**UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549**

****

**FORM 10-K**

**(Mark One)**

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

**FOR THE FISCAL YEAR ENDED DECEMBER 31, 2004,**

**OR**

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

**FOR THE TRANSITION PERIOD FROM                  TO                 .**

| **CommissionFile Number** | **Registrants, State of Incorporation,Address, and Telephone Number** | **I.R.S. EmployerIdentification No.** |
|---------------------------|-----------------------------------------------------------------------|---------------------------------------|
|                      | **001-09120**                                                         |                                  | **PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED(A New Jersey Corporation)80 Park Plaza, P.O. Box 1171Newark, New Jersey 07101-1171973 430-7000http://www.pseg.com** |   | **22-2625848** |   |
|                      | **001-00973**                                                         |                                  | **PUBLIC SERVICE ELECTRIC AND GAS COMPANY(A New Jersey Corporation)80 Park Plaza, P.O. Box 570Newark, New Jersey 07101-0570973 430-7000http://www.pseg.com** |   | **22-1212800** |   |
|                      | **000-49614**                                                         |                                  | **PSEG POWER LLC(A Delaware Limited Liability Company)80 Park Plaza—T25Newark, New Jersey 07102-4194973 430-7000http://www.pseg.com** |   | **22-3663480** |   |
|                      | **000-32503**                                                         |                                  | **PSEG ENERGY HOLDINGS LLC(A New Jersey Limited Liability Company)80 Park Plaza—T20Newark, New Jersey 07102-4194973 456-3581http://www.pseg.com** |   | **42-1544079** |   |

****

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

| **Registrant**                                  |   | **Title of Each Class**       |   | **Name of Each ExchangeOn Which Registered** |
|-------------------------------------------------|--------|-------------------------------|--------|----------------------------------------------|
| **Public Service EnterpriseGroup Incorporated** |   | Common Stock withoutpar value |   | New York Stock Exchange                      |

      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.

| **Registrant**                             |   | **Title of Each Class**                                |   | **Title of Each Class**                  |      | **Name of Each ExchangeOn Which Registered** |
|--------------------------------------------|--------|--------------------------------------------------------|--------|------------------------------------------|--------------------------|----------------------------------------------|
| **Public Service Electric andGas Company** |   | ***Cumulative Preferred Stock$100 par value Series:*** |   | ***First and RefundingMortgage Bonds:*** |                     |                                         |
|                                       |   |                                                   |   |                                     |      | ***Series***                                 |      | ***Due*** |   |   |
|                                       |   | 4.08%                                                  |   | 91⁄8%                              |      | BB                                           |      | 2005 |   |   |
|                                       |   | 4.18%                                                  |   | 91⁄4%                              |      | CC                                           |      | 2021 |   |   |
|                                       |   | 4.30%                                                  |   | 63⁄4%                              |      | UU                                           |      | 2006 |      | New York Stock Exchange |
|                                       |   | 5.05%                                                  |   | 63⁄4%                              |      | VV                                           |      | 2016 |   |   |
|                                       |   | 5.28%                                                  |   | 61⁄4%                              |      | WW                                           |      | 2007 |   |   |
|                                       |   |                                                   |   | 63⁄8%                              |      | YY                                           |      | 2023 |   |   |
|                                       |   |                                                   |   | 8%                                       |                     |                                         |      | 2037 |   |   |
|                                       |   |                                                   |   | 5%                                       |                     |                                         |      | 2037 |   |   |

*(Cover continued on next page)*

*(Cover continued from previous page)*

**Securities registered pursuant to Section 12(g) of the Act:**
**Registrant**    **Title of Class****Public Service Enterprise Group Incorporated**    Floating Rate Capital Securities (Guaranteed Preferred Beneficial Interest in PSEG's Debentures), $1,000 par value issued by Enterprise Capital Trust II (Registrant), LIBOR plus 1.22%.     Trust Originated Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG's Debentures), $25 par value at 7.44%, issued by Enterprise Capital Trust I (Registrant).     Trust Originated Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG's Debentures), $25 par value at 7.25%, issued by Enterprise Capital Trust III (Registrant).**Public Service Electric and Gas Company**    6.92% Cumulative Preferred Stock $100 par valueMedium-Term Notes, Series AMedium-Term Notes, Series BMedium-Term Notes, Series C**PSEG Power LLC**    Limited Liability Company Membership Interest**PSEG Energy Holdings LLC**    Limited Liability Company Membership Interest
      The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated 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:
**Class**    **Outstanding at January 31, 2005**Common Stock, without par value    238,350,363
      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).
      Public Service Enterprise Group Incorporated    Yes S    No £      Public Service Electric and Gas Company    Yes £    No S      PSEG Power LLC    Yes £    No S      PSEG Energy Holdings LLC    Yes £    No S
**DOCUMENTS INCORPORATED BY REFERENCE**
**Part of Form 10-K of Public Service Enterprise Group Incorporated**    **Documents Incorporated by Reference****III**    Portions of the definitive Proxy Statement for the 2005 Annual Meeting of Stockholders of Public Service Enterprise Group Incorporated, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about April 30, 2005, as specified herein.

**TABLE OF CONTENTS**
   **            ** **Page****FORWARD-LOOKING STATEMENTS     1 **WHERE TO FIND MORE INFORMATION     3 **PART I    
Item 1.
  Business     3   General            PSEG, PSE&G, Power and Energy Holdings     3         PSE&G     4         Power     6         Energy Holdings     10   Regulatory Issues     15   Segment Information     23   Environmental Matters     24 
Item 2.
  Properties     29 
Item 3.
  Legal Proceedings     38 
Item 4.
  Submission of Matters to a Vote of Security Holders     42 **PART II**    
Item 5.
  Market for Registrant's Common Equity and Related Stockholder Matters     43 
Item 6.
  Selected Financial Data     44 
Item 7.
  Management's Discussion and Analysis of Financial Condition and Results of Operations     45   Overview of 2004 and Future Outlook     45   Results of Operations     51   Liquidity and Capital Resources     63   Capital Requirements     73   Off-Balance Sheet Arrangements     75   Critical Accounting Estimates     75 
Item 7A.
  Qualitative and Quantitative Disclosures About Market Risk     79 
Item 8.
  Financial Statements and Supplementary Data     87   Report of Independent Registered Public Accounting Firm     88   Consolidated Financial Statements     93   Notes to Consolidated Financial Statements            Note 1. Organization and Summary of Significant Accounting Policies     109         Note 2. Recent Accounting Standards     116         Note 3. Asset Retirement Obligations     123         Note 4. Discontinued Operations, Dispositions and Acquisitions     125         Note 5. Extraordinary Item     128         Note 6. Asset Impairments     129         Note 7. Regulatory Matters     129         Note 8. Earnings Per Share     132         Note 9. Goodwill and Other Intangibles     132         Note 10. Long-Term Investments     134         Note 11. Schedule of Consolidated Capital Stock and Other Securities     138         Note 12. Schedule of Consolidated Debt     139         Note 13. Risk Management     144         Note 14. Commitments and Contingent Liabilities     147         Note 15. Nuclear Decommissioning     159         Note 16. Other Income and Deductions     161         Note 17. Income Taxes     163         Note 18. Pension, Other Postretirement Benefits (OPEB) and Savings Plans     168         Note 19. Stock Options and Employee Stock Purchase Plan     173         Note 20. Financial Information by Business Segments     175 
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**Page**
        Note 21. Property, Plant and Equipment and Jointly-Owned Facilities     179         Note 22. Selected Quarterly Data (Unaudited)     181         Note 23. Related-Party Transactions     182         Note 24. Guarantees of Debt     186         Note 25. Merger Agreement     187 
Item 9.
  Changes In and Disagreements With Accountants on Accounting and Financial Disclosure     189 
Item 9A.
  Controls and Procedures     189 **PART III**    
Item 10.
  Directors and Executive Officers of the Registrants     193 
Item 11.
  Executive Compensation     196 
Item 12.
  Security Ownership of Certain Beneficial Owners and Management     200 
Item 13.
  Certain Relationships and Related Transactions     201 
Item 14.
  Principal Accounting Fees and Services     202 **PART IV**    
Item 15.
  Exhibits and Financial Statement Schedules     202   Schedule II—Valuation and Qualifying Accounts     213   Signatures     216   Exhibit Index     220       
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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-lookingstatements. 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**
•credit, commodity, interest rate, counterparty and other financial market risks; •liquidity and the ability to access capital and credit markets and maintain adequate credit ratings; •adverse or unanticipated weather conditions that significantly impact costs and/or operations, including generation; •changes in the electric industry, including changes to power pools; •changes in the number of market participants and the risk profiles of such participants; •changes in technology that may make power generation, transmission and/or distribution assets less competitive; •availability of power transmission facilities that impact the ability to deliver output to customers; •growth in costs and expenses; •environmental regulations that significantly impact operations; •changes in rates of return on overall debt and equity markets that could adversely impact the value of pension assets and liabilities and the Nuclear Decommissioning Trust Funds; •ability to maintain satisfactory regulatory results; •changes in political conditions, recession, acts of war or terrorism; •continued availability of insurance coverage at commercially reasonable rates; •involvement in lawsuits, including liability claims and commercial disputes; •inability to attract and retain management and other key employees; •acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG's, PSE&G's, Power's and Energy Holdings' structure; •business combinations among competitors and major customers; •general economic conditions, including inflation or deflation; •regulatory issues that significantly impact operations; •changes to accounting standards or accounting principles generally accepted in the U.S., which may require adjustments to financial statements; •changes in tax laws and regulations; •ability to service debt as a result of any of the aforementioned events;
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**PSE&G and Energy Holdings**
•ability to obtain adequate and timely rate relief;
**Power and Energy Holdings**
•energy transmission constraints or lack thereof; •adverse changes in the market for energy, capacity, natural gas, emissions credits, congestion credits and other commodity prices, especially during significant price movements for natural gas and power; •surplus of energy capacity and excess supply; •generation operating performance below projected levels; •substantial competition in the worldwide energy markets; •inability to effectively manage portfolios of electric generation assets, gas supply contracts and electric and gas supply obligations; •margin posting requirements, especially during significant price movements for natural gas and power; •availability of fuel and timely transportation at reasonable prices; •effects on competitive position of actions involving competitors or major customers; •changes in product or sourcing mix; •delays, cost escalations or unsuccessful acquisitions, construction and development;
**Power**
•changes in regulation and safety and security measures at nuclear facilities;
**Energy Holdings**
•changes in political regimes in foreign countries; •international developments negatively impacting business; •changes in foreign currency exchange rates; •substandard operating performance or cash flow from investments falling below projected levels, adversely impacting the ability to service project debt; •deterioration in the credit of lessees and their ability to adequately service lease rentals; and •ability to realize tax benefits.
      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 occuror 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 theNew York Stock Exchange under the ticker symbol “PEG.” You can obtaininformation about PSEG, PSE&G, Power and Energy Holdings at the offices ofthe New York Stock Exchange, 20 Broad Street, New York, New York 10005.

**PART I
      This combined Annual Report on Form 10-K is separately filed by PSEG, PSE&G, Power and Energy Holdings. Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each makes representations only as to itself and its subsidiaries and makes no other representations whatsoever as to any other company.

**ITEM 1. BUSINESS
**GENERAL
**PSEG, PSE&G, Power and Energy Holdings**

      PSEG 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):

**PSEG**

**PSE&G**

**Power**

**Energy Holdings**

**Services**

**Global**

**Resources**

**Fossil**

**Nuclear**

**ER&T**

      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 strategieswithin 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 arenot 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:
   **Term Ending**   **May 2005(a)** **May 2006(b)** **May 2007(a)** **May 2008(c)**      **Term** **12 months** **34 months** **36 months** **36 months**      
Load (MW)
   2,840    2,900    2,840    2,840       
$ per Kilowatt-hour (kWh)
  $0.05479   $0.05560   $0.05515   $0.06541                          (a)   Prices set in the February 2004 BGS auction.   (b)   Prices set in the February 2003 BGS auction.   (c)   Prices set in the February 2005 BGS auction which become effective on June 1, 2005 when the agreements for the 12-month (May 2005) BGS-FP supply agreements expire.
      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.
   **% of Sales**      **Customer Type** **Electric** **Gas**      
Commercial
     30%      60%       
Residential
     55%      36%       
Industrial
     15%      4%                     
Total
     100%      100%                             
      **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.

6

      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 of2005. 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:
      **Unit** **CapacityFactor*** **AvailabilityFactor**      
Salem Unit 1
     74.9%     77.0%      
Salem Unit 2
     89.8%     90.5%      
Hope Creek
     65.6%     69.7%      
Peach Bottom Unit 2
     91.0%     91.9%      
Peach Bottom Unit 3
     102.3%     100.0%                    
Combined Nuclear's Share
     81.8%     83.2%                                 * Maximum Dependable Capacity (MDC) net.     The 2004 capacity factor was adversely affected by extended outages at Salem and Hope Creek during the year. For additional information, see Regulatory Issues—NRC and Item 7. MD&A—Overview of 2004 and Future Outlook—Power. The combined capacity factor for Nuclear in 2003 was approximately 87.7%.
7

      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.
**Generation by Fuel Type** **Actual2004** **Estimated2004(A)**
*Nuclear:*
        
New Jersey facilities
     34%     38%
Pennsylvania facilities
     21%     18%
*Fossil:*
        
*Coal:*
        
New Jersey facilities
     12%     14%
Pennsylvania facilities
     13%     13%
Connecticut facilities
     6%     5%
*Oil and Natural Gas:*
        
New Jersey facilities
     13%     7%
New York facilities
     —      2%
Connecticut facilities
     1%     2%
Midwest facilities
     —      1%
*Pumped Storage:*
     —      —              
Total
     100%     100%                     
   (A)   No assurances can be given that actual 2005 output by source will match estimates.
8

      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 levelsin 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.

9

      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.

10

      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:
   **As ofDecember 31, 2004**      
Leveraged Leases (mainly energy-related)
     40%      
International Electric Distribution Facilities
     22%      
International Electric Generation Plants
     15%      
Domestic Electric Generation Plants
     12%      
Other(1)
     8%      
Other Passive Financial Investments
     3%              
Total
     100%                  
   (1)   Assets not allocated to a special project, including corporate receivables.

      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:
  **As ofDecember 31, 2004**  **Assets** **MW** **Number ofCustomers**  **(Millions)**        
**Generation:**
            
North America
    $841      2,411      N/A 
South America
     335      397      N/A 
Europe
     446      662      N/A 
India and the Middle East
     309      260      40,000 
**Distribution:**
            
South America
     1,616      N/A      2,900,000 
**Other:**
            
Other(1)
     597      N/A      N/A                    
**Total**
    $4,144      3,730      2,940,000                                
   (1)   Assets not allocated to a specific project, including corporate receivables and deferred tax assets.

      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 CarthagePower 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.

12

      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**  **Amount** **% ofResources'Total Assets**  **(Millions)**    
**Leveraged Leases**
        
Energy-Related
        
Foreign
        $1,341          45%
Domestic
         1,177          39%
Real Estate—Domestic
         188          6%
Commuter Railcars—Foreign
         88          3%
Aircraft—Domestic
         57          2%                     
**Total Leveraged Leases**
         2,851          95%                     
**Limited Partnerships**
        
Leveraged Buyout Funds
         27          1%
Other
         14          —                      
**Total Limited Partnerships**
         41          1%                     
**Marketable Securities**
         3          — 
**Other Investments**
         15          1%
**Owned Property**
         72          2%
**Current and Other Assets**
         17          1%                     
**Total Resources' Assets**
        $2,999          100%                             
      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 consolidatedtax 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 leaseare an integral element in Resources' overall security and collateral position. If such assets were to be impaired, the rate of return on a

13

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:
**Investment**    **Description** **RecordedInvestment Balancesas ofDecember 31, 2004** **% ofResources'Total Assets**    **(Millions)**    
Reliant Energy MidAtlanticPower LLC
    Three generating stations (Keystone, Conemaugh and Shawville)    $255      9%
Dynegy Holdings Inc
    Two electric generating stations (Danskammer and Roseton)     207      7%
Seminole Electric Cooperative
    Seminole Generation Station Unit #2     197      7%
Midwest Generation (Guaranteed by Edison Mission Energy)
    Two electric generating stations (Powerton and Joliet)     191      6%
ENECO
    Gas distribution network (Netherlands)     155      5%
Merrill Creek
    Merrill Creek Reservoir Project     136      5%
Grand Gulf
    Nuclear generating station (U.S.)     130      4%
ESG
    Electric distribution system (Austria)     126      4%
EZH
    Electric generating station (Netherlands)     122      4%
NUON
    Gas distribution network (Netherlands)     98      3%                     $1,617      54%               
      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.

14

      **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 agreementwith 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 financingand 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 designedto 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 acceptedthe 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 hasmeritorious 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.

16

      ***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 hearingprocedures 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 anexemption 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 relationshipbetween 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&Lcomplaint. 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:
                          **Facility** **Year**                          
Salem 1
     2016                           
Salem 2
     2020                           
Hope Creek
     2026                           
Peach Bottom 2
     2033                           
Peach Bottom 3
     2034                               
      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.

19

             ***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 refuelingoutage 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 Standardsand 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.

20

**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 thepartial 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 thefinal 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,

21

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

22

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 maintainingand 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 replacementcost 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.

23

**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 (SO****2**** )/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 emissionsprogram.

      The EPA has issued regulations (commonly known as the NOx 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 NOx emissions from power plant and industrial sources. The NOx 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 NOx 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 NOx 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 NOx and SO2 emissions. Additional NOx and SO2 reductions also maybe 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.

24

      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 NOx, with Phase 1 beginning in 2010 and Phase 2 beginning in 2015. TheEPA 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 (CO****2**** ) 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 capCO2 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

25

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 consentdecree 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 systemor 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 watersfor 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'sability 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 guidanceto 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 forSalem, 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

27

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 retrofitthe 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 leastfive 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.

28

**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:
             **Plant**    **Location** **Daily Capacity(Therms)**             
Burlington LNG
    Burlington, NJ     773,000              
Camden LPG
    Camden, NJ     280,000              
Central LPG
    Edison Twp., NJ     960,000              
Harrison LPG
    Harrison, NJ     960,000                        
Total
       2,973,000                              
      As of December 31, 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.

30

      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**
**Name** **Location** **TotalCapacity(MW)** **%Owned** **OwnedCapacity(MW)** **PrincipalFuelsUsed**    **Mission**
*Steam:*
                      
Hudson
     NJ      991      100%      991      Coal/Gas     Load Following
Mercer
     NJ      648      100%      648      Coal/Gas     Load Following
Sewaren
     NJ      453      100%      453      Gas/Oil     Load Following
Linden(F)
     NJ      430      100%      430      Oil     Load Following
Keystone(A)(B)
     PA      1,700      23%      388      Coal     Base Load
Conemaugh(A)(B)
     PA      1,700      23%      382      Coal     Base Load
Kearny
     NJ      300      100%      300      Oil     Load Following
Albany(F)
     NY      376      100%      376      Gas/Oil     Load Following
Bridgeport Harbor
     CT      503      100%      503      Coal/Oil     Base Load
New Haven Harbor
     CT      448      100%      448      Oil/Gas     Load Following                           
Total Steam
         7,549          4,919                                  
*Nuclear:*
                      
Hope Creek(G)
     NJ      1,049      100%      1,049      Nuclear     Base Load
Salem 1 & 2(A)(G)
     NJ      2,304      57%      1,323      Nuclear     Base Load
Peach Bottom 2 & 3(A)(C)
     PA      2,224      50%      1,112      Nuclear     Base Load                           
Total Nuclear
         5,577          3,484                                  
*Combined Cycle:*
                      
Bergen
     NJ      1,221      100%      1,221      Gas/Oil     Load Following
Lawrenceburg
     IN      1,096      100%      1,096      Gas     Load Following
Waterford
     OH      821      100%      821      Gas     Load Following                           
Total Combined Cycle
         3,138          3,138                                  
*Combustion Turbine:*
                      
Essex
     NJ      617      100%      617      Gas/Oil     Peaking
Edison
     NJ      504      100%      504      Gas/Oil     Peaking
Kearny
     NJ      443      100%      443      Gas/Oil     Peaking
Burlington
     NJ      557      100%      557      Gas/Oil     Peaking
Linden
     NJ      324      100%      324      Gas/Oil     Peaking
Mercer
     NJ      129      100%      129      Oil     Peaking
Sewaren
     NJ      129      100%      129      Oil     Peaking
Bayonne
     NJ      42      100%      42      Oil     Peaking
Bergen
     NJ      21      100%      21      Gas     Peaking
National Park
     NJ      21      100%      21      Oil     Peaking
Kearny
     NJ      21      100%      21      Gas     Peaking
Linden(F)
     NJ      21      100%      21      Gas/Oil     Peaking
Salem(A)
     NJ      38      57%      22      Oil     Peaking
Bridgeport Harbor
     CT      10      100%      10      Oil     Peaking                           
Total Combustion Turbine
         2,877          2,861                                  
*Internal Combustion:*
                      
Conemaugh(A)(B)
     PA      11      23%      2      Oil     Peaking
Keystone(A)(B)
     PA      11      23%      3      Oil     Peaking                           
Total Internal Combustion
         22          5                                  
*Pumped Storage:*
                      
Yards Creek(A)(D)(E)
     NJ      400      50%      200         Peaking                           
Total Operating Generation Plants
         19,563          14,607                                                        (A)Power's share of jointly-owned facility.(B)Operated by Reliant Energy.(C)Operated by Exelon Generation.(D)Operated by JCP&L.(E)Excludes energy for pumping and synchronous condensers.(F)These assets are scheduled for retirement within the next five years, partially dependent upon new generation going into service discussed below.(G)Pursuant to the Nuclear OSC, operations of these facilities were transferred from Power to Exelon Generation on January 17, 2005. See Item 1. Business—Power—Nuclear.
31

      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**
**Name** **Location** **TotalCapacity(MW)**    **%Owned** **OwnedCapacity(MW)**    **PrincipalFuelsUsed**    **ScheduledIn ServiceDate**
*Combined Cycle:*
                  
Bethlehem
     NY      763     100%     763     Gas    2005
Linden
     NJ      1,220     100%     1,220     Gas    2006                       
Total Construction
         1,983        1,983                            
*Nuclear Uprates*
     NJ/PA      185     Various     162     Nuclear    2005-2008                       
Total Advanced Development
         185        162                                              **Projected Capacity** **TotalOwnedCapacity(MW)**
Total Owned Operating Generation Plants
     14,607 
Under Construction
     1,983 
Advanced Development
     162 
Less: Planned Retirements
     (827)       
Projected Capacity
     15,925            
**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.

32

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

**OPERATING POWER PLANTS**
**Name**    **Location** **TotalCapacity(MW)** **%Owned** **OwnedCapacity(MW)**    **PrincipalFuelsUsed**
***United States***
                
Texas Independent Energy, L.P. (TIE)
                
Guadalupe Power Partners, L.P. (Guadalupe)
    TX     1,000      100%      1,000     Natural gas
Odessa-Ector Power Partners, L.P. (Odessa)
    TX     1,000      100%      1,000     Natural gas                    
Total TIE
       2,000          2,000   
Kalaeloa Partners L.P. (Kalaeloa)
    HI     209      50%      105     Oil
GWF Power Systems, L.P. (GWF)
                
Bay Area I
    CA     21      50%      10     Petroleum coke
Bay Area II
    CA     21      50%      10     Petroleum coke
Bay Area III
    CA     21      50%      10     Petroleum coke
Bay Area IV
    CA     21      50%      10     Petroleum coke
Bay Area V
    CA     21      50%      10     Petroleum coke                    
Total GWF
       105          50   
Hanford L.P. (Hanford)
    CA     27      50%      14     Petroleum coke
Thermal Energy Development Partnership L.P. (Tracy)
    CA     21      35%      7     Biomass
GWF Energy LLC (GWF Energy)
                
Hanford—Peaker Plant
    CA     95      60%      57     Natural gas
Henrietta—Peaker Plant
    CA     97      60%      58     Natural gas
Tracy—Peaker Plant
    CA     171      60%      103     Natural gas                    
Total GWF Energy
       363          218   
SEGS III
    CA     30      9%      3     Solar
Bridgewater
    NH     16      40%      6     Biomass
Conemaugh
    PA     15      50%      8     Hydro                    
**Total United States**
       2,786          2,411                       
***International***
                
PPN Power Generating Company Limited (PPN)
    India     330      20%      66     Naphtha/Natural gas
Prisma
                
Crotone
    Italy     20      25%      5     Biomass
Bando D'Argenta I
    Italy     20      50%      10     Biomass
Strongoli
    Italy     40      25%      10     Biomass                    
Total Prisma
       80          25   
Electroandes        S.A. (Electroandes)
    Peru     183      100%      183     Hydro
Skawina CHP Plant (Skawina)
    Poland     590      75%      439     Coal
Elektrocieplownia        Chorzow Sp. Z o.o. (ELCHO)
    Poland     220      90%      198     Coal
Turboven
                
Maracay
    Venezuela     60      50%      30     Natural gas
Cagua
    Venezuela     60      50%      30     Natural gas                    
Total Turboven
       120          60   
Turbogeneradores de Maracay (TGM)
    Venezuela     40      9%      4     Natural gas
Dhofar Power Company S.A.O.C. (Dhofar Power)
    Oman     240      81%      194     Natural gas
SAESA Group
    Chile     72      100%      72     Oil/Hydro/Wind                    
**Total International**
       1,875          1,241                       
**Total Operating Power Plants**
       4,661          3,652                       
33

                
      As of December 31, 2004, Global had invested in the following generation facilities that were in construction or advanced development:

**POWER PLANTS IN CONSTRUCTION**
**Name**    **Location** **TotalCapacity(MW)** **%Owned** **OwnedCapacity(MW)**    **PrincipalFuels Used** **ScheduledInServiceDate**
***Construction***
                    
SAESA Group
    Chile     43      100%      43     NaturalGas/Diesel     2005 
***Advanced Development***
                    
Electroandes
    Peru     35      100%      35     Hydro     2007                         
**Total Projected Capacity**
       4,739          3,730                                                   
      **Domestic Generation In Operation**

      ***TIE***

      Global had a 50% interest in TIE through its joint venture with TECO Energy Inc. (TECO). In June 2004, Global signed an agreement to acquire all of TECO's equity interest in TIE for less than $1 million. With this purchase, Global owns 100% of TIE and consolidated this investment effective July 1, 2004. TIE owns and operates two electric generation facilities, one in Guadalupe County in south central Texas (Guadalupe) and one in Odessa in western Texas (Odessa).

      In 2003, TIE entered into an asset management agreement that provides greater access to the energy and gas marketplace. Approximately 55% and 57% of the total peak capacity for the Guadalupe and Odessa plants, respectively, for 2005 have been sold via bilateral PPAs. Any remaining uncommitted output is sold in the Texas spot market. Guadalupe and Odessa continue to enter into forward contracts on an ongoing basis.

      ***Kalaeloa***

      Global's 50% partner in Kalaeloa is a power fund managed by Harbert Power Corporation (Harbert). All of the electricity generated by the Kalaeloa power plant is sold to the Hawaiian Electric Company, Inc. (HECO) under a PPA expiring in May 2016. Under a steam purchase and sale agreement expiring in May 2016, the Kalaeloa power plant supplies steam to the adjacent Tesoro refinery. The primary fuel, low sulfur fuel oil, is provided from the adjacent Tesoro refinery under a long-term all requirements contract. The refinery is interconnected to the power plant by a pipeline and preconditions the fuel oil prior to delivery. Back-up fuel supply is provided by HECO.

      The two combustion turbines of Kalaeloa were upgraded in 2004 resulting in both an increase in the net plant output by approximately 20 MW and an improvement in the efficiency of consuming fuel. As a result of the upgrades, Kalaeloa and HECO entered into two amendments to the PPA. The amendments will be effective upon final approval from the Public Utility Commission of the State of Hawaii. If approved, the amendments could increase Kalaeloa firm capacity and associated energy sales to HECO from 180 MW to 209 MW, or a lesser amount as actually demonstrated.

      ***GWF and Hanford***

      Global and Harbert each own 50% of GWF. PPAs for the five GWF Bay Area plants' net output are in place with Pacific Gas and Electric Company (PG&E) ending in 2020 and 2021. GWF acquires the petroleum coke used to fuel its plants through contracts with two local oil refineries with price and minimum volumes being negotiated annually. Three of the five GWF plants have been modified to burn a wider variety of petroleum coke products to mitigate fuel supply and pricing risk.

      Global and Harbert each own 50% of Hanford. A PPA for the plant's net output is in place with PG&E ending in August 2011. Hanford acquires its petroleum coke from a refinery whose previously scheduled October 2004 closing has been extended to March 2005 to enable the current owner to find a buyer for the refinery. The sale of the refinery is now expected to close in the first quarter of 2005 subject to all required

34

regulatory approvals. During 2004, Hanford tested the quality and firing characteristics of alternate sourced delayed petroleum coke and applied for permit modifications, which are under review, to be in position to transition to a new fuel supply, if necessary.

      ***Hanford, Henrietta and Tracy Peaker Plants***

      GWF Energy, which is 60% owned by Global and 40% owned by Harbinger GWF LLC (Harbinger), an affiliate of Harbert, owns and operates three peaker plants in California. Global had owned approximately 75% of GWF Energy, but was required under an arbitration panel's finding to sell a 14.9% interest to Harbinger for approximately $14 million (approximate book value) in February 2004. The output of these plants is sold under a PPA with the California Department of Water Resources (DWR) with maturities in 2011 and 2012. DWR has the right to schedule energy and/or reserve capacity from each unit of the three plants for a maximum of 2,000 hours each year. Energy and capacity not scheduled by the DWR is available for sale by GWF Energy. GWF Energy obtains the natural gas used to fuel its plants from the spot market on a non-firmbasis, with DWR taking the price and availability risk.

      **International Generation in Operation**

      ***India***

      ***PPN***

      Global owns a 20% interest in PPN located in Tamil Nadu, India. Global's partners include Marubeni Corporation, with a 26% interest, El Paso Energy Corporation, with a 26% interest, and the Apollo Infrastructure Company Ltd., with a 28% interest. PPN has entered into a PPA for the sale of 100% of its output to the State Electricity Board of Tamil Nadu (TNEB) for 30 years, with an agreement to take-or-pay equal to a plant load factor of at least 68.5%. TNEB has not made full payment to PPN for the purchase of energy under the contract. For a discussion of the TNEB's failure to meet its obligations under this PPA, see Item 3. Legal Proceedings.

      ***Oman***

      ***Dhofar Power***

      In March 2001, Global, through Dhofar Power, signed a 20-year concession with the Government of Oman to privatize the electric system of the city of Salalah. A consortium led by Global (81% ownership) and several major Omani investment groups own Dhofar Power. Dhofar Power achieved commercial operation in May 2003. As required under the concession agreement, 35% of Dhofar Power's shares will be made available through a public offering on the Oman stock exchange in 2005. See Note 14. Commitments and Contingent Liabilities of the Notes for additional discussions regarding contractual disputes between Dhofar Power and the Government of Oman.

      ***Peru***

      ***Electroandes***

      Electroandes' main assets include four hydroelectric facilities with a combined installed capacity of 183 MW and 437 miles of transmission lines located in the central Andean region east of Lima. In addition, Electroandes is in the process of developing a 35 MW expansion to an existing station. In 2004, 98% of Electroandes' revenues were obtained through various PPAs expiring between 2005 and 2008.

      ***Venezuela***

      ***Turboven***

      The facilities in Cagua and Maracay are owned and operated by Turboven, an entity which is jointly-owned by Global and Corporacion Industrial de Energia (CIE). PPAs expiring between 2006 and 2011 have been entered into for the sale of approximately 40% of the output of Maracay and Cagua to various industrial customers. The PPAs are structured to provide energy only with minimum take provisions. Fuel

35

costs are passed through directly to customers and the energy tariffs are calculated in U.S. Dollars and paid in local currency.

      ***TGM***

      Global has a 9% indirect interest in TGM through a partnership with CIE. TGM sells all of the energy produced under a PPA with Manufacturas del Papel (MANPA), a paper manufacturing concern located in Maracay. MANPA and CIE have common controlling shareholders.

      ***Poland***

      ***ELCHO***

      Global has 90% ownership in ELCHO, a company that has developed a combined thermal energy and power generation plant located in the city of Chorzow, Poland that began operation in the fourth quarter of 2003. ELCHO also owns an older, smaller combined heat and power plant that was retired in 2004. ELCHO has a 20-year PPA with Polskie Sieci Elektroenergetyczne SA (PSE), the Polish government power grid company. In addition to the PPA, ELCHO has contracts with local distribution companies to provide hot water. Approximately 80% of ELCHO's revenues are derived from the PPA and 20% from the thermal business. A portion of the PPA is indexed to U.S. Dollars to support the portion of ELCHO's non-recourse project financing that is in U.S. Dollars. The remainder of the PPA is in Polish Zlotys. For additional information relatedto ELCHO, see Item 3. Legal Proceedings.

      ***Skawina***

      During 2002, Global acquired a 50% interest in Skawina, a combined thermal energy and power generation plant in Poland. In accordance with the purchase agreement, Global purchased additional shares from Skawina's employees to increase its equity interest in Skawina to approximately 63% in August 2003 and 75% in September 2004. Skawina supplies electricity to several electric distribution companies and heat mainly to the city of Krakow under one-year contracts consistent with current practice in Poland.

      **Electric Distribution Facilities**

      Global has invested in the following major distribution facilities:
             **Name**    **Location** **Number ofCustomers** **Global'sOwnershipInterest**             
RGE
    Brazil     1,070,000      32%             
Chilquinta
    Chile     509,000      50%             
SAESA Group
    Chile     571,000      100%             
LDS
    Peru     750,000      38%                                      
Total
       2,900,000                                                     
      As part of Dhofar Power's concession, Global also operates a small distribution facility serving approximately 40,000 customers.

      ***Brazil***

      ***RGE***

      Global owns a 32% equity interest in RGE. Global is the named operator for the system. A shareholders' agreement establishes corporate governance, voting rights and key financial provisions. Global has veto rights over certain actions, including approval of the annual budget and financing plan, appointment of executive officers, significant investments or acquisitions, sale or encumbrance of assets, establishment of guarantees, amendment of the by-laws of the company and dividend policies. Day-to-day operations are the responsibility of RGE's management, subject to shareholder oversight. During 2001, VBC Energia and Previ transferred their shares to Companhia Paulista de Forcae Luz (CPFL), an electric distribution company in which VBC Energia and Previ collectively own a majority interest.

36

      RGE operates under a territorial concession agreement ending in 2027. Under a new regulation passed in 2004, the concession is exclusive and only large consumers have the right to choose another provider of energy or to self-generate. Global does not believe this represents a material threat to the profitability of the distribution system in Brazil since the tariff structure provides the distribution system the opportunity to recover all costs associated with distribution service plus a return. In 2002, RGE secured its energy supply through a 12-year contract signed with Tractebel, a European generation company, which covers all its actual capacity not covered by other existing contracts. Of RGE's existing contracts, only one is denominated in U.S. Dollars. This contract represents 20% of RGE's current needs.

      For additional information related to RGE, see Item 1. Business—Regulatory Issues and Item 3. Legal Proceedings.

      ***Chile and Peru***

      ***Chilquinta and LDS***

      Global together with its partner, Sempra Energy (Sempra), own 99.99% of the shares of Chilquinta, an energy distribution company with numerous energy holdings, based in Valparaiso, Chile. Global's interest is 50% of this aggregate. Following the sale in 2004 of 12% of shares of LDS to the public, Global and Sempra own 75.9% of LDS, an electric distribution company located in Lima, Peru. As part of the Chilquinta and LDS investments, Global and Sempra also own Tecnored and Tecsur, located in Chile and Peru, respectively. These companies provide procurement and contracting services to Chilquinta, LDS and others.

      As equal partners, Global and Sempra share in the management of Chilquinta and LDS. However, Sempra has assumed lead operational responsibilities at Chilquinta, while Global has assumed lead operational responsibilities at LDS. The shareholders' agreement provides for important veto rights over major partnership decisions including dividend policy, budget approvals, management appointments and indebtedness.

      Chilquinta operates under a non-exclusive perpetual franchise within Chile's Region V which is located just north and west of Santiago. Global believes that direct competition for distribution customers would be uneconomical for potential competitors. LDS operates under an exclusive, perpetual franchise in the southern portion of the city of Lima and in an area just south of the city along the coast serving a population of approximately 3.2 million. Both Chilquinta and LDS purchase energy for distribution from generators in their respective markets on a contract basis. For additional information related to Chilquinta and LDS, see Item 1. Business—Regulatory Issues.

      ***SAESA Group***

      Global owns a 99.98% equity interest in SAESA, 98.36% of Empresa Electrica de la Frontera S.A. (Frontel) and 100% of PSEG Generacion y Energia Chile Limitada (Generacion), collectively known together with subsidiaries of SAESA as the SAESA Group. The SAESA Group consists of four distribution companies and one transmission company that provide electric service to 390 cities and towns over 900 miles in southern Chile and a generating company. The SAESA Group has 72 MW of installed generating capacity in operation (52 MW oil-fired, 18 MW hydro and 2 MW wind) and an additional 43 MW of natural gas-fired peaker capacity under construction. The transmission company, Sistema de Transmision del Sur S.A. (STS), provides transmission services to electric generation facilities that have PPAs with distributors in Regions VIII, IX andX and has installed transformation capacity of 816 megavolt-amperes.

      SAESA also owns a 50% interest in an Argentine distribution company, Empresa de Energia Rio Negro S.A. (EDERSA), which provides generation, transmission and distribution services to approximately 147,000 customers in the Province of Rio Negro.

      The Chilean members of the SAESA Group are organized and administered according to a centralized administrative structure designed to maximize operational synergies. In Argentina, EDERSA has its own independent administrative structure. For additional information related to the SAESA Group, see Item 1. Business—Regulatory Issues.

37

**ITEM 3. LEGAL PROCEEDINGS**

**PSE&G**

      On November  15, 2001, Consolidated Edison Company of New York, Inc. (Con Edison) filed a  complaint against PSE&G with the FERC asserting that PSE&G had breached  agreements covering 1,000 MW of transmission. PSE&G denied the allegations  set forth in the complaint. An Initial Decision issued by an ALJ in April 2002  upheld PSE&G's claim that the contracts do not require the provision  of “firm” transmission service to Con Edison but also accepted Con  Edison's contentions that PSE&G was obligated to provide service to  Con Edison utilizing all the facilities comprising its electrical system including  generation facilities and that PSE&G was financially responsible for “out-of-merit,”  i.e., above-market, generation costs needed to effectuate the desired power  flows. On December 9, 2002, FERC issued an order modifying the Initial Decision  by finding that only 600 MW of the total 1,000 MW power transfers is required  to be supported by out-of-merit generation. FERC also made a number of other  findings, on a preliminary basis, including favorable findings to PSE&G  that power transfers should be measured on a “net” basis that considers  the impacts of third-party transactions and that PSE&G's obligations  should be reduced to the extent that Con Edison has impaired PSE&G's  ability to perform under the contracts. FERC remanded a number of issues to  the ALJ for additional hearings, mainly related to the development of protocols  to implement the findings of the December 9, 2002 order. In addition, issues  related to Phase II of the complaint involving the past administration  of the contracts and a claim that PSE&G improperly benefited from the purchase  of hedging contracts in New York, were also referred to the ALJ. The ALJ issued  an Initial Decision on the Phase II issues on June 11, 2003 and on  August 2, 2004 FERC issued its decision on Phase II issues. Those  decisions were largely favorable to PSE&G; however, PSE&G did seek rehearing  as to certain issues as did Con Edison. Those rehearing applications are currently  pending. The August 2, 2004 order required that PJM, NYISO, Con Edison  and PSE&G meet for the purpose of developing operational protocols to implement  FERC's directives. Several meetings have occurred, including meetings before  the ALJ, in an attempt to agree upon protocols. On February 18, 2005, NYISO,  PJM and PSE&G submitted a joint compliance filing pursuant to the FERC's  August 2, 2004 decision. Comments on the filing are due March 11, 2005.

**Power**

      **Hudson and Mercer Generation Stations**

      During 1997 and 1998, approximately 150,000 tons of fly ash generated by the Hudson and Mercer generating stations was taken by an ash marketer, with whom Power then worked, and sold to the owner and operator of a clay mine. The operator of the clay mine used the fly ash as fill material to return the mine site to grade, without obtaining the necessary approvals from the NJDEP. Upon discovery of this use, Power terminated the services of this ash marketer and initiated discussions with the NJDEP for the appropriate regulatory approvals to allow this material to remain at the site. The NJDEP has approved a closure plan for the site that features a clay cap and other engineering controls to ensure that the ash is isolated from the environment. The cost of resolving this matter will depend upon the results of negotiationswith the property owner and the ash marketer. Although the precise extent of liability is not currently estimable, it is not expected to be material.

      **Kearny Generation Station**

      A preliminary review of possible mercury contamination at the Kearny station concluded that additional studies and investigations are required. A Remedial Investigation (RI) was conducted and a report was submitted to the NJDEP in 1997. This report is currently under technical review. The RI report found that the mercury at the site is stable and immobile and should be addressed at the time the Kearny station is retired.

38

**Energy Holdings**

      **Texas**

      The Public Utility Commission of Texas (PUCT) instituted an investigation regarding certain price spikes in the Electric Reliability Council of Texas (ERCOT) Balancing Energy Service (BES) market and ancillary services market that occurred during extreme weather conditions on February 24-26, 2003, to determine whether any market manipulation occurred and whether any existing protocols need to be revised. On those days, during several trading periods, prices in the ERCOT balancing energy market cleared near the $1,000 per MWh ERCOT price cap. As part of the PUCT investigation, TIE and its two operating subsidiaries, Guadalupe and Odessa, along with the other market participants, were requested to provide certain information to the PUCT relating to their bids during this period. TIE, Guadalupe and Odessa supplied all therequested information and believe such information demonstrates that Guadalupe's and Odessa's bidding activities were consistent with ERCOT protocols.

      The PUCT issued an order in May 2003 directing ERCOT to implement certain changes to the BES market to mitigate the affects of potential future price spikes. These changes have been implemented. Global believes that the new protocols will have minimal financial impact on Guadalupe and Odessa.

      On July 7, 2003, Texas Commercial Energy LLC (TCE) filed suit against the three major electric utilities in Texas, certain wholesale power generators, their related affiliated retail electric providers and certain qualified scheduling entities, as well as ERCOT, in its function as the ISO for the Texas energy market. The action filed in the U.S. District Court for the Southern District of Texas, Civil Action No. C-03-249, alleges price-fixing, predatory pricing and certain common law claims. Automated Power Exchange, Inc. (APX), a named defendant, acted as agent and submitted bids on behalf of Guadalupe and Odessa, as well as several other generators in the ERCOT balancing energy market. APX has submitted a demand for indemnification from Guadalupe and Odessa. On February 3, 2004, TCE amended its complaint and namedTIE, Guadalupe and Odessa and others as additional defendants. On May 20, 2004, the U.S. District Court granted the defendants' motion to dismiss the state and federal antitrust claims. All collateral claims were to be held in abatement pending an appeal of the ruling to the Fifth Circuit Court of Appeals. On July 19, 2004, TCE filed a Notice of Appeal, and the parties subsequently filed briefs and reply briefs. Global continues to believe there are valid defenses to TCE's claims which will be vigorously asserted.

      On February    18, 2005, Utility Choice L.P., and Cirro Group Inc. filed suit against many    of the same defendants in the TCE suit, including TIE based on facts similar to those alleged in the TCE litigation. The new action, filed in the    U.S. District Court for the Southern Division of Texas also alleges price-fixing,    predatory pricing and various other claims. Global believes there are valid    defenses to these claims which will be vigorously asserted.

      **Poland**

      ***ELCHO***

      Global has an approximate 90% ownership interest in ELCHO, which owns a combined power generation and thermal energy plant in Poland. ELCHO has a contract with a local distribution company for the delivery of heat to Chorzow and three other towns, which represents approximately 20% of ELCHO's business. The local heat distribution company is under bankruptcy protection as of June 30, 2004. The bankruptcy of this customer caused a default under ELCHO's bank agreements, which are non-recourse to Global and Energy Holdings. A waiver has been obtained from ELCHO's lenders which Global will seek to extend, as appropriate. ELCHO's net receivable from the local distribution company is approximately $7 million. Payments are currently being made and the receivable has not increased. Although Global believes that thereceivable will be recoverable and that there will not be a material adverse impact on its financial position, results of operations or cash flows as a result of this matter, no assurances can be given.

