10-K 1 file001.txt FORM 10-K ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) [ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to

Commission Registrant, State of Incorporation, I.R.S. Employer File Number Address, and Telephone Number Identification No. ---------------- --------------------------------------------- --------------------- 001-09120 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED 22-2625848

(A New Jersey Corporation) 80 Park Plaza P.O. Box 1171 Newark, New Jersey 07101-1171 973 430-7000 http://www.pseg.com ------------------- Securities registered pursuant to Section 12 (b) of the Act: Title of Each Class Name of Each Exchange on Which Registered ------------------------------- ------------------------------------------ Common Stock without par value New York Stock Exchange 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). Securities registered pursuant to Section 12 (g) of the Act: 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%. Floating Rate Notes, LIBOR plus 0.875%, Due 2002. The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates as of January 31, 2002 was $8,470,188,650 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, 2002 ----- ------------------------------- Common Stock, without par value 205,839,018 DOCUMENTS INCORPORATED BY REFERENCE Part of Form 10-K 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 16, 2002, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 6, 2002, as specified herein. 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. [ ] ================================================================================ -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- TABLE OF CONTENTS -----------------

Page ---- PART I ------ Item 1. Business............................................................................................. 1 General.............................................................................................. 1 Risk Factors......................................................................................... 6 Competitive Environment.............................................................................. 13 Regulatory Issues.................................................................................... 14 Customers............................................................................................ 20 Employee Relations................................................................................... 21 Segment Information.................................................................................. 21 Environmental Matters................................................................................ 21 Item 2. Properties........................................................................................... 27 Item 3. Legal Proceedings.................................................................................... 33 Item 4. Submission of Matters to a Vote of Security Holders.................................................. 37 PART II ------- Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................................ 37 Item 6. Selected Financial Data.............................................................................. 38 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................ 39 Corporate Structure.................................................................................. 39 Overview of 2001 and Future Outlook.................................................................. 40 Results of Operations................................................................................ 42 Liquidity and Capital Resources...................................................................... 49 Capital Requirements................................................................................. 55 Qualitative and Quantitative Disclosures About Market Risk........................................... 57 Foreign Operations................................................................................... 61 Accounting Issues.................................................................................... 61 Forward Looking Statements........................................................................... 64 Item 7A. Qualitative and Quantitative Disclosures About Market Risk........................................... 65 Item 8. Financial Statements and Supplementary Data.......................................................... 65 Consolidated Financial Statements.................................................................... 66 Notes to Consolidated Financial tatements............................................................ 71 Financial Statement Responsibility................................................................... 122 Independent Auditors' Report......................................................................... 123 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure................. 124 PART III -------- Item 10. Directors and Executive Officers..................................................................... 124 Item 11. Executive Compensation............................................................................... 125 Item 12. Security Ownership of Certain Beneficial Owners and Management....................................... 125 Item 13. Certain Relationships and Related Transactions....................................................... 126 PART IV ------- Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...................................... 126 Schedule II--Valuation and Qualifying Accounts....................................................... 127 Signatures........................................................................................... 128 Exhibit Index........................................................................................ 129

i -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- PART I ------ ITEM 1. BUSINESS GENERAL PSEG Public Service Enterprise Group Incorporated (PSEG), incorporated under the laws of the State of New Jersey, 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). Unless the context otherwise indicates, all references to "PSEG," "we," "us" or "our" herein mean Public Service Enterprise Group Incorporated, and its consolidated subsidiaries. We have four principal direct wholly-owned subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings Inc. (Energy Holdings) and PSEG Services (Services). The following organization chart shows PSEG and its principal subsidiaries, as well as the principal operating subsidiaries of Power and Energy Holdings. -------- PSEG -------- ----- --------- ---------------------- ------------- PSE&G Power Energy Holdings Services ----- --------- ---------------------- ------------- ------- ------------------- Fossil Global ------- ------------------- ------- ------------------- Nuclear Resources ------- ------------------- ------- ------------------- ER&T Energy Technologies ------- ------------------- PSE&G PSE&G is a New Jersey corporation 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. In August 2000, pursuant to the terms of the Final Decision and Order (Final Order) issued by the New Jersey Board of Public Utilities (BPU) under the New Jersey Energy Master Plan and the New Jersey Electric Discount and Energy Competition Act (Energy Competition Act), PSE&G transferred its electric generation-related assets and liabilities including its wholesale power contracts to Power. PSE&G Transition Funding LLC (Transition Funding), a bankruptcy remote subsidiary of PSE&G, was formed to issue securitization bonds in connection with the partial recovery of its BPU approved stranded costs. 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 1 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- 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 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. PSE&G supplies customers that are not served by a third party supplier (TPS). PSE&G's revenues are based upon tariffs approved by the BPU for this service (see Regulatory Issues). Pursuant to BPU requirements, PSE&G also serves as the supplier of last resort for electric and gas customers within its service territory. PSE&G's revenues are based upon tariffs approved by the BPU and the Federal Energy Regulatory Commission FERC for these services (see Regulatory Issues). 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. Electric Energy Supply PSE&G has contracted with Power to provide the capacity and electricity necessary to meet its needs of customers who do not choose a TPS. Power will provide this basic generation service (BGS) obligation through July 31, 2002. For each annual period thereafter, PSE&G is required to determine the BGS supplier by competitive bid in accordance with BPU requirements. On June 29, 2001 PSE&G and the other three BPU regulated New Jersey electric utility companies submitted a joint filing to the BPU setting forth an auction proposal for the provision of BGS energy supply beginning August 1, 2002. In addition, each company also filed specific contingency plans and information related to the auction. On December 10, 2001 the BPU approved an Internet auction to determine who will supply BGS to utilities, which commenced on February 4, 2002. This competitive auction covered the BGS supply requirement for the period August 1, 2002 to July 31, 2003. As conditions of qualification, applicants agreed that if they became auction winners, they would execute the BGS Master Service Agreement within two days of BPU Certification of the results and they would demonstrate compliance with the credit worthiness requirements. In addition, qualified bidders were required to post bid bonds. On February 15, 2002 the BPU approved the auction results under which PSE&G secured contracts for its expected peak load of 9,600 MW. In addition, PSE&G purchases energy under various non-utility generation (NUG) contracts and sells such energy to Power with the costs and proceeds applied to the non-utility generation market transition clause (NTC) component of PSE&G's rates (see Note 3. Regulatory Assets and Liabilities of Notes to Consolidated Financial Statements (Notes)). Rates for electricity sold in the wholesale energy market are not subject to BPU ratemaking and are competitive in nature. Effective August 1, 2002, PSE&G will sell the generation from the NUGs to the wholesale market. Gas Supply PSE&G supplements natural gas with purchased refinery/landfill gas and liquefied petroleum gas produced from propane. The adequacy of supply of all types of gas is affected by the nationwide availability of all sources of fuel for energy production. 2 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- As of December 31, 2001, the daily gas capacity of PSE&G was as follows:

Type of Gas Therms Per Day --------------------------------------------------------------- --------------------- Natural gas ................................................... 24,379,300 Liquefied petroleum gas ....................................... 2,200,000 Refinery/landfill gas ......................................... 123,000 --------------------- Total ................................................ 26,702,300 =====================

