 12d: Computation
of Ratios of Earnings to Fixed Charges Exhibit 99f: Certification by E. James Ferland Exhibit 99g: Certification by Thomas M. O’Flynn (See Exhibit Index on page 233) |
||
| (D) |
The following reports
on Form 8-K were filed during the last quarter of 2002 and the 2003 period
covered by this report under Item 5: |
|
| a. PSEG: | ||
| Items Reported | Date of Report | |
|
|
|
|
| Items 5 and 7 | November 22, 2002 | |
| Items 5 and 7 | January 28, 2003 | |
| b. PSE&G: | ||
| Items Reported | Date of Report | |
|
|
|
|
| Items 5 and 7 | January 28, 2003 | |
| c. Power: | ||
| Items Reported | Date of Report | |
|
|
|
|
| Items 5 and 7 | January 28, 2003 | |
| d. Energy Holdings: | ||
| Items Reported | Date of Report | |
|
|
|
|
| Items 5 and 7 | January 28, 2003 |
214
SCHEDULE II
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
Schedule II — Valuation and Qualifying
Accounts
Years Ended December 31, 2002 — December 31, 2000
| Column A | Column B | Column C | Column D | Column E | |||||||||||||||||
| |
|||||||||||||||||||||
| Additions | |||||||||||||||||||||
| Description | Balance
at Beginning of Period |
Charged
to cost and expenses |
Charged
to other accounts describe |
Deductions- describe |
Balance
at End of Period |
||||||||||||||||
| |
|||||||||||||||||||||
| (Millions) | |||||||||||||||||||||
| 2002: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Allowance for Doubtful Accounts | $ | 40 | $ | 43 | $ | — | $ | 49 | (A) | $ | 34 | ||||||||||
| Materials and Supplies Valuation Reserve | 2 | 2 | 1 | (C) | — | 5 | |||||||||||||||
| Other Reserves | 2 | — | 10 | (D) | — | 12 | |||||||||||||||
| Other Valuation Allowances | 22 | — | — | 2 | (F) | 20 | |||||||||||||||
| 2001: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Allowance for Doubtful Accounts | $ | 39 | $ | 39 | $ | 2 | (E) | $ | 40 | (A) | $ | 40 | |||||||||
| Materials and Supplies Valuation Reserve | 11 | — | — | 9 | (B) | 2 | |||||||||||||||
| Other Reserves | 4 | — | — | 2 | (D) | 2 | |||||||||||||||
| Other Valuation Allowances | 22 | — | — | — | 22 | ||||||||||||||||
| 2000: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Allowance for Doubtful Accounts | $ | 35 | $ | 45 | $ | — | $ | 41 | (A) | $ | 39 | ||||||||||
| Materials and Supplies Valuation Reserve | 11 | — | — | — | 11 | ||||||||||||||||
| Other Reserves | 2 | 2 | (D) | — | — | 4 | |||||||||||||||
| Other Valuation Allowances | 22 | — | — | — | 22 | ||||||||||||||||
| (A) | Accounts Receivable/Investments written off. |
| (B) | Reduced reserve to appropriate level and to remove obsolete inventory. |
| (C) | Acquired two Connecticut electric generating stations. |
| (D) | Includes various liquidity, credit and bad debt reserves. |
| (E) | Valuation allowances consolidated in connection with the acquisition of SAESA. |
| (F) | Recorded in connection with the
sales of certain properties held by EGDC. |
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Schedule II — Valuation and Qualifying Accounts
Years Ended December 31, 2002 — December 31, 2000
| Column A | Column B | Column C | Column D | Column E | ||||||||||||||
|
|
|
|
|
|
||||||||||||||
| Additions | ||||||||||||||||||
|
|
||||||||||||||||||
| Description | Balance
at Beginning of Period |
Charged
to cost and expenses |
Charged to other accounts- describe |
Deductions describe |
Balance
at End of Period |
|||||||||||||
|
|
|
|
|
|
|
|||||||||||||
|
(Millions) |
||||||||||||||||||
| 2002: | ||||||||||||||||||
| |
||||||||||||||||||
| Allowance for Doubtful Accounts | $ | 38 | $ | 43 | $— | $ | 49 | (A) | $ | 32 | ||||||||
| 2001: | ||||||||||||||||||
| |
||||||||||||||||||
| Allowance for Doubtful Accounts | $ | 39 | $ | 45 | $— | $ | 46 | (A) | $ | 38 | ||||||||
| 2000: | ||||||||||||||||||
| |
||||||||||||||||||
| Allowance for Doubtful Accounts | $ | 35 | $ | 45 | $— | $ | 41 | (A) | $ | 39 | ||||||||
| Materials and Supplies Valuation Reserve | 11 | — | — | 11 | (B) | — | ||||||||||||
| (A) | Accounts Receivable/Investments written off. |
| (B) | Transferred to Power |
215 |
|
PSEG POWER LLC
Schedule II — Valuation and Qualifying
Accounts
Years Ended December 31, 2002 — December 31, 2000
| Column A | Column B | Column C | Column D | Column E | |||||||||||||||||
| |
|||||||||||||||||||||
| Additions | |||||||||||||||||||||
| Description | Balance
at Beginning of Period |
Charged
to cost and expenses |
Charged
to other accounts- describe |
Deductions describe |
Balance
at End of Period |
||||||||||||||||
| |
|||||||||||||||||||||
| (Millions) | |||||||||||||||||||||
| 2002: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Materials and Supplies Valuation Reserve | $ | 2 | $ | 2 | $ | 1 | (B) | $ | — | $ | 5 | ||||||||||
| Other Reserves | 2 | 10 | (C) | — | — | 12 | |||||||||||||||
| 2001: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Materials and Supplies Valuation Reserve | $ | 11 | $ | — | $ | — | $ | 9 | (A) | $ | 2 | ||||||||||
| Other Reserves | 4 | — | — | 2 | (C) | 2 | |||||||||||||||
| 2000: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Materials and Supplies Valuation Reserve | $ | 11 | $ | — | $ | — | $ | — | $ | 11 | |||||||||||
| Other Reserves | 2 | 2 | (C) | — | — | 4 | |||||||||||||||
| (A) | Reduced reserve to appropriate level and removed obsolete inventory. |
| (B) | Acquired two Connecticut electric generation stations. |
| (C) | Includes various liquidity, credit
and bad debt reserves. |
|
|
| Column A | Column B | Column C | Column D | Column E | |||||||||||||||||
