UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

S ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2004,

OR

£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM                  TO                 .

Securities registered pursuant to Section 12(b) of the Act:

      Participating Equity Preference Securities (consisting of a Purchase Contract and a Preferred Trust Security), $50 par value at 10.25%, issued by PSEG Funding Trust I (Registrant) and registered on the New York Stock Exchange.

      Trust Originated Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG's Debentures), $25 par value at 8.75%, issued by PSEG Funding Trust II (Registrant) and registered on the New York Stock Exchange.

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Securities registered pursuant to Section 12(g) of the Act:

      The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates as of June 30, 2004 was $9,313,972,867 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:

      PSEG Power LLC and PSEG Energy Holdings LLC are wholly-owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are filing their respective Annual Reports on Form 10-K with the reduced disclosure format authorized by General Instruction I.

      As of January 31, 2005, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.

      Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. Yes S    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.  S    

      Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

DOCUMENTS INCORPORATED BY REFERENCE

TABLE OF CONTENTS

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FORWARD-LOOKING STATEMENTS

      Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used herein, the words “will,” “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings LLC (Energy Holdings) 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 should not be construed as a complete list of factors that could effect forward-looking statements.

      In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements discussed above, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

PSEG, PSE&G, Power and Energy Holdings

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PSE&G and Energy Holdings

Power and Energy Holdings

Power

Energy Holdings

      Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements and PSEG, PSE&G, Power and Energy Holdings cannot assure you that the results or developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on, PSEG, PSE&G, Power and Energy Holdings or their respective business prospects, financial condition or results of operations. Undue reliance should not be placed on these forward-looking statements in making any investment decision. Each of PSEG, PSE&G, Power and Energy Holdings expressly disclaims any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or are anticipated to occur or arise after the date hereof. In making any investment decision regarding PSEG's, PSE&G's, Power's and Energy Holdings' securities, PSEG, PSE&G, Power and Energy Holdings are not making, and you should not infer, any representation about the likely existence of any particular future set of facts or circumstances. The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.

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WHERE TO FIND MORE INFORMATION

      Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings LLC (Energy Holdings) file annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission (SEC). You may read and copy any document that PSEG, PSE&G, Power and Energy Holdings file at the Public Reference Room of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. You may also obtain PSEG's, PSE&G's, Power's and Energy Holdings' filings on the Internet at the SEC's website at www.sec.gov or at PSEG's website, www.pseg.com. PSEG's Common Stock is listed on the New York Stock Exchange under the ticker symbol “PEG.” You can obtain information about PSEG, PSE&G, Power and Energy Holdings at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

PART I

ITEM 1. BUSINESS

GENERAL

PSEG, PSE&G, Power and Energy Holdings

      PSEG was incorporated under the laws of the State of New Jersey in 1985 and has its principal executive offices located at 80 Park Plaza, Newark, New Jersey 07102. PSEG is an exempt public utility holding company under the Public Utility Holding Company Act of 1935 (PUHCA).

      PSEG has four principal direct wholly-owned subsidiaries: PSE&G, Power, Energy Holdings and PSEG Services Corporation (Services). The following organization chart shows PSEG and its principal subsidiaries, as well as the principal operating subsidiaries of Power: PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T); and of Energy Holdings: PSEG Global LLC (Global) and PSEG Resources LLC (Resources):

      The regulatory structure that has historically governed the electric and gas utility industries in the United States (U.S.) has changed dramatically in recent years. Deregulation is complete in New Jersey and is complete or underway in certain other states in the Northeast and across the U.S. Actions by state regulators and the Federal Energy Regulatory Commission (FERC) and the implementation of the National Energy Policy Act of 1992 (Energy Policy Act) have afforded power marketers, merchant generators, Exempt Wholesale Generators (EWGs) and utilities the opportunity to compete actively in wholesale energy markets and have allowed consumers the right to choose their energy suppliers. The deregulation and restructuring of the nation's energy markets, the unbundling of energy and related services, the diverse strategies within the industry related to holding, building, buying or selling generation capacity and consolidation within the

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industry have had, and are likely to continue to have, a significant effect on PSEG and its subsidiaries, providing them with new opportunities and exposing them to new risks.

      As energy markets have changed dramatically in recent years, PSEG and its subsidiaries have transitioned from a vertically integrated utility to an energy company with a diversified business mix. PSEG has realigned its organizational structure to address the competitive environment brought about by the deregulation of the electric generation industry and has evolved from primarily being a state regulated New Jersey utility to operating as a competitive energy company with operations primarily in the Northeastern U.S. and in other select markets. As the competitive portion of PSEG's business has grown, the resulting financial risks and rewards have become greater, causing financial requirements to change and increasing the volatility of earnings and cash flows.

      PSEG seeks to reduce future volatility of earnings and cash flows principally by entering into longer-term contracts for material portions of its anticipated energy output. PSEG may also reduce exposure to its international businesses by seeking to opportunistically monetize investments of Energy Holdings that may no longer have a strategic fit. PSEG also expects a gradual decline in earnings from Resources' leveraged leasing business due to the maturation of its investment portfolio. The proceeds from Energy Holdings' asset sales will be used, over time, to reduce debt and equity and to maintain credit requirements. For additional information, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A)—Overview of 2004 and Future Outlook.

      Recent Developments—Merger Agreement

      On December 20, 2004, PSEG entered into an agreement and plan of merger (Merger Agreement) with Exelon Corporation (Exelon), a public utility holding company registered under PUHCA which is headquartered in Chicago, Illinois, whereby PSEG will be merged with and into Exelon (Merger). Under the Merger Agreement, each share of PSEG Common Stock will be converted into 1.225 shares of Exelon Common Stock.

      The Merger Agreement has been unanimously approved by both companies' boards of directors. Before the Merger may be completed, various approvals or consents must be obtained from shareholders, FERC, the SEC, the Nuclear Regulatory Commission (NRC) and various utility regulatory, antitrust and other authorities in the U.S. and in foreign jurisdictions. PSEG and Exelon have made some of the regulatory filings to obtain necessary regulatory approvals. It is anticipated that this approval process will be completed and the Merger will close within 12 months to 15 months after the announcement of the Merger Agreement in December 2004.

      PSEG is committed to this proposed business combination, however, pending receipt of the various required approvals, which cannot be assured, PSEG intends to remain positioned with a viable stand-alone strategy. For additional information related to the Merger, see Item 3. Legal Proceedings, Item 7. MD&A—Overview of 2004 and Future Outlook—Merger Agreement and Note 25. Merger Agreement of the Notes to the Consolidated Financial Statements (Notes).

PSE&G

      PSE&G is a New Jersey corporation, incorporated in 1924, and has principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. PSE&G is an operating public utility company engaged principally in the transmission and distribution of electric energy and gas service in New Jersey. PSE&G, pursuant to an order of the New Jersey Board of Public Utilities (BPU) issued under the provisions of the New Jersey Electric Discount and Energy Competition Act (EDECA), transferred all of its electric generation facilities, plant, equipment and wholesale power trading contracts to Power and its subsidiaries in August 2000 for approximately $2.8 billion. Also, pursuant to a BPU order, PSE&G transferred its gas supply business, including its inventories and supply contracts, to Power in May 2002 for $183 million. PSE&G continues to own and operate its electric and gas transmission and distribution business. In addition, PSE&G Transition Funding LLC (Transition Funding), a bankruptcy-remote subsidiary of PSE&G, was formed in 1999 for the sole purpose of issuing $2.525 billion principal amount of transition bonds in connection with the securitization of $2.4 billion of PSE&G's stranded costs approved for recovery by the BPU under EDECA.

      PSE&G provides electric and gas service in areas of New Jersey in which approximately 5.5 million people, about 70% of the state's population, reside. PSE&G's electric and gas service area is a corridor of approximately 2,600 square miles running diagonally across New Jersey from Bergen County in the northeast to an area below the city of Camden in the southwest. The greater portion of this area is served with both

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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 nationally prominent corporations. PSE&G's load requirements are split among residential, commercial and industrial customers, detailed below under customers. PSE&G believes that it has all the franchise rights (including consents) necessary for its electric and gas distribution operations in the territory it serves. Such franchise rights are not exclusive.

      PSE&G distributes electric energy and gas to end-use customers within its designated service territory. All electric and gas customers in New Jersey have the ability to choose an electric energy and/or gas supplier. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric and gas customers within its service territory. PSE&G earns no margin on the commodity portion of its electric and gas sales. PSE&G earns margins through the transmission and distribution of electricity and gas. PSE&G's revenues for these services are based upon tariffs approved by the BPU and FERC. 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 PSE&G's control.

      New Jersey's Electric Distribution Companies (EDCs), including PSE&G, provide two types of Basic Generation Service (BGS). BGS is the default electric supply service for customers who do not choose a third party to source their electric supply requirements. BGS-Fixed Price (FP) provides supply for smaller commercial and residential customers at seasonally-adjusted fixed prices. BGS-FP rates change annually on June 1 and are based on the average BGS price obtained at auction in the current year and two prior years. BGS-Commercial and Industrial Energy Price (CIEP) provides supply for larger customers at hourly PJM Interconnection, L.L.C. (PJM) real-time market prices for a term of 12 months. BGS-FP and BGS-CIEP represent approximately 84% and 16%, respectively, of PSE&G's load.

      New Jersey's EDCs jointly procure the supply to meet their BGS obligations through two concurrent auctions authorized by the BPU for New Jersey's total BGS requirement each February. The results of this auction determine which energy suppliers are authorized to supply BGS to New Jersey's EDCs. As a condition of qualification to participate in this auction, energy suppliers are required to agree to execute the BGS Master Service Agreement and provide required security within three days of BPU certification of auction results, in addition to satisfying creditworthiness requirements.

      PSE&G's total BGS-FP load is approximately 8,600 megawatts (MW). Approximately one-third of this total load is expected to be auctioned off each year for a three-year term. The current pricing is as follows:

      PSE&G has entered into a full requirements contract through 2007 with Power to meet the supply requirements of PSE&G's gas customers. Power charges PSE&G for gas commodity costs which PSE&G recovers from its customers. Any difference between rates charged by Power under the Basic Gas Supply Service (BGSS) contract and rates charged to its customers are deferred and collected or refunded through adjustments in future rates.

      On October 5, 2004, the BPU approved a 3% increase in PSE&G's residential gas commodity charge to cover the higher cost of natural gas. The cost of energy supply, for both gas and electricity, is passed through from PSE&G to its customers.