      In a separate matter, ELCHO has a 20-year PPA with the Polish government's power grid company. The Polish government has embarked on a process with the intention of terminating all of the more than 30 long-term PPAs it has with energy suppliers. The Polish government has expressed its intention to compensate each entity whose contract is terminated with monies raised by the government by securitizing a charge that will be passed on to ratepayers. In 2003, the Polish government informally proposed compensation that Global did not believe to be adequate. Global has been holding discussions with the Polish government with the objective of ensuring that any settlement is financially neutral to ELCHO. There have been recent fundamental changes to the proposed policy to terminate long-term contracts. Such changes may includemaking it optional for PPA owners to participate in the termination scheme. The risks and benefits to opting in or out of such a program cannot be fully analyzed with information available at this time. Inadequate compensation could lead to lower future revenues and earnings and could have a material adverse impact on Global's financial position, results of operations or cash flows.

39

      **India**

      Global has  a 20% ownership interest in PPN, which sells its output under a long-term PPA  with the TNEB. TNEB has not made full payment to PPN for the purchase of energy  under the PPA and the total receivable as of December 31, 2004 was approximately  $110 million. The project ran on a limited basis during the fourth quarter of  2004, primarily due to the high cost of naphtha fuel and resulting low ranking  on the merit order dispatch list. The past due receivable as of December 31,  2004 was approximately $27 million, net of a $66 million reserve. If TNEB continues  to fail to make required payments under the PPA, PPN may have liquidity problems.  On March 26, 2004, Global and one of its partners in PPN, El Paso Energy Corporation,  filed a notice of arbitration on behalf of PPN against TNEB under the arbitration  clause of the PPA, asserting that they have the right as minority shareholders  to protect the contractual rights of PPN where PPN has failed to exercise those  rights itself. In response, PPN filed a petition for an anti-suit injunction  against the arbitration. Global successfully defended against the petition in  two lower courts. PPN has filed its final appeal in the Supreme Court of India  (SLP Civil No. 23169). Hearings began on January 24, 2005.

      Global expects that a final determination will be made by the Central Electricity Authority and TNEB in 2005 regarding the capital cost of the project that may affect the tariff that PPN charges TNEB. An adverse outcome to the continuing negotiations or arbitration with TNEB could potentially result in an impairment of this investment, which could be material to PSEG's and Energy Holdings' respective results of operations. As of December 31, 2004, Global's total investment in PPN was approximately $38 million.

      **RGE**

      ****

      ***ANEEL—RGE Merger Matter***

      ******

      On June  29, 1998, RGE's parent, DOC3 Participacoes, S.A. (DOC3), was merged into  RGE. In connection with the merger, the shareholders of DOC3 became direct shareholders  in RGE (Downstream Merger). Upon the merger, RGE assumed all of DOC3's liabilities  including loans payable to existing shareholders and issued preferred shares  which bore a fixed interest rate of 13% per annum. The Brazilian electricity  sector regulator, ANEEL, took the position that the Downstream Merger of DOC3  into RGE was inappropriate because it was a related-party transaction and was  not expressly approved by ANEEL. Although RGE believed that ANEEL's prior  approval of the transaction was not required because it did not involve a change  in the control of RGE, it entered into negotiations with ANEEL in order to resolve  the dispute. During the fourth quarter of 2004, RGE and ANEEL settled the dispute.  ANEEL approved the Downstream Merger of DOC3 into RGE and fined RGE $3 million  (Resolution 166, dated July 13, 2004 under Docket No. 48500.003518/03-52).  In addition, RGE's shareholders agreed to modify the preferred shares by  eliminating the 13% fixed interest rate per annum and capitalizing all accrued  and unpaid dividends through the date of the settlement. RGE's preferred  shares will only be paid dividends in the future on the same basis as RGE's  common shares without a preferential fixed rate of return. Global believes that  this outcome is satisfactory because it ends a long lasting dispute and will  normalize the relation with ANEEL.

**PSEG, PSE&G, Power and Energy Holdings**

      In addition to matters discussed above, see information on the following proceedings at the pages indicated for PSEG and each of PSE&G, Power and Energy Holdings as noted:

(1)
    Page 16. (Power) PJM Interconnection      L.L.C. filing with FERC on November 2, 2004, Docket No. EL03-236-003      to amend Tariff and Operating Agreement to request Reliability Must-Run      (RMR) compensation.
(2)
    Page 16. (Power) PSEG Power      Connecticut's filing with FERC on November 17, 2004, Docket No.      ER05-231-000, to request RMR compensation.
(3)
    Page 17. (Power) PSEG Lawrenceburg      Energy Company and PSEG Waterford Energy respective filings of triennial      market power reviews, Docket Nos. ER01-2460-002 and ER01-2482-002, August      2004.
(4)
    Page 17. (PSE&G) FERC proceeding      related to MISO and PJM. Joint Filing of New PJM Companies and PJM Interconnection,      L.L.C. to expand PJM, The New PJM Companies, et al., Docket No. ER03-262-000,      December 11, 2002.
(5)
    Page 17. (PSEG, PSE&G, Power      and Energy Holdings) FERC proceeding related to PJM Restructuring, FERC      Order dated June 26, 2003 seeking comments on proposed revisions to      market-based rate tariffs and authorizations, Investigation of Terms and      Conditions of Public Utility Market-Based Rate Authorizations, 103 FERC      § 61,349.
40

(6)
    Page 18. (PSE&G) Neptune      Regional Transmission System, LLC v. PJM Interconnection, L.L.C. complaint      filed with FERC on December 21, 2004, Docket No. EL05-48-000, alleging      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 $26 million.
(7)
    Page 19. (PSE&G) JCP&L      v. ACE, et al. complaint filed with FERC on December 30, 2004, Docket      No. EL05-50-000, seeking to terminate its construction obligations under      the LDV Agreement.
(8)
    Page 21. (PSE&G) PSE&G's      BGSS Commodity filing with the BPU on May 28, 2004, Docket No. GR04050390.
(9)
    Page 21. (PSE&G) Remediation      Adjustment Clause filing with the BPU filed in June 2003, Docket No. GR03060436.
(10)
    Page 21. (PSE&G) Remediation      Adjustment Clause filing with the BPU on April 22, 2004, Docket No.      GR04040291.
(11)
    Page 21. (PSE&G) PSE&G's      BGSS Commodity filing with the BPU on May 30, 2003, Docket No. EO03050394.
(12)
    Page 22. (PSE&G) Cost Recovery      filing with the BPU on July 1, 2004, Docket No. EE04070718.
(13)
    Page 22. (PSE&G) Deferral      Proceeding filed with the BPU on August 28, 2002, Docket No. EX02060363,      and Deferral Audit beginning on October 2, 2002 at the BPU, Docket      No. EA02060366.
(14)
    Page 22. (PSE&G) BPU's      audit of gas supply costs.
(15)
    Page 22. (PSE&G) BPU Order      dated December 23, 2003, Docket No. EO02120955 relating to the New      Jersey Interim Clean Energy Program.
(16)
    Page 26. (Power) Power's      Petition for Review filed in the United States Court of Appeals for the      District of Columbia Circuit on July 30, 2004 challenging the final      rule of the United States Environmental Protection Agency entitled “National      Pollutant Discharge Elimination System—Final Regulations to Establish      Requirements for Cooling Water Intake Structures at Phase II Existing Facilities,”      now transferred to and venued in the United States Court of Appeals for      the Second Circuit with Docket No. 04-6696-ag.
(17)
    Page 150. (PSE&G) Investigation      Directive of NJDEP dated September 19, 2003 and additional investigation      Notice dated September 15, 2003 by the EPA regarding the Passaic River site.      Docket No. EX93060255.
(18)
    Page 151. (PSE&G) PSE&G's      MGP Remediation Program instituted by NJDEP's Coal Gasification Facility      Sites letter dated March 25, 1988.
(19)
    Page 155. (Power) Filing of         Complaint by Nuclear against the DOE on September 26, 2001 in the U.S.        Court      of Federal Claims, Docket No. 01-551C seeking damages caused by the DOE's         failure to take possession of spent nuclear fuel. The complaint was        amended      to include PSE&G as a prior owner in interest.
(20)
    Page 157. (Energy Holdings)      Peru's Internal Revenue Agency's (SUNAT) claim for past due taxes      at LDS, Resolution No. 0150150000030, dated July 10, 2003.
(21)
    Page 158. (Holdings) Dhofar      Power Company SAOC v. Ministry of Housing, Electricity and Water (Sultanate      of Oman), ICC Reference EXP/233.  
**PSE&G and Power**

      In addition, see the following environmental related matters involving governmental authorities. Based on current information, PSE&G and Power do not expect expenditures for any such site, individually or for all such current sites in the aggregate, to have a material effect on their respective financial condition, results of operations and net cash flows.

      (1) Claim made in 1985 by the U.S. Department of the Interior under CERCLA with respect to the Pennsylvania Avenue and Fountain Avenue municipal landfills in Brooklyn, New York, for damages to natural resources. The U.S. Government alleges damages of approximately $200 million. To PSE&G's knowledge there has been no action on this matter since 1988.

      (2) Duane Marine Salvage Corporation Superfund Site is in Perth Amboy, Middlesex County, New Jersey. The EPA had named PSE&G as one of several potentially responsible parties (PRPs) through a series of administrative orders between December 1984 and March 1985. Following work performed by the PRPs, the EPA declared on May 20, 1987 that all of its administrative orders had been satisfied. The NJDEP,

41

however, named PSE&G as a PRP and issued its own directive dated October 21, 1987. Remediation is currently ongoing.

      (3) Various Spill Act directives were issued by NJDEP to PRPs, including PSE&G with respect to the PJP Landfill in Jersey City, Hudson County, New Jersey, ordering payment of costs associated with operation and maintenance, interim remedial measures and a Remedial Investigation and Feasibility Study (RI/FS) in excess of $25 million. The directives also sought reimbursement of NJDEP's past and future oversight costs and the costs of any future remedial action.

      (4) Claim by the EPA, Region III, under CERCLA with respect to a Cottman Avenue Superfund Site, a former non-ferrous scrap reclamation facility located in Philadelphia, Pennsylvania, owned and formerly operated by Metal Bank of America, Inc. PSE&G, other utilities and other companies are alleged to be liable for contamination at the site and PSE&G has been named as a PRP. A Final Remedial Design Report was submitted to the EPA in September of 2002. This document presents the design details that will implement the EPA's selected remediation remedy. The costs of remedy implementation are estimated to range from $14 million to $24 million. PSE&G's share of the remedy implementation costs are estimated between $4 million and $8 million. The remedy itself and responsibility for the costs of its implementationare the subject of litigation currently in the U.S. District Court for the Eastern District of Pennsylvania entitled United States of America, et. al., v. Union Corporation, et. al., Civil Action No. 80-1589.

      (5) The Klockner Road site is located in Hamilton Township, Mercer County, New Jersey, and occupies approximately two acres on PSE&G's Trenton Switching Station property. PSE&G entered into a memorandum of agreement with the NJDEP for the Klockner Road site pursuant to which PSE&G conducted an RI/FS and remedial action at the site to address the presence of soil and groundwater contamination at the site.

      (6) The NJDEP assumed control of a former petroleum products blending and mixing operation and waste oil recycling facility in Elizabeth, Union County, New Jersey (Borne Chemical Co. site) and issued various directives to a number of entities including PSE&G requiring performance of various remedial actions. PSE&G's nexus to the site is based upon the shipment of certain waste oils to the site for recycling. PSE&G and certain of the other entities named in NJDEP directives are members of a PRP group that have been working together to satisfy NJDEP requirements including: funding of the site security program; containerized waste removal; and a site remedial investigation program.

      (7) The New York State Department of Environmental Conservation (NYSDEC) has named PSE&G as one of many PRPs for contamination existing at the former Quanta Resources Site in Long Island City, New York. Waste oil storage, processing, management and disposal activities were conducted at the site from approximately 1960 to 1981. It is believed that waste oil from PSE&G's facilities was taken to the Quanta Resources Site. NYSDEC has requested that the PRPs reimburse the state for the costs NYSDEC has expended at the site and to conduct an investigation and remediation of the site. Power, PSE&G and the other PRPs have executed an Order on Consent with NYSDEC for the investigation of the site and have entered an agreement among some of the PRPs for the sharing of the associated costs. The holders of a note securinga mortgage on property adjacent to the Quanta Resources Site have filed an action against some of the PRPs seeking to recover damages allegedly incurred as a result of contamination migrating from the Quanta Resources Site onto the adjacent parcels and to compel the cleanup of those parcels.

**ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
      **PSEG**—None.

      **PSE&G**—None.

      **Power**—None.

      **Energy Holdings**—None.

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**PART II
**ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
**PSEG**

      PSEG's Common Stock is listed on the New York Stock Exchange, Inc. As of December 31, 2004, there were 106,039 holders of record.

      The following table indicates the high and low sale prices for PSEG's Common Stock and dividends paid for the periods indicated:
      **Common Stock** **High** **Low** **DividendPer Share**      
***2004:***
                  
First Quarter
    $47.71     $42.85     $0.55       
Second Quarter
    $47.70     $39.66     $0.55       
Third Quarter
    $42.60     $38.10     $0.55       
Fourth Quarter
    $52.64     $40.55     $0.55       
***2003:***
                  
First Quarter
    $37.25     $32.09     $ 0.54       
Second Quarter
    $44.50     $36.45     $0.54       
Third Quarter
    $43.78     $39.77     $0.54       
Fourth Quarter
    $44.20     $39.40     $0.54                   
      In January 2005, PSEG's Board of Directors approved a one-cent increase in its quarterly common stock dividend, from $0.55 to $0.56 per share, for the first quarter of 2005. This increase reflects an indicated annual dividend rate of $2.24 per share.

      The Merger Agreement between PSEG and Exelon provides that, subject to applicable law and the fiduciary duties of its board of directors, Exelon will increase its quarterly dividend so that the first dividend paid after completion of the Merger is an amount equal, on an exchange ratio adjusted basis, to the dividend PSEG shareholders received in the quarter immediately prior to completion of the Merger, up to a maximum of $0.47 per share of Exelon Common Stock (the lesser of $0.47 and the amount required to equal PSEG's dividend on an exchange ratio adjusted basis being referred to as the threshold amount (threshold amount)). Exelon has agreed that as close to 30 days prior to the anticipated closing of the Merger as reasonably practicable, it will notify PSEG of what it believes its first quarterly dividend followingcompletion of the Merger will be. If that dividend is less than the threshold amount, PSEG may make a one time special cash dividend to its shareholders equal to the amount of the difference between the dividend Exelon has informed PSEG it will pay and the threshold amount on an exchange ratio adjusted basis. It is anticipated that the combined company will maintain Exelon's current dividend payout policy of 50% to 60% of earnings. For additional information concerning dividend payments, dividend history, policy and potential preferred voting rights, restrictions on payment and common stock repurchase programs, see Item 7. MD&A—Overview of 2004 and Future Outlook and Liquidity and Capital Resources and Note 11. Schedule of Consolidated Capital Stock and Other Securities of the Notes.

**PSE&G**

      All of the common stock of PSE&G is owned by PSEG. For additional information regarding PSE&G's ability to continue to pay dividends, see Item 7. MD&A—Overview of 2004 and Future Outlook.

**Power**

      All of Power's outstanding limited liability company membership interests are owned by PSEG. For additional information regarding Power's ability to pay dividends, see Item 7. MD&A—Overview of 2004 and Future Outlook.

**Energy Holdings**

      All of Energy Holdings' outstanding limited liability company membership interests are owned by PSEG. For additional information regarding Energy Holdings' ability to pay dividends, see Item 7. MD&A—Overview of 2004 and Future Outlook.

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**ITEM 6. SELECTED FINANCIAL DATA
**PSEG**

      The information presented below should be read in conjunction with the Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) and the Consolidated Financial Statements and Notes to Consolidated Financial Statements (Notes).
  **For the Years Ended December 31,**  **2004** **2003** **2002** **2001** **2000**  **(Millions, where applicable)**
Operating Revenues
    $10,996     $11,139     $8,220         $6,883     $6,521 
Income from Continuing Operations
    $721     $852     $405(A)        $766     $782 
Net Income
    $726     $1,160     $235         $764     $770 
Earnings per Share:
                    
Income from Continuing Operations:
                    
Basic
    $3.04     $3.73     $1.94(A)        $3.68     $3.64 
Diluted
    $3.03     $3.72     $1.94(A)        $3.68     $3.64 
Net Income:
                    
Basic
    $3.06     $5.08     $1.13         $3.67     $3.58 
Diluted
    $3.05     $5.07     $1.13         $3.67     $3.58 
Dividends Declared per Share
    $2.20     $2.16     $2.16         $2.16     $2.16 
As of December 31:
                    
Total Assets
    $29,207     $28,084     $26,147         $25,568     $21,531 
Long-Term Obligations(B)
    $12,975     $12,995     $12,291         $10,814     $5,869 
Preferred Stock With Mandatory Redemption
    $—     $—     $—         $—     $75                        (A)   2002 results include after-tax charges of $368 million, or $1.76 per share, related to losses from Energy Holdings' Argentine investments. See Item 7. MD&A—Results of Operations and Note 6. Asset Impairments of the Notes for further discussion.   (B)   Includes capital lease obligations. The increase in 2001 is related to a $2.5 billion securitization transaction. In addition, this includes debt supporting trust preferred securities in all years presented due to the implementation of Financial Accounting Standards Board (FASB) Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities (VIE).” See Note 2. Recent Accounting Standards of the Notes.
**PSE&G**

      The information presented below should be read in conjunction with the MD&A, the Consolidated Financial Statements and the Notes.
  **For the Years Ended December 31,**  **2004** **2003** **2002** **2001** **2000**  **(Millions)**
Operating Revenues
    $6,972     $6,740     $5,919     $6,091     $5,887 
Income Before Extraordinary Item
    $346     $247     $205     $235     $587 
Net Income
    $346     $229     $205     $235     $587 
As of December 31:
                    
Total Assets
    $13,586     $13,177     $12,867     $13,299     $15,626 
Long-Term Obligations(A)
    $4,877     $5,129     $5,050     $5,180     $4,163 
Preferred Stock With Mandatory Redemption
    $—     $—     $—     $—     $75                        (A)   Includes capital lease obligations. The increase in 2001 is related to a $2.5 billion securitization transaction. In addition, this includes debt supporting trust preferred securities in all years presented due to the implementation of FIN 46. For additional information, see Note 2. Recent Accounting Standards of the Notes.
44

**Power**

      Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

**Energy Holdings**

      Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

**ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)**

      This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no other representations whatsoever as to any other company.

**OVERVIEW OF 2004 AND FUTURE OUTLOOK**

**PSEG, PSE&G, Power and Energy Holdings**

      **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 the Public Utility Holding Company Act of 1935 (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.

      PSEG and Exelon entered into the Merger Agreement with the expectation that the Merger would result in various benefits, including, among other things, cost savings and operating efficiencies. The Merger Agreement also addresses the key issues of leadership succession at PSEG with John Rowe, Exelon's Chief Executive Officer to become Chief Executive Officer of the combined company. Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including whether the businesses of Exelon and PSEG are integrated in an efficient and effective manner, as well as general competitive factors in the market place. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management'stime and energy and could have an adverse effect on the combined company's business, financial condition, operating results and prospects.

      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, the Federal Energy Regulatory Commission (FERC), the Securities  and Exchange Commission (SEC), the Nuclear Regulatory Commission (NRC) and various  utility regulatory, antitrust and other authorities in the United States (U.S.)  and in foreign jurisdictions. The governmental authorities from which these  approvals are required may impose conditions on completion of the merger or  require changes to the terms of the Merger. These conditions or changes could  have the effect of delaying completion of the Merger or imposing additional  costs on or limiting the revenues of the combined company and/or the individual  registrants following the Merger, any of which might have a material adverse  effect on the combined company or the individual registrants following completion  of the Merger. 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.

      On February 4, 2005, PSEG and Exelon filed for approval of the Merger with the FERC, the New Jersey Board of Public Utilities (BPU) and the Pennsylvania Public Utility Commission (PPUC). Exelon also filed a notice of the Merger with the Illinois Commerce Commission.

      Although PSEG and Exelon intend to take steps to reduce any adverse effects, uncertainties relating to the Merger may impair PSEG's and Exelon's ability to attract, retain and motivate key personnel until the Merger is consummated and for a period of time thereafter due to uncertainty about roles with the future combined company, and could cause customers, suppliers and others that deal with PSEG and Exelon to seek to change existing business relationships. Inability to retain key employees or maintain satisfactory

45

relationships with employees, customers or suppliers could have a material adverse impact on the operations of PSEG, Exelon and the combined company following the Merger.

      It is anticipated that the regulatory 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, subject to shareholder and regulatory approvals which cannot be assured. The Merger would create a combined company serving approximately seven million electric customers and approximately two million gas customers in Illinois, New Jersey and Pennsylvania.

      PSEG and Exelon expect to incur costs associated with consummating the Merger and integrating the operations of the two companies, as well as approximately $29 million and $41 million in transaction fees for PSEG and Exelon, respectively. Preliminary estimated integration costs associated with the Merger are approximately $700 million over a period of 4 years, with approximately $400 million being incurred in the first year after completion of the Merger and approximately $150 million being incurred in the second year after completion of the Merger.

      Following the Merger, approximately 50% of the combined company's earnings and cash flow is expected to be produced by the three regulated utilities, PSE&G, Commonwealth Edison Company in northern Illinois and PECO Energy Company in southeastern Pennsylvania, and 50% by the unregulated businesses, primarily from the combined generation of Power and Exelon Generation Company LLC (Exelon Generation). After the Merger, the combined company expects to maintain its proportion of business in regulated operations while reducing the proportion in international operations. The expected strategy of the combined company would be to divest, in an orderly fashion, PSEG Global LLC's (Global) investments that do not meet the strategic objectives of the combined company.

      The Merger Agreement contains certain termination rights for both Exelon and PSEG, and further provides that, upon termination of the Merger Agreement under specified circumstances, (1) Exelon may be required to pay PSEG a termination fee of $400 million plus PSEG's transaction expenses up to $40 million and (2) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon's transaction expenses up to $40 million.

      Among the factors considered by the board of directors of PSEG in connection with its approvals of the Merger Agreement were the benefits as well as the risks that could result from the Merger. PSEG cannot give any assurance that these benefits will be realized within the time periods contemplated or even that they will be realized at all.

      Concurrent  with the Merger Agreement, PSEG Nuclear LLC (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 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 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.

      Prior to the Merger, PSEG and Exelon, and their respective subsidiaries, will continue to operate as separate entities. The discussion contained in the combined MD&A that follows relates solely to the current businesses of PSEG, PSE&G, Power and Energy Holdings and their respective expectations for future financial position, results of operations and cash flows, exclusive of any potential impacts from the Merger.

46

**PSEG**

      PSEG's business consists of four reportable segments, which are PSE&G, Power and the two direct subsidiaries of Energy Holdings: Global and PSEG Resources LLC (Resources). The following is a discussion of the markets in which PSEG and its subsidiaries compete, the corporate strategy for the conduct of PSEG's businesses within these markets and significant events that have occurred during 2004 and expectations for 2005 and beyond.

      PSEG develops a long-range growth target by building business plans and financial forecasts for each major business (PSE&G, Power, Global and Resources). These plans and forecasts incorporate detailed estimates of revenues, operating and maintenance expenses, capital expenditures, financing costs and other material factors for each business. Key factors which may influence the performance of each business, such as fuel costs and forward power prices, are also incorporated. Sensitivity analyses are performed on the key variables that drive the businesses' financial results in order to understand the impact of these assumptions on PSEG's projections. Once plans are in place, PSEG Management monitors actual results and key variables and updates financial projections to reflect changes in the energy markets, theeconomy and regional and global conditions. PSEG Management believes this monitoring and forecasting process enables it to alter operating and investment plans as conditions change.

      PSEG projects earnings from Continuing Operations for 2005 of $3.15 to $3.35 per share. Included in the 2005 earnings projections are improved operations at Power's generating facilities as compared to 2004 and margin improvements through the expiration of existing contracts and the realization of current and anticipated higher market prices. These projected improvements are expected to be partially offset by lower income from Power's Nuclear Decommissioning Trust (NDT) Funds as compared to 2004. PSEG also expects Earnings Per Share in 2005 to be reduced by additional shares outstanding primarily due to the anticipated conversion of participating equity securities in November 2005.

      PSEG expects operating cash flows beyond 2004 to be sufficient to meet capital needs and dividend requirements and may employ any excess cash to reduce debt, invest in its businesses or increase dividends. On January 18, 2005, PSEG announced an increase in its dividend from $0.55 to $0.56 per share for the first quarter of 2005. This quarterly increase reflects an indicated annual dividend rate of $2.24 per share.

      Several key factors that will drive PSEG's future success are energy, capacity and fuel prices, performance of Power's generating facilities, PSE&G's ability to maintain a reasonable rate of return under its regulated rate structure and the stability of international economies for Energy Holdings. Assuming improvements in these factors over the latter part of the planning period, as discussed further below under PSE&G, Power and Energy Holdings, PSEG has a target annual earnings per share growth rate of 4% to 6% from 2005 to 2009.

**PSE&G**

      PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the BPU for its distribution operations and by the FERC for its electric transmission and wholesale sales operations. Consequently, the earnings of PSE&G are largely determined by the regulation of its rates by those agencies. In February 2004, the BPU approved the results of New Jersey's third annual basic generation service (BGS) auction process and PSE&G successfully secured contracts to provide the electricity requirements for its customers' needs. 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.

      In 2005, PSE&G expects Income from Continuing Operations to range from $325 million to $345 million, based on normal weather conditions, expected sales growth, productivity gains and the effects of the 2003 electric base rate case, partially offset by cost increases. In addition, as provided for in a BPU order received in July 2003 in PSE&G's electric base rate case, PSE&G is amortizing a reserve for excess depreciation which results in an annual $64 million reduction in Depreciation and Amortization expense through December 31, 2005. The BPU's order in this case allows PSE&G to file for a $64 million increase in electric distribution rates effective January 1, 2006, subsequent to the amortization of this reserve. Assuming a fair resolution to upcoming rate matters, expected increases insales volumes and stable weather patterns, PSE&G expects annual earnings growth of 1% to 2% from 2005 to 2009.

      The risks from this business generally relate to the treatment of the various rate and other issues by the state and federal regulatory agencies, specifically BPU and FERC. In 2005 and beyond, PSE&G's success will

47

depend, in part, on its ability to maintain a reasonable rate of return, realize a $64 million electric distribution rate increase in 2006, continue cost containment initiatives, maintain system reliability and safety levels and continue to recover with an adequate return the regulatory assets it has deferred and the investments it plans to make in its electric and gas transmission and distribution system. Since PSE&G earns no margin on the commodity portion of its electric and gas sales through tariff agreements, there is no anticipated commodity price volatility for PSE&G.

**Power**

      Power is an electric generation and wholesale energy marketing and trading company that is focused on a generation market extending from Maine to the Carolinas and the Atlantic Coast to Indiana (Super Region). Power's principal operating subsidiaries, PSEG Fossil LLC (Fossil), Nuclear and PSEG Energy Resources & Trade LLC (ER&T) are regulated by FERC. Through its subsidiaries, Power seeks to balance its generating capacity, fuel requirements and supply obligations through integrated energy marketing and trading, enhance its ability to produce low-cost energy through efficient nuclear operations and pursue modest growth in the Super Region based on market conditions.

      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.

      A key factor in Power's ability to achieve its objectives is its capability to operate its nuclear and fossil stations at sufficient capacity to avoid the need to purchase higher-priced electricity to satisfy its obligations. Overall, 2004 earnings were lower than originally expected primarily due to a series of factors related to its nuclear and fossil operations and recent market pricing and electric transmission congestion which resulted in the purchase of higher-priced replacement power.

      In 2004, the absence of the market transition charge (MTC) revenues at Power that had been collected during the four-year transition period under New Jersey's electric utility deregulation provisions that ended August 2003 resulted in a decrease to earnings of approximately $66 million, after-tax.

      Power's results from its nuclear operations have been negatively impacted by unanticipated, extended outages at its Hope Creek and Salem nuclear generation facilities. These outages were the result of necessary repair and maintenance work, which is expected to improve long-term operating performance. In addition, Power's fossil operations were adversely impacted by unanticipated outages at its Hudson station and extended outages at its Mercer station. During much of 2004, the price of replacement power to satisfy Power's contracted obligations to serve load and supply power was significantly impacted by higher than expected fuel and transmission congestion costs. Power believes that a large portion of the increased congestion costs were related to the derating of an electric transformer maintained by PSE&G,which is in the PJM Interconnection, L.L.C. (PJM) system. This transformer is being replaced, with an expected return to service in June 2005.

      In addition, Power's Waterford, Ohio and Lawrenceburg, Indiana facilities in the Midwest have experienced very low capacity factors due to oversupply conditions, and therefore have provided only modest revenues. Power cannot predict when these market conditions will improve.

      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. Hope Creek completed its refueling outage and returned to service on January 26, 2005. In an unrelated matter in early December 2004, the two Salem nuclear generation units were taken offline due to an oil spill from a tanker in the Delaware River, near the facilities. The units, which draw river water for cooling purposes, were shut down for about two weeks to avoid intake of the spilled oil. Power anticipates that it will make a filing to seek recovery of damages and losses resulting from the oil spill. It is not possible to predict at this time what the results of this claim will be. The longer-than-planned outageat Hope Creek and an unexpected shutdown of the two Salem nuclear units resulted in additional maintenance and increased replacement power costs and Operation and Maintenance costs.

48

      As previously discussed, Power has entered into an OSC with Exelon Generation in an attempt to improve nuclear operations. Power expects Income from Continuing Operations to range from $335 million to $385 million in 2005. The increase, as compared to 2004 earnings, is expected from anticipated improvements in Power's nuclear and fossil operations, anticipated higher margins through the expiration of existing contracts, the realization of current and anticipated higher market prices and additional generation going into service. It is expected that these increases will be partially offset by higher Depreciation expense and lower earnings from Power's NDT Funds.

      The improvements discussed above are expected to increase Power's earnings in the latter part of the five-year planning period. Based on these assumptions, Power expects annual earnings growth in a range of 10% to 14% from 2005 to 2009. Power's future success as an energy provider will depend, in part, on its ability to meet its obligations under its full requirements contracts efficiently and profitably and the efficient operation of its low-cost nuclear and coal generation facilities. Power's ability to meet its forecasts are expected to continue to be impacted by low-capacity prices due to the oversupply of electric generation capacity and the resulting competition combined with volatile prices and conditions in energy and fuel markets, including increasing commodity and transportation costs. In addition,such factors could impact liquidity in the event that Power is required to post margin related to its commodity contracts. See Note 14. Commitments and Contingent Liabilities—Guaranteed Obligations of the Notes for additional information.

**Energy Holdings**

      Energy Holdings, through Global, owns and operates electric generation and distribution facilities in international and U.S. markets. The generation plants sell power under long-term agreements, as well as on a merchant basis, while the distribution companies are rate-regulated enterprises. Through Resources, Energy Holdings invests in energy-related financial transactions, including leveraged leases, which are designed to produce predictable earnings and cash flows.

      During 2004, Energy Holdings generated substantial cash flows from operations and asset sales, as discussed below, which it has used to meet its scheduled debt maturity of $267 million in February 2004, repurchase approximately $41 million of its 2007 debt, reducing its next debt maturity to $309 million, and return $491 million of capital to PSEG. In addition, Energy Holdings and its subsidiaries have $199 million of cash (including cash offshore) and a $115 million receivable from PSEG as of December 31, 2004.

      For 2005,  Energy Holdings expects Income from Continuing Operations to range from $135  million to $155 million. The expected 2005 range exceeds the 2004 Income from  Continuing Operations as stronger results from TIE, lower financing costs and  the absence of foreign currency losses at Elektrocieplownia Chorzow Sp. Z o.o.  (ELCHO) more than offset the loss of earnings from the sale of Meiya Power Company  Limited (MPC) and the partial sale of Luz del Sur S.A. (LDS) in 2004. Energy  Holdings expects annual earnings growth of 2% to 3% from 2005 to 2009. This  expected earnings growth assumes a stable foreign currency environment, combined  with expected improvements in earnings from TIE, due to an anticipated recovery  in the Texas market, and improved earnings from Global's facilities in Poland.  It is expected that these improvements will be offset by future reductions in  revenue related to the collection in January 2005 of the final payment related  to the withdrawal from Eagle Point Cogeneration Partnership and the expiration  of the contract for the Bridgewater, New Hampshire facility in 2007.

      **Global**

      Although Global continues to produce significant earnings and operating cash flow, the returns on its international investment portfolio have not been commensurate with the level of risk associated with international investments in developing energy markets. Such risks 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. As a result, since 2003, Energy Holdings has refocused its strategy from one of accelerated growth to one that places emphasis on increasing the efficiencyand returns of its existing assets and seeks to opportunistically monetize investments that may no longer have a strategic fit.

      As part of this process, in 2004, Global completed (1) the sale of its investment in Carthage Power Company (CPC), a generating facility in Rades, Tunisia, for proceeds of $43 million; (2) the sale of a portion of its shares in LDS, a power distribution company in Peru, for proceeds of approximately $31 million; (3) the

49

acquisition of all of TECO Energy Inc.'s (TECO) interests in TIE, which owns two power generation facilities in Texas, for less than $1 million, bringing Global's ownership interest to 100%; and (4) the sale of its 50% equity interest in MPC for approximately $236 million, of which $100 million was paid in cash and the balance of approximately $136 million is in the form of a note due on March 31, 2005. In January 2005, a $38 million principal payment of this note was received. In addition, as part of this change in strategy, Global continues to limit its capital spending, while focusing on operations and improved performance of existing businesses. In 2005, the capital requirements of Global's consolidated subsidiaries will primarily be financed from internally generated cash flow within the projects and from local sources on anon-recourse basis or limited discretionary investments by Energy Holdings.

      Global's success will depend, in part, upon its ability to mitigate risks of its international strategy. The economic and political conditions in certain countries where Global has investments present risks that may be different or more significant than those found in the U.S. including: renegotiation or nullification of existing contracts, changes in law or tax policy, interruption of business, nationalization, expropriation, war and other factors. Operations in foreign countries also present risks associated with currency exchange and convertibility, inflation and repatriation of earnings. In some countries in which Global has interests, economic and monetary conditions and other factors could affect its ability to convert its cash distributions to U.S. Dollars or other freely convertible currencies. Furthermore,the central bank of any such country may have the authority to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to limit distributions to foreign investors. Although Global generally seeks to structure power purchase contracts and other project revenue agreements to provide for payments to be made in, or indexed to, U.S. Dollars or a currency freely convertible into U.S. Dollars, its ability to do so in all cases may be limited.

      **Resources**

      Resources continues to focus on maintaining its current investment portfolio and does not expect to make any new investments. Resources' objective is to produce predictable cash flows, earnings and related tax benefits while monitoring credit concerns with respect to certain lessees in its portfolio. Resources' ability to realize tax benefits associated with its leveraged lease investments is dependent upon operating gains generated by its affiliates. In April 2004, Resources terminated its lease with Edison Mission Energy (EME) in the Collins generating facility, strengthening the credit quality of Resources' remaining exposure with EME, resulting in a weighted average rating of the lessees in Resources' lease portfolio of A-/A3. As a result of sales during 2004, Resources' investment in leveraged buyoutfunds has been reduced from approximately $75 million as of December 31, 2003 to approximately $27 million as of December 31, 2004.

      Resources' earnings and cash flows are expected to decrease in the future as the investment portfolio matures. Resources faces risks with regard to the creditworthiness of its counterparties, specifically certain lessees that collectively comprise a substantial portion of Resources' investment portfolio as discussed further below. Resources also faces risks related to potential changes in the current tax treatment of its investments in leveraged leases. The manifestation of either of these risks could cause a materially adverse effect on Resources' strategy and its forecasted results of operations, financial position and net cash flows.

      Resources has credit risk related to its investments in leveraged leases, totaling $1.2 billion, net of deferred taxes of $1.6 billion, as of December 31, 2004. These investments are largely concentrated in the energy industry and have some exposure to the airline industry. As of December 31, 2004, 69% of counterparties in the lease portfolio were rated investment grade by both Standard & Poors (S&P) and Moody's. For further discussion of these leveraged leases, see Item 7A. Qualitative and Quantitative Discussion of Market Risk—Credit Risk—Resources.

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**RESULTS OF OPERATIONS**

**PSEG, PSE&G, Power and Energy Holdings**

      Net Income for the year ended December 31, 2004 was $726 million or $3.05 per share of common stock, diluted, based on approximately 238 million average shares outstanding. Net Income for the year ended December 31, 2003 was approximately $1.2 billion or $5.07 per share of common stock, diluted, based on approximately 229 million average shares outstanding. Included in 2003's Net Income was a $370 million after-tax Cumulative Effect of a Change in Accounting Principle related to the adoption in 2003 of Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). See Note 3. Asset Retirement Obligations of the Notes. For the year ended December 31, 2002, Net Income was $235 million or $1.13 per share of common stock, diluted,including certain after-tax charges of $538 million or $2.57 per share. The charges related to the abandoned Argentine investments and losses from operations of those assets, discontinued operations of PSEG Energy Technologies Inc. (Energy Technologies) and Tanir Bavi Power Company Private Ltd. (Tanir Bavi), a generating facility in India, and goodwill impairment charges.
   **Earnings (Losses)**   **Years Ended December 31,**   **2004** **2003** **2002**   **(Millions)**      
PSE&G
    $346         $247         $205       
Power
     308          474          468       
Energy Holdings:
                  
Global(A)
     78          121          (297)      
Resources
     68          72          84       
Other(B)
     (10)         (4)         (7)                                  
Total Energy Holdings(A)
     136          189          (220)      
Other(C)(D)
     (69)         (58)         (48)                                  
PSEG Income from Continuing Operations
     721          852          405       
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal(E)
     5          (44)         (49)      
Extraordinary Item(F)
     —          (18)         —       
Cumulative Effect of a Change in Accounting Principle(G)
     —          370          (121)                                  
**PSEG Net Income(A)**
    $726         $1,160         $235                                                  **Contribution to EarningsPer Share (Diluted)**   **Years Ended December 31,**   **2004** **2003** **2002**      
PSE&G
    $1.45         $1.08         $0.98       
Power
     1.29          2.07          2.24       
Energy Holdings:
                  
Global(A)
     0.35          0.53          (1.42)      
Resources
     0.29          0.31          0.40       
Other(B)
     (0.04)         (0.02)         (0.04)                                  
Total Energy Holdings(A)
     0.60          0.82          (1.06)      
Other(C)(D)
     (0.31)         (0.25)         (0.22)                                  
PSEG Income from Continuing Operations
     3.03          3.72          1.94       
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal(E)
     0.02          (0.19)         (0.23)      
Extraordinary Item(F)
     —          (0.08)         —       
Cumulative Effect of a Change in Accounting Principle(G)
     —          1.62          (0.58)                                  
**PSEG Net Income(A)**
    $3.05         $5.07         $1.13                             
*(footnotes on next page)*

51

*(footnotes from previous page)*
                     (A)   Includes after-tax write-down and losses related to Argentine investments of $368 million or $1.76 per share for the year ended December 31, 2002.   (B)   Other activities include amounts of Energy Holdings (parent company), Energy Technologies, Enterprise Group Development Corporation (EGDC) and intercompany eliminations. Specific amounts include interest on certain financing transactions and certain other administrative and general expenses at Energy Holdings.   (C)   Includes pre-tax costs related to the Merger of approximately $8 million for the year ended December 31, 2004, including investment banking fees, accounting and legal fees, consulting fees for market analyses and communications costs.   (D)   Other activities include amounts of PSEG (parent company) and intercompany eliminations. Specific amounts include preferred securities dividends requirements for PSE&G and Energy Holdings, interest on certain financing transactions and certain other administrative and general expenses at PSEG (parent company).   (E)   Includes Discontinued Operations of Energy Technologies in 2003 and 2002, CPC in 2004, 2003 and 2002, and Tanir Bavi in 2002. See Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes.   (F)   Relates to a charge recorded in the second quarter of 2003 from PSE&G's Electric Base Rate Case. See Note 5. Extraordinary Item of the Notes.   (G)   Relates to the adoption of SFAS 143 in 2003 and the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142) in 2002. See Note 2. Recent Accounting Standards and Note 3. Asset Retirement Obligations of the Notes.
      The $131 million, or $0.69 per share, decrease in Income from Continuing Operations for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to lower earnings at Power due to decreased load being served under the fixed-price BGS contracts, higher Operation and Maintenance costs primarily incurred for work performed during a longer-than-planned refueling outage at the Hope Creek nuclear unit, the loss of MTC revenues, which ceased effective August 1, 2003 at the end of the transition period and higher replacement power and congestion costs in 2004. Also contributing to the decrease were currency fluctuations at Global and lower earnings at Resources, primarily resulting from the termination of the Collins lease. These decreases were partially offset by improved earnings atPSE&G primarily relating to increased electric base rates.

      Also contributing to the change in Net Income was Energy Holdings' Income from Discontinued Operations of $5 million for the year ended December 31, 2004, as compared to its Loss from Discontinued Operations of $44 million, after-tax, for the same period in 2003.

      The $447 million increase in Income from Continuing Operations for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to higher earnings from Energy Holdings due to the absence of the $368 million after-tax losses at Energy Holdings' Argentine investments recorded in 2002. In addition, PSE&G improved earnings due to increased electric base rates, seasonality differences in pricing that are a component of those rates, favorable weather effects and lower interest costs. In addition, Power had slightly higher earnings primarily related to the benefits resulting from the operation of the two generating facilities in Connecticut that were acquired in December 2002, higher margins driven by an increase in volume as a result of the BGS contracts that went into effect inAugust 2002 and realized gains in its NDT portfolio, partially offset by the effects of storm-related weather and higher Operation and Maintenance expense. Also contributing to Energy Holdings' increase in earnings were improved results from Global. The growth in Income from Continuing Operations did not result in higher per share amounts due to dilution caused mainly by the PSEG Common Stock issuance in the fourth quarter of 2003.

      Included in PSEG's 2003 Net Income was an after-tax benefit of $370 million related to the adoption of SFAS 143 during the first quarter of 2003. This benefit was due mainly to the required remeasurement of Power's nuclear decommissioning obligations. Conversely, in 2002, PSEG adopted SFAS 142 and incurred an after-tax charge of $121 million related to goodwill impairments at certain of Energy Holdings' investments. Also contributing to the changes in Net Income was a decrease in Energy Holdings' Loss from Discontinued Operations, including Loss on Disposal of $5 million, after-tax, for the year ended December 31, 2003, as

52

compared to the same period in 2002, and an $18 million, after-tax, extraordinary charge recorded at PSE&G in the second quarter of 2003 related to the outcome of its electric base rate case, discussed above in PSE&G's Overview of 2004 and Future Outlook.

**PSEG**
  **For theYears EndedDecember 31,** **2004 vs 2003** **2003 vs 2002**  **2004** **2003** **2002** **Increase(Decrease)** **%** **Increase(Decrease)** **%**      **(Millions)**         **(Millions)**    
Operating Revenues
    $10,996     $11,139     $8,220     $(143)     (1)    $2,919      36 
Energy Costs
    $6,057     $6,391     $3,710     $(334)     (5)    $2,681      72 
Operation and Maintenance
    $2,260     $2,120     $1,899     $140      7     $221      12 
Depreciation and Amortization
    $719     $527     $565     $192      36     $(38)     (7)
Income from Equity Method Investments
    $126     $114     $119     $12      11     $(5)     (4)
Other Income
    $176     $178     $39     $(2)     (1)    $139      356 
Other Deductions
    $(93)    $(101)    $(80)    $(8)     (8)    $21      26 
Interest Expense
    $(859)    $(836)    $(819)    $23      3     $17      2 
Income Tax Expense
    $(446)    $(464)    $(254)    $(18)     (4)    $210      83                             
      PSEG's results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power and Energy Holdings, excluding changes related to intercompany transactions, which are eliminated in consolidation and certain financing costs at the parent company. For additional information on intercompany transactions, see Note 23. Related-Party Transactions of the Notes. For a discussion of the causes for the variances at PSEG in the table above, see the discussions for PSE&G, Power and Energy Holdings that follow.

**PSE&G**
  **For theYears EndedDecember 31,** **2004 vs 2003** **2003 vs 2002**  **2004** **2003** **2002** **Increase(Decrease)** **%** **Increase(Decrease)** **%**      **(Millions)**         **(Millions)**    
Operating Revenues
    $6,972     $6,740     $5,919     $232      3     $821      14 
Energy Costs
    $4,284     $4,421     $3,684     $(137)     (3)    $737      20 
Operation and Maintenance
    $1,083     $1,050     $982     $33      3     $68      7 
Depreciation and Amortization
    $523     $372     $409     $151      41     $(37)     (9)
Other Income
    $12     $6     $15     $6      100     $(9)     (60)
Other Deductions
    $(1)    $(1)    $(2)    $—      —     $(1)     (50)
Interest Expense
    $(362)    $(390)    $(406)    $(28)     (7)    $(16)     (4)
Income Tax Expense
    $(246)    $(129)    $(115)    $117      91     $14      12                             
      **Operating Revenues**

      PSE&G has three sources of revenue: commodity revenues from the sales of energy to customers and in the PJM spot market; delivery revenues from the transmission and distribution of energy through its system; and other operating revenues from the provision of various services.