| |
|||||||||||||||||||||
| Additions | |||||||||||||||||||||
| Description | Balance
at Beginning of Period |
Charged
to cost and expenses |
Charged
to other accounts- describe |
Deductions describe |
Balance
at End of Period |
||||||||||||||||
| |
|||||||||||||||||||||
| (Millions) | |||||||||||||||||||||
| 2002: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Allowance for Doubtful Accounts | $ | 2 | $ | — | $ | — | $ | — | $ | 2 | |||||||||||
| Other Valuation Allowances | 22 | — | — | 2 | (B) | 20 | |||||||||||||||
| 2001: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Allowance for Doubtful Accounts | $ | — | $ | — | $ | 2 | (A) | $ | — | $ | 2 | ||||||||||
| Other Valuation Allowances | 22 | — | — | — | 22 | ||||||||||||||||
| 2000: | |||||||||||||||||||||
| |
|||||||||||||||||||||
| Allowance for Doubtful Accounts | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||
| Other Valuation Allowances | 22 | — | — | — | 22 | ||||||||||||||||
| (A) | Valuation allowance consolidated in connection with the acquisition of SAESA. |
| (B) | Recorded in connection with the sales of certain properties held by EDGC. |
| (C) | Includes various liquidity, credit
and bad debt reserves. |
216
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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| Public Service Enterprise Group Incorporated | ||
| By | /s/ E. JAMES FERLAND | |
|
|
||
| E. James Ferland Chairman of the Board, President and Chief Executive Officer |
||
Date: February 25, 2003
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. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| Signature | Title | Date | ||
| |
|
|
||
| E. JAMES FERLAND | Chairman of the Board, | February 25, 2003 | ||
| |
President and Chief Executive Officer | |||
| E. James Ferland | and Director (Principal Executive Officer) | |||
| THOMAS M. O’FLYNN | Executive Vice President and Chief | February 25, 2003 | ||
| |
Financial Officer (Principal Financial Officer) | |||
| Thomas M. O’Flynn | ||||
| PATRICIA A. RADO | Vice President and Controller | February 25, 2003 | ||
| |
(Principal Accounting Officer) | |||
| Patricia A. Rado | ||||
| ERNEST H. DREW | Director | February 25, 2003 | ||
| |
||||
| Ernest H. Drew | ||||
| ALBERT R. GAMPER, JR. | Director | February 25, 2003 | ||
| |
||||
| Albert R. Gamper, Jr. | ||||
| RAYMOND V. GILMARTIN | Director | February 25, 2003 | ||
| |
||||
| Raymond V. Gilmartin | ||||
| CONRAD K. HARPER | Director | February 25, 2003 | ||
| |
||||
| Conrad K. Harper | ||||
| WILLIAM V. HICKEY | Director | February 25, 2003 | ||
| |
||||
| William V. Hickey | ||||
| SHIRLEY ANN JACKSON | Director | February 25, 2003 | ||
| |
||||
| Shirley Ann Jackson | ||||
| MARILYN M. PFALTZ | Director | February 25, 2003 | ||
| |
||||
| Marilyn M. Pfaltz | ||||
| RICHARD J. SWIFT | Director | February 25, 2003 | ||
| |
||||
| Richard J. Swift | ||||
217
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. The signature of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| Public Service Electric and Gas Company | ||
| By | /s/ ALFRED C. KOEPPE | |
|
|
||
| Alfred C. Koeppe President and Chief Operating Officer |
||
Date: February 25, 2003
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. The signatures of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| Signature | Title | Date | ||
|
|
|
|
||
| E. JAMES FERLAND | Chairman of the Board and Chief | February 25, 2003 | ||
|
|
Executive Officer and Director | |||
| E. James Ferland | (Principal Executive Officer) | |||
| ROBERT E. BUSCH | Senior Vice President — Finance and Chief | February 25, 2003 | ||
|
|
Financial Officer (Principal Financial Officer) | |||
| Robert E. Busch | ||||
| PATRICIA A. RADO | Vice President and Controller | February 25, 2003 | ||
|
|
(Principal Accounting Officer) | |||
| Patricia A. Rado | ||||
| ALBERT R. GAMPER, JR. | Director | February 25, 2003 | ||
|
|
||||
| Albert R. Gamper, Jr. | ||||
| CONRAD K. HARPER | Director | February 25, 2003 | ||
|
|
||||
| Conrad K. Harper | ||||
| MARILYN M. PFALTZ | Director | February 25, 2003 | ||
|
|
||||
| Marilyn M. Pfaltz | ||||
218
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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| PSEG Power LLC | ||
| By | /s/ FRANK CASSIDY | |
|
|
||
| Frank Cassidy | ||
| President and | ||
| Chief Operating Officer | ||
Date: February 25, 2003
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. The signatures of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| Signature | Title | Date | ||
| |
|
|
||
| E. JAMES FERLAND | Chairman of the Board and | February 25, 2003 | ||
| |
Chief Executive Officer and Director | |||
| E. James Ferland | (Principal Executive Officer) | |||
| THOMAS M. O’FLYNN | Executive Vice President and Chief | February 25, 2003 | ||
| |
Financial Officer and Director | |||
| Thomas M. O’Flynn | (Principal Financial Officer) | |||
| PATRICIA A. RADO | Vice President and Controller | February 25, 2003 | ||
| |
(Principal Accounting Officer) | |||
| Patricia A. Rado | ||||
| ROBERT E. BUSCH | Director | February 25, 2003 | ||
| |
||||
| Robert E. Busch | ||||
| FRANK CASSIDY | Director | February 25, 2003 | ||
| |
||||
| Frank Cassidy | ||||
| ROBERT J. DOUGHERTY, JR. | Director | February 25, 2003 | ||
| |
||||
| Robert J. Dougherty, Jr. | ||||
| R. EDWIN SELOVER | Director | February 25, 2003 | ||
| |
||||
| R. Edwin Selover | ||||