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      Competitive Environment

      The electric and gas transmission and distribution business has minimal risks from competitors. PSE&G's transmission and distribution business is minimally impacted when customers choose alternate electric or gas suppliers since PSE&G earns its return by providing transmission and distribution service, not by supplying the commodity.

      Customers

      As of December 31, 2004, PSE&G provided service to approximately 2.1 million electric customers and approximately 1.7 million gas customers, detailed below. In addition to its transmission and distribution business, PSE&G also offers appliance services and repairs to customers throughout its service territory.

      Employee Relations

      As of December 31, 2004, PSE&G had 6,327 employees. PSE&G has three-year collective bargaining agreements in place with four unions, representing 4,996 employees, which expire on April 30, 2005. New six-year collective bargaining agreements with the four unions were ratified in February 2005. PSE&G believes that it maintains satisfactory relationships with its employees. For additional information related to the Merger, see Item 7. MD&A—Overview of 2004 and Future Outlook—Merger Agreement and Note 25. Merger Agreement of the Notes.

Power

      Power is a Delaware limited liability company, formed in 1999, and has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Power is a multi-regional, independent wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management functions through three principal direct wholly-owned subsidiaries: Nuclear, Fossil and ER&T.

      As of December 31, 2004, Power's generation portfolio consisted of approximately 14,607 MW of installed capacity which is diversified by fuel source and market segment. For additional information, see Item 2. Properties.

      Through its operating subsidiaries, Power competes as an independent wholesale electric generating company, primarily in the Northeast U.S. Most of Power's generating assets are strategically located within PJM, one of the nation's largest and most developed energy markets.

      In the PJM market, the pricing of energy is based upon the locational marginal price (LMP) set through power providers' bids. Due to transmission constraints, the LMP may be higher in congested areas during peak demand periods reflecting the bid prices of the higher cost units that are dispatched to supply demand. This typically occurs in the eastern portion of the grid, where many of Power's plants are located. These bids are currently capped at $1,000 per megawatt-hour (MWh). In the event that available generation within PJM is insufficient to satisfy demand, PJM may institute emergency purchases from adjoining regions for which there is no price cap.

      To reduce volatility in earnings and cash flow, Power's objective is to enter into load serving contracts, firm sales and trading positions sufficient to hedge at least 75% of its anticipated output over an 18-month to 24-month horizon. Power has achieved this objective through a combination of contracts related to the New Jersey BGS auctions, contracts in Pennsylvania and Connecticut and other firm sales and trading positions. Prospectively, Power intends to take advantage of the BGS auctions in New Jersey and other opportunities elsewhere in the market region to continue to meet this objective.

      In February 2005, the BPU approved the results of the BGS-FP and CIEP auctions for New Jersey customers. Each bidder was limited to a third of each EDC's total load. Power will continue to be a direct supplier of New Jersey EDCs under both the BGS-FP and CIEP auctions, entering into additional contracts that will begin on June 1, 2005. Power believes that its obligations under these contracts are reasonably balanced by its available supply.

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      In addition to the electric generation business described above, Power's revenues include gas supply sales under the BGSS contract with PSE&G. Power also generates revenue from the sales of various commodity-based instruments, such as capacity, ancillary services, emission credits and congestion credits, such as firm transmission rights (FTRs).

      Fossil

      Fossil has an ownership interest in 12 generating stations in New Jersey, one in New York, two in Connecticut, two in Pennsylvania, one in Ohio and one in Indiana. Fossil also has an ownership interest in one hydroelectric-pumped storage facility in New Jersey. For additional information, see Item 2. Properties—Power.

      Fossil began operating in New England Power Pool (NEPOOL) with the acquisition of two fossil fuel generating stations in Connecticut in late 2002: the Bridgeport Harbor facility, a 513 MW coal/oil fuel facility and the New Haven Harbor facility, a 448 MW oil/gas facility. Fossil completed construction of the Waterford, Ohio plant, an 821 MW natural gas-fired, combined cycle plant, which began commercial operation in August 2003. In addition, Fossil completed construction of a 1,096 MW natural gas-fired, combined cycle plant in Lawrenceburg, Indiana, which began commercial operation in June 2004. Additionally, the Albany, New York generating station is currently being replaced with a 763 MW combined cycle plant, the Bethlehem Energy Center, which is expected to be operational in the second quarter of 2005. The Linden, New Jersey generating station is currently being replaced with a 1,220 MW natural gas-fired, combined cycle plant, which is expected to be operational in 2006.

      Fossil uses coal, natural gas and oil for electric generation. These fuels are purchased through various contracts and in the spot market and represent a significant portion of Power's working capital requirements. Changes in the prices of these fuel sources impact Power's costs and working capital requirements. The majority of Power's fossil generating stations obtain their fuel supply from within the U.S. In order to minimize emissions levels, the Connecticut generating facilities use a specific type of coal, which is obtained from Indonesia through a fixed-price supply contract through 2008 and transportation contracts covering 100% of supply through 2006, 66% in 2007 and 33% in 2008. Fossil believes it can obtain adequate coal, natural gas and oil supplies for its facilities over the next several years. However, issues could arise, such as transportation constraints, which could adversely affect the operation of Fossil's plants. In addition, if the supply of coal from Indonesia or equivalent coal from other sources was not available for the Connecticut facilities, additional material capital expenditures could be required to modify the existing plants to enable their continued operation. For additional information, see Item 2. Properties—Power.

      Nuclear

      Nuclear has an ownership interest in five nuclear generating units: 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 Company LLC (Exelon Generation); the Hope Creek Nuclear Generating Station (Hope Creek), which is owned 100% by Nuclear; and, the Peach Bottom Atomic Power Station Units 2 and 3 (Peach Bottom 2 and 3), each of which is operated by Exelon Generation and owned 50% by Nuclear. For additional information, see Item 2. Properties—Power.

      For a discussion of recent operational issues, see Regulatory Issues—NRC.

      Nuclear unit capacity and availability factors for 2004 were as follows:

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      Nuclear has several long-term purchase contracts with uranium suppliers, converters, enrichers and fabricators to meet the currently projected fuel requirements for the Salem and Hope Creek nuclear power plants. Nuclear has been advised by Exelon Generation that it has similar purchase contracts to satisfy the annual fuel requirements for Peach Bottom. See Note 14. Commitments and Contingent Liabilities of the Notes.

      Concurrent with the Merger Agreement, Nuclear entered into an Operating Services Contract (OSC) with Exelon Generation, which commenced on January 17, 2005, relating to the operation of the Salem and Hope Creek nuclear generating stations. The OSC provides that Exelon Generation will provide a chief nuclear officer and other key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement the Exelon operating model, which defines practices that Exelon has used to manage its own nuclear performance improvement program. Nuclear will continue as the license holder with exclusive legal authority to operate and maintain the plants, will retain responsibility for management oversight and will have full authority with respect to the marketing of its share of the output from the facilities. Exelon Generation will be entitled to receive reimbursement of its costs in discharging its obligations, an annual operating services fee and incentive fees of up to $12 million annually based on attainment of goals relating to safety, capacity factors of the plants and operation and maintenance expenses. The OSC has a term of two years, subject to earlier termination in certain events upon prior notice, including any termination of the Merger Agreement. In the event of such termination, Exelon Generation will continue to provide services under the OSC for a transition period of at least 180 days and up to two years at the election of Nuclear. This period may be further extended by Nuclear for up to an additional 12 months if Nuclear determines that additional time is necessary to complete required activities during the transition period.

      ER&T

      ER&T purchases the capacity and energy produced by each of the generation subsidiaries of Power. In conjunction with these purchases, ER&T uses commodity and financial instruments designed to cover estimated commitments for BGS and other bilateral contract agreements. ER&T also markets electricity, capacity, ancillary services and natural gas products on a wholesale basis. ER&T is a fully integrated wholesale energy marketing and trading organization that is active in the long-term and spot wholesale energy markets.

      Electric Supply

      Power's generation capacity is sourced from a diverse mix of fuels comprised of approximately 45% gas, 24% nuclear, 16% coal, 14% oil and 1% pumped storage. Power's fuel diversity serves to mitigate risks associated with fuel price volatility and market demand cycles. The following table indicates the MWh output of Power's generating stations by fuel type in 2004 and its estimated MWh output by fuel type for 2005.

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      Approximately 86% of Power's generation was from nuclear and coal facilities in 2004, which are typically the most cost-effective fuel types on an operating cost basis. On a per-MWh basis, nuclear power is the most cost-effective and, as a result, Power's profitability is largely affected by the utilization and efficiency of its nuclear facilities. The nuclear facilities are considered “base load” and run continuously when not in shutdown. Older oil and gas-fired facilities are typically the least cost-effective of the fossil fuel burners. Accordingly, these plants are not usually run outside of peak periods of demand when the cost of operation can be justified by the market price. The costs of operating coal and oil burning facilities and new combined cycle gas facilities range between those of the two aforementioned facility types. These plants can be base load plants and/or load following plants.

      Gas Supply

      As described above, Power sells gas to PSE&G under the BGSS contract. Additionally, based upon availability, Power sells gas to others. About 42% of PSE&G's peak daily gas requirements are provided through firm transportation, which is available every day of the year. The remainder comes from field storage, liquefied natural gas, seasonal purchases, contract peaking supply, propane and refinery and landfill gas. Power purchases gas for its gas operations directly from natural gas producers and marketers. These supplies are transported to New Jersey by four interstate pipeline suppliers.

      Power has approximately 1.17 billion cubic-feet-per-day of firm transportation capacity under contract to meet the primary needs of the gas consumers of PSE&G and the needs of its generation fleet. In addition, Power supplements that supply with a total storage capacity of 82 billion cubic feet that provides a maximum of 0.94 billion cubic feet-per-day of gas during the winter season.

      Power expects to be able to meet the energy-related demands of its firm natural gas customers. However, the ability to maintain an adequate supply could be affected by several factors not within Power's control, including curtailments of natural gas by its suppliers, the severe weather and the availability of feedstocks for the production of supplements to its natural gas supply. In addition, supply of all types of gas is affected by the nationwide availability of all sources of fuel for energy production.

      Competitive Environment

      Power's competitors include merchant generators with or without trading capabilities, utilities that have generating capability or have formed generation and/or trading affiliates, aggregators, wholesale power marketers and combinations thereof. These participants compete with Power and 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 allow it to compete effectively in its selected markets.