      ***Commodity***

      PSE&G makes no margin on commodity sales as the costs are passed through to customers. The difference between costs and the amount provided by customers in revenues is deferred and collected from or returned to customers in future periods. Total commodity volumes and revenues are subject to market forces. Gas commodity prices fluctuate monthly for commercial and industrial customers and annually through the BGSS tariff for residential customers. In addition, for residential gas customers, PSE&G has the ability to adjust rates upward two additional times and downward at any time, if warranted, between annual Basic Gas Supply Service (BGSS) proceedings.

53

      Gas commodity revenues decreased $3 million for the year ended December 31, 2004, as compared to the same period in 2003, due primarily to lower sales volumes of 20%, offset by higher BGSS prices. Approximately 80% of the volume decline was due to lower sales to cogenerators and the balance was weather-related. Electric commodity prices are set at the annual BGS auction. Electric commodity revenues increased $16 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to $249 million in increased prices offset by $233 million in lower volumes of 12% caused by migration of large customers to third-party suppliers.

      Gas commodity revenues increased $660 million for the year ended December 31, 2003, as compared to the same period in 2002, due primarily to higher sales volumes of 9% and higher BGSS prices. Electric commodity revenues increased $80 million for the year ended December 31, 2003, as compared to the same period in 2002, primarily due to $217 million in increased prices offset by $137 million in lower volumes of 7% caused by migration of large customers to third-party suppliers.

      ***Delivery***

      Electric delivery revenues increased $222 million for the year ended December 31, 2004, as compared to the same period in 2003. The net effect of full-year base rate increases in August 2003, combined with other annual rate adjustments in January 2004, increased revenues by $180 million. The balance of the increase was driven by higher sales volumes of 3%. Less than one percent of the sales increase was weather-related.

      Gas delivery revenues decreased $24 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to a 4% decline in residential sales due to weather. Heating degree days were 5% lower in 2004.

      Gas delivery revenues increased $97 million for the year ended December 31, 2003, as compared to the same period in 2002, due to higher sales volumes of 14%, primarily due to weather. Heating degree-days were 21% higher in 2003.

      **Operating Expenses**

      ***Energy Costs***

      The $137 million decrease for the year ended December 31, 2004, as compared to the same period in 2003, was comprised of decreases of $96 million in electric costs and $41 million in gas costs. The electric decrease was caused by $262 million in lower BGS volumes due to customer migration to third-party suppliers offset by $166 million in higher prices for BGS and Non-Utility Generation (NUG) purchases. The gas decrease was caused by a $388 million or 20% decrease in sales volumes due primarily to lower sales to cogenerators offset by a $347 million or 26% increase in gas prices.

      The $737 million increase for the year ended December 31, 2003, as compared to the same period in 2002, was comprised of increases of $658 million in gas costs and $79 million in electric costs. The gas increase was caused by a $527 million or 26% increase in gas prices and $131 million or 9% increase in sales volumes. The electric increase was caused by $249 million in higher prices for BGS and NUG purchases, partially offset by $170 million in lower costs due to lower BGS volumes as the result of customer migration and lower NUG volumes.

      ***Operation and Maintenance***

      The $33 million increase for 2004, as compared to the same period in 2003, was due primarily to increased Demand Side Management (DSM) amortization of $20 million, increased consumer education expenses of $24 million, an $18 million reduction in real estate tax expense in 2003 and $10 million related to a regulatory asset reserve reversal in 2003. DSM costs are deferred when incurred and amortized to expense when recovered in revenues. Offsetting the increases were decreased labor and fringe benefits of $7 million, due to lower pension costs as a result of improved fund performance, a $22 million reduction in Societal Benefits Charges (SBC) expenses and $10 million in lower shared services costs due to reduced technology spending.

      The $68 million increase for the year ended December 31, 2003, as compared to the same period in 2002, was due primarily to higher labor and fringe benefit costs of $48 million, due to higher wage and incentive program costs, higher pension costs and increased weather and storm-related expenses due to Hurricane

54

Isabel and the extreme winter weather. Also contributing to the increase were higher bad debt expense of $10 million due to high winter gas sales and higher DSM costs of approximately $38 million related to the increased sales, discussed above. Partially offsetting these increases were a reduction in real estate tax expense of $18 million and the reversal of a $10 million reserve against a regulatory asset that is now being recovered.

      ***Depreciation and Amortization***

      The $151 million increase for the year ended December 31, 2004, as compared to the same period in 2003, was due primarily to a $132 million reduction in amortization of an excess electric distribution depreciation reserve regulatory liability, a $30 million increase in the amortization of various regulatory assets and a $10 million increase due to increased plant in service. These increases were offset by a $16 million decrease from the use of a lower book depreciation rate for electric distribution property, which took effect in August 2003 following the conclusion of the electric base rate case, and a $6 million decrease due to plant assets transferred to an affiliate in 2003.

      The $37 million decrease for the year ended December 31, 2003, as compared to the same period in 2002, was due primarily to a $52 million increase in amortization of an excess electric distribution depreciation reserve regulatory liability and a $11 million decrease from the use of a lower book depreciation rate for electric distribution property starting in August 2003 due to the rate case referred to above. These decreases were offset by increases of $13 million due to increased plant in service and $9 million due to amortization of regulatory assets related to securitization.

      ***Other Income***

      The $6 million increase for the year ended December 31, 2004, as compared to the same period in 2003, was due primarily to $11 million of equity return adjustments to regulatory assets in 2003, $4 million of interest income related to an affiliate loan and other Investment Income of $3 million offset by decreased gains on excess property sales of $12 million.

      The $9 million decrease for the year ended December 31, 2003, as compared to the same period in 2002, was due primarily to equity return adjustments to regulatory assets of $11 million offset by $2 million in increased gains on the disposal of various electric transmission properties.

      ***Interest Expense***

      The $28 million decrease for the year ended December 31, 2004, as compared to the same period in 2003, was due primarily to lower interest on long-term debt of $37 million as a result of lower interest rates and lower levels of long-term debt outstanding, partially offset by $11 million in increased interest on affiliated loans.

      The $16 million decrease for the year ended December 31, 2003, as compared to the same period in 2002, was due primarily to lower interest on long-term debt of $23 million due to various maturities and redemptions of approximately $250 million. These decreases were partially offset by increased short-term interest expense of $2 million due to higher short-term debt balances outstanding due to increased working capital needs and $6 million in increased carrying charges related to certain regulatory assets.

      **Income Taxes**

      The $117 million increase for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to higher pre-tax income combined with lower tax benefits primarily attributable to the excess depreciation reserve adjustment in 2003.

      The $14 million increase for the year ended December 31, 2003, as compared to the same period in 2002, was due to higher pre-tax income, offset by tax benefits recorded in 2003 attributable to the actual filing of the 2002 tax return.

      **Extraordinary Item**

      As discussed previously, included in the Electric Base Rate Case decision issued by the BPU was a refund related to revenues collected through the SBC for nuclear decommissioning. Because this amount

55

reflects the final accounting for PSEG's generation-related business pursuant to the four-year transition plan mandated by the Final Order, the adjustment has been recorded as an $18 million, after-tax, Extraordinary Item as required under Accounting Principles Board (APB) Opinion No. 30, “Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions” (APB 30) and SFAS No. 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of Financial Accounting Standards Board (FASB) Statement No. 71.”

**Power**
  **For theYear EndedDecember 31,** **2004 vs 2003** **2003 vs 2002**  **2004** **2003** **2002** **Increase(Decrease)** **%** **Increase(Decrease)** **%**      **(Millions)**         **(Millions)**    
Operating Revenues
    $5,173     $5,613     $3,640     $(440)     (8)    $1,973      54 
Energy Costs
    $3,558     $3,754     $1,856     $(196)     (5)    $1,898      102 
Operation and Maintenance
    $967     $914     $773     $53      6     $141      18 
Depreciation and Amortization
    $121     $102     $108     $19      19     $(6)     (6)
Other Income
    $166     $149     $1     $17      11     $148      n/a 
Other Deductions
    $(57)    $(78)    $(1)    $(21)     (27)    $77      n/a 
Interest Expense
    $(142)    $(114)    $(122)    $28      25     $(8)     (7)
Income Tax Expense
    $(186)    $(326)    $(313)    $(140)     (43)    $13      4                             
      **Operating Revenues**

      Operating Revenues decreased by $440 million for the year ended December 31, 2004, as compared to the same period in 2003, due to decreases of $485 million in generation revenues and $5 million in trading revenues offset by an increase of $50 million in gas supply revenues.

      Operating Revenues increased by $2 billion for the year ended December 31, 2003, as compared to the same period in 2002, due to increases of $646 million in generation revenues, $1.3 billion in gas supply revenues and $12 million in trading revenues.

      ***Generation***

      Generation revenues decreased by $485 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to $1.1 billion in lower revenues due to decreased load being served under the fixed-priced BGS contracts, which was partially offset by $869 million of higher revenues from new contracts and higher sales into the various power pools. Additionally, the loss of MTC and NDT revenues, which amounted to $111 million and $17 million, respectively, comprised part of the decrease.

      Also contributing to the decrease was the adoption of Emerging Issues Task Force (EITF) Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities,” and Not “Held for Trading Purposes” as defined in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 03-11), which requires gains and losses (realized and unrealized) on all derivative instruments within the scope of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) to be shown net when recognized in the ConsolidatedStatement of Operations, whether or not settled physically, if the derivative instruments are “held for trading purposes” as defined in EITF 02-3, which became effective on a prospective basis for transactions occurring after September 30, 2003. Since prior periods were not restated, the effect of adopting EITF 03-11 reduced Power's Operating Revenues by approximately $174 million, with an equal reduction in Energy Costs, as compared to the same period in 2003.

      Generation revenues increased by $646 million for the year ended December 31, 2003, as compared to the same period in 2002, primarily due to increased BGS related revenues of $293 million from third-party wholesale electric suppliers which commenced on August 1, 2002 and $153 million in increased revenues from two generation facilities in Connecticut acquired in 2002 and the Waterford, Ohio plant, which became operational in August 2003. Also contributing to the increase were increased MTC revenues of $13 million,

56

increased capacity sales of $41 million and $167 million of higher revenues from new contracts and higher sales into the various power pools.

      ***Gas Supply***

      Gas supply revenues increased by $50 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to higher gas prices under the BGSS contract partially offset by decreased sales volumes mainly due to demand by PSE&G.

      Gas supply revenues increased by $1.3 billion for the year ended December 31, 2003, as compared to the same period in 2002, primarily due to 2003 being the first full year of the BGSS contract with PSE&G compared to a partial year in 2002 since the contract commenced in May 2002. Gas revenues for the first four months of 2003 totaled $1.1 billion. Also contributing to the increase in gas revenues were higher sales volumes and higher gas prices.

      **Operating Expenses**

      ***Energy Costs***

      Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power's obligation under its BGSS contract with PSE&G.

      Energy Costs decreased approximately $196 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to a $216 million decrease in purchased power due to decreased load being served under the BGS contracts, which was offset by increased replacement power costs due to outages and higher purchased power for new contracts and a $12 million increase in gas supply costs due to higher gas prices. For additional information related to the outages at Power facilities, see the MD&A—Overview of 2004 and Future Outlook—Power. Also contributing to the decrease for the year was a reduction of approximately $174 million related to the adoption of EITF 03-11, as discussed above. Partially offsetting these decreases were higher fuel costs for generation of approximately $159million, primarily related to higher gas prices and higher usage, including an increase of approximately $20 million related to the settlement for nuclear waste storage costs for Peach Bottom. For additional information regarding the settlement, see Note 14. Commitments and Contingent Liabilities—Nuclear Fuel Disposal of the Notes.

      Energy Costs increased approximately $1.9 billion for the year ended December 31, 2003, as compared to the same period in 2002, primarily due to a $1.3 billion increase in gas costs due to the effect of a full year under the BGSS contract combined with higher gas sales volumes and prices and higher gas, oil and coal costs for generation. The increase in Energy Costs was also due to increased energy purchases on the spot market, as well as bilateral energy purchases, of approximately $413 million. Also, Power incurred an increase of approximately $116 million in network transmission expenses given that there were no payments for the first seven months in 2002. In addition, charges associated with fuel and energy purchases to satisfy wholesale power agreements related to its Connecticut generating facilities totaledapproximately $80 million for the year ended December 31, 2003.

      ***Operation and Maintenance***

      Operation and Maintenance expense increased $53 million for the year ended December 31, 2004, as compared to the same period in 2003, due to increased costs of $85 million related to the outages at Hope Creek, Salem and Mercer. For additional information related to the outages at Power facilities, see the MD&A—Overview of 2004 and Future Outlook—Power. Also contributing to the increase was $10 million of higher operation and maintenance costs related to the Waterford and Lawrenceburg facilities offset by $12 million related to the settlement for nuclear waste storage costs for Peach Bottom, $10 million in lower real estate taxes and other items. Additional offsets include the absence of reorganization costs of $9 million and the lower write-down costs related to obsolete materials and supplies of $8million. For additional information regarding the settlement, see Note 14. Commitments and Contingent Liabilities—Nuclear Fuel Disposal of the Notes.

      Operation and Maintenance expense increased $141 million for the year ended December 31, 2003, as compared to the same period in 2002, due to costs of generating facilities in Connecticut acquired in December 2002 of $56 million, accretion expense of $24 million associated with the nuclear decommissioning

57

liabilities and higher nuclear refueling outage costs of $24 million. Also contributing to the increase was higher pension expense of $20 million, higher reorganization costs of $9 million and higher write-down costs related to obsolete materials and supplies of $8 million.

      ***Depreciation and Amortization***

      Depreciation and Amortization expense increased $19 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to the Waterford facility being placed into service in August 2003 and the Lawrenceburg facility being placed into service in June 2004.

      Depreciation and Amortization expense decreased $6 million for the year ended December 31, 2003, as compared to the same period in 2002. The net decrease was comprised of lower depreciation costs of approximately $30 million due to the absence of decommissioning charges, which are no longer recorded as a result of the implementation of SFAS 143, partially offset by higher depreciation and amortization primarily related to generating facilities in Connecticut acquired in December 2002 and a higher asset base.

      **Other Income**

      Other Income increased $17 million for the year ended December 31, 2004, as compared to the same period in 2003, due primarily to increased realized gains and income related to the NDT Funds.

      Other Income increased $148 million for the year ended December 31, 2003, as compared to the same period in 2002, due primarily to the recording of realized gains and income on the NDT Funds.

      **Other Deductions**

      Other Deductions decreased by $21 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to $28 million in lower realized losses and expenses related to the NDT Funds partially offset by a $7 million write-off of unamortized issuance costs related to the extinguishment of project financing related to Power's Waterford and Lawrenceburg facilities.

      Other Deductions increased by $77 million for the year ended December 31, 2003, as compared to the same period in 2002, due primarily to the recording of realized losses on the NDT Funds.

      **Interest Expense**

      Interest Expense increased by $28 million for the year ended December 31, 2004, as compared to the same period in 2003, including $17 million of increased interest primarily due to higher interest rates on new long-term debt financing that replaced project level non-recourse debt. Also contributing to the increase was interest of $7 million related to the early settlement of an interest rate swap related to the extinguishment of project financing related to the Waterford and Lawrenceburg facilities and higher interest of $4 million related to an affiliate loan.

      Interest Expense decreased by $8 million for the year ended December 31, 2003, as compared to the same period in 2002. Capitalized interest relating to various construction projects reduced interest expense by approximately $13 million for the year ended December 31, 2003, as compared to the same period in 2002. Power incurred additional interest charges of $20 million due primarily to the new long-term financing of $600 million in June 2002, this increase was partially offset by lower interest expense on variable rate debt and other lower charges of approximately $15 million.

      **Income Taxes**

      Income taxes decreased by $140 million for the year ended December 31, 2004, as compared to the same period in 2003, due primarily to lower pre-tax income.

      Income taxes increased by $13 million for the year ended December 31, 2003, as compared to the same period in 2002, due primarily to higher pre-tax income.

      **Cumulative Effect of a Change in Accounting Principle**

      For the year ended December 31, 2003, Power recorded an after-tax benefit in the amount of $370 million due to the required remeasurement of Power's nuclear and fossil decommissioning obligations under

58

SFAS 143, which was adopted on January 1, 2003. See Note 3. Asset Retirement Obligations of the Notes for additional information.

**Energy Holdings**
  **For theYears EndedDecember 31,** **2004 vs 2003** **2003 vs 2002**  **2004** **2003** **2002** **Increase(Decrease)** **%** **Increase(Decrease)** **%**      **(Millions)**         **(Millions)**    
Operating Revenues
    $1,027     $725     $609     $302      42     $116      19 
Energy Costs
    $388     $155     $118     $233      150     $37      31 
Operation and Maintenance
    $239     $176     $168     $63      36     $8      5 
Write-down of Project Investments
    $—     $—     $511     $—      —     $(511)     (100)
Depreciation and Amortization
    $57     $44     $28     $13      30     $16      57 
Income from Equity Method Investments
    $126     $114     $119     $12      11     $(5)     (4)
Other Income
    $4     $20     $26     $(16)     (80)    $(6)     (23)
Other Deductions
    $(33)    $(5)    $(77)    $28      560     $(72)     (94)
Interest Expense
    $(255)    $(218)    $(217)    $37      17     $1      — 
Income Tax (Expense) Benefit
    $(48)    $(59)    $144     $(11)     (19)    $203      141                             
      The variances in Operating Revenues, Energy Costs, Operation and Maintenance expense, Depreciation and Amortization expense and Income from Equity Method Investments were primarily attributed to Global's acquisition of the remaining interests in TIE, thus consolidating the entity effective July 1, 2004, as compared to 2003 when Global's ownership was accounted for under the equity method of accounting. For additional information, see Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes. The increases were also due to ELCHO placing a new generation facility in Poland in service in November 2003, a generation facility in Oman owned by Dhofar Power Company S.A.O.C. (Dhofar Power) beginning commercial operation in May 2003 and increases in ownership of Electrowina Skawina S.A (Skawina)in Poland in 2003 and 2004. The variances are also related to favorable foreign currency exchange rates and higher energy sales volumes at Sociedad Austral de Electricidad S.A. (SAESA) and a change for GWF Energy LLC (GWF Energy), which owns three generation facilities in California, which was accounted for under the equity method of accounting in 2004, due to a change in ownership interest, as compared to the first nine months of 2003 and the fourth quarter of 2002 when GWF Energy was consolidated.

      **Operating Revenues**

      The increase of $302 million for the year ended December 31, 2004, as compared to the same period in 2003, was due to higher revenues at Global of $355 million, including a $247 million increase related to the consolidation of TIE, a $62 million increase from ELCHO, a $35 million increase from SAESA, a $25 million increase from Dhofar Power and a $35 million gain on the sale of MPC, partially offset by a decrease of $53 million related to GWF Energy, which was not consolidated in 2004. Offsetting the increases at Global were lower revenues at Resources of $51 million, primarily due to a loss of $31 million related to the recalculation of certain leverage leases, a loss of $11 million due to the termination of the lease investment in the Collins generating facility and normal amortization of existing leases of $10 millionoffset by a realized gain of $2 million related to investments in leases, partnerships and securities. See Note 10. Long-Term Investments of the Notes for additional information.

      The increase of $116 million for the year ended December 31, 2003, as compared to the same period in 2002, was due to higher revenues at Global of $124 million, including a $47 million increase from Skawina, a $38 million increase from Dhofar Power, a $28 million increase from GWF Energy, which was consolidated for nine months in 2003 compared to three months in 2002, and a $19 million increase from SAESA, offset by the absence of $19 million in revenue from Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), in Argentina, which was abandoned in 2003. Offsetting the increases at Global were lower revenues at Resources of $10 million, primarily related to a $45 million net decrease in leveraged lease income and a $6 million decrease in realized income due to the termination of two leveraged leases inDecember 2002. Partially offsetting these decreases was the absence of an other than temporary impairment of non-publicly traded equity securities held within the leveraged buyout funds of $42 million that was recorded in 2002.

59

      **Energy Costs**

      The increase of $233 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to a $192 million increase related to the consolidation of TIE and increases of $22 million, $12 million and $5 million from SAESA, ELCHO and Dhofar Power, respectively, offset by a decrease of $3 million from GWF Energy.

      The increase  of $37 million for the year ended December 31, 2003, as compared to the  same period in 2002, was primarily due to an increase of $21 million, $14 million,  and $13 million from Skawina, SAESA and Dhofar Power, respectively, offset by  a decrease of $7 million and $5 million from EDEERSA and Electroandes S.A. (Electroandes),  respectively.

      **Operation and Maintenance**

      The increase of $63 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to a $30 million increase related to the consolidation of TIE and increases of $12 million, $9 million, and $2 million from ELCHO, SAESA and Dhofar Power, respectively, offset by a decrease of $8 million from GWF Energy. The increase is also due to higher operating expenses of $9 million at PSEG Energy Technologies Asset Management Company L.L.C. primarily due to higher legal expenses and final asset sale settlements and $7 million at Global primarily due to the 2003 reversal of contingencies related to the Argentine write-down.

      The increase of $8 million for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to increases of $19 million, $7 million, $6 million and $6 million from Skawina, Dhofar Power, GWF Energy and Electroandes, respectively, offset by decreased operation and maintenance expenses at Global of $28 million related to the abandonment of Global's Argentine investments combined with lower labor and administrative costs.

      **Write-down of Project Investments**

      The decrease of $511 million for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to Global's write-down of investments in 2002, primarily in Argentina. See Note 6. Asset Impairments of the Notes.

      **Depreciation and Amortization**

      The increase of $13 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to a $9 million increase related to the consolidation of TIE and increases of $7 million, $5 million and $2 million from ELCHO, Dhofar Power and SAESA, respectively, offset by a decrease of $11 million from GWF Energy.

      The increase of $16 million for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to increases of $8 million from both Dhofar Power and GWF Energy.

      **Income from Equity Method Investments**

      The increase of $12 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily driven by an $8 million increase related to the sale of a portion of Global's investment in LDS, an $11 million increase related to MPC due to additional projects going into operation, and a $4 million increase related to GWF Energy, offset by an $11 million decrease related to the consolidation of TIE commencing July 1, 2004.

      The decrease of $5 million for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to lower equity method income in 2003 of $17 million at GWF Energy, which was recorded as a consolidated company for the first three quarters in 2003, as well as decreased earnings at Chilquinta Energia S.A. (Chilquinta) of $4 million. Partially offsetting this decrease were improved earnings at TIE of $14 million related to power purchase agreements (PPAs) entered into in early 2003 and improved market conditions in Texas.

60

      **Other Income**

      The decrease of $16 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to the absence in 2004 of foreign currency transaction gains of $16 million for RGE and SAESA that occurred in 2003.

      The decrease of $6 million for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to the absence of favorable changes in fair value mainly relating to foreign exchange contracts held by Energy Holdings.

      **Other Deductions**

      The increase of $28 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to foreign currency transaction losses of $26 million and a loss on early extinguishment of debt of $3 million in 2004, offset by a $5 million favorable change in derivative fair value related to Global. The $26 million in foreign currency transaction losses was almost entirely due to the impact of the weakening U.S. Dollar relative to the Polish Zloty on Global's investment in ELCHO. At the inception of this investment, it was determined that ELCHO is a U.S. Dollar functional currency as a portion of the long-term PPA with the Polish government is indexed to the U.S. Dollar to support the portion of ELCHO's financing that is U.S. Dollar denominated. Since ELCHO has a U.S. Dollar functionalcurrency, all monetary assets and liabilities that are not denominated in U.S. Dollars are marked at period-end exchange rates with changes in values recorded as gains or losses in earnings. ELCHO has significant monetary liabilities in local currency, namely Polish Zloty debt used to partially finance the construction of the plant. As a result of the strengthening of the Polish Zloty against the U.S. Dollar in 2004, there were material losses recorded on the Polish Zloty debt to reflect the greater amount of U.S. Dollars required to pay the local debt. However, the accounting model does not capture the increase in value of Polish Zlotys that will be received under the long-term PPA with the Polish government as the contract is not recorded on the balance sheet. As a result, the financial statements only reflect the losses on the Polish Zloty debt which, economically, have been more thanoffset by the increase in the value of the Polish Zlotys that will be received under the PPA.

      The decrease of $72 million for the year ended December 31, 2003, as compared to the same period in 2002, was largely due to a $77 million foreign currency transaction loss during 2002, which primarily related to Global's Argentine investments.

      **Interest Expense**

      The increase of $37 million for the year ended December 31, 2004, as compared to the same period in 2003, was due to a $13 million increase related to the consolidation of TIE commencing on July 1, 2004, a $29 million increase related to ELCHO since interest was no longer capitalized as the plant became operational in the fourth quarter of 2003, and an increase in non-recourse debt at the project level with higher interest rates, offset in part by the repayment of lower interest rate debt at Energy Holdings during 2003 and 2004.

      **Income Taxes**

      The decrease of $11 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to lower pre-tax income and the impact of changes in certain lease forecast assumptions. In the fourth quarter of 2004, Resources revised several of its lease runs and recorded additional benefits of state tax losses generated by certain of its leases. These additional benefits resulted from changes in Resources' forecast of state taxable income and tax liability over the relevant lease terms. This forecast was embedded in the lease reruns and led to an income tax benefit of $43 million in 2004 to reflect the cumulative benefit of this adjustment. This benefit was largely offset by the tax impact associated with a $31 million decrease in leveraged lease revenue. Future earnings will also increaseby a modest amount as a result of this forecasted benefit. If Resources affiliates' taxable earnings decreased significantly, resulting in the inability of Resources to record the benefits related to its taxable losses, it could lead to an adverse material impact to Resources' results of operations, financial position and cash flows. See Note 17. Income Taxes of the Notes for additional information.

      The increase of $203 million for the year ended December 31, 2003, as compared to the same period in 2002, was primarily attributed to increased pre-tax income for the year ended December 31, 2003, as

61

compared to pre-tax losses in the same period in 2002. The pre-tax losses in 2002 resulted from the write-off of $511 million, primarily related to investments in Argentina. See Note 6. Asset Impairments of the Notes.

      **Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax**

      ***Carthage Power Company****(CPC)***

      In May 2004, Global completed the sale of its interest in CPC for approximately $43 million in cash and recognized a gain on disposal of $5 million after-tax. Loss from Discontinued Operations for the year ended December 31, 2003 was $24 million including a $23 million estimated loss on disposal for the write-down of CPC to its fair value less cost to sell. The operating results of CPC for the year ended December 31, 2002 yielded after-tax income of approximately $1 million. See Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information.

      ***Energy Technologies***

      In September 2003, Energy Holdings completed the sale of the remaining companies of Energy Technologies subsequent to recognizing a loss of $9 million, after-tax, in the first quarter of 2003. Loss from Discontinued Operations for years ended December 31, 2003 and 2002 were $11 million and $41 million, respectively, including the initial write-down in 2002. See Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information.

      ***Tanir Bavi***

      In the fourth quarter of 2002, Global sold its 74% interest in Tanir Bavi, a 220 MW generating facility in India. Global reduced the carrying value of Tanir Bavi to the contracted sales price of $45 million and recorded a loss on disposal of $14 million after-tax for the year ended December 31, 2002. The operating results of Tanir Bavi for the year ended December 31, 2002 yielded after-tax income of $5 million. See Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes.

      **Cumulative Effect of Change in Accounting Principle**

      In 2002, Energy Holdings finalized the evaluation of the effect of adopting SFAS 142 on its recorded amount of goodwill. Under this standard, Energy Holdings was required to complete an impairment analysis of its recorded goodwill and record any resulting impairment. The total amount of goodwill impairments was $121 million, net of tax of $66 million and was comprised of $36 million (after-tax) at EDEERSA, $35 million (after-tax) at RGE, $32 million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir Bavi. All of the goodwill on these companies, other than RGE, was fully impaired. In accordance with SFAS 142, this impairment charge was recorded as of January 1, 2002 as a component of the Cumulative Effect of a Change in Accounting Principle and is reflected in the Consolidated Statement of Operationsfor the year ended December 31, 2002. See Note 9. Goodwill and Other Intangibles of the Notes.

      **Other**

      To supplement the Consolidated Financial Statements presented in accordance with accounting principles generally accepted in the U.S. (GAAP), PSEG and Energy Holdings use the non-GAAP measure of Earnings Before Interest and Taxes (EBIT).

      PSEG's and Energy Holdings' Management each reviews EBIT internally to evaluate performance and manage operations and believes that the inclusion of this non-GAAP financial measure provides consistent and comparable measures to help shareholders understand current and future operating results. PSEG and Energy Holdings urge shareholders to carefully review the GAAP financial information included as part of this Annual Report.

62

      ***Global***

      The following table summarizes Global's capital at risk, net contributions to EBIT and non-recourse interest in the following regions as of December 31, 2004 and 2003 and for the years ended December 31, 2004, 2003 and 2002.
  **Total Capital at Risk(A)** **EBIT(B)** **Non-RecourseInterest(C)**  **As ofDecember 31,2004** **As ofDecember 31,2003** **2004** **2003** **2002** **2004** **2003** **2002**  **(Millions)**
**Region:**
                                
North America
    $427     $423     $98     $117     $122     $13     $2     $— 
South America
     1,581      1,575      135      150      (441)     33      27      44 
Asia Pacific(D)
     6      180      54      8      7      —      —      — 
Europe(E)
     209      285      24      22      (8)     33      5      — 
India and Oman
     94      91      18      9      —      15      9      — 
Global G&A—Unallocated
     —      —      (31)     (30)     (38)     —      —      —                                                  
Total
    $2,317     $2,554     $298     $276     $(358)    $94     $43     $44                                                  
Total Global EBIT
            $298     $276     $(358)            
Interest Expense
             (170)     (119)     (118)            
Income Taxes(D)
             (49)     (23)     178             
Minority Interests
             (1)     (13)     1                                                    
Income from Continuing Operations
            $78     $121     $(297)                                                                                   
**
   (A)   Total Capital at Risk includes Global's gross investments and equity commitment guarantees less non-recourse debt at the project level.   (B)   For investments accounted for under the equity method of accounting, includes Global's share of net earnings, including Interest Expense and Income Taxes.   (C)   Non-recourse interest is Interest Expense on debt that is non-recourse to Global.   (D)   The differences in EBIT and Capital at Risk for Asia Pacific and Income Taxes are primarily due to the sale of MPC which closed on December 31, 2004. The 2004 Capital at Risk does not include the $136 million promissory note received from the sale of MPC. See Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes.   (E)   Foreign currency exchange losses at ELCHO were $28 million, $2 million, and $3 million for the years ended December 31, 2004, 2003 and 2002, respectively.
**LIQUIDITY AND CAPITAL RESOURCES**

      The following discussion of liquidity and capital resources is on a consolidated basis for PSEG, noting the uses and contributions of PSEG's three direct operating subsidiaries, PSE&G, Power and Energy Holdings.

**Financing Methodology**

      **PSEG, PSE&G, Power and Energy Holdings**

      Capital requirements for PSE&G, Power and Energy Holdings are met through liquidity provided by internally generated cash flow and external financings. Although earnings growth has moderated, PSEG expects to be able to fund existing commitments, reduce debt and meet dividend requirements using internally generated cash. PSEG, Power and Energy Holdings from time to time make equity contributions or otherwise provide credit support to their respective direct and indirect subsidiaries to provide for part of their capital and cash requirements, generally relating to long-term investments. PSEG does not intend to contribute additional equity to Energy Holdings.

      At times, PSEG utilizes intercompany dividends and intercompany loans (except however, that PSE&G may not, without prior BPU approval, make loans to its parent or to affiliates) to satisfy various subsidiary or

63

parental needs and efficiently manage short-term cash. Any excess funds are invested in short-term liquid investments.

      External funding to meet PSEG's and PSE&G's needs and a majority portion of the requirements of Power and Energy Holdings consist of corporate finance transactions. The debt incurred is the direct obligation of those respective entities. Some of the proceeds of these debt transactions are used by the respective obligor to make equity investments in its subsidiaries.

      As discussed below, depending on the particular company, external financing may consist of public and private capital market debt and equity transactions, bank revolving credit and term loans, commercial paper and/or project financings. Some of these transactions involve special purpose entities (SPEs), formed in accordance with applicable tax and legal requirements in order to achieve specified financial advantages, such as favorable legal liability treatment. PSEG consolidates SPEs, as applicable, in accordance with FASB Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities (VIEs)” (FIN 46). See Note 2. Recent Accounting Standards of the Notes.

      The availability and cost of external capital is affected by each entity's performance, as well as by the performance of their respective subsidiaries and affiliates. This could include the degree of structural separation between PSEG and its subsidiaries and the potential impact of affiliate ratings on consolidated and unconsolidated credit quality. Additionally, compliance with applicable financial covenants will depend upon future financial position, earnings and net cash flows, as to which no assurances can be given.

      Over the next several years, PSEG, PSE&G, Power and Energy Holdings may be required to extinguish or refinance maturing debt and, to the extent there is not sufficient internally generated funds, may incur additional debt and/or provide equity to fund investment activities. Any inability to obtain required additional external capital or to extend or replace maturing debt and/or existing agreements at current levels and reasonable interest rates may adversely affect PSEG's, PSE&G's, Power's and Energy Holdings' respective financial condition, results of operations and net cash flows.

      From time to time, PSEG, PSE&G, Power and Energy Holdings may repurchase portions of their respective debt securities using funds from operations, asset sales, commercial paper, debt issuances, equity issuances and other sources of funding and may make exchanges of new securities, including common stock, for outstanding securities. Such repurchases may be at variable prices below, at or above prevailing market prices and may be conducted by way of privately negotiated transactions, open-market purchases, tender or exchange offers or other means. PSEG, PSE&G, Power and Energy Holdings may utilize brokers or dealers or effect such repurchases directly. Any such repurchases may be commenced or discontinued at any time without notice.

      It is expected  that pursuant to the Merger Agreement, PSEG and Power will be consolidated into  the combined company and all debt outstanding at PSEG and Power will be assumed  by the new entities. Under the current plan, PSE&G's and Energy Holdings'  securities will continue to be outstanding.

      **Energy Holdings**

      A portion of the financing for Global's projects and investments is normally provided by non-recourse project financing transactions. These consist of loans from banks and other lenders that are typically secured by project assets and cash flows. Non-recourse transactions generally impose no material obligation on the parent-level investor to repay any debt incurred by the project borrower. The consequences of permitting a project-level default include loss of any invested equity by the parent. However, in some cases, certain obligations relating to the investment being financed, including additional equity commitments, may be guaranteed by Global and/or Energy Holdings for their respective subsidiaries. PSEG does not provide guarantees or credit support to Energy Holdings or its subsidiaries.

**Operating Cash Flows**

      **PSEG**

      For the  year ended December 31, 2004, PSEG's operating cash flow increased  by approximately $117 million from $1.5 billion to $1.6 billion, as compared  to the same period in 2003, due to net increases from its subsidiaries as discussed  below.

64

      For the year ended December 31, 2003, PSEG's operating cash flow increased by approximately $258 million from $1.2 billion to $1.5 billion, as compared to the same period in 2002, due to net increases from its subsidiaries as discussed below.

      **PSE&G**

      PSE&G's operating cash flow increased approximately $95 million from $704 million to $695 million for the year ended December 31, 2004, as compared to the same period in 2003 primarily due to higher Net Income related to the increase in electric base rates, additional regulatory recoveries and lower benefit plan contributions.

      PSE&G's operating cash flow decreased approximately $223 million from $832 million to $609 million for the year ended December 31, 2003, as compared to same period in 2002. The 2002 operating cash flow was abnormally high primarily due to the sale of the gas inventory totaling approximately $415 million in 2002, $183 million of which related to PSE&G's sale of the gas supply business to Power. Working capital needs also increased during 2003 due to changes in the over/under collected balances of PSE&G's energy clauses and increased Accounts Receivable balances resulting from higher billings.

      **Power**

      Power's operating cash flow decreased approximately $127 million from $624 million to $497 million for the year ended December 31, 2004, as compared to the same period in 2003 due to a decrease in Income from Continuing Operations of $166 million, primarily due to lower sales volumes and higher replacement power and maintenance costs combined with the loss of MTC revenues which ended August 1, 2003 offset by activity in the NDT Funds.

      Power's operating cash flow increased approximately $207 million from $417 million to $624 million for the year ended December 31, 2003, as compared to the same period in 2002. The 2002 operating cash flow was abnormally low, due to the purchase of gas contracts from PSE&G in May 2002 for approximately $183 million and gas storage volume requirements, including higher gas prices, to meet its BGSS and generation requirements in 2002. However, higher gas prices in 2003 led to higher working capital requirements for fuels.

      **Energy Holdings**

      Energy Holdings' operating cash flow increased approximately $115 million from $294 million to $409 million for the year ended December 31, 2004, as compared to the same period in 2003, due primarily to a tax payment made in 2003 related to two terminated leveraged lease transactions in 2002 and sales of certain investments in the KKR leveraged buyout fund in 2004.

      Energy Holdings' operating cash flow increased approximately $186 million from $108 million to $294 million for the year ended December 31, 2003, as compared to the same period in 2002. This increase is primarily related to increased earnings and realization of deferred tax assets, partially offset by a $115 million tax payment in the first quarter of 2003 related to two leveraged lease transactions at Resources with affiliates of TXU-Europe that were terminated in the fourth quarter of 2002 and other miscellaneous items. Also, Global received a $137 million return of capital from its investment in GWF Energy that is reflected in financing activities rather than operating cash flows, as that project had been consolidated at that time.

      **PSEG, PSE&G, Power and Energy Holdings**

      The cash flow measure PSEG uses to manage the business is operating cash flows. PSEG also uses cash available to pay down recourse debt (i.e., excess cash) as a metric. Cash available to pay down recourse debt is calculated by taking PSEG's operating cash flows, less investing activities and net dividends and adjusted for items such as securitization bond principal repayments, offshore cash activity and the impact of consolidation accounting at Energy Holdings.

      In 2004, PSEG had cash available to pay down recourse debt exceeding $100 million, which was substantially supported by the monetization of assets and lease terminations by Energy Holdings with approximately $300 million in net proceeds. In the future, PSEG expects operating cash flows to be sufficient to fund the majority of future capital requirements and dividend payments. PSEG expects that cash available to pay down recourse debt will increase substantially in the latter part of its business plan cycle as capital expenditures are expected to decrease materially after 2005 when the current construction program at Power is completed.

65

**Common Stock Dividends**

      Dividend payments on common stock for the year ended December 31, 2004 were $2.20 per share and totaled approximately $522 million. Dividend payments on common stock for the year ended December 31, 2003 were $2.16 per share and totaled approximately $493 million. Future dividends declared will be dependent upon PSEG's future earnings, cash flows, financial requirements, alternative investment opportunities and other factors. On January 18, 2005, PSEG announced an increase in its dividend from $0.55 to $0.56 per share for the first quarter of 2005. This quarterly increase reflects an indicated annual dividend rate of $2.24 per share.

**Short-Term Liquidity**

      **PSEG, PSE&G, Power and Energy Holdings**

      As of December 31, 2004, PSEG and its subsidiaries had a total of approximately $2.7 billion of committed credit facilities with approximately $1.9 billion of available liquidity under these facilities. In addition, PSEG and PSE&G have access to certain uncommitted credit facilities. PSEG had no loans outstanding and PSE&G had $15 million outstanding under these uncommitted facilities as of December 31, 2004. Each of the facilities is restricted to availability and use to the specific companies as listed below.
**Company**    **ExpirationDate** **TotalFacility**    **PrimaryPurpose** **Usageas of12/31/2004** **AvailableLiquidityas of12/31/2004**  **(Millions)**
**PSEG:**
                
4-year Credit Facility
    April 2008    $450     CP Support/Funding/Lettersof Credit    $—     $450 
5-year Credit Facility
    March 2005    $280     CP Support    $280     $— 
3-year Credit Facility
    December 2005    $350     CP Support/Funding/Lettersof Credit    $153     $197 
Uncommitted Bilateral Agreement
    N/A     N/A     Funding    $—      N/A 
Bilateral Term Loan
    April 2005    $75     Funding    $75     $— 
Bilateral Revolver
    April 2005    $25     Funding    $25     $— 
**PSE&G:**
                
5-year Credit Facility
    June 2009    $600     CP Support/Funding/Lettersof Credit    $90     $510 
Uncommitted Bilateral Agreement
    N/A     N/A     Funding    $15      N/A 
**PSEG and Power:**
                
3-year Credit Facility(A)
    April 2007    $600     CP Support/Funding/Lettersof Credit    $17(B)    $583 
**Power:**
                
3-year Credit Facility
    August 2005    $25     Funding/Lettersof Credit    $—     $25 
Bilateral Credit Facility
    March 2010    $100     Funding/Lettersof Credit    $90(B)    $10 
**Energy Holdings:**
                
3-year Credit Facility(C)
    October 2006    $200     Funding/Lettersof Credit    $31(B)    $169                    (A)   PSEG/Power co-borrower facility.   (B)   These amounts relate to letters of credit outstanding.   (C)   Energy Holdings/Global/Resources joint and several co-borrowed facility.
66

      **PSEG**

      As noted above, S&P downgraded PSEG's commercial paper rating on July 30, 2004. This has limited PSEG's ability to access the commercial paper market; however, PSEG believes it has sufficient liquidity to fund its short-term cash needs. PSEG expects to renew its $280 million and $350 million credit facilities which expire in 2005.

      **PSE&G**

      In June 2004, PSE&G entered into a $600 million five-year credit facility. This facility replaced the expiring $200 million 364-day credit facility and the $200 million three-year credit facility that was to expire in June 2005.

      As noted above, S&P downgraded PSE&G's commercial paper rating on July 30, 2004. This has limited PSE&G's ability to access the commercial paper market; however, PSE&G believes it has sufficient liquidity to fund its short-term cash needs.

      **Power**

      In October 2004, Power entered into a $100 million bilateral credit facility that expires in March 2010. This facility is available to Power for both letters of credit and funding.

      As of December 31, 2004, in addition to amounts outstanding under Power's credit facilities shown in the above table, Power had borrowed approximately $98 million from PSEG.

      Power expects to renew its $25 million credit facility which expires in August 2005.

      As noted above, S&P placed Power on negative outlook on July 30, 2004. Power believes it has sufficient liquidity to meet any required posting of collateral resulting from a downgrade. See Note 14. Commitments and Contingent Liabilities of the Notes for further information.

      **Energy Holdings**

      As of December 31,  2004, Energy Holdings had loaned $115 million of excess cash to PSEG. In addition,  Energy Holdings and its subsidiaries had $199 million in cash, including $139  million invested offshore, as of December 31, 2004.

**External Financings**

      **PSEG**

      In September 2004, PSEG issued and sold $200 million of its 4.66% Series A Senior Notes due 2009 in a private placement. The proceeds were used to reduce short-term debt.

      In 2002, PSEG began issuing shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Plan, rather than purchasing shares on the open market. For the year ended December 31, 2004, PSEG issued approximately 1.9 million shares for approximately $83 million pursuant to these plans.

      **PSE&G**

      In August 2004, PSE&G issued $104 million of its First and Refunding Mortgage Bonds, Pollution Control Series AC due 2031, $88 million of its First and Refunding Mortgage Bonds, Pollution Control Series AD due 2030 and $93 million of its First and Refunding Mortgage Bonds, Pollution Control Series AE due 2029. The proceeds were used to refund $104 million of PSE&G's First and Refunding Mortgage Bonds, Pollution Control Series Q due 2031 and $88 million of PSE&G's First and Refunding Mortgage Bonds, Pollution Control Series R due 2030 in August 2004 as well as $93 million of PSE&G's First and Refunding Mortgage Bonds, Pollution Control Series S due 2029 in October 2004.

      In August 2004, PSE&G issued $250 million of its Secured Medium-Term Notes Series D due 2014. The proceeds were used to redeem the remaining outstanding $254 million of PSE&G's First and Refunding Mortgage Bonds, 7% Series SS due 2024 in September 2004.

67

      In June 2004, PSE&G issued $175 million two-year floating rate First and Refunding Mortgage Bonds. The interest is set quarterly at LIBOR plus 0.125%. The proceeds were primarily used to redeem $159 million of 7.375% Series TT First and Refunding Mortgage Bonds due 2014 in June 2004.

      In May 2004, $286 million of PSE&G's 6.50% Series PP First and Refunding Mortgage Bonds matured.

      In addition, PSE&G paid common stock dividends totaling approximately $100 million to PSEG in 2004.

      In December 2004, September 2004, June 2004 and March 2004, PSE&G Transition Funding LLC (Transition Funding) repaid approximately $39 million, $37 million, $30 million and $32 million, respectively, of its transition bonds.

      **Power**

      In October 2004, PSEG contributed approximately $300 million of equity to Power.