About 40% of the 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. PSE&G's total gas sold to and transported for its various customer classes in 2001 was 3.7 billion therms. Included in this amount were 1 billion therms of gas delivered to customers under PSE&G's transportation tariffs and individual cogeneration contracts. During 2001, PSE&G purchased approximately 3.3 billion therms of gas for its gas operations directly from natural gas producers and marketers. These supplies were transported to New Jersey by four interstate pipeline suppliers. The majority of PSE&G's gas transportation and supply contracts expire at various times over the next 10 years. Since the quantities of gas available to PSE&G under its supply contracts are more than adequate in warm months, PSE&G nominates part of such quantities for storage, to be withdrawn during the winter season when demand peaks. Underground storage capacity currently is approximately 800 million therms. For a discussion of the transfer of PSE&G's gas contracts to Power, see Regulatory Issues-Gas Contract Transfer. The demand for gas by PSE&G's customers is affected by customer conservation, economic conditions, weather, the price relationship between gas and alternative fuels 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. PSE&G was able to meet all of the demands of its firm customers during the 2000-2001 winter season and expects to continue to meet such energy-related demands of its firm customers during the 2001-2002 and 2002-2003 winter seasons. However, the sufficiency of supply could be affected by several factors not within PSE&G'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. PSE&G presently does not anticipate any difficulty in obtaining adequate supplies of natural gas over the next several years. Power Power is a Delaware limited liability company with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Power and its three principal direct wholly-owned subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) were established to acquire, own and operate the generation-related business of PSE&G pursuant to the Final Order issued by the BPU under the Energy Competition Act discussed below. Power also has a finance company subsidiary, PSEG Power Capital Investment Company (Power Capital), which provides certain financing for Power's subsidiaries. Power is a multi-regional generating and energy trading company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and risk management expertise. Power currently has two reportable segments, generation and energy trading. The generation segment of Power's business earns revenues by selling energy on a wholesale basis under contract to its utility affiliate, PSE&G, and to other power marketers and load serving entities (LSE), and by bidding energy, capacity and ancillary services into the wholesale energy market. Power has contracted to sell to BGS suppliers beginning August 1, 2002. The energy trading segment of Power's business earns revenues by trading energy, capacity, fixed transmission rights, fuel and emission allowances in the spot, forward and futures markets. The energy trading segment also earns revenues through financial transactions, including swaps, options and futures in the energy markets. Power's target market, which is herein referred to as the Super 3 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Region, extends from Maine to the Carolinas and the Atlantic Coast to Indiana, encompassing 37% of the nation's power consumption. Power is the single largest power supplier in its primary market, the Pennsylvania-New Jersey-Maryland Power Pool (PJM), which is one of the nation's largest and most well-developed energy markets. Power's generation portfolio consists of 11,487 megawatts (MW) of installed capacity owned or under contract which is diversified by fuel source and market segment. In addition, Power is currently constructing projects which will increase capacity by over 3,500 MW, net of planned retirements. For additional information, see Item 2 - Properties. Power participate primarily in the PJM market, where the pricing of energy was recently modified. Prior to April 1999, the price of energy was based upon the requirement that limited the bid prices for electric energy offered for sale in the PJM market to the variable cost of producing such energy. As of April 1, 1999, the Federal Energy Regulatory Commission (FERC) lifted the requirement. However, transmission constraints have and will continue to affect energy pricing in PJM. All power providers are now paid the locational marginal price (LMP) set through power providers' bids. 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 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. Electric Fuel Supply and Disposal The following table indicates Power's megawatt hour (mWh) output by source of energy in 2001 and its estimated mWh output by source for 2002: Actual Estimated Source 2001 2002 (A) ------------------------------------- ------------ --------------- Nuclear: New Jersey facilities.......... 42% 40% Pennsylvania facilities........ 21% 19% Fossil: Coal: New Jersey facilities.......... 12% 13% Pennsylvania facilities........ 13% 13% Oil and Natural Gas ........... 11% 13% Pumped Storage................. 1% 1% ------------ -------------- Total...................... 100% 100% ============ ============== (A) No assurances can be given that actual output by source will match estimates. Fossil Fossil has an ownership interest in 11 fossil generating stations in New Jersey, one fossil generating station in New York and two fossil generating stations in Pennsylvania. Fossil also has 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. Fossil does not anticipate any difficulties in obtaining adequate coal, natural gas and oil supplies over the next several years. Fossil owns approximately 23% of the Keystone and Conemaugh coal-fired generating stations located in western Pennsylvania and operated by the plants' operator. Fossil has been advised that there are presently no anticipated difficulties in obtaining adequate coal supplies for these facilities over the next several years. 4 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Nuclear 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. Nuclear Fuel Nuclear has several long-term contracts with uranium ore operators, converters, enrichers and fabricators to meet the currently projected fuel requirements for Salem and Hope Creek. Nuclear has been advised by Exelon that it has similar contracts to satisfy the fuel requirements of Peach Bottom. Refueling outages which are expected to last for approximately four to six weeks are scheduled for Salem 1 and 2 and Peach Bottom 2 in 2002. 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 (see Note 8. Financial Instruments, Energy Trading and Risk Management of Notes). 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 energy marketing and trading organization that is active in the long-term and spot wholesale energy markets. Energy Holdings Energy Holdings participates in three energy-related reportable segments through its principal wholly-owned subsidiaries: PSEG Global Inc. (Global), PSEG Resources Inc. (Resources), and PSEG Energy Technologies Inc. (Energy Technologies). Energy Holdings seeks investment opportunities in the rapidly changing global energy markets, with Global focusing on the operating segments of the electric industry and Resources making financial investments in the energy industry. [Energy Technologies focuses on constructing, operating and maintaining heating, ventilating and air conditioning (HVAC) systems and providing energy-related engineering, consulting and mechanical contracting services to industrial and commercial customers.] Energy Holdings also has a finance subsidiary, PSEG Capital Corporation (PSEG Capital), which provides privately-placed debt financing to Energy Holdings' operating subsidiaries on the basis of a minimum net worth maintenance agreement with PSEG (see MD&A - Liquidity and Capital Resources). Energy Holdings is also the parent of Enterprise Group Development Corporation (EGDC), a commercial property management business which is conducting a controlled exit from this business. Global Global develops, owns and operates electric generation and distribution facilities in selected high-growth areas of the worldwide energy market, exclusive of Power's activities in its Super Region target market. In carrying out its strategy, Global's assessment of potential opportunities includes a multi-faceted analysis of the country, potential partners and transaction economics. Global identifies target markets based on economic fundamentals, including expected growth of electricity consumption, evaluation of the social, political and regulatory climates and the opportunities for participation by private power developers. Following the identification of target markets, Global evaluates the possibility of utilizing partners having local contacts and complementary expertise. Global's strategy is to consider investments or projects in which it is the sole or a majority owner if justified by strategic considerations, anticipated returns and other factors. Global focuses on projects which are expected to meet or exceed its specified risk-adjusted rate of return and which present potential synergies with existing projects or anticipated future investments. Global has developed or acquired interests in electric generation and/or distribution facilities in the United States, Argentina, Brazil, Chile, China, India, Italy, Peru, Poland and Venezuela. In addition, projects are in 5 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- construction or advanced development in the United States, Argentina, China, Italy, Oman, Poland, Taiwan, Tunisia and Venezuela. Global expects that future development of projects will take place primarily outside the United States. Global has ownership interests in 31 operating generation projects totaling 4,992 MW (2,047 MW net) and 13 projects totaling 3,205 MW (1,399 MW net) in construction or advanced development. Of Global's generation projects in operation, construction or advanced development 1,350 MW net or 39% are located in the United States. Global currently owns interests in eight distribution companies in Argentina, Brazil, Chile and Peru. For additional information, see Item 2. Properties - Energy Holdings. Fuel supply arrangements are designed to balance Global's ability to meet long-term supply needs with price considerations. Global's project affiliates utilize long-term contracts and spot market purchases to mitigate their exposure. Global believes that there are adequate fuel supplies for the anticipated needs of its generating projects. Global also believes that transmission access and capacity are sufficient at this time for its generation projects in operation or development. Resources Resources focuses on providing energy infrastructure financing in developed countries. 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. Resources seeks to invest in transactions where its expertise and understanding of the inherent risks and operating characteristics of energy-related assets provide a competitive advantage. Resources currently expects to concentrate its future investment activity on energy-related financial transactions. As of December 31, 2001, Resources had approximately $2.4 billion or 79% of its total assets invested in leveraged leases of energy-related plant and equipment. The remainder of Resources' portfolio is further diversified across a wide spectrum of asset types and business sectors including leveraged leases of aircraft, railcars and real estate, limited partnership interests in project finance transactions and leveraged buyout and venture funds. Approximately 95% of the lease investments in Resources' portfolio are with lessees that have investment grade credit ratings. Resources does not manage any fund or partnership in its portfolio. The timing of distributions from certain investments is not within Resources' control. Energy Technologies Energy Technologies is an energy management company that constructs, operates and maintains HVAC systems for and provides energy-related engineering, consulting and mechanical contracting services to industrial and commercial customers in the Northeastern and Middle Atlantic United States. As of December 31, 2001, Energy Technologies had assets of $290 million. We are evaluating the future prospects of Energy Technologies' business model and its fit in the PSEG portfolio given the slower pace of retail energy deregulation in the markets in which we are active, as well as, the substandard performance of Energy Technologies since its inception. 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. RISK FACTORS The following factors should be considered when reviewing our business and are relied upon by us in issuing any forward-looking statements. Such factors could affect actual results and cause such results to differ materially 6 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- from those expressed in any forward-looking statements made by, or on behalf of us. Some or all of these factors may apply to us and our subsidiaries. Because a Portion of Our Business is Conducted Outside the United States, Adverse International Developments Could Negatively Impact Our Business A key component of our business strategy is the development, acquisition and operation of projects outside the United States. The economic and political conditions in certain countries where Global has interests, or in which Global is or could be exploring development or acquisition opportunities, present risks that may be different than those found in the United States including: delays in permitting and licensing, construction delays and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation or nullification of existing contracts and changes in law or tax policy. Changes in the legal environment in foreign countries in which Global may develop or acquire projects could make it more difficult to obtain non-recourse project refinancing on suitable terms and could impair Global's ability to enforce its rights under agreements relating to such projects. Operations in foreign countries also present risks associated with currency exchange and convertibility, inflation and repatriation of earnings. In some countries in which Global may develop or acquire projects in the future, economic and monetary conditions and other factors could affect Global's ability to convert its cash distributions to United States Dollars or other freely convertible currencies, or to move funds offshore from such countries. Furthermore, the central bank of any such country may have the authority to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to approve distributions to foreign investors. 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, United States Dollars or a currency freely convertible into United States Dollars, its ability to do so in all cases may be limited. Credit, Commodity, and Financial Market Risks May Have an Adverse Impact The revenues generated by the operation of our generating stations are subject to market risks that are beyond our control. Our generation output will either be used to satisfy our wholesale contracts or be sold into the competitive power markets or under other bilateral contracts. Participants in the competitive power markets are not guaranteed any specified rate of return on their capital investments through recovery of mandated rates payable by purchasers of electricity. Although a majority of our revenue is generated by the current BGS contract with PSE&G (which expires on July 31, 2002 and is replaced with various contracts with direct bidders of the New Jersey BGS Auction) and from bilateral contracts for the sale of electricity with third-party LSEs and power marketers, generation revenues and results of operations will be dependent upon prevailing market prices for energy, capacity and ancillary services in the markets we serve. Among the factors that will influence the market prices for energy, capacity and ancillary services are: o the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities that may be able to produce electricity less expensively; o changes in the rules set by regulatory authorities with respect to the manner in which electricity sales will be priced; o transmission congestion in PJM and/or other competitive markets; o the operation of nuclear generation plants in PJM and other competitive markets beyond their presently expected dates of decommissioning; o prevailing market prices for enriched uranium, fuel oil, coal and natural gas and associated transportation costs; o fluctuating weather conditions; o reduced growth rate in electricity usage as a result of factors such as national and regional economic conditions and the implementation of conservation programs; and o changes in regulations applicable to PJM and other Independent System Operators (ISO). 7 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- As a result of the BGS auction, Power has entered into a contract with the direct suppliers of the New Jersey electric utilities, including PSE&G, commencing August 1, 2002. These bilateral contracts are subject to credit risk. This credit risk relates to the ability of counterparties to meet their payment obligations for the power delivered under each BGS contract. Depending upon the creditworthiness of the counterparty, this risk may be substantially higher than the risk associated with potential nonpayment by PSE&G under the BGS contract expiring July 31, 2002. Any failure to collect these payments under the new BGS contracts with counterparties could have a material impact on our results of operations, cash flows, and financial position. Energy Obligations, Available Supply and Trading Risks May Have an Adverse Impact Our energy trading and marketing business frequently involves the establishment of energy trading positions in the wholesale energy markets on long-term and short-term bases. To the extent that we have forward purchase contracts to provide or purchase energy in excess of demand, a downturn in the markets is likely to result in a loss from a decline in the value of such long positions as we attempt to sell energy in a falling market. Conversely, to the extent that we enter into forward sales contracts to deliver energy we do not own, or take short positions in the energy markets, an upturn in the energy markets is likely to expose us to losses as we attempt to cover our short positions by acquiring energy in a rising market. If the strategy we utilize to hedge our exposures to these various risks is not effective, we could incur significant losses. Our substantial energy trading positions can also be adversely affected by the level of volatility in the energy markets that, in turn, depends on various factors, including weather in various geographical areas and short-term supply and demand imbalances, which cannot be predicted with any certainty. In addition, we are exposed to the risk that counterparties will not perform their obligations. Although we have devoted significant resources to develop our risk management policies and procedures as well as counterparty credit requirements, and will continue to do so in the future, we can give no assurance that losses from our energy trading activities will not have a material adverse effect on our business, prospects, results of operations, financial condition or net cash flows. In connection with its energy trading business, Power must meet certain credit quality standards as are required by counterparties. Standard industry contracts generally require trading counterparties to maintain investment grade rating. These same contracts provide reciprocal benefits to Power. If Power loses its investment grade credit rating, ER&T would have to provide collateral (letters of credit or cash), which would significantly impact the energy trading business. This would increase our costs of doing business and limit our ability to successfully conduct our energy trading operations. The Electric Energy Industry is Undergoing Substantial Change The electric energy industry in the State of New Jersey, across the country and around the world is undergoing major transformations. As a result of deregulation and the unbundling of energy supplies and services, the electric energy markets are now open to competition from other suppliers in most markets. Increased competition from these suppliers could have a negative impact on our wholesale and retail sales. We are affected by many issues that are common to the electric industry such as: o ability to obtain adequate and timely rate relief, cost recovery, including unsecuritized stranded costs, and other necessary regulatory approvals; o deregulation, the unbundling of energy supplies and services and the establishment of a competitive energy marketplace for products and services; o energy sales retention and growth; o revenue stability and growth; o nuclear operations and decommissioning; o increased capital investments attributable to environmental regulations; o managing energy trading operations; o ability to complete development or acquisition of current and future investments; 8 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- o managing electric generation and distribution operations in locations outside of traditional utility service territory; o exposure to market price fluctuations and volatility; o regulatory restrictions on affiliate transactions; and o debt and equity market concerns. Generation Operating Performance May Fall Below Projected Levels The risks associated with operating power generation facilities (each of which could result in performance below expected capacity levels) include: o breakdown or failure of equipment or processes; o disruptions in the transmission of electricity; o labor disputes; o fuel supply interruptions; o limitations which may be imposed by environmental or other regulatory requirements; o permit limitations; and o operator error or catastrophic events such as fires, earthquakes, explosions, floods, acts of war or terrorism or other similar occurrences. Operation below expected capacity levels may result in lost revenues, increased expenses and penalties. Individual facilities may be unable to meet operating and financial obligations resulting in reduced cash flow. If Our Operating Performance or Cash Flow from Minority Interests Falls Below Projected Levels, We May Not Be Able to Service Our Debt The risks associated with operating power generation facilities include the breakdown or failure of equipment or processes, labor disputes and fuel supply interruption, each of which could result in performance below expected capacity levels. Operation below expected capacity levels may result in lost revenues, increased expenses, higher maintenance costs and penalties, in which case there may not be sufficient cash available to service project debt. In addition, many of Global's generation projects rely on a single fuel supplier and a single customer for the purchase of the facility's output under a long term contract. While Global generally has liquidated damage provisions in its contracts, the default by a supplier under a fuel contract or a customer under a power purchase contract could adversely affect the facility's cash generation and ability to service project debt. Countries in which Global owns and operates electric and gas distribution facilities may impose financial penalties if reliability performance standards are not met. In addition, inefficient operation of the facilities may cause lost revenue and higher maintenance expenses, in which case there may not be sufficient cash available to service project debt. Our ability to control investments in which we own a minority interest is limited. Assuming a minority ownership role presents additional risks, such as not having a controlling interest over operations and material financial and operating matters or the ability to operate the assets more efficiently. As such, neither we nor Global are able to unilaterally cause dividends or distributions to be made to us or Global from these operations. Minority investments may involve risks not otherwise present for investments made solely by us and our subsidiaries, including the possibility that a partner, majority investor or co-venturer might become bankrupt, may have different interests or goals, and may take action contrary to our instructions, requests, policies or business objectives. Also, if no party has full control, there could be an impasse on decisions. In addition, certain investments of Resources are managed by unaffiliated entities which limits Resources' ability to control the activities or performance of such investments and managers. Failure to Obtain Adequate and Timely Rate Relief May Have an Adverse Impact As a public utility, PSE&G's rates are regulated by the BPU and the FERC. These rates are designed to recover its operating expenses and allow it to earn a fair return on its rate base, which primarily consists of its property, plant and equipment less various adjustments. These rates include its electric and gas tariff rates subject to regulation by the BPU as well as its transmission rates contained in the PJM Open Access Transmission Tariff subject to regulation by the FERC. PSE&G's base rates are set by the BPU for electric distribution and gas distribution and are effective until the time a new rate case is brought to the BPU. These base rate cases generally take place every few years. Certain limited categories of costs, such as societal benefits and gas residential commodity costs, are recovered through adjustment charges that are periodically trued-up to actual costs and reset. If these costs exceed the amount included in PSE&G's adjustment charges, there will be a negative impact on cash flows. PSE&G's rates for electric transmission are subject to change based on policies and procedures established by the FERC. If PSE&G's operating expenses (other than costs recovered through adjustment charges) exceed the amount included in its base rates or in its FERC jurisdictional rates, there will be a negative impact on earnings and operating cash flows. Certain electric and gas distribution facilities of Global are rate-regulated enterprises. Rates charged to customers are established by governmental authorities and are currently sufficient to cover all operating costs and provide a return. However, in Argentina, we face considerable fiscal and cash uncertainties, including potential asset impairments, due to the current economic, political and social crisis. We can give no assurances that rates will, in the future, be sufficient to cover such costs and provide a return on Global's investment. In addition, future rates may not be adequate to provide cash flow to pay principal and interest on Global's subsidiaries' and affiliates' debt and to enable such subsidiaries and affiliates to comply with the terms of debt agreements. 9 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- We and Our Subsidiaries are Subject to Substantial Competition From Well Capitalized Participants in the Worldwide Energy Markets We and our subsidiaries are subject to substantial competition in the United States and in international markets from merchant generators, domestic and multi-national utility generators, fuel supply companies, engineering companies, equipment manufacturers and affiliates of other industrial companies. Restructuring of worldwide energy markets, including the privatization of government-owned utilities and the sale of utility-owned assets, is creating opportunities for, and substantial competition from, well-capitalized entities which may adversely affect our ability to make investments on favorable terms and achieve our growth objectives. Increased competition could contribute to a reduction in prices offered for power and could result in lower returns which may affect our ability to service our outstanding indebtedness, including short-term debt. Deregulation may continue to accelerate the current trend toward consolidation among domestic utilities and could also result in the splitting of vertically-integrated utilities into separate generation, transmission and distribution businesses. As a result, additional competitors could become active in the merchant generation business. Resources faces competition from numerous well-capitalized investment and finance company affiliates of banks, utilities and industrial companies. Energy Technologies faces substantial competition from utilities and their affiliates, and HVAC and mechanical contractors. Our Ability to Service Our Debt Could Be Limited We are a holding company with no material assets other than the stock of our subsidiaries and project affiliates. Accordingly, all of our operations are conducted by our subsidiaries and project affiliates which are separate and distinct legal entities that have no obligation, contingent or otherwise, to pay any amounts when due on our debt or to make any funds available to us to pay such amounts. As a result, our debt will effectively be subordinated to all existing and future debt, trade creditors, and other liabilities of our subsidiaries and project affiliates and our rights and hence the rights of our creditors to participate in any distribution of assets of any such subsidiary or project affiliate upon its liquidation or reorganization or otherwise would be subject to the prior claims of such subsidiary's or project affiliate's creditors, except to the extent that our claims as a creditor of such subsidiary or project affiliate may be recognized. We depend on our subsidiaries' and project affiliates' cash flow and our access to capital in order to service our indebtedness. The project-related debt agreements of subsidiaries and project affiliates generally restrict their ability to pay dividends, make cash distributions or otherwise transfer funds to us. These restrictions may include achieving and maintaining financial performance or debt coverage ratios, absence of events of default, or priority in payment of other current or prospective obligations. Our subsidiaries have financed some investments using non-recourse project level financing. Each non-recourse project financing is structured to be repaid out of cash flows provided by the investment. In the event of a default under a financing agreement which is not cured, the lenders would generally have rights to the related assets. In the event of foreclosure after a default, our subsidiary may lose its equity in the asset or may not be entitled to any cash that the asset may generate. Although a default under a project financing agreement will not cause a default with respect to our debt and that of our subsidiaries, it may materially affect our ability to service our outstanding indebtedness. We can give no assurances that our current and future capital structure, operating performance or financial condition will permit us to access the capital markets or to obtain other financing at the times, in the amounts and on the terms necessary or advisable for us to successfully carry out our business strategy or to service our indebtedness. 10 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Power Transmission Facilities May Impact Our Ability to Deliver Our Output to Customers If transmission is disrupted, or if transmission capacity is inadequate, our ability to sell and deliver our electric energy products and grow our business may be adversely impacted. If a region's power transmission infrastructure is inadequate, our ability to generate revenues may be limited. Regulatory Issues Significantly Impact Our Operations The electric power generation business is subject to substantial regulation and permitting requirements from federal, state and local authorities. We are required to comply with numerous laws and regulations and to obtain numerous governmental permits in order to operate our generation stations. We believe that we have obtained all material energy-related federal, state and local approvals including those required by the Nuclear Regulatory Commission (NRC), currently required to operate our generation stations. Although not currently required, additional regulatory approvals may be required in the future due to a change in laws and regulations or for other reasons. No assurance can be given that we will be able to obtain any required regulatory approval that we may require in the future, or that we will be able to obtain any necessary extension in receiving any required regulatory approvals. If we fail to obtain or comply with any required regulatory approvals, there could be a material adverse effect on our ability to operate our generation stations or to sell electricity to third parties. We are subject to pervasive regulation by the NRC with respect to the operation of our nuclear generation stations. 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 applicable requirements are also required. The NRC has the ultimate authority to determine whether any nuclear generation unit may operate. We can give no assurance that existing regulations will not be revised or reinterpreted, that new laws and regulations will not be adopted or become applicable to us or any of our generation stations or that future changes in laws and regulations will not have a detrimental effect on our business. 11 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Environmental Regulation May Limit Our Operations We are required to comply with numerous statutes, regulations and ordinances relating to the safety and health of employees and the public, the protection of the environment and land use. These statutes, regulations and ordinances are constantly changing. While we believe that we have obtained all material environmental-related approvals required as of the date hereof to own and operate our facilities or that such approvals have been applied for and will be issued in a timely manner, we may incur significant additional costs because of compliance with these requirements. Failure to comply with environmental statutes, regulations and ordinances could have a material effect on us, including potential civil or criminal liability and the imposition of clean-up liens or fines and expenditures of funds to bring our facilities into compliance. We can give no assurance that we will be able to: o obtain all required environmental approvals that we do not yet have or that may be required in the future; o obtain any necessary modifications to existing environmental approvals; o maintain compliance with all applicable environmental laws, regulations and approvals; or recover any resulting costs through future sales. Delay in obtaining or failure to obtain and maintain in full force and effect any such environmental approvals, or delay or failure to satisfy any applicable environmental regulatory requirements, could prevent construction of new facilities, operation of our existing facilities or sale of energy there from or could result in significant additional cost to us. We Are Subject to More Stringent Environmental Regulation than Many of Our Competitors Our facilities are subject to both federal and state pollution control requirements. Most of our generating facilities are located in the State of New Jersey. In particular, New Jersey's environmental programs are generally considered to be more stringent in comparison to similar programs in other states. As such, there may be instances where the facilities located in New Jersey are subject to more stringent and therefore, more costly pollution control requirements than competitive facilities in other states. Insurance Coverage May Not Be Sufficient We have insurance for our facilities, including all-risk property damage insurance, commercial general public liability insurance, boiler and machinery coverage, nuclear liability and, for our nuclear generating units, replacement power and business interruption insurance in amounts and with deductibles that we consider appropriate. We can give no assurance that such insurance coverage will be available in the future on commercially reasonable terms nor that the insurance proceeds received for any loss of or any damage to any of our facilities will be sufficient to permit us to continue to make payments on our debt. Additionally, certain properties that we own may not be insured in the event of a terrorist activity. Acquisition, Construction and Development Activities May Not Be Successful We may seek to acquire, develop and construct new energy projects, the completion of any of which is subject to substantial risk. Such activity requires a significant lead time and requires us to expend significant sums for preliminary engineering, permitting, fuel supply, resource exploration, legal and other development expenses in preparation for competitive bids or before it can be established whether a project is economically feasible. The construction, expansion or refurbishment of a generation, transmission or distribution facility may involve equipment and material supply interruptions, labor disputes, unforeseen engineering, environmental and geological problems and unanticipated cost overruns. The proceeds of any insurance, vendor warranties or performance guarantees may not be adequate to cover lost revenues, increased expenses or payments of liquidated damages. In addition, some power purchase contracts permit the customer to terminate the related contract, retain security posted by the developer as liquidated damages or change the payments to be made to the subsidiary or the project affiliate in 12 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- the event certain milestones, such as commencing commercial operation of the project, are not met by specified dates. If project start-up is delayed and the customer exercises these rights, the project may be unable to fund principal and interest payments under its project financing agreements. We can give no assurance that we will obtain access to the substantial debt and equity capital required to develop and construct new generation projects or to refinance existing projects to supply anticipated future demand. Changes in Technology May Make our Power Generation Assets Less Competitive A key element of our business plan is that generating power at central power plants produces electricity at relatively low cost. There are other technologies that produce electricity, most notably fuel cells, microturbines, windmills and photovoltaic (solar) cells. 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. If this were to happen, our market share could be eroded and the value of our power plants could be significantly impaired. Changes in technology could also alter the channels through which retail electric customers buy electricity, thereby affecting our financial results. Recession, Acts of War or Terrorism Could Have an Adverse Impact Consequences of the September 11, 2001 terrorist attacks on the United States are difficult to predict. The consequences of a prolonged recession and market conditions may include the continued uncertainty of energy prices and the capital and commodity markets. We cannot predict the impact of any continued economic slowdown or fluctuating energy prices; however, such impact could have a material adverse effect on its financial condition, results of operations and net cash flows. Like other operators of major industrial facilities, our generation plants, fuel storage facilities and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and/or significant additional costs to repair, which could have a material adverse impact on our financial condition, results of operation and net cash flows. COMPETITIVE ENVIRONMENT The regulatory structure which has historically governed the electric and gas utility industries in the United States 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. States have acted independently to deregulate the electric and gas utility industries. Recent experience in California, with energy shortages, high costs and financial difficulties of utilities and the Enron bankruptcy 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, buying or selling generation capacity and the anticipated resulting industry consolidation have a profound effect on us and our subsidiaries, providing us with new opportunities and exposing us to new risks (see Risk Factors and Overview of 2001 and Future Outlook of MD&A). 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 FERC's 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 issued an order that resulted in expanded access to transmission lines, providing eligible third-party wholesale marketers clear transmission access. These actions have enabled power marketers, merchant generators, Exempt Wholesale Generators (EWGs) and utilities to compete actively in wholesale energy markets, consumers to have the right to choose their energy suppliers and competition to set the price of the generation component of electricity bills in deregulated areas. 13 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Internationally, many countries continue to privatize their electric and gas industries. These efforts include selling of government-owned transmission and distribution and gas assets. In addition, various countries have encouraged private foreign development of generating facilities. 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 an alternate electric or gas suppliers. Power In the regions where Power is the most active, most states have already begun the process of restructuring their electricity markets. As markets continue to evolve, several types of competitors have or will emerge in the markets in which Power participates. These competitors include merchant generators with or without trading capabilities, other utility affiliates that have formed generation and/or trading affiliates, aggregators, wholesale power marketers or combinations thereof. These participants will compete with one another buying and selling in wholesale power pools, entering into bilateral contracts and/or selling to aggregated retail customers. Power believes that its asset size and location, regional market knowledge and integrated functions will allow it to compete effectively in its selected markets. Energy Holdings Energy Holdings and its subsidiaries are subject to substantial competition in the United States as well as in the international markets from merchant generators, 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. Restructuring of worldwide energy markets, including the privatization of government-owned utilities and the sale of utility-owned assets, is creating opportunities for Energy Holdings, and likewise is creating substantial competition from well-capitalized entities which may adversely affect Energy Holdings' ability to make investments on favorable terms and achieve its growth objectives. REGULATORY ISSUES State Regulation As a New Jersey public utility, PSE&G has been 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. PSEG, Power and Energy Holdings 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. 14 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- PSE&G New Jersey Energy Master Plan Proceedings, Securitization and Related Orders Following the enactment of the Energy Competition Act, the BPU rendered its Final Order relating to PSE&G's rate unbundling, stranded costs and restructuring proceedings providing, among other things, for the transfer to an affiliate of all of PSE&G's electric generation facilities, plant and equipment for $2.443 billion and all other related property, including materials, supplies and fuel at the net book value thereof, together with associated rights and liabilities. PSE&G, pursuant to the Final Order, transferred its electric generating facilities and wholesale power contracts to Power and its subsidiaries on August 21, 2000 in exchange for a promissory note from Power in an amount equal to the purchase price of $2.786 billion. Power paid the promissory note on January 31, 2001 at which time the transferred assets were released from the lien of PSE&G's First and Refunding Mortgage (Mortgage). The Energy Competition Act and the related BPU proceedings, including the Final Order, referred to as the Energy Master Plan Proceedings, opened the New Jersey energy markets to competition by allowing all New Jersey retail electric and gas customers to select their suppliers. For further discussion of the Energy Master Plan Proceedings, see Note 3. Regulatory Issues and Accounting Impacts of Deregulation of Notes. In accordance with the Final Order, PSE&G reduced customer rates by 5% in August 1999, an additional 2% after the securitization transaction in February of 2001, another 2% in August 2001, and PSE&G is scheduled to reduce rates 4.9% in August 2002, for a total 13.9% rate reduction since August 1999. These rate reductions reduce the market transition charge (MTC) revenues that PSE&G remits to Power as part of its BGS contract. BGS Auction The BPU approved an auction to identify energy suppliers for our obligation beginning on August 1, 2002. On February 15, 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. Under the BPU approved supply contracts, PSE&G will pay $.0511 per kWh to obtain electricity for 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 our current rate structure, the difference will be deferred and is expected to be recovered with interest in the future. PSE&G will sell the power it receives from NUG contracts into the wholesale energy market, which should offset this underrecovery. PSE&G estimates that the underrecovery relating to the BGS for the period ending July 31, 2003 will amount to approximately $250 million, with a net amount of $125 million after factoring in sales of power relating to NUG contracts. If a supplier defaults on its obligation to provide energy to PSE&G, the energy needed for PSE&G to meets its requirements will be purchased at market prices in accordance with the procedures approved by the BPU. To the extent that the market prices exceed the auction contract price, the difference will be deferred and collected from PSE&G customers as provided in the BPU Order approving the auction process. Electric Base Rate Case In accordance with the Final Order, PSE&G is expected to file an electric base rate case during 2002 that would be effective on August 1, 2003. This case may impact our earnings and cash flows; however, PSE&G cannot predict the actual effects at this time. 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 (Affiliate Standards) 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. The BPU has conducted an audit of New Jersey utilities' competitive activities and compliance with such Affiliate Standards and is expected to issue an order on the audit in 2002. The 15 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- adoption of Affiliate Standards did not have a material adverse effect on our financial condition, results of operations or net cash flows. Gas Unbundling The Energy Competition Act also required that all customers have the ability to choose a competitive gas supplier. In 2000, the BPU issued a written order providing for the unbundling of firm rate schedules into commodity and transportation components and for changes in existing rate schedules. The new rates were implemented for all service provided on and after August 1, 2000. The main features of the gas unbundling are: the development of a Societal Benefits Clause (SBC) to recover specific costs including, social programs, Demand Side Management costs (DSM), Remediation Adjustment Clause (RAC) and consumer education; the development of a Realignment Adjustment Charge to recover lost revenues incurred by PSE&G (subject to certain criteria) as a result of customers switching from commodity service to transportation service; the reallocation of approximately $40 million from transportation rates to commodity and balancing rates; an incentive of approximately 0.9 cents per therm for all customers who leave PSE&G to shop with a TPS and an additional incentive of 1.4 cents per therm for residential customers who leave PSE&G to shop with a TPS. Gas Contract Transfer On August 11, 2000, PSE&G filed a gas merchant restructuring plan with the BPU. On January 9, 2002, the BPU approved an amended stipulation which authorized the transfer of PSE&G's gas supply business, including its interstate capacity, storage and gas supply contracts to ER&T which will, under a requirements contract, provide gas supply to PSE&G to serve its Basic Gas Supply Service (BGSS) customers. The transfer is anticipated to take place in April 2002. The gas contract transfer is expected to reduce volatility in PSE&G's cash flows. Gas residential commodity costs, are currently recovered through adjustment charges that are periodically trued-up to actual costs and reset. After the gas contract transfer, PSE&G will pay ER&T the amount PSE&G charges its gas distribution customers for the commodity. Industrial and commercial BGSS customers will be priced under PSE&G's Market Priced Gas Service (MPGS). Residential BGSS customers will remain under current pricing until April 1, 2004, after which, subject to further BPU approval, those residential gas customers would also move to MPGS service. Gas Base Rate Case and Commodity Charges The BPU has granted PSE&G authority to change the Monthly Pricing Mechanism (MPM) in its levelized gas adjustment clause (LGAC) to cover currently estimated gas price increases on a per month basis, exercisable in any month without an annual limit. In May 2001, PSE&G filed a petition with the BPU for authority to revise its gas property depreciation rates (Depreciation Case). In this filing, PSE&G requested authority to implement its proposed depreciation rates simultaneously for book purposes and ratemaking purposes when the BPU implements new tariffs designed to recover the additional annual revenues resulting from the gas base rate case discussed below. In May 2001, PSE&G filed a petition with the BPU requesting an increase in gas base rates of $171 million for gas delivery service (Gas Base Rate Case). The requested increase was for an overall gas revenue increase of 7.06% to reflect current costs. PSE&G filed the Gas Base Rate Case because the gas base rates, in effect since November 1991, did not reasonably reflect capital investments and other costs required to maintain the gas utility infrastructure. The BPU consolidated the Depreciation Case and the Gas Base Rate Case. In November 2001, PSE&G filed and served its 2001 LGAC filing, requesting approximately a 10% reduction. PSE&G requested that such filing be retained by the BPU and implemented simultaneously with the order in the Gas 16 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Base Rate Case. Also in November 2001, PSE&G made a compliance filing with the BPU to implement an approximate 3% increase through the Gas Cost Underrecovery Adjustment (GCUA) surcharge effective December 1, 2001. This surcharge is designed to recover its October 2001 gas underrecovery balance of $130 million. In January 2002, the BPU issued an order approving the increase. In January 2002, the BPU issued an order approving a Settlement under which PSE&G will receive an additional $90 million of gas base rate revenues, approximately $8 million of which results from gas depreciation rate changes. This will occur simultaneously with PSE&G's implementation of its previously approved 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. The $8 million gas depreciation rate changes are due primarily to the shortening of the useful lives for general plant and equipment. This adjustment will have no impact on earnings as it will be offset by increased operating cash flows in a normal business environment. Assuming current cost levels and a normal business environment, the $82 million balance of PSE&G's gas base rate increase will have a positive impact on earnings and operating cash flows. The settlement set PSE&G's gas rate base at approximately $1.6 billion, its rate of return on this rate base at 8.27% and its cost of capital or total return on equity of its gas operations at 10%. 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 GCUA will have no impact on earnings and 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. Focused Audit For information regarding the 1992 BPU proceeding concerning the relationship of PSE&G to our non-utility businesses (Focused Audit), see Liquidity and Capital Resources of Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A). Federal Regulation Certain of our subsidiaries' domestic operations are subject to regulation by FERC with respect to certain matters, including interstate sales and exchanges of electric transmission, capacity and energy. We have claimed an exemption from regulation by the Securities and Exchange Commission (SEC) as a registered holding company under the Public Utility Holding Company Act of 1935 (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 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 we were no longer exempt from PUHCA, we and our 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. We believe, however, that this would not have a material adverse effect on us and our subsidiaries. PSE&G, Fossil, Nuclear and Global are also subject to the rules and regulation of the United States Environmental Protection Agency (EPA), U.S. Department of Transportation (DOT) and U.S. Department of Energy (DOE). For information on environmental regulation, see Environmental Matters. 17 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- FERC RTO Orders In December 1999, FERC promulgated a Final Rule (Order 2000) in the Regional Transmission Organization (RTO) rulemaking proceeding. In October 2000, PJM and nine PJM transmission owners, including us, made a filing with FERC stating that PJM is an RTO that meets or exceeds the requirements of Order 2000. Included in this filing was a PJM rate proposal designed to provide for deferral recovery of reasonable, risk-adjusted returns on new transmission investments in the PJM region, an accelerated recovery period for such new investments, and a rate moratorium of current charges through December 31, 2004. In July 2001, FERC issued a series of orders that, amongst other things, rejected the rate design proposal established generation interconnection proceedings and called for the creation of RTOs to facilitate competitive regional markets in the U.S. FERC rejected several smaller RTO proposals and directed transmission owners and independent system operators (ISOs) to combine into much larger RTOs, dramatically altering their proposed geographic size and configuration. In August 2001, the PJM transmission owners requested a rehearing of the PJM RTO Order. The matter is still pending. In the Northeast region, FERC conditionally approved the PJM RTO proposal (subject to several modifications and compliance filings) and rejected the New York ISO and ISO-New England RTO proposals. FERC directed that the three existing ISOs for PJM, New York and New England, as well as the systems involved in PJM West, form a single Northeast RTO, based on the "PJM platform" and "best practices" of all three ISO's. FERC directed that the parties in the region engage in mediation (with FERC oversight) to prepare a proposal and timetable for the merger of the ISOs into a single RTO. At the end of the 45-day mediation period, the Administrative Law Judge assigned to the matter submitted a report to the Commission with an attached business plan for implementation of the single northeast RTO possibly as soon as the fourth quarter of 2003. In the Southeast region, FERC rejected two separate RTO proposals and directed parties to engage in mediation under the supervision of an Administrative Law Judge to pursue the goal of creating a single Southeast RTO using the proposed "Grid South platform." We participated in this discussion. Another a model for forming a market for the Southeast region continues to evolve. In January 2002, PJM and the Midwest ISO announced that they had entered into negotiations to create a virtual uniform seamless market encompassing their two RTOs, shortly after the FERC approved the Midwest ISO as an RTO. In addition, the ISO New England and the New York ISO agreed to jointly develop a common electricity market and evaluate a New England-New York RTO. The impact of these developments on us is uncertain because specific rules will not be known for some time and are subject to FERC approval, which cannot be assured. FERC has started a series of conferences to discuss the technical issues related to its consideration of a standard market design - products and protocols - for wholesale electric power markets. The goal of these conferences is to gain a mutual understanding of similarities and differences between various market designs and to allow participants to provide further detail on market operations. We have been supportive of the incorporation of both capacity and spot energy markets as part of any standardized market design. The information from these conferences will be used to issue a formal Notice of Proposed Rulemaking (NOPR) on a standard market design later this year. FERC issued an advance notice of proposed rulemaking seeking comments to help form the basis for a proposed rule to standardize power-plant interconnection requirements to ease market entry for new generation. FERC also will, as part of the rulemaking, 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 us cannot be predicted. The impact of these developments on us is uncertain because specific rules will not be known for some time and are subject to FERC approval, which cannot be assured. 18 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- 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. [Nuclear Regulatory Commission has issued Orders dated February 25, 2002 to all nuclear power plants to implement interim 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 terrorist attacks. Power has evaluated the Orders for the Salem and Hope Creek facilities and considers the implementation of the NRC measures to be without adverse material consequence to the NRC operating license or business interests. 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 is in the process of making the necessary modifications to comply with these requirements, the cost of which are not expected to be material. Failure to resolve fire barrier issues could result in potential NRC violations, fines and/or plant shutdown which could have a material adverse impact to our financial condition, results of operations and net cash flows. Exelon has informed Power that on July 3, 2001 an application was submitted to the NRC to renew the operating licenses for Peach Bottom Units 2 and 3. If approved, the current licenses would be extended by 20 years, to 2033 and 2034 for Units 2 and 3 respectively. NRC review of the application is expected to take approximately two years. For certain litigation relating to Salem, see Item 3. Legal Proceedings. For discussion of the renewal of New Jersey Pollutant Discharge Elimination System (NJPDES) permit related to Salem and its operations, see Environmental Matters - Water Pollution Control. Other Regulatory Issues Tax Sharing Agreement The issue of our sharing the benefits of consolidated tax savings with PSE&G or its customers was addressed by the BPU in 1995 in a letter which informed PSE&G that the issue of consolidated tax savings can be discussed in the context of a future base rate case or plan for an alternative form of regulation. We believe that PSE&G's taxes should be treated on a stand-alone basis for rate making purposes, based on the separate nature of the utility and non-utility businesses. Neither we nor PSE&G is able to predict what action, if any, the BPU may take concerning consolidated tax savings in future proceedings. International Energy Holdings' foreign subsidiaries generally are subject to regulation in the countries in which they operate. Global's electric and gas distribution facilities in South America are rate-regulated enterprises. Rates charged to customers are established by governmental authorities and are currently sufficient to cover all operating costs and provide a risk adjusted fair return, except in Argentina. See Note 9. Commitments and Contingent Liabilities and Note 18. Subsequent Events of Notes. Energy Holdings can give no assurances that future rates will be established at levels sufficient to cover such costs, provide a return on its investment or generate adequate cash flow to pay principal and interest on its debt or to enable it to comply with the terms of debt agreements. Global's South American facilities are also subject to quality of service standards. Global intends to manage its capital improvement budgets within these quality of service standards. Failure to meet required standards could result in penalties which are not expected to have a material adverse impact on these investments, although no assurances can be given. 19 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- CUSTOMERS PSE&G As of December 31, 2001, 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 Pursuant to the BGS contract, PSE&G will be the primary customer for Power's generation business through July 31, 2002. PSE&G, under the terms of the Final Order, is required to provide basic generation service to all retail customers in its service area that either do not choose to buy their power from alternative suppliers or are not being served by their alternative energy supplier for any reason. PSE&G will pay Power the full amount charged to BGS customers, or the retail tariff rate on file at the BPU, less any sales and use taxes. In addition, PSE&G pays Power a price stability charge to compensate them for ensuring the reliability of BGS service and minimizing PSE&G's exposure to price volatility risk. The charge is equal to the full amount collected by PSE&G for its unsecuritized generation stranded costs per billing period, also known as a Market Transition Charge (MTC). As of December 31, 2001, PSE&G provided service to approximately 99% of its traditional load. For the year ended December 31, 2001, Power's electric operating revenues associated with this customer base aggregated approximately $1.8 billion. PSE&G's peak load during the summer of 2001 was 10,425 MW. Power has entered into one-year contracts commencing August 1, 2002 with various direct bidders in the New Jersey BGS Auction, which was approved by the BPU on February 15, 2002. Power believes that its obligations under these contracts are reasonably balanced by its available supply. Power continues to supply certain municipal and electric cooperative customers and one public utility a total of 489 MW of capacity, including some other obligations, such as energy, under the terms of existing contracts for the remaining one to five years of those contracts. Wholesale energy and related product trading have been growing business opportunities throughout the Super Region over the last ten years and we have been in the forefront as an active participant. Trading relationships have been developed with most of the larger and more successful power marketers and existing trading relationships have been strengthened with the region's utilities. More recently, new relationships have developed with companies that are focused on aggregating retail customers in states that have deregulated. Power currently has over 100 active trading counterparties, which have passed a rigorous credit analysis and contracting process. These include investor owned utilities, retail aggregators and marketers. For a discussion of Power's future strategy and the auction impact, refer to Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations. Additionally, for risks associated with Power's new counterparties, as a result of the auction, see Risk Factors discussed above. Energy Holdings Global Global has ownership interests in eight distribution companies which serve approximately 3.6 million customers and has developed or acquired interests in electric generation facilities which sell energy, capacity and ancillary 20 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- 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-Electric Distribution Facilities. Energy Technologies Energy Technologies currently provides services to approximately 8,500 customers. EMPLOYEE RELATIONS PSEG has no employees. As of December 31, 2001, PSE&G had 6,554 employees, Power had 3,143 employees, Energy Holdings had 2,590 employees, and Services had 1,104 employees. PSE&G has a three-year collective bargaining agreement in place with three of its union groups, covering 3,636 employees, which expires on April 30, 2005. PSE&G also has a collective bargaining agreement with the Utility Co-Workers Association, covering 1,397 employees, that expires on April 30, 2002 and plans to negotiate a new agreement, which cannot be assured. Power has collective bargaining agreements, which expire on April 30, 2005, in place with three union groups, representing 1,597 employees (774 employees, or approximately 80% of the workforce in Fossil and 823 employees, or approximately 45% of the workforce in Nuclear). Energy Technologies and its operating subsidiaries are party to agreements with various trade unions through multi-employer associations. PSE&G, Power, Services and Energy Holdings believe that they maintain satisfactory relationships with their employees. For information concerning employee pension plans and other postretirement benefits, see Note 12. Pension, Other Postretirement Benefit and Savings Plans of Notes. SEGMENT INFORMATION Financial information with respect to our business segments is set forth in Note 14. Financial Information by Business Segments of Notes. ENVIRONMENTAL MATTERS Federal, regional, state and local authorities regulate the environmental impacts of our operations. Areas of regulation include air quality, water quality, site remediation, land use, waste disposal, aesthetics and other matters. Compliance with environmental requirements has caused us and our subsidiaries to modify the day-to-day operation of our facilities, to participate in the cleanup of various properties that have been contaminated and to modify, supplement and replace existing equipment and facilities. During 2001, PSE&G and Power expended approximately $18 million for capital related expenditures to improve the environment and comply with laws and regulations and estimates that they will expend approximately $61 million, $76 million and $37 million in the years 2002 through 2004, respectively, including such amounts discussed in the PSD/New Source Review section below. 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 that Power operates or in which it has 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. Capital costs of complying with air pollution control requirements through 2004 are included in our estimate of construction expenditures in MD&A. 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, 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. 21 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- The EPA and the New Jersey Department of Environmental Protection (NJDEP) issued a demand in March 2000 under section 114 of the 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 section 114 information request in November 2000. In January 2002, Power reached an agreement with the state and 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 will install advanced air pollution controls that will dramatically reduce emissions of nitrogen oxides (NOx), sulfur dioxides (SO2), particulate matter, and mercury from the Hudson and Mercer coal units. The estimated cost of the program is $337 million to be incurred through 2011. Power also will pay a $1.4 million civil penalty and spend up to $6 million on supplemental environmental projects. Capital costs of complying with these and other air pollution control requirements through 2004 are included in our estimate of construction expenditures (see Capital Requirements of MD&A). The agreement is still subject to public comment and judicial approval as to which no assurances can be given. As noted below, 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. In 2001, the EPA indicated that it was considering enforcement action under its PSD rules relating to the construction of Bergen 2, scheduled for operation in 2002. The EPA maintained that PSD requirements were applicable to Bergen 2, thereby requiring Fossil to obtain a permit before beginning actual on-site construction. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved the dispute over Bergen 2, and allowed construction of the unit to be completed and operation to commence. Sulfur Dioxide/Nitrogen Oxide To reduce emissions of SO2, the CAA sets a cap on total SO2 emissions from affected units and allocates SO2 "allowances" (each allowance authorizes the emission of one ton of SO2) to those units. Generation units needing to cover emissions above their allocations can buy allowances from sources that have excess allowances. Similarly, to reduce emissions of NOx, which contribute to the formation of smog, 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, a period commonly referred to as the "ozone season." The NOx allowances can be bought and sold through a regional trading program similar to the trading of SO2 allowances. In 2003, the cap will be reduced to limit NOx emissions further. In 1998, the EPA 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 by 2003 and to subsequently cap these emissions. In January 2000, the EPA adopted a revised rule granting petitions filed by certain northeastern states under Section 126 of the CAA. The petitions sought significant reductions in nitrogen oxide emissions from utility and industrial sources. The rule imposes emission reduction requirements comparable to the NOx SIP Call Rule. The EPA has delayed the implementation of the SIP Call and the Section 126 Rule until May 31, 2004. The NOx reduction requirements of the SIP Call and the Section 126 rule are consistent with requirements already in place in New Jersey, New York and Pennsylvania, and therefore are not likely to have an additional impact on or change the 22 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- capacity available from our 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. Power also does not expect that the potential costs for purchasing additional NOx allowances will be material through December 31, 2002. In 2003, when the NOx cap is reduced in New Jersey, New York, Pennsylvania, and other Northeastern states, the cost of complying with the NOx program in those states may increase significantly. Whether the cost will increase or decrease will depend upon whether Power will be a net purchaser or seller of NOx allowances. The extent of any increase or decrease 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 cost of purchasing allowances. In December 1999, the EPA proposed to approve plans by several states (including New Jersey and certain other Northern states) to attain the ozone National Ambient Air Quality Standards. That approval is contingent on these states implementing new programs to further reduce emissions of smog-forming chemicals (including NOx). The affected Northeastern states have committed to make these reductions, and were required to have selected measures by October 1, 2001 to achieve the reductions. Measures selected by the states are currently under EPA review. Measures under consideration may increase demand for NOx allowances and, consequently, increase their prices. 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. However, under the time schedule announced by the EPA when the new standard was adopted, non-attainment areas will not be designated until 2002 and control measures to meet this standard will not be identified until 2005. 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 our 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. 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, concluding that these emissions pose significant hazards to public health. EPA plans 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. In December 1997, delegates from the U.S. and 166 other nations agreed to a treaty known as the Kyoto Protocol. If the U.S. were to ratify the treaty, it would be bound to reduce emissions of CO2 and certain other "greenhouse gases" by 7% below 1990 levels. However, in March 2001, President Bush announced that the United States would not ratify the treaty. On January 11, 2002, Power announced a voluntary agreement that calls for a goal of reducing by December 31, 2005 the annual average carbon dioxide emission rate of its fossil fuel fired electric generating units by 15% below the 1990 average annual carbon dioxide emission rate of its New Jersey fossil fuel fired electric generating units. Fossil also has agreed to make a $1.5 million grant to the NJDEP to assist in the development of landfill gas projects, and 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. 23 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Water Pollution Control 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 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. 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. We also have ownership interests in domestic and international facilities in jurisdictions that have their own laws and implementing regulations to regulate discharges to their surface waters and ground waters that directly regulate our 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 are subject to the Phase I rule. The EPA is scheduled to propose draft Phase II rules covering large existing power plants on February 28, 2002, and issue final rules on August 28, 2003. 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 our existing facilities, the cost of complying with the rules would be material and could require certain of the facilities to be closed. On June 29, 2001, the NJDEP issued a renewal permit (the 2001 Permit) for Salem, with an effective date of August 1, 2001, allowing for the continued operation of Salem with its existing cooling water system. This 2001 Permit renews Salem's variance from applicable thermal water quality standards under Section 316(a) of the FWPCA, determines that the existing intake structure represents best technology available under Section 316(b) of the FWPCA, requires that Power continue to implement the wetlands restoration and fish ladder programs established under the 1994 NJPDES Permit issued for Salem, and imposes requirements for additional analyses of data and studies to determine if other intake technologies are available for application at Salem that are biologically effective. The 2001 Permit also requires us to install up to two additional fish ladders in New Jersey and fund a $500,000 escrow account for the construction of artificial reefs by NJDEP. The 2001 Permit expires on July 31, 2006. Power has also reached a settlement with the Delaware Department of Natural Resources and Environmental Control (DNREC) providing that Nuclear will fund additional habitat restoration and enhancement activities as well as fisheries monitoring and that Power and DNREC will work cooperatively on the finalization of other regulatory approvals required for implementation of the 2001 Permit. As part of this agreement, Power deposited approximately $5.8 million into an escrow account to be used for future costs related to this settlement. In 1970, the Delaware River Basin Commission (the DRBC) had issued a Docket for Salem (1970 Docket) that approved the construction and operation of the station's cooling water system. In 1995, the DRBC had issued a Revised Docket for Salem (1995 Revised Docket) that amended the Heat Dissipation Area (HDA) established in the 1970 Docket, and approved the continued operation of the station's cooling water system. At its meeting on September 13, 2001, the DRBC unanimously approved our request for revisions to the 1995 Revised Docket. The Docket, as revised, provides for an HDA consistent with the hydrothermal modeling studies conducted in connection with the renewal application for Salem's NJPDES permit, incorporates by reference the terms and conditions of the 24 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- 2001 Permit, rescinds the 1995 Revised Docket, and establishes a twenty-five year term for the Docket. The newly revised Docket again includes a re-opener clause that allows the DRBC to re-consider the terms and conditions of the Docket, based upon changed circumstances. Capital costs of complying with water pollution control requirements through 2004 are included in our estimate of construction expenditures in MD&A. Hudson and Mercer Generation Stations The NJDEP is in the process of reviewing the NJPDES permit renewal application for our Hudson Station. As part of that renewal, the NJDEP has requested updated information, in part to address issues identified by a consultant hired by NJDEP. The consultant recommended that Hudson Station be retrofitted to operate with closed cycle cooling to address alleged adverse impacts associated with the thermal discharge and intake structure. Power proposed certain modifications to the intake structure and submitted these demonstrations to NJDEP in the fourth quarter of 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 us that it is reviewing a NJPDES permit renewal application for Mercer Station, and in connection with that renewal, will be reexamining the effects of Mercer Station's cooling water system pursuant to FWPCA. Power has submitted updated 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 our 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 our applications to continue operations of its generating stations with present cooling water intake structures. Control of Hazardous Substances PSE&G Manufactured Gas Plant Remediation Program For information regarding PSE&G's Manufactured Gas Plant Remediation Program, see Note 9. Commitments and Contingent Liabilities of Notes. Hazardous Substances 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. 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 9. Commitments and Contingent Liabilities. For a discussion of remediation/clean-up actions involving PSE&G and Power, see Item 3. Legal Proceedings. 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 25 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- "damages" against persons who have discharged a hazardous substance, which discharge resulted in an "injury" to natural resources. Until recently, the State trustee, NJDEP, has not aggressively pursued natural resource damages. In 1997, the NJDEP adopted changes to the Technical Requirements for Site Remediation pursuant to the Spill Act. Among these changes was a new provision requiring all persons conducting remediation to characterize "injuries" to natural resources. Further, these changes required persons to address those injuries through restoration or damages. Power cannot assess the magnitude of the potential impact of this regulatory change. Although not currently estimable, these costs could be material. A preliminary review of possible mercury contamination at the Kearny Station, concluded that an 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. The EPA has determined that a six mile stretch of the Passaic River in the area of Newark, New Jersey is a facility within the meaning of that term under the CERCLA and that, to date, at least thirteen corporations, including PSE&G and Power, may be potentially liable for performing required remedial actions to address potential environmental pollution at the Passaic River facility. Power has one plant and PSE&G has one former electric plant and four former manufactured gas plants within the Passaic River "facility". We cannot predict what action, if any, the EPA or any third party may take against them with respect to these matters, or in such event, what costs Power or PSE&G may incur to address any such claims. However, such costs may be material. The EPA conducted an inspection of Spill Prevention Control and Countermeasure (SPCC) Plan compliance at three of PSE&G's substation facilities in 1997. The EPA identified certain procedural and substantive deficiencies in the SPCC Plans for these sites. PSE&G has submitted revised SPCC Plans to the EPA for these sites and is currently working with the EPA to finalize these SPCC Plans. In 1998, PSE&G evaluated SPCC Plan compliance at all of SPCC substations and identified deficiencies. The necessary upgrades are now in the process of being made. It is anticipated that these upgrades will take several years to complete. 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 fuel To pay for this service, the nuclear plant operators were required to contribute to a Nuclear Waste Fund at a rate of one mil per kWh of nuclear generation, subject to such escalation as may be required to assure full cost recovery by the Federal government. These costs are being recovered through the BGS contract through July 2002. In addition, a one-time payment was made to the DOE for permanently discharged spent fuels irradiated prior to 1983. 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 Income. Under the NWPA, the DOE was required to begin taking possession of all spent nuclear fuel generated by the Power's nuclear units for disposal by no later than 1998. DOE construction of a permanent disposal facility has not begun and DOE has announced that it does not expect a facility to be available earlier than 2010. In February 2002, President Bush announced that Yucca Mountain in Nevada was designated as the permanent disposal facility for nuclear wastes. The states have thirty days to object, and, if objections are raised, the issue will be determined by the U.S. Congress. No assurances can be given as to the final outcome of this matter. 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 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 future DOE fees. In 2000, a group of eight utilities filed a petition against DOE in the Eleventh Circuit U.S. Court of Appeals seeking to set aside the receipt of credits out of the Nuclear Waste Fund, as stipulated in the Peach Bottom agreement. On September 26, 2001 Nuclear filed a complaint in the U. S. 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. 26 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- 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. On July 3, 2001 an application was submitted to the NRC to renew the operating licenses for Peach Bottom Units 2 and 3. If approved, the current licenses would be extended by 20 years, to 2033 and 2034 for Units 2 and 3 respectively. NRC review of the application is expected to take approximately two years. In October 2001, Nuclear filed a complaint in the United States 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. 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. In 2000, New Jersey, Connecticut and South Carolina formed the Atlantic Compact. This arrangement 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. 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 U.S. 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 $79 million (adjusted for inflation). As of December 31, 2001, $48 million has been paid, resulting in a balance due of $31 million. PSE&G and Power believe that they should not be subject to collection of any such fund payments under the EPAct. Along with a number of other nuclear generator owners, Power and PSE&G have filed suit in the U.S. Court of Claims and in the U.S. District Court, Southern District of NY to recover these costs. ITEM 2. PROPERTIES 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. 27 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- 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 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, 2001, PSE&G's transmission and distribution system included approximately 21,760 circuit miles, of which approximately 6,363 miles were underground, and approximately 836,068 poles, of which approximately 536,780 poles were jointly owned. Approximately 99% of this property is located in New Jersey. In addition, as of December 31, 2001, 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, 2001, 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: Daily Capacity Plant Location (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, 2001, PSE&G owned and operated approximately 16,888 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. 28 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- 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, 2001, PSE&G owned 39 switching stations in New Jersey with an aggregate installed capacity of 30,417,670 kilovolt-amperes and 249 substations with an aggregate installed capacity of 7,446,000 kilovolt-amperes. In addition, six substations in New Jersey having an aggregate installed capacity of 108,000 kilovolt-amperes were operated on leased property. Power Power subleases approximately 148,000 square feet of office space from PSE&G in Newark, New Jersey. Other leased properties include an emergency media center (9,300 square feet) near Salem which is designed as an information clearinghouse in the event of a nuclear emergency. It also leases approximately 19,600 square feet of space in the Hadley Road Training Center in South Plainfield, New Jersey from PSE&G. This space is used for fossil fuel procurement and materials management staff. Power owns a 57.41% interest in about 12,000 acres of restored wetlands and conservation facilities in the Delaware Estuary. This subsidiary was formed to acquire and own lands and other conservation facilities required to satisfy the condition of the NJPDES permit issued for the Salem Generating Station. Power also owns several other facilities including the on-site Nuclear Administration and Processing Center buildings. Power has an 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 entities that have generation facilities along the Delaware River and use the river water in their operations. Power also owns the Maplewood Test Center in Maplewood, New Jersey and the Central Maintenance Shop at Sewaren, New Jersey. Power believes that it maintains 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 Risk Factors and Note 9. Commitments and Contingent Liabilities of Notes. 29 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- As of December 31, 2001, Power's share of installed generating capacity was 11,487 MW, as shown in the following table:

Total Owned Principal Capacity Capacity Fuels Name and Location (MW) (MW) Used Mission ------------------------------------------------------------ -------- -------- --------- -------------- Steam: Hudson, Jersey City, NJ............................... 991 991 Coal/Gas Load Following Mercer, Hamilton, NJ.................................. 648 648 Coal/Gas Load Following Sewaren, Woodbridge Twp., NJ.......................... 453 453 Gas/Oil Load Following Linden, Linden, NJ (F)................................ 430 430 Oil Load Following Keystone, Shelocta, PA--22.84%(A)(B)................... 1,700 388 Coal Base Load Conemaugh, New Florence, PA--22.50%(A)(B).............. 1,700 382 Coal Base Load Kearny, Kearny, NJ.................................... 300 300 Oil Load Following Albany, Albany, NY (F)................................ 380 380 Oil Load Following ----------- ----------- Total Steam........................... 6,602 3,972 ----------- ----------- Nuclear: (Capacity calculated in accordance with industry maximum dependable capability standards) Hope Creek, Lower Alloways Creek, NJ ................. 1,049 1,049 Nuclear Base Load Salem 1 & 2, Lower Alloways Creek, NJ 57.41%(A)....... 2,188 1,275 Nuclear Base Load Peach Bottom 2 & 3, Peach Bottom, PA 50%(A)(C)........ 2,186 1,094 Nuclear Base Load ----------- ----------- Total Nuclear...................................... 5,423 3,418 ----------- ----------- Combined Cycle: Bergen, Ridgefield, NJ................................ 675 675 Gas Load Following Burlington, Burlington, NJ............................ 245 245 Gas Load Following ----------- ----------- Total Combined Cycle............................... 920 920 ----------- ----------- Combustion Turbine: Essex, Newark, NJ..................................... 617 617 Gas/Oil Peaking Edison, Edison Township, NJ........................... 504 504 Gas/Oil Peaking Kearny, Kearny, NJ (F)................................ 443 443 Gas/Oil Peaking Burlington, Burlington, NJ............................ 561 557 Oil Peaking Linden, Linden, NJ.................................... 316 316 Gas/Oil Peaking Hudson, Jersey City, NJ............................... 129 129 Oil Peaking Mercer, Hamilton, NJ.................................. 129 129 Oil Peaking Sewaren, Woodbridge Township, NJ...................... 129 129 Oil Peaking Bayonne, Bayonne, NJ.................................. 42 42 Oil Peaking Bergen, Ridgefield, NJ................................ 21 21 Gas Peaking National Park, National Park, NJ...................... 21 21 Oil Peaking Kearny, Kearny, NJ.................................... 21 21 Gas Peaking Linden, Linden, NJ.................................... 21 21 Gas/Oil Peaking Salem, Lower Alloways Creek, NJ 50%(A)................ 38 22 Oil Peaking ----------- ----------- Total Combustion Turbine........................... 2,992 2,972 ----------- ----------- Internal Combustion: Conemaugh, New Florence, PA--22.50%(A)(B).............. 11 2 Oil Peaking Keystone, Shelocta, PA--22.84%(A)(B)................... 11 3 Oil Peaking ----------- ----------- Total Internal Combustion.......................... 22 5 ----------- ----------- Pumped Storage: Yards Creek, Blairstown, NJ--50%(A)(D)(E)...... 400 200 Peaking ----------- ----------- Total Operating Generation Plants.................. 16,359 11,487 =========== ===========

(A) Power's share of jointly owned facility. (B) Operated by Reliant Energy (C) Operated by Exelon (D) Operated by Jersey Central Power & Light (E) Excludes energy for pumping and synchronous condensers. (F) These assets are scheduled for retirement within the next five years, partially dependent upon new generation going into service discussed below. 30 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- As of December 31, 2001, Power had 3,830 MW of generating capacity in construction, as shown in the following table: POWER PLANTS IN CONSTRUCTION OR ADVANCED DEVELOPMENT As of December 31, 2001

Total Principal Capacity Fuels Expected in Name and Location (MW) Used Missions Service Date ---------------------------------------------------------- ----------- ------------- ----------------- ------------ Single Cycle: Waterford (Phase I), Ohio (June 2002)............. 500 Gas Load Following June 2002 Combined Cycle: Bergen, Ridgefield, NJ (June 2002).............. 546 Gas Load Following June 2002 Lawrenceburg, Indiana (May 2003)................ 1,150 Gas Load Following May 2003 Waterford (Phase II), Ohio (May 2003)........... 350 Gas Load Following May 2003 Linden, Linden, NJ (June 2003).................. 1,218 Gas Load Following June 2003 ----------- Total Construction............................. 3,764 ===========

As of December 31, 2001, Power had 900 MW of generating capacity in advanced development, as shown in the following table:

Total Principal Capacity Fuels Expected in Name and Location (MW) Used Missions Service Date --------------------------------------------------------- -------- --------- ---------------- ------------ Combined Cycle: Bethlehem, NY (June 2004)....................... 750 Gas/Oil Load Following June 2004 Nuclear Uprates...................................... 150 Nuclear Base Load Various ----------- Total Advanced Development................... 900 -----------

Total Capacity Projected Capacity (mw) ---------------------------------------------------------------------------- Total Owned Operating Generating Plants 11,487 Under Construction 3,764 Advanced Development 900 Less: Planned Retirements (1,253) ---------------- Projected Capacity 14,898 ================ Energy Holdings Energy Holdings does not own any real property. Energy Holdings subleases 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. 31 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Electric Generation Facilities Global has invested in the following generation facilities which are in operation or under construction or advanced development: -------------------------------------------------------------------------------- OPERATING POWER PLANTS -------------------------------------------------------------------------------- As of December 31, 2001 --------------------------------------------------------------------------------

Global's Net Equity Global's Interest in Total Ownership Total Location Primary Fuel MW Interest MW --------------------------------------------------------------- United States ------------- Texas Independent Energy Guadalupe......................... TX Natural gas 1,000 50% 500 Odessa............................ TX Natural gas 1,000 50% 500 Kalaeloa............................. HI Oil 180 50% 90 GWF Bay Area I........................ CA Petroleum coke 21 50% 10 Bay Area II....................... CA Petroleum coke 21 50% 10 Bay Area III...................... CA Petroleum coke 21 50% 10 Bay Area IV....................... CA Petroleum coke 21 50% 10 Bay Area V........................ CA Petroleum coke 21 50% 10 Hanford.............................. CA Petroleum coke 27 50% 14 Hanford - Peaking Plant.............. CA Natural gas 90 50% 45 SEGS III............................. CA Solar 30 9% 3 Tracy................................ CA Biomass 21 35% 7 Bridgewater.......................... NH Biomass 16 40% 6 Kennebec............................. ME Hydro 15 16% 2 Conemaugh............................ PA Hydro 15 50% 8 ------------ ---------- Total United States 2,499 1,225 ------------ ---------- --------------------------------------------------------------- International ------------- CTSN................................. Argentina Coal/Natural 650 19% 124 gas/Oil MPC Jingyuan - Units 5 and 6.......... China Coal 600 15% 90 Tongzhou.......................... China Coal 30 40% 12 Nantong........................... China Coal 24 46% 11 Jinqiao (Thermal Energy).......... China Coal/Oil N/A 30% N/A Zuojiang - Units 1, 2 and 3....... China Hydro 72 30% 22 Fushi - Units 1, 2 and 3.......... China Hydro 54 35% 19 Shanghai BFG...................... China Blast furnace 50 16% 8 gas PPN.................................. India Naphtha/Natural 330 20% 66 gas Tanir Bavi........................... India Naphtha 220 74% 163 Crotone.............................. Italy Biomass 20 26% 5 Electroandes......................... Peru Hydro 183 100% 183 Chorzow (existing facility).......... Poland Coal 100 55% 55 Turboven Maracay.............................. Venezuela Natural gas 60 50% 30 Cagua................................ Venezuela Natural gas 60 50% 30 TGM.................................. Venezuela Natural gas 40 9% 4 ----------- ------------ Total International (A) 2,493 822 ----------- ------------ Total Operating Power Plants 4,992 2,047 ----------- ------------

32 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- -------------------------------------------------------------------------------- POWER PLANTS IN CONSTRUCTION OR ADVANCED DEVELOPMENT -------------------------------------------------------------------------------- As of December 31, 2001 --------------------------------------------------------------------------------

Global's Net Equity Global's Interest in In Total Ownership Total Service International Location Primary Fuel MW Interest MW Date ------------- ------------------------------------------------------------------------------- United States GWF Energy Henrietta) (A) California Natural gas 90 50% 45 2002 Tracy) (A) California Natural gas 160 50% 80 2002 Parana......................... Argentina Natural gas 830 33% 274 2002 Halan (Thermal Energy)...... China Coal N/A 50% N/A 2002 Prisma Strongoli................... Italy Biomass 40 26% 10 2002 Porto Empedocle (A)......... Italy Biomass 24 26% 6 2002 Bando....................... Italy Biomass 20 51% 10 2002 Salalah........................ Oman Natural gas 200 81% 162 2003 Skawina CHP (A)................ Poland Coal 590 35% 207 2003 Chorzow........................ Poland Coal 220 90% 198 2003 Kuo Kuang...................... Taiwan Natural gas 480 18% 84 2003 Rades.......................... Tunisia Natural gas 471 60% 283 2002 Turboven Valencia (A)................ Venezuela Natural gas 80 50% 40 2002 ---------- ---------- Total Construction or Advanced Development 3,205 1,399 ---------- ---------- TOTAL Generation Facilities 8,197 3,446 ========== ==========

(A) In advanced development. Electric Distribution Facilities Global also has invested in the following distribution facilities:

Global's Number of Ownership Location Customers Interest ------------------------------------------ EDEN (B)......................... Argentina 270,000 30% EDES (B)......................... Argentina 150,000 30% EDELAP (B)....................... Argentina 280,000 30% EDEERSA.......................... Argentina 235,000 90% Rio Grande Energia............... Brazil 990,000 32% Chilquinta Energia............... Chile 400,000 50% SAESA............................ Chile 630,000 100% Luz del Sur...................... Peru 690,000 44% --------- 3,645,000 ========== (B) Assets Held for Sale to AES. See Note 18. Subsequent Events.