      Actions by developers, including Power, to build new generating stations have led to an overbuild situation in certain markets, including PJM, causing downward pressure on energy and capacity prices. Capacity prices in PJM have recently averaged well below $10 per kW-year as compared to historical levels of more than $25 per kW-year. This overcapacity has decreased capacity revenues and has decreased margins from some of Power's units. Power believes that recent events in PJM, including preliminary discussions with regard to changes in the design of the capacity market, as well as advancement toward reliability-based payments to generators, may lead to changes that could enhance the value of Power's generation fleet in PJM. In addition, Power anticipates that capacity prices in PJM will return to historical levels in the next several years.

      The New England market is also overbuilt and is also undergoing changes. The existence of reliability-based payments, coupled with the anticipated start of locational capacity markets in 2006, could also enhance the value of Power's generation assets in Connecticut.

      The Midwest is also expected to have excess capacity over the next several years due to recent additions, which will continue to negatively impact the expected returns of Power's Lawrenceburg and Waterford facilities. The drivers to reduce the excess capacity will be load growth, the retirement of certain plants, particularly older plants of competitors due to the weakened wholesale energy and capacity market, and increased costs associated with higher levels of environmental compliance.

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      PJM continues to expand. On May 1, 2004, Commonwealth Edison Company joined PJM. On June 17, 2004, FERC issued two orders to allow the operating affiliates of American Electric Power (AEP) Service Corporation to transfer transmission facilities in Virginia to PJM's control and to allow AEP's Kentucky operating company to join PJM. AEP joined PJM effective October 1, 2004. On January 1, 2005, Duquesne Light Company joined PJM. In addition, FERC has conditionally approved Virginia Electric and Power Company's, a unit of Dominion Resources Inc., application to join PJM. These changes bring both opportunities and risks to Power.

      Power's businesses are also under competitive pressure due to technological advances in the power industry and increased efficiency in certain energy markets. It is possible that advances in technology, such as distributed generation, will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production.

      Additional legislation in the states where Power operates or into which Power sells energy has been introduced within the last few years to further encourage competition at the retail level (often referred to as customer choice or retail access). However, there is a risk if states should decide to turn away from competition and allow regulated utilities to continue to own or reacquire and operate generating stations in a regulated and potentially uneconomical manner. This has already occurred in certain states in which Power does business. The lack of consistent rules in markets outside of PJM can negatively impact the competitiveness of Power's plants. Also, regional inconsistencies in environmental regulations, particularly those related to emissions, have put some of Power's plants which are located in the Northeast, where rules are more stringent, at an economic disadvantage compared to its competitors in certain Midwest states.

      Customers

      As EWGs, Power's subsidiaries do not directly serve retail customers. Power uses its generation facilities primarily for the production of electricity for sale at the wholesale level. Power's customers consist mainly of wholesale buyers, primarily within PJM, but also in New York, Connecticut and the Midwest. Power is a direct supplier of New Jersey's EDCs. In addition, Power extended into the New England Power Market by securing a three-year, full requirements contract with a Connecticut utility with an expected peak load of 1,150 MW expiring December 31, 2006. In addition, Power has entered into four-year contracts totaling 500 MW with two Pennsylvania utilities, expiring in 2008 and is considering pursuing similar opportunities in other states.

      Employee Relations

      As of December 31, 2004, Power had 2,935 employees. Power has collective bargaining agreements with three union groups, which expire on April 30, 2005, October 31, 2005 and May 15, 2006, respectively. New six-year collective bargaining agreements were ratified with the three union groups in February 2005. These agreements cover 1,449 employees (701 employees, or approximately 65% of the workforce for Fossil and 748 employees, or approximately 45% of the workforce for Nuclear). Power believes that it maintains satisfactory relationships with its employees. For additional information, see Item 7. MD&A—Overview of 2004 and Future Outlook—Merger Agreement and Note 25. Merger Agreement of the Notes.

      Energy Holdings

      Energy Holdings is a New Jersey limited liability company and is the successor to PSEG Energy Holdings Inc., which was originally incorporated in 1989. Energy Holdings' principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. Energy Holdings has two principal direct wholly-owned subsidiaries, which are also its segments: Global and Resources.

      Energy Holdings has pursued investment opportunities in the global energy markets, with Global focusing on the operating segments of the electric industries and Resources primarily making financial investments in these industries. Global and Resources have more than 70 financial and operating investments.

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      Energy Holdings' portfolio is diversified by number, type and geographic location of investments. As of December 31, 2004, its assets were comprised of the following types:

      The characteristics of each of these investment types are described in more detail below.

      Global

      Global is a power producer and distributor that owns and operates electric generation and distribution facilities in selected domestic and international markets.

      As of December 31, 2004, Global's assets, which include consolidated projects and those accounted for under the equity method, share of project MW and number of customers by region are as follows:

      Global realized substantial growth prior to 2002, but has been faced with significant challenges as the international electricity privatization model has become stressed. These challenges include the losses incurred on the abandonment of Global's Argentine investments in 2002, the devaluation of the Brazilian Real and the corresponding decrease in earnings and cash flow from Global's investment in Rio Grande Energia S.A. (RGE), the impact of other foreign currency fluctuations and the failure of certain counterparties to honor contracts with certain of Global's investments. In 2003, Global began to review its portfolio and to seek to opportunistically monetize investments that no longer had a strategic fit. As part of this strategy, in May 2004, Global completed the sale of its majority interest in Carthage Power Company (CPC) in Rades, Tunisia. In December 2004, Global completed the sale of its 50% equity interest in Meiya Power Company Limited (MPC) to BTU Power Company. For additional information relating to these dispositions, see Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes.

      Global has placed its near-term emphasis on maintaining adequate liquidity and improving profitability of currently held investments. While Global still expects certain of its investments in South America to

11

contribute significantly to its earnings in the future, adverse political and economic risks associated with this region could have a material adverse impact on such investments.

      Global has sought to minimize risk in the development and operation of its generation projects by selecting partners with complementary skills, structuring long-term power purchase contracts, arranging financing prior to the commencement of construction and contracting for adequate fuel supply. Historically, Global's operating affiliates have entered into long-term power purchase contracts, thereby selling the electricity produced for the majority of the project life. However, two plants in Texas, Guadalupe (1,000 MW) and Odessa (1,000 MW), and one plant in Poland, Skawina CHP Plant (Skawina) (439 MW), operate as merchant plants without long-term power purchase agreements (PPAs).

      Global, to the extent practical, attempts to limit its financial exposure associated with each project and to mitigate development risk, foreign currency exposure, interest rate risk and operating risk, including exposure to fuel costs, through contracts. For additional information related to these risks, see Item 7A. Qualitative and Quantitative Disclosures About Market Risk. In addition, project loan agreements are generally structured on a non-recourse basis. Further, Global generally structures project financings so that a default under one project's loan agreement will have no effect on the loan agreements of other projects or Energy Holdings' debt.

      Fuel supply arrangements are designed to balance long-term supply needs with price considerations. Global's project affiliates generally utilize a combination of long-term contracts and spot-market purchases. 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.

      See Item 2. Properties—Energy Holdings for discussion of individual investments.

      Resources

      Resources invests in energy-related financial transactions and manages a diversified portfolio of assets, including leveraged leases, operating leases, leveraged buyout funds, limited partnerships and marketable securities. Established in 1985, Resources has a portfolio of more than 50 separate investments. Based on current market conditions and Energy Holdings' intent to limit capital expenditures, it is unlikely that Resources will make significant additional investments in the near term.

      Also, the Demand Side Management (DSM) business, previously managed by PSEG Energy Technologies Inc. (Energy Technologies) was transferred to Resources as of December 31, 2002. DSM revenues are earned principally from monthly payments received from utilities, which represent shared electricity savings from the installation of the energy efficient equipment.

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      The major components of Resources' investment portfolio as a percent of its total assets as of December 31, 2004 were:

      As of December 31, 2004, no single investment represented more than 9% of Resources' total assets.

      Leveraged Lease Investments

      Resources maintains a portfolio that is designed to provide a fixed rate of return. Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as Operating Revenues as these events occur in the ordinary course of business of managing the investment portfolio.

      In a leveraged lease, the lessor acquires an asset by obtaining equity representing approximately 15% to 20% of the cost and incurring non-recourse lease debt for the balance. The lessor acquires economic and tax ownership of the asset and then leases it to the lessee for a period of time no greater than 80% of its remaining useful life. As the owner, the lessor is entitled to depreciate the asset under applicable federal and state tax guidelines. In addition, the lessor receives income from lease payments made by the lessee during the term of the lease and from tax receipts associated with interest and depreciation deductions with respect to the leased property. The ability of Resources to realize these tax benefits is dependent on operating gains generated by its affiliates and allocated pursuant to PSEG's consolidated tax sharing agreement. Lease rental payments are unconditional obligations of the lessee and are set at levels at least sufficient to service the non-recourse lease debt. The lessor is also entitled to any residual value associated with the leased asset at the end of the lease term. An evaluation of the after-tax cash flows to the lessor determines the return on the investment. Under accounting principles generally accepted in the U.S. (GAAP), the lease investment is recorded on a net basis and income is recognized as a constant return on the net unrecovered investment.

      Resources has evaluated the lease investments it has made against specific risk factors. The assumed residual-value risk, if any, was analyzed and verified by third parties at the time the investment was made. Credit risk was assessed and, if necessary, mitigated or eliminated through various structuring techniques, such as defeasance mechanisms and letters of credit. Resources has not taken currency risk in its cross-border lease investments. Transactions have been structured with rental payments denominated and payable in U.S. Dollars. Resources, as a passive lessor or investor, has not taken operating risk with respect to the assets it owns, so leveraged leases have been structured with the lessee having an absolute obligation to make rental payments whether or not the related assets operate. The assets subject to lease are an integral element in Resources' overall security and collateral position. If such assets were to be impaired, the rate of return on a

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particular transaction could be affected. The operating characteristics and the business environment in which the assets operate are, therefore, important and must be understood and periodically evaluated. For this reason, Resources retains experts to conduct appraisals on the assets it owns and leases, as necessary.

      Resources' ten largest lease investments as of December 31, 2004 were as follows:

      For additional information on leases, including credit, tax and accounting risk related to certain lessees, see Item 7. MD&A—Results of Operations—Energy Holdings and Item 7A. Qualitative and Quantitative Disclosures About Market Risk—Credit Risk—Energy Holdings.