      In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009 and $250 million of 5.00% Senior Notes due April 2014. The net proceeds of $488 million, together with other available cash, were used to fund the repayment of $800 million of project finance debt to certain of Power's subsidiaries.

      **Energy Holdings**

      During 2004, Energy Holdings made cash distributions to PSEG totaling $491 million in the form of preference unit redemptions, preference unit distributions, ordinary unit distributions and return of capital contributed. In February 2005, Energy Holdings returned an additional $100 million of capital to PSEG in the form of an ordinary unit distribution.

      During the second quarter of 2004, Energy Holdings repurchased approximately $41 million of its 7.75% Senior Notes due April 2007 at a premium of $3 million, reducing the aggregate amount of that security outstanding to $309 million.

      In February 2004, Energy Holdings repaid $267 million of its 9.125% Senior Notes at maturity.

      During 2004, Skawina and SAESA issued a total of approximately $15 million of non-recourse project debt.

**Debt Covenants**

      **PSEG, PSE&G, Power and Energy Holdings**

      PSEG's, PSE&G's, Power's and Energy Holdings' respective credit agreements generally contain customary provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower's business or financial condition.

      As explained in detail below, some of these credit agreements also contain maximum debt to equity ratios, minimum cash flow tests and other restrictive covenants and conditions to borrowing. Compliance with applicable financial covenants will depend upon the respective future financial position, level of earnings and cash flows of PSEG, PSE&G, Power and Energy Holdings, as to which no assurances can be given. The ratios presented below are for the benefit of the investors of the related securities to which the covenants apply. They are not intended as a financial performance or liquidity measure. The debt underlying the preferred securities of PSEG, which is presented in Long-Term Debt in accordance with FIN 46, is not included as debt when calculating these ratios, as provided for in the various credit agreements.

      **PSEG**

      Financial covenants contained in PSEG's credit facilities include a ratio of debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including commercial paper and loans, certain letters of credit and similar instruments) to total capitalization (including preferred securities outstanding) covenant. This covenant requires that at the end of any quarterly financial period, such ratio not be more than 70.0%. As of December 31, 2004, PSEG's ratio of debt to capitalization (as defined above) was 57.5%. PSEG expects to continue to meet the financial covenants.

68

      **PSE&G**

      Financial covenants contained in PSE&G's credit facilities include a ratio of long-term debt (excluding securitization debt and long-term debt maturing within one year) to total capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio will not be more than 65.0%. As of December 31, 2004, PSE&G's ratio of long-term debt to total capitalization (as defined above) was 51.4%.

      In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of December 31, 2004, PSE&G's Mortgage coverage ratio was 5.41 to 1 and the Mortgage would permit up to approximately $1.6 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements.

      **PSEG and Power**

      Financial covenants contained in the PSEG/Power joint and several credit facility include a ratio of debt to total capitalization for each specific borrower. Where PSEG is the borrower, the covenant described above in PSEG is applicable. Where Power is the borrower, a debt (excluding non-recourse project financings and including loans, certain letters of credit and similar instruments) to total capitalization, adjusted for the $986 million Basis Adjustment (see Consolidated Balance Sheets), covenant applies. This covenant requires that at the end of any quarterly financial period, such ratio will not exceed 65.0%. As of December 31, 2004, Power's ratio of debt to capitalization (as defined above) was 46.8%.

      **Energy Holdings**

      In April 2003, Energy Holdings issued $350 million of Senior Notes which contain financial covenants that include debt incurrence tests consisting of a debt service coverage test and a ratio of consolidated recourse indebtedness to recourse capitalization test, which covenants require that Energy Holdings will not incur additional consolidated recourse indebtedness, other than certain permitted indebtedness, unless, on a pro forma basis, giving effect to the incurrence of the additional consolidated recourse indebtedness: (i) the debt service coverage ratio would be at least 2 to 1 and (ii) the ratio of consolidated recourse indebtedness to recourse capitalization would not exceed 0.60 to 1. Certain permitted indebtedness, such as permitted refinancings and borrowings, are excluded from the requirements under this test.The provisions of the Senior Notes also restrict Energy Holdings from selling assets with a net book value greater than 10% of its assets in any four consecutive quarters, unless the proceeds are used to reduce debt of Energy Holdings or its subsidiaries or are retained by Energy Holdings.

      Energy Holdings entered into a $200 million three-year bank revolving credit agreement in October 2003 with a covenant requiring the ratio of Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) to fixed charges to be greater than 1.75. As of December 31, 2004, Energy Holdings' coverage of this covenant was 2.51. Additionally, Energy Holdings must maintain a ratio of net debt to EBITDA of less than 5.25. As of December 31, 2004, Energy Holdings' ratio under this covenant was 4.29. Energy Holdings is a co-borrower under this facility with Global and Resources, which are joint and several obligors. The terms of the agreement include a pledge of Energy Holdings' membership interest in Global, restrictions on the use of proceeds related to material sales of assets and the satisfactionof certain financial covenants. Cash proceeds from asset sales in excess of 5% of total assets of Energy Holdings during any 12-month period must be used to repay any outstanding amounts under the credit agreement. Cash proceeds during any 12-month period in excess of 10% must be retained by Energy Holdings or used to repay the debt of Energy Holdings, Global or Resources.

**Cross Default Provisions**

      **PSEG, PSE&G, Power and Energy Holdings**

      The PSEG credit agreements contain default provisions under which a default by it, PSE&G or Power in an aggregate amount of $50 million or greater would result in the potential acceleration of payment under those agreements.

69

      PSEG's bank credit agreements and note purchase agreements (collectively, Credit Agreements) related to its private placement of debt contain cross default provisions under which certain payment defaults by PSE&G or Power, certain bankruptcy events relating to PSE&G or Power, the failure by PSE&G or Power to satisfy certain final judgments or the occurrence of certain events of default under the financing agreements of PSE&G or Power, would each constitute an event of default under the PSEG Credit Agreements. It is also an event of default under the PSEG Credit Agreements if PSE&G or Power ceases to be wholly-owned by PSEG.

      PSEG removed Energy Holdings from all cross default provisions effective with the cancellation of Energy Holdings' $495 million revolving credit agreement in September 2003. In October 2003, Energy Holdings entered into a three-year bank revolving credit agreement in the amount of approximately $200 million that does not include PSEG-level covenants other than the maintenance of ownership of at least 80% of the capital stock of Energy Holdings by PSEG or its successor.

      **PSE&G**

      PSE&G's Mortgage has no cross defaults. The PSE&G Medium-Term Note Indenture has a cross default to the PSE&G Mortgage. The credit agreements have cross defaults under which a default by PSE&G in the aggregate of $50 million or greater would result in an event of default and the potential acceleration of payment under the credit agreements.

      **Power**

      The Power Senior Debt Indenture contains a default provision under which a default by it, Nuclear, Fossil or ER&T in an aggregate amount of $50 million or greater would result in an event of default and the potential acceleration of payment under the indenture. There are no cross defaults within Power's indenture from PSEG, Energy Holdings or PSE&G.

      **Energy Holdings**

      Energy Holdings' Credit Agreement and Senior Note Indenture contain default provisions under which a default by it, Resources or Global in an aggregate amount of $25 million or greater would result in an event of default and the potential acceleration of payment under that agreement or the Indenture.

**Ratings Triggers**

      **PSEG, PSE&G, Power and Energy Holdings**

      The debt indentures and credit agreements of PSEG, PSE&G, Power and Energy Holdings do not contain any material “ratings triggers” that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and certain collateral requirements.

      **PSE&G**

      In accordance with the BPU approved requirements under the BGS contracts that PSE&G enters into with suppliers, PSE&G is required to maintain an investment grade credit rating. If PSE&G were to lose its investment grade rating, PSE&G would be required to file with the BPU a plan to assure continued payment for the BGS requirements of its customers.

      PSE&G is the servicer for the bonds issued by Transition Funding. If PSE&G were to lose its investment grade rating, PSE&G would be required to remit collected cash daily to the bond trustee. Currently, cash is remitted monthly.

      **Power**

      In connection with the management and optimization of Power's asset portfolio, ER&T maintains underlying agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power's credit rating to below an investment grade rating, many of these agreements allow the counterparty to demand that ER&T provide performance

70

assurance, generally in the form of a letter of credit or cash. As of December 31, 2004, if Power were to lose its investment grade rating and assuming all counterparties to agreements in which ER&T is “out-of-the-money” were contractually entitled to demand, and demanded, performance assurance, ER&T could be required to post collateral in an amount equal to approximately $701 million. Providing this credit support would increase Power's costs of doing business and could restrict the ability of ER&T to manage and optimize Power's asset portfolio. See Note 14. Commitments and Contingent Liabilities of the Notes.

      **Energy Holdings**

      In 2003, Energy Holdings and Global posted $44 million of letters of credit for certain of their equity commitments as a result of Energy Holdings' ratings falling below investment grade. Under existing agreements, no further letters of credit will need to be posted should there be a future downgrade.

**Credit Ratings**

      **PSEG, PSE&G, Power and Energy Holdings**

      The current ratings of securities of PSEG and its subsidiaries are shown below and reflect the respective views of the rating agencies. Any downward revision or withdrawal may adversely affect the market price of PSEG's, PSE&G's, Power's and Energy Holdings' securities and serve to increase those companies' cost of capital and limit their access to capital. All ratings have a stable outlook unless otherwise noted. (N) denotes a negative outlook, (P) denotes a positive outlook and (WD) denotes a credit watch developing indicating that ratings could be raised or lowered. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances so warrant. Each rating given by an agencyshould be evaluated independently of the other agencies' ratings. The ratings should not be construed as an indication to buy, hold or sell any security.
      **Moody's(A)**    **S&P(B)**    **Fitch(C)**      
**PSEG:**
            
Preferred Securities
    Baa3    BB+(WD)    BBB–(P)      
Commercial Paper
    P2    A3(WD)    F2      
**PSE&G:**
            
Mortgage Bonds
    A3    A–(WD)    A      
Cumulative Preferred Stock without Mandatory Redemption
    Baa3    BB+(WD)    BBB+      
Commercial Paper
    P2    A3(WD)    F2      
**Power:**
            
Senior Notes
    Baa1    BBB(WD)    BBB(P)      
**Energy Holdings:**
            
Senior Notes
    Ba3(N)    BB–(N)    BB(N)            
**
   (A)   Moody's ratings range from Aaa (highest) to C (lowest) for long-term securities and P-1 (highest) to NP (lowest) for short-term securities.   (B)   S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A-1 (highest) to D (lowest) for short-term securities.   (C)   Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F-1 (highest) to D (lowest) for short-term securities.
      On April 12, 2004, Fitch downgraded Energy Holdings' Senior Notes rating to BB from BBB–, with a negative outlook.

      On July 30, 2004, S&P placed the Corporate Credit Ratings of PSEG, PSE&G and Power on negative outlook. S&P also downgraded PSEG's and PSE&G's respective commercial paper ratings from A2 to A3.

      On August 6, 2004, Moody's placed Power on a negative outlook.

      On September 10, 2004, Fitch downgraded PSEG's Preferred Securities to BBB– from BBB with a stable outlook and placed an F2 rating on PSEG's commercial paper program. Fitch also downgraded Power's

71

Senior Notes to BBB from BBB+. In addition, Fitch reaffirmed its A rating on PSE&G's Mortgage Bonds. However, Fitch downgraded PSE&G's commercial paper program to F2 from F1.

      On December 20, 2004, in conjunction with the announcement of the Merger Agreement between PSEG and Exelon, all of the rating agencies reviewed their ratings and took the following actions:
•Moody's affirmed the ratings for PSEG, Power and Energy Holdings. Moody's revised its outlook to stable from negative for PSEG and Power. The outlook for PSE&G remained stable and the outlook for Energy Holdings remained negative.  •S&P placed its BBB Corporate Credit Rating for PSEG, Power and PSE&G on Credit Watch with developing implications. S&P indicated that, if not for the Merger, the corporate credit ratings assigned to PSEG and its subsidiaries, other than Energy Holdings, would have been lowered to BBB– with a negative outlook. S&P lowered its outlook for Energy Holdings to negative. •Fitch affirmed its ratings for PSEG, Power, PSE&G and Energy Holdings. Fitch revised the outlook for PSEG and Power to positive from stable. The outlook for PSE&G remained stable and Energy Holdings remained negative.
**Other Comprehensive Loss (Income)**

      **PSEG, PSE&G, Power and Energy Holdings**

      For the year ended December 31, 2004, PSEG, Power and Energy Holdings had Other Comprehensive Loss (Income) of $76 million, $135 million and $(62) million, respectively, due primarily to net unrealized losses on derivatives accounted for as hedges in accordance with SFAS 133, unrealized gains and losses in the NDT Funds at Power and foreign currency translation adjustments at Energy Holdings.

72

**CAPITAL REQUIREMENTS**

**Forecasted Expenditures**

      **PSEG, PSE&G, Power and Energy Holdings**

      It is expected that the majority of each subsidiary's capital requirements over the next five years will come from internally generated funds. Projected construction and investment expenditures, excluding nuclear fuel purchases, for PSEG's subsidiaries for the next five years are presented in the table below. These amounts are subject to change, based on various factors, including the possible change in strategy of the combined company following the Merger.
  **2005** **2006** **2007** **2008** **2009**  **(Millions)**
***PSE&G:***
                    
Facility Support
    $44     $36     $36     $44     $40 
Environmental/Regulatory
     32      51      22      21      20 
Facility Replacement
     183      187      184      189      198 
System Reinforcement
     125      122      100      92      101 
New Business
     147      151      156      158      162                                
***Total PSE&G***
     531      547      498      504      521                                
***Power:***
                    
Non-Recurring (new MW and Environmental)
     315      178      145      109      30 
Maintenance
     134      146      114      84      99                                
***Total Power***
     449      324      259      193      129                                
***Energy Holdings*** 
     120      60      40      20      30 
***Other***
     15      20      15      15      14                                
***Total PSEG***
    **$****1,115**     **$****951**     **$****812**     **$****732**     **$****694**                                                    
      **PSE&G**

      In 2004, PSE&G made approximately $428 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $428 million does not include approximately $32 million spent on cost of removal. PSE&G projections for future capital expenditures include additions to its transmission and distribution systems to meet expected growth and to manage reliability and cost of removal expenditures. The current projections do not include investments required as a result of PJM's approval of the Regional Transmission Expansion Plan (RTEP) in December 2004. As project scope and cost estimates develop, PSE&G will modify its current projections to include these required investments.

      **Power**

      In 2004, Power made approximately $618 million of capital expenditures (excluding $107 million for nuclear fuel), primarily related to the Bethlehem, New York (Albany) site, the Linden station in New Jersey and various other projects at Nuclear and Fossil.

      In 2004, Power increased the scope of outages at the Salem and Hope Creek nuclear generating facilities to make equipment modifications. Power's ongoing capital expenditure program for its share of the Salem, Hope Creek and Peach Bottom facilities includes approximately $669 million (including interest capitalized during construction) for 2005 through 2009 to improve operations and complete power uprates. The forecasted capital expenditures do not include potential expenditures for environmental control equipment at Power's Keystone, Conemaugh and Hudson Stations.

      **Energy Holdings**

      Energy Holdings' capital needs in 2005 will be limited to fulfilling existing contractual and potential contingent commitments. The balance of the forecasted expenditures relates to capital requirements of consolidated subsidiaries, which will primarily be financed from internally generated cash flow within the projects and from local sources on a non-recourse basis or limited discretionary investments by Energy

73

Holdings. Such capital requirements include organic growth in SAESA's service territory, the Electroandes expansion project, the majority of which is expected to be completed in 2005, and other capital improvements at Global's consolidated subsidiaries.

      In 2004, Energy Holdings incurred approximately $86 million of capital expenditures, primarily related to capital projects at SAESA, Dhofar Power and Skawina.

**Disclosures about Long-Term Maturities, Contractual and Commercial Obligations and Certain Investments**

      The following table reflects PSEG's and its subsidiaries' contractual cash obligations and other commercial commitments in the respective periods in which they are due. In addition, the table summarizes anticipated recourse and non-recourse debt maturities for the years shown. The table below does not reflect debt maturities of Energy Holdings' non-consolidated investments. If those obligations were not able to be refinanced by the project, Energy Holdings may elect to make additional contributions in these investments. For additional information, see Note 12. Schedule of Consolidated Debt of the Notes.
**Contractual Cash Obligations** **TotalAmountsCommitted** **LessThan1 year** **2–3years** **4–5years** **Over5 years**  **(Millions)**
***Short-Term Debt Maturities***
                    
PSEG
    $533     $533     $—     $—     $— 
PSE&G
     105      105      —      —      — 
***Long-Term Debt Maturities***
                    
***Recourse Debt Maturities***
                    
PSEG(A)
     1,654      49      558      298      749 
PSE&G
     3,063      125      435      310      2,193 
Transition Funding (PSE&G)
     2,085      146      317      346      1,276 
Power
     3,316      —      500      250      2,566 
Energy Holdings
     1,756      —      309      907      540 
***Non-Recourse Project Financing***
                    
Energy Holdings
     1,437      66      328      368      675 
***Interest on Recourse Debt***
                    
PSEG
     102      24      44      34      — 
PSE&G
     2,029      158      278      260      1,333 
Transition Funding (PSE&G)
     852      133      237      196      286 
Power
     2,346      209      389      379      1,369 
Energy Holdings
     583      147      258      131      47 
***Interest on Debt Supporting Trust Preferred Securities***
                    
PSEG
     1,970      101      168      108      1,593 
***Interest on Non-Recourse Project Financing***
                    
Energy Holdings
     618      97      182      142      197 
***Capital Lease Obligations***
                    
PSEG
     79      7      14      14      44 
Power
     16      1      3      3      9 
***Operating Leases***
                    
PSE&G
     9      3      5      1      — 
Services
     7      1      2      2      2 
***Energy Related Purchase Commitments***
                    
Power
     2,061      561      761      438      301 
Energy Holdings
     188      188      —      —      —                                
**Total Contractual Cash Obligations**
    $24,809     $2,654     $4,788     $4,187     $13,180                                
***Standby Letters of Credit***
                    
Power
    $145     $135     $10     $—     $— 
Energy Holdings
     31      17      14      —      — 
***Guarantees and Equity Commitments***
                    
Energy Holdings
     107      1      26      —      80                                
**Total Commercial Commitments**
    $283     $153     $50     $—     $80                                                    
*(footnotes on next page)*

74

*(footnotes from previous page)*
   (A)   Includes debt supporting trust preferred securities of $1.2 billion.

      Power has also entered into contractual commitments for a variety of services for which annual amounts are not quantifiable. See Note 14. Commitments and Contingent Liabilities of the Notes.

**OFF-BALANCE SHEET ARRANGEMENTS**

      **Power**

      Power issues guarantees in conjunction with certain of its energy trading activities. See Note 14. Commitments and Contingent Liabilities of the Notes for further discussion.

      **PSEG and Energy Holdings**

      Global has  certain investments that are accounted for under the equity method in accordance  with GAAP. Accordingly, amounts recorded on the Consolidated Balance Sheets  for such investments represent Global's equity investment, which is increased  for Global's pro-rata share of earnings less any dividend distribution from  such investments. The companies in which Global invests, that are accounted  for under the equity method have an aggregate $1.3 billion of debt on their  combined, consolidated financial statements. PSEG's pro-rata share of such  debt is $563 million. This debt is non-recourse to PSEG, Energy Holdings and  Global. PSEG is generally not required to support the debt service obligations  of these companies. However, default with respect to this non-recourse debt  could result in a loss of invested equity.

      Resources has investments in leveraged leases that are accounted for in accordance with SFAS No. 13, “Accounting for Leases.” Leveraged lease investments generally involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease financing, the lessor purchases an asset to be leased. The purchase price is typically financed 80% with debt provided by the creditor and the balance comes from equity funds provided by the lessor. The creditor provides long-term financing to the transaction, and is secured by the property subject to the lease. Such long-term financing is non-recourse to the lessor. As such, in the event of default, the leased asset, and in some cases the lessee, secure the loan. As a lessor, Resources has ownership rights to the property and rents the property to thelessees for use in their business operation. As of December 31, 2004, Resources' equity investment in leased assets was approximately $1.3 billion, net of deferred taxes of approximately $1.6 billion. For additional information, see Note 10. Long-Term Investments of the Notes.

      In the event that collectibility of the minimum lease payments to be received by the lessor is no longer reasonably assured, the accounting treatment for some of the leases may change. In such cases, Resources may deem that a lessee has a high probability of defaulting on the lease obligation. Should Resources ever directly assume a debt obligation, the fair value of the underlying asset and the associated debt would be recorded on the Consolidated Balance Sheets instead of the net equity investment in the lease.

      Energy Holdings has guaranteed certain obligations of its subsidiaries or affiliates related to certain projects. See Note 14. Commitments and Contingent Liabilities of the Notes for additional information.

**CRITICAL ACCOUNTING ESTIMATES**

      **PSEG, PSE&G, Power and Energy Holdings**

      Under GAAP, many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. The managements of PSEG, PSE&G, Power and Energy Holdings have each determined that the following estimates are considered critical to the application of rules that relate to their respective businesses.

75

      ***Accounting for Pensions***

      PSEG, PSE&G, Power and Energy Holdings account for pensions under SFAS No. 87, “Employers' Accounting for Pensions” (SFAS 87). Pension costs under SFAS 87 are calculated using various economic and demographic assumptions. Economic assumptions include the discount rate and the long-term rate of return on trust assets. Demographic assumptions include projections of future mortality rates, pay increases and retirement patterns. In 2004, PSEG and its subsidiaries recorded pension expense of $102 million, compared to $147 million in 2003 and $89 million in 2002. Additionally, in 2004, PSEG and its respective subsidiaries contributed cash of approximately $96 million, compared to cash contributions of $211 million in 2003 and $240 million in 2002.

      PSEG's discount rate assumption, which is determined annually, is based on the rates of return on high-quality fixed-income investments currently available and expected to be available during the period to maturity of the pension benefits. The discount rate used to calculate pension obligations is determined as of December 31 each year, PSEG's SFAS 87 measurement date. The discount rate used to determine year-end obligations is also used to develop the following year's net periodic pension cost. The discount rates used in PSEG's 2003 and 2004 net periodic pension costs were 6.75% and 6.25%, respectively. PSEG's 2005 net periodic pension cost was developed using a discount rate of 6.00%.

      PSEG's expected rate of return on plan assets reflects current asset allocations, historical long-term investment performance and an estimate of future long-term returns by asset class using input from PSEG's actuary and investment advisors, as well as long-term inflation assumptions. For 2003 and 2004, PSEG assumed a rate of return of 9.0% and 8.75%, respectively, on PSEG's pension plan assets. For 2005, PSEG will continue the rate of return assumption of 8.75%.

      Based on the above assumptions, PSEG has estimated net period pension costs of approximately $110 million and contributions of up to $100 million in 2005. As part of the business planning process, PSEG has modeled its future costs assuming an 8.75% rate of return and the return to a 6.25% discount rate for 2006 and beyond. Based on these assumptions, PSEG has estimated net period pension costs of approximately $80 million in 2006 and $70 million in 2007. Actual future pension expense and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to PSEG's pension benefit obligation (PBO) and accumulated benefit obligation (ABO) and various other factors related to the populations participating in PSEG's pension plans.

      The following chart reflects the sensitivities associated with a change in certain actuarial assumptions. The effects of the assumption changes shown below solely reflect the impact of that specific assumption.
      **Actuarial Assumption** **Current** **Change/(Decrease)** **As ofDecember 31, 2004Impact onPension BenefitObligation** **Increase toPension Expensein 2005**           **(Millions)**      
Discount Rate
     6.00%      (1%)    $526     $54       
Rate of Return on Plan Assets
     8.75%      (1%)    $—     $29                       
      ***Accounting for Deferred Taxes***

      PSEG, PSE&G,  Power and Energy Holdings provide for income taxes based on the liability method  required by SFAS No. 109, “Accounting for Income Taxes” (SFAS 109).  Under this method, deferred tax assets and liabilities are recognized for the  future tax consequences attributable to differences between the financial statement  carrying amounts of existing assets and liabilities and their respective tax  basis, as well as net operating loss and credit carryforwards.

      PSEG, PSE&G, Power and Energy Holdings evaluate the need for a valuation allowance against their respective deferred tax assets based on the likelihood of expected future taxable income. PSEG, PSE&G, Power and Energy Holdings do not believe a valuation allowance is necessary; however, if the expected level of future taxable income changes or certain tax planning strategies become unavailable, PSEG, PSE&G, Power and Energy Holdings would record a valuation allowance through income tax expense in the period the valuation allowance is deemed necessary. Resources' and Global's ability to realize their deferred tax assets are dependent on PSEG's subsidiaries' ability to generate ordinary income and capital gains.

76

***Accounting for Long-Lived Assets***

      SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144), a standard related to testing long-lived assets for impairment, was adopted on January 1, 2002. Testing under SFAS 144 consists of an undiscounted cash flow analysis to determine if an impairment existed, and, if an impairment existed, a discounted cash flow test would be performed to quantify it. This new standard is broader in that it includes discontinued operations as part of its scope. This test requires the same judgment to be employed by management in building assumptions related to future earnings of individual assets or an investment as is required in determining potential impairments of goodwill as discussed below.

      These tests are required whenever events or circumstances indicate that an impairment may exist. Examples of potential events which could require an impairment test are when power prices become depressed for a prolonged period in a market, when a foreign currency significantly devalues or when an investment generates negative operating cash flows. Any potential impairment of investments under these circumstances is recorded as a component of operating expenses.

      **PSE&G**

      ***Unbilled Revenues***

      Electric and gas revenues are recorded based on services rendered to customers during each accounting period. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. Unbilled usage is calculated in two steps. The initial step is to apply a base usage per day to the number of unbilled days in the period. The second step estimates seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. The resulting usage is priced at current rate levels and recorded as revenue. A calculation of the associated energy cost for the unbilled usage is recorded as well. Each month the prior month's unbilledamounts are reversed and the current month's amounts are accrued. Using benchmarks other than those used in this calculation could have a material effect on the amounts accrued in a reporting period. The resulting revenue and expense reflect the service rendered in the calendar month.

      **PSE&G and Energy Holdings**

      ***SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71)***

      PSE&G and certain of Global's investments prepare their respective Consolidated Financial Statements in accordance with the provisions of SFAS 71, which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or recognize obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G and Global have deferred certain costs, which will be amortized over various future periods. To the extent that collection of such costs or paymentof liabilities is no longer probable as a result of changes in regulation and/or PSE&G's and Global's competitive position, the associated regulatory asset or liability is charged or credited to income. See Note 7. Regulatory Matters of the Notes for additional information related to these and other regulatory issues.

      **Power**

      ***NDT Funds***

      Power accounts for the assets in the NDT Fund under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS 115). The assets in the NDT Fund are classified as available-for-sale securities and are marked to market with unrealized gains and losses recorded in Accumulated Other Comprehensive Income (OCI). Realized gains, losses and dividend and interest income are recorded on Power's and PSEG's Statements of Operations under Other Income and Other Deductions. Unrealized losses that are deemed to be Other Than Temporarily Impaired, as defined under SFAS 115, and related interpretive guidance, are charged against earnings rather than OCI. Factors, such as the length of time and extent to which the fair value is below carrying value, the potential for impairmentsof securities

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when the issuer or industry is experiencing significant financial difficulties and Power's intent and ability to continue to hold securities, are used as indicators of the prospects of the securities to recover their value.

      **Power and Energy Holdings**

      ***Accounting for Goodwill***

      SFAS 142 requires an entity to evaluate its goodwill for impairment at least annually or when indications of impairment exist. An impairment may exist when the carrying amount of goodwill exceeds its implied fair value.

      Accounting estimates related to goodwill fair value are highly susceptible to change from period to period because they require management to make cash flow assumptions about future sales, operating costs, economic conditions and discount rates over an indefinite life. The impact of recognizing an impairment could have a material impact on financial position and results of operations.

      Power and Energy Holdings perform annual goodwill impairment tests and continuously monitor the business environment in which they operate for any impairment issues that may arise. As indicated above, certain assumptions are used to arrive at a fair value for goodwill testing. Such assumptions are consistently employed and include, but are not limited to, free cash flow projections, interest rates, tariff adjustments, economic conditions prevalent in the geographic regions in which Power and Energy Holdings do business, local spot market prices for energy, foreign exchange rates and the credit worthiness of customers. If an adverse event were to occur, such an event could materially change the assumptions used to value goodwill and could result in impairments of goodwill.

      **PSEG and Energy Holdings**

      ***Permanent Reinvestment Strategy***

      As allowed  under APB No. 23, “Accounting for Income Taxes—Special Areas”  and SFAS 109, management has maintained a permanent reinvestment strategy  as it relates to Global's international investments. If management were  to change that strategy, a deferred tax expense and deferred tax liability would  be recorded to reflect the expected taxes that would need to be paid on Global's  offshore earnings. As of December 31, 2004, the undistributed foreign earnings  were approximately $256 million. The determination of the amount of unrecognized  U.S. Federal deferred tax liability for unrealized earnings is not practicable.  The American Jobs Creation Act of 2004 (Jobs Act), as discussed further in Note  2. Recent Accounting Standards of the Notes, provides a one-year window to repatriate  earnings from foreign investments and claim a special 85% dividends received  tax deduction on such distributions. The range of undistributed earnings that  PSEG could consider for possible repatriation under the Jobs Act is between  $0 and $256 million, which would result in additional income tax expense  between $0 and $15 million. On January 13, 2005, the IRS published Notice 2005-10,  which discusses some of the rules that pertain to this deduction. Whether PSEG  will ultimately take advantage of this provision, all or in part, depends on  a number of factors, including but not limited to evaluating the impact of Notice  2005-10 and any future authoritative guidance. Management has made no change  in its current intention to indefinitely reinvest accumulated earnings of its  foreign subsidiaries. PSEG and Energy Holdings are currently evaluating the  impacts of the entire Jobs Act, which could have a material impact on their  financial condition, results of operations and cash flows.

      ***Foreign Currency Translation***

      Energy Holdings' financial statements are prepared using the U.S. Dollar as the reporting currency. In accordance with SFAS No. 52 “Foreign Currency Translation,” for foreign operations whose functional currency is deemed to be the local (foreign) currency, asset and liability accounts are translated into U.S. Dollars at current exchange rates and revenues and expenses are translated at average exchange rates prevailing during the period. Translation gains and losses (net of applicable deferred taxes) are not included in determining Net Income but are reported in OCI. Gains and losses on transactions denominated in a currency other than the functional currency are included in the results of operations as incurred.

      The determination of an entity's functional currency requires management's judgment. It is based on an assessment of the primary currency in which transactions in the local environment are conducted, and whether the local currency can be relied upon as a stable currency in which to conduct business. As economic

78

and business conditions change, Energy Holdings is required to reassess the economic environment and determine the appropriate functional currency. The impact of foreign currency accounting could have a material adverse impact on Energy Holdings' financial condition, results of operation and net cash flows.

**ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT                  MARKET RISK
**PSEG, PSE&G, Power and Energy Holdings**

      The market risk inherent in PSEG's, PSE&G's, Power's and Energy Holdings' market risk sensitive instruments and positions is the potential loss arising from adverse changes in foreign currency exchange rates, commodity prices, equity security prices and interest rates as discussed in the Notes to Consolidated Financial Statements (Notes). It is the policy of each entity to use derivatives to manage risk consistent with its respective business plans and prudent practices. PSEG, PSE&G, Power and Energy Holdings have a Risk Management Committee (RMC) comprised of executive officers who utilize an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices.

      Additionally, PSEG, PSE&G, Power and Energy Holdings are exposed to counterparty credit losses in the event of non-performance or non-payment. PSEG has a credit management process, which is used to assess, monitor and mitigate counterparty exposure for PSEG and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG and its subsidiaries' financial condition, results of operations or net cash flows.

**Foreign Exchange Rate Risk**

      **Energy Holdings**

      Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk is that some of its foreign subsidiaries and affiliates utilize currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, certain of Global's foreign subsidiaries and affiliates have entered into monetary obligations and maintain receipts/receivables in U.S. Dollars or currencies other than their own functional currencies. Primarily, Global is exposed to changes in the U.S. Dollar to Brazilian Real, Euro, Polish Zloty, Peruvian Nuevo Sol and the Chilean Peso exchange rates. With respect to the foreign currency risk associated with the Brazilian Real, there has been significant devaluation since the initial acquisitionof Global's investment in Rio Grande Energia S.A. (RGE), which has resulted in reduced U.S. Dollar earnings and cash flows relative to initial projections. However, there have been material improvements in a number of currencies during 2003 and 2004 due to the weakness of the U.S. Dollar, that have offset some of the loss incurred because of the devaluation of the Brazilian Real. Whenever possible, these subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements, wherever possible, to manage risk related to certain foreign currency transactions.

      As of December 31, 2004, the devaluing Brazilian Real has resulted in a cumulative $240 million loss of value which is recorded as a $215 million after-tax charge to Other Comprehensive Income (OCI) related to Global's equity method investments in RGE. An additional devaluation in the December 31, 2004 Brazilian Real to U.S. Dollar exchange rate of 10% would result in a $16 million change in the value of the investment in RGE and corresponding impact to OCI. If the December 31, 2004 Brazilian Real to U.S. Dollar exchange rate were to appreciate by 10%, it would result in a $20 million after-tax increase in the value of the investment in RGE.

      Additionally, Global has approximately $65 million of Euro-denominated receivables related to Global's equity method investments in Prisma which is subject to fluctuations in the U.S. Dollar to Euro exchange rate. If the December 31, 2004 Euro to U.S. Dollar exchange rate were to increase by 10%, Global would record approximately $7 million of foreign currency transaction losses. If the December 31, 2004 Euro to U.S. Dollar exchange rate were to decrease by 10%, Global would record approximately $6 million of foreign currency transaction gains.

      In January 2005, Energy Holdings entered into an option to sell U.S. Dollars and buy Polish Zlotys with a notional amount equivalent to the amount of its Polish Zloty bank debt at ELCHO, a U.S. Dollar

79

functional currency entity. As a result, if the U.S. Dollar weakens relative to the Polish Zloty, the accounting losses generated by the mark-to-market on the Polish Zloty debt would be significantly reduced by the option's increases in value. To the extent the U.S. Dollar strengthens relative to the Polish Zloty, gains would be recorded on the Polish Zloty debt (and other monetary liabilities), and the option would expire with no value.

      Global has various other foreign currency exposures related to translation adjustments. A devaluation of 10% in such foreign currencies would result in an aggregate after-tax charge to OCI of $76 million.

**Commodity Contracts**

      **PSEG and Power**

      The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, Power enters into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge its anticipated supply and demand differential. These contracts, in conjunction with demand obligations help optimize the value of owned electric generation capacity.

      ***Normal Operations and Hedging Activities***

      Power enters into physical contracts, as well as financial contracts, including forwards, futures, swaps and options designed to reduce risk associated with volatile commodity prices. Commodity price risk is associated with market price movements resulting from market generation demand, changes in fuel costs and various other factors.

      Power's derivative contracts are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), its amendments and related guidance. Changes in the fair value of qualifying cash flow hedge transactions are recorded in OCI, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS 133 and the ineffective portion of hedge contracts are recognized in earnings currently. Additionally, changes in the fair value attributable to fair value hedges are similarly recognized in earnings.

      Most non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133 and/or SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149) for contracts entered into or modified and hedging relationships designated after June 30, 2003.

      ***Trading***

      Power maintains a strategy of entering into trading positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. In addition, Power has non-asset based trading activities. These contracts also involve financial transactions including swaps, options and futures. These activities are marked to market in accordance with SFAS 133, its amendments and related guidance, with gains and losses recognized in earnings.

**Value-at-Risk (VaR) Models**

      **Power**

      Power uses VaR models to assess the market risk of its commodity businesses. The portfolio VaR model for Power includes its owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. VaR represents the potential gains or losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. Power estimates VaR across its commodity businesses.

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      Power manages its exposure at the portfolio level. Its portfolio consists of owned generation, load-serving contracts (both gas and electric), fuel supply contracts and energy derivatives designed to manage the risk around the differential between generation and load. While Power manages its risk at the portfolio level, it also monitors separately the risk of its trading activities and other non-trading activities that receive mark-to-market accounting treatment. Non-trading VAR includes derivatives that are economic hedges that do not qualify for hedge accounting.

      The VaR models used by Power are variance/covariance models adjusted for the delta of positions with a 95% one-tailed confidence level and a one-day holding period for the mark-to-market trading and non-trading activities and a 95% one-tailed confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods, whereas Power actively manages its portfolio.

      As of December 31, 2004 and 2003, trading VaR was approximately $2 million.
        **For the Year Ended December 31, 2004** **Trading VaR** **Non-TradingMTM VaR**   **(Millions)**        
*95% Confidence Level, One-Day Holding Period, One-Tailed:*
                
Period End
    $2     $18         
Average for the Period
    $2     $13         
High
    $6     $31         
Low
    $1     $1         
*99% Confidence Level, One-Day Holding Period, Two-Tailed:*
                
Period End
    $4     $28         
Average for the Period
    $4     $20         
High
    $9     $49         
Low
    $1     $2                 
**Interest Rates**

      **PSEG, PSE&G, Power and Energy Holdings**

      PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. It is the policy of PSEG, PSE&G, Power and Energy Holdings to manage interest rate risk through the use of fixed and floating rate debt, interest rate swaps and interest rate lock agreements. PSEG, PSE&G, Power and Energy Holdings manage their respective interest rate exposures by maintaining a targeted ratio of fixed and floating rate debt. As of December 31, 2004, a hypothetical 10% change in market interest rates would result in a $1 million, $3 million and $1 million change in annual interest costs related to debt at PSEG, PSE&G and Energy Holdings, respectively. In addition, as of December 31, 2004, a hypothetical 10% change in market interest rates would result ina $9 million, $153 million, $122 million and $38 million change in the fair value of the debt of PSEG, PSE&G, Power and Energy Holdings, respectively.

**Debt and Equity Securities**

      **PSEG, PSE&G, Power and Energy Holdings**

      PSEG has approximately $2.9 billion invested in its pension plans. Although fluctuations in market prices of securities within this portfolio do not directly affect PSEG's earnings in the current period, changes in the value of these investments could affect PSEG's future contributions to these plans, its financial position if its accumulated benefit obligation (ABO) under its pension plans exceeds the fair value of its pension funds and future earnings as PSEG could be required to adjust pension expense and its assumed rate of return.

      **Power**

      Power's NDT Funds are comprised of both fixed income and equity securities totaling $1.1 billion as of December 31, 2004. The fair value of equity securities is determined independently each month by the Trustee. As of December 31, 2004, the portfolio was comprised of approximately $678 million of equity securities and approximately $408 million in fixed income securities. The fair market value of the NDT assets will fluctuate primarily depending upon the performance of equity markets. As of December 31, 2004, a

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hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Funds by approximately $68 million.

      Power uses duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Funds is the Lehman Brothers Aggregate Bond Index, which currently has a duration of 4.34 years and a yield of 4.38%. The portfolio's value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2004, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $16 million.

      **Energy Holdings**

      Resources has investments in equity securities and limited partnerships. Resources carries its investments in equity securities at their fair value as of the reporting date. Consequently, the carrying value of these investments is affected by changes in the fair value of the underlying securities. Fair value is determined by adjusting the market value of the securities for liquidity and market volatility factors, where appropriate.

      As of December 31, 2004, Resources had investments in leveraged buyout funds of approximately $27 million, all of which are public securities with available market prices. The potential change in fair value resulting from a hypothetical 10% change in quoted market prices of the publicly traded investments would amount to $3 million as of December 31, 2004.

**Credit Risk**

      **PSEG, PSE&G, Power and Energy Holdings**

      Credit risk relates to the risk of loss that PSEG, PSE&G, Power and Energy Holdings would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG, PSE&G, Power and Energy Holdings have established credit policies that they believe significantly minimize credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which may allow for the netting of positive and negative exposures associated with a single counterparty.

      **PSE&G**

      Basic Generation Service (BGS) suppliers expose PSE&G to credit losses in the event of non-performance or non-payment upon a default of the BGS supplier. Credit requirements are governed under the Board of Public Utilities (BPU) approved BGS contracts.

      **Power**

      Counterparties expose Power's trading operation to credit losses in the event of non-performance or non-payment. Power has a credit management process, which is used to assess, monitor and mitigate counterparty exposure for Power and its subsidiaries. Power's counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Power's trading operations have entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Power's exposure to counterparty risk by providing the offset of amounts payable to the counterparty against amounts receivable from the counterparty. In the event of non-performanceor non-payment by a major counterparty, there may be a material adverse impact on Power's and its subsidiaries' financial condition, results of operations or net cash flows. As of December 31, 2004, over 88% of the credit exposure (mark-to-market plus net receivables and payables, less cash collateral) for Power's trading operations was with investment grade counterparties. The majority of the credit exposure with non-investment grade counterparties was with certain companies that supply fuel (primarily coal) to Power. Therefore, this exposure relates to the risk of a counterparty performing under its obligations rather than payment risk. As of December 31, 2004, Power's trading operations had over 184 active counterparties.

      As a result of the 2003 New Jersey BGS auction, Power's trading operation contracted to provide energy to the direct suppliers of New Jersey electric utilities, including PSE&G, commencing August 1, 2003. In

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February 2004, the BPU approved the results of the 2004 BGS auction for New Jersey customers. Power is a direct supplier of New Jersey Electric Distribution Companies (EDCs) entering into seasonally-adjusted fixed-price contracts for 12-month and 36-month periods that began on June 1, 2004. The revenue from the majority of the suppliers is paid directly to Power from the utilities that those suppliers serve. These bilateral contracts are subject to credit risk. A material portion of credit risk relates to the ability of suppliers to meet their payment obligations for the power delivered under each contract. Any failure to collect these payments under the contracts could have a material impact on Power's results of operations, cash flows and financial position. The payment risk that is associated with potential nonpayment by any New Jersey EDC makingdirect payment under the BGS contracts is lower than the risk under standard bilateral contracts, since the EDCs are rate-regulated entities.

      **Energy Holdings**

      ***Global***

      Global has credit risk with respect to its counterparties to power purchase agreements (PPAs) and other parties. For further discussion, see MD&A—Future Outlook—Energy Holdings.

      ***Resources***

      Resources has credit risk related to its investments in leveraged leases, totaling $1.2 billion, which is net of deferred taxes of $1.6 billion, as of December 31, 2004. These investments are largely concentrated in the energy industry and have some exposure to the airline industry. As of December 31, 2004, 69% of counterparties in the lease portfolio were rated investment grade by both S&P and Moody's.

      Resources is the lessor of various aircraft to several domestic airlines including United Airlines (UAL), Delta Airlines (Delta) and Northwest Airlines (Northwest). Resources leases a Boeing B767 aircraft to UAL. In December 2002, UAL filed for Chapter 11 bankruptcy protection. UAL has stated that it intends to retain and use its B767 aircraft. UAL has an additional debt obligation of $48 million associated with this aircraft which is non-recourse to Resources. Resources will work constructively with UAL to keep the leveraged lease in place. The gross invested balance of this investment as of December 31, 2004 was $21 million. In the fourth quarter of 2004, Resources entered into agreements with Delta and Northwest to extend the term of both of these leases. As part of Delta's financial restructuring,Delta entered into a broad settlement with certain lessors and other financial stakeholders. Through this settlement, Resources agreed to extend Delta's lease on the airplane for three years with a 25% reduction in rental payments. Resources also received shares of Delta stock through the transaction and retained its rights in the event Delta declares bankruptcy. Separately, Resources extended the lease on one of the airplanes to Northwest for two years. Each of these lessees are current on its required rental payments. The gross investment balances in Delta and Northwest as of December 31, 2004 was $5 million and $32 million, respectively. Delta is rated CC by S&P and Caa3 by Moody's. Northwest is rated B by S&P and Caa2 by Moody's.

      Resources is the lessor of domestic generating facilities in several U.S. energy markets. As a result of rating agency actions due to concerns over forward energy prices, the credit of some of the lessees was downgraded. Specifically, the lessees in the following transactions were downgraded below investment grade during 2002 by these rating agencies. Resources' investment in such transactions was approximately $301 million, net of deferred taxes of $398 million as of December 31, 2004.

      Resources leases a generation facility to Reliant Energy Mid Atlantic Power Holdings LLC (REMA), an indirect wholly-owned subsidiary of Reliant Resources Incorporated (RRI). The leased assets are the Keystone, Conemaugh and Shawville generating facilities located in the PJM West market in Pennsylvania. REMA is capitalized with over $1 billion of equity from RRI and has no debt obligations senior to the lease obligations. REMA was upgraded to ratings of B+ by S&P and B1 by Moody's during 2004. As the lessor/equity participant in the lease, Resources is protected with significant lease covenants that restrict the flow of dividends from REMA to its parent, and by over-collateralization of REMA with non-leased assets, transfer of which is restricted by the financing documents. Restrictive covenants include historicaland forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverages are not met, and similar cash flow restrictions if ratings are not maintained at stated levels. The covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a market downturn

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or degradation in operating performance of the leased assets. Resources' investment in the REMA transaction was $107 million, net of deferred taxes of $149 million as of December 31, 2004.