ITEM 3. LEGAL PROCEEDINGS As previously disclosed, by complaints filed in 1995 and 1996, shareholder derivative actions on behalf of PSEG shareholders were commenced by purported shareholders against certain directors and officers. The four complaints generally sought recovery of damages for alleged losses purportedly arising out of PSE&G's operation of the Salem and Hope Creek generating stations, together with certain other relief, including removal of certain executive officers of PSE&G and PSEG and certain changes in the composition of PSEG's Board of Directors. By decision dated July 28, 1999, the Court granted the defendants' motions for summary judgment dismissing all four derivative actions. The plaintiffs have appealed in all three of these actions. In April 2001, the Appellate Division of the New Jersey Superior Court unanimously affirmed the lower court's order granting summary judgment in the shareholder derivative litigation. The plaintiffs have filed petitions for certification with the New Jersey Supreme 33 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Court seeking permission to appeal this order, which PSEG has opposed. The New Jersey Supreme Court granted the Petition for Certification and the matter was argued in February 2002. PSEG cannot predict the outcome of these appeals. Public Service Enterprise Group Inc. by G. E. Stricklin, derivatively v. E. James Ferland, et. al., Superior Court of New Jersey, Chancery Division, Essex County, Docket No. C-160-96. Dr. Steven Fink and Dr. David Friedman, P.C. Profit Sharing Plan, derivatively, Lawrence R. Codey, et. al., Superior Court of New Jersey, Chancery Division, Essex County, Docket No. C-65-96. A. Harold Datz Pension and Profit Sharing Plan derivatively, et. al., v. Lawrence R. Codey, et. al., Superior Court of New Jersey, Chancery Division, Essex County, Docket No. C-68-96. The Brazilian Consumer Association of Water and Energy has filed a lawsuit against Rio Grande Energia S.A. (RGE), a 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. 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 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: (1) Pages 15 and 78. 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 16. PSE&G's Gas Base Rate Filings, Docket Nos. GR01050328 and GR01050297. (3) Page 24. Administrative proceedings before the NJDEP under the FWPCA for certain electric generating stations. (4) Pages 26 and 27. Department of Energy (DOE) Overcharges, Docket No. 01-592C. (5) Pages 26 and 27. DOE not taking possession of spent nuclear fuel, Docket No. 01-551C. (6) Pages 102. PSE&G's MGP Remediation Program. (7) Page 102. Investigation and additional investigation by the EPA regarding the Passaic River site. Docket No. EX93060255. (8) Page 104. Complaint filed with the Federal Energy Regulatory Commission 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. In addition, see the following environmental related matters involving governmental authorities. Based on current information, PSEG does not expect expenditures for any such site, individually or all such current sites in the aggregate, to have a material effect on their financial condition, results of operations and net cash flows. (1) Claim made in 1985 by U.S. Department of the Interior under CERCLA with respect to the Pennsylvania Avenue and Fountain Avenue municipal landfills in Brooklyn, New York, for damages to natural resources. The U.S. Government alleges damages of approximately $200 million. To PSE&G's knowledge there has been no action on this matter since 1988. 34 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- (2) Duane Marine Salvage Corporation Superfund Site is in Perth Amboy, Middlesex County, New Jersey. The EPA had named PSE&G as one of several potentially responsible parties (PRPs) through a series of administrative orders between December 1984 and March 1985. Following work performed by the PRPs, the EPA declared on May 20, 1987 that all of its administrative orders had been satisfied. The NJDEP, however, named us as a PRP and issued its own directive dated October 21, 1987. Remediation is currently ongoing. (3) Various Spill Act directives were issued by NJDEP to PRPs, including 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 60% Complete Remedial Design document was submitted to the EPA in March of 2001. 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. Additionally, with respect to this site, the United States of America application in the matter entitled United States of America, et. al., v. Union Corporation, et. al., Civil Action No. 80-1589, United States District Court for the Eastern District of Pennsylvania, seeking leave of court to file an amended complaint adding claims under the CERCLA was granted. One other utility and us were named as third party defendants in the foregoing captioned matter. An application to intervene in the captioned matter as third party defendants, filed by seven other utilities alleged to be liable for contamination at the Site, has also been granted by the Court. (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) In 1991, the NJDEP issued Directive and Notice to Insurers Number Two (Directive Two) to 24 Insurers and 52 Respondents, including PSE&G, in connection with an investigation and remediation of the Global Landfill Site in Old Bridge Township, Middlesex County, New Jersey seeking recovery of past and anticipated future NJDEP response costs ($37 million). PSE&G and other participating PRPs have agreed with NJDEP to a partial settlement of such costs and to perform the remedial design and remedial action. In 1996, 13 of the Directive Two Respondents, including PSE&G, filed a contribution action pursuant to CERCLA and the Spill Act against approximately 190 parties seeking contribution for an equitable share of all liability for response costs incurred and to be incurred in connection with the site. In September 1997, the NJDEP issued a Superfund record of decision (ROD) with estimated cost of $3.7 million. The Directive Two Respondents' foregoing contribution claims have been resolved by settlement in 2001. (7) In 1991, the NJDEP issued Directive and Notice To Insurers Number One (Directive No. One) to 50 insurers and 20 respondents, including PSE&G, seeking from the respondents payment of $5.5 million 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). The $5.5 million represents NJDEP's 10% share of total estimated site remediation costs and administrative oversight costs pursuant to a cooperative agreement with the United States concerning the selected 35 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- remedial action for the site. In 1996, the NJDEP issued Directive Number Two (Directive No. Two) to 37 respondents, including PSE&G, directing the respondents to arrange for the operation, maintenance and monitoring of the implemented remedial action described therein or pay the NJDEP's future costs of these activities, estimated to be $39 million. In addition, Directive No. Two directs the respondents to prepare a work plan for the development and implementation of a Natural Resource Damage Restoration Plan. In October 1998, the NJDEP and The United States of America filed separate cost recovery actions pursuant to CERCLA and/or the Spill Act against approximately 30 parties seeking recovery of their respective shares of past and future site investigation and remediation response and administrative oversight costs incurred and to be incurred at the site. Third party contribution actions were also filed in each of the foregoing cost recovery actions seeking contribution for an equitable share of all liability for these same costs from approximately 170 third party defendants. PSE&G is a named defendant in the NJDEP cost recovery action and a named third party defendant in the contribution action filed in the United States' lawsuit. (8) Spill Act Multi-Site Directive (Directive) issued by the NJDEP to PRPs, including PSE&G, listing four separate sites, including the former solid waste bulking and transfer facility called the Marvin Jonas Transfer Station (Sewell Site) in Deptford Township, Gloucester County, New Jersey. With regard to the Sewell Site, this Directive ordered approximately 350 PRPs, including PSE&G, to enter into an Administrative Consent Order (ACO) with NJDEP, requiring them to remediate the Sewell Site. PSE&G and certain other de minimis parties have accepted a settlement offer in 2001 from other PRPs to resolve their liability for response and removal costs at the site. (9) 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. (10) The New York State Department of Environmental Conservation (NYSDEC) has named PSE&G as one of many potentially responsible parties for contamination existing at the former Quanta Resources Site in Long Island City, New York. Waste oil storage, processing, management and disposal activities were conducted at the site from approximately 1960 to 1981. It is believed that waste oil from our facilities was taken to the Quanta Resources Site. NYSDEC has requested that the potentially responsible parties reimburse the state for the costs NYSDEC has expended at the site and to conduct an investigation and remediation of the site. Power, PSE&G and the other PRPs are negotiating with NYSDEC the terms of an agreement that will set forth these requirements, and are negotiating among themselves an agreement for the sharing of the associated costs. 36 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ------- ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Our Common Stock is listed on the New York Stock Exchange, Inc. As of December 31, 2001, there were 119,944 holders of record. The following table indicates the high and low sale prices for our Common Stock and dividends paid for the periods indicated: Dividend Common Stock High Low Per Share ------------ ---- --- --------- 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 2000: First Quarter.......................... $36.00 $25.69 $0.54 Second Quarter......................... 38.19 29.25 0.54 Third Quarter.......................... 45.69 32.88 0.54 Fourth Quarter......................... 50.00 38.88 0.54 For additional information concerning dividend history, policy and potential preferred voting rights, restrictions on payment and common stock repurchase programs, see Liquidity and Capital Resources and External Financings of MD&A and Note 6. Schedule of Consolidated Capital Stock and Other Securities of Notes. 37 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- ITEM 6. SELECTED FINANCIAL DATA PSEG The information presented below should be read in conjunction with our Consolidated Financial Statements and Notes thereto.

Years Ended December 31, ---------------------------------------------------------------------------- 2001 2000 1999 1998 1997 ------------- ------------- ------------- ------------- ------------- (Millions of Dollars, where applicable) Total Operating Revenues.................... $9,815 $9,495 $8,327 $7,864 $6,447 ============= ============= ============= ============= ============= Income Before Extraordinary Item............ $763 $764 $723 $644 $560 Extraordinary Item (A)...................... (2) -- (804) -- -- Cumulative Effect Adjustment (B)............ 9 -- -- -- -- ------------- ------------- ------------- ------------- ------------- Net Income (Loss)........................... $770 $764 $(81) $644 $560 ============= ============= ============= ============= ============= Earnings per Average Share (Basic and Diluted): Before Extraordinary Item................ $3.67 $3.55 $3.29 $2.79 $2.41 Extraordinary Item (A)................... (0.01) -- (3.66) -- -- Cumulative Effect Adjustment (B) ........ 0.04 -- -- -- -- ------------- ------------- ------------- ------------- ------------- Total Earnings per Average Share....... 3.70 $3.55 $(0.37) $2.79 $2.41 ============= ============= ============= ============= ============= Dividends Paid per Share.................... $2.16 $2.16 $2.16 $2.16 $2.16 As of December 31: Total Assets............................. $25,397 $21,526 $19,015 $17,991 $17,943 Long-Term Liabilities: Long-Term Debt (C) .................... $10,301 $5,297 $4,575 $4,763 $4,885 Other Noncurrent Liabilities (E)....... $1,981 $1,762 $1,562 $764 $609 Preferred Stock With Mandatory Redemption... -- $75 $75 $75 $75 Monthly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures....... $60 $210 $210 $210 $210 Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures....... $95 $303 $303 $303 $303 Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures........ $525 $525 $525 $525 -- Ratio of Earnings to Fixed Charges (D)... 2.30 2.73 3.09 2.86 2.55

(A) 2001 charge relates to loss on early debt retirement. For the extraordinary charge recorded in 1999, see Note 3 - Regulatory Issues and Accounting Impacts of Deregulation. (B) Impact of SFAS 133 Adoption, See Note 8. Financial Instruments, Energy Trading and Risk Management. (C) Increase in debt partially related to securitization transaction in 2001 and consolidation of non-recourse debt. (D) Excludes income and expenses from Extraordinary Item. (E) Excludes Deferred Taxes and ITC and the Excess Depreciation Reserve portion of Regulatory Liabilities. 38 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This discussion makes reference to the Consolidated Financial Statements and related Notes to Consolidated Financial Statements (Notes) of Public Service Enterprise Group Incorporated and should be read in conjunction with such statements and notes. CORPORATE STRUCTURE We are a holding company and, as such, have no operations of our own. We have four principal direct wholly-owned subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings Inc. (Energy Holdings) and PSEG Services Corporation (Services). PSE&G is an operating public utility company engaged principally in the transmission, distribution and sale of electric energy and gas service in New Jersey. On August 21, 2000, pursuant to the terms of the Final Order issued by the New Jersey Board of Public Utilities (BPU), PSE&G transferred its generation-related assets and liabilities and its wholesale power contracts to Power and its subsidiaries in exchange for a promissory note in an amount equal to the total purchase price of $2.786 billion. Power paid the promissory note on January 31, 2001 at which time the transferred assets were released from the lien of PSE&G's First and Refunding Mortgage. PSE&G continues to own and operate its regulated electric and gas transmission and distribution business. A bankruptcy-remote subsidiary of PSE&G, PSE&G Transition Funding LLC, issued $2.525 billion of securitization bonds in January of 2001 in partial recovery of PSE&G's stranded cost resulting from New Jersey deregulation and restructuring. An additional $540 million of PSE&G's stranded costs is being recovered from its customers over a four-year transition period ending July 31, 2003 through a Market Transition Charge (MTC). Power was formed in June 1999 to acquire, own and operate the electric generation-related assets of PSE&G pursuant to the Final Order issued by the BPU under the New Jersey Energy Master Plan (Energy Master Plan Proceedings) and the New Jersey Electric Discount and Energy Competition Act (Energy Competition Act). Power has three principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T) and currently operates in two reportable segments, generation and trading. The generation segment of Power's business earns revenues by selling energy on a wholesale basis under contract to power marketers and to load serving entities, and by bidding energy, capacity and ancillary services into the market. The energy trading segment of Power's business earns revenues by trading energy, capacity, fixed transmission rights, fuel and emission allowances in the spot, forward and futures markets. The trading segment also earns revenues through financial transactions, including swaps, options and futures in the electricity and gas markets. Power also has a finance company subsidiary, PSEG Power Capital Investment Co. (Power Capital), which provides certain financing for its other subsidiaries. Energy Holdings participates in three energy-related reportable segments through its principal wholly-owned subsidiaries: PSEG Global Inc. (Global), which develops, acquires, owns and operates electric generation and distribution facilities; PSEG Resources Inc. (Resources), which provides energy infrastructure financing and invests in energy-related financial transactions and manages a diversified portfolio of investments including leveraged leases, operating leases, leveraged buyout (LBO) funds, limited partnerships and marketable securities; and PSEG Energy Technologies Inc. (Energy Technologies), an energy management company that constructs, operates and maintains heating, ventilating and air conditioning (HVAC) systems for, and provides energy-related engineering, consulting and mechanical contracting services to, industrial and commercial customers in the Northeastern and Middle Atlantic United States. Energy Holdings also has a finance subsidiary, 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. See Liquidity and Capital Resources for further detail. Energy Holdings is also the parent of Enterprise Group Development Corporation (EGDC), a property management business and is conducting a controlled exit from this business. 39 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Services was formed in 1999 and provides management and administrative services to us and our subsidiaries. OVERVIEW OF 2001 AND FUTURE OUTLOOK The Energy Competition Act and the related BPU proceedings, including the Final Order and the Energy Master Plan Proceedings, have dramatically reshaped the utility industry in New Jersey and have directly affected how we will conduct business, and therefore, our financial prospects in the future. Deregulation, restructuring, privatization and consolidation are creating opportunities and risks for us and our subsidiaries. We have realigned our organizational structure to address the competitive environment brought about by the deregulation of the electric generation industry in New Jersey and the Eastern U.S and have transitioned from primarily being a regulated New Jersey utility to a operating as a competitive global energy company. We have been engaged in the competitive energy business for a number of years through certain of our unregulated subsidiaries; however, competitive businesses now constitute a much larger portion of our activities. As of December 31, 2001, Power, PSE&G, and Energy Holdings comprised approximately 20%, 51% and 29% of PSEG's consolidated assets and contributed approximately 50%, 30% and 20% of our net income for the year ended December 31, 2001. Our projected earnings contributions for 2002 and 2003 are 50% to 55% from Power, 25% to 30% from Energy Holdings and 20% to 25% from PSE&G. Additionally, we will be more dependent on cash flows generated from our unregulated operations for our capital needs. 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. Our subsidiaries consist of a portfolio of energy-related businesses that together are designed to produce a coherent 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 designed to produce consistent earnings growth in a manner that will mitigate the adverse financial effects of business losses or an economic downturn is any one sector or geographic region. For 2001, we earned $3.70 per share. Our improved earnings for 2001 as compared to 2000 were due primarily to new acquisitions, asset sales and improved operations at Global, new leveraged lease investments at Resources, continued strong performance of our nuclear generating facilities and improved performance of our energy trading operations, which saw an increase in margins from $72 million in 2000 to $140 million in 2001. These improvements more than offset the effects of comparatively unfavorable weather conditions, two BPU mandated 2% rate reductions, effective in February 2001 and August 2001, and the effects of the securitization transaction that occurred on January 31, 2001. We estimate a 7% compound annual growth rate in earnings per share over the next five years. Our earnings for 2002 will depend on several factors, including our ability to effectively manage our commitments under contracts to deliver energy, capacity and ancillary services to the various suppliers of BGS to New Jersey's utilities and our ability to minimize the effects, including potential asset impairments, brought about by the economic, political and social crisis in Argentina, where we face considerable fiscal and cash uncertainties. For further discussion of our $632 million investment exposure in Argentina, see Note 9. Commitments and Contingent Liabilities. Looking beyond 2002, our earnings will depend on the outcome of future BGS auctions in New Jersey, energy prices, which are currently depressed, in the United States markets in which Power and Global participate, the successful operation of our generation stations, PSE&G's ability to obtain timely and adequate rate relief, regulatory decisions affecting our interests in distribution companies in South America, and the effect of economic conditions in foreign countries in which we invest. PSE&G PSE&G operates under cost-based regulation by the 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 is expected to continue to make a steady contribution to earnings in the future as it continues its transmission and distribution and sale of electric energy and gas service in 40 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 are relatively modest and generally relate to the regulatory treatment of the various rate and other issues by the BPU and the FERC. On January 9, 2002 the BPU approved an additional $90 million of gas base rate revenues for PSE&G, simultaneously with other PSE&G rate filings related to underrecovered gas costs which were deferred on its balance sheet. All three rate changes were effective January 9, 2002. Also on January 9, 2002, the BPU approved the transfer of the utility's gas supply business, including its transportation and storage contracts, to Power. As a result, after April 1, 2002, Power will provide gas supply to PSE&G to serve its Basic Gas Supply Service (BGSS) customers under a Requirements Contract at market prices. Industrial and commercial BGSS customers will be priced under PSE&G's Market Priced Gas Service (MPGS) and residential BGSS customers will remain under current pricing until April 1, 2004 after which, subject to further BPU approval, those residential gas customers would also move to MPGS service. On February 15, 2002, the BPU announced the successful outcome of the BGS auction. Through the auction, PSE&G contracted for sufficient electricity to serve all of its BGS customers and any difference between the existing tariff rates and the rates set through the auction for the one-year contract period beginning August 1, 2002 will be deferred and recovered over future periods as a regulatory asset. POWER Power is focused on a generation market extending from Maine to the Carolinas and the Atlantic Coast to Indiana (Super Region). The risks of Power's business are 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. These risks are higher than those for a regulated business. Therefore, they provide the opportunity for greater returns, but they also present the greater possibility of business losses and counterparty credit risk. Power is currently constructing projects which will increase capacity by over 3,500 MW, net of planned retirements. Power currently sells approximately 95% of the output from its generation facilities under bilateral contracts, primarily the BGS contract with PSE&G, and the remaining 5% to customers in the competitive wholesale (spot) market. Within the spot market, Power sells into the energy, capacity and ancillary services markets. Ancillary services include operating reserves and area regulation. Power has entered into one-year contracts commencing August 1, 2002 with various direct bidders in the New Jersey BGS Auction, which was approved by the BPU on February 15, 2002. Power believes that its obligations under these contracts are reasonably balanced by its available supply. In addition, we anticipate that Power will continue its strong growth in its energy trading segment. In 2001, the energy trading business realized a gross margin of $140 million and forecasts an improvement for 2002, primarily driven by the transfer of PSE&G's gas supply business to Power, discussed below. We marked to market energy trading contracts with gains and losses included in earnings. The vast majority of these contracts have terms of less than one year and are valued using market exchange prices and broker quotes. The energy trading business provides the opportunity for greater returns, but it also is more risky than the regulated business, and can be adversely impacted by fluctuating energy market prices and by the credit quality of the counterparties with which it does business. Our trading business utilizes a conservative risk management strategy to minimize exposure to credit risk. For further information, see Accounting Issues, Note 1. Organizationa and Summary of Significant Accounting Policies and Note 8. Financial Instruments, Energy Trading and Risk Management. ENERGY HOLDINGS Energy Holdings is a major part of our growth strategy. In order to achieve this strategy, Global will focus on generation and distribution investments within targeted high-growth regions. Resources will utilize its market access, industry knowledge and transaction structuring capabilities to expand its energy-related financial investment 41 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- portfolio. We are evaluating the future prospects of Energy Technologies' business model and its fit in our portfolio given the slower pace of retail deregulation in the markets in which we operate. Resources' assets generate cash flow and earnings in the near term, while investments at Global generally have a longer time horizon before achieving expected cash flow and earnings. Also, Resources' passive lower-risk assets serve to balance the higher risk associated with operating assets at Global and Energy Technologies. Global's more recent activities have been concentrated on developing generation internationally and in acquiring distribution businesses, principally in South America, that have been privatized by the local governments. As Global has grown, its objective has evolved from being a minority or equal partner to seeking to be the majority or sole owner of many of its investments. Global's business depends on the ability to negotiate or obtain favorable prices and terms for the output of its generating facilities nationally and internationally, and to obtain favorable governmental and regulatory treatment for its distribution assets in foreign countries. Global undertakes investments where the expected return is commensurate with the market, regulatory, international and currency risks that are inherent with its investments. Since these risks are priced in the original investment decision, to the extent that market, regulatory international or currency conditions evolve differently than originally forecast, the investment performance of Global's assets will differ form the expected performance. Thus, the expected investment returns from Global's projects are priced to produce relatively high returns to compensate for the high level of risk associated with this business. Global has investment exposure of $632 million in four distribution companies and two generation plants in Argentina. For further discussion of our $632 million investment exposure in Argentina, see Note 9. Commitments and Contingent Liabilities. Resources invests principally in energy-related financing transactions, principally leveraged leases. As such, it is designed to produce predictable earnings at reasonable levels with relatively low risk. The modest risks faced by Resources are the credit risk of its counterparties and the tax treatment of its investment structures. Resources' earnings and cash flow streams are dependent upon the availability of and its ability to continue to enter into these transactions. Energy Technologies is a business that principally constructs and installs heating, ventilating and air conditioning equipment and related services. It has not produced profitable operations due to the extremely competitive nature of the business and the failure of the retail energy market to develop. The principal risks of this business are to be able to reduce internal costs to become profitable in this market and to obtain revenues to cover the carrying value of its assets. RESULTS OF OPERATIONS Our business consists of six reportable segments which are Generation, Energy Trading, PSE&G, Global, Resources and Energy Technologies. The following is a discussion of the major year-to-year financial statement variances and follows the financial statement presentation as it relates to each of our segments. The presentation of Electric Revenues and Electric Energy Costs includes Power's generation business, the electric transmission and distribution business of PSE&G and the consolidated portions of Global's operations; Gas Revenues and Gas Costs includes the gas distribution business of PSE&G; Trading Revenues and Costs includes Power's energy trading business; and Other Revenues includes Global's unconsolidated operations, Resources and Energy Technologies. Prior to 2001, Energy Technologies had certain electric and gas costs which were included in Electric Energy Costs and Gas Costs, respectively. For a discussion of management's determination of our reportable segments and related disclosures, see Note 14. Financial Reporting by Business Segments. Prior to April 1999, the discussion that follows reports on business conducted under full monopoly regulation of the utility businesses. It must be understood that such businesses have changed due to the deregulation of the electric generation and natural gas commodity sales businesses, the subsequent transfer of the generation business, and the anticipated transfer of the gas supply business from PSE&G to Power. Past results are not an indication of future business prospects or financial results. 42 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED --------------------------------------------

Earnings (Losses) ------------------------------------------------ Year Ended December 31, ------------------------------------------------ 2001 2000 1999 (A) ------------ ------------ ------------ (Millions of Dollars) Generation...................... $311 $270 $490 Energy Trading.................. 83 43 23 PSE&G........................... 230 369 131 Resources....................... 64 65 66 Global.......................... 116 40 28 Energy Technologies............. (18) (10) (6) Other (B)....................... (16) (13) (9) ------------ ------------ ------------ Total PSEG................. $770 $764 $723 ============ ============ ============

Contribution to Earnings Per Share (Basic and Diluted) ------------------------------------------------ Year Ended December 31, ------------------------------------------------ 2001 2000 1999 (A) ------------ ------------ ------------ Generation...................... $1.49 $1.26 $2.23 Energy Trading.................. 0.40 0.20 0.10 PSE&G........................... 1.11 1.71 0.60 Resources....................... 0.31 0.30 0.30 Global.......................... 0.55 0.19 0.13 Energy Technologies............. (0.08) (0.05) (0.03) Other (B)....................... (0.08) (0.06) (0.04) ------------ ------------ ------------ Total PSEG................. $3.70 $3.55 $3.29 ============ ============ ============

(A) Excludes $804 million, net of tax, extraordinary item recorded in 1999. (B) Other activities include amounts applicable to PSEG (parent corporation), Energy Holdings (parent corporation) and EGDC. Losses primarily result from after-tax effect of interest on certain financing transactions and certain other administrative and general expenses at parent companies. For the Year Ended December 31, 2001 compared to the Year Ended December 31, 2000 Basic and diluted earnings per share of our common stock (Common Stock) were $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 our stock repurchase program, discussed in Liquidity and Capital Resources. In addition, our improved earnings for 2001 as compared to 2000 resulted from improved performance from our Energy Trading segment, Global's withdrawal and sale of its interest in the Eagle Point Cogeneration Partnership (Eagle Point), acquisitions and expanded operations at Global, new leveraged lease investments at Resources and continued strong performance of our nuclear facilities. These improvements 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 generation revenues, and the effects of the securitization transaction that occurred on January 31, 2001. 43 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Operating Revenues Electric Electric revenues increased $319 million or 8% in 2001 as compared to 2000 primarily due to the inclusion of $172 million of revenues related to various majority owned acquisitions and plants going into operation at our Global segment in 2001. In addition, revenues from our generation segment increased $108 million in 2001 as compared to 2000 primarily due to an increase of $180 million in BGS revenue for the year ended December 31, 2001 as compared to 2000 which resulted from customers returning to PSE&G in 2001 from third party suppliers (TPS) as wholesale market prices exceeded fixed BGS rates. At December 31, 2001, TPS were serving less than 1% of the customer load traditionally served by PSE&G as compared to the December 31, 2000 level of 10.5%. Partially offsetting this increase was a net $40 million decrease in MTC revenues, relating to two 2% rate reductions offset by a pre-tax charge to income related to MTC recovery in 2000. As of December 31, 2001, as required by the Final Order, PSE&G has had rate reductions totaling 9% since August 1, 1999 and will have an additional 4.9% rate reduction effective August 1, 2002, which will be in effect until July 31, 2003. The remaining $39 million of the increase related to the PSE&G segment and was primarily related to increases in electric distribution and appliance service revenue. Gas Distribution In our PSE&G segment, Gas Distribution revenues increased $153 million or 7% in 2001 as compared to 2000 primarily due to higher gas costs experienced in 2001. Customer rates in all classes of business have 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. Pursuant to a settlement, the BPU issued an order approving a $90 million gas base rate increase effective January 9, 2002. The BPU approved the settlement simultaneously with the implementation of PSE&G's previously approved Gas Cost Underrecovery Adjustment (GCUA) surcharge to recover its October 31, 2001 gas cost under-recovery balance of approximately $130 million over a three year period with interest and also approved PSE&G's proposal to reduce its 2001/2003 Commodity Charges (formerly Levelized Gas Adjustment Clause (LGAC)) by approximately $140 million. The net impact of simultaneously implementing the above three proceedings for the typical gas residential heating customers is an approximate rate reduction of 2%. Trading Revenues from our energy trading segment decreased by $321 million or 12% for the year ended December 31, 2001 from the comparable periods in 2000, respectively, due to lower energy trading volumes and lower prices as compared to 2000. For information regarding valuation, term, credit and other issues related to Power's energy trading segment, see Accounting Issues, Note 1. Organization and Summary of Significant Accounting Policies and Note 8. Financial Instruments, Energy Trading and Risk Management of Notes. Other Other revenues increased $169 million or 21% in 2001 as compared to 2000. This increase was due to an increase in revenues at the Global, Resources and Energy Technologies segments of $111 million, $9 million and $50 million, respectively. The increase at Global was primarily realized 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 $26 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 44 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- interest income related to certain loans, 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 United States dollar and Brazilian Real. The increase at Resources was 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. The increase at Energy Technologies was primarily due to increased sales in its mechanical contracting business partially offset by a decrease of energy supply revenues. Operating Expenses Electric Energy Costs Electric Energy Costs increased $159 million or 17% in 2001 as compared to 2000. The increase was primarily due to $85 million of Electric Energy Costs relating to the various majority-owned acquisitions and projects going into operation at Global in 2001; higher costs in our generation segment associated with increased load served under the BGS contract due to retail customers returning to PSE&G in 2001 as discussed previously; and higher fuel costs of $73 million for fossil generation from higher natural gas prices in the early part of 2001 and higher gas expense due to increased MMBTU usage. These increases were partially offset by low cost generation from the continued strong performance of our nuclear generation facilities. Gas Costs Gas Costs increased $125 million or 8% in 2001 as compared to 2000 due to higher natural gas prices at our PSE&G segment in the early part of 2001. Under the LGAC in PSE&G, underrecoveries or overrecoveries, together with interest (in the case of net overrecoveries), are deferred and included in operations in the period in which they are reflected in rates. These increases were partially offset by lower costs incurred at Energy Technologies due to the outsourcing of certain supply contracts since June 2000 under its retail gas service agreements. Trading Costs Energy Trading costs decreased $391 million or 15% in 2001 compared to 2000, primarily due to lower energy trading volumes and lower prices. Operation and Maintenance Operation and Maintenance expense increased $280 million or 14% in 2001 as compared to 2000. Contributing to the increase were higher operating expenses relating to various majority-owned acquisitions and new plants going into operation at Global in 2001. Additionally, operation and maintenance expenses increased due to planned generation outage work in the first quarter of 2001 and higher expenses relating to projects going into operation during the second quarter of 2000 for our generation segment and 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 $160 million or 44% in 2001 as compared to 2000. The 2001 increase was due primarily due to $180 million of amortization of the regulatory asset recorded for PSE&G's stranded costs, which commenced with the issuance of the transition bonds, previously discussed. These increases were partially offset by a reduction in the accrual for the estimated cost of removal in our Generation segment. 45 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Taxes Other Than Income Taxes Taxes Other Than Income Taxes decreased $16 million or 9% in 2001 as compared to 2000. This decrease was primarily due to a reduction in the net taxable Transitional Energy Facility Assessment (TEFA) sales and the scheduled phase out of the TEFA. The TEFA was enacted as part of the energy tax reform bill and was scheduled to be phased out by 2003. Recent legislation delayed the phase out until 2007. Interest Expense Interest expense increased $131 million or 23% in 2001 as compared to 2000. The increase was primarily due to increased debt associated with the issuance of $2.525 billion securitization bonds by Transition Funding and the issuance of $1.8 billion of senior notes by Power to finance the generation asset transfer. These increases were offset by a general reduction in the amount of short-term and long-term debt at PSEG and PSE&G using proceeds from securitization bonds. Interest expense at Energy Holdings increased $53 million primarily from additional borrowings used for equity investments in Global and Resources. Preferred Securities Dividend Requirements of Subsidiaries Preferred Securities Dividend Requirements decreased $22 million or 23% in 2001 as compared to 2000 due to redemption of trust preferred securities. Income Taxes Income Taxes decreased $117 million or 24% in 2001 as compared to 2000. The decrease was primarily due to lower pre-tax income and normal adjustments as a result of closing the audit for the 1994-1996 tax years and upon filing our actual tax return for 2000. For the Year Ended December 31, 2000 compared to the Year Ended December 31, 1999 Excluding the $804 million, net of tax, extraordinary charge recorded in 1999, resulting from the deregulation of our generation segment, basic and diluted earnings per share increased $0.26 for the year ended December 31, 2000 as compared to 1999, including $0.08 of accretion as a result of our stock repurchase program. For further discussion, see Note 3. Regulatory Issues and Accounting Impacts of Deregulation of Notes. This increase was primarily due to lower depreciation and amortization resulting from the amortization of the excess depreciation reserve at our PSE&G segment beginning in January 2000 and the lower depreciation resulting from the lower recorded amounts of the generation-related assets in our generation segment resulting from the 1999 impairment recorded pursuant to Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121). Also contributing to the increase were increased sales due to favorable weather conditions in the fourth quarter of 2000 and higher profits realized from our energy trading segment. In addition, better overall performance of our Global segment, which benefited from favorable performance by its domestic generation assets and by its investments made in South America distribution assets in 1999, contributed to the increase. The increase in earnings was partially offset by the 5% electric rate reduction, beginning August 1, 1999 coupled with a charge to income in the third quarter of 2000 related to MTC recovery at our generation segment. Operating Revenues Electric Electric revenues decreased $244 million or 6% in 2000 as compared to 1999 due to a decrease in revenues from our generation segment primarily relating to the 5% rate reduction, which decreased our revenues by approximately $120 million combined with a $115 million deferral of MTC revenues; and reduced retail demand as PSE&G lost retail customers to TPS which amounted to approximately $182 million. See Accounting Issues-Accounting for the Effects of Regulation for a discussion of the deferral of MTC revenues. These decreases were partially offset by increased revenues from our PSE&G segment relating to higher transmission and distribution sales. 46 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- To the extent fuel expense flowed through the Electric Levelized Energy Adjustment Clause (LEAC) through July 31, 1999, the Levelized Gas Adjustment Clause (LGAC), the Societal Benefits Clause (SBC) or the non-utility generation market transition charge (NTC) mechanisms, as established by the BPU with respect to PSE&G's rates, variances in certain revenues and expenses offset and thus had no effect on earnings. On August 1, 1999, the LEAC mechanism was eliminated as a result of the Final Order. This has increased earnings volatility since Power now bears the full risks and rewards of changes in nuclear and fossil generating fuel costs and purchased power costs. See Note 3. Regulatory Issues and Accounting Impacts of Deregulation for a discussion of LEAC, LGAC, SBC, NTC, Remediation Adjustment Clause (RAC) and Demand Side Management (DSM) and their status under the Energy Master Plan Proceedings. Gas Distribution Revenues from our PSE&G segment for gas distribution increased $423 million or 25% in 2000 as compared to 1999 primarily due to increases in natural gas prices being passed along to customers under certain transportation only contracts. Under these contracts, PSE&G is responsible only for delivery of gas to its customers. Such customers are responsible for payment to PSE&G for the cost of the commodity and as PSE&G's costs for these customers increase, the customer's rates will increase. Also contributing to this increase were higher sales resulting from colder weather in the fourth quarter of 2000 as compared to the same period in 1999 and higher rates approved by the BPU to allow PSE&G to recover for increasing natural gas costs. Trading Energy Trading revenues increased $882 million or 48% for the year ended December 31, 2000 from the comparable period in 1999 primarily due to increased energy trading volumes. Other Other revenues increased $107 million or 16% in 2000 as compared to 1999. The increase was due to an increase of $26 million at Resources due to higher leveraged lease income from new leveraged lease investments, and increases in revenue at Energy Technologies due to the addition of revenues from acquisitions of various HVAC companies in 2000 and 1999. These increases were partially offset by a reduction in revenues of $42 million at Global primarily due to a gain on sale of Newark Bay recorded in 1999 as compared to no significant gain on sale of assets in 2000. Operating Expenses Electric Energy Costs Electric Energy Costs increased $38 million or 4% in 2000 as compared to 1999. The increase was primarily due to higher fuel costs in our generation segment and additional costs related to projects at our Global and Energy Technologies segments. Due to the elimination of the LEAC on August 1, 1999, the historical trends can no longer be considered an indication of future Electric Energy Costs. Given the elimination of the LEAC, the lifting of the requirements that electric energy offered for sale in the Pennsylvania-New Jersey-Maryland Power Pool (PJM) regional pool not exceed the variable cost of producing such energy (capped at $1,000 per megawatt-hour), the absence of a PJM price cap in situations involving emergency purchases and the potential for plant outages, price movements could have a material impact on our financial condition, results of operations or net cash flows. Gas Costs Gas Costs increased $364 million or 33% in 2000 as compared to 1999 primarily due to the higher prices for natural gas and increased demand for natural gas at our PSE&G segment due to colder weather in the fourth quarter 47 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- of 2000 as compared to the same period in 1999. This increase was partially offset by the outsourcing of certain supply contracts at Energy Technologies in June 2001, as discussed previously. Due to the operation of the Levelized Gas Adjustment Clause (LGAC) mechanism, variances in gas revenues and costs at PSE&G offset and had no direct effect on earnings. Trading Costs Energy Trading Costs increased $847 million or 47% for the year ended December 31, 2000 from the comparable 1999 period primarily due to increased energy trading volumes. Operation and Maintenance Operation and Maintenance expense increased $81 million or 4% in 2000 as compared to 1999. The increase was primarily due to the addition of $123 million in operating expenses from the HVAC and mechanical service contracting companies acquired by Energy Technologies in 2000 and 1999. The increase was partially offset by the effects of a $55 million pre-tax charge to earnings to reduce the carrying value of certain assets at Global and EGDC in 1999. Depreciation and Amortization Depreciation and Amortization expense decreased $174 million or 32% in 2000 as compared to 1999. The decrease was primarily due to the amortization of the regulatory liability for the excess electric distribution depreciation reserve at PSE&G, which amounted to approximately $125 million as of December 31, 2000. Also contributing to the decrease was lower depreciation resulting from the lower net book value balances of the generation-related assets in our generation segment. The generation-related asset balances were reduced as of April 1, 1999 as a result of the impairment recorded pursuant to SFAS 121. Taxes Other Than Income Taxes Taxes Other Than Income Taxes, which include TEFA, decreased $14 million or 7% in 2000 as compared to 1999 due to New Jersey Energy tax reform and the five-year commencing in January 1999. Effective January 1, 2000, revised rates became effective which reflected two years phase out of the TEFA discussed previously. Interest Expense Interest expense increased $84 million or 17% in 2000 as compared to 1999. The increase was primarily due to interest expense associated with recourse financing activities at Energy Holdings which increased $51 million from additional borrowings incurred as a result of equity investments in distribution and generation facilities and the repayment of non-recourse debt. Also contributing to the increase was the interest related to higher levels of short-term debt. Income Taxes Income Taxes decreased $73 million or 13% in 2000 as compared to 1999. The decrease is primarily due to a decrease in the foreign tax liability from foreign investments at Global recorded under the equity method. Under such accounting method, Global reflects in revenues its pro rata share of investments net income. Under this accounting method, the foreign income taxes are a component of equity in earnings, thereby distorting the effective tax rate downward. During 1999, there was an increase in state income taxes at Resources totaling $11 million due to the early termination of a leveraged lease. The decrease was also due to lower effective tax rates relating to the amortization of the excess depreciation reserve for electric distribution. 48 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- LIQUIDITY AND CAPITAL RESOURCES The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions of our three direct operating subsidiaries in 2001, PSE&G, Power and Energy Holdings. Our capital requirements and those of our subsidiaries are met and liquidity provided by internally generated cash flow and external financings. PSEG, Power and Energy Holdings from time to time make equity contributions 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, we utilize inter-company dividends and inter-company loans to satisfy various subsidiary needs and efficiently manage our and our subsidiaries' short-term cash needs. Any excess funds are invested in accordance with guidelines adopted by our Board of Directors. External funding to meet our needs and the needs of PSE&G, 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. All of our publicly traded debt as well as that of PSE&G, Power and Energy Holdings have received investment grade ratings from each of the three major credit rating agencies. The changes in the energy industry and the recent bankruptcy of Enron Corp. are attracting increased attention from the rating agencies which regularly assess business and financial matters. Given the changes in the industry, attention to and scrutiny of our, PSE&G's, Power's and Energy Holdings' performance, capital structure and competitive strategies by rating agencies will likely continue. These changes could affect the bond ratings, cost of capital and market prices of our respective securities. We will continue to evaluate our capital structure, financing requirements, competitive strategies and future capital expenditures to maintain our current 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 or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely effect the market price of PSEG's, Energy Holdings' Powers and PSE&G's securities and serve to increase those companies' cost of capital.