| MICHAEL J. THOMSON | Director | February 25, 2003 | ||
| |
||||
| Michael J. Thomson | ||||
| 219 | ||||
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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| PSEG Energy Holdings LLC | ||
| By | /s/ ROBERT J. DOUGHERTY, JR. | |
| Robert J. Dougherty, Jr. President and Chief Operating Officer |
||
Date: February 25, 2003
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. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| Signature | Title | Date | ||
|
|
|
|
||
| E. JAMES FERLAND | Chairman of the Board and | February 25, 2003 | ||
|
|
Chief Executive Officer and Director | |||
| E. James Ferland | (Principal Executive Officer) | |||
| THOMAS M. O’FLYNN | Executive Vice President and | February 25, 2003 | ||
|
|
Chief Financial Officer and Director | |||
| Thomas M. O’Flynn | (Principal Financial Officer) | |||
| DEREK M. DIRISIO | Vice President and Controller | February 25, 2003 | ||
|
|
(Principal Accounting Officer) | |||
| Derek M. DiRisio | ||||
| ROBERT E. BUSCH | Director | February 25, 2003 | ||
|
|
||||
| Robert E. Busch | ||||
| FRANK CASSIDY | Director | February 25, 2003 | ||
|
|
||||
| Frank Cassidy | ||||
| ROBERT J. DOUGHERTY, JR. | Director | February 25, 2003 | ||
|
|
||||
| Robert J. Dougherty, Jr. | ||||
| R. EDWIN SELOVER | Director | February 25, 2003 | ||
|
|
||||
| R. Edwin Selover |
220
| 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. | |
| (a) | Filed by PSE&G with Form 10-K
under the Securities Exchange Act of 1934, on the respective dates indicated,
File No. 001-00973. |
| (b) | Filed by PSE&G with Form 10-Q
under the Securities Exchange Act of 1934, on the respective dates indicated,
File No. 001-00973. |
| (c) | Filed by PSEG with Form 10-K under
the Securities Exchange Act of 1934, on the respective dates indicated,
File No. 001-09120. |
| (d) | Filed with registration statement
of PSE&G under the Securities Exchange Act of 1934, File No. 1-973,
effective July 1, 1935, relating to the registration of various issues of
securities. |
| (e) | Filed with registration statement
of Public Service Enterprise Group Incorporated under the Securities Act
of 1933, No. 33-2935 filed January 28, 1986, relating to PSE&G’s
plan to form a holding company as part of a corporate restructuring. |
| (f) | Filed with PSEG Form 10-K under
the Securities Exchange Act of 1934, on the respective dates indicated,
File No. 001-09120. |
| (g) | Filed by PSE&G with Form 8-A
under the Securities Exchange Act of 1934, on the respective dates indicated,
File No. 001-00973. |
| (h) | Filed by PSE&G with Form 8-K
under the Securities Exchange Act of 1934, on the respective dates indicated,
File No. 001-00973. |
| (i) | Filed by PSE&G with Form 10-K
under the Securities Exchange Act of 1934, on the respective dates indicated,
File No. 001-00973. |
| (j) | Filed by PSE&G with Form 10-Q
under the Securities Exchange Act of 1934, on the respective dates indicated,
File No. 001-00973. |
| (k) | Filed by PSEG with Form 10-K under
the Securities Exchange Act of 1934, on the respective dates indicated,
File No. 001-09120. |
| (l) | Filed with registration statement
of PSE&G under the Securities Exchange Act of 1934, File No. 1-973,
effective July 1, 1935, relating to the registration of various issues of
securities. |
| (m) | Filed with registration statement
of PSE&G under the Securities Act of 1933, No. 2-4995, effective May
20, 1942, relating to the issuance of $15,000,000 First and Refunding Mortgage
Bonds, 3% Series due 1972. |
| (n) | Filed with registration statement
of PSE&G under the Securities Act of 1933, No. 2-7568, effective July
1, 1948, relating to the proposed issuance of 200,000 shares of Cumulative
Preferred Stock. |
| (o) | Filed with registration statement
of PSE&G under the Securities Act of 1933, No. 2-8381, effective April
18, 1950, relating to the issuance of $26,000,000 First and Refunding Mortgage
Bonds, 2 3/4% Series due 1980. |
| (p) | Filed with registration statement
of PSE&G under the Securities Act of 1933, No. 2-12906, effective December
4, 1956, relating to the issuance of 1,000,000 shares of Common Stock. |
| (q) | Filed with registration statement
of PSE&G under the Securities Act of 1933, No. 2-59675, effective September
1, 1977, relating to the issuance of $60,000,000 First and Refunding Mortgage
Bonds, 8 1/8% Series I due 2007. |
| (r) | Filed with registration statement
of PSE&G under the Securities Act of 1933, No. 2-60925, effective March
30, 1978, relating to the issuance of 750,000 shares of Common Stock through
an Employee Stock Purchase Plan. |
| (s) | Filed with registration statement
of PSE&G under the Securities Act of 1933, No. 2-65521, effective October
10, 1979, relating to the issuance of 3,000,000 shares of Common Stock. |
| (t) | Filed with registration statement
of PSE&G under the Securities Act of 1933, No. 2-74018, filed on June
16, 1982, relating to the Thrift Plan of PSE&G. |
| (u) | Filed with registration statement
of PSEG under the Securities Act
of 1933, No. 33-2935 filed January 28, 1986, relating to PSE&G’s
plan to form a holding company as part of a corporate restructuring. |
| (v) | Filed with registration statement
of PSE&G under the Securities Act of 1933, No. 33-13209 filed April
9, 1987, relating to the registration of $575,000,000 First and Refunding
Mortgage Bonds pursuant to Rule 415. |
| (w) | Filed with registration statement of PSE&G under the Securities Act of 1933, No. 333-02763,