      Resources is the lessor/equity participant to the lease of the Powerton and Joliet power generating facilities operated by the lessee, Midwest Generation LLC (Midwest), an indirect subsidiary of Edison Mission Energy (EME). EME is the guarantor for the lease obligations. As of December 31, 2004, Resources lease investment in the Powerton and Joliet facilities was $57 million, net of taxes of $134 million. With ongoing credit problems and maturing debt during 2003, EME's corporate credit rating was lowered to B by S&P on credit watch with negative implications in October 2003. EME successfully refinanced its debt in December 2003 through a complex plan which included new debt and bridge financing to be followed by significant offshore asset sales in 2004. In August 2004, EME's credit rating outlook improvedto B with positive implications.

      Resources is the lessor of the Danskammer generation facility in New York to Dynegy Danskammer LLC (Danskammer) and the Roseton generation facility to Dynegy Roseton LLC (Roseton). Both Danskammer and Roseton are indirect subsidiaries of Dynegy Holdings Inc. (DHI). The lease obligations are guaranteed by DHI which is currently rated B by S&P and Caa2 by Moody's. Resources' investment in Danskammer and Roseton was $116 million, net of deferred taxes of $91 million as of December 31, 2004.

      Resources is a lessor/equity participant in a lease to the Midland Cogeneration Venture, LP (MCV) of a 1,500 MW natural gas-fired cogeneration facility located in Midland, Michigan. The principal partners in the limited partnership, which leases the asset, are indirect subsidiaries of CMS Energy Corporation (CMS Energy) and El Paso Energy Corporation (El Paso). S&P's rating of the stand-alone credit quality of the facility is BB- reflecting both CMS Energy's and El Paso's credit deterioration, high fuel gas prices and a mismatch between coal-based energy rates and the price of natural gas fuel supply. To meet these challenges, MCV actively manages and hedges its fuel purchases and has accumulated substantial cash reserves for bondholder protection. Additionally, the partnership has negotiated and receivedthe Michigan Public Service Commission's approval for an operating agreement with Consumers Power to allow the facility to dispatch in a more economic manner, mitigating the fuel risk. Resources closely monitors this credit situation. The facility has been in commercial operation since 1990, successfully paying down a significant portion of its debt to date. Resources' net investment in MCV was $21 million, net of deferred taxes of $24 million as of December 31, 2004.

      In the event of a default, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessor and failure to recover adequate value could lead to a foreclosure of the lease. Under a worst-case scenario, if a foreclosure were to occur, Resources would record a pre-tax write-off up to its gross investment, including deferred taxes, in these facilities. The investment balance increases as earnings are recognized and decreases as rental payments are received by the lessor. Also, in the event of a potential foreclosure, the net tax benefits generated by Resources' portfolio of investments could be materially reduced in the period in which gains associated with the potential forgiveness of debt at these projectsoccurs. The amount and timing of any potential reduction in net tax benefits is dependent upon a number of factors including, but not limited to, the time of a potential foreclosure, the amount of lease debt outstanding, any cash trapped at the projects and negotiations during such potential foreclosure process. The potential loss of earnings, impairment and/or tax payments could have a material impact to PSEG's and Energy Holdings' financial position, results of operations and net cash flows.

      As of December 31, 2004, lease payments on these facilities were current and Resources determined that the collectibility of the minimum lease payments under its leveraged lease investments is still reasonably probable and therefore continues to account for these investments as leveraged leases.

**Other Supplemental Information Regarding Market Risk**

      **Power**

      The following presentation of the activities of Power is included to address the recommended disclosures by the energy industry's Committee of Chief Risk Officers. For additional information, see Note 13. Risk Management of the Notes.

      The following table describes the drivers of Power's energy trading and marketing activities and Operating Revenues included in its Consolidated Statement of Operations for the year ended December 31,

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2004. Normal operations and hedging activities represent the marketing of electricity available from Power's owned or contracted generation sold into the wholesale market. As the information in this table highlights, mark-to-market activities represent a small portion of the total Operating Revenues for Power. Activities accounted for under the accrual method, including normal purchases and sales, account for the majority of the revenue. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices.

**Operating RevenuesFor the Year Ended December 31, 2004**
  **NormalOperations andHedging(A)** **Trading** **Total**  **(Millions)**
**Mark-to-Market Activities:**
            
Unrealized Mark-to-Market Gains (Losses)
            
Changes in Fair Value of Open Positions
    $36     $58     $94 
Origination Unrealized Gain at Inception
     —      —      — 
Changes in Valuation Techniques and Assumptions
     —      —      — 
Realization at Settlement of Contracts
     (29)     (58)     (87)                   
Total Change in Unrealized Fair Value
     7      —      7 
Realized Net Settlement of Transactions Subject to Mark-to-Market
     29      58      87 
Broker Fees and Other Related Expenses
     —      (11)     (11)                   
Net Mark-to-Market Gains
     36      47      83 
**Accrual Activities:**
            
Accrual Activities—Revenue, Including Hedge Reclassifications
     5,090      —      5,090                    
**Total Operating Revenues**
    **$****5,126**     **$****47**     **$****5,173**                                   (A)   Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply, all asset backed transactions (ABT) and hedging activities, but excludes owned and contracted generation assets.
      The following table indicates Power's energy trading assets and liabilities, as well as Power's hedging activity related to ABTs and derivative instruments that qualify for hedge accounting under SFAS 133, its amendments and related guidance. This table presents amounts segregated by portfolio which are then netted for those counterparties with whom Power has the right to set off and therefore, are not necessarily indicative of amounts presented on the Consolidated Balance Sheets since balances with many counterparties are subject to offset and are shown net on the Consolidated Balance Sheets regardless of the portfolio in which they are included.

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**Energy Contract Net Assets/LiabilitiesAs of December 31, 2004**
  **NormalOperations andHedging** **Trading** **Total**  **(Millions)**
Mark-to-Market Energy Assets
            
Current Assets
    $24     $144     $168 
Noncurrent Assets
     19      13      32                    
Total Mark-to-Market Energy Assets
    $43     $157     $200                    
Mark-to-Market Energy Liabilities
            
Current Liabilities
    $(161)    $(129)    $(290)
Noncurrent Liabilities
     (122)     (18)     (140)                   
Total Mark-to-Market Current Liabilities
    $(283)    $(147)    $(430)                   
**Total Mark-to-Market Energy Contract Net (Liabilities) Assets**
    **$****(240****)**    **$****10**     **$****(230****)**                               
      The following table presents the maturity of net fair value of mark-to-market energy trading contracts.

**Maturity of Net Fair Value of Mark-to-Market Energy Trading ContractsAs of December 31, 2004**
  **Maturities within**  **2005** **2006** **2007** **2008-2009 ** **Total**  **(Millions)**
Trading
    $8     $(4)    $(4)    $2     $2 
Normal Operations and Hedging
     (131)     (32)     (36)     (33)     (232)                               
**Total Net Unrealized Losses on Mark-to-Market Contracts**
    **$****(123****)**    **$****(36****)**    **$****(40****)**    **$****(31****)**    **$****(230****)**                                                   
      Wherever possible, fair values for these contracts were obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques were employed using assumptions reflective of current market rates, yield curves and forward prices as applicable to interpolate certain prices. The effect of using such modeling techniques is not material to Power's financial results.

      **PSEG, Power and Energy Holdings**

      The following table identifies losses on cash flow hedges that are currently in Accumulated Other Comprehensive Loss, a separate component of equity. Power uses forward sale and purchase contracts, swaps and firm transmission rights (FTRs) contracts to hedge forecasted energy sales from its generation stations and its contracted supply obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. PSEG, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG's policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt and interest rate derivatives. The table also provides an estimate of the losses that are expected to be reclassifiedout of OCI and into earnings over the next twelve months.

86

**Cash Flow Hedges Included in OCIAs of December 31, 2004**
   **AccumulatedOCI** **Portion Expectedto be Reclassifiedin next 12 months**   **(Millions)**                
**Cash Flow Hedges Included in OCI**
                        
Commodities
    $(148)    $(81)                
Interest Rates
     (64)     (28)                
Foreign Currency
     —      —                               
**Net Cash Flow Hedge Loss Included in OCI**
    **$****(212****)**    **$****(109****)**                                      
      **Power**

      ***Credit Risk***

      The following table provides information on Power's credit exposure, net of collateral, as of December 31, 2004. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value on open positions. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company's credit risk by credit rating of the counterparties.

**Schedule of Credit Risk Exposure on Energy Contracts Net AssetsAs of December 31, 2004**
**Rating** **CurrentExposure** **SecuritiesHeldas Collateral** **NetExposure** **Number ofCounterparties>10%** **Net Exposure ofCounterparties>10%**  **(Millions)**     **(Millions)**
Investment Grade—External Rating
    $554     $84     $521      1     $304 
Non-Investment Grade—External Rating
     24      5      20      —      — 
Investment Grade—No External Rating
     3      —      3      —      — 
Non-Investment Grade—No External Rating
     54      —      54      —      —                                
**Total**
    $635     $89     $598      1     $304                                                    
      The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more collateral than the outstanding exposure, in which case there would not be exposure.

**ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
      This combined Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and makes no representations as to any other company.

87

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

To the Stockholders and Board of Directors ofPUBLIC SERVICE ENTERPRISE GROUP INCORPORATED:

      We have audited the accompanying consolidated balance sheets of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, common stockholders' equity and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.

      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.

      As discussed in Note 2 to the consolidated financial statements, on January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.”

      As discussed in Note 2 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

      We have  also audited, in accordance with the standards of the Public Company Accounting  Oversight Board (United States), the effectiveness of the Company's internal  control over financial reporting as of December 31, 2004, based on the  criteria established in “Internal Control—Integrated Framework”  issued by the Committee of Sponsoring Organizations of the Treadway Commission  and our report dated February 28, 2005 expressed an unqualified opinion  on management's assessment of the effectiveness of the Company's internal  control over financial reporting and an unqualified opinion on the effectiveness  of the Company's internal control over financial reporting.

DELOITTE & TOUCHE LLP

Parsippany, New JerseyFebruary 28, 2005

88

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

To the Sole Stockholder and Board of Directors ofPUBLIC SERVICE ELECTRICAND GAS COMPANY:

      We have audited the accompanying consolidated balance sheets of Public Service Electric and Gas Company and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.

      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management,as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.

DELOITTE & TOUCHE LLP

Parsippany, New JerseyFebruary 28, 2005

89

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

To the Sole Member and Board of Directors ofPSEG POWER LLC:

      We have audited the accompanying consolidated balance sheets of PSEG Power LLC and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, capitalization and member's equity and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.

      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management,as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.

      As discussed in Note 2 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

DELOITTE & TOUCHE LLP

Parsippany, New JerseyFebruary 28, 2005

90

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

To the Sole Member and Board of Directors ofPSEG ENERGY HOLDINGS L.L.C.:

      We have audited the accompanying consolidated balance sheets of PSEG Energy Holdings L.L.C. and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, member's equity and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.

      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management,as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.

      As discussed in Note 2 to the consolidated financial statements, on January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.”

DELOITTE & TOUCHE LLP

Parsippany, New JerseyFebruary 28, 2005

91

**[THIS PAGE INTENTIONALLY LEFT BLANK]**

92

**PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONSOLIDATED STATEMENTS OF OPERATIONS(Millions, except for share data)**
  **For The Years Ended December 31,**  **2004** **2003** **2002**
OPERATING REVENUES
    $10,996         $11,139         $8,220 
OPERATING EXPENSES
            
Energy Costs
     6,057          6,391          3,710 
Operation and Maintenance
     2,260          2,120          1,899 
Write-down of Project Investments
     —          —          511 
Depreciation and Amortization
     719          527          565 
Taxes Other Than Income Taxes
     139          136          131                            
Total Operating Expenses
     9,175          9,174          6,816                            
Income from Equity Method Investments
     126          114          119                            
OPERATING INCOME
     1,947          2,079          1,523 
Other Income
     176          178          39 
Other Deductions
     (93)         (101)         (80)
Interest Expense
     (859)         (836)         (819)
Preferred Stock Dividends
     (4)         (4)         (4)                           
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
     1,167          1,316          659 
Income Tax Expense
     (446)         (464)         (254)                           
INCOME FROM CONTINUING OPERATIONS
     721          852          405 
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax benefit of $0, $8 and $28 for the years ended 2004, 2003 and 2002, respectively
     5          (44)         (49)                           
INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE INACCOUNTING PRINCIPLE
     726          808          356 
Extraordinary Item, net of tax benefit of $12 for 2003
     —          (18)         — 
Cumulative Effect of a Change in Accounting Principle, net of tax (expense) benefit of ($255) and $66 for the years ended 2003 and 2002, respectively
     —          370          (121)                           
NET INCOME
    $726         $1,160         $235                            
WEIGHTED AVERAGE COMMON SHARESOUTSTANDING (THOUSANDS):
            
BASIC
     236,984          228,222          208,647                            
DILUTED
     238,286          228,824          208,813                            
EARNINGS PER SHARE:
            
BASIC
            
INCOME FROM CONTINUING OPERATIONS
    $3.04         $3.73         $1.94 
NET INCOME
    $3.06         $5.08         $1.13                            
DILUTED
            
INCOME FROM CONTINUING OPERATIONS
    $3.03         $3.72         $1.94 
NET INCOME
    $3.05         $5.07         $1.13                            
DIVIDENDS PAID PER SHARE OF COMMON STOCK
    $2.20         $2.16         $2.16                            
See Notes to Consolidated Financial Statements.

93

**PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONSOLIDATED BALANCE SHEETS(Millions)**
  **December 31,**  **2004** **2003**        
**ASSETS**
        
CURRENT ASSETS
        
Cash and Cash Equivalents
    $279     $452 
Accounts Receivable, net of allowances of $34 and $40 in 2004 and 2003, respectively
     1,621      1,551 
Unbilled Revenues
     340      261 
Fuel
     633      527 
Materials and Supplies
     258      227 
Energy Trading Contracts
     135      103 
Prepayments
     123      164 
Restricted Funds
     50      37 
Assets of Discontinued Operations
     —      298 
Other
     204      45              
Total Current Assets
     3,643      3,665              
PROPERTY, PLANT AND EQUIPMENT
     19,121      17,396 
Less: Accumulated Depreciation and Amortization
     (5,371)     (4,981)             
Net Property, Plant and Equipment
     13,750      12,415              
NONCURRENT ASSETS
        
Regulatory Assets
     5,128      4,800 
Long-Term Investments
     4,181      4,810 
Nuclear Decommissioning Trust (NDT) Funds
     1,086      985 
Other Special Funds
     488      470 
Goodwill and Other Intangibles
     643      625 
Other
     288      314              
Total Noncurrent Assets
     11,814      12,004              
TOTAL ASSETS
    $29,207     $28,084              
**LIABILITIES AND CAPITALIZATION**
        
CURRENT LIABILITIES
        
Long-Term Debt Due Within One Year
    $386     $726 
Commercial Paper and Loans
     638      301 
Accounts Payable
     1,362      1,202 
Derivative Contracts
     207      103 
Energy Trading Contracts
     121      75 
Accrued Interest
     154      185 
Accrued Taxes
     54      13 
Clean Energy Program
     82      110 
Liabilities of Discontinued Operations
     —      242 
Other
     484      419              
Total Current Liabilities
     3,488      3,376              
NONCURRENT LIABILITIES
        
Deferred Income Taxes and Investment Tax Credits (ITC)
     4,347      4,216 
Regulatory Liabilities
     517      551 
Nuclear Decommissioning Liabilities
     310      284 
Other Postretirement Benefit (OPEB) Costs
     563      532 
Clean Energy Program
     324      — 
Environmental Costs
     366      144 
Other
     548      427              
Total Noncurrent Liabilities
     6,975      6,154              
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 14)
        
CAPITALIZATION
        
LONG-TERM DEBT
        
Long-Term Debt
     8,414      7,921 
Securitization Debt
     1,939      2,085 
Project Level, Non-Recourse Debt
     1,371      1,738 
Debt Supporting Trust Preferred Securities
     1,201      1,201              
Total Long-Term Debt
     12,925      12,945              
SUBSIDIARY'S PREFERRED SECURITIES
        
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2004 and 2003—795,234 shares
     80      80              
COMMON STOCKHOLDERS' EQUITY
        
Common Stock, no par, authorized 500,000,000 shares; issued 2004—264,128,807 shares and 2003—262,252,032 shares
     4,569      4,490 
Treasury Stock, at cost; 2004—26,029,740 shares; 2003—26,118,590 shares
     (978)     (981)
Retained Earnings
     2,425      2,221 
Accumulated Other Comprehensive Loss
     (277)     (201)             
Total Common Stockholders' Equity
     5,739      5,529              
Total Capitalization
     18,744      18,554              
TOTAL LIABILITIES AND CAPITALIZATION
    $29,207     $28,084              
See Notes to Consolidated Financial Statements.

94

**PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONSOLIDATED STATEMENTS OF CASH FLOWS(Millions)**
  **For The Years EndedDecember 31,**  **2004** **2003** **2002**
CASH FLOWS FROM OPERATING ACTIVITIES
            
Net Income
    $726     $1,160     $235 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
            
Extraordinary Item, net of tax benefit
     —      18      — 
(Gain) Loss on Disposal of Discontinued Operations, net of tax
     (5)     32      35 
Cumulative Effect of a Change in Accounting Principle, net of tax
     —      (370)     121 
Write-Down of Project Investments
     —      —      511 
Depreciation and Amortization
     719      527      565 
Amortization of Nuclear Fuel
     80      89      89 
Provision for Deferred Income Taxes (Other than Leases) and ITC
     172      365      (117)
Non-Cash Employee Benefit Plan Costs
     217      253      187 
Leveraged Lease (Income) Loss, Adjusted for Rents Received
     (92)     77      (44)
Undistributed Earnings from Affiliates
     (12)     40      (5)
Foreign Currency Transaction Loss (Gain)
     26      (16)     77 
Unrealized Losses on Energy Contracts and Other Derivatives
     (4)     38      (35)
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs
     80      (38)     (19)
(Under) Over Recovery of Societal Benefits Charge (SBC)
     (158)     4      20 
Net Realized Gains and Income from NDT Funds
     (105)     (65)     — 
Gain on Sale of Investments
     (79)     (56)     (16)
Other Non-Cash Charges (Credits)
     59      102      (15)
Net Change in Certain Current Assets and Liabilities
     —      (428)     (20)
Employee Benefit Plan Funding and Related Payments
     (174)     (274)     (304)
Proceeds from the Withdrawal of Partnership Interests and Other Distributions
     126      66      54 
Other
     34      (31)     (84)                   
Net Cash Provided By Operating Activities
     1,610      1,493      1,235                    
CASH FLOWS FROM INVESTING ACTIVITIES
            
Additions to Property, Plant and Equipment
     (1,255)     (1,402)     (1,620)
Investments in Joint Ventures, Partnerships and Capital Leases
     (14)     (37)     (227)
Proceeds from the Sale of Investments and Return of Capital from Partnerships
     438      30      388 
Acquisitions, net of Cash Provided
     —      —      (271)
Restricted Cash
     54      (86)     (23)
Other
     23      —      17                    
Net Cash Used In Investing Activities
     (754)     (1,495)     (1,736)                   
CASH FLOWS FROM FINANCING ACTIVITIES
            
Net Change in Commercial Paper and Loans
     339      (327)     (642)
Issuance of Long-Term Debt
     1,429      1,209      1,164 
Issuance of Non-Recourse Debt
     —      1,036      242 
Issuance of Participating Units
     —      —      457 
Issuance of Common Stock
     83      441      536 
Issuance of Preferred Securities
     —      —      174 
Redemptions of Long-Term Debt
     (2,309)     (1,325)     (971)
Redemptions of Preferred Securities
     —      (155)     — 
Cash Dividends Paid on Common Stock
     (522)     (493)     (456)
(Contributions from) Distributions to Minority Shareholders
     (1)     (48)     5 
Other
     (49)     (36)     (13)                   
Net Cash (Used In) Provided By Financing Activities
     (1,030)     302      496                    
Effect of Exhange Rate Change
     1      2      (13)                   
Net (Decrease) Increase in Cash and Cash Equivalents
     (173)     302      (18)
Cash and Cash Equivalents at Beginning of Period
     452      150      168                    
Cash and Cash Equivalents at End of Period
    $279     $452     $150                    
Supplemental Disclosure of Cash Flow Information:
            
Income Taxes Paid
    $104     $(21)    $145 
Interest Paid, Net of Amounts Capitalized
    $851     $975     $843             
See Notes to Consolidated Financial Statements.

95

**PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY(Millions)**
  **Common Stock** **Treasury Stock**              **Shs.** **Amount** **Shs.** **Amount** **Retained Earnings** **AccumulatedOtherComprehensiveLoss** **Total**
**Balance as of January 1, 2002**
   232   $3,599    (26)  $(981)  $1,769   $(319)  $4,068                              
Net Income
   —    —    —    —    235    —    235 
Other Comprehensive Income (Loss), net of tax:
                            
Currency Translation Adjustment, net of tax $(45)
   —    —    —    —    —    (140)   (140)
Reclassification Adjustment for Losses Included in Net Income
   —    —    —    —    —    68    68 
Change in Fair Value of Derivative Instruments, net of tax $(13)
   —    —    —    —    —    (60)   (60)
Reclassification Adjustments for Net Amounts included in Net Income
   —    —    —    —    —    9    9 
Settlement Adjustments Related to Projects Under Construction
   —    —    —    —    —    (3)   (3)
Minimum Pension Liability, net of tax $(201)
   —    —    —    —    —    (293)   (293)
Change in Fair Value of Equity Investments
   —    —    —    —    —    (1)   (1)                             
Other Comprehensive Loss
                           (420)                             
Comprehensive Loss
                           (185)
Cash Dividends on Common Stock
   —    —    —    —    (456)   —    (456)
Issuance of Equity
   19    536    —    —    —    —    536 
Issuance Costs and Other
   —    (84)   —    —    6    —    (78)                             
**Balance as of December 31, 2002**
   251   $4,051    (26)  $(981)  $1,554   $(739)  $3,885                              
Net Income
   —    —    —    —    1,160    —    1,160 
Other Comprehensive Income (Loss), net of tax:
                            
Currency Translation Adjustment, net of tax $4
   —    —    —    —    —    164    164 
Available for Sale Securities, net of tax $81
   —    —    —    —    —    118    118 
Change in Fair Value of Derivative Instruments, net of tax $(32)
   —    —    —    —    —    (57)   (57)
Reclassification Adjustments for Net Amounts included in Net Income
   —    —    —    —    —    32    32 
Settlement Adjustments Related to Projects Under Construction
   —    —    —    —    —    (11)   (11)
Minimum Pension Liability, net of tax $200
   —    —    —    —    —    289    289 
Change in Fair Value of Equity Investments
   —    —    —    —    —    3    3                              
Other Comprehensive Income
                           538                              
Comprehensive Income
                           1,698 
Cash Dividends on Common Stock
   —    —    —    —    (493)   —    (493)
Issuance of Equity
   11    452    —    —    —    —    452 
Issuance Costs and Other
   —    (13)   —    —    —    —    (13)                             
**Balance as of December 31, 2003**
   262   $4,490    (26)  $(981)  $2,221   $(201)  $5,529                              
Net Income
   —    —    —    —    726    —    726 
Other Comprehensive Income (Loss), net of tax:
                            
Currency Translation Adjustment, net of tax $19
   —    —    —    —    —    64    64 
Reclassification Adjustment for Losses Included in Net Income
   —    —    —    —    —    —    — 
Available for Sale Securities, net of tax $29
   —    —    —    —    —    (16)   (16)
Change in Fair Value of Derivative Instruments, net of tax $(115)
   —    —    —    —    —    (167)   (167)
Reclassification Adjustments for Net Amounts included in Net Income
   —    —    —    —    —    50    50 
Other
   —    —    —    —    —    (3)   (3)
Minimum Pension Liability, net of tax $(3)
   —    —    —    —    —    (6)   (6)
Change in Fair Value of Equity Investments
   —    —    —    —    —    2    2                              
Other Comprehensive Loss
                           (76)                             
Comprehensive Income
                           650 
Cash Dividends on Common Stock
   —    —    —    —    (522)   —    (522)
Issuance of Equity
   2    83    —    —    —    —    83 
Issuance Costs and Other
   —    (4)   —    3    —    —    (1)                             
**Balance as of December 31, 2004**
   264   $4,569    (26)  $(978)  $2,425   $(277)  $5,739                                                          
See Notes to Consolidated Financial Statements.

96

**PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONSOLIDATED STATEMENTS OF OPERATIONS(Millions)**
  **For The Years Ended December 31,**  **2004** **2003** **2002**
OPERATING REVENUES
    $6,972           $6,740           $5,919 
OPERATING EXPENSES
            
Energy Costs
     4,284            4,421            3,684 
Operation and Maintenance
     1,083            1,050            982 
Depreciation and Amortization
     523            372            409 
Taxes Other Than Income Taxes
     139            136            131                                
Total Operating Expenses
     6,029            5,979            5,206                                
OPERATING INCOME
     943            761            713 
Other Income
     12            6            15 
Other Deductions
     (1)           (1)           (2)
Interest Expense
     (362)           (390)           (406)                               
INCOME BEFORE INCOME TAXES ANDEXTRAORDINARY ITEM
     592            376            320 
Income Tax Expense
     (246)           (129)           (115)                               
INCOME BEFORE EXTRAORDINARY ITEM
     346            247            205 
Extraordinary Item, net of tax benefit of $12 for 2003
     —            (18)           —                                
NET INCOME
     346            229            205 
Preferred Stock Dividends
     (4)           (4)           (4)                               
EARNINGS AVAILABLE TO PUBLIC SERVICEENTERPRISE GROUP INCORPORATED
    $342           $225           $201                                
See disclosures regarding Public Service Electric and Gas Company included in theNotes to Consolidated Financial Statements.

97

**PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONSOLIDATED BALANCE SHEETS(Millions)**
  **December 31,**  **2004** **2003**        
**ASSETS**
        
CURRENT ASSETS
        
Cash and Cash Equivalents
    $6     $140 
Accounts Receivable, net of allowances of $34 and $34 in 2004 and 2003, respectively
     745      804 
Unbilled Revenues
     340      261 
Materials and Supplies
     45      50 
Prepayments
     61      44 
Restricted Cash
     5      3 
Other
     19      17              
Total Current Assets
     1,221      1,319              
PROPERTY, PLANT AND EQUIPMENT
     10,156      9,793 
Less: Accumulated Depreciation and Amortization
     (3,469)     (3,269)             
Net Property, Plant and Equipment
     6,687      6,524              
NONCURRENT ASSETS
        
Regulatory Assets
     5,128      4,800 
Long-Term Investments
     138      131 
Other Special Funds
     278      272 
Other
     134      131              
Total Noncurrent Assets
     5,678      5,334              
TOTAL ASSETS
    $13,586     $13,177              
**LIABILITIES AND CAPITALIZATION**
        
CURRENT LIABILITIES
        
Long-Term Debt Due Within One Year
    $271     $423 
Commercial Paper and Loans
     105      — 
Accounts Payable
     250      286 
Accounts Payable—Affiliated Companies, net
     422      409 
Accrued Interest
     59      71 
Clean Energy Program
     82      110 
Other
     318      239              
Total Current Liabilities
     1,507      1,538              
NONCURRENT LIABILITIES
        
Deferred Income Taxes and ITC
     2,653      2,737 
Other Postretirement Benefit (OPEB) Costs
     534      509 
Regulatory Liabilities
     517      551 
Clean Energy Program
     324      — 
Environmental Costs
     309      86 
Other
     85      87              
Total Noncurrent Liabilities
     4,422      3,970              
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 14)
        
CAPITALIZATION
        
LONG-TERM DEBT
        
Long-Term Debt
     2,938      3,044 
Securitization Debt
     1,939      2,085              
Total Long-Term Debt
     4,877      5,129              
PREFERRED SECURITIES
        
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2004 and 2003—795,234 shares
     80      80              
COMMON STOCKHOLDER'S EQUITY
        
Common Stock; 150,000,000 shares authorized, 132,450,344 shares issued and outstanding
     892      892 
Contributed Capital
     170      170 
Basis Adjustment
     986      986 
Retained Earnings
     656      414 
Accumulated Other Comprehensive Loss
     (4)     (2)             
Total Common Stockholder's Equity
     2,700      2,460              
Total Capitalization
     7,657      7,669              
TOTAL LIABILITIES AND CAPITALIZATION
    $13,586     $13,177              
See disclosures regarding Public Service Electric and Gas Company included in theNotes to Consolidated Financial Statements.

98

**PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONSOLIDATED STATEMENTS OF CASH FLOWS(Millions)**
  **For The Years EndedDecember 31,**  **2004** **2003** **2002**
CASH FLOWS FROM OPERATING ACTIVITIES
            
Net Income
    $346     $229     $205 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
            
Extraordinary Item, net of tax benefit
     —      18      — 
Depreciation and Amortization
     523      372      409 
Provision for Deferred Income Taxes and ITC
     (80)     130      (1)
Non-Cash Employee Benefit Plan Costs
     155      179      141 
Non-Cash Interest Expense
     24      50      25 
Over (Under) Recovery of Electric Energy Costs (BGS and NTC)
     10      (139)     (19)
Over (Under) Recovery of Gas Costs
     70      101      (41)
(Under) Over Recovery of SBC
     (158)     4      61 
Other Non-Cash Charges (Credits)
     3      (8)     (34)
Gain on Sale of Property, Plant and Equipment
     —      (11)     (10)
Net Changes in Certain Current Assets and Liabilities:
            
Accounts Receivable and Unbilled Revenues
     (20)     (21)     (154)
Natural Gas
     —      —      415 
Materials and Supplies
     5      (5)     5 
Prepayments
     (17)     (19)     15 
Accrued Taxes
     18      2      (22)
Accrued Interest
     (12)     2      (13)
Accounts Payable
     (45)     (33)     60 
Other Current Assets and Liabilities
     59      (52)     2 
Employee Benefit Plan Funding and Related Payments
     (115)     (177)     (198)
Other
     (62)     (13)     (14)                   
Net Cash Provided By Operating Activities
     704      609      832                    
CASH FLOWS FROM INVESTING ACTIVITIES
            
Additions to Property, Plant and Equipment
     (428)     (411)     (447)
Proceeds from the Sale of Property, Plant and Equipment—Affiliate
     —      53      — 
Proceeds from the Sale of Property, Plant and Equipment
     13      13      10 
Restricted Cash
     (4)     (4)     (2)
Other
     —      5      —                    
Net Cash Used In Investing Activities
     (419)     (344)     (439)                   
CASH FLOWS FROM FINANCING ACTIVITIES
            
Net Change in Short-Term Debt
     105      (224)     224 
Issuance of Long-Term Debt
     710      909      300 
Redemption of Securitization Debt
     (137)     (129)     (120)
Redemption of Long-Term Debt
     (984)     (514)     (547)
Redemption of Preferred Securities
     —      (155)     — 
Contributed Capital
     —      170      — 
Deferred Issuance Costs
     (9)     (10)     (2)
Cash Dividends Paid on Common Stock
     (100)     (200)     (305)
Preferred Stock Dividends
     (4)     (4)     (4)
Other
     —      (3)     (6)                   
Net Cash Used In Financing Activities
     (419)     (160)     (460)                   
Net (Decrease) Increase in Cash and Cash Equivalents
     (134)     105      (67)
Cash and Cash Equivalents at Beginning of Period
     140      35      102                    
Cash and Cash Equivalents at End of Period
    $6     $140     $35                    
Supplemental Disclosure of Cash Flow Information:
            
Income Taxes Paid
    $355     $16     $161 
Interest Paid, Net of Amounts Capitalized
    $347     $371     $428 
See disclosures regarding Public Service Electric and Gas Company included in theNotes to Consolidated Financial Statements.

99

**PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY(Millions)**
  **CommonStock** **ContributedCapital fromPSEG** **BasisAdjustment** **RetainedEarnings** **AccumulatedOtherComprehensiveLoss** **Total**
**Balance as of January 1, 2002**
  $892    $—    $986    $493    $(1)   $2,370                               
Net Income
   —     —     —     205     —     205 
Other Comprehensive Loss, net of tax:
                        
Minimum Pension Liability, net of tax $(104)
   —     —     —     —     (171)    (171)                          
Comprehensive Income
                        34                           
Cash Dividends on Common Stock
   —     —     —     (305)    —     (305)
Cash Dividends on Preferred Stock
   —     —     —     (4)    —     (4)                              
**Balance as of December 31, 2002**
  $892    $—    $986    $389    $(172)   $2,095                               
Net Income
   —     —     —     229     —     229 
Other Comprehensive Income, net of tax:
                        
Minimum Pension Liability, net of tax $117
   —     —     —     —     170     170                          
Comprehensive Income
                        399                          
Cash Dividends on Common Stock
   —     —     —     (200)    —     (200)
Cash Dividends on Preferred Stock
   —     —     —     (4)    —     (4)
Contributed Capital
   —     170     —     —     —     170                               
**Balance as of December 31, 2003**
  $892    $170    $986    $414    $(2)   $2,460                               
Net Income
   —     —     —     346     —     346 
Other Comprehensive Loss, net of tax:
                        
Minimum Pension Liability, net of tax $(1)
   —     —     —     —     (2)    (2)                          
Comprehensive Income
                        344                           
Cash Dividends on Common Stock
   —     —     —     (100)    —     (100)
Cash Dividends on Preferred Stock
   —     —     —     (4)    —     (4)                              
**Balance as of December 31, 2004**
  $892    $170    $986    $656    $(4)   $2,700                               
See disclosures regarding Public Service Electric and Gas Company included in theNotes to Consolidated Financial Statements.

100

**PSEG POWER LLCCONSOLIDATED STATEMENTS OF OPERATIONS(Millions)**
  **For The Years EndedDecember 31,**  **2004** **2003** **2002**
OPERATING REVENUES
    $5,173     $5,613     $3,640 
OPERATING EXPENSES
            
Energy Costs
     3,558      3,754      1,856 
Operation and Maintenance
     967      914      773 
Depreciation and Amortization
     121      102      108                    
Total Operating Expenses
     4,646      4,770      2,737                    
OPERATING INCOME
     527      843      903 
Other Income
     166      149      1 
Other Deductions
     (57)     (78)     (1)
Interest Expense
     (142)     (114)     (122)                   
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECTOF A CHANGE IN ACCOUNTING PRINCIPLE
     494      800      781 
Income Tax Expense
     (186)     (326)     (313)                   
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE
     308      474      468 
Cumulative Effect of a Change in Accounting Principle, net of a tax expense of $255 for 2003
     —      370      —                    
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISEGROUP INCORPORATED
    $308     $844     $468                                
See disclosures regarding PSEG Power LLC included in theNotes to Consolidated Financial Statements.

101

**PSEG POWER LLCCONSOLIDATED BALANCE SHEETS(Millions)**
  **December 31,**  **2004** **2003**
**ASSETS**
        
CURRENT ASSETS
        
Cash and Cash Equivalents
    $10     $27 
Accounts Receivable
     747      617 
Accounts Receivable—Affiliated Companies, net
     343      230 
Short-Term Loan to Affiliate
     —      77 
Fuel
     621      516 
Materials and Supplies
     178      162 
Energy Trading Contracts
     135      103 
Other
     63      53              
Total Current Assets
     2,097      1,785              
PROPERTY, PLANT AND EQUIPMENT
     6,577      5,980 
Less: Accumulated Depreciation and Amortization
     (1,499)     (1,399)             
Net Property, Plant and Equipment
     5,078      4,581              
NONCURRENT ASSETS
        
Nuclear Decommissioning Trust (NDT) Funds
     1,086      985 
Goodwill and Other Intangibles
     120      122 
Other Special Funds
     121      115 
Deferred Income Taxes and Investment Tax Credits (ITC)
     —      22 
Other
     95      125              
Total Noncurrent Assets
     1,422      1,369              
TOTAL ASSETS
    $8,597     $7,735              
**LIABILITIES AND MEMBER'S EQUITY**
        
CURRENT LIABILITIES
        
Accounts Payable
    $992     $786 
Short-Term Loan from Affiliate
     98      — 
Energy Trading Contracts
     121      75 
Derivative Contracts
     151      37 
Accrued Interest
     42      38 
Other
     114      134              
Total Current Liabilities
     1,518      1,070              
NONCURRENT LIABILITIES
        
Deferred Income Taxes and Investment Tax Credits (ITC)
     94      — 
Nuclear Decommissioning Liabilities
     310      284 
Other
     281      160              
Total Noncurrent Liabilities
     685      444              
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 14)
        
LONG-TERM DEBT
        
Project Level, Non-Recourse Debt
     —      800 
Long-Term Debt
     3,316      2,816              
Total Long-Term Debt
     3,316      3,616              
MEMBER'S EQUITY
        
Contributed Capital
     2,000      1,700 
Basis Adjustment
     (986)     (986)
Retained Earnings
     2,118      1,810 
Accumulated Other Comprehensive (Loss) Income
     (54)     81              
Total Member's Equity
     3,078      2,605              
TOTAL LIABILITIES AND MEMBER'S EQUITY
    $8,597     $7,735                      
See disclosures regarding PSEG Power LLC included in theNotes to Consolidated Financial Statements.

102

**PSEG POWER LLCCONSOLIDATED STATEMENTS OF CASH FLOWS(Millions)**
  **For The Years EndedDecember 31,**  **2004** **2003** **2002**
CASH FLOWS FROM OPERATING ACTIVITIES
            
Net Income
    $308     $844     $468 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
            
Cumulative Effect of a Change in Accounting Principle, net of tax
     —      (370)     — 
Depreciation and Amortization
     121      102      108 
Amortization of Nuclear Fuel
     80      89      89 
Interest Accretion on NDT Liability
     26      24      — 
Provision for Deferred Income Taxes and ITC
     168      151      90 
Unrealized Losses on Energy Contracts and Derivatives
     (7)     33      (23)
Non-Cash Employee Benefit Plan Costs
     40      54      32 
Net Realized Gains and Income on NDT Funds
     (105)     (65)     — 
Net Changes in Certain Current Assets and Liabilities:
            
Fuel, Materials and Supplies
     (121)     (125)     (329)
Accounts Receivable
     (243)     (82)     (200)
Accounts Payable
     206      96      261 
Other Current Assets and Liabilities
     23      (37)     82 
Employee Benefit Plan Funding and Other Payments
     (39)     (70)     (76)
Other
     86      (20)     (85)                   
Net Cash Provided By Operating Activities
     497      624      417                    
CASH FLOWS FROM INVESTING ACTIVITIES
            
Additions to Property, Plant and Equipment
     (725)     (699)     (1,046)
Short-Term Loan to Affiliate
     77      (77)     — 
Change in Restricted Cash
     39      (39)     — 
Acquisition of Generation Businesses, net of cash
     —      —      (271)
Proceeds from the Sale of Property, Plant and Equipment
     —      —      47 
Other
     9      (17)     (29)                   
Net Cash Used In Investing Activities
     (600)     (832)     (1,299)                   
CASH FLOWS FROM FINANCING ACTIVITIES
            
Issuance of Recourse Long-Term Debt
     500      300      600 
Issuance of Non-Recourse Long-Term Debt
     —      —      30 
Redemption of Non-Recourse Long-Term Debt
     (800)     —      — 
Proceeds from Contributed Capital
     300      150      200 
Deferred Issuance Costs
     (12)     (2)     (6)
Short-Term Loan from Affiliate
     98      (239)     75                    
Net Cash Provided By Financing Activities
     86      209      899                    
Net (Decrease) Increase in Cash and Cash Equivalents
     (17)     1      17 
Cash and Cash Equivalents at Beginning of Period
     27      26      9                    
Cash and Cash Equivalents at End of Period
    $10     $27     $26                    
Supplemental Disclosure of Cash Flow Information:
            
Income Taxes Paid
    $12     $99     $91 
Interest Paid, Net of Amounts Capitalized
    $233     $217     $200             
See disclosures regarding PSEG Power LLC included in theNotes to Consolidated Financial Statements.

103

**PSEG POWER LLCCONSOLIDATED STATEMENTS OF CAPITALIZATION AND MEMBER'S EQUITY(Millions)**
  **ContributedCapital** **BasisAdjustment** **RetainedEarnings** **AccumulatedOtherComprehensiveIncome (Loss)** **TotalMember'sEquity**
**Balance as of January 1, 2002**
    $1,350     $(986)    $498     $(2)    $860                                
Net Income
     —      —      468      —      468 
Other Comprehensive Loss,net of tax:
                    
Change in Fair Value ofDerivative Instruments, net oftax $(3)
     —      —      —      (5)     (5)
Pension Adjustments, net of tax $(50)
     —      —      —      (84)     (84)                      
Other Comprehensive Loss
                     (89)                      
Comprehensive Income
                     379 
Contributed Capital
     200      —      —      —      200                                
**Balance as of December 31, 2002**
    $1,550     $(986)    $966     $(91)    $1,439                                
Net Income
     —      —      844      —      844 
Other Comprehensive Income(Loss), net of tax:
                    
Available for Sale Securities,net of tax $81
     —      —      —      118      118 
Change in Fair Value ofDerivative Instruments, net oftax $(21)
     —      —      —      (40)     (40)
Reclassification Adjustments forNet Amount Included in NetIncome, net of tax
     —      —      —      11      11 
Pension Adjustments, net of tax$58
     —      —      —      83      83                       
Other Comprehensive Income
                     172                       
Comprehensive Income
                     1,016 
Contributed Capital
     150      —      —      —      150                                
**Balance as of December 31, 2003**
    $1,700     $(986)    $1,810     $81     $2,605                                
Net Income
     —      —      308      —      308 
Other Comprehensive Income(Loss), net of tax:
                    
Available for Sale Securities,net of tax $29
     —      —      —      (16)     (16)
Change in Fair Value ofDerivative Instruments, net oftax $(115)
     —      —      —      (166)     (166)
Reclassification Adjustments forNet Amount Included in NetIncome, net of tax
     —      —      —      47      47                       
Other Comprehensive Loss
                     (135)                      
Comprehensive Income
                     173 
Contributed Capital
     300      —      —      —      300                                
**Balance as of December 31, 2004**
    $2,000     $(986)    $2,118     $(54)    $3,078                                
See disclosures regarding PSEG Power LLC included in theNotes to Consolidated Financial Statements.

104

**PSEG ENERGY HOLDINGS LLCCONSOLIDATED STATEMENTS OF OPERATIONS(Millions)**
  **For The Years EndedDecember 31,**  **2004** **2003** **2002**
OPERATING REVENUES
            
Electric Generation and Distribution Revenues
    $749     $431     $304 
Income from Capital and Operating Leases
     165      217      217 
Other
     113      77      88                    
Total Operating Revenues
     1,027      725      609                    
OPERATING EXPENSES
            
Energy Costs
     388      155      118 
Operation and Maintenance
     239      176      168 
Write-down of Project Investments
     —      —      511 
Depreciation and Amortization
     57      44      28                    
Total Operating Expenses
     684      375      825                    
Income from Equity Method Investments
     126      114      119                    
OPERATING INCOME (LOSS)
     469      464      (97)
Other Income
     4      20      26 
Other Deductions
     (33)     (5)     (77)
Interest Expense
     (255)     (218)     (217)                   
INCOME (LOSS) BEFORE INCOME TAXES, MINORITYINTEREST, DISCONTINUED OPERATIONS ANDCUMULATIVE EFFECT OF A CHANGE INACCOUNTING PRINCIPLE
     185      261      (365)
Income Tax (Expense) Benefit
     (48)     (59)     144 
Minority Interests in (Earnings) Losses of Subsidiaries
     (1)     (13)     1                    
INCOME (LOSS) BEFORE DISCONTINUEDOPERATIONS AND CUMULATIVE EFFECT OF ACHANGE IN ACCOUNTING PRINCIPLE
     136      189      (220)
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax benefit of $8 and $28 for the years ended 2003 and 2002, respectively
     5      (44)     (49)                   
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE
     141      145      (269)
Cumulative Effect of a Change in Accounting Principle, net of tax benefit of $66 for the year ended 2002
     —      —      (121)                   
NET INCOME (LOSS)
     141      145      (390)
Preference Units Distributions
     (16)     (23)     (23)                   
EARNINGS (LOSS) AVAILABLE TO PUBLIC SERVICEENTERPRISE GROUP INCORPORATED
    $125     $122     $(413)                   
See disclosures regarding PSEG Energy Holdings LLC included in theNotes to Consolidated Financial Statements.