      Other Subsidiaries

      Enterprise Group Development Corporation (EGDC), a commercial real estate property management business, is conducting a controlled exit from the real estate business. Total assets of EGDC as of December 31, 2004 and 2003 were $72 million and $86 million, respectively, and include development land in New Jersey, Maryland and Virginia and an 80% partnership interest in buildings and land in New Jersey.

      Competitive Environment

      Energy Holdings and its subsidiaries continue to experience substantial competition, both in the U.S. and in international markets. In the U.S., an overbuild in generation facilities has led to a large capacity surplus in several regions, including Texas. This has resulted in reduced operating margins for both independent power producers and utility generators where the marketplace has been evolving from a rate-regulated structure to a competitive environment. Global anticipates that these matters in Texas may improve in the long term, leading to higher capacity prices and increased utilization of its facilities.

      In addition, the Polish government is seeking to renegotiate existing PPAs that it believes to be uncompetitive in the local energy market. With respect to Global's distribution businesses in Chile, Peru and Brazil, these investments are rate-regulated and are exposed to minimal risks from competitors. See Regulatory Issues—International Regulation for additional information.

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      Customers

      Global has ownership interests in four distribution companies in South America which serve approximately 2.9 million customers and has developed or acquired interests in electric generation facilities which sell energy, capacity and ancillary services to numerous customers through PPAs, as well as into the wholesale market. For additional information, see Item 2. Properties—Energy Holdings.

      Employee Relations

      As of December 31, 2004, Energy Holdings had 68 employees. Energy Holdings believes that it maintains satisfactory relationships with its employees. For additional information, see Item 7. MD&A—Overview of 2004 and Future Outlook—Merger Agreement and Note 25. Merger Agreement of the Notes.

Services

      Services is a New Jersey corporation with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Services provides management and administrative services to PSEG and its subsidiaries. These include accounting, legal, communications, human resources, information technology, treasury and financial, investor relations, stockholder services, real estate, insurance, risk management, tax, library and information services, security, corporate secretarial and certain planning, budgeting and forecasting services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to the terms and conditions of intercompany service agreements. As of December 31, 2004, Services had 1,183 employees, including 114 unionized employees. A new six-year collective bargaining agreement with the union group was ratified in February 2005. Services believes that it maintains satisfactory relationships with its employees. For additional information, see Item 7. MD&A—Overview of 2004 and Future Outlook—Merger Agreement and Note 25. Merger Agreement of the Notes.

REGULATORY ISSUES

Federal Regulation

      PSEG, PSE&G, Power and Energy Holdings

      PUHCA

      PSEG has claimed an exemption from regulation by the SEC as a registered holding company under PUHCA, except for Section 9(a)(2) thereof, which relates to the acquisition of 5% or more of the voting securities of an electric or gas utility company. Fossil, Nuclear, certain subsidiaries of Fossil and certain subsidiaries of Energy Holdings with domestic operations are EWGs. In addition, several of Energy Holdings' investments include foreign utility companies (FUCOs) under PUHCA and Qualifying Facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 (PURPA). If PSEG were no longer exempt under PUHCA, or if the subsidiaries' investments failed to maintain their status as EWGs, FUCOs or QFs, PSEG and its subsidiaries may 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 they would be permitted to make. PSEG does not believe, however, that this would have a material adverse effect on it and its subsidiaries.

      Environmental

      PSEG and its subsidiaries are also subject to the rules and regulations relating to environmental issues promulgated by the U.S. Environmental Protection Agency (EPA), the U.S. Department of Energy (DOE) and other regulators. For information on environmental regulation, see Environmental Matters.

      FERC

      FERC is an independent federal agency that regulates the transmission of electric energy and sale of electric energy at wholesale prices in interstate commerce pursuant to the Federal Power Act. FERC also regulates the interstate transportation of, as well as certain wholesale sales of, natural gas pursuant to the Natural Gas Act. Several PSEG subsidiaries including PSE&G, Fossil, Nuclear, ER&T and certain subsidiaries of Fossil and certain subsidiaries of Energy Holdings with domestic operations are public utilities subject to regulation by FERC. FERC's regulation of public utilities is comprehensive and governs such

15

matters as rates, services, mergers, financings, affiliate transactions, market behaviors and reporting. FERC is also responsible under PURPA for administering PURPA's requirements for QFs.

      Power

             Reliability Must-Run (RMR) Status in PJM and New England

      In September 2004, Power filed notice with PJM that it was considering the retirement of seven generating units in New Jersey, effective December 7, 2004, due to concerns about whether the units were economically viable under the current market structure. The units being considered for retirement are Sewaren 1, 2, 3 and 4, Kearny 7 and 8 and Hudson 1. The sites where the units are located have other electric generating units that would remain in operation. The units that were the subject of the notice have a combined installed capacity of 1,132 MW and a combined book value of $22 million. In response to Power's filed notice, PJM identified certain system reliability concerns associated with the retirements and said it would initiate meetings with Power on these and other issues designed to address these concerns including the compensation necessary to retain the generating units, discussed below.

      Although applicable tariff provisions differ from region to region, RMR tariff provisions provide compensation to a generation owner when a unit proposed for retirement must continue operating for reliability purposes. On November 2, 2004, PJM filed with FERC to amend its Tariff and Operating Agreement. This filing sets forth a RMR compensation mechanism for those generation units in PJM that are scheduled to be retired or mothballed but would remain necessary for reliability. Under the proposal, RMR compensation would be in the form of cost-of-service recovery or recovery of going-forward costs plus a fixed cost adder. By order dated January 25, 2005, FERC approved the RMR compensation mechanism set forth in the November 2, 2004 filing. It is anticipated that the Sewaren 1, 2, 3 and 4 and Hudson 1 units will qualify for RMR treatment under these procedures at least through the summer of 2006. In February 2005, Power requested that FERC approve cost-of-service recovery rates for the Sewaren and Hudson units. If approved the rates would provide approximately $23 million and $17 million of annual revenue for the Sewaren and Hudson units, respectively. The Kearny 7 and 8 units, however, require significant repairs before they can be returned to operational status and it is not anticipated that this work can be performed in time for the units to be available for the summer of 2005, which is the only period for which PJM has identified a reliability need for them. As a result, it does not appear that these units will be eligible for RMR treatment under the PJM procedures.

      In the New England electricity market, many owners of generation facilities have filed with FERC for RMR treatment under the NEPOOL Open Access Transmission Tariff. If FERC grants RMR status for a generation facility, the owner is entitled to receive cost-of-service treatment for its facility for the duration of an RMR contract that it enters into with ISO New England Inc. On November 17, 2004, PSEG Power Connecticut LLC (Power Connecticut), a Power subsidiary, filed a request for RMR treatment for the New Haven Harbor generation station and Unit 2 at the Bridgeport Harbor generation station. Numerous parties, including the Connecticut Department of Public Utility Control, the Connecticut Attorney General and various consumer groups, opposed this filing. On January 14, 2005, FERC issued an order that accepted the filing, suspended its effectiveness for a nominal period of 60 days, and set certain issues for hearing and settlement procedures. Beginning on January 14, 2005, subject to refund and hearing, Power Connecticut began collecting a monthly fixed payment amount of approximately $1.6 million for reliability services provided by the Bridgeport Harbor Station, Unit 2 and approximately $3.9 million for reliability services performed by the New Haven Harbor Station. By their terms, the RMR contracts expire when a locational installed capacity mechanism becomes effective in New England, which, according to FERC's directives, is expected to occur on January 1, 2006. The first RMR settlement conference was held on February 8, 2005. It is anticipated that settlement discussions will continue for a 60-day period, at a minimum. Power Connecticut believes that it has meritorious positions with respect to the issues set for hearing and settlement; however, a final outcome of this process cannot be determined at this time. In addition, it is anticipated that certain parties opposing the filing will seek rehearing of the January 14, 2005 order and, following the exhaustion of remedies at FERC, could seek judicial review. Settlement of challenges to the order would result in dismissal by the settling parties. While Power Connecticut does not believe such challenges are likely to be successful, Power Connecticut cannot predict a final outcome at this time.

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      PSEG, PSE&G and Power

             Regional through and out rates (RTOR)

      RTOR are separate transmission rates for transactions where electricity originated in one transmission control area was transmitted to a point outside that control area. Both the Midwest Independent Transmission System Operator, Inc. (MISO) and PJM charged RTORs through December 1, 2004. Under an order dated November 18, 2004, FERC approved a new regional rate design which became effective December 1, 2004 for the entire PJM/MISO region. FERC's order also approved the continuation of license plate or concentrated rates with a transitional Seams Elimination Charge/Cost Adjustment/Assignment (SECA) methodology effective from December 1, 2004 through March 2006.

      PSEG and its subsidiaries, along with other stakeholders, jointly (1) filed for rehearing of the November 18, 2004 order as it relates to the imposition of a SECA charge, (2) protested the SECA compliance filings and (3) protested and moved to reject the filing of AEP, Commonwealth Edison Company and Dayton Power & Light Company (New PJM Companies) to collect certain lost revenues resulting from the elimination of RTORs between PJM transmission owners. This request for rehearing is currently pending. On November 30, 2004, FERC issued an order that allowed the New PJM Companies to make a filing with FERC to collect their lost revenues. On December 1, 2004, PSE&G began charging its BGS-FP customers for the increase in transmission charges. Consistent with the terms of the BGS-FP contracts, ER&T (and other BGS-FP suppliers) will not receive any revenue associated with a BGS-FP pass-through of the SECA charge until the FERC's November 18, 2004 order is final and non-appealable. In the case of BGS-CIEP, it is anticipated that pass-through of the SECA charge will commence at the time when PJM begins billing of the SECA. Pursuant to a reciprocity provision in its tariff, PJM will not bill for the SECA until MISO commences billing of the SECA, which is estimated to be during March or April 2005. This delay in billing may allow sufficient time for FERC to rule on the protests before the Regional Transmission Organizations (RTOs) begin SECA billing, subject to refund. On February 10, 2005, FERC issued an order that accepted various SECA filings, established December 2004 as the effective date for the SECA rates, made them subject to refund and surcharge, and established hearing procedures to resolve the outstanding factual issues raised in the filings and the responsive pleadings. Depending on the outcome of this proceeding, which cannot be predicted at this time, PSEG, PSE&G and/or Power's results of operations could be negatively affected.