Moody's Standard & Poor's Fitch ------------------------------------------------------------------ PSEG ----------------------------- Extendible Notes Baa2 BBB BBB+ Preferred Securities Baa3 BB+ BBB Commercial Paper P2 A2 Not Rated PSE&G ----------------------------- Mortgage Bonds A3 A- A Preferred Securities Baa1 BBB A- 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 Not Rated

Depending on the particular company, external financing may consist of public and private capital market debt and equity transactions, bank revolving credit and term loan facilities, commercial paper and/or project financings. Some of these transactions involve special purpose entities. These are corporations, limited liability companies or partnerships formed in accordance with applicable tax, accounting and legal requirements in order to achieve specified beneficial financial advantages, such as favorable tax, legal liability or accounting treatment. 49 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- 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 or regulatory separation between us and our subsidiaries and between PSE&G and its non-utility affiliates 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. 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 special purpose subsidiary assets and/or cash flows. Two of Power's projects currently under construction have similar financing. Non-recourse transactions generally impose no obligation on the parent-level investor to repay any debt incurred by the project borrower. However, in some cases, certain obligations relating to the investment being financed, including additional equity commitments, are guaranteed by Global, Energy Holdings, and/or Power. Further, the consequences of permitting a project-level default include loss of any invested equity by the parent. Our debt indentures and credit agreements and those of our subsidiaries contain cross-default provisions under which a default by us or by specified subsidiaries involving specified levels of indebtedness in other agreements would result in a default and the potential acceleration of payment under such indentures and credit agreements. For example, a default for a specified amount with respect to any indebtedness of Global and Power, as set forth in various credit agreements, including obligations in non-recourse transactions, could cause a cross-default in one of our or our subsidiaries' credit agreements. Such lenders, or the debt holders under any of our or our subsidiaries' indentures, could determine that debt payment obligations may be accelerated as a result of a cross-default. These occurrences could severely limit our liquidity and restrict our ability to meet our debt, capital and, in extreme cases, operational cash requirements. Any inability to satisfy required covenants and/or borrowing conditions would have a similar impact. This would have a material adverse effect on our financial condition, results of operations and net cash flows, and those of our subsidiaries. In addition, our credit agreements and those of our subsidiaries generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower's, and as may be relevant, our, Energy Holdings', Power's or PSE&G's business or financial condition. In the event that we or the lenders in any of our or our subsidiaries' credit agreements determine that a material adverse change has occurred, loan funds may not be advanced. 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 our future financial position and the level of earnings and cash flow, as to which no assurances can be given. As part of our financial planning forecast, we perform stress tests on our financial covenants. These tests include a consideration of the impacts of potential asset impairments, foreign currency fluctuations, and other items. Our current analyses and projections indicate that, even in a worst-case scenario with respect to our investments in Argentina and considering other potential events, we will still be able to meet our financial covenants. Our debt indentures and credit agreements and those of our subsidiaries do not contain any "ratings triggers" that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade we and/or our subsidiaries may be subject to increased interest costs on certain bank debt. Also, in connection with its energy trading business, 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 energy trading business. These same contracts provide reciprocal benefits to Power. Global and Energy Holdings may have to provide collateral for certain of their equity commitments if Energy Holdings' ratings should fall below investment grade. This would increase our costs of doing business and limit our ability to successfully conduct our energy trading operations. In addition, our counterparties may require us to meet margin or other security requirements which may include cash payments. Capital resources and investment requirements could be affected by the outcome of proceedings by the BPU pursuant to its Energy Master Plan and Energy Competition Act and the requirements of the 1992 Focused Audit 50 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- conducted by the BPU, of the impact of our non-utility businesses, owned by Energy Holdings, on PSE&G. As a result of the Focused Audit, the BPU ordered that, among other things: (1) We will not permit Energy Holdings' investments to exceed 20% of our consolidated assets without prior notice to the BPU; (2) PSE&G's Board of Directors would provide an annual certification that the business and financing plans of Energy Holdings will not adversely affect PSE&G (3) We will (a) limit debt supported by the minimum net worth maintenance agreement between us and PSEG Capital to $650 million and (b) make a good-faith effort to eliminate such support over a six to ten year period from May 1993; and (4) Energy Holdings will pay PSE&G an affiliation fee of up to $2 million a year which is to be used to reduce customer rates. In the Final Order the BPU noted that, due to significant changes in the industry and, in particular, our corporate structure as a result of the Final Order, modifications to or relief from the Focused Audit order might be warranted. PSE&G has notified the BPU that PSEG will eliminate PSEG Capital debt by the end of 2003 and that it believes that the Final Order otherwise supercedes the requirements of the Focused Audit. While we believe that this issue will be satisfactorily resolved, no assurances can be given. In addition, if we were no longer to be exempt under the Public Utility Holding Company Act of 1935 (PUHCA), we and our subsidiaries would be subject to additional regulation by the SEC with respect to financing and investing activities, including the amount and type of non-utility investments. We believe that this would not have a material adverse effect on our financial condition, results of operations and net cash flows. Over the next several years, we and our subsidiaries will be required to refinance maturing debt, incur additional debt and provide equity to fund investment activity. Any inability to obtain required additional external capital or to extend or replace maturing debt and/or existing agreements at current levels and reasonable interest rates may affect our financial condition, results of operations and net cash flows. We and our subsidiaries have the following credit facilities for various funding purposes and to provide liquidity for our $850 million commercial program and PSE&G's $900 million commercial paper program. These agreements are with a group of banks and provide for borrowings with maturities of up to one year. The following table summarizes our various facilities as of December 31, 2001.

Commercial Maturity Total Primary Amount Paper (Cp) Company Date Facility Purpose Outstanding Outstanding ------------------------------------------- -------- -------- ------- ----------- ----------- (MILLIONS OF DOLLARS) PSEG ------------------------------------------- 364-day Credit Facility March 2002 $570 CP Support $ -- $475 5-year Credit Facility March 2002 280 CP Support -- N/A 5-year Credit Facility December 2002 150 Funding 125 N/A Bilateral Credit Agreement N/A No Limit Funding 153 N/A PSE&G ------------------------------------------- 364-day Credit Facility June 2002 390 CP Support -- -- 5-year Credit Facility June 2002 450 CP Support -- -- Bilateral Credit Agreement June 2002 60 CP Support -- -- Bilateral Credit Agreement N/A No Limit Funding -- N/A Energy Holdings ------------------------------------------- 364-day Credit Facility May 2002 200 Funding -- N/A 5-year Credit Facility May 2004 495 Funding 250 N/A Bilateral Credit Agreement N/A 100 Funding 50 N/A ---- ---- Total N/A $578 $475 ==== ====

PSEG As of December 31, 2001, we had repurchased approximately 26.5 million shares of Common Stock, at a cost of approximately $997 million since 1998. The repurchased shares have primarily been 51 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- held as treasury stock with the balance used for general corporate purposes. Dividend payments on Common Stock were $2.16 per share and totaled approximately $449 million and $464 million for the years ended December 31, 2001 and 2000, respectively. Our dividend rate has remained constant since 1992 in order to retain additional capital for reinvestment and to reduce the payout ratio as earnings grow. Although we presently believe we will have adequate earnings and cash flow in the future from our subsidiaries to maintain common stock dividends at the current level, earnings and cash flows required to support the dividend will become more volatile as our business continues to change from one that is principally regulated to one that is principally competitive. Future dividends declared will necessarily be dependent upon our future earnings, cash flows, financial requirements, alternate investment opportunities and other factors. We have issued Deferrable Interest Subordinated Debentures in connection with the issuance of tax deductible preferred securities. If payments on these 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. Financial covenants contained in our facilities include the ratio of debt (excluding non-recourse project financings and securitization debt and including commercial paper and loans) to total capitalization. At the end of any quarterly financial period such ratio shall not be more than .70 to 1. As of December 31, 2001, the ratio of debt to capitalization was .64 to 1. In June 2001, $300 million of Extendible Notes, Series C matured. In 2001, we invested $400 million in Energy Holdings and expect to make approximately the same contribution in 2002. PSE&G Under its Mortgage, PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements and/or retired Mortgage Bonds provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2:1. At December 31, 2001, PSE&G's Mortgage coverage ratio was 3:1. As of December 31, 2001, 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 will need to obtain BPU authorization to issue any incremental debt financing necessary for its capital program, including refunding of maturing debt and opportunistic refinancing. In January 2002, PSE&G filed a petition with the BPU for authorization to issue $1 billion of long-term debt through December 31, 2003. On December 27, 2001, PSE&G filed a shelf registration statement on Form S-3 for the issuance of $1 billion of debt and tax deferred preferred securities, which was declared effective by the SEC in February 2002. 52 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- On January 31, 2001, $2.525 billion of transition bonds were issued by PSE&G Transition Funding LLC, a bankruptcy-remote, wholly-owned subsidiary of PSE&G, in eight classes with maturities ranging from 1 year to 15 years. PSE&G also received payment from Power on its $2.786 billion promissory note used to finance the transfer of its generation business to Power. 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's common equity, loan funds to us and make various short-term investments. In March 2001, PSE&G redeemed all of its $150 million of 9.375% Series A cumulative monthly income preferred securities, all of its $75 million of 5.97% preferred stock, $15 million of its 6.75% preferred stock and $52 million of its floating rate notes due December 7, 2002. In June 2001, PSE&G redeemed the remaining $248 million outstanding of floating rate notes due December 7, 2002. In June 2001, PSE&G redeemed all of its $208 million of 8.625% Series A cumulative quarterly income preferred securities. In November 2001, $100 million of PSE&G Mortgage Bonds, Series FF matured. Also in November 2001, PSE&G redeemed $105 million of its variable rate Pollution Control Notes. In December 2001, PSE&G redeemed an additional $19 million of its variable rate Pollution Control Notes. Since 1986, PSE&G has made regular cash payments to us in the form of dividends on outstanding shares of PSE&G's common stock. PSE&G paid common stock dividends of $112 million and $638 million to us for the years ended December 31, 2001 and 2000, respectively. 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. Power Power's short-term financing needs will be met using our commercial paper program or lines of credit discussed above. As of December 31, 2001, letters of credit were issued in the amount of approximately $100 million. 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 8.625% Senior Notes due 2031. The net proceeds from the sale of the senior notes were used primarily for the repayment of loans from us. In August 2001, subsidiaries of Power closed on $800 million of non-recourse project bank financing for projects in Waterford, Ohio and Lawrenceburg, Indiana. The total combined project cost for Waterford and Lawrenceburg is estimated at $1.2 billion. Power's required estimated equity investment in these projects is approximately $400 million. In connection with these projects, ER&T has entered into a five-year tolling agreement pursuant to which it is obligated to purchase the output of these facilities at stated prices. As a result, ER&T will bear the price risk related to the output of these generation facilities which are scheduled to be completed in 2003. In the fourth quarter of 2001, Power issued $124 million in Pollution Control Notes. 53 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Energy Holdings As of December 31, 2001, Energy Holdings had two separate senior revolving credit facilities with a syndicate of banks as discussed in the table above. The five-year facility permits up to $250 million of letters of credit to be issued of which $57 million are outstanding as of December 31, 2001. Financial covenants contained in these 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 us to the extent not used to fund investing activity. 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 us. As of December 31, 2001, the latest 12 months CFADS coverage ratio was 4.4 and the ratio of recourse indebtedness to recourse capitalization was .45 to 1. PSEG Capital has a $750 million MTN program which provides for the private placement of MTNs. This MTN program is supported by a minimum net worth maintenance agreement between PSEG Capital and us which provides, among other things, that we (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. We believe that we are capable of eliminating our support of PSEG Capital debt within the time period set forth in the Focused Audit. In October 2001, $135 million of 6.74% MTNS matured and were refinanced with funds from the issuance of short-term debt at Energy Holdings. At December 31, 2001 and December 31, 2000, total debt outstanding under the MTN program was $480 million and $650 million, respectively maturing from 2002 to 2003. In February 2001, Energy Holdings sold $400 million of 8.625% Senior Notes due 2008 and in July 2001, sold $550 million of 8.50% Senior Notes due 2011. The net proceeds were used to repay short-term debt outstanding from intercompany loans and borrowings under Energy Holdings' revolving credit facilities and for general corporate purposes. In March 2001, $160 million of non-recourse bank debt originally incurred to fund a portion of the purchase price of Global's interest in Chilquinta Energia, S.A. was refinanced. The private placement offering by Chilquinta Energia Finance Co. LLC, a Global affiliate, of senior notes was structured in two tranches: $60 million due 2008 at an interest rate of 6.47% and $100 million due 2011 at an interest rate of 6.62%. An extraordinary loss of $2 million (after-tax) was recorded in connection with the refinancing of the $160 million non-recourse bank debt. In October 2001, PSEG Chile Holdings, a wholly-owned subsidiary of Global and a United States functional currency entity closed on $150 million of project financing related to its investment in SAESA, a Chilean Peso functional currency entity. The debt is variable and is based on LIBOR. In connection with this project financing, PSEG Chile Holdings entered into two foreign currency forward exchange contracts with a total notional amount of $150 million. The two contracts were entered into to hedge the Peso/United States Dollar exposure on the net investment. 54 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- CAPITAL REQUIREMENTS For the year ended December 31, 2001, we made net plant additions of $2.053 billion, excluding Allowance for Funds Used During Construction (AFDC) and capitalized interest. The majority of these additions, $1.5 billion, primarily related to Power for developing the Lawrenceburg, Indiana and the Waterford, Ohio sites and adding capacity to the Bergen, Linden, Burlington and Kearny stations in New Jersey. In addition, PSE&G had net plant additions of $398 million related to improvements in its transmission and distribution system, gas system and common facilities. Also in 2001, Energy Holdings' subsidiaries made investments totaling approximately $1.7 billion. These investments included leveraged lease investments totaling $460 million by Resources and new acquisitions by Global and additional investments in existing domestic and international facilities. Forecasted Expenditures Our subsidiaries have substantial commitments as part of their growth strategies and ongoing construction programs. We expect that the majority of each subsidiaries' 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 us. Projected construction and investment expenditures for our subsidiaries for the next five years are as follows:

2002 2003 2004 2005 2006 (Millions of Dollars) Power........................ $ 960 $ 700 $ 340 $ 250 $ 230 Energy Holdings.............. 450 600 600 600 600 PSE&G........................ 485 440 440 450 465 ---------------------------------------------------------------------------------- Total................... $ 1,895 $ 1,740 $ 1,380 $ 1,300 $ 1,295 ==================================================================================

For a discussion of new generation and development and other commitments to purchase equipment and services, all of which are included in our forecasts above, see Note 9. Commitments and Contingent Liabilities 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 will size its fleet of generation assets to take advantage of market opportunities, while seeking to increase its value and manage commodity price risk through its wholesale energy trading activity. A significant portion of Power's projected investment expenditures in the latter part of this forecast are not yet committed to specific projects. 55 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Energy Holdings plans to continue the growth of Global and Resources. The majority of Energy Holdings' projected investment expenditures are not yet committed to specific projects. Investment activity is subject to periodic review and revision and may vary significantly depending upon the opportunities presented. PSE&G's construction expenditures are primarily to maintain the safety and reliability of its electric and gas transmission and distribution facilities. Factors affecting our subsidiaries' actual expenditures and investments, including ongoing construction programs, include: availability of capital, suitable investment opportunities, prices of energy and supply in markets in which we participate, economic and political trends, revised load forecasts, business strategies, site changes, cost escalations under construction contracts, requirements of regulatory authorities and laws, and the timing of and amount of electric and gas transmission and/or distribution rate changes. Disclosures about Contractual Obligations and Commercial Obligations and Certain Investments The following tables, reflect our and our subsidiaries' contractual cash obligations and other commercial commitments in the respective periods in which they are due.

Less Total Amounts Than Contractual Cash Obligations Committed 1 year 2 - 3 years 4 - 5 years Over 5 years (Millions of Dollars) ------------------------------------------------------------------------------ Long - Term Debt $10,301 $1,093 $1,364 $1,622 $6,222 Capital Lease Obligations 102 8 16 16 62 Operating Leases 64 14 20 11 19 ------------------------------------------------------------------------------ Total Contractual Cash Obligations $10,467 $1,115 $1,400 $1,649 $6,303 ==============================================================================

We, Power, and Energy Holdings have guaranteed certain obligations of affiliates, including the successful completion, performance or other obligations and have contract equity contribution obligations related to certain projects in an aggregate amount of approximately $730 million, as of December 31, 2001. A substantial portion of such guarantees is eliminated upon successful completion, performance and/or refinancing of construction debt with non-recourse project term debt. In the normal course of business, Energy Technologies secures construction obligations with performance bonds issued by insurance companies. In the event that Energy Technologies' tangible equity falls below $100 million, Energy Holdings would be required to provide additional support for the performance bonds. As of December 31, 2001, Energy Technologies had tangible equity of $114 million and performance bonds outstanding of $124 million. The performance bonds are not included in the table below.

Total Less Amounts Than Other Commercial Commitments Committed 1 year 2 - 3 years 4 - 5 years Over 5 years --------- ------ ----------- ----------- ------------ (Millions of Dollars) ------------------------------------------------------------------------------ Standby Letters of Credit $159 $144 $5 $4 $ 6 Guarantees and Equity Commitments 571 428 101 - 42 ------------------------------------------------------------------------------ Total Commercial Commitments $730 $572 $106 $4 $ 48 ==============================================================================

Off Balance Sheet Arrangements Global has certain investments that are accounted for under the equity method in accordance with generally accepted accounting principles (GAAP). Accordingly, an amount is recorded on our balance sheet which is primarily Energy Holdings' equity investment and is increased for Energy Holdings' pro-rata share of earnings less any dividend distribution from such investments. The companies in which we invest that are accounted for under the equity method have an aggregate $1.88 billion of debt on their combined, consolidated financial statements. Our pro-rata share of such debt is $737 million and is non-recourse to us, Energy Holdings and Global. We are generally not required to support the debt service obligations of these companies. However, default with respect to this non-recourse debt could result in a loss of invested equity. 56 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Resources has investments in leveraged leases that are accounted for in accordance with SFAS 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. The creditor provides long term financing to the transaction, and is secured by the property subject to 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 his 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, 2001 Resources' equity investment in leased assets was approximately $1.6 billion, net of deferred taxes of approximately $1.2 billion. 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. 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. Should Resources ever directly assume a debt obligation, the fair value of the underlying asset and the associated debt would be recorded on the balance sheet instead of the net equity investment in the lease. In the events described above, the lease essentially changes from being classified as a capital lease to a conventional operating lease. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK The market risk inherent in our market risk sensitive instruments and positions is the potential loss arising from adverse changes in foreign currency exchange rates, commodity prices, equity security prices, and interest rates as discussed in the notes to the financial statements. Our policy is to use derivatives to manage risk consistent with our business plans and prudent practices. We have a Risk Management Committee comprised of executive officers which utilizes an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices. Counterparties expose us to credit losses in the event of non-performance or non-payment. We have a credit management process which is used to assess, monitor and mitigate counterparty exposure for us and our subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our and our subsidiaries' financial condition, results of operations or net cash flows. 57 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Foreign Currencies The objective of our foreign currency risk management policy is to preserve the economic value of cash flows in non-functional currencies. Toward this end, Energy Holdings' policy is to hedge all significant firmly committed cash flows identified as creating foreign currency exposure. In addition, we typically hedge a portion of exposure resulting from identified anticipated cash flows, providing the flexibility to deal with the variability of longer-term forecasts as well as changing market conditions, in which the cost of hedging may be excessive relative to the level of risk involved. As of December 31, 2001, Global and Resources had assets located or held in international locations of approximately $3.4 billion and $1.3 billion, respectively. Resources' international investments are primarily leveraged leases of assets located in Australia, Austria, Belgium, China, Germany, the Netherlands, the United Kingdom, and New Zealand with associated revenues denominated in United States Dollars ($US) and therefore, not subject to foreign currency risk. Global's international investments are primarily in companies that generate or distribute electricity in Argentina, Brazil, Chile, China, India, Italy, Oman, Peru, Poland, Taiwan, Tunisia and Venezuela. Investing in foreign countries involves certain additional risks. Economic conditions that result in higher comparative rates of inflation in foreign countries are likely to result in declining values in such countries' currencies. As currencies fluctuate against the $US, there is a corresponding change in Global's investment value in terms of the $US. Such change is reflected as an increase or decrease in the investment value and Other Comprehensive Income (Loss), a separate component of Stockholder's Equity. As of December 31, 2001, net foreign currency devaluations have reduced the reported amount of Energy Holdings' total Stockholder's Equity by $258 million (after-tax), of which $79 million (after-tax) was caused by the devaluation of the Chilean Peso and $169 million (after-tax) was caused by the devaluation of the Brazilian Real. Global holds a 60% ownership interest in a Tunisian generation facility under construction. The Power Purchase Agreement, signed in 1999, contains an embedded derivative that indexes the fixed Tunisian dinar payments to United States Dollar exchange rates. The embedded derivative is being marked to market through the income statement. As of January 1, 2001, a $9 million gain was recorded in the cumulative effect of accounting change for SFAS No. 133. During 2001, an additional gain of $1.4 million was recorded to the income statement as a result of favorable movements in the United States Dollar to Tunisian dinar exchange rate. Global holds approximately a 32% ownership interest in RGE whose debt is denominated in United States Dollars. In December 2001, the distribution company entered into a series of three forward exchange contracts to purchase United States Dollars for Brazilian Reals in order to hedge the risk of fluctuations in the exchange rate between the two currencies associated with the upcoming principal payments on the debt. These contracts expire in May, June and July 2002. As of December 31, 2001, Global's share of the fair value and aggregate notional value of the contracts was approximately $13 million. These contracts were established as hedges for accounting purposes resulting in an after tax charge to Other Comprehensive Income (OCI) of approximately $1.2 million. In addition, in order to hedge the foreign currency exposure associated with the outstanding portion of the debt, Global entered into a forward exchange contract in December 2001 to purchase United States Dollars for Brazilian Reals in approximately their share of the total debt outstanding ($61 million). The contract expired prior to December 31, 2001 and was not designated as a hedge for accounting purposes. As a result of unfavorable movements in the United States Dollars to Brazilian Real exchange rates, a loss of $4 million, after-tax was recorded related to this derivative upon maturity of the contract. This amount was recorded in Other Income. Through its 50% joint venture, Meiya Power Company, Global holds a 17.5% ownership interest in a Taiwanese generation project under construction where the construction contractor's fees, payable in installments through July 2003, are payable in Euros. To manage the risk of foreign exchange rate fluctuations associated with these payments, the project entered into a series of forward exchange contracts to purchase Euros in exchange for Taiwanese dollars. As of December 31, 2001, Global's share of the fair value and aggregate notional value of these forward exchange contracts was approximately $1 million and $16 million, respectively. These forward exchange contracts were not designated as hedges for accounting purposes, resulting in an after-tax gain of approximately $0.5 million. In addition, after-tax gains of $1 million were recorded during 2001 on similar forward exchange contracts expiring during the year. 58 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- During 2001, Global purchased approximately 100% of a Chilean distribution company. In order to hedge final Chilean peso denominated payments required to be made on the acquisition, Global entered into a forward exchange contract to purchase Chilean Pesos for United States Dollars. This transaction did not qualify for hedge accounting, and, as such, upon settlement of the transaction, Global recognized an after-tax loss of $0.5 million. Furthermore, as a requirement to obtain certain debt financing necessary to fund the acquisition, and in order to hedge against fluctuations in the United States Dollars to Chilean Peso foreign exchange rates, Global entered into a forward contract with a notional value of $150 million to exchange Chilean Pesos for United States Dollars. This transaction expires in October 2002 and is considered a hedge for accounting purposes. As of December 31, 2001, the derivative asset value of $4 million has been recorded to OCI, net of taxes ($1.4 million). In addition, Global holds a 50% interest in another Chilean distribution company, which was anticipating paying its U.S. investors a return of capital. In order to hedge the risk of fluctuations in the Chilean peso to U.S. dollar exchange rate, the distribution company entered into a forward exchange contract to purchase United States Dollars for Chilean Pesos. Global's after-tax share of the loss on settlement of this transaction (recorded by the distribution company) was $0.3 million. In January 2002, RGE entered into a series of nine cross currency interest rate swaps for the purpose of hedging its exposure to fluctuations in the Brazilian Real to United States Dollars exchange rates with respect to its United States Dollars denominated debt principal payments due in 2003 through 2006. The instruments convert the variable LIBOR based interest payments on the loan balance to variable CDI based interest payments. CDI is the Brazilian interbank interest rate. As a result, the distribution company has hedged its foreign currency exposure but is still at risk for variability in the Brazilian CDI interest rate during the terms of the instruments. Global's share of the notional value of the instruments is approximately $15 million for the instruments maturing in May, June and July of 2003 through 2005 and approximately $19 million for the instruments maturing in May, June and July 2006. Also in January 2002, the distribution company entered into two similar cross currency interest rate swaps to hedge the United States Dollar denominated interest payments due on the debt in February 2002 and May 2002. Global's share of the notional value of these two instruments is approximately $3 million each. Commodity Contracts During 2001, Power entered into electric physical forward contracts and gas futures and swaps with a maximum term of approximately one year, to hedge our forecasted BGS requirements and gas purchases requirements for generation. These transactions qualified for hedge accounting treatment under SFAS 133 and were settled prior to the end of 2001. The majority of the marked-to-market valuations were reclassified from OCI to earnings during the quarter ended September 30, 2001. As of December 31, 2001, we did not have any outstanding derivatives accounted for under this methodology. However, there was substantial activity during the year ended December 31, 2001. In 2001, the values of these forward contracts, gas futures and swaps as of June 30 and September 30 were $(34.2) million and $(0.4) million. Also as of December 31, 2001, PSE&G had entered into 330 MMBTU of gas futures, options and swaps to hedge forecasted requirements. As of December 31, 2001, the fair value of those instruments was $(137) million with a maximum term of approximately one year. PSE&G utilizes derivatives to hedge its gas purchasing activities which, when realized, are recoverable through its Levelized Gas Adjustment Clause (LGAC). Accordingly, these commodity contracts are recognized at fair value as derivative assets or liabilities on the balance sheet and the offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies and other events. To reduce price risk caused by market fluctuations, we enter into derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge our anticipated demand. These contracts, in conjunction with owned electric generation capacity, are designed to cover estimated electric customer commitments. We use a value-at-risk (VAR) model to assess the market risk of our commodity business. This model includes fixed price sales commitments, owned generation, native load requirements, physical contracts and financial derivative instruments. VAR represents the potential gains or losses for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. PSEG estimates VAR across its commodity business using a model with historical volatilities and correlations. The Risk Management Committee (RMC) established a VAR threshold of $25 million. If this threshold was reached, the RMC would be notified and the portfolio would be closely monitored to reduce risk and potential adverse movements. In anticipation of the completion of the current BGS contract with PSE&G on July 31, 2002, and the BGS auction, the VAR threshold was increased to $75 million. 59 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- The measured VAR using a variance/co-variance model with a 95% confidence level and assuming a one-week time horizon as of December 31, 2001 was approximately $18 million, compared to the December 31, 2000 level of $19 million. This estimate was driven by our assumption that Power would enter into contracts for approximately 50% of its generating capacity during the BGS auction. Since Power obtained contracts in excess of this amount, the VAR at December 31, 2001 would have been even lower. This estimate, however, is not necessarily indicative of actual results, which may differ due to the fact that actual market rate fluctuations may differ from forecasted fluctuations and due to the fact that the portfolio of hedging instruments may change over the holding period and due to certain assumptions embedded in the calculation. Interest Rates PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. Their 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. As of December 31, 2001, a hypothetical 10% change in market interest rates would result in a $3 million, $4 million, and $2 million, change in annual interest costs related to short-term and floating rate debt at PSEG, PSE&G, and Energy Holdings, respectively. The following table shows details of the interest rate swaps at PSEG, PSE&G, Power and Energy Holdings and their associated values that are still open at December 31, 2001:

Total Fair Other Project Notional Pay Receive Market Comprehensive Underlying Securities Percent Amount Rate Rate Value Income ------------------------------------------------------------------------------------------------------------------- PSEG: Enterprise Capital Trust II 100% $150.0 5.975% 3-month LIBOR $(5.1) $(3.0) Securities PSE&G: Transition Funding Bonds 100% $497.0 6.287% 3-month LIBOR $(18.5) $ - Power: Construction Loan - Waterford 100% $177.5 4.23% 3-month LIBOR $2.3 $1.3 Energy Holdings: Construction Loan - Tunisia (US$) 60% $60.0 6.9% 3-month LIBOR $(4.4) $(1.7) Construction Loan - Tunisia (EURO) 60% $67.2 5.2% 3-month EURIBOR* $(1.5) $(0.6) Construction Loan - Poland (US$) 55% $85.0 8.4% 3-month LIBOR $(30.1) $(8.5) Construction Loan - Poland (PLN) 55% $37.6 13.2% 3-month WIBOR** $(21.9) $(9.3) Construction Loan - Oman 81% $18.2 6.3% 3-month LIBOR $(3.3) $(1.7) Construction Loan - Kalaeloa 50% $57.3 6.6% 3-month LIBOR $(1.8) $(1.2) Construction Loan - Guadalupe 50% $126.8 6.57% 3-month LIBOR $(4.1) $(2.7) Construction Loan - Odessa 50% $138.3 7.39% 3-month LIBOR $(6.0) $(3.9) ----------- ---------- -------------- -------------------------- Total Energy Holdings $590.4 $(73.1) $(29.6) ----------- ---------- -------------- -------------------------- Total PSEG $1,414.9 $(94.4) $(31.3) =========== ========== ============== ==========================