effective June 12, 1996, relating to the registration of $350,000,000 of Cumulative Quarterly Income Preferred Securities
of PSE&G Capital Trust I, II and III. |
| (x) | Filed with the registration statement of PSEG under the Securities Act of 1933, No.
333-43241, effective January 8, 1998, relating to the registration of $225,000,000 of Trust Preferred Securities of Enterprise
Capital Trust, I, II and III. |
| (y) | Filed with registration statement
of PSE&G under the Securities Act of 1933, No. 333-76020, effective
February 12, 2002, relating to the registration of $1,000,000,000 of Senior
Debt Securities. |
| (z) | Filed with registration statement
of PSEG under the Securities Act of 1933, No. 333-86372, effective July
3, 2002 relating to the registration of $1.5 billion of Common Stock, Preferred
Stock, Stock Purchase Contracts, Stock Purchase Units and Debt Securities
and PSEG Funding Trust I Preferred Trust Securities. |
| (aa) | Filed with registration statement
of PSEG under the Securities Act of 1933, No. 333-101400, effective December
5, 2002 relating to the registration of $1.0 billion of Common Stock, Preferred
Stock, Stock Purchase Contracts, Stock Purchase Units and Debt Securities
and PSEG Funding Trust II, III and IV Preferred Trust Securities. |
| (bb) | Filed with registration statement
of PSEG under the Securities Act of 1933, No. 033-45491, effective February
4, 1992, relating to the Employee Stock Purchase Plan. |
| PSEG | |||||||||||
| Exhibit Number | |||||||||||
| Previous Filing | |||||||||||
| This Filing | Commission | Exchanges | |||||||||
| 3 | (e) | 3a | (e) | 3a | Certificate of Incorporation Public Service Enterprise | ||||||
| Group Incorporated | |||||||||||
| 3 | b | (z) | 3b | (z) | 3b | By-Laws of Public Service Enterprise | |||||
| 4/16/02 | 4/16/02 | Group Incorporated | |||||||||
| 3 | c | (c) | 3c | (c) | 3c | Certificate of Amendment of Certificate of | |||||
| 4/11/88 | 4/11/88 | Incorporation of Public Service Enterprise Group Incorporated, | |||||||||
| effective April 23, 1987 | |||||||||||
| 3 | d | Amended and Restated Trust Agreement for Enterprise Capital Trust I | |||||||||
| 3 | e | (b) | 3 | (b) | 3 | Amended and Restated Trust Agreement for Enterprise Capital | |||||
| 8/14/98 | 8/14/98 | Trust II | |||||||||
| PSEG | ||||||||||
| Exhibit Number | ||||||||||
| Previous Filing | ||||||||||
| This Filing | Commission | Exchanges | ||||||||
| 3 | f | Amended and Restated Trust Agreement for Enterprise Capital Trust III | ||||||||
| 3 | g | Amended and Restated Trust Agreement for PSEG Funding Trust I | ||||||||
| 3 | h | Amended and Restated Trust Agreement for PSEG Funding Trust II | ||||||||
| 4a(1) | (b) | 4f | (b) | 4f | Indenture between Public Service Enterprise Group Incorporated and | |||||
| 5/13/98 | 5/13/98 | First Union National Bank (now, Wachovia Bank,National | ||||||||
| Association), as Trustee, dated January 1, 1998 providing for | ||||||||||
| Deferrable Interest Subordinated Debentures in Series (relating to | ||||||||||
| Quarterly Preferred Securities) | ||||||||||
| 4a(2) | (b) | 4a | (b) | 4a | First Supplemental Indenture to Indenture dated as of January 1, 1998 | |||||
| 8/14/98 | 8/14/98 | between Public Service Enterprise Group Incorporated and First | ||||||||
| Union National Bank (now, Wachovia Bank, National Association), | ||||||||||
| as Trustee, dated June 1, 1998 providing for the issuance of Floating | ||||||||||
| Rate Deferrable Interest Subordinated Debentures, Series B (relating | ||||||||||
| to Trust Preferred Securities) | ||||||||||
| 4a(3) | (b) | 4b | (b) | 4b | Second Supplemental Indenture to Indenture dated as of January1, | |||||
| 8/14/98 | 8/14/98 | 1998 between Public Service Enterprise Group Incorporated and First | ||||||||
| Union National Bank (now, Wachovia Bank, National Association), | ||||||||||
| as Trustee, dated July 1, 1998 providing for the issuance of | ||||||||||
| Deferrable Interest Subordinated Debentures, Series C (relating to | ||||||||||
| Trust Preferred Securities) | ||||||||||
| 4 | b | (a) | 4f | (a) | 4f | Indenture dated as of November 1, 1998 between Public Service | ||||
| 11/1/00 | 11/1/00 | Enterprise Group Incorporated and First Union National Bank (now, | ||||||||
| Wachovia Bank, National Association) providing for the issuance of | ||||||||||
| Senior Debt Securities | ||||||||||
| 4 | c | First Supplemental Indenture to Indenture dated as of November 1, | ||||||||
| 1998 between Public Service Enterprise Group Incorporated and | ||||||||||
| Wachovia Bank, National Association, as Trustee, dated September | ||||||||||
| 10, 2002 providing for the issuance of Senior Deferrable Notes | ||||||||||
| (Senior Debt Securities) | ||||||||||
| 4 | d | Indenture dated as of December 17, 2002 between Public Service | ||||||||
| Enterprise Group Incorporated and Wachovia Bank, National | ||||||||||
| Association providing for the issuance of Debentures in Series | ||||||||||
| including 8.75% Deferrable Interest Junior Subordinated Debentures, | ||||||||||
| Series D | ||||||||||
| 9 | Inapplicable | |||||||||
| 10a(1) | (c) | 10a(1) | (c) | 10a(1) | Deferred Compensation Plan for Directors | |||||
| 2/25/00 | 2/25/00 | |||||||||
| 10a(2) | (c) | 10a(2) | (c) | 10a(2) | Deferred Compensation Plan for Certain Employees | |||||
| 2/25/00 | 2/25/00 | |||||||||
| 10a(3) | (c) | 10a(3) | (c) | 10a(3) | Limited Supplemental Benefits Plan for Certain Employees | |||||