             PJM Expansion

      For information on PJM expansion, see Item 1. Business—Power—Competitive Environment.

      PSEG, PSE&G, Power and Energy Holdings

             Market Power

      Under FERC regulations, public utilities may sell power at cost-based rates or apply to FERC for authority to sell at market-based rates (MBR). PSE&G, Fossil, Nuclear, ER&T and certain subsidiaries of Fossil, have applied for and received MBR authority from FERC.

      On April 14, 2004, FERC issued a final order revising its generation market power screen, which it uses to determine whether power sellers may have the ability to exercise market power. Upon application by a power seller, if FERC determines that a seller is not able to exercise market power under the screen, and the seller passes other tests, FERC's rules permit the seller to sell power at MBR. Failing FERC's revised screen will not conclusively determine whether an entity has market power, and applicants failing the test will have the ability to demonstrate that they do not possess market power despite the screen failure. The screen includes two separate analyses: (1) an uncommitted pivotal supplier analysis and (2) a market share analysis that is to be prepared on a seasonal basis. FERC eliminated an exemption that previously existed for generators in RTOs and Independent System Operators (ISOs), such as PJM and New York ISO (NYISO), and will require all entities that wish to sell at MBR to comply with the revised market power screen.

      Also on April 14, 2004, FERC issued a notice that it will commence a pre-rulemaking to analyze the adequacy of its overall process used to consider whether an applicant is entitled to MBR authority. On July 8, 2004, FERC clarified that MBR applicants may net their supply against load-following or provider of last resort contracts, such as obligations to supply BGS in New Jersey, within the screen.

      PSEG Lawrenceburg Energy Company LLC (Lawrenceburg) and PSEG Waterford Energy LLC (Waterford), indirect wholly-owned subsidiaries of Power, filed their respective triennial market power

17

reviews in August 2004, and received a notice from FERC on November 16, 2004 requesting further information as to whether Lawrenceburg and Waterford comply with FERC's revised market power screen in combination with other generation assets that their affiliates own in PJM. FERC required this new information by February 7, 2005, and Lawrenceburg and Waterford provided the required information by that date. Power is scheduled for its next triennial market power review in 2006. Despite the request for further information, Power continues to believe that the new market power rules as adopted by FERC will not have a material adverse effect on Power's ability to sell at MBR, although no assurances can be given.

      On October 6, 2004, FERC issued a Notice of Proposed Rulemaking (NOPR) regarding reporting requirements for changes in status for entities with MBR authority. On February 10, 2005, FERC issued a final rule in this proceeding that requires entities with MBR to report to FERC within 90 days any changes in circumstances that FERC relied upon in granting MBR authority, and requires FERC to reevaluate MBR status following such an update. The final rule may require updates to FERC upon an acquisition, merger, generation retirement, contract execution or any other event that could affect the facts upon which FERC ruled in granting MBR to an entity. PSEG, PSE&G, Power and Energy Holdings cannot predict the impact, if any, that this rule will have on their operations.

             Standards of Conduct

      Since 1996, FERC has maintained standards of conduct governing the relationship between transmission providers and their domestic wholesale generation affiliates. These rules prevent domestic wholesale generation affiliates of a transmission provider from gaining an anticompetitive advantage over entities that are not affiliated with a transmission provider by obtaining non-public transmission information or preferential treatment from the affiliated transmission provider. In late 2003, FERC extended the applicability of its standards of conduct to gas and electric transmission providers and their energy affiliates. On April 16, 2004, FERC issued an order on rehearing that further revised and clarified its standards of conduct for transmission providers and their energy affiliates. The revised rules apply to the relationship between PSE&G, as an electric transmission provider, and (1) wholesale sales or marketing employees of PSE&G and (2) employees of Power and certain domestic subsidiaries of Energy Holdings. As of December 31, 2004, PSE&G and the applicable subsidiaries of PSEG believe that they are in compliance with FERC's revised standards of conduct, and posted written procedures on FERC's Open Access Same-Time Information System (OASIS) for compliance with FERC's standards of conduct.

             RTO Accounting Treatment

      On September 16, 2004, FERC issued a NOPR for the purpose of considering standard accounting and financial reporting rules for RTOs, ISOs and transmission owners within RTOs or ISOs. The proposed rule generally focuses on ensuring consistency in the reporting of costs by RTOs, ISOs and transmission owners within RTOs and ISOs. PSE&G, Power and Energy Holdings cannot predict the impact, if any, that these proceedings will have on their respective businesses.

      PSE&G

             Neptune Complaint Proceeding

      On December 21, 2004, Neptune Regional Transmission System, LLC (Neptune) filed a complaint with FERC against PJM. Neptune is a 660 MW merchant transmission project running from central New Jersey to Long Island, with an expected in-service date of June 2007. Neptune is directly interconnected to the transmission system of FirstEnergy Corporation (FirstEnergy), but upgrades to the PSE&G transmission system will also be required to move power across the grid. In its complaint, Neptune alleges that PJM impermissibly conducted an interconnection re-study triggered by generator retirements in PJM, which had the effect of increasing Neptune's cost exposure for network upgrades from approximately $4 million to approximately $26 million. Neptune is thus seeking to cap its cost exposure for upgrades. On February 10, 2005, FERC granted Neptune's complaint against PJM. In this order, FERC directed PJM to provide an Interconnection Agreement to Neptune within 10 days of the date of the order, which agreement will limit Neptune's cost responsibility for network upgrades to $4.4 million. FERC expressly declined to determine which entity(ies) would be responsible for paying the cost difference between $4.4 million and $26 million, noting that these issues would be addressed once transmission service is requested on the Neptune line. All affected parties in this proceeding are expected to seek rehearing of the FERC order, and may seek judicial

18

review as well. It is difficult to determine at this time whether PSE&G will be required to bear any portion of the upgrade costs related to the provision of transmission service on the Neptune line.

             Lower Delaware Valley (LDV) Complaint Proceeding

      On December 30, 2004, Jersey Central Power & Light Company (JCP&L) filed a complaint at the FERC against the other four signatories to the LDV Transmission System Agreement (LDV Agreement), including PSE&G. The LDV Agreement, which governs the construction of, and investment in, certain 500 kilovolt (kV) transmission facilities, was entered into by the parties in 1977 and remains in effect until 2027. JCP&L seeks to terminate its construction obligations under the LDV Agreement and to terminate its payment obligations to the other contract signatories under related agreements. PSE&G receives from JCP&L approximately $2.7 million annually under the LDV Agreement and its related agreements. PSE&G, along with the other LDV Agreement signatories, will file a response opposing the JCP&L complaint. At this time, PSE&G cannot predict the outcome of this proceeding.

      NRC

      PSEG and Power

      Nuclear's operation of nuclear generating facilities is subject to continuous regulation by the NRC, a federal agency established to regulate nuclear activities to ensure protection of public health and safety, as well as the security and protection of the environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstrations to the NRC that plant operations meet requirements are also necessary. The NRC has the ultimate authority to determine whether any nuclear generating unit may operate. The current operating licenses of Power's nuclear facilities expire in the years shown below:

      The NRC has issued orders to all nuclear power plants to implement compensatory security measures. Some of the requirements formalize a series of security measures that licensees had taken in response to advisories issued by the NRC in the aftermath of the September 11, 2001 terrorist attacks. Nuclear has evaluated these orders for the Salem, Peach Bottom and Hope Creek facilities and does not expect the cost of implementation of the additional NRC measures to be material. Security measures required to be in place by October 2004 have been completed at Salem, Hope Creek and Peach Bottom.

             Reactor Vessel Heads

      In 2002, the NRC issued a bulletin requiring that all operators of pressurized water reactor (PWR) nuclear units submit certain information related to potential degradation of reactor vessel heads. In 2003, the NRC issued an order to all operators of PWR units concerning reactor vessel head inspections. The order confirms the previous bulletin's requirements and adds more intrusive and frequent future inspections, which apply to Salem 1 and 2. In September 2002, Nuclear provided the requested information for Salem to the NRC, and performed inspections in accordance with the NRC order for Salem 1 and 2 during 2004 and 2003, respectively. The reactor heads were determined to be satisfactory for continued safe operation. Nuclear plans to replace Salem 1 and 2 reactor heads in 2005 as a preventive measure, during scheduled refueling outages.

      Also in 2003, the NRC issued a bulletin requiring that all operators of PWR nuclear units also perform inspections of the reactor vessel lower head, due to leakage observed at another nuclear unit not owned by Power. Bare metal visual examinations were completed during Salem 2's October 2003 outage and Salem 1's April 2004 outage, and no degradation was observed. Nuclear's Hope Creek nuclear unit and Peach Bottom 2 and 3 are unaffected by either of these bulletins as they are boiling water reactor nuclear units. Power cannot predict what other actions the NRC may take on this issue.

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             Nuclear Safety Issues

      On January 28, 2004, the NRC issued a letter requesting Power to conduct a review of its Salem and Hope Creek nuclear generation facilities to assess the workplace environment for raising and addressing safety issues. Power responded to the letter on February 28, 2004 and had independent assessments of the work environment at both facilities performed. The results of these assessments were provided to the NRC in May 2004. The assessments concluded that Salem and Hope Creek were safe for continued operations, but also identified issues that needed to be addressed.

      At an NRC public meeting on June 16, 2004, PSEG outlined its action plan to address these issues, which focused on a safety-conscious work environment, the corrective action program and work management. A letter documenting these plans and commitments was sent to the NRC on June 25, 2004. On July 30, 2004, the NRC provided a letter to PSEG indicating that it had completed its review. The letter indicated that the NRC had not identified any safety violations and that it appeared that the PSEG action plan would address the key findings of both the NRC and PSEG assessments. On August 30, 2004, the NRC provided Power with its mid-cycle performance reviews of Salem and Hope Creek, which detailed the NRC's plan for enhanced oversight related to the work environment. The letter indicated the NRC plans to continue with this heightened oversight until Power has concluded that substantial, sustainable progress has been made, and the NRC has completed a review that confirms Power's conclusions. Under the NRC oversight program, among other things, Power provided the NRC with a report of its progress at a public meeting in December 2004 and began publishing quarterly metrics to demonstrate performance in the fourth quarter of 2004. The next public meeting is scheduled for Spring 2005.