* EURIBOR - EURO Area Inter-Bank Offered Rate ** WIBOR - Warsaw Inter-Bank Offered Rate We expect to reclass approximately $14.0 million of open interest rate swaps from OCI to earnings during the next twelve months. As of December 31, 2001, there was a $31.3 million balance remaining in the Accumulated Other Comprehensive Loss Account, as indicated in the table above. We have also entered into several interest rate swaps that were closed out during 2001 and are being amortized to earnings over the life of the underlying debt. These items, along with their current and anticipated effect on earnings discussed below. In February 2001, we entered into various forward-interest rate swaps, with an aggregate notional amount of $400 million, to hedge the interest rate risk related to the anticipated issuance of debt. On April 11, 2001, Power issued $1.8 billion in fixed-rate Senior Notes and closed out the forward starting interest rate swaps. The aggregate loss, net of tax, of $3.2 million was classified as Accumulated Other Comprehensive Loss and is being amortized and charged to interest expense over the life of the debt. During the year ended December 31, 2001, approximately $0.6 million was reclassified from OCI to earnings. Management expects it will amortize approximately $0.8 million from OCI to earnings during the next twelve months. In March 2001, $160 million of non-recourse bank debt originally incurred to fund a portion of the purchase price of Global's interest in Chilquinta Energia, S.A. was refinanced. The private placement offering by Chilquinta Energia Finance Co. LLC, a Global affiliate, of senior notes was structured in two tranches: $60 million due 2008 at an interest rate of 6.47% and $100 million due 2011 at an interest rate of 6.62%. An extraordinary loss of $2 million (after-tax) was recorded in connection with the refinancing of the $160 million non-recourse bank debt. 60 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Equity Securities 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. The aggregate fair values of such investments, which had quoted market prices at December 31, 2001 and December 31, 2000 were $34 million and $115 million, respectively. The potential change in fair value resulting from a hypothetical 10% change in quoted market prices of these investments amounted to $3 million and $9 million at December 31, 2001 and December 31, 2000, respectively. Credit Risk Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we 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. As a result of the BGS auction, Power has contracted to provide generating capacity to the direct suppliers of New Jersey electric utilities, including PSE&G, commencing August 1, 2002. These bilateral contracts are subject to credit risk. This credit risk relates to the ability of counterparties to meet their payment obligations for the power delivered under each BGS contract. This risk is substantially higher than the risk associated with potential nonpayment by PSE&G under the BGS contract expiring July 31, 2002 since PSE&G is a rate-regulated entity. Any failure to collect these payments under the new BGS contracts could have a material impact on our results of operations, cash flows, and financial position. In December 2001, Enron Corp. (Enron) filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Power had entered into a variety of energy trading contracts with Enron and its affiliates in the Pennsylvania-New Jersey-Maryland Power Pool (PJM) area as part of its energy trading activities. We took proper steps to mitigate our exposures to both Enron and other counterparties who could have been affected by Enron. As of December 31, 2001, we owed Enron approximately $23 million, net, and Enron held a letter of credit from Power for approximately $40 million. As a result of the California Energy Crisis, Pacific Gas & Electric Company (PG&E) filed for protection under Chapter 11 of the US Bankruptcy Code on April 16, 2001. GWF, Hanford and Tracy had combined pre-petition receivables due from PG&E, for all plants amounting to approximately $62 million. Of this amount, approximately $25 million had been reserved as an allowance for doubtful accounts resulting in a net receivable balance of approximately $37 million. Global's pro-rata share of this gross receivable and net receivable was approximately $30 million and $18 million, respectively. In December 2001, GWF, Hanford and Tracy reached an agreement with PG&E which stipulates that PG&E will make full payment of the $62 million in 12 equal installments, including interest by the end of 2002. On December 31, 2001, PG&E paid GWF $8 million, representing the initial installment payment and all accrued interest due, pursuant to the agreement. As of December 31, 2001, GWF, Hanford and Tracy still had combined pre-petition receivables due from PG&E for all plants amounting to approximately $57 million. Global's pro-rata share of this receivable was $27 million. As a result of this agreement, GWF, Hanford and Tracy reversed the reserve of $25 million which increased operating income by $25 million (of which Global's share was $11 million). FOREIGN OPERATIONS As of December 31, 2001, Global and Resources had approximately $3.4 billion and $1.3 billion, respectively, of international assets. As of December 31, 2001, foreign assets represented 19% of our consolidated assets and the revenues related to those foreign assets contributed 4% to consolidated revenues for the year ended December 31, 2001. For discussion of foreign currency risk and potential asset impairments related to our investments in Argentina, see the above discussion in Qualitative and Quantitive Disclosures About Market Risk and Note 9. Commitments and Contingent Liabilities and Note 17. Subsequent Events of Notes. ACCOUNTING ISSUES Critical Accounting Policies and Other Accounting Matters Our most critical accounting policies include the application of: SFAS No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) for PSE&G, our regulated 61 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- transmission and distribution business; Emerging Issues Task Force (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10) and EITF 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent" (EITF 99-19), for our Energy Trading business; and SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended (SFAS 133), to account for the various hedging transactions, and SFAS 52, "Foreign Currency Translation" and its impacts on Global's foreign investments. Accounting for the Effects of Regulation PSE&G prepares its financial statements in accordance with the provisions of SFAS No. 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 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. As a result of New Jersey deregulation legislation and regulatory orders issued by the BPU, certain regulatory assets and liabilities were recorded. The amortization of two of these regulatory liabilities will have a significant effect on our annual earnings. They include the estimated amount of MTC revenues to be collected in excess of the authorized amount of $540 million and the amount of excess electric distribution depreciation reserves. The amount of these regulatory liabilities will be amortized to earnings over the four-year transition period from August 1, 1999 through July 31, 2003. The MTC was authorized by the BPU as an opportunity to recover up to $540 million (net of tax) of our unsecuritized generation-related stranded costs on a net present value basis. As a result of the appellate reviews of the Final Order, PSE&G's securitization transaction was delayed until the first quarter of 2001, causing a delay in the implementation of the Securitization Transition Charge (STC) which would have reduced the MTC. As a result, MTC was being recovered at a faster rate than intended under the Final Order and a significant overrecovery was probable. In order to properly recognize the recovery of the allowed unsecuritized stranded costs over the transition period, PSE&G recorded a regulatory liability and Power 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. PSE&G then began deferring a portion of these revenues each month to recognize the estimated collections in excess of the allowed unsecuritized stranded costs. As of December 31, 2001, this deferred amount was $168 million and is aggregated with the Societal Benefits Clause. After deferrals, pre-tax MTC revenues recognized were $220 million in 1999, $239 million in 2000, and $196 million in 2001. In 2002 and 2003, we expect to record approximately $90 million and $121 million, respectively. The amortization of the Excess Depreciation Reserve is another significant regulatory liability affecting our earnings. As required by the BPU, PSE&G reduced its depreciation reserve for its electric distribution assets by $569 million and recorded such amount as a regulatory liability to be amortized over the period from January 1, 2000 to July 31, 2003. In 2000 and 2001, $125 million was amortized and recorded as a reduction of depreciation expense pursuant to the Final Order. The remaining $319 million will be amortized through July 31, 2003. See Note 4. Regulatory Assets and Liabilities of Notes for further discussion of these and other regulatory issues. Accounting, Valuation and Presentation of Our Energy Trading Business Accounting - We account for our energy trading business in accordance with the provisions of EITF Issue No. 98-10 which requires that energy trading contracts be marked to market with gains and losses included in current earnings. 62 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- Valuation - Since the vast majority of our energy trading contracts have terms of less than one year, valuations for these contracts are readily obtainable from the market exchanges, such as PJM, and over the counter quotations. The valuations also include a credit reserve and a liquidity reserve, which is determined using financial quotation systems, monthly bid-ask prices and spread percentages. We have consistently applied this valuation methodology for each reporting period presented. The fair values of these contracts and a more detailed discussion of credit risk are reflected in Note 8. Financial Instruments, Energy Trading and Risk Management. Presentation - EITF 99-19 provided guidance on the issue of whether a company should report revenue based on the gross amount billed to the customer or the net amount retained. The guidance states that whether a company should recognize revenue based on the gross amount billed or the net retained requires significant judgment, which depends on the relevant facts and circumstances. Based on the analysis and interpretation of EITF 99-19, we report all of the energy trading revenues and energy trading-related costs on a gross basis for physical bilateral energy and capacity sales and purchases. We report swaps, futures, option premiums, firm transmission rights, transmission congestion credits, and purchases and sales of emission allowances on a net basis. The prior year financial statements have been reclassified accordingly. One of the primary drivers of our determination that these contracts should be presented on a gross basis was that we retain counterparty risk. SFAS 133 - Accounting for Derivative Instruments and Hedging Activities SFAS 133 established accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize the fair value of derivative instruments held as assets or liabilities on the balance sheet. In accordance with SFAS 133, the effective portion of the change in the fair value of a derivative instrument designated as a cash flow hedge is reported in OCI, net of tax, or as a Regulatory Asset (Liability). Amounts in accumulated OCI are ultimately recognized in earnings when the related hedged forecasted transaction occurs. The change in the fair value of the ineffective portion of the derivative instrument designated as a cash flow hedge is recorded in earnings. Derivative instruments that have not been designated as hedges are adjusted to fair value through earnings. We have entered into several derivative instruments, including hedges of anticipated electric and gas purchases, interest rate swaps and foreign currency hedges which have been designated as cash flow hedges. The fair value of the derivative instruments is determined by reference to quoted market prices, listed contracts, published quotations or quotations from counterparties. In the absence thereof, we utilize mathematical models based on current and historical data. The fair value of most of our derivatives is determined based upon quoted market prices. Therefore, the effect on earnings of valuations from our models is minimal. For additional information regarding Derivative Financial Instruments, See Note 8 - Financial Instruments, Energy Trading and Risk Management - Derivative Instruments and Hedging Activities of Notes. SFAS 52 - Foreign Currency Translation Our financial statements are prepared using the United States Dollar as the reporting currency. In accordance with SFAS 52 "Foreign Currency Translation", foreign operations whose functional currency is deemed to be the local (foreign) currency, asset and liability accounts are translated into United States Dollars at current exchange rates and revenues and expenses are translated at average exchange rates prevailing during the period. Translation gains and losses (net of applicable deferred taxes) are not included in determining net income but are reported in other comprehensive income. Gains and losses on transactions denominated in a currency other than the functional currency are included in the results of operations as incurred. 63 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- The determination of an entity's functional currency requires management's judgment. It is based on an assessment of the primary currency in which transactions in the local environment are conducted, and whether the local currency can be relied upon as a stable currency in which to conduct business. As economic and business conditions change, we are required to reassess the economic environment and determine the appropriate functional currency. The impact of foreign currency accounting could have a material adverse impact on our financial condition, results of operation and net cash flows. Other Accounting Issues For additional information on our accounting policies and the implementation of recently issued accounting standards, see Note 1. Organization and Summary of Significant Accounting Policies and Note 2. Accounting Matters of Notes, respectively. FORWARD LOOKING STATEMENTS Except for the historical information contained herein, certain of the matters discussed in this report constitute "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties which could cause actual results to differ materially from those anticipated. Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used herein, the words "will", "anticipate", "intend", "estimate", "believe", "expect", "plan", "hypothetical", "potential", variations of such words and similar expressions are intended to identify forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The following review of factors should not be construed as exhaustive or as any admission regarding the adequacy of our disclosures prior to the effective date of the Private Securities Litigation Reform Act of 1995. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: o because a portion of our business is conducted outside the United States, adverse international developments could negatively impact our business; o credit, commodity, and financial market risks may have an adverse impact; o energy obligations, available supply and trading risks may have an adverse impact; o the electric industry is undergoing substantial change; o generation operating performance may fall below projected levels; o ability to obtain adequate and timely rate relief; o we and our subsidiaries are subject to substantial competition from well capitalized participants in the worldwide energy markets; o our ability to service debt could be limited; o if our operating performance or cash flow from minority interests falls below projected levels, we may not be able to service our debt; o power transmission facilities may impact our ability to deliver our output to customers; o government regulation affects many of our operations; o environmental regulation significantly impacts our operations; o we are subject to more stringent environmental regulation than many of our competitors; o insurance coverage may not be sufficient; o acquisition, construction and development may not be successful; and o recession, acts of war or terrorism could have an adverse impact. 64 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK Information relating to quantitative and qualitative disclosures about market risk is set forth under the caption "Qualitative and Quantitative Disclosures About Market Risk" in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Such information is incorporated herein by reference. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 65 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED STATEMENTS OF INCOME (Millions of Dollars, except for Per Share Data)

For The Years Ended December 31, ------------------------------------------------- 2001 2000 1999 -------------- ------------- ------------ OPERATING REVENUES Electric $ 4,156 $ 3,837 $ 4,081 Gas 2,293 2,140 1,717 Trading 2,403 2,724 1,842 Other 963 794 687 ------- ------- ------- Total Operating Revenues 9,815 9,495 8,327 OPERATING EXPENSES Electric Energy Costs 1,119 960 922 Gas Costs 1,596 1,471 1,107 Trading Costs 2,256 2,647 1,800 Operation and Maintenance 2,264 1,984 1,903 Depreciation and Amortization 522 362 536 Taxes Other Than Income Taxes 166 182 196 ------- ------- ------- Total Operating Expenses 7,923 7,606 6,464 ------- ------- ------- OPERATING INCOME 1,892 1,889 1,863 Other Income and Deductions 21 33 7 Interest Expense-net (705) (574) (490) Preferred Securities Dividend Requirements and Premium on Redemption (72) (94) (94) ------- ------- ------- INCOME BEFORE INCOME TAXES, EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 1,136 1,254 1,286 Income Taxes (373) (490) (563) ------- ------- ------- INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 763 764 723 Extraordinary Item (net of tax - 2001, $1; 1999, $345) (2) - (804) Cumulative Effect of a Change in Accounting Principle (net of tax) 9 - - ------- ------- ------- NET INCOME (LOSS) $ 770 $ 764 $ (81) ======= ======= ======= WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (000's) 208,226 215,121 219,814 ======= ======= ======= EARNINGS PER SHARE (BASIC AND DILUTED): INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE $ 3.67 $ 3.55 $ 3.29 Extraordinary Item (net of tax) (0.01) - (3.66) Cumulative Effect of a Change in Accounting Principle (net of tax) 0.04 - - ------- ------- ------- NET INCOME (LOSS) $ 3.70 $ 3.55 $ (0.37) ======= ======= ======= DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 2.16 $ 2.16 $ 2.16 ======= ======= =======

See Notes to Consolidated Financial Statements. 66 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED BALANCE SHEETS ASSETS (Millions of Dollars)

December 31, ----------------------------------- 2001 2000 --------------- ------------- CURRENT ASSETS Cash and Cash Equivalents $ 169 $ 102 Accounts Receivable: Customer Accounts Receivable 824 778 Other Accounts Receivable 348 431 Allowance for Doubtful Accounts (43) (44) Unbilled Electric and Gas Revenues 291 357 Fuel 509 431 Materials and Supplies 174 155 Prepayments 74 31 Energy Trading Contracts 454 799 Restricted Cash 13 1 Assets held for Sale 422 48 Other 24 50 --------------- ------------- Total Current Assets 3,259 3,139 --------------- ------------- PROPERTY, PLANT AND EQUIPMENT Generation 4,884 2,860 Transmission and Distribution 9,500 8,479 Other 502 608 --------------- ------------- Total 14,886 11,947 Accumulated depreciation and amortization (4,822) (4,266) --------------- ------------- Net Property, Plant and Equipment 10,064 7,681 --------------- ------------- NONCURRENT ASSETS Regulatory Assets 5,220 4,995 Long-Term Investments, net of accumulated amortization and net of valuation allowances - 2001, $30; 2000, $72 4,818 4,545 Nuclear Decommissioning Fund 817 716 Other Special Funds 222 122 Goodwill, net of accumulated amortization 649 78 Other, net of accumulated amortization 348 250 --------------- ------------- Total Noncurrent Assets 12,074 10,706 --------------- ------------- TOTAL ASSETS $ 25,397 $ 21,526 =============== =============

See Notes to Consolidated Financial Statements. 67 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED BALANCE SHEETS LIABILITIES AND CAPITALIZATION (Millions of Dollars)

December 31, ------------------------------------ 2001 2000 --------------- --------------- CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 1,213 $ 667 Commercial Paper and Loans 1,338 2,885 Accounts Payable 790 1,001 Energy Trading Contracts 602 730 Other 751 429 --------------- --------------- Total Current Liabilities 4,694 5,712 --------------- --------------- NONCURRENT LIABILITIES Deferred Income Taxes and ITC 3,205 3,107 Regulatory Liabilities 373 470 Nuclear Decommissioning 817 716 OPEB Costs 476 448 Cost of Removal 146 157 Other 488 415 --------------- --------------- Total Noncurrent Liabilities 5,505 5,313 --------------- --------------- COMMITMENTS AND CONTINGENT LIABILITIES - - --------------- --------------- CAPITALIZATION: LONG-TERM DEBT 10,301 5,297 --------------- --------------- SUBSIDIARIES' PREFERRED SECURITIES: Preferred Stock Without Mandatory Redemption 80 95 Preferred Stock With Mandatory Redemption - 75 Guaranteed Preferred Beneficial Interest in Subordinated Debentures 680 1,038 --------------- --------------- Total Subsidiaries' Preferred Securities 760 1,208 --------------- --------------- COMMON STOCKHOLDERS' EQUITY: Common Stock, issued; 2001 and 2000, 231,957,608 shares 3,599 3,604 Treasury Stock, at cost; 2001 - 26,118,590 shares, 2000 - 23,986,290 shares (981) (895) Retained Earnings 1,809 1,493 Accumulated Other Comprehensive Loss (290) (206) --------------- --------------- Total Common Stockholders' Equity 4,137 3,996 --------------- --------------- Total Capitalization 15,198 10,501 --------------- --------------- TOTAL LIABILITIES AND CAPITALIZATION $ 25,397 $ 21,526 =============== ==============

See Notes to Consolidated Financial Statements. 68 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of Dollars)

For the Years Ended December 31, ------------------------------------------------- 2001 2000 1999 ------------ ------------- ------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ 770 $ 764 $ (81) Adjustments to reconcile net income (loss) to net cash flows from operating activities: Extraordinary Loss - net of tax 2 - 804 Depreciation and Amortization 522 362 536 Amortization of Nuclear Fuel 99 96 92 Recovery (Deferral) of Electric Energy and Gas Costs - net (86) 16 61 Excess Unsecuritized Stranded Costs 54 115 - Provision for Deferred Income Taxes and ITC - net (179) (11) (215) Investment Distributions 73 56 134 Equity Income from Partnerships (107) (28) (53) Unrealized Gains on Investments (67) (39) (63) Leasing Activities (7) 74 6 Proceeds from Sale of Capital Leases 104 89 125 Proceeds from Withdrawal/Sale of Partnerships 75 - 71 Net Changes in certain current assets and liabilities: Inventory - Fuel and Materials and Supplies (84) (145) 9 Accounts Receivable and Unbilled Revenues 272 (299) (236) Prepayments (40) 8 8 Accounts Payable (406) 260 57 Other Current Assets and Liabilities 511 (47) 59 Other (164) (42) 114 ------------ ------------- ------------- Net Cash Provided By Operating Activities 1,342 1,229 1,428 ------------ ------------- ------------- CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment, excluding IDC and AFDC (2,053) (959) (582) Net Change in Long-Term Investments (709) (678) (1,127) Acquisitions, Net of Cash Provided (756) (14) (49) Other (260) (53) (70) ------------ ------------- ------------- Net Cash Used In Investing Activities (3,778) (1,704) (1,828) ------------ ------------- ------------- CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt (1,512) 913 916 Issuance of Long-Term Debt 6,317 1,200 1,143 Redemption/Purchase of Long-Term Debt (1,292) (1,033) (676) Redemption of Preferred Securities (448) - - Purchase of Treasury Stock (91) (298) (400) Cash Dividends Paid on Common Stock (449) (464) (474) Other (22) - 11 ------------ ------------- ------------- Net Cash Provided By (Used In) Financing Activities 2,503 318 520 ------------ ------------- ------------- Net Change In Cash And Cash Equivalents 67 (157) 120 Cash And Cash Equivalents At Beginning Of Period 102 259 139 ------------ ------------- ------------- Cash And Cash Equivalents At End Of Period $ 169 $ 102 $ 259 ============ ============= ============= Income Taxes Paid $ 87 $ 485 $ 534 Interest Paid $ 700 $ 550 $ 494

See Notes to Consolidated Financial Statements. 69 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (Millions)

Common Treasury Stock Stock ------------------- ---------------------- Shs. Amount Shs. Amount ------- ---------- ------- ----------- BALANCE AS OF JANUARY 1, 1999 232 3,603 (5) (207) Net Income (Loss) - - - - Other Comprehensive Income (Loss), net of tax: Currency Translation Adjustment, net of tax of $(17) - - - - Other Comprehensive Income (Loss) - - - - Comprehensive Income (Loss) - - - - Cash Dividends on Common Stock - - - - Purchase of Treasury Stock - - (11) (400) Other - 1 - 10 ------------------- ---------------------- BALANCE AS OF DECEMBER 31, 1999 232 3,604 (16) (597) ------------------- ---------------------- Net Income (Loss) - - - - Other Comprehensive Income (Loss), net of tax: Currency Translation Adjustment, net of tax of $(0) - - - - Other Comprehensive Income (Loss) - - - - Comprehensive Income (Loss) - - - - Cash Dividends on Common Stock - - - - Purchase of Treasury Stock - - (8) (298) ------------------- ---------------------- BALANCE AS OF DECEMBER 31, 2000 232 $ 3,604 (24) $ (895) ------------------- ---------------------- Net Income (Loss) - - - - 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) and minority interest $(6) - - - - Cumulative Effect of Change in Accounting Principle net of tax $(14) - - - - Reclassification Adjustments for Net Amounts included in Net Income, net of tax of $19 and minority interest of $3 - - - - Pension Adjustments, net of tax $(1) - - - - Change in Fair Value of Equity Investments, net of tax $(1) - - - - Other Comprehensive Income (Loss) - - - - Comprehensive Income (Loss) - - - - Cash Dividends on Common Stock - - - - Purchase of Treasury Stock - - (2) (92) Other - (5) - 6 =================== ====================== BALANCE AS OF DECEMBER 31, 2001 232 $ 3,599 (26) $ (981) =================== ======================

Accumulated Other Retained Comprehensive Earnings Income (Loss) Total ------------ ----------------- ------------ Balance as of January 1, 1999 1,748 (46) 5,098 Net Income (Loss) (81) - (81) Other Comprehensive Income (Loss), net of tax: Currency Translation Adjustment, net of tax of $(17) - (158) (158) ------------ Other Comprehensive Income (Loss) - - (158) ------------ Comprehensive Income (Loss) - - (239) Cash Dividends on Common Stock (474) - (474) Purchase of Treasury Stock - - (400) Other - - 11 ------------ ----------------- ------------ Balance as of December 31, 1999 1,193 (204) 3,996 ------------ ----------------- ------------ Net Income (Loss) 764 - 764 Other Comprehensive Income (Loss), net of tax: Currency Translation Adjustment, net of tax of $(0) - (2) (2) ------------ Other Comprehensive Income (Loss) - - (2) ------------ Comprehensive Income (Loss) - - 762 Cash Dividends on Common Stock (464) - (464) Purchase of Treasury Stock - - (298) ------------ ----------------- ------------ Balance as of December 31, 2000 $1,493 $ (206) $3,996 ------------ ----------------- ------------ Net Income (Loss) 770 - 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) and minority interesf $(6) - (57) (57) Cumulative Effect of Change in Accounting Principle net of tax $(14) - (15) (15) Reclassification Adjustments for Net Amounts included in Net Income, net of tax of $19 and minority interest of $3 - 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 Income (Loss) - - (84) ------------ Comprehensive Income (Loss) - - 686 Cash Dividends on Common Stock (449) - (449) Purchase of Treasury Stock - - (92) Other (5) - (4) ------------ ----------------- ------------ Balance as of December 31, 2001 $1,809 $ (290) $4,137 ============ ================= ============

See Notes to Consolidated Financial Statements. 70 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1. Organization and Summary of Significant Accounting Policies Organization We have four principal direct wholly-owned subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings Inc. (Energy Holdings) and PSEG Services Corporation (Services). 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 to Power in August 2000, PSE&G continues to own and operate its transmission and distribution business. Power has three principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T) and currently operates in two reportable segments, generation and energy trading. Power and its subsidiaries were established to acquire, own and operate the electric generation-related business of PSE&G pursuant to the Final Decision and Order (Final Order) issued by the New Jersey Board of Public Utilities (BPU) under the New Jersey Electric Discount and Energy Competition Act (Energy Competition Act) discussed below. Power also has a finance company subsidiary, PSEG Power Capital Investment Co. (Power Capital), which provides certain financing for Power's subsidiaries. Energy Holdings participates in three energy-related reportable segments through its wholly-owned subsidiaries: PSEG Global Inc. (Global), PSEG Resources Inc. (Resources) and PSEG Energy Technologies Inc. (Energy Technologies). Energy Holdings also has a finance subsidiary, PSEG Capital Corporation (PSEG Capital) and is also the parent of Enterprise Group Development Corporation (EGDC), a commercial real estate property management business, and is conducting a controlled exit from this business. Services provides management and administrative services at cost to us and our subsidiaries. Summary of Significant Accounting Policies Consolidation Our consolidated financial statements include our accounts and those of our subsidiaries. We and our subsidiaries consolidate those entities in which we have a controlling interest. Those entities in which we and our 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. 71 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Regulation PSE&G prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for 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 We use derivative financial instruments to manage our risk from changes in interest rates, commodity prices and foreign currency exchange rates, pursuant to its business plans and prudent practices. On January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended (SFAS 133). SFAS 133 established accounting and reporting standards for derivative instruments, including certain derivative instruments included in other contracts, and for hedging activities. It requires an entity to recognize the fair value of derivative instruments held as assets or liabilities on the balance sheet. For cash flow hedging purposes, changes in the fair value of the effective portion of the gain or loss on the derivative are reported in Other Comprehensive Income (OCI) 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. We recorded a cumulative effect in a change in accounting principle of $9 million, net of tax and a decrease to OCI of ($15) million, respectively, in connection with the adoption of 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, we utilize mathematical models based on current and historical data. Prior to the adoption of SFAS 133, we accounted for the results of our derivative activities for hedging purposes utilizing the settlement method. The settlement method provided for recognizing gains or losses from derivatives when the related physical transaction was completed. Derivatives that were not entered into for hedging purposes were valued at fair value and changes in fair value were recorded in earnings. For additional information regarding Derivative Financial Instruments, See Note 8. Financial Instruments, Energy Trading and Risk Management. Commodity Contracts PSE&G enters into natural gas commodity forwards, futures, swaps and options with counterparties to reduce exposure to price fluctuations from factors such as weather, changes in demand and changes in supply. These instruments, in conjunction with physical gas supply contracts, are designed to cover estimated gas customer commitments. In accordance with SFAS 133, such energy contracts are recognized at fair value as 72 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued derivative assets or liabilities on the balance sheet. These derivatives, when realized, are recoverable through the Levelized Gas Adjustment Clause (LGAC). Accordingly, the offset to the change in fair value of these derivatives is specified as a regulatory asset or liability. Power enters into electricity forward purchases and natural gas commodity futures and swaps with counterparties to manage exposure to electricity and natural gas price risk. These contracts, in conjunction with owned electric generating capacity, are designed to manage price risk exposure for electric customer commitments. In accordance with SFAS 133, such energy contracts are recognized at fair value as derivative assets or liabilities on the balance sheet and the effective portion of the gain of loss on the contracts is reported in OCI, net of tax. Amounts in accumulated OCI are ultimately recognized in earnings when the related hedged forecasted transaction occurs. Power also enters into forwards, futures, swaps and options as part of its energy trading operations. Effective January 1, 1999, Power adopted Emerging Issues Task Force (EITF) Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10). EITF 98-10 requires that energy trading contracts be marked to market with gains and losses included in current earnings. The vast majority of these commodity-related contracts have terms of less than one year. Valuations for these contracts are readily obtainable from the market exchanges, such as PJM, and over the counter quotations. The fair value of the financial instruments that are marked to market are based on management's best estimates. The valuations also take into account a liquidity reserve, which is determined by using financial quotation systems, monthly bid-ask prices and spread percentages. The valuations also take into account credit reserves, discussed in Note 8. Financial Instruments, Energy Trading and Risk Management - Credit Risk. We have consistently applied this valuation methodology for each reporting period presented. In July 2000, EITF 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent" (EITF 99-19), provided guidance on the issue of whether a company should report revenue based on the gross amount billed to the customer or the net amount retained. The guidance states that whether a company should recognize revenue based on the gross amount billed or the net retained requires significant judgment, which depends on the relevant facts and circumstances. Based on the analysis and interpretation of EITF 99-19, we report all of the energy trading revenues and energy trading-related costs on a gross basis for physical bilateral energy and capacity sales and purchases. We continue to report swaps, futures, option premiums, firm transmission rights, transmission congestion credits, and purchases and sales of emission allowances on a net basis. The prior year financial statements have been reclassified accordingly. For additional information regarding commodity-related contracts, See Note 8 - Financial Instruments, Energy Trading and Risk Management. Revenues and Fuel Costs 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. Prior to August 1, 1999, fuel revenue and expense flowed through the Electric Levelized Energy Adjustment Clause (LEAC) mechanism. Variances in fuel revenues and expenses were subject to deferral accounting and had no direct effect on earnings. Under the LEAC and the Levelized Gas Adjustment Clause (LGAC), any LEAC and 73 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued LGAC underrecoveries or overrecoveries, together with interest (in the case of net overrecoveries), are deferred and included in operations in the period in which they are reflected in rates. Following the transfer of generation-related assets and liabilities in August 2000, Power bears the full risks and rewards of changes in nuclear and fossil generating fuel costs and replacement power costs. Cash and Cash Equivalents 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. Restricted Cash Transition Funding has deposited funds with a Trustee which are required to be used for payment of principal, interest and other expenses related to its transition bonds (see Note 3. Regulatory Issues and Accounting Impacts of Deregulation). Accordingly, these funds are classified as "Restricted Cash" on our Consolidated Balance Sheets Materials and Supplies and Nuclear Fuel PSE&G's materials and supplies are carried on the books at average cost in accordance with rate based regulation. The carrying value of the materials and supplies and nuclear fuel for our non-utility subsidiaries is valued at lower of cost or market. Depreciation and Amortization 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 3.32% for 2001 and 3.52% for 2000 and 1999. PSE&G has certain regulatory assets and liabilities resulting from the use of a level of depreciation expense in the ratemaking process that differs from the amount that is recorded under generally accepted accounting principles (GAAP) for non-regulated companies. Power calculates depreciation on generation-related assets based on the assets' estimated useful lives determined based on planned operations, rather than using depreciation rates prescribed by the BPU in rate proceedings. 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 25-55 years Nuclear Generation 30 years Pumped Storage 45 years Nuclear fuel burnup costs are charged to fuel expense on a units-of-production basis over the estimated life of the fuel. Rates for the recovery of fuel used at all nuclear units include a provision of one mill per kilowatt-hour (kWh) of nuclear generation for spent fuel disposal costs. Energy Holdings calculates depreciation on property, plant and equipment under the straight line method with estimated useful lives from 3 years to 40 years. 74 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Unamortized Loss on Reacquired Debt and Debt Expense Bond issuance costs and associated premiums and discounts are generally amortized over the life of the debt issuance. In accordance with 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. For our non-utility subsidiaries, all gains and losses on reacquired debt are reflected in earnings as an extraordinary item. Allowance for Funds Used During Construction (AFDC) and Interest Capitalized During Construction (IDC) 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 Income as a reduction of interest charges. The rates used for calculating AFDC in 2001, 2000 and 1999 were 6.71%, 6.45% and 5.29%, respectively. Effective April 1, 1999, AFDC was no longer used for any capital projects related to our generation assets. Interest related to these capital projects is now capitalized in accordance with SFAS No. 34, "Capitalization of Interest Cost." In 2001, 2000 and 1999, AFDC amounted to $2 million, $1 million and $3 million, respectively. IDC represents the cost of debt used to finance the construction of non-utility facilities. The amount of IDC capitalized is reported in the Consolidated Statements of Income as a reduction of interest charges. The weighted average rates used for calculating IDC in 2001 and 2000 were 7.98% and 9.98%, respectively. In 2001, 2000 and 1999, IDC amounted to $80 million, $35 million and $13 million, respectively. Income Taxes We and our subsidiaries file a consolidated Federal income tax return and income taxes are allocated to our 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. Property, Plant and Equipment 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. At the time units of depreciable property are retired or otherwise disposed, the original cost adjusted for net salvage value is charged to accumulated depreciation. Our non-regulated subsidiaries 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. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets' environmental safety or efficiency. All other environmental expenditures are expensed. 75 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Assets Held For Sale For a discussion of the pending sale of certain investments in Argentina, see Note 9. Commitments and Contingent Liabilities. EGDC is conducting a controlled exit from the real estate business. In 1999, a pre-tax charge of $11 million was recorded for a property held for sale. This amount is recorded in operations and maintenance expense. Since EGDC has been conducting a controlled exit from the real estate business, gains and losses from property sales are considered to be in the normal course of business of EGDC. As of December 31, 2001 and December 31, 2000, EGDC has three properties and four properties, respectively, reported as Assets Held for Sale amounting to $23 and $13 million, respectively. Foreign Currency Translation/Transactions The assets and liabilities of foreign operations are translated into United States dollars at current exchange rates and revenues and expenses are translated at average exchange rates for the year. Resulting translation adjustments are reflected as a separate component of stockholders' equity. 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. Capital Leases as Lessee The Consolidated Balance Sheets include assets and related obligations applicable to capital leases under which the entity is a lessee. The total amortization of the leased assets and interest on the lease obligations equals the net minimum lease payments included in rent expense for capital leases. Capital leases of PSE&G relate primarily to its corporate headquarters. See Note 9 - Commitments and Contingent Liabilities. Impairment of Long-Lived Assets We and our unregulated subsidiaries review long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In the event that facts and circumstances indicate that the carrying amount of long-lived assets may be impaired, an evaluation of recoverability would be performed. If an evaluation is required, the estimated future undiscounted cash flows associated with the asset would be compared to the asset's carrying amount to determine if a writedown is required. If this review indicates that the assets will not be recoverable, the carrying value of our assets would be reduced to their estimated market value. Upon deregulation, PSE&G evaluated the recoverability of its generation related assets and recorded an extraordinary, non-cash charge to earnings. For the impact of the application of SFAS 121, see Note 3. Regulatory Issues and Accounting Impacts of Deregulation. Goodwill We classified the cost in excess of fair value of the net assets as goodwill (including tax attributes) of companies acquired in purchase business transactions. Goodwill recorded in connection with acquisitions that occurred prior to July 1, 2001 are amortized on a straight line basis over its estimated useful life, principally over a forty year period, except for certain amounts with lives determined to be shorter than forty years. For a discussion of recent accounting standards with respect to recent business combinations and goodwill, see Note 2. "Accounting Matters". We evaluate the recoverability of goodwill by estimating the future discounted cash flows of the businesses to which goodwill relates. The rate used in determining discounted cash flows is a rate corresponding to our cost of 76 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued capital. Estimated cash flows are then determined by disaggregating our 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 carrying value of the net assets (tangible or identifiable intangibles) and goodwill over the discounted cash flows of the business being evaluated. In determining the estimated future cash flows, we consider current and projected future levels of income as well as business trends, prospects and economic conditions. For a discussion of recent accounting standards with respect to recent business combinations and goodwill, see Note 2. Accounting Matters and Note 9. Commitments and Contingent Liabilities. Use of Estimates The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. 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. Nuclear Decommissioning Trust Funds Funds in our Nuclear Decommissioning Trust are stated at fair value. Changes in the fair value of trust funds are also reflected in the accrued liability for nuclear decommissioning. Reclassifications Certain reclassifications of amounts reported in prior periods have been made to conform with the current presentation. Current Assets and Current Liabilities The fair value of the current assets and liabilities approximate their carrying amounts. Note 2. Accounting Matters In July 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS 141). SFAS 141 was effective July 1, 2001 and requires that all business combinations on or after that date be accounted for under the purchase method. Upon implementation of this standard, there was no impact on our financial position or results of operations and we do not believe it will have a substantial effect on our strategy. Also in July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). Under SFAS 142, goodwill is considered a nonamortizable asset and will be subject to an annual review for impairment and an interim review when events or circumstances occur. SFAS 142 is effective for all fiscal years beginning after December 15, 2001. The impact of adopting SFAS 142 is likely to be material to our financial position and results of operations. For additional information relating to potential asset impairments, see Note 9. Commitments and Contingent Liabilities. Also in July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). Under SFAS 143, the fair value of a liability for an asset retirement obligation should be recorded in the period in which it is created with an offsetting amount to an asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. SFAS 143 is effective for fiscal years beginning after June 15, 2002. We are currently evaluating this guidance and cannot predict the impact on our financial position or results of operations; however, such impact could be material. 77 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued In August 2001, FASB issued SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets" (SFAS 144). Under SFAS 144 long-lived assets to be disposed of will be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continued operations or in discontinued operations. Discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operations. SFAS 144 is effective for fiscal years beginning after December 15, 2001. We are currently evaluating this guidance and which may have a material impact on our financial position or results of operations. Note 3. Regulatory Issues and Accounting Impacts of Deregulation New Jersey Energy Master Plan Proceedings and Related Orders Following the enactment of the Energy Competition Act, the BPU rendered a Final Order relating to PSE&G's rate unbundling, stranded costs and restructuring proceedings (Final Order). PSE&G, pursuant to the Final Order, transferred its electric generating facilities and wholesale power contracts to Power and its subsidiaries on August 21, 2000 in exchange for a promissory note in an amount equal to the purchase price. The generating assets were transferred at the price specified in the BPU order - $2.443 billion plus $343 million for other generation related assets and liabilities. Because the transfer was between affiliates, PSE&G and Power recorded the sale at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities was recorded as an equity adjustment on PSE&G's and Power's Consolidated Balance Sheets. These amounts are eliminated on our consolidated financial statements. Power paid the promissory note on January 31, 2001, with funds provided from us via equity contributions and loans. Also in the Final Order, the BPU concluded that PSE&G should recover up to $2.94 billion (net of tax) of its generation-related stranded costs through securitization of $2.4 billion, plus an estimated $125 million of transaction costs, and an opportunity to recover up to $540 million (net of tax) of its unsecuritized generation-related stranded costs on a net present value basis. The $540 million is subject to recovery through a market transition charge (MTC). PSE&G remits the MTC revenues to Power as part of the BGS contract as provided for by the Final Order. In September 1999, the BPU issued its order approving PSE&G's petition relating to the proposed securitization transaction (Finance Order) which authorized, among other things, the imposition of a non-bypassable transition bond charge (TBC) on PSE&G's customers; the sale of PSE&G's property right in such charge to a bankruptcy-remote financing entity; the issuance and sale of $2.525 billion of securitization bonds by such entity as consideration for such property right, including an estimated $125 million of transaction costs; and the application by PSE&G of the transition bond proceeds to retire outstanding debt and/or equity. PSE&G Transition Funding LLC (Transition Funding) issued the transition bonds on January 31, 2001; and the TBC and a 2% rate reduction became effective on February 7, 2001 in accordance with the Final Order. An additional 2% rate reduction became effective on August 1, 2001 bringing the total rate reduction to 9% since August 1, 1999. These rate reductions and the TBC were funded through the MTC rate. On January 31, 2001, $2.525 billion of securitization bonds (non-recourse asset backed securities) were issued by 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 $2.786 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 us and make various short-term investments. 78 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued In order to properly recognize the recovery of the allowed unsecuritized stranded costs over the transition period, we 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, 2001, the amount of estimated collections in excess of the allowed unsecuritized stranded costs was $168 million. Extraordinary Charge and Other Accounting Impacts of Deregulation In April 1999, PSE&G determined that SFAS 71 was no longer applicable to the electric generation portion of its business in accordance with the requirements of Emerging Issues Task Force Issue 97-4, "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and No. 101" (EITF 97-4). Accordingly, in 1999, we recorded an extraordinary charge to earnings of $804 million (after tax), consisting primarily of the write-down of PSE&G's nuclear and fossil generating stations in accordance with SFAS 121. As a result of this impairment analysis, the net book value of the generating stations was reduced by approximately $5.0 billion (pre-tax) or $3.1 billion (net of tax). This amount was offset by the creation of a $4.057 billion (pre-tax), or $2.4 billion (net of tax) regulatory asset, as provided for in the Final Order and Finance Order. In addition to the impairment of PSE&G's electric generating stations, the extraordinary charge consisted of various accounting adjustments to reflect the absence of cost of service regulation in the electric generation portion of its business. The adjustments primarily related to materials and supplies, general plant items and liabilities for certain contractual and environmental obligations. In accordance with the Final Order, PSE&G also reclassified a $569 million excess depreciation reserve related to PSE&G's electric distribution assets from Accumulated Depreciation to a Regulatory Liability. Such amount is being amortized in accordance with the terms of the Final Order over the period from January 1, 2000 to July 31, 2003. 79 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Note 4. Regulatory Assets and Liabilities At December 31, 2001 and December 31, 2000, respectively, we had deferred the following regulatory assets and liabilities on the Consolidated Balance Sheets:

December ---------------------------- 2001 2000 ------------ ----------- (Millions of Dollars) Regulatory Assets ----------------- Stranded Costs to be Recovered................................ $4,105 $4,057 SFAS 109 Income Taxes......................................... 302 285 OPEB Costs.................................................... 212 232 Societal Benefits Charges (SBC)............................... 4 135 Environmental Costs........................................... 87 13 Unamortized Loss on Reacquired Debt and Debt Expense.......... 92 104 Underrecovered Gas Costs...................................... 120 -- Unrealized Losses on Gas Contracts............................ 137 -- Non-Utility Generation Transition Charge (NTC)................ -- 7 Other......................................................... 161 162 ------------ ----------- Total Regulatory Assets................................. $5,220 $4,995 ============ =========== Regulatory Liabilities ---------------------- Excess Depreciation Reserve................................... $319 $444 Non-Utility Generation Transition Charge (NTC)................ 48 -- Overrecovered Gas Costs....................................... -- 26 Other......................................................... 6 -- ------------ ----------- Total Regulatory Liabilities............................ $373 $470 ============ ===========

Stranded Costs To Be Recovered: This reflects deferred costs to be recovered through securitization transition charge which was authorized by the Final Order and Finance Order. SFAS 109 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. OPEB 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". Prior to the adoption of SFAS 106, post-retirement benefits costs were recognized on a cash basis. SFAS 106 required that these costs be accrued as the benefits were earned. Accordingly a liability and a regulatory asset were recorded for the total benefits earned at the implementation date. Beginning January 1, 1998, we commenced the amortization of this regulatory asset over 15 years. See Note 12. Pension, Other Postretirement Benefit and Savings Plans for additional information. Societal Benefit Charges (SBC): The SBC includes costs related to PSE&G's electric transmission and distribution business as follows: 1) social programs which include the universal service fund; 2) nuclear plant decommissioning; 3) demand side management (DSM) programs; 4) manufactured gas plant remediation; 5) consumer education; 6) Under and overrecovered electric bad debt expenses; and 7) MTC overrecovery. Environmental Costs: Represents environmental investigation and remediation costs which are probable of recovery in future rates. 80 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Unamortized Loss on Reacquired Debt and Debt Expense: Represents bond issuance costs, premiums, discounts and losses on reacquired long-term debt. Underrecovered/Overrecovered Gas Costs: Represents gas costs in excess of or below the amount included in rates and probable of recovery in the future. Unrealized Losses on Gas Contracts: This represents the recoverable portion of unrealized losses associated with contracts used in the company's gas distribution business Non-utility Generation Transition Charge (NTC): This clause was established to account for above market costs related to non-utility generation contracts. The charge for the stranded NTC recovery was initially set at $183 million annually. Any NUG contract costs and/or buyouts are charged to the NTC. Proceeds from the sale of the energy and capacity purchased under these NUG contracts are also credited to this account. Other Regulatory Assets: Includes Decontamination and Decommissioning Costs, Plant and Regulatory Study Costs, Repair Allowance Tax Deficiencies and Interest, Property Abandonments and Oil and Gas Property Write-Down and recovery of costs related to Transition Funding's interest rate swap. Excess Depreciation Reserve: As required by the BPU, PSE&G reduced its depreciation reserve for its electric distribution assets by $569 million and recorded such amount as a regulatory liability to be amortized over the period from January 1, 2000 to July 31, 2003. In 2000 and 2001, $125 million was amortized. The remaining $319 million will be amortized through July 31, 2003. Other Regulatory Liabilities: This includes the following: 1) Interest on amounts collected from customers that are used to fund incentives for choosing a third party gas supplier; 2) Interest on amounts collected early from customers relating to the Transitional Energy Facility Assessment tax; and 3) Amounts collected from customers in order for Transition Funding to obtain a AAA rating on its transition bonds. Note 5. Long-Term Investments Long-Term Investments are primarily those of Energy Holdings' subsidiaries:

December 31, --------------------------- 2001 2000 ----------- ----------- (Millions of Dollars) Leveraged Leases................................................ $2,784 $2,253 Partnerships: General Partnerships....................................... 44 46 Limited Partnerships....................................... 615 479 ----------- ----------- Total................................................ 659 525 ----------- ----------- Corporate Joint Ventures........................................ 1,111 1,584 Securities...................................................... 6 6 Other Investments............................................... 258 177 ----------- ----------- Total Long-Term Investments.......................... $4,818 $4,545 =========== ===========

81 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Leveraged Leases Resources' net investment in leveraged leases is comprised of the following elements:

December 31, -------------------------------- 2001 2000 ------------ ------------ (Millions of Dollars) Lease rents receivable............................................ $3,644 $3,175 Estimated residual value of leased assets......................... 1,414 1,040 ------------ ------------ 5,058 4,215 Unearned and deferred income...................................... (2,274) (1,962) ------------ ------------ Total investments in leveraged leases........................ 2,784 2,253 Deferred taxes arising from leveraged leases...................... (1,175) (1,031) ------------ ------------ Net investment in leverage leases............................ $1,609 $1,222 ============ ============

Resources' pre-tax income and income tax effects related to investments in leveraged leases are as follows:

Years ended December 31, ------------------------------------------------------------- 2001 2000 1999 ------------------ ------------------ ----------------- (Millions of Dollars) Pre-tax income......................................... $ 206 $ 163 $ 112 ================== ================== ================= Income tax effect on pre-tax income.................... $ 62 $ 58 $ 41 Amortization of investment tax credits................. $ (1) $ (1) $ (1)

Resources, as lessor, has certain ownership rights to the property through leveraged leases, with terms ranging from 4 to 45 years. The lease investments are recorded on a net basis by summing 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. 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 liability, in the years in which the net investment is positive. Initial direct costs are deferred and amortized using the interest method over the lease period. 82 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Partnership Investments and Corporate Joint Ventures Partnership investments of approximately $615 million and corporate joint ventures of approximately $1.1 billion are those of Resources, Global and EGDC. Energy Holdings accounts for such investments under the equity method of accounting. As of December 31, 2001 Energy Holdings had approximately $1.5 billion of investments accounted for under the equity method of accounting. 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 of Dollars) December 31, 2001 Condensed Income Statement Information Revenue.................................................. $ 819 $ 473 $ 1,292 Gross Profit............................................. 317 165 482 Minority Interest........................................ (20) -- (20) Net Income............................................... 141 91 232 Condensed Balance Sheet Information Assets: Current Assets.......................................... $ 341 $ 131 $ 472 Property, Plant & Equipment............................. 1,198 1,406 2,604 Goodwill................................................ 863 50 913 Other Non-current Assets............................... 616 23 639 ----------------- -------------- ---------------- Total Assets............................................. $ 3,018 $ 1,610 $ 4,628 ----------------- -------------- ----------------

83 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued

----------------- -------------- ---------------- Liabilities: Current Liabilities..................................... $ 415 $ 109 $ 524 Debt.................................................... 761 658 1,419 Other Non Current Liabilities........................... 132 212 344 Minority Interest....................................... 25 -- 25 ----------------- -------------- ---------------- Total Liabilities........................................ 1,333 979 2,312 Equity................................................... 1,685 631 2,316 ----------------- -------------- ---------------- Total Liabilities & Equity............................... $ 3,018 $ 1,610 $ 4,628 ----------------- -------------- ---------------- Foreign Domestic Total ----------------- -------------- ---------------- (Millions of Dollars) December 31, 2000 Condensed Income Statement Information Revenue.................................................. $ 1,059 $ 452 $ 1,511 Gross Profit............................................. 434 256 690 Minority Interest........................................ (25) -- (25) Net Income............................................... 156 162 318 Condensed Balance Sheet Information Assets: Current Assets.......................................... $ 504 $ 130 $ 634 Property, Plant & Equipment............................. 2,355 1,349 3,704 Goodwill................................................ 1,201 -- 1,201 Other Non-current Assets............................... 464 77 541 ----------------- -------------- ---------------- Total Assets............................................. $ 4,524 $ 1,556 $ 6,080 ----------------- -------------- ---------------- Liabilities: Current Liabilities..................................... $ 818 $ 99 $ 917 Debt.................................................... 696 732 1,428 Other Non Current Liabilities........................... 174 90 264 Minority Interest....................................... 129 1 130 ----------------- -------------- ---------------- Total Liabilities........................................ 1,817 922 2,739 Equity................................................... 2,707 634 3,341 ----------------- -------------- ---------------- Total Liabilities & Equity............................... $ 4,524 $ 1,556 $ 6,080 ----------------- -------------- ---------------- Foreign Domestic Total ----------------- -------------- ---------------- (Millions of Dollars) December 31, 1999 Condensed Income Statement Information Revenue.................................................. $ 1,184 $ 423 $ 1,607 Gross Profit............................................. 416 265 681 Minority Interest........................................ (23) -- (23) Net Income............................................... 110 155 265

Purchase Business Combinations/Asset Acquisitions In December 2001, Global acquired Empresa de Electricidad de los Andes S.A. (Electroandes) for $227 million, subject to certain purchase price adjustments pending completion in April 2002. Electroandes is the sixth largest electric generator in Peru with a 6% market share. 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 the exclusive rights to develop a 100 MW expansion of an existing station and a 150 MW greenfield hydroelectric facility. In 2000, Electroandes generated 1,150 GWH of electrical energy, of which 97% was sold through power purchase agreements to mining companies in the region. We have not finalized the allocation of the purchase price as of December 31, 2001. An estimation of this allocation was prepared and included as part of our consolidated financial statements. The purchase price was allocated $15 million to Current Assets, $78 million to Property, Plant and Equipment, $164 million to Goodwill, and $30 million to Current Liabilities. In August 2001, Global purchased a 94% equity stake in SAESA and all of its subsidiaries from Compania de Petroleos de Chile S.A. (COPEC). The SAESA group of companies consists of four distribution companies and one transmission company that provide electric service in the southern part of Chile. Additionally, Global purchased from COPEC approximately 14% of Empresa Electrica de la Frontera S.A. (Frontel) not owned by SAESA. SAESA also owns a 50% interest in the Argentine distribution company Empresa Electrica del Rio Negro S.A. In 2001 Global spent $447 million (net of $16 million in cash acquired) to acquire a 94% interest in SAESA and a 14% interest in Frontel. In October 2001, Global completed a tender offer for an additional 6% of publicly trades SAESA shares, for approximately $25 million. We have not finalized the allocation of the purchase price as of December 31, 2001. An estimation of this allocation was prepared and included as part of our consolidated financial statements. The total purchase price of $488 million was allocated $55 million to Current Assets, $210 million to Property, Plant and Equipment, $315 million to Goodwill, $10 million to Other Non-Current Assets, $46 million to Current Liabilities, $39 million to Long-Term Debt, $17 million to Deferred Taxes and Other Non-Current Liabilities. In June 2001, Global exercised its option to acquire an additional 49% of Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), an electric distribution company providing electric service to more than 230,000 customers in the Province of Entre Rios, Argentina, bringing its total ownership of EDEERSA to 90%. The additional ownership was purchased for $110 million. An estimation of this allocation was prepared and included as part of our consolidated financial statements. The purchase price was allocated approximately $22 million to Current Assets, $114 million to Property, Plant and Equipment, $30 million to Goodwill, $15 million to Current Liabilities, and $41 million to Long-Term Debt. We have not finalized the allocation of the purchase price as of December 31, 2001. In 2000, Global acquired a 49% interest in Tanir Bavi Power Company Private Ltd., which was constructing a 220 MW barge mounted, combined-cycle generating facility located near Mangalore in the state of Karnataka, India. In January 2001, Global acquired an additional 25% interest in the project bringing its total ownership interest to 74%. In November 2001, the facility achieved full commercial operation. Power from the facility will be sold to the Karnataka Electricity Board pursuant to a seven year fixed price power purchase agreement with a five-year renewal term. Other Investments Other investments primarily include amounts related to Life Insurance, Energy Technologies investments in DSM projects. As of December 31, 2001, amounts related to such items were $108 84 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued million and $47 million, respectively. As of December 31, 2000, amounts related to such items were $89 million and $56 million, respectively. Note 6. Schedule of Consolidated Capital Stock and Other Securities

Outstanding Current Shares Redemption At December 31, Price December 31, December 31, 2001 Per Share 2001 2000 ---------------------------------- -------------- ---------------- (Millions of Dollars) PSEG Common Stock (no par) (A) Authorized 500,000,000 shares; issued and outstanding at December 31, 2001, 205,839,018 shares and at December 31, 2000, shares 207,971,318 $2,618 $2,709 PSEG Preferred Securities (B) PSEG Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures (D)(E)(G) 7.44%........................................... 9,000,000 -- $225 $225 Floating Rate................................... 150,000 -- 150 150 7.25%........................................... 6,000,000 -- 150 150 -------------- ---------------- Total Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures.................. $525 $525 ============== ================ PSE&G Preferred Securities PSE&G Cumulative Preferred Stock (C) without Mandatory Redemption (D)(E) $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 $25 par value series 6.75%........................................... -- -- -- 15 -------------- ---------------- Total Preferred Stock without Mandatory Redemption $80 $95 ============== ================ With Mandatory Redemption (D)(E) $100 par value series 5.97%........................................... -- -- $-- $75 -------------- ---------------- Total Preferred Stock with Mandatory Redemption... $-- $75 ============== ================ PSE&G Monthly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures (D)(E)(F) 9.375%.......................................... -- -- $-- $150 8.00%........................................... 2,400,000 25.00 60 60 -------------- ---------------- Total Monthly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures................. $60 $210 ============== ================ PSE&G Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures (D)(E)(F) 8.625%.......................................... -- -- $-- $208 8.125%.......................................... 3,800,000 -- 95 95 -------------- ---------------- Total Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures................. $95 $303 ============== ================

(A) Our Board of Directors authorized the repurchase of up to 30 million shares of its common stock in the open market. At December 31, 2001, we had repurchased approximately 26.5 million shares of common stock at a cost of approximately $997 million. The repurchased shares have been held as treasury stock or used for other corporate purposes. Total authorized and unissued shares include 7,302,488 shares of common stock available 85 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued for issuance through our Dividend Reinvestment and Stock Purchase Plan and various employee benefit plans. In 2001 and 2000, no shares of common stock were issued or sold through these plans. (B) We have authorized a class of 50,000,000 shares of Preferred Stock without par value, none of which is outstanding. (C) At December 31, 2001, there were an aggregate of 6,704,766 aggregates of 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. (D) At December 31, 2001 and 2000, the annual dividend requirement of our Trust Preferred Securities (Guaranteed Preferred Beneficial Interest in our Subordinated Debentures) and their embedded costs were $38,433,000 and 4.91%, respectively. At December 31, 2001 and 2000, the annual dividend requirement and embedded dividend rate for PSE&G's Preferred Stock without mandatory redemption was $10,127,383 and 5.03%, $10,886,758 and 5.18%, respectively, and for our Preferred Stock with mandatory redemption was $1,119,375 and 6.02%, $4,477,500 and 6.02%, respectively. At December 31, 2001 and 2000, the annual dividend requirement and embedded cost of the Monthly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures) was $7,768,750 and 4.90%, $18,862,500 and 5.50%, respectively. At December 31, 2001 and 2000, 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 $16,439,584 and 4.97%, $25,658,750 and 5.18%, respectively. (E) For information concerning fair value of financial instruments, see Note 8. Financial Instruments, Energy Trading and Risk Management. (F) 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. (G) Enterprise Capital Trust I, Enterprise Capital Trust II, Enterprise Capital Trust III and Enterprise Capital Trust IV were formed and are controlled by us for the purpose of issuing Quarterly Trust Preferred Securities (Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures). The proceeds were loaned to us and are evidenced by our Deferrable Interest Subordinated Debentures. If and for as long as payments on our Deferrable Interest Subordinated Debentures have been deferred, or we have defaulted on 86 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued the indentures related thereto or its guarantees thereof, PSEG may not pay any dividends on its common and preferred stock. The Subordinated Debentures constitute our full and unconditional guarantee of the Preferred Securities issued by the trusts. Note 7. Schedule of Consolidated Debt

LONG-TERM Interest Rates Maturity 2001 2000 ------------------------------------------------------ --------------------- -------------- --------------- PSEG (Millions of Dollars) ---- Extendible Notes LIBOR plus 0.40% (A) 2001................ $ -- $300 Floating Rate Notes-LIBOR plus 0.875% 2002................ 275 275 -------------- --------------- Principal Amount Outstanding (C)............................................. 275 575 Amounts Due Within One Year (D).............................................. (275) (300) -------------- --------------- Total Long-Term Debt of PSEG ......................................... $ -- $275 ============== =============== PSE&G ----- First and Refunding Mortgage Bonds (B): 7.875% 2001................ $ -- $100 6.125% 2002................ 258 258 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 Variable 2008-2012........... -- 66 6.75%-7.375% 2013-2017........... 330 330 6.45%-9.25% 2018-2022........... 139 139 Variable 2018-2022........... -- 14 5.20%-7.50% 2023-2027........... 434 434 5.45%-6.55% 2028-2032........... 499 499 Variable 2028-2032........... -- 25 5.00%-8.00% 2033-2037........... 160 160 Medium-Term Notes: 7.19% 2002................ 290 290 8.10%-8.16% 2008-2012........... 60 60 7.04% 2018-2022........... 9 9 7.15%-7.18% 2023-2027........... 39 39 -------------- --------------- Total First and Refunding Mortgage Bonds............................ 3,189 3,394 -------------- --------------- Unsecured Bonds-7.43% (L) 2002............... -- 300 Unsecured Bonds-Variable 2027............... -- 19 -------------- --------------- Total Unsecured Bonds............................................... -- 319 -------------- --------------- Principal Amount Outstanding (C)............................................. 3,189 3,713 Amounts Due Within One Year (D).............................................. (547) (100) Net Unamortized Discount..................................................... (16) (23) -------------- --------------- Total Long-Term Debt of PSE&G (E)................................... $2,626 $3,590 ============== ===============

87 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued

December 31, --------------------------------- Interest Rates Maturity 2001 2000 ------------------------------------------------------ --------------------- -------------- --------------- Transition Funding (Millions of Dollars) ------------------ Securitization Bonds (I): 5.46%................................................. 2004................ $52 -- 5.74%................................................. 2007................ 369 -- 5.98%................................................. 2008................ 183 -- LIBOR plus 0.30%...................................... 2011................ 496 -- 6.45%................................................. 2013................ 328 -- 6.61%................................................. 2015................ 454 -- 6.75%................................................. 2016................ 220 -- 6.89%................................................. 2017................ 370 -- -------------- --------------- Principal Amount Outstanding (C)............................................. 2,472 -- Amounts Due Within One Year (I).............................................. (121) -- -------------- --------------- Total Long-Term Debt of Transition Funding, LLC ...................... $2,351 -- ============== =============== Power ----- Senior Notes: 6.88%............................................... 2006................. $500 -- 7.75%............................................... 2011................. 800 -- 8.63%............................................... 2031................. 500 -- Pollution Control Bonds (J)............................ 5.00%............................................... 2012................. 66 -- 5.50%............................................... 2020................. 14 -- 5.85%............................................... 2027................. 19 -- 5.75%............................................... 2031................. 25 -- Non-recourse debt (K): Variable............................................ 2005................. 770 -- ------------ ------------ Principal Amount Outstanding (C).............................................. 2,694 -- Amounts Due Within One Year (D)............................................... -- -- Net Unamortized Discount...................................................... (9) -- -------------- --------------- Total Long-Term Debt of Power ....................................... $2,685 -- ============== ===============

88 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued

December 31, --------------------------------- Interest Rates Maturity 2001 2000 ------------------------------------------------------ --------------------- -------------- --------------- Energy Holdings (Millions of Dollars) --------------- Senior Notes: 9.125% 2004................. $300 $ 300 8.625% 2008................. 400 -- 10.00% 2009................. 400 400 8.50% 2011................. 550 -- -------------- ------------ Principal Amount Outstanding (C)............................................. 1,650 700 Net Unamortized Discount..................................................... (6) (5) -------------- ------------ $1,644 $695 -------------- ------------ PSEG Capital ------------ Medium-Term Notes (F): 6.73% - 6.74% 2001................ -- 170 3.12% - 7.72% 2002................ 228 228 6.25% 2003................ 252 252 -------------- ------------ Principal Amount Outstanding (C)............................................. 480 650 -------------- ------------- Amounts Due Within One Year (D).............................................. (228) (170) Net Unamortized Discount..................................................... -- (1) -------------- ------------- Total Long-Term Debt of PSEG Capital................................ 252 479 -------------- ------------- Global ------ Non-recourse Debt (G): 10.01% -10.385% - Bank Loan 2001................ -- 96 5.47% - 10.385 - Bank Loan 2002................ 41 64 6.64% - 9.46 - Bank Loan 2003-2019........... 711 160 14.00% - Minority Shareholder Loan 2027................ 10 10 -------------- ------------ Principal Amount Outstanding (C)............................................. 762 330 Amounts Due Within One Year (D).............................................. (41) (96) -------------- ------------- Total Long-Term Debt of Global...................................... 721 234 -------------- ------------- Resources --------- 8.60% - Bank Loan 2001-2020........... 22 24 -------------- ------------- Principal Amount Outstanding (C)............................................. 22 24 Amounts Due Within One Year (D).............................................. (1) (1) -------------- ------------- Total Long-Term Debt of Resources................................... 21 23 -------------- ------------- Energy Technologies ------------------- 2.90% - 11.65% Various Loans 2002-2005........... 1 1 -------------- ------------- Total Long-Term Debt of Energy Technologies......................... 1 1 -------------- ------------- Total Long-Term Debt of Energy Holdings........................ 2,639 1,432 ============== ============= Consolidated Long-Term Debt (H)............................ $10,301 $5,297 ============== =============

89 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued (A) In June 1999, we issued $300 million of Extendible Notes, Series C, due June 15, 2001. At December 31, 2000, the interest rate on Series C was 6.955%. These Extendible Notes were repurchased in 2001 and are no longer outstanding. In November 2000, we issued $275 million of Floating Rate Notes due May 21, 2002 with an interest rate is at three-month LIBOR, plus 0.875%. (B) PSE&G's First and Refunding Mortgage (Mortgage), securing the Bonds, constitutes a direct first mortgage lien on substantially all of PSE&G's property and franchises. (C) For information concerning fair value of financial instruments, see Note 8. Financial Instruments Energy Trading and Risk Management. (D) The aggregate principal amounts of mandatory requirements for sinking funds and maturities for each of the five years following December 31, 2001 are as follows:

Transition PSEG Energy PSEG Year PSEG PSE&G Funding Power Holdings Capital Global Resources Total ------ -------- -------- ----------- ------- ---------- -------- ------- -------- -------- 2002 275 547 -- -- -- 228 41 1 1,092 2003 -- 300 -- -- -- 252 56 1 609 2004 -- 286 52 -- 300 -- 116 1 755 2005 -- 125 -- 770 -- -- 39 1 935 2006 147 -- 500 -- -- 39 1 687 -------- -------- ----------- ------- ---------- -------- ------- -------- -------- 275 1,405 52 1,270 300 480 291 5 4,078 ======== ======== =========== ======= ========== ======== ======= ======== ========

(E) At December 31, 2001 and 2000, PSE&G's annual interest requirement on long-term debt was $220 million and $256 million, of which $220 million and $233 million, respectively, was the requirement for Mortgage Bonds. The embedded interest cost on long-term debt on such dates was 7.46% and 7.30%, respectively. The embedded interest cost on long-term debt due within one year at December 31, 2001 was 6.76%. (F) PSEG Capital has provided up to $750 million debt financing for Energy Holdings' businesses, except Energy Technologies, on the basis of a net worth maintenance agreement with PSEG. Since 1995, PSEG Capital has limited its borrowings to no more than $650 million. (G) Global's projects are generally financed with non-recourse debt at the project level, with the balance in the form of equity investments by the sponsors in the project. The non-recourse debt shown in the above table is that of consolidated subsidiaries which have equity investments in distribution facilities in Argentina, Chile and Peru and generation facilities under construction in Poland and Tunisia. Global's capital at risk on the projects is limited to its original investment. (H) At December 31, 2001 and 2000, our annual interest requirement on long-term debt was $645 million and $440 million. The embedded interest cost on long-term debt on such dates was 7.83% and 7.66%, respectively. (I) At January 31, 2001, Transition Funding issued $2.525 billion of Bonds in eight classes with estimated final payment dates from one year to fifteen years. The net proceeds were remitted to PSE&G as consideration for the property right in the TBC. At December 31, 2001, Transition Funding annual interest requirement on securitization bonds was $148 million. The current portion of Transition Funding's debt is based on estimated payment dates, with final estimated payment dates at two years earlier than the final maturity dates for each respective class of Bonds. At December 31, 2001, Transition Funding's annual interest requirement on its Bonds was $137 million. 90 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued (J) At November 20, 2001 & December 5, 2001, Power issued $124 million of Pollution Control Notes in four classes with maturities ranging from 11 years to 30 years. (K) In August 2001, subsidiaries of Power closed with a group of banks on $800 million of non-recourse project financing for projects in Waterford, Ohio and Lawrenceburg, Indiana. The Waterford project will be completed in two phases and will increase Power's capacity by 850 MW. The first phase and second phase of the project are expected to achieve commercial operation in June 2002 and May 2003, respectively. The Lawrenceburg project will increase Power's capacity by 1,150 MW and is expected to achieve commercial operation by May 2003. The total combined project cost for Waterford and Lawrenceburg is estimated at $1.2 billion. Power's required estimated equity investment in these projects is approximately $400 million. In connection with these projects, ER&T has entered into a tolling agreement pursuant to which it is obligated to purchase the output of these facilities at stated prices. As a result, ER&T bears the price risk related to the output of these generation facilities. (L) On December 7, 2000, PSE&G issued $300 million of Floating Rate Notes at 7.4275%, due December 7, 2002. The proceeds were used for general corporate purposes including the repayment of short-term debt. These notes were repurchased during 2001. SHORT-TERM DEBT At December 31, 2001, we and Energy Holdings had a $753 million and $585 million of short-term debt as detailed below. As of December 31, 2001 the weighted-average short-term debt rates for us and Energy Holdings were 2.8% and 3.3%, respectively.

Commercial Maturity Total Primary Amount Paper (Cp) Company Date Facility Purpose Outstanding Outstanding ------------------------------------------- -------- -------- ------- ----------- ----------- (MILLIONS OF DOLLARS) PSEG ------------------------------------------- 364-day Credit Facility March 2002 $570 CP Support $ -- $475 5-year Credit Facility March 2002 280 CP Support -- N/A 5-year Credit Facility December 2002 150 Funding 125 N/A Bilateral Credit Agreement N/A No Limit Funding 153 N/A PSE&G ------------------------------------------- 364-day Credit Facility June 2002 390 CP Support -- -- 5-year Credit Facility June 2002 450 CP Support -- -- Bilateral Credit Agreement June 2002 60 CP Support -- -- Bilateral Credit Agreement N/A No Limit Funding -- N/A Energy Holdings ------------------------------------------- 364-day Credit Facility May 2002 200 Funding -- N/A 5-year Credit Facility May 2004 495 Funding 250 N/A Bilateral Credit Agreement N/A 100 Funding 50 N/A ---- ---- Total N/A $578 $475 ==== ====

91 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Note 8. Financial Instruments, Energy Trading and Risk Management Our operations are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could affect results of operations and financial conditions. We manage our exposure to these market risks through our regular operating and financing activities and, when deemed appropriate, hedge these risks through the use of derivative financial instruments. We use the term hedge to mean a strategy designed to manage risks of volatility in prices or rate movements on certain assets, liabilities or anticipated transactions and by creating a relationship in which gains or losses on derivative instruments are expected to counterbalance the losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. We use derivative instruments as risk management tools consistent with our business plans and prudent business practices and for energy trading purposes. 92 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Fair Value of Financial Instruments The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions at December 31, 2001 and December 31, 2000, respectively.