105

**PSEG ENERGY HOLDINGS LLCCONSOLIDATED BALANCE SHEETS(Millions)**
  **December 31,**  **2004** **2003**        
**ASSETS**
        
CURRENT ASSETS
        
Cash and Cash Equivalents
    $199     $104 
Accounts Receivable:
        
Trade—net of allowances of $0 and $6 in 2004 and 2003,respectively
     114      103 
Other Accounts Receivable
     20      19 
Affiliated Companies
     19      173 
Notes Receivable:
        
Affiliated Companies
     115      300 
Other
     138      2 
Inventory
     47      26 
Restricted Funds
     45      16 
Assets of Discontinued Operations
     —      298 
Other
     7      10              
Total Current Assets
     704      1,051              
PROPERTY, PLANT AND EQUIPMENT
     2,084      1,352 
Less: Accumulated Depreciation and Amortization
     (227)     (170)             
      Net Property, Plant and Equipment
     1,857      1,182              
NONCURRENT ASSETS
        
Leveraged Leases, net
     2,851      2,981 
Corporate Joint Ventures
     894      1,041 
Partnership Interests
     219      531 
Goodwill and Other Intangibles
     517      496 
Other
     153      182              
Total Noncurrent Assets
     4,634      5,231              
TOTAL ASSETS
    $7,195     $7,464              
**LIABILITIES AND MEMBER'S EQUITY**
        
CURRENT LIABILITIES
        
Long-Term Debt Due Within One Year
    $66     $303 
Accounts Payable:
        
Trade
     59      53 
Affiliated Companies
     2      4 
Derivative Contracts
     37      37 
Accrued Interest
     51      58 
Liabilities of Discontinued Operations
     —      242 
Other
     71      72              
Total Current Liabilities
     286      769              
NONCURRENT LIABILITIES
        
Deferred Income Taxes and Investment and Energy Tax Credits
     1,587      1,487 
Derivative Contracts
     88      73 
Other
     56      58              
Total Noncurrent Liabilities
     1,731      1,618              
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 14)
        
MINORITY INTERESTS
     35      35              
LONG-TERM DEBT
        
Project Level, Non-Recourse Debt
     1,371      938 
Senior Notes
     1,756      1,800              
Total Long-Term Debt
     3,127      2,738              
MEMBER'S EQUITY
        
Ordinary Unit
     1,813      1,888 
Preference Units
     184      509 
Retained Earnings
     228      178 
Accumulated Other Comprehensive Loss
     (209)     (271)             
Total Member's Equity
     2,016      2,304              
TOTAL LIABILITIES AND MEMBER'S EQUITY
    $7,195     $7,464              
See disclosures regarding PSEG Energy Holdings LLC included in theNotes to Consolidated Financial Statements.

106

**PSEG ENERGY HOLDINGS LLCCONSOLIDATED STATEMENTS OF CASH FLOWS(Millions)**
  **For The Years EndedDecember 31,**  **2004** **2003** **2002**
CASH FLOWS FROM OPERATING ACTIVITIES
            
Net Income (Loss)
    $141     $145     $(390)
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:
            
Write-down of Project Investments
     —      —      511 
Cumulative Effect of a Change in Accounting Principle, net of tax
     —      —      121 
(Gain) Loss on Disposal of Discontinued Operations, net of tax
     (5)     32      35 
Depreciation and Amortization
     67      53      48 
Deferred Income Taxes (Other than Leases)
     83      81      (212)
Leveraged Lease Income, Adjusted for Rents Received
     (92)     77      (44)
Unrealized Loss on Investments
     —      1      — 
Change in Fair Value of Derivative Financial Instruments
     3      5      (12)
Undistributed (Earnings) Losses from Affiliates
     (12)     40      (5)
Gain on Sale of Investments
     (79)     (45)     (6)
Foreign Currency Transaction Loss (Gain)
     26      (16)     77 
Other Non-Cash Charges
     4      31      (6)
Net Changes in Certain Current Assets and Liabilities:
            
Accounts Receivable
     189      (24)     2 
Inventory
     (9)     (12)     — 
Accounts Payable
     (44)     (124)     (37)
Other Current Assets and Liabilities
     8      (3)     (15)
Proceeds from Withdrawal of Partnership Interests and Other Distributions
     126      66      54 
Other
     3      (13)     (13)                   
Net Cash Provided By Operating Activities
     409      294      108                    
CASH FLOWS FROM INVESTING ACTIVITIES
            
Additions to Property, Plant and Equipment
     (86)     (271)     (113)
Investments in Joint Ventures, Partnerships, and Leveraged Lease Agreements
     (14)     (37)     (227)
Proceeds from the Sale of Investments and Return of Capital from Partnerships
     191      19      205 
Proceeds from Termination of Capital Leases
     247      11      183 
Short-Term Loan Receivable—Affiliated Company
     185      (238)     (62)
Restricted Cash
     19      (43)     (21)
Other
     4      (7)     (15)                   
Net Cash Provided By (Used In) Investing Activities
     546      (566)     (50)                   
CASH FLOWS FROM FINANCING ACTIVITIES
            
Net Change in Short-Term Debt
     —      —      (332)
Proceeds from Issuance of Senior Notes
     —      340      133 
Repayment of Senior Notes
     (311)     (13)     (41)
Repayment of Medium-Term Notes
     —      (252)     (228)
Proceeds from Project-Level Non-Recourse Long-Term Debt
     19      677      77 
Repayment of Project-Level Non-Recourse Long-Term Debt
     (77)     (396)     (2)
Redemption of Preference Units
     (325)     —      — 
Return of Capital Contributed
     (75)     —      — 
Proceeds from Capital Contributions
     —      —      400 
Ordinary Unit Distributions
     (75)     —      — 
Payments to Minority Shareholders
     (1)     (48)     5 
Cash Distributions Paid on Preference Units/Preferred Stock
     (16)     (22)     (23)                   
Net Cash (Used In) Provided By Financing Activities
     (861)     286      (11)                   
Effect of Exchange Rate Change
     1      2      (13)                   
Net Increase in Cash and Cash Equivalents
     95      16      34 
Cash and Cash Equivalents at Beginning of Period
     104      88      54                    
Cash and Cash Equivalents at End of Period
    $199     $104     $88                    
Supplemental Disclosure of Cash Flow Information:
            
Income Taxes Received
    $(197)    $(154)    $(126)
Interest Paid, Net of Amounts Capitalized
    $247     $166     $193             
See disclosures regarding PSEG Energy Holdings LLC included in theNotes to Consolidated Financial Statements.

107

**PSEG ENERGY HOLDINGS LLCCONSOLIDATED STATEMENTS OF MEMBER'S/STOCKHOLDER'S EQUITY(Millions)**
  **OrdinaryUnit** **PreferenceUnits** **PreferredStock** **AdditionalPaid-InCapital** **RetainedEarnings** **OtherComprehensiveIncome (Loss)** **Total Member's/Stockholder'sEquity**
**Balance as of January 1, 2002**
  $—   $—   $509   $1,490   $469   $(313)  $2,155                              
Net Loss
   —    —    —    —    (390)   —    (390)
Other Comprehensive Income (Loss), net of tax:
                            
Currency Translation Adjustment, net of tax $(45)
   —    —    —    —    —    (140)   (140)
Reclassification Adjustment for Losses Included in Net Loss, net of tax $37
   —    —    —    —    —    68    68 
Current Period Declines in Fair Value of Derivative Instruments, net of tax $(10)
   —    —    —    —    —    (45)   (45)
Reclassification Adjustments for Net Amounts Included in Net Loss
   —    —    —    —    —    9    9 
Settlement Adjustments Related to Projects Under Construction
   —    —    —    —    —    (3)   (3)
Minimum Pension Liability Adjustment
   —    —    —    —    —    (6)   (6)                            
Other Comprehensive Loss
                           (117)                            
Comprehensive Loss
                           (507)
Additional Contributed Capital
   100    —    —    300    —    —    400 
Recapitalization of Energy Holdings' Assets and Liabilities
   1,790    509    (509)   (1,790)   —    —    — 
Preference Units Distribution
   —    —    —    —    (23)   —    (23)
Dividend of Pantellos Corporation to PSEG
   (2)   —    —    —    —    —    (2)                             
**Balance as of December 31, 2002**
  $1,888   $509   $—   $—   $56   $(430)  $2,023                              
Net Income
   —    —    —    —    145    —    145 
Other Comprehensive Income (Loss), net of tax:
                            
Currency Translation Adjustment, net of tax $4
   —    —    —    —    —    164    164 
Current Period Declines in Fair Value of Derivative Instruments, net of tax $(11)
   —    —    —    —    —    (22)   (22)
Reclassification Adjustments for Net Amounts Included in Net Income
   —    —    —    —    —    23    23 
Settlement Adjustments Related to Projects Under Construction
   —    —    —    —    —    (11)   (11)
Minimum Pension Liability Adjustment
   —    —    —    —    —    5    5                             
Other Comprehensive Income
                           159                             
Comprehensive Income
                           304 
Preference Units Distribution
   —    —    —    —    (23)   —    (23)                             
**Balance as of December 31, 2003**
  $1,888   $509   $—   $—   $178   $(271)  $2,304                              
Net Income
   —    —    —    —    141    —    141 
Other Comprehensive Income (Loss), net of tax:
                            
Currency Translation Adjustment, net of tax $(8)
   —    —    —    —    —    64    64 
Current Period Declines in Fair Value of Derivative Instruments, net of tax $(1)
   —    —    —    —    —    (2)   (2)
Reclassification Adjustments for Net Amounts Included in Net Income
   —    —    —    —    —    3    3 
Other
   —    —    —    —    —    (3)   (3)                            
Other Comprehensive Income
                           62                             
Comprehensive Income
                           203 
Ordinary Unit Distributions
   —    —    —    —    (75)   —    (75)
Return of Contributed Capital
   (75)   —    —    —    —    —    (75)
Preference Units Redemption
   —    (325)   —    —    —    —    (325)
Preference Units Distribution
   —    —    —    —    (16)   —    (16)                             
**Balance as of December 31, 2004**
  $1,813   $184   $—   $—   $228   $(209)  $2,016                                                          
See disclosures regarding PSEG Energy Holdings LLC included in theNotes to Consolidated Financial Statements.

108

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Note 1. Organization and Summary of Significant Accounting Policies
**Organization**

      **Public Service Enterprise Group Incorporated (PSEG)**

      PSEG has four principal direct wholly-owned subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings LLC (Energy Holdings) and PSEG Services Corporation (Services).

      On December 20, 2004, PSEG and Exelon Corporation (Exelon), a public utility company headquartered in Chicago, Illinois, entered into an agreement and plan of merger (Merger Agreement). For additional information, see Note 25. Merger Agreement.

      **PSE&G**

      PSE&G is an operating public utility engaged principally in the transmission and distribution of electric energy and natural gas service in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC).

      PSE&G also owns PSE&G Transition Funding LLC (Transition Funding), a bankruptcy remote entity that purchased certain intangible transition property from PSE&G and issued certain transition bonds secured by such property.

      **Power**

      Power is a multi-regional, independent wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management function through three principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Nuclear and Fossil own and operate generation and generation-related facilities. ER&T is responsible for the day-to-day management of the portfolio. Fossil, Nuclear and ER&T are subject to regulation by the FERC.

      **Energy Holdings**

      Energy Holdings has two principal direct wholly-owned subsidiaries: PSEG Global LLC (Global), which owns and operates international and domestic projects engaged in the generation and distribution of energy, including independent power production facilities and electric distribution companies; and PSEG Resources LLC (Resources), which has primarily invested in energy-related leveraged leases. Energy Holdings also owns Enterprise Group Development Corporation (EGDC), a commercial real estate property management business. During the third quarter of 2003, Energy Holdings completed the sale of PSEG Energy Technologies Inc. (Energy Technologies). For additional information relating to Energy Technologies, see Note 4. Discontinued Operations, Dispositions and Acquisitions.

      **Services**

      Services provides management and administrative services to PSEG and its subsidiaries. These include accounting, legal, communications, human resources, information technology, treasury and financial services, investor relations, stockholder services, real estate, environmental, health and safety, 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.

109

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Summary of Significant Accounting Policies**

      **Principles of Consolidation**

      ***PSEG, PSE&G, Power and Energy Holdings***

      PSEG's, PSE&G's, Power's and Energy Holdings' consolidated financial statements include their respective accounts and consolidate those entities in which they have a controlling interest or are the primary beneficiary, except for certain of PSEG's and PSE&G's capital trusts which were deconsolidated in accordance with Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities (VIE)” (FIN 46), as discussed in Note 2. Recent Accounting Standards. Entities over which PSEG, PSE&G, Power and Energy Holdings exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary are accounted for under the equity method of accounting. For investments in which significant influencedoes not exist and it is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation.

      ***PSE&G and Power***

      PSE&G and Power each has undivided interests in certain jointly-owned facilities. PSE&G and Power are responsible to pay for their respective ownership share of additional construction costs, fuel inventory purchases and operating expenses. All revenues and expenses related to these facilities are consolidated at their respective pro-rata ownership share in the appropriate revenue and expense categories on the Consolidated Statements of Operations. For additional information regarding these jointly-owned facilities, see Note 21. Property, Plant and Equipment and Jointly-Owned Facilities.

      **Accounting for the Effects of Regulation**

      ***PSE&G and Energy Holdings***

      PSE&G  and certain of Global's investments prepare their respective financial statements  in accordance with the provisions of Statement of Financial Accounting Standards  (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation”  (SFAS 71). In general, SFAS 71 recognizes that accounting for rate-regulated  enterprises should reflect the economic effects of regulation. As a result,  a regulated utility is required to defer the recognition of costs (a regulatory  asset) or record the recognition of obligations (a regulatory liability) if  it is probable that, through the rate-making process, there will be a corresponding  increase or decrease in future rates. Accordingly, PSE&G and Global have  deferred certain costs and recoveries, which are being amortized over various  future periods. To the extent that collection of any such costs or payment of  liabilities is no longer probable as a result of changes in regulation and/or  PSE&G's and Global's competitive positions, the associated regulatory  asset or liability is charged or credited to income. Management believes that  PSE&G's and certain of Global's transmission and distribution businesses  continue to meet the requirements for application of SFAS 71. For additional  information, see Note 7. Regulatory Matters.

      **Derivative Financial Instruments**

      ***PSEG, PSE&G, Power and Energy Holdings***

      PSEG, PSE&G, Power and Energy Holdings use derivative financial instruments to manage risk from changes in interest rates, congestion credits, emission credits, commodity prices and foreign currency exchange rates, pursuant to their business plans and prudent practices.

      PSEG, PSE&G, Power and Energy Holdings recognize derivative instruments on the balance sheet at their fair value. Changes in the fair value of a derivative that is highly effective as, and that is designated and qualifies as, a fair-value hedge (including foreign currency fair-value hedges), along with changes of the fair value of the hedged asset or liability that are attributable to the hedged risk, are recorded in current-period earnings. Changes in the fair value of a derivative that is highly effective as, and that is designated and qualifies as, a cash flow hedge (including foreign currency cash flow hedges) are recorded in Other Comprehensive Income (OCI) until earnings are affected by the variability of cash flows of the hedged

110

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

transaction. Any hedge ineffectiveness is included in current-period earnings. In certain circumstances, PSEG, PSE&G, Power and/or Energy Holdings enter into derivative contracts that do not qualify as hedges or choose not to designate them as fair value or cash flow hedges; in such cases, changes in fair value are recorded in current-period earnings.

      For additional information regarding derivative financial instruments, see Note 13. Risk Management.

      **Revenue Recognition**

      ***PSE&G***

      PSE&G's Operating Revenues are recorded based on services rendered to customers during each accounting period. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms.

      ***Power***

      The majority of Power's revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power also records revenues and energy costs for physical energy delivered and received. Power records margins from energy trading on a net basis pursuant to accounting principles generally accepted in the U.S. (GAAP). See Note 13. Risk Management for further discussion.

      ***Energy Holdings***

      Global records revenues from its investments in generation and distribution facilities. Certain of Global's investments are majority owned, controlled and consolidated by Global. Revenues from these projects are recorded as Global's revenues. Other investments are less than majority owned and are accounted for under the equity or cost methods as appropriate. Income from these investments is recorded as a component of Operating Income. Gains or losses incurred as a result of exiting one of these businesses are typically recorded as a component of Operating Income.

      The majority of Resources' revenues relate to its investments in leveraged leases and are accounted for under SFAS No. 13, “Accounting for Leases” (SFAS 13). Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as revenues as these events occur in the ordinary course of business of managing the investment portfolio. For its equity securities, Resources records revenues from the changes in share prices of publicly-traded equity securities held within its leveraged buyout funds. See Note 10. Long-Term Investments for further discussion.

      **Depreciation and Amortization**

      ***PSE&G***

      PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU. The depreciation rate stated as a percentage of original cost of depreciable property was 3.07% for 2004, 3.30% for 2003 and 3.37% for 2002.

      ***Power***

      Power calculates depreciation on generation-related assets under the straight-line method based on the assets' estimated useful life which is determined based on planned operations. The estimated useful lives are from three years to 20 years for general plant assets. The estimated useful lives are 30 years to 55 years for

111

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

fossil production assets, 49 years to 56 years for nuclear generation assets and 45 years for pumped storage facilities.

      ***Energy Holdings***

      Energy Holdings calculates depreciation on property, plant and equipment under the straight-line method with estimated useful lives ranging from three years to 40 years.

      **Taxes Other Than Income Taxes**

      ***PSE&G***

      Excise taxes, transitional energy facilities assessment (TEFA) and gross receipts tax (GRT) collected from PSE&G customers are presented on the financial statements on a gross basis. As a result of New Jersey energy tax reform, effective January 1, 1998, TEFA and GRT are the residual of the prior excise tax, New Jersey gross receipts and franchise taxes. For the years ended December 31, 2004, 2003 and 2002, combined TEFA and GRT of approximately $153 million, $152 million and $145 million, respectively, are reflected in Operating Revenues and $139 million, $136 million and $131 million, respectively, are included in Taxes Other Than Income Taxes on the Consolidated Statements of Operations.

      **Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC)**

      ***PSE&G***

      AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets under the guidance of SFAS 71. The amount of AFUDC capitalized is reported in the Consolidated Statements of Operations as a reduction of interest charges. PSE&G's average rate used for calculating AFUDC in 2004, 2003 and 2002 was 1.33%, 3.43% and 8.34%, respectively. For the years ended December 31, 2004, 2003 and 2002, PSE&G's AFUDC amounted to $0.1 million, $0.3 million and $1 million, respectively.

      ***Power and Energy Holdings***

      IDC represents the cost of debt used to finance construction at Power and Energy Holdings. The amount of IDC capitalized is reported in the Consolidated Statements of Operations as a reduction of interest charges and is included in Property, Plant and Equipment on the Consolidated Balance Sheets. Power's average rate used for calculating IDC in 2004, 2003 and 2002 was 6.81%, 7.07% and 7.01%, respectively. For the years ended December 31, 2004, 2003 and 2002, Power's IDC amounted to $111 million, $109 million and $95 million, respectively. Energy Holdings' average rate used for calculating IDC in 2004, 2003 and 2002 was 8.37%, 8.70% and 9.06%, respectively. For the years ended December 31, 2004, 2003 and 2002, Energy Holdings' IDC amounted to $4 million, $12 million and $13 million, respectively.

      **Income Taxes**

      ***PSEG, PSE&G, Power and Energy Holdings***

      PSEG and its subsidiaries file a consolidated Federal income tax return and income taxes are allocated to PSEG's subsidiaries based on the taxable income or loss of each subsidiary. Investment tax credits were deferred in prior years and are being amortized over the useful lives of the related property.

      **Foreign Currency Translation/Transactions**

      ***Energy Holdings***

      A business's functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. In accordance with SFAS No. 52, “Foreign Currency Translation,” the assets and liabilities of foreign operations

112

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

of Energy Holdings, with a functional currency  other than the U.S. Dollar, are translated into U.S. Dollars at the current  exchange rates in effect at the end of the reporting period. The translation  differences that result from this process, and gains and losses on intercompany  foreign currency transactions, which are long-term in nature and that Energy  Holdings does not intend to settle in the foreseeable future, are shown in OCI  as a separate component of member's equity. U.S. deferred taxes are not  provided on translation gains and losses where Energy Holdings expects earnings  of a foreign operation to be permanently reinvested. The revenue and expense  accounts of such foreign operations are translated into U.S. Dollars at the  average exchange rates that prevail during the period.

      Gains and losses that arise from exchange rate fluctuations on monetary assets and monetary liabilities denominated in a currency other than the functional currency are included in determining Net Income. Gains and losses relating to derivatives designated as hedges of the foreign currency exposure of a net investment in foreign operations are reported in Currency Translation Adjustment, a separate component of OCI.

      The determination of an entity's functional currency requires management's judgment. It is based on an assessment of the primary currency in which transactions in the local environment are conducted, and whether the local currency can be relied upon as a stable currency in which to conduct business. As economic and business conditions change, Energy Holdings is required to reassess the economic environment and determine the appropriate functional currency. The impact of foreign currency accounting could have a material effect on Energy Holdings' financial statements.

      **Cash and Cash Equivalents**

      ***PSEG, PSE&G, Power and Energy Holdings***

      Cash and cash equivalents consist primarily of working funds and highly liquid marketable securities (commercial paper and money market funds) with an original maturity of three months or less.

      **Materials and Supplies and Fuel**

      ***PSE&G***

      PSE&G's materials and supplies are carried at average cost consistent with the rate-making process.

      ***Power and Energy Holdings***

      Materials and supplies and fuel for Power and Energy Holdings are valued at the lower of average cost or market.

      **Property, Plant and Equipment**

      ***PSE&G***

      PSE&G's additions and replacements to property, plant and equipment that are either retirement units or property record units are capitalized at original cost. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation.

      ***Power and Energy Holdings***

      Power and Energy Holdings only capitalize costs which increase the capacity or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets' environmental safety or efficiency. All other environmental expenditures are expensed as incurred.

113

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      **Other Special Funds**

      ***PSEG, PSE&G, Power and Energy Holdings***

      Other Special Funds represents amounts deposited to fund the qualified pension plans and to fund a Rabbi Trust which was established to meet the obligations related to three non-qualified pension plans and a deferred compensation plan.

      **Nuclear Decommissioning Trust (NDT) Funds**

      ***Power***

      Prior to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143), amounts collected from PSE&G customers that had been deposited into the NDT Funds and realized and unrealized gains and losses in the trusts were recorded as changes in the NDT Funds and as offsetting changes to the nuclear decommissioning liability.

      Effective January 1, 2003, Power adopted SFAS 143, which addresses accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. In addition, the BPU issued an order that PSE&G's customers will no longer be required to fund the NDT Funds. Therefore, deferral accounting ceased to be appropriate. Beginning January 1, 2003, realized gains and losses are recorded in earnings and unrealized gains and losses are recorded as a component of OCI, as required under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS 115). See Note 2. Recent Accounting Standards and Note 3. Asset Retirement Obligations for a discussion of SFAS 143 and the impact of its adoption.

      **Investments in Corporate Joint Ventures and Partnerships**

      ***Energy Holdings***

      Generally, Global's and Resources' interests in active joint ventures and partnerships are accounted for under the equity method of accounting where their respective ownership interests are 50% or less, it is not the primary beneficiary, as defined under FIN 46, and significant influence over joint venture or partnership operating and management decisions exists. For investments in which significant influence does not exist and it is not the primary beneficiary, the cost method of accounting is applied.

      There are several investments recorded using the equity method of accounting for which there is a difference in the investment account when compared to the underlying equity in net assets. The reconciling items include amounts for capitalized interest and capitalized expenses. In the instance of capitalized interest, to the extent borrowings on the part of Global were required to fund the underlying investment of the project, and such project was under construction, the interest accrued on such borrowings was recorded in the investment account. This is a temporary difference, as amortization of the amount of interest capitalized began upon commencement of the project. In the instance of capitalized expenses, all direct external and internal costs related to project development were capitalized once a project reached certainmilestones. When the project reached financial closing, Global transferred the deferred project balance to the investment account. This is a temporary difference, as the capitalized expenses started being amortized upon commencement of the project. For additional information related to these investments, see Note 10. Long-Term Investments.

      Resources carries its partnership investments in certain venture capital and leveraged buyout funds investing in securities at fair value where market quotations and an established liquid market of underlying securities in the portfolio are available. Fair value is determined based on the review of market price and volume data in conjunction with Resources' invested liquid position in such securities. Changes in fair value are recorded in Operating Revenues in the Consolidated Statements of Operations.

114

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      **Deferred Project Costs and Development Costs**

      ***Power and Energy Holdings***

      Power and Energy Holdings capitalize all incremental and direct external and direct internal costs related to project development once a project reaches certain milestones. On Power's Consolidated Balance Sheets, deferred project costs are recorded in Construction Work in Progress. On Energy Holdings' Consolidated Balance Sheets, deferred project costs are recorded in Investments or Other Assets. These costs are amortized on a straight-line basis over the lives of the related project assets. Such amortization commences upon the date of commercial operation. Development costs related to unsuccessful projects are charged to expense. No project development commenced in 2004.

      **Stock Compensation**

      ***PSEG***

      PSEG applies Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), and related interpretations in accounting for stock-based compensation plans. Accordingly, no compensation cost has been recognized for fixed stock option grants since the exercise price of the stock options equaled the market price of the underlying stock on the date of grant. Had compensation costs for stock option grants been determined based on the fair value at the grant dates for awards under these plans in accordance with SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS 123), there would have been an additional charge to Net Income of approximately $5 million, $8 million and $10 million in 2004, 2003 and 2002, respectively, with a $(0.02), $(0.04) and $(0.05)impact on diluted earnings per share in 2004, 2003 and 2002, respectively.

      The following table illustrates the effect on Net Income and Earnings Per Share if PSEG had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation:
   **Years EndedDecember 31,**   **2004** **2003** **2002**   **(Millions, exceptShare Data)**            
Net Income, as reported
    $726     $1,160     $235             
Add: Total stock-based compensation expensed during the period, net of tax
     1      —      —             
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects
     (6)     (8)     (10)                                
Pro forma Net Income
    $721     $1,152     $225                                 
Earnings per share:
                        
Basic—as reported
    $3.06     $5.08     $1.13             
Basic—pro forma
    $3.04     $5.05     $1.08             
Diluted—as reported
    $3.05     $5.07     $1.13             
Diluted—pro forma
    $3.03     $5.03     $1.08                         
      See Note 2. Recent Accounting Standards and Note 8. Earnings Per Share for further information.

      **Basis Adjustment**

      ***PSE&G and Power***

      PSE&G and Power have recorded a Basis Adjustment on their Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, PSE&G and Power, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, approximately $986

115

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

million, net of tax, was recorded as a Basis Adjustment on PSE&G's and Power's Consolidated Balance Sheets. These amounts are eliminated on PSEG's consolidated financial statements.

      **Use of Estimates**

      ***PSEG, PSE&G, Power and Energy Holdings***

      The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may materially differ from estimated amounts.

      **Reclassifications**

      ***PSEG, PSE&G, Power and Energy Holdings***

      Certain reclassifications of amounts reported in prior periods have been made to conform with the current presentation.

**Note 2. Recent Accounting Standards**

**SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29” (SFAS 153)**

      **PSEG, PSE&G, Power and Energy Holdings**

      On December 16, 2004, the FASB issued SFAS 153 which addresses the measurement of exchanges of nonmonetary assets and redefines the scope of transactions that should be measured based on the fair value of the assets exchanged. SFAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. PSEG, PSE&G, Power and Energy Holdings do not believe the adoption of SFAS 153 will have a material effect on their respective financial statements.

**SFAS No. 151, “Inventory Costs” (SFAS 151)**

      **PSEG, PSE&G, Power and Energy Holdings**

      On November 29, 2004, the FASB issued SFAS 151 which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. SFAS 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. PSEG, PSE&G, Power and Energy Holdings do not believe the adoption of SFAS 151 will have a material effect on their respective financial statements.

**SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (SFAS 150)**

      **PSEG, PSE&G, Power and Energy Holdings**

      SFAS 150, which became effective July 1, 2003, establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. There was no impact on PSEG's, PSE&G's, Power's or Energy Holdings' respective financial statements due to the adoption of this standard.

**SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149)**

      **PSEG, PSE&G, Power and Energy Holdings**

      SFAS 149 amends and clarifies the accounting guidance for derivative instruments (including certain derivative instruments embedded in other contracts) and hedging activities that fall within the scope of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). Under this standard, any non-power commodity contracts (e.g., gas contracts) and power contracts that do not meet the definition

116

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

in SFAS 133 and SFAS 149 that are subject to unplanned netting, will be ineligible for “normal” treatment, which would result in those contracts being marked to market. SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. There was no impact on PSEG's, PSE&G's, Power's or Energy Holdings' respective financial statements due to the adoption of this standard.

**SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (SFAS 146)**

      **PSEG, PSE&G, Power and Energy Holdings**

      SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)” (EITF 94-3). The principal difference between SFAS 146 and EITF 94-3 relates to its requirements for recognition of a liability for a cost associated with an exit or disposal activity. SFAS 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF 94-3, a liability for an exit cost, as defined therein, was recognized at the date of an entity's commitment to an exit plan. A fundamentalconclusion reached by the FASB was that an entity's commitment to a plan, by itself, does not create a present obligation to others that meets the definition of a liability. Therefore, SFAS 146 eliminates the definition and requirements for recognition of exit costs in EITF 94-3. SFAS 146 also establishes that fair value is the objective for initial measurement of the liability. The adoption of SFAS 146, which was effective January 1, 2003, did not have any effect on PSEG's, PSE&G's, Power's or Energy Holdings' financial statements.

**SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143)**

      **PSEG, PSE&G, Power and Energy Holdings**

      Effective January 1, 2003, PSEG, PSE&G, Power and Energy Holdings each adopted SFAS 143. Under SFAS 143, a company must initially recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred and concurrently capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. A company is required to subsequently depreciate that asset retirement cost to expense over its useful life. In periods subsequent to the initial measurement, a company is required to recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either the timing or the amount of the originally estimated cash flows. Changes in the liability due to accretion are charged toOperation and Maintenance expense on the Consolidated Statements of Operations, whereas changes due to the timing or amount of cash flows are adjustments to the carrying amount of the related asset. See Note 3. Asset Retirement Obligations for additional information.

**SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142)**

      **PSEG, PSE&G, Power and Energy Holdings**

      On January 1, 2002, PSEG, PSE&G, Power and Energy Holdings adopted SFAS 142. Under this standard, PSEG, PSE&G, Power and Energy Holdings were required to complete an impairment analysis of goodwill. Under SFAS 142, goodwill is a nonamortizable asset subject to an annual review for impairment and an interim review when certain events or changes in circumstances occur. At the time of adoption, PSE&G had no goodwill. The effect of no longer amortizing goodwill on an annual basis was not material to PSEG's or Power's financial statements upon adoption. Power and Energy Holdings evaluated the recoverability of the recorded amount of their goodwill based on certain operating and financial factors. Such impairment testing included discounted cash flow tests, which require broad assumptions and significantjudgment to be exercised by management.

      On January 1, 2002, Energy Holdings recorded the results of its evaluation under SFAS 142. The total amount of goodwill impairments was $121 million, net of tax of $66 million.

      For additional information related to goodwill, see Note 9. Goodwill and Other Intangibles.

117

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**SFAS No. 123R, “Share-Based Payment, an amendment of SFAS No. 123 and 95” (SFAS 123R)**

      **PSEG**

      In December 2004, the FASB issued SFAS 123R. SFAS 123R is a revision of SFAS 123, and supersedes APB 25 and its related implementation guidance. SFAS 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS 123R is effective for the first interim or annual reporting period beginning after June 15, 2005 and requires entities to recognize stock compensation expense for awards of equity instruments to employees based on the grant-date fair value of those awards (with limited exceptions). PSEG is currently evaluating the two methods of adoption allowed by SFAS 123, the modified-prospective transition method and the modified-retrospective transition method and has not yet determined the impact of either method onPSEG.

**FASB Staff Position (FSP) 109-1, “Application of FASB Statement No. 109, “*****Accounting for Income Taxes*****”, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (FSP 109-1)**

      **PSEG, Power and Energy Holdings**

      On December 21, 2004, the FASB issued FSP 109-1, which was effective upon issuance, to provide guidance on the application of SFAS No. 109, “Accounting for Income Taxes” (SFAS 109), to the provision within the American Jobs Creation Act of 2004 (Jobs Act) that provides a tax deduction on qualified production activities. The Jobs Act includes a tax deduction of up to 9% (when fully phased-in) of the lesser of (a) “qualified production activities income,” as defined in the Jobs Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). The tax deduction is limited to 50% of W-2 wages paid by the taxpayer. FSP 109-1 clarifies that the manufacturer's deduction provided for under the Jobs Act should be accounted for as a specialdeduction in accordance with SFAS 109 and not as a tax rate reduction. The adoption of FSP 109-1 had no impact on PSEG, Power and Energy Holdings' respective financial statements. PSEG, Power and Energy Holdings are evaluating the effect that the manufacturer's deduction will have in subsequent years.

**FSP 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” (FSP 109-2)**

      **PSEG and Energy Holdings**

      On December 21, 2004, the FASB issued FSP 109-2, which was effective upon issuance, to provide guidance on the application of the provision in the Jobs Act that allows a special one-time dividends received deduction on the repatriation of certain foreign earnings to a U.S. taxpayer, provided certain criteria are met. The Jobs Act provides a one-year window to repatriate earnings from foreign investments and claim a special 85% dividends received tax deduction on such distributions. The FASB believes that the lack of clarification of certain provisions and the timing of the enactment necessitate a practical exception to the SFAS 109 requirement to reflect the effect of a new tax law in the period of enactment, and therefore, a company is allowed time beyond the financial reporting period of enactment to evaluatethe effect of the Jobs Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS 109.

      As of December 31,  2004, Global had approximately $256 million of undistributed earnings that could  be repatriated. The range of undistributed earnings that PSEG could consider  for possible repatriation under the Jobs Act is between $0 and $256 million,  which would result in additional income tax expense between $0 and $15 million.  On January 13, 2005, the IRS published Notice 2005-10, which discusses some  of the rules that pertain to this deduction. Whether PSEG will ultimately take  advantage of this provision, all or in part, depends upon a number of factors  including but not limited to evaluating the impact of Notice 2005-10 and any  future authoritative guidance. Global has made no change in its current intention  to indefinitely reinvest accumulated earnings of its foreign subsidiaries.

118

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**FASB Staff Position 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP 106-2)**

      **PSEG, PSE&G, Power and Energy Holdings**

      FSP 106-2 provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Drug Act) for employers who sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 also requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Drug Act. The Medicare Drug Act generally permits plan sponsors that provide retiree prescription drug benefits that are “actuarially equivalent” to the benefits of Medicare Part D to be eligible for a non-taxable federal subsidy. FSP 106-2 was effective for periods beginning after June 15, 2004. PSEG selected the prospective method of adoption of FSP 106-2. Upon adoption of FSP 106-2, the subsidy reduced the accumulatedpostretirement benefit obligation by $45 million from $929 million to $884 million on July 1, 2004 and therefore will reduce future periodic other postretirement benefits (OPEB) expense. There was no impact from adoption on PSEG's, PSE&G's, Power's or Energy Holdings' respective financial statements.

**FIN 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN 46R)**

      **PSEG, PSE&G, Power and Energy Holdings**

      FIN 46R replaces FIN 46, which was issued July 1, 2003. FIN 46R clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to certain entities in which equity investors do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support.

      FIN 46R requires the adoption of either FIN 46 or FIN 46R by the first period ended after December 15, 2003 for Special Purpose Entities (SPEs), but no later than the first period ended after March 15, 2004. Non-SPEs are required to be accounted for under the provisions of FIN 46R no later than the first period ended after March 15, 2004. PSEG, PSE&G, Power and Energy Holdings adopted the provisions of FIN 46 as of July 1, 2003.

      There was no effect on Power's financial statements due to the adoption of these rules.

      The adoption of FIN 46 required PSEG and PSE&G to deconsolidate their capital trusts and Energy Holdings to consolidate its investments in four real estate partnerships. Prior period financial statements were reclassified for comparability in accordance with FIN 46.

      **PSEG**

      PSEG's Consolidated Balance Sheets reflect its common equity investment in the capital trusts, which were previously eliminated in consolidation resulting in recording equal amounts of additional assets and liabilities of $36 million as of December 31, 2004 and 2003. The invested cash was loaned back to PSEG in connection with the issuance of the preferred securities.

119

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      The following table displays the securities, and their original issuance amounts, held by the trusts that have now been deconsolidated.
   **As ofDecember 31,**   **2004** **2003**   **(Millions)**      
**PSEG**
              
PSEG Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures
              
7.44%
    $225     $225       
Floating Rate
     150      150       
7.25%
     150      150       
8.75%
     180      180       
PSEG Participating Units
              
10.25%
     460      460                     
**Total PSEG**
    $1,165     $1,165               
      PSEG now records interest expense (previously eliminated against the interest income of the trust) instead of preferred securities dividends (since the preferred dividends are in the trusts that are no longer consolidated). For PSEG, these amounts totaled $56 million, $56 million and $40 million for the years ended December 31, 2004, 2003 and 2002, respectively.

      **PSE&G**

      In December 2003, PSE&G redeemed its trust preferred securities. The capital trusts related to the securities were deconsolidated when FIN 46 was adopted in 2003. For PSE&G, interest expense related to these trusts totaled $13 million for each of the years ended December 31, 2003 and 2002.

      In addition, PSE&G reviewed its Non-Utility Generation (NUG) contracts to determine if the entities involved were VIEs and, if so, if PSE&G was the primary beneficiary. These entities own power plants that sell their output to PSE&G, which PSE&G is contractually obligated to purchase at a variable price that correlates with certain major operating costs of the plants. As a result, PSE&G assumes some of the variability inherent in the operation of these plants.

      PSE&G attempted to obtain the information necessary to conduct the analysis of the cash flow variability required under FIN 46R from two facility owners where PSE&G held a potentially significant variable interest, as defined in FIN 46R, based on the NUG contracts. The respective facility owners did not provide the information based on their respective belief that the data was competitive and proprietary. As a result, PSE&G is unable to determine whether these entities should be consolidated under FIN 46R and applies the scope exception in FIN 46R that exempts entities that conduct exhaustive unsuccessful efforts to obtain the necessary information.

      PSE&G incurred Energy Costs related to these two specific NUG contracts of approximately $5 million, $7 million and $8 million for the years ended December 31, 2004, 2003 and 2002, respectively. PSE&G sells the electricity purchased under all of its NUG contracts at market prices in the PJM Interconnection, L.L.C. (PJM) spot market and recovers the difference between the variable contract price and market price through the NUG Market Transition Charge.

      **Energy Holdings**

      Energy Holdings evaluated its interests in four real estate partnerships previously accounted for under the equity method of accounting. These entities were determined to be VIEs and Energy Holdings was determined to be the primary beneficiary and therefore is required to consolidate these entities. The current presentation reflects these entities on a fully consolidated basis and all periods have been restated in accordance with FIN 46.

120

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      The consolidation of the real estate partnerships on the Consolidated Balance Sheets resulted in an increase of approximately $31 million in assets and liabilities. There was no material impact of consolidating the real estate partnerships on Operating Revenues and Operating Expenses.

**FIN No. 45, “Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45)**

      **PSEG, PSE&G, Power and Energy Holdings**

      FIN 45 enhances the disclosures to be made by a guarantor about its obligations under certain guarantees that it has issued in its interim and annual financial statements. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this Interpretation were applicable on a prospective basis to guarantees issued or modified after December 31, 2002. For further information regarding Power's and Energy Holdings' respective guarantees, refer to Note 14. Commitments and Contingent Liabilities.

**EITF Issue No. 04-1, “Accounting for Pre-existing Relationships Between the Parties to a Business Combination” (EITF 04-1)**

      **PSEG, PSE&G, Power and Energy Holdings**

      EITF 04-1 reaffirms that the consummation of a business combination between two parties that have a pre-existing relationship(s) are multiple element transactions. The EITF also developed a model to address the settlement of the pre-existing relationship. This consensus is effective for business combinations consummated and goodwill impairment tests performed in reporting periods beginning after October 13, 2004. The adoption of EITF 04-1 did not have an effect on PSEG's, PSE&G's, Power's or Energy Holdings' respective financial statements.

**EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations” (EITF 03-13)**

      **PSEG, PSE&G, Power and Energy Holdings**

      EITF 03-13 concluded that classification of a disposed component as a discontinued operation is appropriate only if the ongoing entity has no continuing direct cash flows (a term EITF 03-13 introduces to interpret paragraph 42(a)), and does not retain an interest, contract, or other arrangement sufficient to enable it to exert significant influence over the disposed component's operating and financial policies after the disposal transaction (an interpretation of paragraph 42(b)). EITF 03-13 should be applied to components that are disposed of or classified as held for sale in periods beginning after December 15, 2004. PSEG, PSE&G, Power and Energy Holdings do not believe that the adoption of EITF 03-13 will have a material effect on their respective financial statements.

**EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133”, “Accounting for Derivative Instruments and Hedging Activities”, and Not “Held for Trading Purposes” as Defined in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 03-11)**

      **PSEG and Power**

      The EITF has previously discussed the income statement presentation of gains and losses on contracts held for trading purposes in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). The EITF reached a consensus that gains and losses (realized and unrealized) on all derivative instruments within the scope of SFAS 133 should be shown net when recognized in the Consolidated

121

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

Statement of Operations, whether or not settled physically, if the derivative instruments are “held for trading purposes” as defined in EITF 02-3. EITF 03-11 contemplates whether realized gains and losses should be shown gross or net in the Consolidated Statement of Operations for contracts that are not held for trading purposes, but are derivatives subject to SFAS 133. On July 31, 2003, the EITF indicated that the determination of whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported on a gross or net basis is a matter of judgment. The EITF indicated that companies may base their judgment on existing authoritative guidance in gross/net presentation, such as EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal Versus Net as an Agent”(EITF 99-19). These rules, which are effective for transactions occurring after September 30, 2003, required PSEG and Power to reduce revenues and costs by approximately $228 million and $5 million for the years ended December 31, 2004 and 2003, respectively.

**EITF Issue No. 03-4, “Accounting for Cash Balance Pension Plans” (EITF 03-4)**

      **PSEG, PSE&G, Power and Energy Holdings**

      EITF 03-4 requires that cash balance pension plans be accounted for as defined benefit plans. EITF 03-4 indicates that cash balance plans are forms of accumulation plans with variable crediting formulas and are therefore not pay-related. As a result, a company would apply a traditional unit credit method for determining the expense associated with these plans. PSEG, PSE&G, Power and Energy Holdings each have previously accounted for their cash balance pension plans as defined benefit plans; thus there will be no material impact on their respective financial statements.

**EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF 03-1)**

      **PSEG, PSE&G, Power and Energy Holdings**

      EITF 03-1 further defines the meaning of an “other-than-temporary impairment” and its application to debt and equity securities. Impairment occurs when the fair value of a security is less than its cost basis. When such a condition exists, the investor is required to evaluate whether the impairment is other-than-temporary as defined in EITF 03-1. When an impairment is other-than-temporary, the unrealized loss must be charged to earnings.

      On September 30, 2004, the FASB issued FSP EITF 03-1-1, “Effective date of Paragraphs 10-20 of EITF Issue No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (FSP EITF 03-1-1). FSP EITF 03-1-1 delayed the effective date for the measurement and recognition guidance contained in EITF 03-1 until further implementation guidance is issued.

      EITF 03-1, when fully adopted, could materially impact the accounting for the investments held in Nuclear Decommissioning Trust Funds. The ultimate impact to PSEG and its subsidiaries cannot be determined until the FASB issues final guidance.

**EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3)**

      **PSEG and Power**

      EITF 02-3 requires all gains and losses on energy trading derivatives to be reported on a net basis. Also, energy trading contracts that are not derivatives under SFAS 133 will no longer be marked to market. EITF 02-3 became fully effective January 1, 2003. The majority of Power's energy trading contracts at January 1, 2003 qualified as derivatives under SFAS 133 and therefore continued to be marked to market. The implementation of these rules had no effect on PSEG's or Power's Net Income for the years ended December 31, 2004 and 2003. Prior period Operating Revenues and Energy Costs on the Consolidated Statements of Operations have been reclassified on a net basis for comparability.

122

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**EITF Issue No. 01-8, “Determining Whether an Arrangement is a Lease” (EITF 01-8)**

      **PSEG, PSE&G, Power and Energy Holdings**

      EITF 01-8 provides guidance in determining whether an arrangement should be considered a lease subject to the requirements of SFAS 13. EITF 01-8 states that the evaluation of whether an arrangement contains a lease within the scope of SFAS 13 should be based on the substance of the arrangement. EITF 01-8 is applied to arrangements agreed or committed to, modified, or acquired in business combinations initiated on or after October 1, 2003. There was no significant impact on PSEG's, PSE&G's, Power's and Energy Holdings' respective financial statements as a result of the adoption of EITF 01-8.