             Steam Pipe Failure

      On October 24, 2004, Power's Hope Creek nuclear generation facility transitioned to a planned refueling outage following the unit's shutdown on October 10, 2004 due to a steam pipe failure. Power's preliminary investigation revealed equipment and personnel performance issues associated with the shutdown. The NRC also investigated the event and held a public meeting on January 12, 2005. In the meeting, the NRC reviewed its findings, concurring with the root causes and corrective actions that Power had identified. In a letter to the NRC dated January 9, 2005, Power committed to install vibration-monitoring equipment on the “B” Reactor Recirculation Pump prior to the unit's return to service to address pump vibration concerns and replace the pump's shaft during the next refueling outage or any sooner outage of sufficient duration. This commitment was the subject of a January 11, 2005 Confirmatory Action Letter from the NRC. Hope Creek completed its refueling outage and returned to service on January 26, 2005.

      For additional information, see Note 14. Commitments and Contingent Liabilities of the Notes.

Other Regulatory Matters

      PSEG, PSE&G, Power and Energy Holdings

      American Jobs Creation Act of 2004 (Jobs Act)

      On October 22, 2004, President Bush signed into law the Jobs Act which provides a phased-in special deduction associated with pre-tax income from certain of PSEG's businesses, including Power's and Global's pre-tax income from domestic generation projects. This special deduction is equal to 3% of qualifying income for years 2005 and 2006, 6% in years 2007 through 2009 and 9% thereafter. This law is also expected to provide energy tax credits for certain renewable energy projects, including two projects at Global. Additionally, this law provides a one-year window to repatriate earnings from foreign investments and claim a special 85% dividends received tax deduction on such distributions. For additional information see Item 7. MD&A—Critical Accounting Estimates and Note 2. Recent Accounting Standards and Note 17. Income Taxes of the Notes.

      PSE&G

      Investment Tax Credits (ITC)

      For a discussion of an Internal Revenue Service (IRS) proposal that could have a material impact on PSE&G's treatment of ITCs, see Note 14. Commitments and Contingent Liabilities of the Notes.

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State Regulation

      PSEG, PSE&G, Power and Energy Holdings

      The BPU is the regulatory authority that oversees electric and natural gas distribution companies in New Jersey. PSE&G is subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service and the issuance and sale of securities. Power's partial ownership of nuclear generating facilities in Pennsylvania, as well as PSE&G's ownership of certain transmission facilities in Pennsylvania, are subject to regulation by the Pennsylvania Public Utility Commission (PPUC), which oversees the electric and natural gas industries in Pennsylvania. PSE&G and Power are also subject to rules and regulations of the New Jersey Department of Environmental Protection (NJDEP) and the New Jersey Department of Transportation (NJDOT).

      PSEG is not subject to direct regulation by the BPU, except potentially with respect to certain transfers of control and reporting requirements. Certain subsidiaries of PSEG and Power with operations in New Jersey may be subject to some regulation by the BPU, with respect to energy supply (BGS and BGSS), certain asset sales, transfers of control, reporting requirements and affiliate standards.

      Various Power subsidiaries and Energy Holdings' subsidiaries are subject to some state regulation in other individual states where they operate facilities, including New York, Connecticut, Indiana, Ohio, Texas, California, Hawaii and New Hampshire.

      PSE&G and Power

      BGSS Filing

      On April 9, 2004, PSE&G received the Administrative Law Judge's (ALJ) Initial Decision on the two remaining issues from the 2003/2004 BGSS Commodity Charge Proceeding, filed on May 30, 2003. Under the ALJ's Initial Decision, the partial settlement executed and submitted by the parties was approved. Moreover, under the Initial Decision, the New Jersey Rate Payer Advocate's (RPA) proposal to return pipeline refunds previously received by Power in September and November 2002 and the deferred cost balance as of May 1, 2002 retained by Power to commercial and industrial customers was rejected. On August 18, 2004, the BPU approved a stipulation authorizing a refund of approximately $6 million from Power to commercial and industrial customers in September 2004 and gave final approval to the partial settlement.

      On May 28, 2004, PSE&G filed its 2004/2005 BGSS commodity charge filing, requesting an increase in its BGSS commodity charges to its residential gas customers of approximately $47 million in annual revenues effective October 1, 2004 or approximately 3% for the class average residential heating customer. A provisional settlement was approved by the BPU on October 5, 2004. Under this settlement, PSE&G's filed BGSS rates became effective on October 5, 2004 on a provisional basis, subject to refund with interest. The BPU also ordered that PSE&G's filing be transferred to the Office of Administrative Law (OAL) for a full review and an Initial Decision. On January 4, 2005, the parties entered into a final settlement, which was approved by the ALJ on January 6, 2005. Under the final settlement, the provisional rates became final and all other issues raised during the proceeding were resolved. The BPU approved the ALJ Decision and Settlement with no changes on February 1, 2005.

      PSE&G

      Remediation Adjustment Clause (RAC) Filing

      PSE&G is currently implementing a program to address potential environmental concerns regarding its former Manufactured Gas Plant (MGP) properties in cooperation with and under the NJDEP. On March 5, 2004, the BPU approved PSE&G's RAC-10 petition, filed in June 2003, for the recovery of approximately $35 million of certain environmental remediation program expenditures for the period August 1, 2001 through July 31, 2002. The Final Decision and Order approved the Stipulation of Settlement from December 16, 2003, without exception.

      On April 22, 2004, PSE&G filed its RAC-11 filing with the BPU to recover approximately $36 million of remediation program expenditures for the period from August 1, 2002 through July 31, 2003. Public hearings were held in July 2004. On September 10, 2004, the ALJ issued an Initial Decision recommending approval of the settlement reached between all parties, allowing PSE&G to recover all requested costs. This will result in PSE&G recovering an additional $0.4 million annually in remediation program expenditures. On October 5,

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2004, the BPU issued a Final Decision and Order approving, in its entirety, the ALJ's Initial Decision recommending acceptance of the settlement.

      Cost Recovery Mechanism

      EDECA required that the BPU provide electric and natural gas customers with the opportunity to choose a supplier for some or all electric or natural gas customer account services (CAS). On July 1, 2004, PSE&G filed a petition with the BPU to implement the CAS Cost Recovery Mechanism for both the electric and gas operations. The request petitions the BPU for the approval to recover $4 million of CAS costs and accumulated interest resulting from implementing PSE&G's dual billing for its delivery costs and for the third-party suppliers' commodity charges as a result of customer migration from PSE&G. On September 21, 2004, the case was transferred to the OAL as a contested case.

      Deferral Audit

      The BPU Energy and Audit Division conducts audits of deferred balances. A draft Deferral Audit—Phase II report relating to the 12-month period ended December 31, 2003 was released by the consultant to the BPU in February 2005. The draft report addressed the Societal Benefits Clause (SBC), Market Transition Charge (MTC) and Non-Utility Generation (NUG) deferred balances.

      While the consultant to the BPU found that the deferral balances complied in all material respects with the BPU Orders regarding such deferrals, the consultant noted that the BPU Staff had raised certain questions with respect to the reconciliation method PSE&G employed in calculating the overrecovery of its MTC and other charges during the four-year transition period. PSE&G and the BPU Staff are continuing discussions to resolve these questions and, if a resolution cannot be achieved, a BPU proceeding may be instituted to consider the issues raised.

      While PSE&G believes the MTC methodology it used was fully litigated and resolved, without exception, by the BPU and other intervening parties in its previous electric base rate case, deferral audit and deferral proceeding that were approved by the BPU in its order of April 22, 2004, and that such order is non-appealable, PSE&G cannot predict the impact of the outcome of any such proceeding, which could be material.

      Levelized Gas Adjustment Clause (LGAC)/BGSS Audit

      The BPU's Division of Audit reviews gas costs of utilities in New Jersey on a regular basis. As part of its regular review in November 2004, the BPU commenced an audit of the gas supply costs incurred during the period October 1, 1999 through September 30, 2004. The outcome of the audit cannot be determined at this time.

      New Jersey Clean Energy Program

      The BPU has approved a new funding requirement for each New Jersey utility applicable to Renewable Energy and Energy Efficiency programs for the years 2005 to 2008. The sum of PSE&G's electric and gas funding requirement for 2005 is $82 million and grows to $137 million in 2008 for a four-year total of $406 million, a liability that has been recorded at discounted present value with an offsetting regulatory asset. The BPU is seeking new program managers for the Energy Efficiency program, currently being administered by the utilities. The transition from the utilities to the program managers is expected to take place in mid-2005.

International Regulation

      Energy Holdings

      Global

      Global's electric distribution facilities in South America and Oman are rate-regulated enterprises. Rates charged to customers are established by government authorities and are viewed by Global as currently sufficient to cover all operating costs and provide a return. Global can give no assurances that future rates will be established at levels sufficient to cover such costs, provide a return on its investments or generate

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adequate cash flow to pay principal and interest on its debt or to enable it to comply with the terms of its debt agreements.

      Brazil

      RGE is regulated by Agencia Nacional de Energia Eletrica (ANEEL), the national regulatory authority. ANEEL's functions include granting and supervising electric utility concessions, approving electricity tariffs, issuing regulations and auditing distribution systems' performance. The rate setting process for Brazilian distribution companies has two components: an annual adjustment for which RGE applies every April which is embedded in the concession contract and a rate case revision, which was last conducted in 2003 and will be repeated again every fifth year.

      In 2004, RGE received a 15% tariff increase adjustment based on 2003 annual inflation. In April 2005, RGE will apply for the annual rate case adjustment. Based on 2004 annual inflation and other postponed increases, Global expects that RGE should be granted a 15% tariff increase, although no assurances can be given.

      Chile

      Distribution companies in Chile, including Chilquinta Energia S.A. (Chilquinta), Sociedad Austral de Electricidad S.A. (SAESA) and other members of the SAESA Group, are subject to rate regulation by the Comision Nacional de Energia (CNE), a national governmental regulatory authority. The Chilean regulatory framework has been in existence since 1982, with rates set every four years based on a model company for each typical concession area. The tariff which distribution companies charge to regulated customers consists of two components: the actual cost of energy purchased plus an additional amount to compensate for the value added in distribution (DVA tariff). The DVA tariff considers allowed losses incurred in the distribution of electricity, administrative costs of providing service to customers, costs of maintaining and operating the distribution systems and an annual return on investment of 6% to 14% over inflation based on the replacement cost of distribution assets. Changes in electricity distribution companies' cost of energy are passed through to customers, with no impact on the distributors' margins (equal to the DVA tariff). Therefore, distributors, including members of the SAESA Group and Chilquinta, should not be affected by changes in the generation sector which affect prices. The most recent tariff adjustments for members of the SAESA Group and Chilquinta occurred in 2004 and have been reviewed and approved by CNE.