December 31, 2001 December 31, 2000 ------------------------- --------------------------- Carrying Fair Carrying Fair Amount Value Amount Value ------------ ----------- ------------ ----------- (Millions of Dollars) Long-Term Debt (A): PSEG.................................................. $275 $275 $575 $575 Energy Holdings....................................... 2,909 2,971 1,699 1,725 PSE&G................................................. 3,173 3,290 3,690 3,453 Transition Funding.................................... 2,472 2,575 -- -- Power................................................. 2,685 2,835 -- -- Preferred Securities Subject to Mandatory Redemption: PSE&G Cumulative Preferred Securities................. -- -- 75 60 Monthly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures.................... 60 60 210 212 Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures.................... 95 96 303 304 Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures..................... 525 520 525 474

(A) Includes current maturities. At December 31, 2001 we, Energy Holdings, Power and Transition Funding had interest rate swap agreements outstanding with notional amounts up to $150 million, $599 million, $178 million and $497 million, respectively. For additional information concerning consolidated debt, see Note 7. Schedule of Consolidated Debt. For additional information concerning preferred securities, see Note 6. Schedule of Consolidated Capital Stock and Other Securities. Global had $1.048 billion of project debt that is non-recourse to PSEG, Energy Holdings and Global associated with investments in Argentina, India, Chile, Peru Oman, Poland and Tunisia. Energy Trading Effective January 1, 1999, we adopted EITF 98-10, which requires that energy trading contracts be recognized on the balance sheet at fair value with resulting realized and unrealized gains and losses included in current earnings. In 2001 we recorded $147 million of gains from our Energy Trading segment, including realized gains of $169 million and unrealized losses of $22 million. In 2000 we recorded gains of $77 million, including $22 million of realized gains and $55 million of unrealized gains and in 1999 recorded gains of $42 million, including $37 million of realized gains and $5 million of unrealized gains. Net of broker fees and other trading related expenses, our energy trading business earned margins of $140 million, $72 million and $39 million for the years ended December 31, 2001, 2000 and 1999, respectively. As of December 31, 2001, we had a total of $9 million of unrealized gains on our balance sheet, over 90% of which related to contracts with terms of less than two years. [Chart to Come] 93 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued We engage in physical and financial transactions in the electricity wholesale markets and execute an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. We actively trade energy, capacity, fixed transmission rights and emissions allowances in the spot, forward and futures markets primarily in PJM, but also throughout the Super Region. We are also involved in the financial transactions that include swaps, options and futures in the electricity markets. The fair values as of December 31, 2001 and December 31, 2000 and the average fair values for the periods then ended of our financial instruments related to the energy commodities in the energy trading segment are summarized in the following table:

December 31, 2001 December 31, 2000 ----------------------------------------- --------------------------------------------- Notional Notional Fair Average Notional Notional Fair Average (mWh) (MMBTU) Value Fair Value (mWh) (MMBTU) Value Fair Value ------------------------------ ---------- ----------------------- --------------------- (Millions) (Millions) Futures and Options NYMEX .. -- 16.0 $(1.2) $(2.0) 17.0 167.0 $5.7 $(1.4) Physical forwards........... 41.0 9.0 $(2.6) $12.1 50.0 10.0 $13.5 $13.6 Options-- OTC............... 8.0 803.0 $(19.4) $18.5 12.0 437.0 $184.2 $68.0 Swaps....................... -- 1,131.0 $23.9 $2.3 -- 218.0 $(137.8) $(42.5) Emission Allowances......... -- -- $8.3 $23.8 -- -- $6.0 $9.5

We routinely enter into exchange traded futures and options transactions for electricity and natural gas as part of our energy trading operations. Generally, exchange-traded futures contracts require deposit of margin cash, the amount of which is subject to change based on market movement in exchange rules. The amount of the margin deposits as of December 31, 2001 and 2000 were approximately $2.6 million and $1 million, respectively. Derivative Instruments and Hedging Activities Commodity Contracts During 2001, Power entered into electric physical forward contracts and gas futures and swaps with a maximum term of approximately one year, to hedge our forecasted BGS requirements and gas purchases requirements for generation. These transactions qualified for hedge accounting treatment under SFAS 133 and were settled prior to the end of 2001. The majority of the marked-to-market valuations were reclassified from OCI to earnings during the quarter ended September 30, 2001. As of December 31, 2001, we did not have any outstanding derivatives accounted for under this methodology. However, there was substantial activity during the year ended December 31, 2001. In 2001, the values of these forward contracts, gas futures and swaps as of June 30 and September 30 were $(34.2) million and $(0.4) million. Also as of December 31, 2001, PSE&G had entered into 330 MMBTU of gas futures, options and swaps to hedge forecasted requirements. As of December 31, 2001, the fair value of those instruments was $(137) million with a maximum term of approximately one year. PSE&G utilizes derivatives to hedge its gas purchasing activities which, when realized, are recoverable through its Levelized Gas Adjustment Clause (LGAC). Accordingly, these commodity contracts are recognized at fair value as derivative assets or liabilities on the balance sheet and the offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. 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 94 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued reduce price risk caused by market fluctuations, we enter into derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge our anticipated demand. These contracts, in conjunction with owned electric generation capacity, are designed to cover estimated electric customer commitments. We use a value-at-risk (VAR) model to assess the market risk of our commodity business. This model includes fixed price sales commitments, owned generation, native load requirements, physical contracts and financial derivative instruments. VAR represents the potential gains or losses for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. PSEG estimates VAR across its commodity business using a model with historical volatilities and correlations. The Risk Management Committee (RMC) established a VAR threshold of $25 million. If this threshold was reached, the RMC would be notified and the portfolio would be closely monitored to reduce risk and potential adverse movements. In anticipation of the completion of the current BGS contract with PSE&G on July 31, 2002, the VAR threshold was increased to $75 million. The measured VAR using a variance/co-variance model with a 95% confidence level and assuming a one-week time horizon as of December 31, 2001 was approximately $18 million, compared to the December 31, 2000 level of $19 million. This estimate, however, is not necessarily indicative of actual results, which may differ due to the fact that actual market rate fluctuations may differ from forecasted fluctuations and due to the fact that the portfolio of hedging instruments may change over the holding period and due to certain assumptions embedded in the calculation. Interest Rates PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. Their 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. As of December 31, 2001, a hypothetical 10% change in market interest rates would result in a $3 million, $4 million, and $2 million, change in annual interest costs related to short-term and floating rate debt at PSEG, PSE&G, and Energy Holdings, respectively. The following table shows details of the interest rate swaps at PSEG, PSE&G, Power and Energy Holdings and their associated values that are still open at December 31, 2001:

Total Fair Other Project Notional Pay Receive Market Comprehensive Underlying Securities Percent Amount Rate Rate Value Income ------------------------------------------------------------------------------------------------------------------- PSEG: Enterprise Capital Trust II 100% $150.0 5.975% 3-month LIBOR $(5.1) $(3.0) Securities PSE&G: Transition Funding Bonds 100% $497.0 6.287% 3-month LIBOR $(18.5) $ - Power: Construction Loan - Waterford 100% $177.5 4.23% 3-month LIBOR $2.3 $1.3

95 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued

Total Fair Other Project Notional Pay Receive Market Comprehensive Underlying Securities % Amount Rate Rate Value Income ---------------------------------------------------------------------------------------------------------------- Energy Holdings: Construction Loan - Tunisia (US$) 60% $60.0 6.9% 3-month LIBOR $(4.4) $(1.7) Construction Loan - Tunisia (EURO) 60% $67.2 5.2% 3-month EURIBOR* $(1.5) $(0.6) Construction Loan - Poland (US$) 55% $85.0 8.4% 3-month LIBOR $(30.1) $(8.5) Construction Loan - Poland (PLN) 55% $37.6 13.2% 3-month WIBOR** $(21.9) $(9.3) Construction Loan - Oman 81% $18.2 6.3% 3-month LIBOR $(3.3) $(1.7) Construction Loan - Kalaeloa 50% $57.3 6.6% 3-month LIBOR $(1.8) $(1.2) Construction Loan - Guadalupe 50% $126.8 6.57% 3-month LIBOR $(4.1) $(2.7) Construction Loan - Odessa 50% $138.3 7.39% 3-month LIBOR $(6.0) $(3.9) ----------- ---------- -------------- -------------------------- Total Energy Holdings $590.4 $(73.1) $(29.6) ----------- ---------- -------------- -------------------------- Total PSEG $1,414.9 $(94.4) $(31.3) =========== ========== ============== ==========================

* EURIBOR - EURO Area Inter-Bank Offered Rate ** WIBOR - Warsaw Inter-Bank Offered Rate We expect to reclass approximately $14.0 million of open interest rate swaps from OCI to earnings during the next twelve months. As of December 31, 2001, there was a $31.3 million balance remaining in the Accumulated Other Comprehensive Loss Account, as indicated in the table above. We have also entered into several interest rate swaps that were closed out during 2001 and are being amortized to earnings over the life of the underlying debt. These items, along with their current and anticipated effect on earnings discussed. In February 2001, we entered into various forward-interest rate swaps, with an aggregate notional amount of $400 million, to hedge the interest rate risk related to the anticipated issuance of debt. On April 11, 2001, Power issued $1.8 billion in fixed-rate Senior Notes and closed out the forward starting interest rate swaps. The aggregate loss, net of tax, of $3.2 million was classified as Accumulated Other Comprehensive Loss and is being amortized and charged to interest expense over the life of the debt. During the year ended December 31, 2001, approximately $0.6 million was reclassified from OCI to earnings. Management expects it will amortize approximately $0.8 million from OCI to earnings during the next twelve months. In March 2001, $160 million of non-recourse bank debt originally incurred to fund a portion of the purchase price of Global's interest in Chilquinta Energia, S.A. was refinanced. The private placement offering by Chilquinta Energia Finance Co. LLC, a Global affiliate, of senior notes was structured in two tranches: $60 million due 2008 at 96 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued an interest rate of 6.47% and $100 million due 2011 at an interest rate of 6.62%. An extraordinary loss of $2 million (after-tax) was recorded in connection with the refinancing of the $160 million non-recourse bank debt. Equity Securities 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. The aggregate fair values of such investments, which had quoted market prices at December 31, 2001 and December 31, 2000 were $34 million and $115 million, respectively. The potential change in fair value resulting from a hypothetical 10% change in quoted market prices of these investments amounted to $3 million and $9 million at December 31, 2001 and December 31, 2000, respectively. Foreign Currencies The objective of our foreign currency risk management policy is to preserve the economic value of cash flows in non-functional currencies. Toward this end, Holdings' policy is to hedge all significant firmly committed cash flows identified as creating foreign currency exposure. In addition, we typically hedge a portion of exposure resulting from identified anticipated cash flows, providing the flexibility to deal with the variability of longer-term forecasts as well as changing market conditions, in which the cost of hedging may be excessive relative to the level of risk involved. As of December 31, 2001, Global and Resources had assets located or held in international locations of approximately $3.4 billion and $1.3 billion, respectively. Resources' international investments are primarily leveraged leases of assets located in Australia, Austria, Belgium, China, Germany, the Netherlands, the United Kingdom, and New Zealand with associated revenues denominated in United States Dollars ($US) and therefore, not subject to foreign currency risk. Global's international investments are primarily in companies that generate or distribute electricity in Argentina, Brazil, Chile, China, India, Italy, Oman, Peru, Poland, Taiwan, Tunisia and Venezuela. Investing in foreign countries involves certain additional risks. Economic conditions that result in higher comparative rates of inflation in foreign countries are likely to result in declining values in such countries' currencies. As currencies fluctuate against the $US, there is a corresponding change in Global's investment value in terms of the $US. Such change is reflected as an increase or decrease in the investment value and Other Comprehensive Income (Loss), a separate component of Stockholder's Equity. As of December 31, 2001, net foreign currency devaluations have reduced the reported amount of Energy Holdings' total Stockholder's Equity by $258 million (after-tax), of which $79 million (after-tax) was caused by the devaluation of the Chilean Peso and $169 million (after-tax) was caused by the devaluation of the Brazilian Real. Global holds a 60% ownership interest in a Tunisian generation facility under construction. The Power Purchase Agreement, signed in 1999, contains an embedded derivative that indexes the fixed Tunisian dinar payments to United States Dollar exchange rates. The embedded derivative is being marked to market through the income statement. As of 97 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued January 1, 2001, a $9 million gain was recorded in the cumulative effect of accounting change for SFAS No. 133. During 2001, an additional gain of $1.4 million was recorded to the income statement as a result of favorable movements in the United States Dollar to Tunisian dinar exchange rate. Global holds approximately a 32% ownership interest in RGE, a Brazilian distribution company whose debt is denominated in United States Dollars. In December 2001, the distribution company entered into a series of three forward exchange contracts to purchase United States Dollars for Brazilian Reals in order to hedge the risk of fluctuations in the exchange rate between the two currencies associated with the upcoming principal payments on the debt. These contracts expire in May, June and July 2002. As of December 31, 2001, Global's share of the fair value and aggregate notional value of the contracts was approximately $13 million. These contracts were established as hedges for accounting purposes resulting in an after tax charge to Other Comprehensive Income (OCI) of approximately $1.2 million. In addition, in order to hedge the foreign currency exposure associated with the outstanding portion of the debt, Global entered into a forward exchange contract in December 2001 to purchase United States Dollars for Brazilian Reals in approximately their share of the total debt outstanding ($61 million). The contract expired prior to December 31, 2001 and was not designated as a hedge for accounting purposes. As a result of unfavorable movements in the United States Dollars to Brazilian Real exchange rates, a loss of $4 million, after-tax was recorded related to this derivative upon maturity of the contract. This amount was recorded in Other Income. Through its 50% joint venture, Meiya Power Company, Global holds a 17.5% ownership interest in a Taiwanese generation project under construction where the construction contractor's fees, payable in installments through July 2003, are payable in Euros. To manage the risk of foreign exchange rate fluctuations associated with these payments, the project entered into a series of forward exchange contracts to purchase Euros in exchange for Taiwanese dollars. As of December 31, 2001, Global's share of the fair value and aggregate notional value of these forward exchange contracts was approximately $1 million and $16 million, respectively. These forward exchange contracts were not designated as hedges for accounting purposes, resulting in an after-tax gain of approximately $0.5 million. In addition, after-tax gains of $1 million were recorded during 2001 on similar forward exchange contracts expiring during the year. During 2001, Global purchased approximately 100% of a Chilean distribution company. In order to hedge final Chilean peso denominated payments required to be made on the acquisition, Global entered into a forward exchange contract to purchase Chilean Pesos for United States Dollars. This transaction did not qualify for hedge accounting, and, as such, upon settlement of the transaction, Global recognized an after-tax loss of $0.5 million. Furthermore, as a requirement to obtain certain debt financing necessary to fund the acquisition, and in order to hedge against fluctuations in the United States Dollars to Chilean Peso foreign exchange rates, Global entered into a forward contract with a notional value of $150 million to exchange Chilean Pesos for United States Dollars. This transaction expires in October 2002 and is considered a hedge for accounting purposes. As of December 31, 2001, the derivative asset value of $4 million has been recorded to OCI, net of taxes ($1.4 million). In addition, Global holds a 50% interest in another Chilean distribution company, which was anticipating paying its U.S. investors a return of capital. In order to hedge the risk of fluctuations in the Chilean peso to U.S. dollar exchange rate, the distribution company entered into a forward exchange contract to purchase United States Dollars for Chilean Pesos. Global's after-tax share of the loss on settlement of this transaction (recorded by the distribution company) was $0.3 million. In January 2002, RGE entered into a series of nine cross currency interest rate swaps for the purpose of hedging its exposure to fluctuations in the Brazilian Real to United States Dollars exchange rates with respect to its United States Dollars denominated debt principal payments due in 2003 through 2006. The instruments convert the variable LIBOR based interest payments on the loan balance to variable CDI based interest payments. CDI is the Brazilian interbank interest rate. As a result, the distribution company has hedged its foreign currency exposure but is still at risk for variability in the Brazilian CDI interest rate during the terms of the instruments. Global's share of the notional value of the instruments is approximately $15 million for the instruments maturing in May, June and July of 98 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued 2003 through 2005 and approximately $19 million for the instruments maturing in May, June and July 2006. Also in January 2002, the distribution company entered into two similar cross currency interest rate swaps to hedge the United States Dollars denominated interest payments due on the debt in February 2002 and May 2002. Global's share of the notional value of these two instruments is approximately $3 million each. Credit Risk Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we 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. As a result of the BGS auction, Power has contracted to provide generating capacity to the direct suppliers of New Jersey electric utilities, including PSE&G, commencing August 1, 2002. These bilateral contracts are subject to credit risk. This credit risk relates to the ability of counterparties to meet their payment obligations for the power delivered under each BGS contract. This risk is substantially higher than the risk associated with potential nonpayment by PSE&G under the BGS contract expiring July 31, 2002. Any failure to collect these payments under the new BGS contracts could have a material impact on our results of operations, cash flows, and financial position. In December 2001, Enron Corp. (Enron) filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Power had entered into a variety of energy trading contracts with Enron and its affiliates in the Pennsylvania-New Jersey-Maryland Power Pool (PJM) area as part of its energy trading activities. We took proper steps to mitigate our exposures to both Enron and other counterparties who could have been affected by Enron. As of December 31, 2001, we owed Enron approximately $23 million, net, and Enron held a letter of credit from Power for approximately $40 million. As a result of the California Energy Crisis, Pacific Gas Electric Company (PG&E) filed for protection under Chapter 11 of the US Bankruptcy Code on April 16, 2001. GWP, Hanford and Tracy had combined pre-petition receivables due from PG&E, for all plants amounting to approximately $62 million. Of this amount, approximately $25 million had been reserved as an allowance for doubtful accounts resulting in a net receivable balance of approximately $37 million. Global's pro-rata share of this gross receivable and net receivable was approximately $30 million and $18 million, respectively. In December 2001, GWF, Hanford and Tracy reached an agreement with PG&E which stipulates that PG&E will make full payment of the $62 million in 12 equal installments, including interest by the end of 2002. On December 31, 2001, PG&E paid GWF $8 million, repesenting the initial installment payment and all accrued interest due, pursuant to the agreement. As of December 31, 2001, GWF, Hanford and Tracy still had combined pre-petition receivables due from PG&E for all plants amounting to approximately $57 million. Global's pro-rata share of this receivable was $27 million. As a result of this agreement, GWF, Hanford and Tracy reversed the reserve of $25 million which increased operating income by $25 million (of which Global's share was $11 million). 99 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Note 9. Commitments and Contingent Liabilities Nuclear Insurance Coverages and Assessments Our insurance coverages and maximum retrospective assessments for its nuclear operations are as follows:

Total Site Power Type and Source of Coverages Coverage Assessments ------------------------------------------------------- -------------------- ------------------ (Millions of Dollars) Public and Nuclear Worker Liability (Primary Layer): American Nuclear Insurers...................... $200.0 (A) $10.7 Nuclear Liability (Excess Layer): Price-Anderson Act............................. 9,338.1 (B) 277.3 -------------------- ------------------ Nuclear Liability Total.................. $9,538.1 (C) $288.0 ==================== ================== Property Damage (Primary Layer): Nuclear Electric Insurance Limited (NEIL) Primary (Salem/Hope Creek/Peach Bottom)....................... $500.0 $19.3 Property Damage (Excess Layers): NEIL II (Salem/Hope Creek/Peach Bottom)........ 1,250.0 13.2 NEIL Blanket Excess (Salem/Hope Creek/Peach Bottom)............. 1,000.0 (D) 2.1 -------------------- ------------------ Property Damage Total (Per Site)............... $2,750.0 (E) $34.6 ==================== ================== Accidental Outage: NEIL I (Peach Bottom).......................... $245.0 (F) $6.0 NEIL I (Salem)................................. 281.3 7.7 NEIL I (Hope Creek)............................ 490.0 4.9 -------------------- ------------------ Replacement Power Total ................. $1,016.3 $18.6 ==================== ==================

(A) The primary limit for Public Liability is a per site aggregate limit with no potential for assessment. The Nuclear Worker Liability represents the potential liability from workers claiming exposure to the hazard of nuclear radiation. This coverage is subject to an industry aggregate limit, includes annual automatic reinstatement if the Industry Credit Rating Plan (ICRP) Reserve Fund exceeds $400 million, and has an assessment potential under former canceled policies. (B) Retrospective premium program under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. Nuclear is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the United States. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of August 20, 1998. This retrospective program is in excess 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 $1.75 billion, we participate in a Blanket Limit policy where the $1 billion limit is shared by Amergen, Exelon, and us among the Clinton, 100 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Oyster Creek, TMI-1, Peach Bottom, Salem and Hope Creek sites. This limit is not subject to reinstatement in the event of a loss. Participation in this program significantly reduces our premium and the associated potential assessment. (E) Effective January 1, 2002, NEIL II coverage was reduced to $600 million. (F) Peach Bottom has an aggregate indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Salem has an aggregate indemnity limit based on a weekly indemnity of 2.5 million for 52 weeks followed by 80% of the weekly indemnity for 75 weeks. Hope Creek has an aggregate indemnity limit based on a weekly indemnity of $3.5 million for 52 weeks followed by 80% of the weekly indemnity for 110 weeks. The Price-Anderson Act sets the "limit of liability" for claims that could arise from an incident involving any licensed nuclear facility in the nation. The "limit of liability" is based on the number of licensed nuclear reactors and is adjusted at least every five years based on the Consumer Price Index. The current "limit of liability" is $9.5 billion. All utilities owning a nuclear reactor, including us, have provided for this exposure through a combination of private insurance and mandatory participation in a financial protection pool as established by the Price-Anderson Act. Under the Price-Anderson Act, each party with an ownership interest in a nuclear reactor can be assessed its share of $88.1 million per reactor per incident, payable at $10 million per reactor per incident per year. If the damages exceed the "limit of liability," the President is to submit to Congress a plan for providing additional compensation to the injured parties. Congress could impose further revenue raising measures on the nuclear industry to pay claims. PSEG Nuclear's LLC maximum aggregate assessment per incident is $277.3 million (based on our ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $31.5 million. This does not include the $10.7 million that could be assessed under the nuclear worker policies. Further, a decision by the U.S. Supreme Court, not involving us, has held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damages. We are a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL). NEIL provides the primary property and decontamination liability insurance at Salem/Hope Creek and Peach Bottom. NEIL also provides excess property insurance through its decontamination liability, decommissioning liability, and excess property policy and replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in case of adverse loss experience. Our maximum potential liabilities under these assessments are included in the table and notes above. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on a site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down. Guaranteed Obligations Power has guaranteed certain energy trading contracts of ER&T. As of December 31, 2001 Power has issued or primarily executed $506 million of guarantees on behalf of ER&T, of which Power's exposure is $153 million. We, Energy Holdings or Global have guaranteed certain obligations of Global's affiliates, including the successful completion, performance or other obligations related to certain of the projects, in an aggregate amount of approximately $230 million as of December 31, 2001. A substantial portion of such guarantees is eliminated upon successful completion, performance and/or refinancing of construction debt with non-recourse project debt. 101 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued 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 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 and predecessor companies owned and/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. We do 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. PSE&G Manufactured Gas Plant Remediation Program PSE&G is currently working with NJDEP under a program (Remediation Program) to assess, investigate and, if necessary, remediate environmental conditions at PSE&G's former manufactured gas plant 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. Net of insurance recoveries, costs incurred from January 1, 2001 through December 31, 2001 for the Remediation Program amounted to approximately $22.8 million. Net of insurance recoveries, costs incurred through December 31, 2001 for the Remediation Program amounted to $164.6 million. In addition, at December 31, 2001, PSE&G's estimated liability for remediation costs through 2004 aggregated $87 million. Expenditures beyond 2004 cannot be reasonably estimated. Passaic River Site The EPA has determined that a six mile stretch of the Passaic River in Newark, New Jersey is a "facility" within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and that, to date, at least thirteen corporations, including PSE&G, may be potentially liable for performing required remedial actions to address potential environmental pollution at the Passaic River "facility." PSE&G and certain of its predecessors operated industrial facilities at properties within the Passaic River "facility," comprised of four former manufactured gas plants (MGP), one operating electric generating station and one former generating station. Costs to clean up former MGPs are recoverable from utility customers under the SBC. The operating station has been transferred to Power, which is responsible for its clean up. We cannot predict what action, if any, the EPA or any third party may take against PSE&G and Power with respect to these matters, or in such event, what costs PSE&G and Power may incur to address any such claims. However, such costs may be material. Prevention of Significant Deterioration (PSD)/New Source Review The EPA and NJDEP issued a demand in March 2000 under section 114 of the Federal Clean Air Act (CAA) requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal burning units were implemented in accordance with applicable PSD/New Source Review regulations. We completed our response to the section 114 information request in November 2000. In January 2002, we reached an agreement with the state 102 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued and federal governments to resolve allegations of noncompliance with federal and State of New Jersey New Source Review (NSR) regulations. Under that agreement, we will install advanced air pollution controls over 10 years that will dramatically reduce emissions of NOx, SO2, particulate matter, and mercury from the Hudson and Mercer coal units. The estimated cost of the program is $337 million. We also will pay a $1.4 million civil penalty and spend up to $6 million on supplemental environmental projects. The EPA had also asserted that PSD requirements are applicable to Bergen 2, such that we were required to have obtained a permit before beginning actual on-site construction. We disputed that PSD requirements were applicable to Bergen 2. The agreement resolving the NSR allegations concerning Hudson and Mercer also resolved the dispute over Bergen 2, and allowed construction of the unit to be completed and operation to commence. New Generation and Development Power PSEG Power New York Inc., an indirect subsidiary of Power, is in the process developing the Bethlehem Energy Center, a 750 MW combined-cycle power plant that will replace the 400 MW Albany Steam Station, which was acquired from Niagara Mohawk Power Corporation (Niagara Mohawk) in May 2000. Pending a final project certification decision that is expected within 12 months, Power will be obligated to pay Niagara Mohawk up to $9 million if it redevelops the Albany Station. However, Power expects this payment will be reduced based on conditions related to the service date and regulatory requirements. Power is constructing a 546 MW natural gas-fired, combined cycle electric generation plant at Bergen Generation Station at a cost of approximately $290 million with completion expected in June 2002. Power is also constructing an 1,218 MW combined cycle generation plant at Linden for approximately $590 million expected to be completed in May 2003. In August 2001, subsidiaries of Power closed with a group of banks on non-recourse project financing for projects in Waterford, Ohio and Lawrenceburg, Indiana. The Waterford project will be completed in two phases and are expected to achieve commercial operation in June 2002 and May 2003, respectively. The Lawrenceburg project is expected to achieve commercial operation by May 2003. The total combined project cost for Waterford and Lawrenceburg is estimated at $1.2 billion. Power's required estimated equity investments for these projects is approximately $400 million. In connection with these projects, ER&T has entered into a five-year tolling agreement pursuant to which it is obligated to purchase the output of these facilities at stated prices. As a result, ER&T will bear the price risk related to the output of these generation facilities which are scheduled to be completed in 2003. Power has filed an application with the New York State Public Service Commission for permission to construct and operate a direct generator lead (dedicated transmission line) that would deliver up to 1,200 MW of electricity to the West Side of Manhattan from the Bergen Generating Station. Applications for New Jersey and Federal approvals are expected to be filed in the near future. Estimated costs are not expected to exceed $100 million for one 500 MW line. In addition, Power has other commitments to purchase equipment and services to meet its current plans to develop additional generating capacity. The aggregate amount due under these commitments is approximately $ 500 million. Energy Holdings 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. The project commenced construction in September 103 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued 2001 and is expected to achieve commercial operation by March 2003. Total project cost is estimated at $277 million. Global's equity investment, including contingencies, is expected to be approximately $82 million. In May 2001, GWF Energy LLC (GWF Energy), a 50/50 joint venture between Global and Harbinger GWF LLC, entered into a 10-year power purchase agreement with the California Department of Water Resources to provide 340 MW of electric capacity to California from three new natural gas-fired peaker plants that GWF Energy expects to build and operate in California. Total project cost is estimated at $325 million. The first plant, a 90 MW facility, was completed and began operation in August 2001. Global's permanent equity investment in these plants, including contingencies, is not expected to exceed $100 million after completion of project financing, expected to occur in 2002. On February 25, 2002 the Public Utilities Commission of the State of California (CPUC) filed a complaint with the Federal Energy Regulatory Commission (FERC) under Section 206 of the Federal Power Act against sellers who, pursuant to long-term, FERC authorized contracts, provide power to the California Division of Water Resources (DWR). GWF Energy LLC, an affiliate of PSEG Global, as a long-term contract to sell wholesale power to the DWR and is a named respondent in this proceeding. The CPUC's complaint, which addresses 44 transactions embodied in 32 contracts with 22 sellers, alleges that collectively, the specified long term wholesale power contracts are priced at unjust and unreasonable levels and requests FERC to abrogate the contracts to enable the State to obtain replacement contracts as necessary or in the alternative, to reform the contracts to provide for just and reasonable pricing, reduce the length of the contracts, and strike from the contracts the specific non-price and conditions found to be unjust and unreasonable. In the event of an adverse ruling by the FERC, Energy Holdings and Global would reconsider any plans to invest in generation facilities in California. As of December 31, 2001, Global had $281 million invested in two 1000 MW gas-fired combined cycle electric generating facilities in Texas, including approximately $165 million of notes receivable earning an annual rate of 12%. Of the $165 million outstanding at December 31, 2001, $88 million was repaid in February 2002. Texas Independent Energy's (TIE) funding for these payments to Global were made from equity contributions of $44 million from Global and $44 million from Panda Energy, our partner for this project. Earnings and cash distributions from TIE during 2001 were $15 million and $25 million, respectively, below expectations due to lower energy prices resulting from the over-supply of energy in the Texas power market and mild summer temperatures surpressing demand in the region. Global expects this trend 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. Current projections of future cash flows for each plant, using independent market studies for estimating gas and electricity prices, market heat rates and capacity prices, do not indicate the investment to be impaired. We believe that those independent market studies are the best available for estimating future prices. Potential Asset Impairments Global has total investment exposure in Argentina of approximately $632 million. The investments include the following minority interests, with investment exposure of approximately $420 million, jointly owned by Global and AES, which are the subject of the Stock Purchase Agreement: a 30% interest in three Argentine electric 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); a 19% share in the 650 MW Central Termica San Nicolas power plant (CTSN); and a 33% interest in the 850 MW Parana power plant (Parana) nearing completion of construction. In addition to these investments, Global owns a 90% interest in another Argentine company, Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), with about $212 million of investment exposure. Global's Argentine properties continue to operate, but are faced with considerable fiscal and cash flow uncertainties due to economic, political and social conditions in Argentina. Moreover, Parana, EDEN, EDES and EDELAP have recently received notices of default from its international lenders related to their non recourse financings. If Argentine conditions do not improve soon, Global's other Argentine properties may also default on their international financings. Under a worst case scenario, if PSEG Global were to cease all operations in Argentina, it would record a pre-tax write off of approximately $632 million. See Note 18. "Subsequent Events" for a discussion of the sale to AES. As of December 31, 2001, we had recorded unamortized goodwill in the amount of $649 million, of which $479 million was recorded in connection with Global's acquisitions of SAESA and Electroandes in Chile and Peru in August and December of 2001, respectively. The amortization expense related to goodwill was approximately $3 million for the year ended December 31, 2001. 104 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued As of December 31, 2001, our pro-rata share of goodwill included in equity method investees totaled $375 million. Such goodwill is not consolidated on our balance sheet in accordance with generally accepted accounting principles. Global's share of the amortization expense related to such goodwill was approximately $8 million. We are currently evaluating the effect of adopting SFAS 142 on the recorded amount of goodwill. Some or all of the goodwill at: Rio Grande Energia (RGE) totaling $142 million (PSEG share), EDEERSA totaling $63 million and Energy Technologies totaling $53 million could be impaired upon completion of our evaluation. The impact of adopting SFAS 142 is likely to be material to our financial position and results of operations. As of December 31, 2001, our unamortized goodwill and pro-rata share of goodwill in equity method investees was as follows: As of December 31, 2000 ---------------------------------------------------------------------- (Millions of dollars) EDEERSA...................................... $63 SAESA........................................ 315 ElectroAndes................................. 164 Tanir Bavi................................... 27 Chorzow...................................... 6 Total Global............................ 575 Energy Technologies.......................... 53 Power........................................ 21 ----------------------- Total On Balance Sheet................ $649 ----------------------- Global --------------------------------------------- RGE.......................................... $142 Chilquinta/Luz............................... 174 Luz Del Sur.................................. 34 Kalaeloa..................................... 25 ----------------------- Total Off Balance Sheet 375 ----------------------- Total Goodwill $1,024 ======================= Minimum Lease Payments We and our subsidiaries lease administrative office space under various operating leases. As of December 31, 2001 our rental expense under these leases was approximately $10 million dollars. Total future minimum lease payments as of December 31, 2001 are: (Millions of Dollars) --------------------- 2002 $14 2003 10 2004 10 2005 7 2006 4 Thereafter 19 ----------- Total minimum lease payments $64 =========== PSE&G has entered into a capital lease for administrative office space. The total future minimum payments and present value of this capital lease as of December 31, 2001 are: 105 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued (Millions of Dollars) --------------------- 2002 $8 2003 8 2004 8 2005 8 2006 8 Thereafter 62 ----------- Total minimum lease payments 102 ----------- Less: Imputed Interest (42) ----------- Present Value of net minimum lease payments $60 =========== Note 10. Nuclear Decommissioning Trust In accordance with Federal regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. PSE&G currently recovers from its customers the amounts to be paid into the trust fund each year and remits these amounts to Power. 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 its share of its five nuclear units was estimated at $986 million in year-end 1995 dollars, excluding contingencies. Pursuant to the Final Order, PSE&G will collect $29.6 million annually through the SBC and will remit to Power an equivalent amount solely to fund the trust. The fair market value of these funds as of December 31, 2001 and 2000 was $817 million and $716 million, respectively. Contributions made into the Nuclear Decommissioning Trust Funds are invested in debt and equity securities. These marketable debt and equity securities are recorded at amounts that approximate their fair market value. Those securities have exposure to market price risk. The potential change in fair value, resulting from a hypothetical 10% change in quoted market prices of these securities amounts to $82 million. The ownership of the Nuclear Decommissioning Trust Funds was transferred to Nuclear with the transfer of the generation-related assets from PSE&G to Power. With the purchase of Atlantic City Electric Company's (ACE) and Delmarva Power and Light Company (DP&L)'s interests in Salem, Peach Bottom and Hope Creek, we received a transfer of $82 million and $50 million representing those companies respective NDT funds related to the stations in 2001 and 2000, respectively. 106 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Note 11. Income Taxes A reconciliation of reported income tax expense with the amount computed by multiplying pretax income by the statutory Federal income tax rate of 35% is as follows:

2001 2000 1999 -------------- -------------- --------------- (Millions of Dollars) Net Income (Loss)............................................. $770 $764 $(81) Extraordinary Item (Net of Tax 2001, $1; 1999 $345)...... 2 -- 804 Cumulative Effect of a Change in Accounting Principle (9) -- -- (Net of Tax) -------------- -------------- --------------- Net Income before Extraordinary Item.......................... 763 764 723 Preferred securities (net).................................... 5 9 9 -------------- -------------- --------------- Subtotal............................................ 768 773 732 -------------- -------------- --------------- Income taxes: Federal - Current........................................ 249 150 398 Deferred ...................................... 57 228 63 ITC............................................ (3) (2) (12) -------------- -------------- --------------- Total Federal............................... 303 376 449 -------------- -------------- --------------- State - Current.......................................... 63 160 132 Deferred ......................................... (1) (50) (13) -------------- -------------- --------------- Total State................................. 62 110 119 -------------- -------------- --------------- Foreign - Current........................................ 1 -- -- Deferred ...................................... 7 4 (5) -------------- -------------- --------------- Total Foreign............................... 8 4 (5) -------------- -------------- --------------- Total............................................... 373 490 563 -------------- -------------- --------------- Pretax income................................................. $1,141 $1,263 $1,295 ============== ============== ===============

Reconciliation between total income tax provisions and tax computed at the statutory tax rate on pretax income:

2001 2000 1999 ------------- -------------- --------------- (Millions of Dollars) Tax computed at the statutory rate............................ $399 $442 $453 Increase (decrease) attributable to flow through of certain tax adjustments: Plant Related Items...................................... (41) (15) 35 Amortization of investment tax credits................... (3) (2) (12) Tax Effects Attributable to Foreign Operations........... (20) (14) (7) New Jersey Corporate Business Tax........................ 41 74 84 Other.................................................... (3) 5 10 ------------- -------------- --------------- Subtotal............................................ (26) 48 110 ------------- -------------- --------------- Total income tax provisions......................... $373 $490 $563 ============= ============== =============== Effective income tax rate..................................... 32.8% 38.8% 43.5%

We provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities 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 utility customers in the future. Accordingly, an offsetting regulatory asset was established. As of December 31, 2001, PSE&G had a deferred tax liability and an offsetting regulatory asset of $302 million representing the tax costs expected to be recovered 107 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued 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%. The following is an analysis of deferred income taxes:

December 31, ----------------------------- 2001 2000 ------------- ------------- Deferred Income Taxes (Millions of Dollars) --------------------- Assets: Current (net)........................................... $21 $23 ------------- ------------- Non-current: Unrecovered Investment Tax Credits.................... 19 20 Nuclear Decommissioning............................... 25 26 FASB 133.............................................. 16 -- New Jersey Corporate Business Tax..................... 544 544 OPEB ................................................. 83 64 Cost of Removal....................................... 54 55 Development Fees...................................... 21 17 Foreign Currency Translation.......................... 29 23 Contractual Liabilities and Environmental Costs....... 35 35 Market Transition Charge.............................. 59 40 ------------- ------------- Total Non-current................................ 885 824 ------------- ------------- Total Assets..................................... 906 847 ------------- ------------- Liabilities: Non-current: Plant Related Items................................... 905 842 Securitization-EMP.................................... 1594 1,657 Leasing Activities.................................... 1146 987 Partnership Activities................................ 73 101 Conservation Costs.................................... 24 124 Pension Costs......................................... 94 58 Taxes Recoverable Through Future Rates (net).......... 130 90 Income from Foreign Operation......................... 41 14 Other................................................. 11 (16) ------------- ------------- Total Non-current................................ 4,018 3,857 ------------- ------------- Total Liabilities................................ 4,018 3,857 ------------- ------------- Summary -- Accumulated Deferred Income Taxes Net Current Assets...................................... 21 23 Net Non-current Liability............................... 3,133 3,033 ------------- ------------- Total.............................................. $3,112 $3,010 ============= =============

108 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Note 12. Pension, Other Postretirement Benefit and Savings Plans We sponsor several qualified and nonqualified pension plans and other postretirement benefit plans covering our, as well as our participating affiliates, current and former employees who meet certain eligibility criteria. The following table provides a reconciliation of the changes in the benefit obligations and fair value of plan assets over each of the two years in the period ended December 31, 2001 and a reconciliation of the funded status for at the end of both years. 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 and Other Postretirement Benefit Plans

----------------------------------------------------------------------------------------------------------------------------- Pension Benefits Other Benefits ---------------------------- ----------------------------------- $ in Millions 2001 2000 2001 2000 ----------------------------------------------------------------------------------------------------------------------------- Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 2,494.4 $ 2,383.6 $ 702.7 $ 691.2 Service Cost 62.8 60.5 16.3 12.0 Interest Cost 181.6 172.6 46.6 53.9 Actuarial (Gain)/Loss 90.0 (6.2) 8.2 (20.1) Benefits Paid (153.3) (145.3) (40.4) (36.6) Plan Amendments -- 22.2 (59.6) 0.0 Business Combinations -- 7.0 -- 2.3 ------------ ------------- ------------ --------------- Benefit Obligation at End of Year 2,675.5 2,494.4 673.8 702.7 ------------ ------------- ------------ --------------- Change in Plan Assets Fair Value of Assets at Beginning of Year 2,376.1 2,525.6 28.4 28.5 Actual Return on Plan Assets (85.3) (11.8) (1.2) (0.1) Employer Contributions 90.3 2.8 53.4 36.6 Benefits Paid (153.3) (145.3) (40.4) (36.6) Business Combinations -- 4.8 -- 0.0 ------------ ------------- ------------ --------------- Fair Value of Assets at End of Year 2,227.8 2,376.1 40.2 28.4 ------------ ------------- ------------ --------------- Reconciliation of Funded Status Funded Status (447.7) (118.3) (633.6) (674.3) Unrecognized Net Transition Obligation 12.7 20.8 275.8 337.9 Prior Service Cost 113.6 129.4 -- 25.1 (Gain)/Loss 455.6 70.3 (120.1) (139.0) ------------ ------------- ------------ --------------- Net Amount Recognized $ 134.2 $ 102.2 $ (477.9) $ (450.3) ============ ============= ============ =============== Amounts Recognized In Statement Of Financial Position Prepaid Benefit Cost $ 160.5 $ 125.4 $ -- $ 0.0 Accrued Cost (53.3) (49.5) (477.9) (450.3) Intangible Asset 19.8 22.6 N/A N/A Accumulated Other Comprehensive Income 7.2 3.7 N/A N/A ------------ ------------- ------------ --------------- Net Amount Recognized $ 134.2 $ 102.2 $ (477.9) $ (450.3) ============ ============= ============ =============== Separate Disclosure for Pension Plans With Accumulated Benefit Obligation In Excess of Plan Assets: Projected Benefit Obligation at End of Year $ 76.3 $ 66.7 Accumulated Benefit Obligation at End of Year $ 61.3 $ 52.7 Fair Value of Assets at End of Year $ 8.4 $ 4.5