| 2/25/00 | 2/25/00 | |||||||||
| 10a(4) | (c) | 10a(4) | (c) | 10a(4) | Mid Career Hire Supplemental Retirement Income Plan | |||||
| 2/25/00 | 2/25/00 | |||||||||
| 10a(5) | (c) | 10a(5) | (c) | 10a(5) | Retirement Income Reinstatement Plan for Non-Represented | |||||
| Employees | ||||||||||
| 2/25/00 | 2/25/00 | |||||||||
| 10a(6) | (b) | 10a(6) | (b) | 10a(6) | 1989 Long-Term Incentive Plan, as amended | |||||
| 11/2/02 | 11/2/02 | |||||||||
| 10a(7) | (c) | 10a(7) | (c) | 10a(7) | 2001 Long-Term Incentive Plan | |||||
| 3/06/01 | 3/06/01 | |||||||||
| PSEG | ||||||||
| |
||||||||
| Exhibit Number | ||||||||
| Previous Filing | ||||||||
| This Filing | Commission | Exchanges | ||||||
| 10a(8) | (c) | 10a(8) | (c) | 10a(8) | Restated and Amended Management | |||
| 3/06/01 | 3/06/01 | Incentive Compensation Plan | ||||||
| 10a(9) | (b) | 10 | (b) | 10 | Employment Agreement with E. James Ferland dated | |||
| 8/14/98 | 8/14/98 | June 16, 1998 | ||||||
| 10a(10) | (c) | 10(a)10 | (c) | 10(a)10 | Amendment to Employment Agreement with E. James Ferland dated | |||
| 3/1/02 | 3/1/02 | November 20, 2001 | ||||||
| 10a(11) | (b) | 10a(22) | (a) | 10a(22) | Employment Agreement with Thomas M. O’Flynn | |||
| 11/13/00 | 11/13/00 | dated April 18, 2001 | ||||||
| 10a(12) | (c) | 10(a)12 | (c) | 10(a)12 | Amendment to Employment Agreement with Thomas M. O’Flynn | |||
| 3/1/02 | 3/1/02 | dated December 21, 2001 | ||||||
| 10a(13) | (a) | 10a(14) | (a) | 10a(14) | Letter Agreement with Patricia A. Rado dated | |||
| 02/26/94 | 03/09/94 | March 24, 1993 | ||||||
| 10a(14) | (b) | 10a(21) | (b) | 10a(21) | Employment Agreement with Alfred C. Koeppe dated | |||
| 11/13/00 | 11/13/00 | October 17, 2000 | ||||||
| 10a(15) | (b) | 10a(19) | (b) | 10a(19) | Employment Agreement with Frank Cassidy dated | |||
| 11/13/00 | 11/13/00 | October 17, 2000 | ||||||
| 10a(16) | (b) | 10a(20) | (b) | 10a(20) | Employment Agreement with Robert J. Dougherty, Jr. dated | |||
| 11/13/00 | 11/13/00 | October 17, 2000 | ||||||
| 10a(17) | Stock Plan for Outside Directors, as amended | |||||||
| 10a(18) | (f) | 10a(23) | (f) | 10a(23) | Employment Agreement with Robert E. Busch dated April 24, | |||
| 8/9/01 | 8/9/01 | 2001 | ||||||
| 10a(19) | (bb) | (bb) | Employee Stock Purchase Plan | |||||
| 10a(20) | Compensation Plan for Outside Directors | |||||||
| 11 | Inapplicable | |||||||
| 12 | Computation of Ratios of Earnings to Fixed Charges | |||||||
| 13 | Inapplicable | |||||||
| 16 | Inapplicable | |||||||
| 18 | Independent Auditors’ Preferability Letter dated February 7, 2003 | |||||||
| 21 | Subsidiaries of the Registrant | |||||||
| 22 | Inapplicable | |||||||
| 23 | Independent Auditors’ Consent | |||||||
| 24 | Inapplicable | |||||||
| 99 | Certification by E. James Ferland, pursuant to Section 1350 of | |||||||
| Chapter 63 of Title 18 of the United States Code | ||||||||
| 99a | Certification by Thomas M. O’Flynn, pursuant to Section 1350 | |||||||
| of Chapter 63 of Title 18 of the United States Code | ||||||||
| PSE&G | ||||||||
| Exhibit Number | ||||||||
| Previous Filing | ||||||||
| This Filing | Commission | Exchanges | ||||||
| 3a(1) | (b) | 3a | (b) | 3a | Restated Certificate of Incorporation of PSE&G | |||
| 8/28/86 | 8/29/86 | |||||||
| 3a(2) | (c) | 3a(2) | (c) | 3a(2) | Certificate of Amendment of Certificate of Restated Certificate of | |||
| 4/10/87 | Incorporation of PSE&G filed February 18, 1987 with the State of | |||||||
| New Jersey adopting limitations of liability provisions in | ||||||||
| accordance with an amendment to New Jersey Business | ||||||||
| Corporation Act | ||||||||
| 3a(3) | (a) | 3(a)3 | (a) | 3(a)3 | Certificate of Amendment of Restated Certificate of Incorporation | |||
| 2/3/94 | 2/14/94 | of PSE&G filed June 17, 1992 with the State of New Jersey, | ||||||
| establishing the 7.44% Cumulative Preferred Stock ($100 Par) as a | ||||||||
| series of Preferred Stock | ||||||||
| 3a(4) | (a) | 3(a)4 | (a) | 3(a)4 | Certificate of Amendment of Restated Certificate of Incorporation | |||
| 2/3/94 | 2/14/94 | of PSE&G filed March 11, 1993 with the State of New Jersey, | ||||||
| establishing the 5.97% Cumulative Preferred Stock ($100 Par) as a | ||||||||
| series of Preferred Stock | ||||||||
| 3a(5) | (a) | 3(a)5 | (a) | 3(a)5 | Certificate of Amendment of Restated Certificate of Incorporation | |||
| 2/3/94 | 2/14/94 | of PSE&G filed January 27, 1995 with the State of New Jersey, | ||||||
| establishing the 6.92% Cumulative Preferred Stock ($100 Par) and | ||||||||
| the 6.75% Cumulative Preferred Stock — $25 Par as series of | ||||||||
| Preferred Stock | ||||||||
| 3b(1) | (d) | (d) | Copy of By-Laws of PSE&G | |||||
| 8/8/00 | 8/8/00 | |||||||
| 3c | Amended and Restated Trust Agreement for PSE&G Capital Trust I | |||||||
| 3d(1) | Amended and Restated Trust Agreement for PSE&G Capital Trust II | |||||||
| 3e | (w) | 3.6 | (w) | Trust Agreement for PSE&G Capital Trust III | ||||
| 4/23/96 | 4/23/96 | |||||||
| 4a(1) | (f) | B-1 | (c) | 4b(1) | Indenture between PSE&G and Fidelity Union Trust Company | |||
| 2/18/81 | (now, Wachovia Bank, National Association), as Trustee, dated | |||||||
| August 1, 1924, securing First and Refunding Mortgage Bond | ||||||||
| Indentures between PSE&G and First Fidelity Bank, National | ||||||||
| Association (now, Wachovia Bank, National Association), as | ||||||||
| Trustee, supplemental to Exhibit 4a(1), dated as follows: | ||||||||