**Derivatives Implementation Group (DIG) Issues**

      **PSEG, PSE&G, Power and Energy Holdings**

      DIG C15, “SFAS No. 133 Implementation Issue No. C15–Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity” (DIG C15), which became effective January 1, 2004, revised the guidance for the normal purchase and normal sales (NPNS) exception for fair value accounting for power derivatives. If the revised requirements were not met and the contract did not qualify for NPNS treatment, the contract would be considered “financial” in nature and would be marked to market, resulting in a gain or loss on the Statement of Operations. However, the derivative can be used as a hedging derivative to defer gains and losses in OCI if it meets hedge accounting requirements.

      In connection with the January 2003 EITF meeting, the FASB was requested to reconsider an interpretation of SFAS 133. The interpretation, which is contained in the DIG Issue C-11 guidance, further clarified by the issuance of DIG Issue C-20, relates to the pricing of contracts that include broad market indices. In particular, that guidance discusses whether the pricing in a contract that contains broad market indices (e.g., Consumer Price Index) could qualify as a normal purchase or sale under SFAS 133. There were no significant impacts on PSEG's, PSE&G's, Power's and Energy Holdings' respective financial statements.

**Note 3. Asset Retirement Obligations**

**PSEG and Power**

      In the first quarter of 2003, Power completed a review of potential obligations under SFAS 143 and determined that its obligations were primarily related to the decommissioning of its nuclear power plants. Power's recorded liability for decommissioning as of December 31, 2002 was approximately $766 million and equaled the balance of its NDT Funds, as discussed below. As of January 1, 2003, this liability was recalculated under SFAS 143, and was determined to be approximately $261 million. Concurrently, an asset was recorded of approximately $50 million and represented the fair value of the asset retirement obligation at adoption. This asset and liability was calculated using a probability-weighted average of multiple scenarios. The scenarios were each based on estimated cash flows, which were discountedusing Power's risk-adjusted interest rate at the required effective date of the standard and considering the expected time period of the cash outflows. The scenarios included estimates for inflation, contingencies and assumptions related to the timing of decommissioning costs, using the current license lives for each unit, as well as early shutdown and license extensions scenarios.

      In addition to the $261 million nuclear decommissioning liability, Power identified certain other legal obligations that meet the criteria of SFAS 143, which are currently not quantifiable, but could be material in the future. These obligations relate to certain industrial establishments subject to the New Jersey Industrial Site Recovery Act (ISRA), underground storage tanks subject to closure requirements, permits and authorizations, the restoration of an area to be occupied by a reservoir at the end of its useful life, an obligation to retire certain plants prior to the start up of a new plant and the demolition and restoration of certain other plant sites once they are no longer in service. Because these legal obligations are not quantifiable, no amounts have been recorded.

123

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      Power also had $131 million of cost of removal liabilities recorded on its Consolidated Balance Sheet, as of December 31, 2002, which did not meet the requirements of an Asset Retirement Obligation (ARO) and were therefore reversed and included in the Cumulative Effect of a Change in Accounting Principle recorded in the first quarter of 2003.

      As a result of adopting SFAS 143, PSEG and Power recorded a Cumulative Effect of a Change in Accounting Principle of $370 million, after-tax, in the first quarter of 2003. Of this amount, $292 million (after-tax) related to decommissioning at Nuclear and $78 million (after-tax) related to the cost of removal liabilities for the fossil units that were reversed.

      The following table reflects pro forma results which include accretion and depreciation expense as if SFAS 143 had always been in effect.
   **Years EndedDecember 31,**   **2003** **2002**   **(Millions)**                  
**PSEG**
                          
Net Income—as reported
    $1,160       $235                   
Net Income—pro forma
    $790       $221                   
Earnings per share:
                          
Basic—as reported
    $5.08       $1.13                   
Basic—pro forma
    $3.46       $1.06                   
Diluted—as reported
    $5.07       $1.13                   
Diluted—pro forma
    $3.45       $1.06                   
**Power**
                          
Net Income—as reported
    $844       $468                   
Net Income—pro forma
    $474       $454                           
      The pro forma amount of the liability for Power's asset retirement obligations for the period ended December 31, 2002, as well as the actual amount of the liability recorded on Power's Consolidated Balance Sheets as of December 31, 2004 and 2003 are presented in the following table. These amounts were calculated using current information, current assumptions and current interest rates.
   **As ofDecember 31,**   **2004** **2003**   **(Millions)**                  
**PSEG and Power**
                          
Beginning of Period ARO Liability
    $284       $260                   
Accretion Expense
     26        24                                   
End of Period ARO Liability
    $310       $284                                           
**PSE&G**

      PSE&G identified certain legal obligations that meet the criteria of SFAS 143, which are currently not quantifiable and therefore are not recorded. These obligations relate to certain industrial establishments subject to the ISRA, underground storage tanks subject to closure requirements, leases and licenses and the requirement to seal natural gas pipelines when the pipelines are no longer in service.

      PSE&G had cost of removal liabilities of approximately $418 million and $395 million recorded on its Consolidated Balance Sheets as of December 31, 2004 and 2003, respectively, which did not meet the requirements of an ARO and were therefore classified as regulatory liabilities. See Note 7. Regulatory Matters for further discussion.

**Energy Holdings**

      Energy Holdings identified certain legal obligations that meet the criteria of SFAS 143. However, it determined that they are not material to its financial position, results of operations or net cash flows.

124

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NDT Funds**

      **Power**

      Prior to 2003, amounts collected from PSE&G customers through rates were deposited into the NDT Funds and realized and unrealized gains and losses in the trust were all recorded as changes in the NDT Funds with an offsetting charge to the nuclear decommissioning liability, pursuant to SFAS 71 and other related accounting guidance. Based on an order issued by the BPU, PSE&G's customers are no longer required to fund the NDT Funds, and therefore deferral accounting is no longer appropriate for changes in the fair value of securities within the NDT Funds.

      Beginning January 1, 2003, realized gains and losses were recorded in earnings and unrealized gains and losses were recorded as a component of OCI, net of tax, as required under SFAS 115. Additionally, because deferral accounting was no longer appropriate, as of January 1, 2003, Power recognized $68 million of pre-tax unrealized losses on securities in the NDT Funds, approximately $40 million of which were deemed other than temporarily impaired and recorded this amount against earnings in Cumulative Effect of a Change in an Accounting Principle in the first quarter of 2003.

      As of December 31, 2004 and 2003, the fair market value of the NDT Funds was approximately $1.1 billion and $985 million, respectively. For further information regarding the NDT Funds, refer to Note 15. Nuclear Decommissioning Trust.

**Note 4. Discontinued Operations, Dispositions and Acquisitions
**Discontinued Operations**

      **Energy Holdings**

      ***Carthage Power Company (CPC)***

      In December 2003, Global entered into a definitive purchase and sale agreement related to the sale of its majority interest in CPC, which owns and operates a power plant located in Rades, Tunisia. In May 2004, Global completed the sale of CPC for approximately $43 million in cash. The assets sold consisted primarily of accounts receivable, property, plant and equipment and other assets. The buyer also assumed certain accounts payable, accrued liabilities and debt obligations.

      In December 2003, Global recognized an estimated loss on disposal of $23 million for the initial write-down of its carrying amount of CPC to its fair value less cost to sell. During the first quarter of 2004, Energy Holdings re-evaluated the carrying value of CPC's assets and liabilities and determined that an additional write-down to fair value of $2 million was required. In May 2004, Global recognized a gain on disposal of $5 million.

      The operating results of CPC for the years ended December 31, 2004, 2003 and 2002 are summarized below:
   **Years EndedDecember 31,**   **2004** **2003** **2002**   **(Millions)**      
Operating Revenues
    $38       $95       $57       
Pre-Tax Income (Loss)
    $2       $(8)      $2       
Net Income (Loss)
    $2       $(1)      $1 
125

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
                  
      The carrying amounts of the assets and liabilities of CPC as of December 31, 2003 are summarized in the following table:
   **As ofDecember 31, 2003**   **(Millions)**                  
Current Assets
    $45                   
Noncurrent Assets
     253                           
Total Assets
    $298                           
Current Liabilities
    $161                   
Noncurrent Liabilities
     81                           
Total Liabilities
    $242                               
      ***Energy Technologies***

      In June 2002, Energy Holdings adopted a plan to sell Energy Technologies, its heating, ventilating and air conditioning (HVAC)/mechanical operating companies. The HVAC/mechanical operating companies met the criteria for classification as components of Discontinued Operations. Energy Holdings reduced the carrying value of the Energy Technologies' assets and liabilities to their fair value less costs to sell, and recorded a loss on disposal for the year ended December 31, 2002 of $20 million, net of $11 million tax benefit. During the first quarter of 2003, Energy Holdings re-evaluated the carrying value of Energy Technologies' assets and liabilities and determined that an additional write-down to fair value of $9 million, net of a $3 million tax benefit, was required. The sale of the HVAC/mechanical operatingcompanies and Energy Technologies was complete as of September 30, 2003.

      The revenues and results of operations of Energy Technologies for the periods ended December 31, 2003 and 2002 are displayed below:
   **Years EndedDecember 31,**   **2003** **2002**   **(Millions)**                  
Operating Revenues
    $68       $378                   
Pre-Tax Loss
    $(18)      $(32)                  
Net Loss
    $(11)      $(21)                          
      **Tanir Bavi Power Company Private Ltd. (Tanir Bavi)**

      In the fourth quarter of 2002, Global sold its interest in Tanir Bavi for approximately $45 million. Global reduced the carrying value of Tanir Bavi to the contracted sales price of $45 million and recorded a loss on disposal of $14 million, net of a $7 million tax benefit, for the year ended December 31, 2002. The facility met the criteria for classification as a component of discontinued operations. The operating results of Tanir Bavi for the year ended December 31, 2002 are summarized below.
   **Year EndedDecember 31, 2002**   **(Millions)**                  
Operating Revenues
    $61                   
Pre-Tax Income
    $7                   
Net Income
    $5 
126

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
                      
**Dispositions**

      **Energy Holdings**

      ***Meiya Power Company Limited (MPC)***

      On October 1, 2004, Global entered into an agreement to sell its 50% equity interest in MPC to BTU Power Company. The sale closed on December 31, 2004 for approximately $236 million, of which $100 million was paid in cash and the balance of approximately $136 million was provided in the form of a secured promissory note due on March 31, 2005. The sale resulted in an after-tax gain of approximately $2 million. In January 2005, a $38 million principal payment on the note was received.

      ***Luz del Sur S.A.A. (LDS)***

      In April 2004, Global sold a portion of its shares in LDS in the Lima stock exchange, reducing its ownership from 44% to 38% and received gross proceeds of approximately $31 million. Global realized an after-tax gain of approximately $5 million in the second quarter of 2004 related to the LDS sale. The gain is recorded in Income from Equity Method Investments on the Consolidated Statements of Operations.

      ***GWF Energy LLC (GWF Energy)***

      Prior to the fourth quarter of 2002, GWF Energy was accounted for under the equity method of accounting. Pursuant to the partnership agreement, a partner is required to have at least 75% interest in the partnership to have control. During the fourth quarter of 2002, Global increased its interest in GWF Energy to 76%, therefore acquiring control pursuant to the partnership agreement. Due to this change, Global's investment in GWF Energy was consolidated on the Consolidated Financial Statements as of December 31, 2002 and for the three months ended December 31, 2002 and for each quarterly period thereafter through September 30, 2003. Global's investment in GWF Energy decreased to 74.9% during the fourth quarter of 2003 and accordingly, GWF Energy was deconsolidated and recorded under the equity method ofaccounting as of December 31, 2003. In February 2004, Harbinger GWF LLC (Harbinger) repurchased a 14.9% ownership interest from Global for approximately $14 million, resulting in a 60% ownership interest in GWF Energy as of December 31, 2004.

      ***Resources***

      In March  2004, Resources entered into an agreement with Midwest Generation LLC, an indirect  subsidiary of Edison Mission Energy (EME), to terminate its lease investment  in the Collins generating facility in Illinois. In April 2004, Resources closed  on the termination of the lease agreement and received gross proceeds of approximately  $184 million (approximately $85 million, after-tax) that allowed it to substantially  recover its investment in this lease. Resources recorded a realized loss of  $11 million, after-tax, related to the termination of the lease.

      In January 2004, Resources terminated two lease transactions with Qantas and China Eastern resulting from the lessees exercising their respective purchase options. Resources received aggregate gross cash proceeds of approximately $45 million (approximately $9 million, after-tax), and recorded an after-tax gain of $4 million.

      In November 2003, Resources sold its interest in Chelsea Historic Properties. Resources received net cash proceeds of $9 million and recorded an after-tax gain of approximately $4 million. As a result of the sale of this lease, Resources paid income taxes of approximately $3 million.

      In November 2002, Resources terminated two lease transactions due to an uncured default under the lease financial covenants. Resources received cash proceeds of $183 million, recorded an after-tax gain of $4 million and paid income taxes of $115 million in 2003.

127

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Acquisitions**

      **Energy Holdings**

      ***Texas Independent Energy, L.P. (TIE)***

      In June 2004, Global notified TECO Energy, Inc. (TECO) of its intent to convert a fractional amount of its preferred interest in TIE and thereby gain majority control of TIE.

      In July 2004, Global signed an agreement to acquire all of TECO's 50% equity interest in TIE for less than $1 million, which was included in cash flows used in investing activities. With this purchase, Global now owns 100% of TIE and consolidated this investment effective July 1, 2004. As a result, Energy Holdings presents approximately $630 million of Property, Plant and Equipment, $72 million of Other Assets, $461 million of Long-Term Non-Recourse Debt, and $27 million of Other Liabilities related to TIE in its Condensed Consolidated Balance Sheet as of the effective acquisition date.

      The following (unaudited) pro forma consolidated results of operations of Energy Holdings have been prepared as if the acquisition of TIE had occurred at the beginning of 2002:
   **Pro Forma**   **For the Years EndedDecember 31,**   **2004** **2003** **2002**   **(Millions)**      
Operating Revenues
    $1,287     $1,178     $886       
Income (Loss) Before Discontinued Operations and CumulativeEffect of a Change in Accounting Principle
    $137     $177     $(233)      
Net Income (Loss)
    $142     $133     $(403)                  
      The pro forma information is presented for informational purposes only and is not necessarily indicative of the results of operations that actually would have been achieved had the acquisition been consummated as of that time, nor is it intended to be a projection of future results.

      ***Electrowina Skawina S.A. (Skawina)***

      In 2002, Global acquired a controlling interest in the electric and thermal coal-fired Skawina plant in Poland. In accordance with the purchase agreement, Global acquired an additional 12% from Skawina's employees in 2004, increasing its ownership interest to approximately 75%. The transaction required an additional investment of approximately $8 million and closed in the third quarter of 2004.

**Power**

      In 2002, Power purchased Wisvest Connecticut LLC, which owned the Bridgeport Harbor Station (BHS), the New Haven Harbor Station (NHHS) and the related assets and liabilities, from Wisvest Corporation (Wisvest), a subsidiary of Wisconsin Energy Corporation. Wisvest Connecticut LLC was subsequently renamed PSEG Power Connecticut LLC (Power Connecticut).

      The aggregate purchase price was approximately $271 million, which was included in cash flows used in investing activities. As a result, PSEG and Power consolidated approximately $235 million of Property, Plant and Equipment, $47 million of Intangible Assets, $25 million of Current Assets, and $36 million of Liabilities in 2002.

**Note 5. Extraordinary Item
**PSE&G**

      In May 2002, PSE&G filed an Electric Base Rate Case with the BPU requesting an annual $250 million increase for its electric distribution business. In July 2003, PSE&G received an oral decision from the BPU approving a proposed settlement with certain modifications. The related Final Order was received on April 22, 2004. As a result of the oral decision and subsequent summary written order, in the second quarter of 2003, PSE&G recorded certain adjustments in connection with the resolution of various issues relating to the Final Order PSE&G received from the BPU in 1999 relating to PSE&G's rate unbundling, stranded costs and restructuring proceedings. These amounts included a $30 million pre-tax refund to customers related to

128

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

revenues previously collected in rates for nuclear decommissioning. Because this amount reflected the final accounting for PSEG's generation-related business pursuant to the four-year transition plan mandated by the Final Order, the adjustment was recorded as an $18 million, after-tax, Extraordinary Item as required under APB Opinion No. 30, “Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions” (APB 30) and SFAS No. 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement No. 71.”

**Note 6. Asset Impairments
**Energy Holdings**

      In January 2002, the Argentine Federal government enacted a temporary emergency law that imposed various changes to the concession contracts in effect between electric distributors and local and federal regulators. The Argentine government and regulators made unilateral decisions to abrogate key components of the tariff concessions related to public utilities. Such laws significantly restricted Global's ability to control the operations of its projects in Argentina and to manage its operations to reduce the financial losses incurred as a result of such actions.

      Based on actual and projected operating losses and the continued economic uncertainty in Argentina, Energy Holdings determined that it was necessary to test these assets for impairment. Such impairment analyses were completed as of June 30, 2002. As a result of these analyses, Energy Holdings determined that these assets were completely impaired.

      The combination of the operating losses, goodwill impairments and write-down of $497 million for all Argentine assets for the year ended December 31, 2002, combined with certain loss contingencies resulted in a pre-tax charge to earnings of $621 million ($404 million after-tax). In connection with the write-down of Energy Holdings' Argentine assets, Energy Holdings recorded a net deferred tax asset of $217 million. Energy Holdings has reviewed this deferred tax asset for recoverability and has determined that no valuation allowance is required.

      The remaining $27 million of the $217 million deferred tax asset will expire in 2007. PSEG expects to fully realize this deferred tax asset.

**Note 7. Regulatory Matters
**Regulatory Assets and Liabilities**

      **PSE&G**

      PSE&G prepares its financial statements in accordance with the provisions of SFAS 71. A regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs, which will be amortized over various future periods. These costs are deferred based on rate orders issued by the BPU or the FERC or PSE&G's experience with prior rate cases. As of December 31, 2004 and 2003, approximately 89% and 88%, respectively, of PSE&G's regulatory assets were deferred based on written rate orders. Regulatory assets recorded on a basis other than by an issued rate orderhave less certainty of recovery since they can be disallowed in the future by regulatory authorities. PSE&G believes that all of its regulatory assets are probable of recovery. To the extent that collection of any regulatory assets or payments of regulatory liabilities is no longer probable, the amounts would be charged or credited to income.

129

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      PSE&G had the following regulatory assets and liabilities on the Consolidated Balance Sheets:
  **As ofDecember 31,**    **2004** **2003**    **Recovery/Refund Period**  **(Millions)**  
**Regulatory Assets**
          
Securitized Stranded Costs
    $3,427      $3,661     Through December 2015(1)(2)
Deferred Income Taxes
     366       369     Various
Other Postretirement Benefit (OPEB)-Related Costs
     154       174     Through December 2012(2)
Societal Benefits Charges (SBC)
     430       —     Through December 2005(1)(2)
Manufactured Gas Plant Remediation Costs
     356       123     Various(2)
Unamortized Loss on Reacquired Debt
     97       79     Over remaining debt life(1)
Underrecovered Gas Costs
     —       53     Through September 2004(1)(2)
Non-Utility Transition Charge (NTC)
     102       112     Through December 2005(1)(2)
Unrealized Losses on Interest Rate Swap
     34       51     Through December 2015(2)
Repair        Allowance 
     76       82     Through August 2013(1)(2)
Decontamination and Decommissioning Costs
     11       16     Through December 2007(2)
Asbestos Abatement Costs
     11       12     Through 2020(2)
Plant and Regulatory Study Costs
     21       22     Through December 2021(2)
Regulatory Restructuring Costs
     38       42     Through August 2013(1)(2)
Other
     5       4     To be determined(1)                
Total Regulatory Assets
    $5,128      $4,800                   
**Regulatory Liabilities**
          
Cost of Removal
    $418      $395     Various
Excess Depreciation Reserve
     60       127     Through December 2005(2)
Overrecovered Gas Costs
     17       —     Through December 2005(1)(2)
SBC
     —       19     Through December 2005(1)(2)
Other
     22       10     Various(1)                
Total Regulatory Liabilities
    $517      $551                             
   (1)   Recovered/Refunded with interest.   (2)   Recoverable/Refundable per specific rate order.

      All regulatory assets and liabilities are excluded from PSE&G's rate base unless otherwise noted. The descriptions below define certain regulatory items.

**Securitized Stranded Costs:**This reflects deferred costs, which are being recovered through the securitization transition charge authorized by the BPU. Funds collected through the securitization transition charge are remitted to Transition Funding and are solely used for interest and principal payments on the transition bonds, and the related costs and taxes.

**Deferred Income Taxes:**This amount represents the portion of deferred income taxes that will be recovered through future rates, based upon established regulatory practices, which permit the recovery of current taxes. Accordingly, this regulatory asset is offset by a deferred tax liability and is expected to be recovered, without interest, over the period the underlying book-tax timing differences reverse and become current taxes.

**OPEB-Related Costs:**Includes costs associated with the adoption of SFAS No. 106 “Employers' Accounting for Benefits Other Than Pensions” which were deferred in accordance with EITF Issue No. 92-12, “Accounting for OPEB Costs by Rate Regulated Enterprises.”

**SBC:**The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act (EDECA), includes costs related to PSE&G's electric and gas business as follows: 1) the universal service fund; 2) amortization of previous overrecovery of nuclear plant decommissioning; 3) Demand Side Management (DSM) programs; 4) social programs which include bad debt expense; 5) consumer education;

130

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

6) the New Jersey Clean Energy Program costs payable in 2005 through 2008, recorded at discounted present value; 7) amortization of the market transition charge (MTC) overrecovery; and 8) the Remediation Adjustment Clause for incurred Manufactured Gas Plants (MGP) remediation expenditures. All components except for MTC and Clean Energy accrue interest.

**MGP Remediation Costs:**Represents the low end of the range for the remaining environmental investigation and remediation program costs that are probable of recovery in future rates.

**Unamortized Loss on Reacquired Debt:**Represents losses on reacquired long-term debt, which are recovered through rates over the remaining life of the debt or the life of the refinanced debt.

**Overrecovered/Underrecovered Gas Costs:**Represents PSE&G's gas costs in excess or shortfall of the amount included in rates and probable of recovery or refund in the future.

**NTC:**This clause was established by the EDECA to account for above market costs related to NUG contracts, as approved by the BPU. Costs or benefits associated with the restructuring of these contracts are deferred. This clause also includes Basic Generation Service (BGS) costs in excess of current rates, as approved by the BPU.

**Unrealized Losses on Interest Rate Swap:**This represents the costs related to Transition Funding's interest rate swap that are being recovered without interest over the life of Transition Funding's transition bonds. This asset is offset by a derivative liability on the balance sheet.

**Repair Allowance:**This  represents tax, interest and carrying charges relating to disallowed tax deductions  for repair allowance as authorized by the BPU with recovery over 10 years  effective August 1, 2003.

**Decontamination and Decommissioning Costs:**These costs are related to PSE&G's portion of the obligation for nuclear decontamination and decommissioning costs of U.S. Department of Energy nuclear sites prior to the generation asset transfer to Power in 2000.

**Asbestos Abatement Program:**Represents costs incurred to remove and dispose of asbestos insulation at PSE&G's fossil generating stations. Per a BPU order dated December 9, 1992, these costs are treated as Cost of Removal for ratemaking purposes.

**Plant and Regulatory Study Costs:**These are costs incurred by PSE&G and required by the BPU which are related to current and future operations, including safety, planning, management and construction.

**Regulatory Restructuring Costs:**These are costs related to the restructuring of the energy industry in New Jersey through EDECA and include such items as the system design work necessary to transition PSE&G to a transmission and distribution only company, as well as costs incurred to transfer and establish the generation function as a separate corporate entity with recovery over 10 years beginning August 1, 2003.

**Other Regulatory Assets:**This includes deferred consolidated billing start-up and deferred Energy Information Control Network program costs. Both items were deferred based on BPU orders and the recovery period will be determined in future proceedings.

**Cost of Removal:**PSE&G accrues and collects for Cost of Removal in rates. Pursuant to the adoption of SFAS 143, the liability for Cost of Removal was reclassified as a regulatory liability. This liability is reduced as removal costs are incurred. Cost of removal is a reduction to the rate base.

**Excess Depreciation Reserve:**As required by the BPU in 1999, PSE&G reduced its depreciation reserve for its electric distribution assets and recorded such amount as a regulatory liability. The original liability was fully amortized in July 2003. In June 2003, PSE&G recorded an additional $155 million liability as a result of the BPU order in PSE&G's Electric Base Rate Case. This $155 million is being amortized from August 1, 2003 through December 31, 2005.

**Other Regulatory Liabilities:**This includes the following: 1) a retail adder included in the BGS charges beginning on August 1, 2003. The BPU will determine the disposition of this amount in a future proceeding; 2) Gas Margin Adjustment Cost to be returned to customers in the future; and 3) amounts collected from customers in order for Transition Funding to obtain a AAA rating on its transition bonds.

131

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Note 8. Earnings Per Share (EPS)
**PSEG**

      Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding under PSEG's stock option plans, upon payment of performance units and upon conversion of Participating Units. The following table shows the effect of these stock options, performance units and Participating Units on the weighted average number of shares outstanding used in calculating diluted EPS:
  **Years Ended December 31,**  **2004** **2003** **2002**  **Basic** **Diluted** **Basic** **Diluted** **Basic** **Diluted**                        
**EPS Numerator:**
                        
**Earnings (Millions)**
                        
Continuing Operations
      $721       $721       $852       $852       $405       $405 
Discontinued Operations
       5        5        (44)       (44)       (49)       (49)
Extraordinary Item
       —        —        (18)       (18)       —        — 
Cumulative Effect of a Change in Accounting Principle
       —        —        370        370        (121)       (121)                                                 
**Net Income**
      $726       $726       $1,160       $1,160       $235       $235                                                  
**EPS Denominator (Thousands):**
                        
Weighted Average Common Shares Outstanding
       236,984        236,984        228,222        228,222        208,647        208,647 
Effect of Stock Options
       —        464        —        602        —        166 
Effect of Stock PerformanceUnits
       —        36        —        —        —        — 
Effect of Participating Units
              —             802               —               —               —               —                                                  
**Total Shares**
       236,984        238,286        228,222        228,824        208,647        208,813                                                  
**EPS:**
                        
Continuing Operations
      $3.04       $3.03       $3.73       $3.72       $1.94       $1.94 
Discontinued Operations
       0.02        0.02        (0.19)       (0.19)       (0.23)       (0.23)
Extraordinary Item
       —        —        (0.08)       (0.08)       —        — 
Cumulative Effect of a Change in Accounting Principle
       —        —        1.62        1.62        (0.58)       (0.58)                                                 
**Net Income**
      $3.06       $3.05       $5.08       $5.07       $1.13       $1.13                                                                          
      There were approximately 2.9 million, 5.3 million and 6.3 million stock options excluded from the weighted average common shares calculation used for diluted EPS due to their antidilutive effect for the years ended December 31, 2004, 2003 and 2002, respectively.

      There were approximately 9.2 million Participating Units excluded from the weighted average common shares calculation used for diluted EPS due to their antidilutive effect for the years ended December 31, 2003 and 2002.

      Dividend payments on common stock for the year ended December 31, 2004 were $2.20 per share and totaled approximately $522 million. Dividend payments on common stock for the year ended December 31, 2003 were $2.16 per share and totaled approximately $493 million. Dividend payments on common stock for the year ended December 31, 2002 were $2.16 per share and totaled approximately $456 million.

**Note 9. Goodwill and Other Intangibles
      **PSEG, Power and Energy Holdings**

      PSEG, Power and Energy Holdings conducted an annual review for goodwill impairment as of November 30, 2004 and concluded that goodwill was not impaired.

132

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      **Power and Energy Holdings**

      As of December 31, 2004 and 2003, Power's and Energy Holdings' goodwill and pro-rata share of goodwill in equity method investments were as follows:
   **As of December 31,**   **2004** **2003**   **(Millions)**      
**Consolidated Investments**
              
Energy Holdings—Global
              
Sociedad Austral de Electricidad S.A. (SAESA)(A)
    $373     $350       
Electroandes        S.A. (Electroandes)
     133      133       
Elektrocieplownia Chorzow Sp. Z o.o. (ELCHO)
     8      8                     
Total Energy Holdings—Global
     514      491       
Power—Albany Steam Station (Albany Station)
     16      16                     
Total PSEG Consolidated Goodwill
     530      507                     
**Pro-Rata Share of Equity Method Investments**
              
Energy Holdings—Global
              
Rio Grande Energia S.A. (RGE)(A)
     81      73       
Chilquinta Energia S.A. (Chilquinta)(A)
     178      163       
LDS(B)
     55      63       
Kalaeloa Partners L.P. (Kalaeloa)
     25      25                     
Pro-Rata Share of Equity Investment Goodwill
     339      324                     
Total PSEG Goodwill
    $869     $831                             
   (A)   Changes relate to changes in foreign exchange rates.   (B)   Changes primarily relate to a sale of a portion of Global's interest in LDS in April 2004. See Note 4. Discontinued Operations, Dispositions and Acquisitions.
      **PSEG, PSE&G, Power and Energy Holdings**

      In addition to goodwill, as of December 31, 2004 and 2003, PSEG, PSE&G, Power, Energy Holdings and Services had the following recorded intangible assets:
  **PSE&G** **Power** **EnergyHoldings** **Services** **ConsolidatedTotal**  **(Millions)**
**As of December 31, 2004:**
                    
Defined Benefit Pension Plan(A)
    $2     $3     $3     $4     $12 
Emissions Allowances(B)
     —      40      —      —      40 
Various Access Rights(A)
     —      40      —      —      40 
Transmission Credits(C)
     —      21      —      —      21                                
Total Intangibles
    $2     $104     $3     $4     $113                                
**As of December 31, 2003:**
                    
Defined Benefit Pension Plan(A)
    $2     $3     $4     $5     $14 
Emissions Allowances(B)
     —      49      —      —      49 
Various Access Rights(A)
     —      40      —      —      40 
Transmission Credits(C)
     —      14      —      —      14 
Other(C)
     —      —      1      —      1                                
Total Intangibles
    $2     $106     $5     $5     $118                                                    
**   (A)   Not subject to amortization.
*(footnotes continued on next page)*

133

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

*(footnotes continued from previous page)*
   (B)   Expensed when used or sold amounting to approximately $7 million, $17 million and $3 million for the years ended December 31, 2004, 2003 and 2002, respectively.   (C)   Amortized on a straight-line basis.
**Note 10. Long-Term Investments**

**PSEG, PSE&G, Power and Energy Holdings**

      PSEG, PSE&G, Power and Energy Holdings had the following Long-Term Investments as of December 31, 2004 and 2003:
   **As of December 31,**   **2004** **2003**   **(Millions)**      
**Energy Holdings:**
              
Leveraged Leases
    $2,851     $2,981       
Partnerships:
              
General Partnerships
     13      25       
Limited Partnerships
     206      506                     
Total Partnerships
     219      531                     
Corporate Joint Ventures
     894      1,041       
Securities
     3      5       
Other Investments(A)
     15      27                     
**Total Long-Term Investments of Energy Holdings**
     3,982      4,585       
**PSE&G(B)**
     138      131       
**Power(C)**
     11      43       
**Other Investments(D)**
     50      51                     
**Total Long-Term Investments**
    $4,181     $4,810                             
   (A)   Primarily relates to DSM investments at Resources.   (B)   Primarily relates to life insurance and supplemental benefits of $130 million and $123 million as of December 31, 2004 and 2003, respectively.   (C)   Amounts represent sulfur dioxide (SO2) and nitrogen oxide (NOx) emission credits held for trading purposes.   (D)   Amounts represent investments at PSEG (parent company), primarily related to investments in its Capital Trusts.
134

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Energy Holdings**

      **Leveraged Leases**

      Energy Holdings' net investment, through Resources, in leveraged leases was comprised of the following elements:
   **As of December 31,**   **2004** **2003**   **(Millions)**      
Lease rents receivable (net of non-recourse debt)
    $3,094     $3,373       
Estimated residual value of leased assets
     1,278      1,405                          4,372      4,778       
Unearned and deferred income
     (1,521)     (1,797)                    
Total investments in leveraged leases
     2,851      2,981       
Deferred tax liabilities
     (1,623)     (1,563)                    
Net investment in leveraged leases
    $1,228     $1,418                             
      Resources' pre-tax income and income tax effects related to investments in leveraged leases were as follows:
   **Years EndedDecember 31,**   **2004** **2003** **2002**   **(Millions)**      
Pre-tax income of leveraged leases
    $153     $206     $251                           
Income tax effect on pre-tax income of leveraged leases
    $12     $74     $92       
Amortization of investment tax credits of leveraged leases
    $(1)    $(1)    $(1)                  
      Of the $53 million decrease in pre-tax leveraged lease income in 2004 as compared to 2003, $31 million was due to a lower economic lease yield, computed for certain leases, resulting from changes in certain lease forecast assumptions pertaining to state income taxes. A change in a key assumption which effects the estimated total net income over the life of a leveraged lease requires a recalculation of the leveraged lease, from inception, using the revised information. Any change in the net investment in the leveraged leases is recognized as a gain or loss in the year the assumption is changed. The remaining $22 million decrease in pre-tax leveraged lease income was primarily due to a realized loss and a reduction in leveraged lease income related to the termination of the Collins lease with Midwest Generation LLC in April2004.

      Of the $45 million decrease in pre-tax leveraged lease income in 2003 as compared to 2002, $29 million resulted from a gain recognized in 2002 due to a recalculation of certain leveraged leases. The change in assumption that occurred was related to a change in New Jersey tax rates due to the restructuring of Resources from a corporation to a limited liability company in 2002. This change allowed Resources to more efficiently match state tax expenses of an affiliate company with the state tax benefits associated with its lease portfolio. The remaining $16 million decrease in pre-tax leveraged lease income was due to the termination of two leveraged leases in November 2002.

      **Partnership Investments and Corporate Joint Ventures**

      Energy Holdings' partnership investments of $219 million and $531 million as of December 31, 2004 and 2003, respectively, and corporate joint ventures of approximately $894 million and $1 billion as of December 31, 2004 and 2003, respectively, are those of Resources, Global and EGDC. These investments are accounted for under the equity method of accounting.

      Resources also has limited partnership investments in two leveraged buyout funds, a collateralized bond obligation structure, a clean air facility and solar electric generating systems. Resources' total investment in limited partnerships was $41 million and $94 million as of December 31, 2004 and 2003, respectively.

135

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      The leveraged buyout funds mentioned above hold publicly-traded securities as of December 31, 2004. The book value of the investment in the leveraged buyout funds was $27 million and $75 million as of December 31, 2004 and 2003, respectively.

      Resources applies fair value accounting to investments within the funds where publicly-traded market prices are available. Approximately $27 million and $26 million represent the fair value of Resources' share of the publicly traded securities in the funds as of December 31, 2004 and 2003, respectively. For a discussion of other than temporary impairments of securities of privately held interests in certain companies held within certain leveraged buyout funds at Resources, see Note 13. Risk Management.

      **Investments in and Advances to Affiliates**

      Investments  in net assets of affiliated companies accounted for under the equity method  of accounting by Global amounted to $1 billion and $1.5 billion as of December 31,  2004 and 2003, respectively. During the three years ended December 31,  2004, 2003 and 2002, the amount of dividends from these investments was $89 million,  $130 million and $64 million, respectively. Global's share of  income and cash flow distribution percentages ranged from 25% to 60% as of December  31, 2004. Interest is earned on loans made to various projects. Such loans earn  interest that ranged from 6% to 12% during 2004.

      As of December  31, 2004, Global's recorded investment in equity method subsidiaries was  approximately $1 billion as compared to approximately $770 million of underlying  equity in net assets of such investments. The difference primarily relates to  an approximate $160 million investment in a foreign subsidiary which is  classified as an equity investment on Global's financial statements and  recorded as a loan on the equity method subsidiary. Investment classification  is appropriate due to its long-term investment nature. The difference is also  related to a $65 million Euro-denominated receivable from a foreign subsidiary  included in Global's investment in equity method subsidiaries.

      Global had the following equity method investments as of December 31, 2004:
                **Name** **Location** **%Owned**                
Kalaeloa
     HI      50%                
GWF
                        
Bay Area I
     CA      50%                
Bay Area II
     CA      50%                
Bay Area III
     CA      50%                
Bay Area IV
     CA      50%                
Bay Area V
     CA      50%                
Hanford L.P.
     CA      50%                
Tracy
     CA      35%                
GWF Energy
                        
Hanford-Peaker Plant
     CA      60%                
Henrietta-Peaker Plant
     CA      60%                
Tracy-Peaker Plant
     CA      60%                
Bridgewater
     NH      40%                
Conemaugh
     PA      50%                
Prisma 2000 S.p.A. (Prisma)
                        
Crotone
     Italy      25%                
Bando D'Argenta I
     Italy      50%                
Strongoli
     Italy      25%                
Turboven
                        
Maracay
     Venezuela      50%                
Cagua
     Venezuela      50%                
RGE
     Brazil      32%                
Chilquinta
     Chile      50%                
LDS
     Peru      38%
136

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
                        
      Summarized results of operations and financial position of affiliates in which Global applied the equity method of accounting are presented below:
  **Foreign** **Domestic** **Total**  **(Millions)**
**December 31, 2004**
            
*Statement of Operations Information*
            
Revenue
    $1,397     $537     $1,934 
Gross Profit
    $510     $130     $640 
Minority Interest
    $7     $—     $7 
Net Income
    $148     $46     $194 
*Balance Sheet Information*
            
Assets:
            
Current Assets
    $419     $89     $508 
Property, Plant and Equipment
     1,612      627      2,239 
Goodwill
     716      50      766 
Other Noncurrent Assets
     240      34      274                    
Total Assets
    $2,987     $800     $3,787                    
Liabilities:
            
Current Liabilities
    $374     $78     $452 
Debt*
     1,024      293      1,317 
Other Noncurrent Liabilities
     188      43      231 
Minority Interest
     65      —      65                    
Total Liabilities
     1,651      414      2,065 
Equity
     1,336      386      1,722                    
Total Liabilities and Equity
    $2,987     $800     $3,787                    
**December 31, 2003**
            
*Statement of Operations Information*
            
Revenue
    $1,042     $747     $1,789 
Gross Profit
    $415     $231     $646 
Minority Interest
    $(5)    $—     $(5)
Net Income
    $138     $67     $205 
*Balance Sheet Information*
            
Assets:
            
Current Assets
    $562     $168     $730 
Property, Plant and Equipment
     1,853      1,465      3,318 
Goodwill
     681      50      731 
Other Noncurrent Assets
     473      35      508                    
Total Assets
    $3,569     $1,718     $5,287                    
Liabilities:
            
Current Liabilities
    $579     $154     $733 
Debt*
     1,075      785      1,860 
Other Noncurrent Liabilities
     217      124      341 
Minority Interest
     80      —      80                    
Total Liabilities
     1,951      1,063      3,014 
Equity
     1,618      655      2,273                    
Total Liabilities and Equity
    $3,569     $1,718     $5,287                    
**December 31, 2002**
            
*Statement of Operations Information*
            
Revenue
    $1,022     $516     $1,538 
Gross Profit
    $413     $166     $579 
Minority Interest
    $(10)    $—     $(10)
Net Income
    $45     $20     $65             

* Debt is non-recourse to PSEG, Energy Holdings and Global.

137

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      The differences in the results of operations and the financial position as of and for the year ended December 31, 2004, as compared to the same period in 2003, was due to: (1) the sale of a portion of its shares in LDS reducing its ownership from 44% to 38% in April 2004; (2) the acquisition of all of TECO's interests in TIE, bringing Global's ownership interest to 100% and therefore consolidating the entity as of July 1, 2004; (3) the sale of its 50% equity interest in MPC in December 2004; and (4) the change in accounting for Global's investment is PPN Power Generating Company Limited (PPN) from the equity method of accounting to the cost method in June 2004. See Note 4. Discontinued Operations, Dispositions and Acquisitions.

      Global    also has investments in certain companies in which it does not have the ability    to exercise  significant influence. Such investments are accounted for under the cost method.    As of December 31, 2004 and 2003, the carrying value of these investments    aggregated  $46 million and $7 million, respectively. The primary reason for the increase    in 2004 as compared to 2003 is the change in accounting for Global's investment    in PPN to the cost method in June 2004. Global did not test these investments    for impairment in 2004 since there were no identified events or changes in    circumstances  that would have an adverse effect on the fair value of these investments.

**Note 11. Schedule of Consolidated Capital Stock and Other Securities**

**PSEG and PSE&G**
          **Book ValueAs ofDecember 31**  **OutstandingSharesAs ofDecember 31,2004** **CurrentRedemptionPricePer Share** **2004** **2003**          **(Millions)**                
PSEG Common Stock (no par value)(A)
                
Authorized 500,000,000 shares; (outstanding as ofDecember 31, 2003, 236,133,442 shares)
     238,099,067         $3,591     $3,509                     
PSE&G Cumulative Preferred Stock(B) withoutMandatory Redemption(C) $100 par value series
                
4.08%
     146,221     $103.00     $15     $15 
4.18%
     116,958     $103.00      12      12 
4.30%
     149,478     $102.75      15      15 
5.05%
     104,002     $103.00      10      10 
5.28%
     117,864     $103.00      12      12 
6.92%
     160,711      —      16      16                       
Total Preferred Stock without Mandatory Redemption
     795,234         $80     $80                                       
   (A)   In October 2003, PSEG issued approximately 8.8 million shares of its common stock for $356 million. In November 2002, PSEG issued 17.3 million shares of common stock for approximately $458 million, with net proceeds of $443 million. In addition, in 2002, PSEG began issuing new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) and the Employee Stock Purchase Plan (ESPP), rather than purchasing them on the open market. For the years ended December 31, 2004, 2003 and 2002, PSEG issued approximately 1.9 million, 2.1 million and 2.2 million shares, respectively, for approximately $83 million, $85 million and $78 million, respectively, under these plans. Total authorized and unissued shares of common stock available for issuance through PSEG's DRASPP, ESPP and various employee benefit plans amounted to approximately 3.2million shares as of December 31, 2004.   (B)   As of December 31, 2004, there was an aggregate of approximately 6.7 million shares of $100 par value and 10 million shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption. If dividends upon any shares of Preferred Stock are in arrears for four consecutive quarters, holders receive voting rights for the election of a majority of PSE&G's Board of Directors and continue until all accumulated and unpaid dividends thereon have been paid, whereupon all such voting rights cease. There are no arrearages in cumulative preferred stock and hence currently no voting rights for preferred shares. No preferred stock agreement contains any liquidation preferences in excess of par values or any “deemed” liquidation events.   (C)   As of December 31, 2004 and 2003, the annual dividend requirement and the embedded dividend rate for PSE&G's Preferred Stock without mandatory redemption was approximately $4 million and 5.03%, respectively, for each year.
138

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Fair Value of Preferred Securities**

      The estimated fair value of PSE&G's Cumulative Preferred Stock was $73 million and $70 million as of December 31, 2004 and 2003, respectively. The estimated fair value was determined using market quotations.