      Peru

      Distribution companies in Peru, including Luz del Sur (LDS), are subject to tariff regulation by the Organismo Supervisor de la Inversión en Energí a, a national governmental regulatory authority. The Peruvian regulatory framework has been in existence since 1992, with tariffs set every four years based on a model company. The tariff which distribution companies charge to regulated customers consists of two components: the actual cost of energy purchased plus an additional amount to compensate for the value added in distribution (DVA tariff). The DVA tariff considers allowed losses incurred in the distribution of electricity, administrative costs of providing service to customers, costs of maintaining and operating the distribution systems and an annual return on investment of 8% to 16%, based on the replacement cost of distribution assets. Changes in electricity distribution companies' cost of energy are passed through to customers, with no impact on the distributors' margins (equal to the DVA tariff). Therefore, distributors, including LDS, should not be affected by changes in the generation sector which affect prices. The most recent tariff adjustments for LDS occurred in 2001 and the 2005 tariff setting process is currently in progress. New tariffs will be applicable as of November 1, 2005.

SEGMENT INFORMATION

      Financial information with respect to the business segments of PSEG, PSE&G, Power and Energy Holdings is set forth in Note 20. Financial Information by Business Segments of the Notes.

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ENVIRONMENTAL MATTERS

      PSEG, PSE&G, Power and Energy Holdings

      Federal, regional, state and local authorities regulate the environmental impacts of PSEG's operations within the U.S. Laws and regulations particular to the region, country or locality where PSEG's operations are located govern the environmental impacts associated with its foreign operations. For both domestic and foreign operations, areas of regulation may include air quality, water quality, site remediation, land use, waste disposal, aesthetics, impact on global climate and other matters.

      To the extent that environmental requirements are more stringent and compliance more costly in certain states where PSEG operates compared to other states that are part of the same market, such rules may impact its ability to compete within that market. Due to evolving environmental regulations, it is difficult to project expected costs of compliance and its impact on competition. For additional information related to environmental matters, see Item 3. Legal Proceedings.

      PSEG, Power and Energy Holdings

      Air Pollution Control

      The Federal Clean Air Act (CAA) and its implementing regulations require controls of emissions from sources of air pollution and also impose record keeping, reporting and permit requirements. Facilities in the U.S. that Power and Energy Holdings operate or in which they have an ownership interest are subject to these Federal requirements, as well as requirements established under state and local air pollution laws applicable where those facilities are located. Except as noted below, capital costs of complying with air pollution control requirements through 2009 are included in Power's estimate of construction expenditures in Item 7. MD&A—Capital Requirements.

      Prevention of Significant Deterioration (PSD)/New Source Review (NSR)

      For a discussion of PSD/NSR, see Note 14. Commitments and Contingent Liabilities of the Notes.

      Sulfur Dioxide (SO₂ )/Nitrogen Oxide (NO_x )

      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 with emissions greater than their allocations can obtain allowances from sources that have excess allowances. At this time, Power does not expect to incur material expenditures to continue complying with the SO₂ emissions program.

      The EPA has issued regulations (commonly known as the NO_x State Implementation Plan (SIP) Call) requiring the 19 states in the eastern half of the U.S. and the District of Colombia to reduce and cap NO_x emissions from power plant and industrial sources. The NO_x reduction requirements are consistent with requirements already in place in New Jersey, New York, Connecticut and Pennsylvania, and therefore have not had an additional impact on the capacity available from Power's facilities in those states. Power has been implementing measures to reduce NO_x emissions at several of its units (including the installation of selective catalytic reduction systems at the Mercer Generating Station), which should reduce the impact of any further increases to the costs of allowances. New facilities that Power developed in Ohio and Indiana became subject to rules that those states have promulgated to comply with the NO_x SIP Call. Because the rules in Ohio and Indiana both set aside allowances for allocation to new sources, Power did not experience any material adverse effects from complying with this program in these states.

      In 1997, the EPA adopted a new air quality standard for fine particulate matter and a revised air quality standard for ozone. In 2004, the EPA identified and designated areas of the U.S. that fail to meet the revised federal health standard for ozone or the new federal health standard for fine particulates. States are expected to develop regulatory measures necessary to achieve and maintain the health standards, which may require reductions in NO_x and SO₂ emissions. Additional NO_x and SO₂ reductions also may be required to satisfy requirements of an EPA rule protecting visibility in many of the nation's Class 1 (pristine) environmental areas, including most areas near Power's facilities. Power cannot at this time determine whether any costs it may incur to comply with these standards would be material.

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      In December 2003, the EPA announced its intent to propose an Interstate Air Quality Rule (IAQR) (which was renamed as the Clean Air Interstate Rule (CAIR)) that would identify 29 states and the District of Columbia as contributing significantly to the levels of fine particulates and/or eight-hour ozone in downwind states. New Jersey, New York, Pennsylvania and Connecticut are among the states the EPA lists in the proposed CAIR. Based on state obligations to address interstate transport of pollutants under the CAA, the EPA is proposing a two-phased emission reduction program for SO₂ and NO_x, with Phase 1 beginning in 2010 and Phase 2 beginning in 2015. The EPA is recommending that the program be implemented through a cap-and-trade program, although states are not required to proceed in this manner. States would have to submit plans to the EPA for complying with the rule within 18 months of publication of the notice of final rulemaking. The rule is anticipated to be finalized or re-proposed in 2005. Alternatively, Congress has also expressed interest in providing legislation to further improve air quality. Power cannot at this time determine whether any costs it may incur to comply with these standards would be material.

      Carbon Dioxide (CO₂ ) Emissions

      Countries participating in the Kyoto Protocol will be required to achieve material reductions of CO₂ and certain other greenhouse gases between 2008 and 2012. Although the U.S. has not ratified the treaty, Global's assets in Europe will be affected by implementation of the Kyoto Protocol, as adopted through regulations by the European Union (EU). At this time, these regulations are not anticipated to have a material effect on operations at Global's European assets in Poland and Italy.

      In 2002, Power announced a voluntary agreement that calls for a December 31, 2005 goal of reducing the annual average CO₂ emission rate of its New Jersey fossil fuel-fired electric generating units by 15% below the 1990 average annual CO₂ emission rate. Fossil also made a $1.5 million payment to the NJDEP to assist in the development of landfill gas projects and has agreed to make an additional payment equal to $1 per ton of CO₂ emitted greater than the 15% goal, up to $1.5 million, if that reduction is not achieved.

      PSEG joined the EPA Climate Leaders Program in February 2002. On January 13, 2004, PSEG established a goal of reducing its CO₂ emissions intensity by 18% per MWh generated (nuclear excluded) from 2000 levels by December 31, 2008. The goal would in part be met by re-powering the Bergen, Linden and Albany plants. PSEG has developed an emission inventory and is currently working with the EPA Climate Leaders Program to obtain approval of the inventory management plan.

      There continues to be a debate within the U.S. over the direction of change in domestic climate policy. Several states, primarily in the Northeastern U.S., are developing state-specific or regional legislative initiatives to stimulate CO₂ emission reductions in the electric power industry. For example, New York initiated the Regional Greenhouse Gas Initiative (RGGI) in April 2003 and the NJDEP in 2004 proposed amendments to its regulations governing air pollution control that would designate CO₂ as an air contaminant subject to regulation. Currently, in the RGGI, nine Northeastern states are participating in discussions intended to lead to a regional program to cap CO₂ emissions from the electric power sector in the region. The outcome of this initiative cannot be determined at this time; however, adoption of stringent CO₂ emission reduction requirements in the Northeast could materially impact Power's operations.

      Other Air Pollutants

      The CAA directed the EPA to study potential public health impacts of mercury and nickel hazardous air pollutants (HAP) 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 by requiring Maximum Achievable Control Technology (MACT) standards for these units. The EPA proposed the MACT standards in December 2003 and expects to promulgate a final rule by March 2005, with compliance expected by December 2007. PSEG is evaluating the potential impact of these proposed standards.

      The EPA announced in December 2003 its intent to propose alternative rules for addressing emissions of mercury from electric generating sources. The first alternative proposes to regulate mercury through the establishment of a MACT standard applicable on a unit-by-unit basis or through a cap-and-trade program. The MACT standard would establish mercury emission limits for all new and existing units and reduce nationwide mercury emissions by approximately 29% by December 2007. The second option requires the EPA to rescind its December 2000 announcement to regulate mercury as a HAP through a MACT standard and to regulate mercury through a cap-and-trade program to be implemented by changes to the states' individual SIPs that establish decreasing emission caps in 2010 and 2018. As part of the December 15, 2003

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proposal, the EPA is also proposing to set nickel MACT emission limits for oil-fired electric steam generating units.

      New Jersey and Connecticut have already adopted standards for the reduction of emissions of mercury from coal-fired electric generating units. The Connecticut legislation requires coal-fired power plants in Connecticut to achieve either an emissions limit or a 90% mercury removal efficiency through technology installed to control mercury emissions effective in July 2008. The regulations in New Jersey require coal-fired electric generating units in New Jersey to meet certain emission limits or reduce emissions by 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements are permitted to postpone such reductions on half of their coal-fired electric generating capacity until December 15, 2012. Power has a multi-pollutant reduction agreement with the NJDEP as a result of a consent decree that resolved issues arising out of the PSD and NSR air pollution control programs at the Hudson, Mercer and Bergen facilities. Substantial uncertainty exists regarding the feasibility of achieving the reductions in mercury emissions required by the New Jersey regulations and Connecticut statute; however, the costs of technology believed to be capable of meeting these emissions limits at Power's coal-fired unit in Connecticut by July 2008 and at its Mercer Station by December 15, 2007 are included in Power's capital expenditure forecast.