| 4a(2) | (i) | 7 | (1a) | (c) | 4b(2) | April 1, 1927 | ||
| 2/18/81 | ||||||||
| 4a(3) | (k) | 2b(3) | (c) | 4b(3) | June 1, 1937 | |||
| 2/18/81 | ||||||||
| 4a(4) | (k) | 2b(4) | (c) | 4b(4) | July 1, 1937 | |||
| 2/18/81 | ||||||||
| 4a(5) | (k) | 2b(5) | (c) | 4b(5) | December 19, 1939 | |||
| 2/18/81 | ||||||||
| 4a(6) | (g) | B-10 | (c) | 4b(6) | March 1, 1942 | |||
| 2/18/81 | ||||||||
| 4a(7) | (k) | 2b(7) | (c) | 4b(7) | June 1, 1949 | |||
| 2/18/81 | ||||||||
| 4a(8) | (k) | 2b(8) | (c) | 4b(8) | May 1, 1950 | |||
| 2/18/81 | ||||||||
| 4a(9) | (k) | 2b(9) | (c) | 4b(9) | October 1, 1953 | |||
| 2/18/81 | ||||||||
| 4a(10) | (k) | 2b(10) | (c) | 4b(10) | May 1, 1954 | |||
| 2/18/81 | ||||||||
| PSE&G | |||||||||
| Exhibit Number | |||||||||
| Previous Filing | |||||||||
| This Filing | Commission | Exchanges | |||||||
| 4a(11) | (j) | 4b(16) | (c) | 4b(11) | November 1, 1956 | ||||
| 2/18/81 | |||||||||
| 4a(12) | (k) | 2b(12) | (c) | 4b(12) | September 1, 1957 | ||||
| 2/18/81 | |||||||||
| 4a(13) | (k) | 2b(13) | (c) | 4b(13) | August 1, 1958 | ||||
| 2/18/81 | |||||||||
| 4a(14) | (k) | 2b(14) | (c) | 4b(14) | June 1, 1959 | ||||
| 2/18/81 | |||||||||
| 4a(15) | (k) | 2b(15) | (c) | 4b(15) | September 1, 1960 | ||||
| 2/18/81 | |||||||||
| 4a(16) | (k) | 2b(16) | (c) | 4b(16) | August 1, 1962 | ||||
| 2/18/81 | |||||||||
| 4a(17) | (k) | 2b(17) | (c) | 4b(17) | June 1, 1963 | ||||
| 2/18/81 | |||||||||
| 4a(18) | (k) | 2b(18) | (c) | 4b(18) | September 1, 1964 | ||||
| 2/18/81 | |||||||||
| 4a(19) | (k) | 2b(19) | (c) | 4b(19) | September 1, 1965 | ||||
| 2/18/81 | |||||||||
| 4a(20) | (k) | 2b(20) | (c) | 4b(20) | June 1, 1967 | ||||
| 2/18/81 | |||||||||
| 4a(21) | (k) | 2b(21) | (c) | 4b(21) | June 1, 1968 | ||||
| 2/18/81 | |||||||||
| 4a(22) | (k) | 2b(22) | (c) | 4b(22) | April 1, 1969 | ||||
| 2/18/81 | |||||||||
| 4a(23) | (k) | 2b(23) | (c) | 4b(23) | March 1, 1970 | ||||
| 2/18/81 | |||||||||
| 4a(24) | (k) | 2b(24) | (c) | 4b(24) | May 15, 1971 | ||||
| 2/18/81 | |||||||||
| 4a(25) | (k) | 2b(25) | (c) | 4b(25) | November 15, 1971 | ||||
| 2/18/81 | |||||||||
| 4a(26) | (k) | 2b(26) | (c) | 4b(26) | April 1, 1972 | ||||
| 2/18/81 | |||||||||
| 4a(27) | (a) | 2 | (c) | 4b(27) | March 1, 1974 | ||||
| 3/29/74 | 2/18/81 | ||||||||
| 4a(28) | (a) | 2 | (c) | 4b(28) | October 1, 1974 | ||||
| 10/11/74 | 2/18/81 | ||||||||
| 4a(29) | (a) | 2 | (c) | 4b(29) | April 1, 1976 | ||||
| 4/6/76 | 2/18/81 | ||||||||
| 4a(30) | (a) | 2 | (c) | 4b(30) | September 1, 1976 | ||||
| 9/16/76 | 2/18/81 | ||||||||
| 4a(31) | (k) | 2b(31) | (c) | 4b(31) | October 1, 1976 | ||||
| 2/18/81 | |||||||||
| PSE&G | ||||||||
| |
||||||||
| Exhibit Number | ||||||||
| Previous Filing | ||||||||
| This Filing | Commission | Exchanges | ||||||
| 4a(32) | (a) | 2 | (c) | 4b(32) | June 1, 1977 | |||
| 6/29/77 | 2/18/81 | |||||||
| 4a(33) | (l) | 2b(33) | (c) | 4b(33) | September 1, 1977 | |||
| 2/18/81 | ||||||||
| 4a(34) | (a) | 2 | (c) | 4b(34) | November 1, 1978 | |||
| 11/21/78 | 2/18/81 | |||||||
| 4a(35) | (a) | 2 | (c) | 4b(35) | July 1, 1979 | |||
| 7/25/79 | 2/18/81 | |||||||
| 4a(36) | (m) | 2d(36) | (c) | 4b(36) | September 1, 1979 (No. 1) | |||
| 2/18/81 | ||||||||
| 4a(37) | (m) | 2d(37) | (c) | 4b(37) | September 1, 1979 (No. 2) | |||
| 2/18/81 | ||||||||
| 4a(38) | (a) | 2 | (c) | 4b(38) | November 1, 1979 | |||
| 12/3/79 | 2/18/81 | |||||||
| 4a(39) | (a) | 2 | (c) | 4b(39) | June 1, 1980 | |||
| 6/10/80 | 2/18/81 | |||||||
| 4a(40) | (a) | 2 | (a) | 2 | August 1, 1981 | |||
| 8/19/81 | 8/19/81 | |||||||
| 4a(41) | (b) | 4e | (b) | 4e | April 1, 1982 | |||
| 4/29/82 | 5/5/82 | |||||||
| 4a(42) | (a) | 2 | (a) | 2 | September 1, 1982 | |||
| 9/17/82 | 9/20/82 | |||||||
| 4a(43) | (a) | 2 | (a) | 2 | December 1, 1982 | |||
| 12/21/82 | 12/21/82 | |||||||
| 4a(44) | (d) | 4(ii) | (d) | 4(ii) | June 1, 1983 | |||
| 7/26/83 | 7/27/83 | |||||||
| 4a(45) | (a) | 4 | (a) | 4 | August 1, 1983 | |||
| 8/19/83 | 8/19/83 | |||||||
| 4a(46) | (d) | 4(ii) | (d) | 4(ii) | July 1, 1984 | |||
| 8/14/84 | 8/17/84 | |||||||
| 4a(47) | (d) | 4(ii) | (d) | 4(ii) | September 1, 1984 | |||
| 11/2/84 | 11/9/84 | |||||||
| 4a(48) | (b) | 4(ii) | (b) | 4(ii) | November 1, 1984 (No. 1) | |||
| 1/4/85 | 1/9/85 | |||||||
| 4a(49) | (b) | 4(ii) | (b) | 4(ii) | November 1, 1984 (No. 2) | |||
| 1/4/85 | 1/9/85 | |||||||
| 4a(50) | (a) | 2 | (a) | 2 | July 1, 1985 | |||
| 8/2/85 | 8/2/85 | |||||||
| 4a(51) | (c) | 4a(51) | (c) | 4a(51) | January 1, 1986 | |||
| 2/11/86 | 2/11/86 | |||||||
| 4a(52) | (a) | 2 | (a) | 2 | March 1, 1986 | |||
| 3/28/86 | 3/28/86 | |||||||
| PSE&G | ||||||||
| Exhibit Number | ||||||||
| |
||||||||
| Previous Filing | ||||||||
| This Filing | Commission | Exchanges | ||||||
| 4a(53) | (a) | 2(a) | (a) | 2(a) | April 1, 1986 (No. 1) | |||
| 5/1/86 | 5/1/86 | |||||||
| 4a(54) | (a) | 2(b) | (a) | 2(b) | April 1, 1986 (No. 2) | |||
| 5/1/86 | 5/1/86 | |||||||
| 4a(55) | (p) | 4a(55) | (p) | 4a(55) | March 1, 1987 | |||
| 4/9/87 | 4/9/87 | |||||||
| 4a(56) | (a) | 4 | (a) | 4 | July 1, 1987 (No. 1) | |||
| 8/17/87 | 8/17/87 | |||||||
| 4a(57) | (d) | 4 | (d) | 4 | July 1, 1987 (No. 2) | |||
| 11/13/87 | 11/20/87 | |||||||
| 4a(58) | (a) | 4 | (a) | 4 | May 1, 1988 | |||
| 5/17/88 | 5/18/88 | |||||||
| 4a(59) | (a) | 4 | (a) | 4 | September 1, 1988 | |||
| 9/27/88 | 9/28/88 | |||||||
| 4a(60) | (a) | 4 | (a) | 4 | July 1, 1989 | |||
| 7/25/89 | 7/26/89 | |||||||