109 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued

------------------------------------------------------------------------------------------------------------------------------ Pension Benefits Other Benefits ------------------------------------ --------------------------------------- $ in Millions 2001 2000 1999 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------------------ Components of Net Periodic Benefit Cost Service Cost $ 62.8 $ 60.5 $ 68.0 $ 16.3 $ 12.0 $ 13.1 Interest Cost 181.6 172.6 163.3 46.6 53.9 51.3 Expected Return on Plan Assets (211.1) (221.0) (197.3) (3.1) (2.6) (1.7) Amortization of Net Transition Obligation 8.1 8.1 8.1 27.3 30.4 30.4 Prior Service Cost 15.9 14.3 14.1 0.0 2.2 2.2 (Gain)/Loss 0.4 0.5 0.8 (5.9) (3.4) (3.0) ----------- ------------ ----------- ------------- ------------ ------------ Net Periodic Benefit Cost $ 57.7 $ 35.0 $ 57.0 $ 81.2 $ 92.5 $ 92.3 =========== ============ =========== ============= ============ ============ Components of Total Benefit Expense Net Periodic Benefit Cost $ 57.7 35.0 57.0 $ 81.2 $ 92.5 $ 92.3 Effect of Regulatory Asset 0.0 0.0 0.0 19.3 19.3 19.3 Total Benefit Expense Including Effect of ----------- ------------ ----------- ------------- ------------ ------------ Regulatory Asset $ 57.7 $ 35.0 $ 57.0 $ 100.5 $ 111.8 $ 111.6 =========== ============ =========== ============= ============ ============ Components of Other Comprehensive Income Decrease in Intangible Asset $ 2.8 $ 0.9 $ 2.6 Increase in Additional Minimum Liability 0.7 (1.8) (3.4) ----------- ------------ ----------- ------------- ------------ ------------ Other Comprehensive Income $ 3.5 $ (0.9) $ (0.8) N/A N/A N/A =========== ============ =========== ============= ========== ============ Weighted-Average Assumptions as of December 31 Discount Rate 7.25% 7.50% 7.50% 7.25% 7.50% 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% 5.00% Pre-65 Medical Costs Immediate Rate 9.50% 10.00% 11.00% Ultimate Rate 6.00% 6.00% 5.00% Year Ultimate Rate Reached 2008 2008 2011 Post-65 Medical Costs Immediate Rate 7.50% 8.00% 7.00% Ultimate Rate 6.00% 6.00% 5.00% Year Ultimate Rate Reached 2004 2004 2003 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 4.6 4.5 4.5 Postretirement Benefit Obligation 45.4 48.5 45.7 Effect of a 1% Decrease On Total of Service Cost and Interest Cost (3.9) (3.8) (4.7) Postretirement Benefit Obligation (39.1) (41.4) (39.3)

In 1999, $12 million was funded, as allowed. Remaining OPEB costs will not be funded in an external trust, as mandated by the BPU. 110 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued In October 1999, PSE&G recorded deferred assets and liabilities associated with the payment and collection of co-owner related OPEB costs. Such costs will be amortized over the remainder of the twenty-year period through 2013, in accordance with SFAS 106. No assurances for recovery of such assets and liabilities can be given. 401K Plans We sponsor two defined contribution plans. Represented employees of PSE&G, Power and Services are eligible for participation in the PSEG Employee Savings Plan (Savings Plan), while non-represented employees of PSE&G, Power, Energy Holdings and Services are eligible for participation in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). These plans are 401(k) plans to which eligible employees may contribute up to 25% of their compensation. Employee contributions up to 7% for Savings Plan participants and up to 8% for Thrift Plan participants are matched with employer contributions of cash 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. Beginning on March 1, 2002, and thereafter, all Employer contributions will be made in cash to the each plan. The amount expensed for Employer matching contributions to the plans was approximately $23, $22 million, and $21 million in 2001, 2000, and 1999, respectively. Note 13. Stock Options, Stock Purchase Plan and Stock Repurchase Program Stock Options We apply 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, compensation expense has been recognized for performance units and dividend equivalent rights issued in tandem with an equal number of options under its fixed stock option grants under the 1989 Long-Term Incentive Plan (1989 LTIP). Performance units and dividend equivalents provide cash payments, dependent upon our future financial performance in comparison to other companies and dividend payments made on our Common Stock, to assist recipients in exercising options granted. Prior to 1997, all options were granted in tandem with performance units and dividend equivalent rights. In 2001, 2000 and 1999, there were no options granted in tandem with performance units and dividend equivalent rights. 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 our net income of approximately $9.6 million, $3.6 million and $1.8 million in 2001, 2000 and 1999, respectively, with a $(0.05), $(0.02) and $(0.01) impact on earnings per share in 2001, 2000 and 1999, respectively. Under our 1989 LTIP and 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 selected by the Organization and Compensation Committee of our Board of Directors, the plan's administrative committee (the "Committee"). 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 111 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued 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 15,000,000 options to purchase shares of common stock. At December 31, 2001, there were 10,759,350 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, 2001, there were 11,169,500 options available for future grants under the 2001 LTIP. Since the 1989 LTIP's inception, we have purchased 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, 2001 are summarized as follows:

2001 2000 1999 ---------------------------- ---------------------------- ----------------------------- Weighted Weighted Weighted Average Average Average Options Exercise Price Options Exercise Price Options Exercise Price ----------- ---------------- ----------- ---------------- ------------ ---------------- Beginning of year 5,186,099 40.38 2,561,883 $34.60 1,243,800 $36.01 Granted 2,833,000 41.84 2,745,500 45.33 1,367,000 33.13 Exercised (303,135) 32.83 (110,684) 29.87 (44,167) 30.37 Canceled (63,501) 41.27 (10,600) 31.23 (4,750) 28.01 ----------- ----------- ----------- ---------- ------------ ---------- End of year 7,652,463 41.22 5,186,099 40.38 2,561,883 34.60 ----------- ----------- ----------- ---------- ------------ ---------- Exercisable at end of year 2,767,830 39.19 1,170,278 $34.91 412,738 $35.07 ----------- ----------- ----------- ---------- ------------ ---------- ----------------------------------------------------------------------------------------------- Weighted average fair value of options granted during the year $7.22 $8.73 $4.20 =========== ========== ==========

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 2001, 2000, and 1999, respectively: expected volatility of 28.22%, 26.63%, and 21.45%, risk free interest rates of 4.40%, 6.06%, and 6.16%, expected lives of 4.2 years, 4.4 years, and 4 years, respectively. There was a dividend yield of 5.18% in 2001, 4.77% in 2000, and 6.52% in 1999 on the non-tandem grants. The following table provides information about options outstanding at December 31, 2001:

-------------------------------------------------------------------------- ------------------------------------- Options Outstanding Options Exercisable -------------------------------------------------------------------------- ------------------------------------- Weighted Weighted Weighted Average Average Average Range of Outstanding at Remaining Exercise Exercisable at Exercise Exercise Prices December 31, 2001 Contractual Life Price December 31, 2000 Price -------------------------------------------------------------------------- ------------------------------------- $25.03-$30.02 173,300 5.6 years $ 29.56 173,300 $ 29.56 $30.03-$35.03 1,158,663 7.6 years 33.13 782,322 33.13 $35.04-$40.03 774,500 5.9 years 39.31 774,500 39.31 $40.04-$45.04 3,263,000 9.1 years 41.79 400,000 44.06 $45.05-$50.05 2,283,000 8.8 years 46.06 637.708 46.06 -------------------------------------------------------------------------- ------------------------------------- $25.03-$50.05 7,652,463 8.3 years $ 41.22 2,767,830 $ 39.19 -------------------------------------------------------------------------- -------------------------------------

112 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued In June 1998, the Committee granted 150,000 shares of restricted common stock to a key executive. An additional 60,000 shares or 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, 2001 is approximately $5 million and is included in retained earnings on the consolidated balance sheets. In addition 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 on at one-third per year beginning on July 1, 2002 and become fully vested on July 1, 2004. The unearned compensation related to this restricted stock grant as of December 31, 2001 is approximately $4 million and is included in retained earnings on the consolidated balance sheets. Our Stock Plan for Outside Directors provides non-employee directors, as part of their annual retainer, 600 shares of common stock, increased from 300 shares per year beginning in 1999. With certain exceptions, the restrictions on the stock provide that the shares are subject to forfeiture if the individual ceases to be a director at any time prior to the Annual Meeting of Stockholders following his or her 70th birthday. The fair value of these shares is recorded as compensation expense in the consolidated statements of income. Employee Stock Purchase Plan We maintain an employee stock purchase plan for all eligible employees. Under the plan, shares of the common stock may be purchased at 95% of the fair market value. Employees may purchase shares having a value not exceeding 10% of their base pay. During 2001, 2000 and 1999, employees purchased 85,552, 101,986, and 98,099 shares at an average price of $44.02, $37.06, and $38.21 per share, respectively. At December 31, 2001, 1,289,780 shares were available for future issuance under this plan. Stock Repurchase Program In September 1998, our Board of Directors authorized the repurchase of 30 million shares of Common Stock. A total of 24.3 million shares were repurchased at a cost of approximately $905 million under this program as of December 31, 2000, when the authorization expired. In September 2001, the board re-authorized the purchase of the balance of 5.7 million shares. As of December 31, 2001, an additional 2.2 million shares were repurchased at a cost of approximately $92 million. Note 14. Financial Information by Business Segments Basis of Organization The reportable segments were determined by Management in accordance with SFAS 131, "Disclosures About Segments of an Enterprise and Related Information" (SFAS 131). These segments were determined based on how Management measures the performance based on segment net income, as illustrated in the following table, and how it allocates resources to our businesses. Our organizational structure supports these segments. 113 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Generation The generation segment of our business earns revenues by selling energy on a wholesale basis under contract to power marketers and to load serving entities (LSEs) and by bidding the energy, capacity and ancillary services of Power into the market. Electrical energy is produced by generation plants and is ultimately delivered to customers for use in lighting, heating and air conditioning and operation of other electrical equipment. Energy is our principal product and is priced on a usage basis, typically in cents per thousand Watt-hours (kWh) or dollars per million Watt-hours (mWh). Capacity, as a product that is distinct from energy, is a commitment to the ISO that a given unit will be available for dispatch if it is needed to meet system demand. Capacity is typically priced in dollars per MW for a given sale period (e.g., mW-day or mW-year). Capacity generally refers to the power output rating of a generation plant, measured on an instantaneous basis. Ancillary services constitutes another category of energy-related activities supplied by generation unit owners to the ISO. Energy Trading The energy trading segment of our business earns revenues by trading energy, capacity, fixed transmission rights, fuel and emission allowances in the spot, forward and futures markets. Our energy trading segment also earns revenues through financial transactions, including swaps, options and futures in the electricity markets. We engage in physical and financial transactions in the electricity wholesale markets and execute an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. We actively trade energy, capacity, fixed transmission rights, fuel and emission allowances in the spot, forward and futures markets primarily within PJM, but also throughout the Super Region. We are also involved in financial transactions that include swaps, options and futures in the electricity markets. In addition to participating in each of the major electricity supply and capacity markets in the Super Region, we also market and trade a broad spectrum of other energy and energy-related products. These products include coal, oil, natural gas, sulfur dioxide and nitrous oxide emissions allowances and financial instruments including fixed transmission rights. Our marketing and energy trading activity for these products extends throughout the United States and involves physical and financially settled transactions, futures, options, swaps and basis contracts. None of our trading revenue with any individual counterparty exceeds 10%. We have developed a hedging and overall risk management strategy to limit our risk exposure and to track our positions in the wholesale markets. Hedging is used as the primary method for protecting against adverse price fluctuations and involves taking a position in a related financial instrument that is designed to offset the risk associated with the original position. We only use hedging instruments that correspond to the generation, purchase or sale of electricity and the purchase or sale of fuel. PSE&G All operations of this segment are conducted by PSE&G. The PSE&G segment generates 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. 114 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Global Global earns revenues from its investment in and operation of projects in the generation and distribution of energy, both domestically (exclusive of the Super Region included in the Generation segment above) and internationally. Resources Resources receives revenues from its passive investments in leveraged leases, limited partnerships, leveraged buyout funds and marketable securities. Resources operates both domestically and internationally. Energy Technologies Energy Technologies earns its revenues from constructing, operating and maintaining heating, ventilating and air conditioning (HVAC) systems and providing energy related services to industrial and commercial customers. Other Our other activities include amounts applicable to PSEG (parent corporation), Energy Holdings (parent corporation), EGDC and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. The net losses primarily relate to financing and certain administrative and general costs at the parent corporations. Information related to the segments of our business is detailed below:

Generation Energy Energy Consolidated (B) Trading PSE&G Resources Global Technologies Other Total ------------ ---------- --------- ------------ ---------- --------------- -------- ------------ (Millions of Dollars) ------------------------------------- For the Year Ended December 31, 2001: Electric Revenues................. $2,311 $-- $3,798 $-- $172 $-- $(2,125) $4,156 Gas Distribution Revenues......... -- -- 2,293 -- -- -- -- 2,293 Trading Revenues.................. -- 2,403 -- -- -- -- -- 2,403 Other Revenues.................... -- -- -- 215 280 467 1 963 Total Operating Revenues.......... 2,311 2,403 6,091 215 452 467 (2,124) 9,815 Depreciation and Amortization..... 95 -- 384 4 15 8 16 522 Interest Income................... 1 -- 21 1 1 4 5 33 Net Interest Charges.............. 143 -- 356 100 84 5 17 705 Operating Income Before Income Taxes............................. 504 140 324 100 169 (26) (75) 1,136 Income Taxes...................... 193 57 89 30 40 (9) (27) 373 Equity in earnings of unconsolidated Subsidiaries...................... -- -- -- 55 143 -- -- 198 Segment Earnings (Loss)........... 311 83 230 64 116 (18) (16) 770 Gross Additions to Long-Lived Assets............................ 1,456 6 398 1 167 1 24 2,053 As of December 31, 2001: Total Assets...................... $4,830 $790 $12,936 $3,026 $4,074 $290 $(549) 25,397 Investments in equity method subsidiaries...................... -- -- -- 163 1,541 3 19 1,726

115 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued

For the Year Ended December 31, 2000: ------------------------------------- Electric Revenues................. $2,203 $-- $2,505 $-- $-- $-- $(871) $3,837 Gas Distribution Revenues......... -- -- 2,140 -- -- -- -- 2,140 Trading Revenues.................. -- 2,724 -- -- -- -- -- 2,724 Other Revenues.................... -- -- -- 206 169 417 2 794 Total Operating Revenues.......... 2,203 2,724 4,645 206 169 417 (869) $9,495 Depreciation and Amortization..... 136 -- 213 5 1 7 -- 362 Interest Income................... 1 -- 21 2 1 4 3 32 Net Interest Charges.............. 198 -- 208 79 53 3 33 574 Operating Income Before Income Taxes............................. 449 72 638 111 69 (14) (71) 1,254 Income Taxes...................... 179 29 260 40 12 (4) (26) 490 Equity in earnings of unconsolidated Subsidiaries...................... -- -- -- 13 157 2 -- 172 Segment Earnings (Loss)........... 270 43 369 65 40 (10) (13) 764 Gross Additions to Long-Lived Assets............................ 479 -- 401 -- 56 7 16 959 As of December 31, 2000: Total Assets...................... $3,439 $1,091 $15,267 $2,565 $2,271 $312 $(3,419) $21,526 Investments in equity method subsidiaries...................... -- -- -- 239 1,900 -- 24 2,163 For the Year Ended December 31, 1999: ------------------------------------- Electric Revenues................. $2,652 $-- $1,429 $-- $-- $-- $-- $4,081 Gas Distribution Revenues......... -- -- 1,717 -- -- -- -- 1,717 Trading Revenues.................. -- 1,842 -- -- -- -- -- 1,842 Other Revenues.................... -- -- -- 179 211 297 -- 687 Total Operating Revenues.......... 2,652 1,842 3,146 179 211 297 -- 8,327 Depreciation and Amortization..... 224 -- 305 1 1 5 -- 536 Interest Income................... -- -- 12 1 -- 2 -- 15 Net Interest Charges.............. 112 -- 275 46 48 -- 9 490 Operating Income Before Income Taxes............................. 768 39 356 123 69 (9) (60) 1,286 Income Taxes...................... 275 16 219 50 24 (2) (19) 563 Equity in earnings of unconsolidated Subsidiaries...................... -- -- -- 78 129 -- -- 207 Segment Income before Extraordinary Item................ 490 23 131 66 28 (6) (9) 723 Extraordinary Item (A)............ (3,204) -- 2,400 -- -- -- -- (804) Segment Earnings (Loss)........... (2,714) 23 2,531 66 28 (6) (9) (81) Gross Additions to Long-Lived Assets............................ 92 -- 387 -- 1 8 94 582

(A) See Note 3. Regulatory Issues and Accounting Impacts of Deregulation for discussion of the extraordinary charge recorded by the generation segment in 1999 and the related regulatory asset for securitization recorded by the T&D segment. (B) Includes approximately $2.1 billion and $870 million charges in 2001 and 2000, respectively, to PSE&G related to the BGS Contract which commenced in August 2000, following the generation-related asset transfer to Power. 116 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Geographic information for us is disclosed below. The foreign assets and operations noted below were made solely through Energy Holdings.

Revenues (1) Identifiable Assets (2) ----------------------------------------------- ------------------------------- December 31, December 31, ----------------------------------------------- ------------------------------- 2001 2000 1999 2001 2000 ----------------------------------------------- ------------------------------- (Millions of Dollars) (Millions of Dollars) United States................. $9,391 $9,307 $8,178 $20,633 $18,536 Foreign - Resources........... 132 109 89 1,348 1,194 Foreign - Global.............. 292 79 60 3,416 1,796 ------------- ------------- ------------- -------------- ------------ Total.................... $9,815 $9,495 $8,327 $25,397 $21,526 ============= ============= ============= ============== ============

Identifiable assets in foreign countries include: Argentina $737 $470 Brazil $282 $295 Chile $880 $270 Peru $520 $250 Netherlands $911 $815 Other $1,434 $880 -------------------------------------------------------------------------------- (1) 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. (2) Total assets are net of foreign currency translation adjustment of $(283) million (pre-tax) as of December 31, 2001 and $(225) million (pre-tax) as of December 31, 2000. The table below reflects our investment exposure in Latin American countries:

INVESTMENT EXPOSURE (C) -------------------------------- DECEMBER 31, -------------------------------- 2001 2000 --------------- -------------- (MILLIONS OF DOLLARS) Argentina..................................... $ 632 $ 622 Brazil........................................ 467 462 Chile......................................... 542 180 Peru.......................................... 387 224 Venezuela..................................... 53 51

(C) The investment exposure consists of invested equity plus equity commitment guarantees. The investments in these Latin American countries are Global's. 117 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Note 15. Property, Plant and Equipment and Jointly Owned Facilities Information related to Property, Plant and Equipment of PSEG and its subsidiaries is detailed below: December 31, ---------------------------------- 2001 2000 ---------------- ---------------- Property, Plant and Equipment: (Millions of Dollars) Generation: Fossil Production (A).................. $2,233 $1,829 Nuclear Production..................... 154 130 Nuclear Fuel in Service................ 486 417 Construction Work in Progress (A)...... 2,004 483 Other.................................. 7 1 ---------------- ---------------- Total Generation.................. 4,884 2,860 ---------------- ---------------- Transmission and Distribution: Electric Transmission (A).............. 1,685 1,183 Electric Distribution.................. 4,254 4,056 Gas Transmission....................... 74 69 Gas Distribution....................... 3,121 2,978 Construction Work in Progress (A)...... 54 43 Plant Held for Future Use.............. 20 20 Other.................................. 292 130 ---------------- ---------------- Total Transmission and Distribution 9,500 8,479 ---------------- ---------------- Other.................................... 502 608 ---------------- ---------------- Total........................... $14,886 $11,947 ================ ================ (A) These items include the following amounts which relate to our Global segment: December 31, ---------------------------------- 2001 2000 ---------------- ---------------- Generation: (Millions of Dollars) Fossil Production...................... $335 $10 Construction Work in Progress.......... 317 172 ---------------- ---------------- Total Generation.................. $652 $182 ---------------- ---------------- Transmission and Distribution: Electric Transmission.................. 484 - Construction Work in Progress.......... 28 - ---------------- ---------------- Total Transmission and Distribution 512 - ---------------- ---------------- Total............................ $1,164 $182 ================ ================ 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 Income as operating expenses. 118 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued

Plant--December 31, 2001 -------------------------------------------------------------------- Ownership Accumulated Interest Plant Depreciation -------------------- -------------------- ----------------- (Millions of Dollars) Coal Generating Conemaugh.............................. 22.50% 199 70 Keystone............................... 22.84% 128 51 Nuclear Generating Peach Bottom........................... 50.00% 249 156 Salem.................................. 57.41% 671 582 Nuclear Support Facilities............. Various 5 1 Pumped Storage Facilities Yards Creek............................ 50.00% 28 12 Transmission Facilities..................... Various 80 30 Merrill Creek Reservoir..................... 13.91% 2 -- Linden SNG Plant............................ 90.00% 5 4 Plant--December 31, 2000 -------------------------------------------------------------------- Ownership Accumulated Interest Plant Depreciation -------------------- -------------------- ----------------- (Millions of Dollars) Coal Generating Conemaugh.............................. 22.50% 198 63 Keystone............................... 22.84% 122 47 Nuclear Generating Peach Bottom........................... 50.00% 88 10 Hope Creek............................. 95.00% 606 508 Salem.................................. 50.00% 645 544 Nuclear Support Facilities............. Various 5 1 Pumped Storage Facilities Yards Creek............................ 50.00% 28 11 Transmission Facilities..................... Various 97 33 Merrill Creek Reservoir..................... 13.91% 2 -- Linden SNG Plant............................ 90.00% 16 15

119 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Note 16. Selected Quarterly Data (Unaudited) The information shown below, in our opinion, includes all adjustments, consisting only of normal recurring accruals, necessary to a fair presentation of such amounts. Due to the seasonal nature of the utility business, quarterly amounts vary significantly during the year.

Calendar Quarter Ended ----------------------------------------------------------------------------------------- March 31, June 30, September 30, December 31, --------------------- --------------------- ----------------------- --------------------- 2001 2000 2001 2000 2001 2000 2001 2000 ---------- ---------- ---------- ---------- ---------- ------------ ---------- ---------- (Millions where Applicable) Operating Revenues......... $2,814 $2,483 $2,171 $2,159 $2,401 $2,207 $2,429 $2,646 Operating Income........... 577 603 402 393 431 392 482 501 Income before Extraordinary Item 254 270 143 142 172 142 194 210 Extraordinary Item......... (2) -- -- -- -- -- -- -- Cumulative Effective Adjustment 9 -- -- -- -- -- -- -- Net Income................. 261 270 143 142 172 142 194 210 Earnings per Share (Basic and Diluted)...... 1.25 1.25 0.68 0.66 0.82 0.66 0.95 0.98 Weighted Average Common Shares and Potential Dilutive Effect of Stock Options Outstanding..... 208 216 209 215 208 215 208 215

Note 17. Related Party Transactions We enter into a number of contracts with various suppliers, customers and other counterparties in the ordinary course of business. Certain contracts were entered into with subsidiaries of Foster Wheeler Ltd. E. James Ferland, our Chairman of the Board, President and Chief Executive Officer, serves on the Board of Directors of Foster Wheeler. Richard J. Swift, who serves on our Board of Directors, was the President and Chief Executive Officer of Foster Wheeler Ltd. at the time the contract was entered into. The open commitment under the contracts is for approximately $200 million of engineering, procurement and construction services related to the development of certain generating facilities for Power and Global. We believe that the contracts were entered into on commercial terms no more favorable than those available in an arms-length transaction from other parties and the pricing is consistent with that available from other third parties. Note 18. Subsequent Events On August 24, 2001, Global, an indirect subsidiary of us and a direct subsidiary of Holdings, entered into a Stock Purchase Agreement to sell its minority interests in certain assets located in Argentina to the AES Corporation (AES), the majority owner. These assets are "Assets Held for Sale" in the December 31, 2001 balance sheet. The sale has not closed, pending receipt of certain lender consents and regulatory approvals. On February 6, 2002, AES notified Global of its intent to terminate 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. We disagree that a "Political Risk Event", as defined in the Stock Purchase Agreement, has occurred and have so notified AES. We will vigorously pursue our rights under the Stock Purchase Agreement including ongoing discussions with AES to successfully resolve the matter. We cannot predict the ultimate outcome. As of December 31, 2001, Global had total investment exposure in Argentina of approximately $632 million. The investments include the following minority interests, with investment exposure of approximately $420 million, 120 -------------------------------------------- PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED -------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued including $92 million of goodwill, jointly owned by Global and AES, which are the subject of the Stock Purchase Agreement: a 30% interest in three Argentine electric 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); a 19% share in the 650 MW Central Termica San Nicolas power plant (CTSN); and a 33% interest in the 850 MW Parana power plant (Parana) nearing the completion of construction. In addition to these investments, Global has $212 million of investment exposure with respect to its 90% interest in another Argentine company, Inversora en Distribucion de Entre Rios S.A. (EDEERSA), inclusive of $63 million of goodwill. We have approximately $18 million of interest receivables due from AES, as provided for in the Stock Purchase Agreement and is due upon resolution of the pending sale. 121 FINANCIAL STATEMENT RESPONSIBILITY Our management is responsible for the preparation, integrity and objectivity of our 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 our 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 our 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 the corporation'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. 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 the corporation'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, 2001, the corporation's system of internal accounting controls was adequate to accomplish the objectives discussed herein. Our Board of Directors carries out its responsibility of financial overview through its Audit Committee, which presently consists of six directors who are not our employees or any of our 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 15, 2002 122 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, 2001 and 2000, and the related consolidated statements of income, common stockholders' equity and cash flows for each of the three years in the period ended December 31, 2001. Our audits also included the consolidated financial statement schedule listed in the Index in Item 14(B)(a). These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and the consolidated financial statement schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein. We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheets of the Company as of December 31, 1999, 1998, and 1997, and the related consolidated statements of income, common stockholders' equity and cash flows for the years ended December 31, 1998 and 1997 (none of which are presented herein), and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Selected Financial Data for each of the five years in the period ended December 31, 2001, presented in Item 6, is fairly stated in all material respects, in relation to the consolidated financial statements from which it has been derived. As discussed in Note 1 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. DELOITTE & TOUCHE LLP Parsippany, New Jersey February 15, 2002 123 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III -------- ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS The information required by Item 10 of Form 10-K with respect to (i) present directors who are nominees for election as directors at PSEG's Annual Meeting of Stockholders to be held on April 16, 2002, 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 heading "Election of Directors" and "Section 16 Beneficial Ownership Reporting Compliance" in our 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 1, 2002 and which information set forth under said heading is incorporated herein by this reference thereto.

============================================================================================================================= AGE EFFECTIVE DATE FIRST ELECTED NAME DECEMBER 31, 2001 OFFICE TO PRESENT POSITION ----------------------------------------------------------------------------------------------------------------------------- E. James Ferland 59 Chairman of the Board, President and July 1986 to present 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, President and November 1999 to present Chief Executive Officer (Services) ----------------------------------------------------------------------------------------------------------------------------- Thomas M.O'Flynn 41 Executive Vice President and Chief July 2001 to present Financial Officer (PSEG) Executive Vice President- Finance (Services) ----------------------------------------------------------------------------------------------------------------------------- Robert J. Dougherty, 50 President and Chief Operating Officer January 1997 to present Jr. (Energy Holdings) President (Enterprise Ventures and February 1995 to December 1996 Services Corporation) ----------------------------------------------------------------------------------------------------------------------------- Alfred C. Koeppe 55 President and Chief Operating February 2000 to present Officer (PSE&G) Senior Vice President--Corporate October 1996 to February 2000 Services and External Affairs (PSE&G) Senior Vice President--External October 1995 to October 1996 Affairs (PSE&G) =============================================================================================================================

124 Executive Officers of the Registrant The following table sets forth certain information concerning our executive officers.

============================================================================================================================= AGE EFFECTIVE DATE FIRST ELECTED NAME DECEMBER 31, 2001 OFFICE TO PRESENT POSITION ----------------------------------------------------------------------------------------------------------------------------- R. Edwin Selover 56 Vice President and General Counsel April 1988 to present (PSEG) Senior Vice President and General January 1988 to present Counsel (PSE&G) Senior Vice President and General November 1999 to present Counsel (Services) ----------------------------------------------------------------------------------------------------------------------------- Robert E. Busch 55 Senior Vice President and March 1998 to present Chief Financial Officer (PSE&G) President & COO November 1999 to present (Services) ----------------------------------------------------------------------------------------------------------------------------- Frank Cassidy 55 President and July 1999 to present Chief Operating Officer (Power) President (Energy Technologies) November 1996 to June 1999 Senior Vice President--Fossil February 1995 to November 1996 Generation (PSE&G) ----------------------------------------------------------------------------------------------------------------------------- Patricia A. Rado 59 Vice President and Controller April 1993 to present (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) =============================================================================================================================

ITEM 11. EXECUTIVE COMPENSATION The information required by Item 11 of Form 10-K is set forth under the heading "Executive Compensation" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 16, 2002 which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 1, 2002 and such information set forth under such heading is incorporated herein by this reference thereto. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 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 our definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 16, 2002 which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 1, 2002, and such information set forth under such heading is incorporated herein by this reference thereto. 125 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by Item 13 of Form 10-K is set forth under the heading "Executive Compensation" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 16, 2002, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 1, 2002. Such information set forth under such heading is incorporated herein by this reference thereto. PART IV ------- ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (A) Financial Statements: a. PSEG Consolidated Statements of Income for the years ended December 31, 2001, 2000 and 1999 on page 66. PSEG Consolidated Balance Sheets for the years ended December 31, 2001 and 2000 on pages 67 and 68. PSEG Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999 on page 69. PSEG Statements of Common Stockholders' Equity for the years ended December 31, 2001, 2000 and 1999 on page 66. PSEG Notes to Consolidated Financial Statements on pages 71 to 121. (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, 2001 (page 127) Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto. The following exhibits are filed herewith: Exhibit 10a(10): Amended Employment Agreement with E. James Ferland dated November 20, 2001 Exhibit 10a(12): Amended Employment Agreement with Thomas M. O'Flynn dated December 21, 2001 Exhibit 12: Computation of Ratios of Earnings to Fixed Charges Exhibit 21: Subsidiaries of Registrant Exhibit 23: Independent Auditors' Consent (See Exhibit Index on pages 130 to 135) (C) The following reports on Form 8-K were filed during the last quarter of 2001 and the 2002 period covered by this report under Item 5: Date of Report Items Reported -------------- -------------- February 7, 2002 Item 5 January 25, 2002 Items 5 and 7 October 24, 2001 Items 5 and 7 126 SCHEDULE II PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED Schedule II -- Valuation and Qualifying Accounts Years Ended December 31, 2001 -- December 31, 1999

Column A Column B Column C Column D Column E -------- ------------- ----------------------------- ------------- ------------- Additions ----------------------------- Balance at Charged to Charged to Balance at beginning cost and other accounts Deductions- end of Description of period expenses Describe describe Period ------------------------------------------- ------------- ----------------------------- ------------- ------------- (Millions of Dollars) 2001: ----- Allowance for Doubtful Accounts.......... $44 $45 $-- $46(A) $43 Materials and Supplies Valuation Reserve. 11 -- -- 9(D) 2 Other Valuation Allowances............... 22 -- -- -- 22 2000: ----- Allowance for Doubtful Accounts.......... $40 $45 $-- $41(A) $44 Materials and Supplies Valuation Reserve. 11 -- -- -- 11 Other Valuation Allowances............... 22 -- -- -- 22 1999: ----- Allowance for Doubtful Accounts.......... $38 $40 $-- $38(A) $40 Discount on Property Abandonments........ 1 -- -- 1(B) -- Materials and Supplies Valuation Reserve. 12 41 -- 42(C) 11 Other Valuation Allowances............... 11 11 -- -- 22

(A) Accounts Receivable/Investments written off. (B) Amortization of discount to income. (C) Inventory written off. (D) Reduced reserve to appropriate level and to remove obsolete inventory. 127 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. Public Service Enterprise Group Incorporated By E. JAMES FERLAND ------------------------------------------ E. James Ferland Chairman of the Board, President and Chief Executive Officer Date: March 1, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature Title Date --------- ----- ---- E. JAMES FERLAND Chairman of the Board, March 1, 2002 -------------------------------------------- President and Chief Executive Officer E. James Ferland and Director (Principal Executive Officer) THOMAS M. O'FLYNN Executive Vice President and Chief March 1, 2002 -------------------------------------------- Financial Officer Thomas M. O'Flynn (Principal Financial Officer) PATRICIA A. RADO Vice President and Controller March 1, 2002 -------------------------------------------- (Principal Accounting Officer) Patricia A. Rado ERNEST H. DREW Director March 1, 2002 -------------------------------------------- Ernest H. Drew T. J. DERMOT DUNPHY Director March 1, 2002 -------------------------------------------- T. J. Dermot Dunphy ALBERT R. GAMPER, JR. Director March 1, 2002 -------------------------------------------- Albert R. Gamper, Jr. RAYMOND V. GILMARTIN Director March 1, 2002 -------------------------------------------- Raymond V. Gilmartin CONRAD K. HARPER Director March 1, 2002 -------------------------------------------- Conrad K. Harper WILLIAM V. HICKEY Director March 1, 2002 -------------------------------------------- William V. Hickey SHIRLEY ANN JACKSON Director March 1, 2002 -------------------------------------------- Shirley Ann Jackson MARILYN M. PFALTZ Director March 1, 2002 -------------------------------------------- Marilyn M. Pfaltz RICHARD J. SWIFT Director March 1, 2002 -------------------------------------------- Richard J. Swift

128 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. 129

PSEG --------------------------------------------------- Exhibit Number --------------------------------------------------- This Previous Filing ------------------------------------ Filing Commission Exchanges ------ ---------- --------- 3a (e) 3a (e) 3a Certificate of Incorporation Public Service Enterprise Group Incorporated 3b (c) 3b (c) 3b By-Laws of Public Service Enterprise 4/11/88 Group Incorporated 3c (c) 3c (c) 3c Certificate of Amendment of Certificate of 4/11/88 Incorporation of Public Service Enterprise Group Incorporated, effective April 23, 1987 3d (d) (d) Trust Agreements for Enterprise Capital Trust I and III 12/24/97 3e (b) 3 (b) 3 Amended and Restated Trust Agreement for Enterprise 8/14/98 8/14/98 Capital Trust II 4a(1) (b) 4f (b) 4f Indenture between Public Service Enterprise Group 5/13/98 5/13/98 Incorporated and First Union National Bank, 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 8/14/98 8/14/98 of January 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank, 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 8/14/98 8/14/98 of January 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank, as Trustee, dated July 1, 1998 providing for the issuance of Deferrable Interest Subordinated Debentures, Series C (relating to Trust Preferred Securities) 4b (a) 4f (a) 4f Indenture dated as of November 1, 1998 between Public 11/1/00 11/1/00 Service Enterprise Group Incorporated and First Union National Bank providing for the issuance of Senior Debt Securities 9 Inapplicable 10a(1) (c) 10a(1) (c) 10a(1) Directors' Deferred Compensation Plan 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 Plan 2/25/00 2/25/00 10a(5) (c) 10a(5) (c) 10a(5) Retirement Income Reinstatement Plan 2/25/00 2/25/00 10a(6) (c) 10a(6) (c) 10a(6) 1989 Long-Term Incentive Plan 2/22/99 2/22/99 10a(7) (c) 10a(7) (c) 10a(7) 2001 Long-Term Incentive Plan 3/06/01 3/06/01 10a(8) (c) 10a(8) (c) 10a(8) Restated and Amended Management Incentive Compensation Plan 3/06/01 3/06/01

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PSEG ---------------------------------------------------- Exhibit Number ---------------------------------------------------- This Previous Filing Filing Commission Exchanges ------ ---------- --------- 10a(9) (b) 10 (b) 10 Employment Agreement with E. James Ferland dated 8/14/98 8/14/98 June 16, 1998 10a(10) Amended Employment Agreement with E. James Ferland dated November 20, 2001 10a(11) (b) 10a(22) (b) 10a(22) Employment Agreement with Thomas M. O'Flynn dated 11/13/00 11/13/00 April 18, 2001 10a(12) Amended Employment Agreement with Thomas M. O'Flynn dated December 21, 2001 10a(13) (a) 10a(14) (a) 10a(14) Letter Agreement with Patricia A. Rado dated 2/26/94 3/9/94 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) (c) 10a(14) (c) 10a(14) Directors' Stock Plan 2/22/99 2/22/99 10a(18) (a) 10a(16) (a) 10a(16) Letter Agreement with Harold W. Keiser dated January 5, 2/23/98 2/23/98 1998 10a(19) (c) 10a(16) (c) 10a(16) Global Deferred Compensation Plan 2/22/99 2/22/99 10a(20) (c) 10a(17) (c) 10a(17) Global 2001 Executive Long-Term Incentive Compensation Plan 2/22/99 2/22/99 10a(21) (c) 10a(20) (c) 10a(20) Energy Technologies Executive Incentive Compensation Plan 2/22/99 2/22/99 10a(22) (c) 10a(22) (c) 10a(22) Resources Annual Incentive Compensation Plan 2/22/99 2/22/99 10a(23) (f) 10a(23) (f) 10a(23) Employment Agreement with Robert E. Busch dated April 24, 2001 8/09/01 8/09/01 11 Inapplicable 12 Computation of Ratios of Earnings to Fixed Charges 13 Inapplicable 16 Inapplicable 18 Inapplicable 21 Subsidiaries of the Registrant 22 Inapplicable 23 Independent Auditors' Consent 24 Inapplicable 28 Inapplicable 99 Inapplicable

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