      Water Pollution Control

      The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to waters of the U.S. from point sources, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permit issued by the EPA or by a state under a federally authorized state program. The FWPCA authorizes the imposition of technology-based and water quality-based effluent limits to regulate the discharge of pollutants into surface waters and ground waters. The EPA has delegated authority to a number of state agencies, including the NJDEP, to administer the NPDES program through state acts. The New Jersey Water Pollution Control Act (NJWPCA) authorizes the NJDEP to implement regulations and to administer the NPDES program with EPA oversight, and to issue and enforce New Jersey Pollutant Discharge Elimination System (NJPDES) permits. Power and Energy Holdings also have ownership interests in domestic facilities in other jurisdictions that have their own laws and implement regulations to control discharges to their surface waters and ground waters that directly govern Power's or Energy Holdings' 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 covering new facilities became effective on January 17, 2002. None of the projects that Power currently has under construction or in development is subject to the Phase I rule. The Phase II rule covering large existing power plants became effective on September 7, 2004. The regulations provide the following five alternative methods by which a facility can demonstrate that it complies with the requirement for BTA for minimizing adverse environmental impacts associated with cooling water intake structures: (1) reduce flow commensurate with a closed-cycle system or reduce intake velocity; (2) meet applicable performance standards for reduction of entrainment and impingement mortality through the use of the existing design, construction, operational or restoration measures; (3) meet applicable performance standards through a combination of existing and proposed design, construction, operational or restoration measures; (4) installation of a design and construction technology specified by the regulation or pre-approved by the agency; and (5) a site-specific determination that the cost to the facility to meet the performance standards is “significantly greater” than either (a) the costs that the EPA estimated for that type of facility or (b) the environmental benefits of complying with the performance standards. Although the rule applies to all of Power's electric generating units that use surface waters for once-through cooling purposes, the impact of the rule to Power and the rule's ability to withstand legal challenges cannot be determined at this time. If application of the Phase II rules by the states requires the retrofitting of cooling water intake structures at Power's existing facilities, additional material capital expenditures could be required to modify the existing plants to enable their continued operations. Several environmental groups, the Attorneys General of six Northeastern states, the Utility Water Act Group and several of its members, including Power, are parties to litigation challenging the Phase II rule. The case will be heard in the U.S. Court of Appeals for the Second Circuit. The states and environmental groups have indicated that they intend to challenge the use of restoration and other measures to satisfy performance standards as well as a state's ability to make site-specific determinations based on cost tests. A decision issued in February 2004 by the Second Circuit in litigation challenging the Phase I rule (new facilities) struck down that rule's provision allowing for the use of

26

restoration measures to satisfy the specified performance standards. An unfavorable decision in the Phase II litigation could have a material impact on Power's ability to renew its NJPDES permits at its larger once-through cooled plants without significant upgrades to their existing intake structures and cooling systems.

      PSE&G and Power

Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and New Jersey Spill Compensation and Control Act (Spill Act)

      CERCLA and the Spill Act authorize Federal and state trustees for natural resources to assess damages against persons who have discharged a hazardous substance, causing an injury to natural resources. Pursuant to the Spill Act, the NJDEP requires persons conducting remediation to characterize injuries to natural resources and to address those injuries through restoration or damages. The NJDEP adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. In 2003, the NJDEP issued a policy directive memorializing its efforts to recover natural resource damages and its intent to continue to pursue the recovery of natural resource damages. The NJDEP also issued guidance to assist parties in calculating their natural resource damage liability for settlement purposes, but has stated that those calculations are applicable only for those parties that volunteer to settle a claim for natural resource damages before a claim is asserted by the NJDEP. PSE&G and Power cannot assess the magnitude of the potential financial impact of this regulatory change. See Note 14. Commitments and Contingent Liabilities of the Notes for additional information.

      Because of the nature of PSE&G's and Power's respective businesses, including the production and delivery 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 14. Commitments and Contingent Liabilities of the Notes. For a discussion of remediation/clean-up actions involving PSE&G and Power, see Item 3. Legal Proceedings.

      Uranium Enrichment Decontamination and Decommissioning Fund

      In accordance with the Energy Policy Act, 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 was $75 million (adjusted for inflation). As of December 31, 2004, PSE&G had paid $64 million, resulting in a balance due of $11 million. As of December 31, 2004, Power also had a balance due of approximately $2 million, which related to interests in certain nuclear units it purchased. These amounts are payable to the DOE in annual installments through October 2006.

      PSE&G and Power

      Permit Renewals

      In June 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. A renewal application prepared in accordance with the new Phase II 316(b) rule will be filed by February 1, 2006. Recently published regulations pursuant to Section 316(b) of the FWPCA require existing facilities, including Salem, to demonstrate that their cooling water intake structures reflect the BTA for minimizing adverse environmental impact through one of several options including the reduction of cooling water intake commensurate with closed cycle cooling. For additional information, see Environmental Matters—Water Pollution Control. The NJDEP, in anticipation of the company's application to renew the permit for Salem, has advised PSEG that it strongly recommends that cooling water intake flow at the Salem facility be reduced commensurate with closed cycle cooling. The installation of structures at the Salem facility to reduce cooling water intake flow commensurate with closed cycle cooling would result in material costs of compliance for Power. Power is

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evaluating its ability to demonstrate compliance with the new Phase II 316(b) rule through all applicable options available under the new rule.

      The consultant hired by the NJDEP to review the NJPDES permit renewal application and studies filed in the 1980s for the Hudson generating station recommended that the Hudson generating 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 in filings with the NJDEP in 1998. In the fourth quarter of 2004, Power received a modified NJPDES permit for its Hudson generating station that required the modification to the intake structures that Power had proposed consistent with the timing of upgrades of air pollution control technology pursuant to the consent decree that resolved issues related to NSR and PSD for Hudson Unit 2, but did not require Power to retrofit the station to operate with closed cycle cooling.

      The NJDEP has advised Power that it is reviewing a NJPDES permit renewal application and recent studies for the Mercer station and, in connection with these filings, will be re-examining the effects of the Mercer station's cooling water system pursuant to FWPCA. Power cannot predict the timing and/or outcome of NJDEP's review. An unfavorable outcome could require significant modifications to the Mercer station's cooling water system at material cost.

      Title V Operating Permits

      Title V of the CAA and Sub-Chapter 22 of the New Jersey Administrative Code require that certain air emissions sources obtain Operating Permits issued by NJDEP. All Power generating facilities are required to be included in Title V Operating Permits. The costs of compliance associated with any new requirements imposed by these permits are not known at this time, but may be material.

      Nuclear Fuel Disposal

      For a discussion of nuclear fuel disposal, see Note 14. Commitments and Contingent Liabilities of the Notes.

      Low Level Radioactive Waste (LLRW)

      As a by-product of their operations, nuclear generation units produce LLRW. Such wastes include paper, plastics, protective clothing, water purification materials and other materials. LLRW materials are accumulated on site and disposed of at licensed permanent disposal facilities. New Jersey, Connecticut and South Carolina have formed the Atlantic Compact, which gives New Jersey nuclear generators, including Power, continued access to the Barnwell LLRW disposal facility which is owned by South Carolina. Power believes that the Atlantic Compact will provide for adequate LLRW disposal for Salem and Hope Creek through the end of their current licenses, although no assurances can be given. Both Power and Exelon have on-site LLRW storage facilities for Salem, Hope Creek and Peach Bottom, which have the capacity for at least five years of temporary storage for each facility.

      PSE&G

      MGP Remediation Program

      For information regarding PSE&G's MGP Remediation Program, see Note 14. Commitments and Contingent Liabilities of the Notes.

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ITEM 2. PROPERTIES

PSEG and Services

      PSEG does not own any property. All property is owned by PSEG's subsidiaries.

      Services leases substantially all of a 25-story office tower for PSEG's corporate headquarters at 80 Park Plaza, Newark, New Jersey, together with an adjoining three-story building. In addition, the Maplewood Test Services in Maplewood, New Jersey was transferred to Services from Power in January 2004.

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.

      PSE&G's electric lines and gas mains 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 other rights are deemed by PSE&G to be adequate for the purposes for which they are being used.

      PSE&G believes that it maintains adequate insurance coverage against loss or damage to its principal properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost.

      Electric Transmission and Distribution Properties

      As of December 31, 2004, PSE&G's transmission and distribution system included approximately 21,735 circuit miles, of which approximately 7,754 circuit miles were underground, and approximately 757,646 poles, of which approximately 525,872 poles were jointly-owned. Approximately 99% of this property is located in New Jersey.

      In addition, as of December 31, 2004, 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, 2004, 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:

      As of December 31, 2004, PSE&G owned and operated approximately 17,064 miles of gas mains, owned 12 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 suppliers and were operated under lease, easement or other similar arrangement. In some instances, the pipeline companies owned portions of the metering and regulating facilities.

      Office Buildings and Facilities

      PSE&G rents office space from Services as its headquarters in Newark, New Jersey. PSE&G also leases office space at various locations throughout New Jersey for district offices and offices for various corporate

29

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, 2004, PSE&G owned 41 switching stations in New Jersey with an aggregate installed capacity of 21,203 megavolt-amperes and 242 substations with an aggregate installed capacity of 7,652 megavolt-amperes. In addition, four substations in New Jersey having an aggregate installed capacity of 109 megavolt-amperes were operated on leased property.

Power

      Power rents office space from Services as its headquarters in Newark, New Jersey. Other leased properties include office, warehouse, classroom and storage space, primarily located in New Jersey. Power also owns the Central Maintenance Shop at Sewaren, New Jersey.

      Power has a 57.41% ownership interest in approximately 13,000 acres in the Delaware River Estuary region to satisfy the condition of the NJPDES permit issued for Salem. Power also owns several other facilities, including the on site Nuclear Administration and Processing Center buildings.

      Power has a 13.91% ownership interest in the 650-acre Merrill Creek Reservoir in Warren County, New Jersey and approximately 2,158 acres of land surrounding the reservoir. The reservoir was constructed to store water for release to the Delaware River during periods of low flow. Merrill Creek is jointly-owned by seven companies that have generation facilities along the Delaware River or its tributaries and use the river water in their operations.

      Power believes that it maintains adequate insurance coverage against loss or damage to its plants and properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Note 14. Commitments and Contingent Liabilities of the Notes.

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      As of December 31, 2004, Power's share of installed generating capacity was 14,607 MW, as shown in the following table:

OPERATING POWER PLANTS

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      As of December 31, 2004, Power had generating capacity in construction or advanced development, as shown in the following table:

POWER PLANTS IN CONSTRUCTION OR ADVANCED DEVELOPMENT

Energy Holdings

      Energy Holdings rents office space from Services as its headquarters in Newark, New Jersey.

      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.

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      Global has invested in the following generation facilities that were in operation as of December 31, 2004:

OPERATING POWER PLANTS