| 4a(61) | (a) | 4 | (a) | 4 | July 1, 1990 (No. 1) | |||
| 7/25/90 | 7/26/90 | |||||||
| 4a(62) | (a) | 4 | (a) | 4 | July 1, 1990 (No. 2) | |||
| 7/25/90 | 7/26/90 | |||||||
| 4a(63) | (a) | 4 | (a) | 4 | June 1, 1991 (No. 1) | |||
| 7/1/91 | 7/2/91 | |||||||
| 4a(64) | (a) | 4 | (a) | 4 | June 1, 1991 (No. 2) | |||
| 7/1/91 | 7/2/91 | |||||||
| 4a(65) | (a) | 4 | (a) | 4 | November 1, 1991 (No. 1) | |||
| 12/2/91 | 12/3/91 | |||||||
| 4a(66) | (a) | 4 | (a) | 4 | November 1, 1991 (No. 2) | |||
| 12/2/91 | 12/3/91 | |||||||
| 4a(67) | (a) | 4 | (a) | 4 | November 1, 1991 (No. 3) | |||
| 12/2/91 | 12/3/91 | |||||||
| 4a(68) | (a) | 4 | (a) | 4 | February 1, 1992 (No. 1) | |||
| 2/27/92 | 2/28/92 | |||||||
| 4a(69) | (a) | 4 | (a) | 4 | February 1, 1992 (No. 2) | |||
| 2/27/92 | 2/28/92 | |||||||
| 4a(70) | (a) | 4 | (a) | 4 | June 1, 1992 (No. 1) | |||
| 6/17/92 | 6/11/92 | |||||||
| 4a(71) | (a) | 4 | (a) | 4 | June 1, 1992 (No. 2) | |||
| 6/17/92 | 6/11/92 | |||||||
| 4a(72) | (a) | 4 | (a) | 4 | June 1, 1992 (No. 3) | |||
| 6/17/92 | 6/11/92 | |||||||
| PSE&G | ||||||||
| Exhibit Number | ||||||||
| Previous Filing | ||||||||
| This Filing | ||||||||
| Commission | Exchanges | |||||||
| 4a(73) | (a) | 4 | (a) | 4 | January 1, 1993 (No. 1) | |||
| 2/2/93 | 2/2/93 | |||||||
| 4a(74) | (a) | 4 | (a) | 4 | January 1, 1993 (No. 2) | |||
| 2/2/93 | 2/2/93 | |||||||
| 4a(75) | (a) | 4 | (a) | 4 | March 1, 1993 | |||
| 3/17/93 | 3/18/93 | |||||||
| 4a(76) | (b) | 4 | (a) | 4 | May 1, 1993 | |||
| 5/27/93 | 5/28/93 | |||||||
| 4a(77) | (a) | 4 | (a) | 4 | May 1, 1993 (No. 2) | |||
| 5/25/93 | 5/25/93 | |||||||
| 4a(78) | (a) | 4 | (a) | 4 | May 1, 1993 (No. 3) | |||
| 5/25/93 | 5/25/93 | |||||||
| 4a(79) | (b) | 4 | (b) | 4 | July 1, 1993 | |||
| 12/1/93 | 12/1/93 | |||||||
| 4a(80) | (a) | 4 | (a) | 4 | August 1, 1993 | |||
| 8/3/93 | 8/3/93 | |||||||
| 4a(81) | (b) | 4 | (b) | 4 | September 1, 1993 | |||
| 12/1/93 | 12/1/93 | |||||||
| 4a(82) | (a) | 4 | (a) | 4 | September 1, 1993 (No. 2) | |||
| 12/1/93 | 12/1/93 | |||||||
| 4a(84) | (a) | 4 | (a) | 4 | February 1, 1994 | |||
| 2/3/94 | 2/14/94 | |||||||
| 4a(85) | (a) | 4 | (a) | 4 | March 1, 1994 (No. 1) | |||
| 3/15/94 | 3/16/94 | |||||||
| 4a(86) | (a) | 4 | (a) | 4 | March 1, 1994 (No. 2) | |||
| 3/15/94 | 3/16/94 | |||||||
| 4a(87) | (d) | 4 | (d) | 4 | May 1, 1994 | |||
| 11/8/94 | 12/2/94 | |||||||
| 4a(88) | (d) | 4 | (d) | 4 | June 1, 1994 | |||
| 11/8/94 | 12/2/94 | |||||||
| 4a(89) | (d) | 4 | (d) | 4 | August 1, 1994 | |||
| 11/8/94 | 12/2/94 | |||||||
| 4a(90) | (d) | 4 | (d) | 4 | October 1, 1994 (No. 1) | |||
| 11/8/94 | 12/2/94 | |||||||
| 4a(91) | (d) | 4 | (d) | 4 | October 1, 1994 (No. 2) | |||
| 11/8/94 | 12/2/94 | |||||||
| 4a(92) | (a) | 4 | (a) | 4 | January 1, 1996 (No.1) | |||
| 1/26/96 | 1/26/96 | |||||||
| 4a(93) | (a) | 4 | (a) | 4 | January 1, 1996 (No. 2) | |||
| 1/26/96 | 1/26/96 | |||||||
| 4a(94) | (c) | 4 | December 1, 1996 | |||||
| 2/26/97 | ||||||||
| PSE&G | ||||||||
| Exhibit Number | ||||||||
| Previous Filing | ||||||||
| This Filing | Commission | Exchanges | ||||||
| |
||||||||
| 4a(95) | (a) | 4 | (a) | 4 | June 1, 1997 | |||
| 6/17/97 | 6/17/97 | |||||||
| 4a(96) | (a) | 4 | (a) | 4 | May 1, 1998 | |||
| 5/15/98 | 5/15/98 | |||||||
| 4a(97) | September 1, 2002 | |||||||
| 4b | (b) | 4 | (b) | 4 | Indenture of Trust between PSE&G and Chase Manhattan Bank | |||
| 12/1/93 | 12/1/93 | (National Association), as Trustee, providing for Secured Medium- | ||||||
| Term Notes dated July 1, 1993 | ||||||||
| 4c(1) | (b) | (c) | Indenture between PSE&G and First Fidelity Bank, National | |||||
| 2/23/95 | 2/23/95 | Association (now, Wachovia Bank, National Association), as | ||||||
| Trustee, dated November 1, 1994, providing for Deferrable Interest | ||||||||
| Subordinated Debentures in Series | ||||||||
| 4c(2) | (a) | 4b(5) | (a) | 4b(5) | Supplemental Indenture between PSE&G and First Fidelity Bank, | |||
| National Association (now, Wachovia Bank, National | ||||||||
| (d) | 4d(2) | (d) | 4d(2) | Association), as Trustee, dated September 1, 1995 providing for | ||||
| 5/13/98 | 5/13/98 | Deferrable Interest Subordinated Debentures, Series B (relating to | ||||||
| Monthly Preferred Securities) | ||||||||
| 4d(1) | (d) | 4e(1) | (d) | 4e(1) | Indenture between PSE&G and First Union National Bank (now, | |||
| 5/13/98 | 5/13/98 | Wachovia Bank, National Association), as Trustee, dated June 1, | ||||||
| 1996 providing for Deferrable Interest Subordinated Debentures in | ||||||||
| Series (relating to Quarterly Preferred Securities) | ||||||||
| 4d(2) | (d) | 4e(2) | (d) | 4e(2) | Supplemental Indenture between PSE&G and First Union National | |||
| 5/13/98 | 5/13/98 | Bank (now, Wachovia Bank, National Association), as Trustee, | ||||||
| dated February 1, 1997 providing for Deferrable Interest | ||||||||
| Subordinated Debentures, Series B (relating to Quarterly Preferred | ||||||||
| Securities) | ||||||||
| 4e | (q) | 4-6 | (q) | 4-6 | Indenture dated as of December 1, 2000 between Public Service | |||
| 2/12/02 | 2/12/02 | and Gas Company and First Union National Bank (now, Wachovia | ||||||
| Bank, National Association), as Trustee, providing for Senior Debt | ||||||||
| Securities. | ||||||||
| 10a(1) | (c) | 10a(1) | (c) | 10a(1) | Deferred Compensation Plan for Directors | |||
| 2/25/00 | 2/25/00 | |||||||
| 10a(2) | (c) | 10a(2) | (c) | 10a(2) | Deferred Compensation Plan for Certain Employees | |||
| 2/25/00 | 2/25/00 | |||||||
| 10a(3) | (c) | 10a(3) | (c) | 10a(3) | Limited Supplemental Benefits Plan for Certain Employees | |||
| 2/25/00 | 2/25/00 | |||||||
| 10a(4) | (c) | 10a(4) | (c) | 10a(4) | Mid Career Hire Supplemental Retirement Income Plan | |||
| 2/25/00 | 2/25/00 | |||||||
| 10a(5) | (c) | 10a(5) | (c) | 10a(5) | Retirement Income Reinstatement Plan for Non-Represented | |||
| Employees | ||||||||
| 2/25/00 | 2/25/00 | |||||||
| 10a(6) | (b) | 10a(6) | (b) | 10a(6) | 1989 Long-Term Incentive Plan, as amended | |||
| 11/2/02 | 11/2/02 | |||||||
| 10a(7) | (c) | 10a(7) | (c) | 10a(7) | 2001 Long-Term Incentive Plan | |||
| 3/5/01 | 3/5/01 | |||||||
| 10a(8) | (c) | 10a(8) | 10a(8) | Restated and Amended Management | ||||
| 3/5/01 | 3/5/01 | Incentive Compensation Plan | ||||||
| PSE&G | ||||||||
| Exhibit Number | ||||||||
| Previous Filing | ||||||||
| This Filing | Commission | Exchanges | ||||||
| 10a(9) | (d) | 10 | (d) | 10 | Employment Agreement with E. James Ferland, dated June 16, | |||
| 8/14/98 | 8/14/98 | 1998 | ||||||
| 10a(10) | (c) | 10(a)10 | (c) | 10(a)10 | Amendment to Employment Agreement with E. James Ferland dated | |||
| 3/1/02 | 3/1/02 | November 20, 2001 | ||||||
| 10a(11) | (c) | 10a(13) | (c) | 10a(13) | Letter Agreement with Patricia A. Rado dated | |||
| 2/26/94 | 3/9/94 | March 24, 1993 | ||||||
| 10a(12) | (d) | 10a(21) | (d) | 10a(21) | Employment Agreement with Alfred C. Koeppe dated | |||
| 11/13/00 | 11/13/00 | October 17, 2000 | ||||||
| 10a(13) | (f) | 10a(23) | (f) | 10a(23) | Employment Agreement with Robert E. Busch dated April 24, | |||
| 8/9/01 | 8/9/01 | 2001 | ||||||
| 11 | Inapplicable | |||||||
| 12 | a | Computation of Ratios of Earnings to Fixed Charges | ||||||
| 12 | b | Computation of Ratios of Earnings to Fixed Charges Plus | ||||||
| Preferred Stock Dividend Requirements | ||||||||
| 13 | Inapplicable | |||||||
| 16 | Inapplicable | |||||||
| 18 | Independent Auditors’ Preferability Letter dated February 7, 2003 | |||||||
| 19 | Inapplicable | |||||||
| 21 | a | Inapplicable | ||||||
| 23 | a | Independent Auditors’ Consent | ||||||
| 24 | Inapplicable | |||||||
| 99 | b | Certification by E. James Ferland, pursuant to Section 1350 of | ||||||
| Chapter 63 of Title 18 of the United States Code | ||||||||
| 99 | c | Certification by Robert E. Busch, pursuant to Section 1350 of | ||||||
| Chapter 63 of Title 18 of the United States Code | ||||||||
Power
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.
| Power | ||||
| |
||||
| Exhibit Number | ||||
| Previous Filing | ||||
| This Filing | Commission | |||
| 3 | a | 3.1 | Certificate of Formation of PSEG Power LLC; Filed by Power with Registration | |
| Statement No. 333-69228 on Form S-4 filed October 5, 2001. | ||||
| 3 | b | 3.2 | PSEG Power LLC Limited Liability Company Agreement; Filed by Power with | |
| Registration Statement No. 333-69228 on Form S-4 filed October 5, 2001. | ||||
| 4 | a | 4.1 | Indenture dated April 16, 2001 between Registrants and The Bank of New York and | |
| form of Subsidiary Guaranty included therein.Filed by Power with Registration | ||||
| Statement No. 333-69228 on Form S-4 filed October 5, 2001. | ||||
| 10 | 10 | Basic Generation Service Contract with PSE&G. Filed by Power with Registration | ||
| Statement No. 333-69228 on Form S-4 filed October 5, 2001. | ||||
| 11 | Inapplicable | |||
| 12 | c | Computation of Ratio of Earnings to Fixed Charges | ||
| 13 | Inapplicable | |||
| 16 | Inapplicable | |||
| 18 | Independent Auditors’ Preferability Letter dated February 7, 2003 | |||
| 19 | Inapplicable | |||
| 24 | Inapplicable | |||
| 99 | d | Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 | ||
| of the United States Code | ||||
| 99 | e | Certification by Thomas M. O’Flynn, pursuant to Section 1350 of Chapter 63 of Title | ||
| 18 of the United States Code | ||||
Energy Holdings
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.
| Energy Holdings | ||||
| Exhibit Number | ||||
| Previous Filing | ||||
| This Filing | Commission | |||
| 3 | a | 3 | Certificate of Formation of PSEG Energy Holdings LLC. Incorporated by reference from Form 8- | |
| K dated October 1, 2002. | ||||
| 3 | b | 3.1 | Certificate of Amendment to Certificate of Formation of PSEGH LLC. | |
| Incorporated by reference from Form 8-K dated October 1, 2002. | ||||
| 3 | c | 3.2 | Limited Liability Company Agreement of PSEG Energy Holdings L.L.C. | |
| Incorporated by reference from Form 8-K dated October 1, 2002. | ||||
| 4 | a | 4.1 | Indenture dated October 8, 1999 between Energy Holdings and First Union | |
| National Bank. Incorporated by reference from Registration Statement No. 333- | ||||
| 95697 filed June 29, 2000. | ||||
| 4 | b | 4 | First Supplemental Indenture to Indenture dated October 8, 1999 between Energy | |
| Holdings and Wachovia Bank, National Association dated September 30, 2002. | ||||
| Incorporated by reference from Form 8-K dated October 1, 2002. | ||||
| 11 | Inapplicable | |||
| 12 | d | Statement regarding Computation of Ratios of Earnings to Fixed Charges | ||
| 13 | Inapplicable | |||
| 16 | Inapplicable | |||
| 19 | Inapplicable | |||
| 24 | Inapplicable | |||
| 99 | f | Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title | ||
| 18 of the United States Code | ||||
| 99 | g | Certification by Thomas M. O’Flynn, pursuant to Section 1350 of Chapter 63 of | ||
| Title 18 of the United States Code | ||||