**Note 12. Schedule of Consolidated Debt
**Long-Term Debt**
    **As of December 31,**     **Maturity** **2004** **2003**    **(Millions)**
**PSEG**
          
Senior Note—6.89%
    2005–2009    $245     $245 
Senior Note—4.66%(C)
    2009     200      — 
Debt Supporting Trust Preferred Securities(A)
    2007–2047     1,201      1,201 
Other
       8      16               
Principal Amount Outstanding
       1,654      1,462 
Amounts Due Within One Year(B)
       (49)     —               
Total Long-Term Debt of PSEG (Parent)
      $1,605     $1,462               
**PSE&G**
          
First and Refunding Mortgage Bonds:
          
6.50%(G)
    2004    $—     $286 
9.125%
    2005     125      125 
6.75%
    2006     147      147 
LIBOR plus 0.125%(E)(N)
    2006     175      — 
6.25%
    2007     113      113 
7.375%(E)
    2014     —      159 
6.75%
    2016     171      171 
6.45%
    2019     5      5 
9.25%
    2021     134      134 
6.38%
    2023     157      157 
7.00%(D)
    2024     —      254 
5.20%
    2025     23      23 
1.10% Auction Rate(N)
    2028     64      64 
6.55%(F)
    2029     —      93 
1.38% Auction Rate(F)(N)
    2029     93      — 
6.20%(F)
    2030     —      88 
1.38% Auction Rate(F)(N)
    2030     88      — 
6.25%(F)
    2031     —      104 
1.40% Auction Rate(F)(N)
    2031     104      — 
5.45%
    2032     50      50 
6.40%
    2032     100      100 
1.14% Auction Rate(N)
    2033     50      50 
1.10% Auction Rate(N)
    2033     50      50 
1.15% Auction Rate(N)
    2033     45      45 
8.00%
    2037     7      7 
5.00%
    2037     8      8 
Medium-Term Notes:
          
4.00%
    2008     250      250 
8.16%
    2009     16      16 
8.10%
    2009     44      44 
5.125%
    2012     300      300 
5.00%
    2013     150      150 
5.375%
    2013     300      300 
5.00%(D)
    2014     250      — 
7.04%
    2020     9      9 
7.18%
    2023     5      5 
7.15%
    2023     34      34               
Principal Amount Outstanding
       3,067      3,341 
Amounts Due Within One Year(B)
       (125)     (286)
Net Unamortized Discount
       (4)     (11)              
Total Long-Term Debt of PSE&G (Parent)
      $2,938     $3,044               *(table continued on next page)*
139

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

*(table continued from previous page)*
    **As of December 31,**     **Maturity** **2004** **2003**    **(Millions)**
**Transition Funding (PSE&G)**
          
Securitization Bonds:
          
5.74%(M)
    2007    $34     $171 
5.98%
    2008     183      183 
6.29%
    2011     496      496 
6.45%
    2013     328      328 
6.61%
    2015     454      454 
6.75%
    2016     220      220 
6.89%
    2017     370      370               
Principal Amount Outstanding
       2,085      2,222 
Amounts Due Within One Year(B)
       (146)     (137)              
Total Securitization Debt of Transition Funding
      $1,939     $2,085               
Total Long-Term Debt of PSE&G
      $4,877     $5,129               
**Power**
          
Senior Notes:
          
6.875%
    2006    $500     $500 
3.75%(H)
    2009     250      — 
7.75%
    2011     800      800 
6.95%
    2012     600      600 
5.00%(H)
    2014     250      — 
5.50%
    2015     300      300 
8.625%
    2031     500      500               
Total Senior Notes
      $3,200     $2,700 
Pollution Control Notes:
          
5.00%
    2012    $66     $66 
5.50%
    2020     14      14 
5.85%
    2027     19      19 
5.75%
    2031     25      25               
Total Pollution Control Notes
      $124     $124 
Net Unamortized Discount
       (8)     (8)              
Total Long-Term Debt of Power (Parent)
      $3,316     $2,816 
Non-Recourse Debt:
          
Variable (3.00% to 5.00%)(H)
    2005    $—     $800               
Total Long-Term Debt of Power
      $3,316     $3,616               
**Energy Holdings (Parent)**
          
Senior Notes:
          
9.125%(I)
    2004    $—     $267 
7.75%(J)
    2007     309      350 
8.625%
    2008     507      507 
10.00%
    2009     400      400 
8.50%
    2011     544      544               
Principal Amount Outstanding
       1,760      2,068 
Amounts Due Within One Year(B)
       —      (267)
Net Unamortized Discount and Senior Note Rate Swap
       (4)     (1)              
Total Long-Term Debt of Energy Holdings (Parent)
      $1,756     $1,800               *(table continued on next page)*
140

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

*(table continued from previous page)*
    **As of December 31,**     **Maturity** **2004** **2003**    **(Millions)**
**Global (Energy Holdings)**
          
Non-Recourse Debt:
          
Skawina–5.60%
    2004–2005    $17     $3 
Dhofar Power–6.27%
    2004–2018     195      201 
ELCHO (Chorzow)–9.550%–13.225%
    2004–2019     305      285 
SAESA–3.807%
    2004–2023     167      167 
TIE (Odessa)–4.3125%–8.000%(K)
    2007     227      — 
TIE (Guadalupe)–4.3125%–8.000%(K)(L)
    2009     207      — 
Electroandes–5.880%–6.438%
    2005–2016     103      100 
Chilquinta–5.58%–6.62%
    2008–2011     162      161               
Principal Amount Outstanding
       1,383      917 
Amounts Due Within One Year(B)
       (62)     (33)              
Total Long-Term Debt of Global
      $1,321     $884               
**Resources (Energy Holdings)**
          
8.60%–9.30%—Non-Recourse Bank Loan
    2004–2020    $31     $32 
Amounts Due Within One Year(B)
       (2)     (1)              
Total Long-Term Debt of Resources
      $29     $31               
**EGDC (Energy Holdings)**
          
8.27%—Non-Recourse Mortgage
    2004–2013    $23     $25 
Amounts Due Within One Year(B)
       (2)     (2)              
Total Long-Term Debt of EGDC
      $21     $23               
Total Long-Term Debt of Energy Holdings
      $3,127     $2,738               
Total PSEG Consolidated Long-Term Debt
      $12,925     $12,945               
**
   (A)   As of each of the years ended December 31, 2004 and 2003, the annual dividend requirement of PSEG's Trust Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures), including those issued in connection with the Participating Units, and their embedded costs was approximately $104 million and 8.98%.    Enterprise Capital Trust I, Enterprise Capital Trust II, Enterprise Capital Trust III, Enterprise Capital Trust IV and PSEG Funding Trust II were formed and are controlled by PSEG for the purpose of issuing Quarterly Trust Preferred Securities (Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures). The proceeds were loaned to PSEG and are evidenced by Deferrable Interest Subordinated Debentures. If and for as long as payments on the Deferrable Interest Subordinated Debentures have been deferred, or PSEG had defaulted on the indentures related thereto or its guarantees thereof, PSEG may not pay any dividends on its common and preferred stock. The Subordinated Debentures support the Preferred Securities issued by the trusts.    In September 2002, PSEG Funding Trust I issued 9.2 million Participating Units with a stated amount of $50 per unit. Each unit consists of a 6.25% trust preferred security due 2007 having a liquidation value of $50, and a stock purchase contract obligating the purchasers to buy shares of PSEG Common Stock in an amount equal to $50 on November 16, 2005. In exchange for the obligations under the purchase contract, the purchasers receive quarterly contract adjustment payments at the annual rate of 4.00% through the purchase date. The number of new shares to be issued on November 16, 2005 will depend upon the average closing price per share of PSEG Common Stock for the 20 consecutive trading days ending the third trading day immediately preceding November 16, 2005. Based on the formula described in the purchase contract, at that time PSEG willissue between 11.4 million and 13.7 million shares of its common stock. The net proceeds from the sale of the Participating Units was $446 million. In connection with the issuance of the Participating Units, PSEG recorded a $54 million reduction to equity associated with the stock purchase contracts. For additional information, see Note 19. Stock Options and Employee Stock Purchase Plan.
*(footnotes continued on next page)*

141

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

*(footnotes continued from previous page)*
   (B)   The aggregate principal amounts of mandatory requirements for sinking funds and maturities for each of the five years following December 31, 2004 are as follows:      **PSE&G**     **Energy Holdings**    **Year** **PSEG** **PSE&G** **TransitionFunding** **Power** **EnergyHoldings** **Global** **Resources** **EGDC** **Total**  **(Millions)**
2005
    $49     $125     $146     $—     $—     $62     $2     $2     $386 
2006
     49      322      —      500      —      60      2      2      935 
2007
     509      113      34      —      309      261      1      2      1,229 
2008
     49      250      183      —      507      130      1      2      1,122 
2009
     249      60      —      250      400      230      2      3      1,194                                                            $905     $870      $363     $750     $1,216     $743     $8     $11     $4,866                                                                                               (C)   In September 2004, PSEG issued and sold $200 million of its 4.66% Series A Senior Notes due 2009 in a private placement. The proceeds were used to reduce short-term debt.   (D)   In August 2004, PSE&G issued $250 million of 5.00% Medium-Term Notes due 2014. The proceeds of this issuance were used to redeem the remaining outstanding $254 million of PSE&G's First and Refunding Mortgage Bonds, 7% Series SS due 2024 in September 2004.   (E)   In June 2004, PSE&G issued $175 million of floating rate First and Refunding Mortgage Bonds due 2006. The interest is set quarterly at LIBOR plus 0.125%. The proceeds were primarily used to redeem $159 million of 7.375% Series TT First and Refunding Mortgage Bonds due 2014 in June 2004.   (F)   In August 2004, PSE&G issued $104 million of its First and Refunding Mortgage Bonds, Pollution Control Series AC due 2031; $88 million of its First and Refunding Mortgage Bonds, Pollution Control Series AD due 2030; and $93 million of its First and Refunding Mortgage Bonds, Pollution Control Series AE due 2029. The proceeds were used to refund $104 million of PSE&G's First and Refunding Mortgage Bonds, Pollution Control Series Q due 2031, $88 million of PSE&G's First and Refunding Mortgage Bonds, Pollution Control Series R due 2030 in August 2004; and $93 million of PSE&G's First and Refunding Mortgage Bonds, Pollution Control Series S due 2029 in October 2004.   (G)   In May 2004, $286 million of PSE&G's 6.50% Series PP First and Refunding Mortgage Bonds matured.   (H)   In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009 and $250 million of 5.00% Senior Notes due April 2014. The net proceeds of $488 million, together with other available cash, were used to fund the repayment of $800 million of project finance debt of certain of Power's subsidiaries.   (I)   In February 2004, Energy Holdings repaid $267 million of its 9.125% Senior Notes at maturity.   (J)   During the second quarter of 2004, Energy Holdings repurchased approximately $41 million of its 7.75% Senior Notes due April 2007 at a premium of $3 million, reducing the aggregate amount of that security outstanding to $309 million.   (K)   In July 2004, Global signed an agreement to acquire all of TECO Energy Inc.'s 50% equity interest in TIE for less than $1 million. With this purchase, Global now owns 100% of TIE and consolidated this investment effective July 1, 2004. As a result, Energy Holdings presents approximately $434 million of Long-Term Non-Recourse Debt on its Consolidated Balance Sheet as of December 31, 2004.   (L)   In October 2004, Global invested approximately $20 million in TIE which was primarily used to reduce the Non-Recourse Long-Term Debt related to the Guadalupe project. The maturity date of the remaining debt of approximately $207 million associated with the project was extended from April 2006 to December 2009.   (M)   In December 2004, September 2004, June 2004 and March 2004, Transition Funding repaid approximately $38 million, $37 million, $30 million and $32 million, respectively, of its transition bonds.   (N)   As of December 31, 2004, variable interest rates were 2.66%, 1.75%, 1.80%, 1.85%, 1.80%, 1.80%, 1.80%, 1.80%, respectively.
142

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Short-Term Liquidity**

      **PSEG, PSE&G, Power and Energy Holdings**

      As of December 31, 2004, PSEG and its principal subsidiaries had an aggregate of approximately $2.7 billion of committed credit facilities. Each facility is restricted as to availability and use to the specific companies as listed below.
**Company**    **Expiration Date** **TotalFacility**    **Primary Purpose** **Usage as of12/31/2004** **AvailableLiquidity as of12/31/2004**    **(Millions)**          
**PSEG:**
                
4-year Credit Facility
    April 2008    $450     Commercial Paper(CP) Support/Funding/Letters of Credit    $—     $450 
5-year Credit Facility
    March 2005    $280     CP Support    $280     $— 
3-year Credit Facility
    December 2005    $350     CP Support/Funding/Letters of Credit    $153     $197 
Uncommitted Bilateral Agreement
    N/A     N/A     Funding    $—      N/A 
Bilateral Term Loan
    April 2005    $75     Funding    $75     $— 
Bilateral Revolver
    April 2005    $25     Funding    $25     $— 
**PSE&G:**
                
5-year Credit Facility
    June 2009    $600     CP Support/Funding/Letters of Credit    $90     $510 
Uncommitted Bilateral Agreement
    N/A     N/A     Funding    $15      N/A 
**PSEG and Power:**
                
3-year Credit Facility(A)
    April 2007    $600     CP Support/Funding/Letters of Credit    $17(B)    $583 
**Power:**
                
3-year Credit Facility
    August 2005    $25     Funding/Letters of Credit    $—     $25 
Bilateral Credit Facility
    March 2010    $100     Funding/Letters of Credit    $90(B)    $10 
**Energy Holdings:**
                
3-year Credit Facility(C)
    October 2006    $200     Funding/Letters of Credit    $31(B)    $169    (A)   PSEG/Power joint and several co-borrower facility.   (B)   These amounts relate to letters of credit outstanding.   (C)   Energy Holdings/Global/Resources joint and several co-borrower facility.
      **Energy Holdings**

      As of December 31, 2004, Energy Holdings had loaned $115 million of excess cash to PSEG. For information regarding affiliate borrowings, see Note 23. Related-Party Transactions.

**Fair Value of Debt**

      The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of December 31, 2004 and 2003, respectively.

143

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
  **December 31, 2004** **December 31, 2003**  **CarryingAmount** **FairValue** **CarryingAmount** **FairValue**  **(Millions)**
**Long-Term Debt:**
                
PSEG
    $1,654     $1,817     $1,462     $1,586 
Energy Holdings
     3,193      3,389      3,041      3,230 
PSE&G
     3,063      3,209      3,330      3,601 
Transition Funding (PSE&G)
     2,085      2,272      2,222      2,474 
Power
     3,316      3,714      3,616      4,034                              $13,311     $14,401     $13,671     $14,925                          
      Because their maturities are less than one year, fair values approximate carrying amounts for cash and cash equivalents, short-term debt and accounts payable. For additional information related to interest rate derivatives, see Note 13. Risk Management.

**Note 13. Risk Management**

**PSEG, PSE&G, Power and Energy Holdings**

      The operations of PSEG, PSE&G, Power and Energy Holdings are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could affect their results of operations and financial conditions. PSEG, PSE&G, Power and Energy Holdings manage exposure to these market risks through their regular operating and financing activities and, when deemed appropriate, hedge these risks through the use of derivative financial instruments. PSEG, PSE&G, Power and Energy Holdings use the term “hedge” to mean a strategy designed to manage risks of volatility in prices or rate movements on certain assets, liabilities or anticipated transactions and by creating a relationship in which gains or losses on derivative instruments are expected to counterbalancethe gains or losses on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, PSE&G, Power and Energy Holdings uses derivative instruments as risk management tools consistent with its respective business plan and prudent business practices.

**Derivative Instruments and Hedging Activities**

      **Energy Trading Contracts**

      ***Power***

      Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, firm transmission rights (FTRs), coal, oil, weather derivatives and emission allowances in the spot, forward and futures markets, primarily in PJM, but also in the surrounding region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana, and natural gas in the producing region.

      Power maintains a strategy of entering into positions to optimize the value of its portfolio and reduce earnings volatility of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy seeking to mitigate the effects of adverse movements in the fuel and electricity markets. These contracts also involve financial transactions including swaps, options and futures.

      Power marks its derivative energy trading contracts to market in accordance with SFAS 133, as amended, with changes in fair value charged to the Consolidated Statement of Operations. Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices, as applicable, to interpolate certain prices. The effect of using such modeling techniques is not material to Power's financial results.

144

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      Power routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, exchange-traded futures contracts require a deposit of margin cash, the amount of which is subject to change based on market movement and in accordance with exchange rules.

      **Commodity Contracts**

      ***Power***

      The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events. Power manages its risk of fluctuations of energy price and availability through derivative instruments, such as forward purchase or sale contracts, swaps, options, futures and FTRs.

      ***Cash Flow Hedges***

      Power uses forward sale and purchase contracts, swaps and FTR contracts to hedge forecasted energy sales from its generation stations and to hedge related load obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements. These derivative transactions are designated and effective as cash flow hedges under SFAS 133, as amended. As of December 31, 2004, the fair value of these hedges was $(248) million, $(145) million after-tax. As of December 31, 2003, the fair value of these hedges was $(37) million, $(22) million after-tax. During the next 12 months, $81 million of unrealized losses (after-tax) on these commodity derivatives in Accumulated Other Comprehensive Loss is expected to be reclassified to earnings. Ineffectiveness associatedwith these hedges, as defined in SFAS 133, was immaterial. The expiration date of the longest dated cash flow hedge is in 2008.

      ***Other Derivatives***

      Power also enters into certain other contracts that are derivatives, but do not qualify for hedge accounting under SFAS 133. Most of these contracts are used for fuel purchases for generation requirements and for electricity purchases for contractual sales obligations. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs or Operating Revenues, as appropriate, on the Consolidated Statements of Operations. The net fair value of these instruments as of December 31, 2004 and 2003 was $14 million and $7 million, respectively.

**Interest Rates**

      **PSEG, PSE&G, Power and Energy Holdings**

      PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG's policy is to manage interest rate risk through the use of fixed and floating rate debt and interest rate derivatives.

      **Fair Value Hedges**

      ***PSEG and Power***

      In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009. PSEG used an interest rate swap to convert Power's fixed-rate debt into variable-rate debt. The interest rate swap is designated and effective as a fair value hedge. The fair value changes of the interest rate swap are fully offset by the fair value changes in the underlying debt. As of December 31, 2004, the fair value of the hedge was $(3) million and there was no ineffectiveness related to the hedge.

      ***Energy Holdings***

      In April 2003, Energy Holdings issued $350 million of 7.75% Senior Notes due in 2007. Energy Holdings used interest rate swaps to convert $200 million of this fixed-rate debt into variable-rate debt. The interest rate swaps are designated and effective as fair value hedges. The fair value changes of these interest rate

145

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

swaps are fully offset by the fair value changes in the underlying debt. As of December 31, 2004 and 2003, the fair value of these hedges was $(3) million and $(1) million, respectively, and there was no ineffectiveness related to these hedges.

      **Cash Flow Hedges**

      ***PSEG, PSE&G, Power and Energy Holdings***

      PSEG, PSE&G, Power and Energy Holdings use interest rate swaps and other interest rate derivatives to manage their exposures to the variability of cash flows, primarily related to variable-rate debt instruments. The interest rate derivatives used are designated and effective as cash flow hedges. The fair value changes of these derivatives are initially recorded in OCI. As of December 31, 2004, the fair value of these cash flow hedges was $(145) million, including $(11) million, $(34) million and $(100) million at PSEG, PSE&G and Energy Holdings, respectively. As of December 31, 2003, the fair value of these cash flow hedges was $(186) million, including $(16) million, $(51) million, $(7) million and $(112) million at PSEG, PSE&G, Power and Energy Holdings, respectively. The $(34) million and $(51) million atPSE&G as of December 31, 2004 and 2003, respectively, is not included in Accumulated Other Comprehensive Loss and is deferred as a Regulatory Asset and expected to be recovered from PSE&G's customers. During the next 12 months, $28 million of unrealized losses (net of taxes) on interest rate derivatives in Accumulated Other Comprehensive Loss is expected to be reclassified to earnings, including $7 million and $21 million at PSEG and Energy Holdings, respectively. As of December 31, 2004, hedge ineffectiveness associated with these hedges was not material.

      **Other Derivatives**

      ***Energy Holdings***

      Foreign subsidiaries and affiliates of Energy Holdings have entered into interest rate forward contracts, which effectively converted variable-rate debt to fixed-rate debt. Since these contracts have not been designated as cash flow or fair value hedges, changes in the fair value of these derivative instruments are recorded directly to Interest Expense. The fair value of these instruments as of December 31, 2004 and 2003 was not material.

**Foreign Currencies**

      **Energy Holdings**

      Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of its risks is that some of its foreign subsidiaries and affiliates have functional currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, Global and certain of its foreign subsidiaries and affiliates have entered into monetary obligations and maintain receipts/receivables in U.S. Dollars or currencies other than their own functional currencies. Global, a U.S. Dollar functional currency entity, is primarily exposed to changes in the Brazilian Real, the Euro, the Polish Zloty, the Peruvian Nuevo Sol and the Chilean Peso. Changes in valuation of these currencies can impact the value of Global's investments, as well as its abilityto service locally funded debt obligations. With respect to the foreign currency risk associated with the Brazilian Real, there has already been significant devaluation since the initial acquisition of that investment in 1997, which has resulted in reduced U.S. Dollar earnings and cash flows relative to initial projections. Global has attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust for changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements to manage risk related to certain foreign currency fluctuations.

      As of December 31, 2004, net cumulative foreign currency devaluations had reduced the total amount of Energy Holdings' Member's Equity by $116 million. This decrease was primarily due to the devaluation of the Brazilian Real in 1999. During 2004, as the U.S. Dollar weakened against many currencies, Global's equity increased by $75 million. As of December 31, 2003, net cumulative foreign currency devaluations had

146

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

reduced the total amount of Energy Holdings' Member's Equity by $193 million, including $228 million caused by the devaluation of the Brazilian Real.

      In November 2004, Energy Holdings entered into foreign currency call options in order to hedge the majority of its 2005 expected earnings denominated in Brazilian Reais, Chilean Pesos and Peruvian Nuevo Soles. These options are not considered hedges for accounting purposes under SFAS 133 and, as a result, changes in their fair value are recorded directly to earnings.

**Equity Securities**

      **Energy Holdings**

      For the year ended December 31, 2004, Resources recognized a $13 million (pre-tax) loss related to non-publicly traded equity securities and an $11 million (pre-tax) gain on publicly traded equity securities, which are held within its investments in certain venture capital and leveraged buyout funds. For the year ended December 31, 2003, Resources had an $11 million (pre-tax) loss from other than temporary impairments of non-publicly traded equity securities, which are held within its investments in certain leveraged buyout funds and a $5 million (pre-tax) gain on the publicly traded equity securities. In September 2004, Resources received cash distributions totaling approximately $26 million from the sale of some of its investments in KKR's leveraged buyout fund. As a result of this sale and sales earlier in the year,Resources' investment in leveraged buyout funds has been reduced to approximately $27 million as of December 31, 2004, all of which is comprised of public securities with available market prices. As of December 31, 2003, Resources had investments in leveraged buyout funds of approximately $75 million, of which $26 million was comprised of public securities with available market prices and $49 million was comprised of privately-held interests in certain companies.

**Note 14. Commitments and Contingent Liabilities**

**Nuclear Insurance Coverages and Assessments**

      **Power**

      Power is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the primary property and decontamination liability insurance at Salem Nuclear Generating Station (Salem), Hope Creek Nuclear Generating Station (Hope Creek) and Peach Bottom Atomic Power Station (Peach Bottom). NEIL also provides excess property insurance through its decontamination liability, decommissioning liability and excess property policy and replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in case of adverse loss experience. Power's maximum potential liabilities under these assessments are included in the table and notes below. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respectto all nuclear units on a site without notice if the Nuclear Regulatory Commission (NRC) suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.

      The American Nuclear Insurers (ANI) and NEIL policies both include coverage for claims arising out of acts of terrorism. Both ANI and NEIL make a distinction between certified and non-certified acts of terrorism, as defined under the Terrorism Risk Insurance Act (TRIA), and thus their policies respond accordingly. For non-certified acts of terrorism, ANI policies are subject to an industry aggregate limit of $300 million, subject to reinstatement at ANI discretion. Similarly, NEIL policies are subject to an industry aggregate limit of $3.2 billion plus any amounts available through reinsurance or indemnity for non-certified acts of terrorism. For certified acts, Power's nuclear liability ANI and nuclear property NEIL policies will respond similarly to other covered events.

      The Price-Anderson Act sets the “limit of liability” for claims that could arise from an incident involving any licensed nuclear facility in the U.S. The “limit of liability” is based on the number of licensed nuclear reactors and is adjusted at least every five years based on the Consumer Price Index. The current “limit of liability” is $10.8 billion. All utilities owning a nuclear reactor, including Power, have provided for this exposure through a combination of private insurance and mandatory participation in a financial protection

147

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

pool as established by the Price-Anderson Act. Under the Price-Anderson Act, each party with an ownership interest in a nuclear reactor can be assessed its share of $101 million per reactor per incident, payable at $10 million per reactor per incident per year. If the damages exceed the “limit of liability,” the President is to submit to Congress a plan for providing additional compensation to the injured parties. Congress could impose further revenue raising measures on the nuclear industry to pay claims. Power's maximum aggregate assessment per incident is $317 million (based on Power's ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $32 million. This does not include the $11 million that could be assessed under the nuclear worker policies. Further, a decision bythe U.S. Supreme Court, not involving Power, has held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damages.

      Power's insurance coverages and maximum retrospective assessments for its nuclear operations are as follows:
  **Total SiteCoverage** **RetrospectiveAssessments**  **(Millions)**
**Type and Source of Coverages**
        
*Public and Nuclear Worker Liability (Primary Layer):*
        
ANI
    $300.0(A)        $10.7 
*Nuclear Liability (Excess Layer):*
        
Price-Anderson Act
     10,461.0(B)         316.7                  
Nuclear Liability Total
    $10,761.0(C)        $327.4                  
*Property Damage (Primary Layer):*
        
NEIL
        
Primary (Salem/Hope Creek/Peach Bottom)
    $500.0         $19.7 
*Property Damage (Excess Layers):*
        
NEIL II (Salem/Hope Creek/Peach Bottom)
     600.0          6.2 
NEIL Blanket Excess (Salem/Hope Creek/Peach Bottom)
     1,000.0(D)         6.6                  
Property Damage Total (Per Site)
    $2,100.0         $32.5                  
*Accidental Outage:*
        
NEIL I (Peach Bottom)
    $245.0(E)        $9.7 
NEIL I (Salem)
     281.4(E)         10.8 
NEIL I (Hope Creek)
     490.0(E)         8.9                  
Replacement Power Total
    $1,016.4         $29.4                  
**
   (A)   The primary limit for Public Liability is a per site aggregate limit with no potential for assessment. The Nuclear Worker Liability represents the potential liability from workers claiming exposure to the hazard of nuclear radiation. This coverage is subject to an industry aggregate limit that is subject to reinstatement at ANI discretion and has an assessment potential under former canceled policies.   (B)   Retrospective premium program under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. Power is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the U.S. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of August 20, 2003. This retrospective program is in excess over the Public and Nuclear Worker Liability primary layers.   (C)   Limit of liability under the Price-Anderson Act for each nuclear incident.   (D)   For property limits in excess of $1.1 billion, Power participates in a Blanket Limit policy where the $1.0 billion limit is shared by Power with Amergen Energy Company, LLC and Exelon Generation Company, LLC (Exelon Generation) among the Braidwood, Byron, Clinton, Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 facilities owned by Amergen and Exelon and the Peach Bottom, Salem and
*(footnotes continued on next page)*

148

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

*(footnotes continued from previous page)*
    Hope Creek facilities. This limit is not subject to reinstatement in the event of a loss. Participation in this program materially reduces Power's premium and the associated potential assessment.   (E)   Peach Bottom has an aggregate indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Salem has an aggregate indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 75 weeks. Hope Creek has an aggregate indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80% of the weekly indemnity for 71 weeks.
**Guaranteed Obligations**

      **Power**

      Power has unconditionally guaranteed payment by its subsidiary, ER&T, in certain commodity-related transactions in the ordinary course of business. These payment guarantees were provided to counterparties in order to obtain credit under physical and financial agreements in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. These Power payment guarantees support the current exposure, interest and other costs on sums due and payable by ER&T under these agreements. Guarantees offered for trading and marketing cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. The face value of the guarantees outstanding as of December 31, 2004 and 2003 was $1.6 billion and $1.4 billion, respectively.In order for Power to incur a liability for the face value of the outstanding guarantees, ER&T would have to fully utilize the credit granted to it by every counterparty to whom Power has provided a guarantee and all of ER&T's contracts would have to be “out-of-the-money” (if the contracts were terminated, Power would owe money to the counterparties). The probability of all contracts at ER&T being simultaneously “out-of-the-money” is highly unlikely. For this reason, the current exposure at any point in time is a more meaningful representation of the potential liability to Power under these guarantees. The current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any margins posted. The current exposure from such liabilities was $507 million and $228 million as of December 31, 2004and 2003, respectively. Of the $507 million exposure, $193 million was recorded on Power's Consolidated Balance Sheet as of December 31, 2004. Of the $228 million exposure, $167 million is recorded on Power's Consolidated Balance Sheet as of December 31, 2003. The increase in exposure as of December 31, 2004, as compared to December 31, 2003, is partially due to the inclusion of an additional year of BGS exposure that commenced in February 2004. BGS exposure is not marked to market and therefore this exposure is not included on the Consolidated Balance Sheets.

      Power is subject to collateral calls related to commodity contracts. As of December 31, 2004, Power had recorded margin (cash) paid of approximately $23 million. An increase in energy prices causes a commensurate increase in collateral requirements for Power. As of December 31, 2004, if Power had lost its investment grade credit rating, there was a potential for approximately $701 million of additional collateral calls for those counterparties with whom Power was “out-of-the-money” under such contracts and where those counterparties were entitled to and had called for collateral. Extreme market events, like the daily price movements in natural gas and power experienced recently, can significantly impact these requirements. As of December 31, 2004, Power had recorded margin received of approximately $68 million.

      As of December 31, 2004, letters of credit issued by Power were outstanding in the amount of approximately $145 million in support of various contractual obligations, environmental liabilities and to satisfy trading collateral obligations.

      **Energy Holdings**

      Energy Holdings and/or Global have guaranteed certain obligations of their subsidiaries or affiliates, including the successful completion, performance or other obligations related to certain projects in an aggregate amount of approximately $138 million and $180 million as of December 31, 2004 and 2003, respectively. As of December 31, 2004 and 2003, the guarantees of payment include $26 million and $49 million, respectively, for a standby equity commitment for Skawina in Poland expiring in August 2007 and a

149

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

$25 million contingent guarantee related to debt service obligations of Chilquinta in Chile expiring in 2011. Additional guarantees consist of a $35 million and $37 million leasing agreement guarantee for Prisma in Italy as of December 31, 2004 and 2003, respectively, $13 million and $24 million of performance and payment guarantees related to Energy Technologies as of December 31, 2004 and 2003, respectively, that are supported by letters of credit that expire in May 2005, and various other guarantees comprising the remaining $39 million and $45 million as of December 31, 2004 and 2003, respectively, expiring through 2010.

      In September 2003, Energy Holdings completed the sale of Energy Technologies and nearly all of its assets. However, Energy Holdings retained certain outstanding construction and warranty obligations related to ongoing construction projects previously performed by Energy Technologies. These construction obligations have performance bonds issued by insurance companies for which exposure is adequately supported by the outstanding letters of credit described above. As of December 31, 2004, there were $30 million of such bonds outstanding, which are related to uncompleted construction projects. These performance bonds are not included in the $138 million of guaranteed obligations discussed above.

      In addition to the amounts discussed above, certain subsidiaries of Energy Holdings also have contingent obligations related to their respective projects, which are non-recourse to Energy Holdings and Global.

**Environmental Matters**

      **PSEG, PSE&G and Power**

      ***Hazardous Substances***

      The New Jersey Department of Environmental Protection (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. These regulations may substantially increase the costs of environmental investigations and necessary remediation, particularly at sites situated on surface water bodies. PSE&G, Power and respective predecessor companies own or owned and/or operate or operated certain facilities situated on surface water bodies, certain of which are currently the subject of remedial activities. The financial impact of these regulations on these projects is not currently estimable. However, neither PSE&G nor Power anticipate that compliance with these regulationswill have a material adverse effect on its respective financial position, results of operations or net cash flow.

      The U.S. Environmental Protection Agency (EPA) has determined that a six mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA). PSE&G and certain of its predecessors conducted industrial operations at properties adjacent to the Passaic River facility. The operations included one operating (Essex Site, one former generating station and four former MGPs. PSE&G's costs to clean up former MGPs are recoverable from utility customers through the SBC. PSE&G has sold the site of the former generating station and obtained releases and indemnities for liabilities arising out of the site in connection with the sale. The Essex Site was transferredto Power in August 2000. Power assumed any environmental liabilities of PSE&G associated with the electric generating stations that PSE&G transferred to it, including the Essex Site.

      In 2003, the EPA notified 41 potentially responsible parties (PRPs), including PSE&G and Power, that it was expanding its assessment of the Passaic River Study Area to the entire 17-mile tidal reach of the lower Passaic River. The EPA further indicated, with respect to PSE&G, that it believed that hazardous substances were being released from the Essex Site and a former MGP located in Harrison, New Jersey (Harrison Site), which also includes facilities for PSE&G's ongoing gas operations. The EPA has estimated that its study would require five to eight years to complete and would cost approximately $20 million, of which it would seek to recover $10 million from the PRPs, including PSE&G and Power. Power is evaluating recoverability of any disbursed amounts from its insurance carriers.

      Also, in 2003, PSEG, PSE&G and 56 other PRPs received a Directive and Notice to Insurers from the NJDEP that directed the PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged in the Directive that it had determined that hazardous substances had been discharged from the Essex Site and the Harrison Site.

150

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

The NJDEP announced that it had estimated the cost of interim natural resource injury restoration activities along the lower Passaic River to approximate $950 million.

      PSE&G and Power have indicated to both the EPA and NJDEP that they are willing to work with the agencies in an effort to resolve their respective claims and, along with approximately 40 other PRPs, have executed an agreement with the EPA that provides for sharing the costs of the study between the government organizations and the PRPs. PSEG, PSE&G and Power cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River or natural resource damages. However, such costs could be material.

      **PSE&G**

      ***MGP Remediation Program***

      PSE&G is currently working with the NJDEP under a program to assess, investigate and remediate environmental conditions at PSE&G's former MGP sites (Remediation Program). To date, 38 sites have been identified as sites requiring some level of remedial action. The Remediation Program is periodically reviewed, and the estimated costs are revised by PSE&G based on regulatory requirements, experience with the program and available remediation technologies. Since the inception of the program in 1988 through December 31, 2004, PSE&G had expenditures of approximately $294 million.

      During the fourth quarter of 2004, PSE&G refined the detailed site estimates, and determined that total Remediation Program costs could range between $650 million and $685 million. No amount within the range was considered to be most likely. Therefore, $356 million was accrued at December 31, 2004, which represents the difference between the low end of the total program cost estimate of $650 million and the total incurred costs through December 31, 2004 of $294 million. Of this amount, approximately $47 million was recorded in Other Current Liabilities and $309 million was reflected in Other Noncurrent Liabilities. The costs associated with the MGP Remediation Program have historically been recovered through the SBC charges to PSE&G ratepayers. As such, a $356 million Regulatory Asset was also recorded.

      Costs for the MGP Remediation Program were approximately $34 million in 2004. PSE&G anticipates spending $47 million in 2005, $35 million in 2006, and an average of $26 million per year through 2016.

      ***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 for PSE&G's funding requirement has been recorded at discounted present value with an offsetting regulatory asset.

      **Power**

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

      The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The Federal government is seeking to order companies allegedly not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties of up to approximately $27,500 for each day of continued violation.

      The EPA and the NJDEP issued a demand in March 2000 under the CAA requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal-burning units were implemented in accordance with applicable PSD/NSR regulations. Power completed its response to the requests for information and, in January 2002, reached an agreement with New Jersey and the Federal government to resolve allegations of noncompliance with PSD/NSR regulations. Under that agreement, over the course of 10 years, Power has agreed to install advanced air pollution controls that are designed to reduce emissions of NOx, SO2, particulate matter and mercury. The estimated costof the program as of December

151

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

31, 2004 includes approximately $110 million for installation of selective catalytic reduction systems (SCRs) at Mercer, of which approximately $92 million has been spent, as well as approximately $300 million to $350 million at the Hudson unit and $150 million to $200 million for other pollution control equipment at Mercer to be installed by December 31, 2012. Power also paid a $1.4 million civil penalty and has agreed to spend up to $6 million on supplemental environmental projects. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved a dispute over Bergen 2 regarding the applicability of PSD requirements and allowed construction of the unit to be completed and operations to commence.

      Power has notified the EPA and the NJDEP that it is evaluating the continued operation of the Hudson coal unit in light of changes in the energy and capacity markets, increases in the cost of pollution control equipment and other necessary modifications to the unit. These and other factors impacting the power industry identified to the agencies continue to cast doubts on the appropriateness of making the necessary investments and Power's ability to complete the work at this time. A decision has not yet been made as to the Hudson unit's continued operation beyond the December 31, 2006 deadline for installation of pollution control equipment. The related costs associated with the pollution control modifications for the Hudson unit have not been included in Power's capital expenditure projections.

      ***ISRA***

      Potential environmental liabilities related to subsurface contamination at certain generating stations have been identified. In the second quarter of 1999, in anticipation of the transfer of PSE&G's generation-related assets to Power, a study was conducted pursuant to ISRA, which applies to the sale of certain assets. PSEG had a $51 million liability as of December 31, 2004 related to these obligations, which is recorded on the Consolidated Balance Sheets.

**New Generation and Development**

      **Power**

      Completion of the projects discussed below, within the estimated time frames and cost estimates cannot be assured. Construction delays, cost increases and various other factors could result in changes in the operational dates or ultimate costs to complete.

      Power is constructing the Bethlehem Energy Center, which will replace the Albany Station. Total costs for this project are expected to be approximately $551 million with expenditures to date of approximately $496 million (including IDC of $52 million). Construction began in 2002 with the expected completion date in mid-2005, at which time the existing station will be retired.

      Power is constructing a natural gas-fired generation plant in Linden, New Jersey. Power is replacing the tubes in both steam turbine condensers due to corrosion that was detected. Power anticipates that construction will be completed in the second quarter of 2006. Including the replacement of the tubes, the total costs are currently estimated at approximately $1 billion with expenditures to date of approximately $880 million (including IDC of $135 million).

      Power also  has contracts with outside parties to purchase upgraded turbines for Salem Units  1 and 2 and to purchase upgraded turbines and complete a power uprate for Hope  Creek to modestly increase its generating capacity. Salem Unit 2 completed Phase  I of its turbine replacement during its Fall 2003 refueling outage and gained  24 MW, primarily due to the replacement. Phase II of the replacement is currently  scheduled for 2008 and is anticipated to increase capacity by 26 MW. Salem Unit  1 completed its turbine replacement during its Spring 2004 refueling outage  and gained 63 MW, primarily due to the replacement. Phase I of Hope Creek's  turbine replacement was completed in January 2005 and is anticipated to increase  capacity by 10 MW. Phase II is expected to be completed in 2006 and along with  the power uprate is expected to add 125 MW. This schedule for completion of  Hope Creek's power uprate in 2006, which depends on timely approval from  the NRC, is currently being reevaluated. Power's expenditures to date approximate  $183 million (including IDC of $13 million) with an aggregate estimated share  of total costs for these projects of $250 million (including IDC of $22 million).  Timing, costs and results of these projects is dependant on timely completion  of work, timely approval from the NRC and various other factors.

152

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      Power has entered into a long-term contractual services agreement with a vendor to provide the outage and service needs for certain of Power's generating units at market rates. The contract covers approximately 25 years and could result in annual payments ranging from approximately $10 million to $50 million for services, parts and materials rendered.

      **Energy Holdings**

      ***Electroandes***

      There is a 35 MW expansion project on an existing hydro station under development at Electroandes. The project is expected to be placed into service in 2007 at a total cost of $27 million. The project is being financed with cash and non-recourse debt at Electroandes.

**BGS and Basic Gas Supply Service (BGSS)**

      **PSE&G and Power**

      PSE&G is required to obtain all of its basic generation energy supply needs through the New Jersey BGS auctions for its customers that are not served by a third-party supplier. PSE&G has entered into contracts with Power, as well as with third-party suppliers, to purchase BGS for PSE&G's anticipated load requirements. In addition, PSE&G has a full requirements natural gas contract for gas supply with Power under which Power will provide PSE&G with its BGSS requirements into 2007.

      The BPU permits recovery of the cost of hedging up to 115 billion cubic feet of PSE&G's residential gas supply annually through the BGSS tariff. Power has hedged approximately 75% to 80% of the allowed residential volume for the current winter season (2004/05) at an average price of $5.78 per decatherm (dth). For the upcoming 2005 summer season, approximately 50% to 55% of the allowed residential volume has been hedged at an average price of $5.84 per dth. Approximately 35% to 40% of the allowed residential volume has been hedged for next winter season (2005/06) at an average price of $6.76 per dth.

      **Power**

      Power's objective is to enter into load serving supply contracts and trading positions for at least 75% of its anticipated output over an 18-month to 24-month horizon. As part of this objective, Power has entered into contracts to directly supply PSE&G    and other New Jersey Electric Distribution Companies (EDC) with a portion    of their BGS requirements, through the New Jersey BGS auction process. In    addition to the BGS related contracts, Power has entered into firm supply    contracts with EDCs in Pennsylvania, Connecticut and Maryland, as well asother firm sales and trading positions and commitments.

**Minimum Fuel Purchase Requirements**

      **Power**

      Power purchases coal and oil for certain of its fossil generation stations through various long-term commitments. The total minimum purchase requirements included in these commitments amount to approximately $851 million through 2009.

      Power has various multi-year requirements-based purchase commitments that total approximately $87 million per year to meet Salem's and Hope Creek's nuclear fuel needs, of which Power's share is approximately $63 million per year through 2010. Power has been advised by Exelon Generation, the co-owner and operator of Peach Bottom, that it has similar purchase contracts to satisfy the fuel requirements for Peach Bottom through 2010, of which Power's share is approximately $23 million per year.

      In addition to its fuel requirements, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas, primarily to meet its gas supply obligations to PSE&G. As of December 31, 2004, the total minimum requirements under these contracts were approximately $627 million through 2016.

153

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      These purchase obligations are in keeping with Power's objective to enter into load serving supply contracts and trading positions for at least 75% of its anticipated output over an 18-month to 24-month horizon and to enter into contracts for its fuel supply in comparable volumes.

      **Energy Holdings**

      TIE's    Guadalupe and Odessa plants committed to purchase fuel under gas supply agreements.    As of December 31, 2004, Guadalupe and Odessa had fuel purchase commitments    totaling $188 million. These supply contracts are expected to cover 43% ofanticipated output during 2005.

**Operating Services Contract (OSC)**

      **Power**

      Nuclear    has entered into an 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 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 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 additionaltime is necessary to complete required activities during the transition period.

**Nuclear Fuel Disposal**

      **Power**

      Under the Nuclear Waste Policy Act of 1982, as amended (NWPA), the Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001) per Kilowatt-hour (kWh) of nuclear generation, subject to such escalation as may be required to assure full cost recovery by the Federal government. Under the NWPA, the U.S. Department of Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998. The DOE has announced that it does not expect a facility for such purpose to be available earlier than 2010.

      Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent fuel storage installations located at reactors or away-from-reactor sites for at least 30 years beyond the licensed life for reactor operation (which may include the term of a revised or renewed license). Adequate spent fuel storage capacity is estimated to be available through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power has commenced construction of an on-site storage facility that will satisfy the spent fuel storage needs of both Salem and Hope Creek through the end of their current respective license lives. Exelon Generation has advised Power that it has a licensed and operational on-site storage facility at Peach Bottom that will satisfy Peach Bottom's spentfuel storage requirements until at least 2014.

      Exelon Generation had previously advised Power that it had signed an agreement with the DOE, applicable to Peach Bottom, under which Exelon Generation would be reimbursed for costs incurred resulting from the DOE's delay in accepting spent nuclear fuel for permanent storage. Under this agreement, Power's portion of Peach Bottom's Nuclear Waste Fund fees were reduced by approximately $18 million through August 31, 2002, at which point credits were fully utilized and covered the cost of Exelon

154

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

Generation's onsite storage facility. In September 2002, the U.S. Court of Appeals for the Eleventh Circuit issued an opinion upholding a petition seeking to set aside the receipt of these credits by Exelon Generation. On August 14, 2003, Exelon Generation received a letter from the DOE demanding repayment of previously received credits from the Nuclear Waste Fund. The letter also demanded a total of approximately $1.5 million of accrued interest (100% share). In August 2004, Exelon Generation advised Nuclear that it reached a settlement with the U.S. Department of Justice, under which Exelon Generation will be reimbursed for costs associated with the storage of spent nuclear fuel at the Peach Bottom facility, a portion of which will be paid to Nuclear as a co-owner of Peach Bottom. Future costs incurred resulting from DOE delays in accepting spent fuelwill be reimbursed annually until the DOE fulfills its obligation to accept spent nuclear fuel. In addition, Exelon Generation and Nuclear are required to reimburse the DOE for the previously received credits from the Nuclear Waste Fund, plus lost earnings. Under this settlement, Power received approximately $27 million for its share of previously incurred storage costs for Peach Bottom, $22 million of which was used for the required reimbursement to the Nuclear Waste Fund. As a result of this settlement, Power reversed approximately $12 million of previously capitalized plant-related costs and recognized an increase of $7 million to Operating Expenses in 2004.

      In September 2001, Power filed a complaint in the U.S. Court of Federal Claims (Court) seeking damages caused by the DOE not taking possession of spent nuclear fuel in 1998. On October 14, 2004, an order to show cause was issued regarding whether the Court has jurisdiction over the matter. Power responded to this order in November 2004. On January 31, 2005, the Judge dismissed the breach-of-contract claims of Power and three other utilities. Power moved for reconsideration at the Court of Federal Claims and jointly petitioned for permission to appeal the January 31, 2005 order to the U.S. Court of Appeals for the Federal Circuit. No assurances can be given as to any damage recovery or the ultimate availability of a disposal facility.

**Spent Fuel Pool**

      **Power**

      The spent fuel pool at each Salem unit has an installed leakage collection system. This normal leakage path was found to be obstructed, causing concern about the extent of leakage contact with the fuel handling building's concrete structure. Power is developing a solution to maintain the design function of the leakage collection system and is investigating the extent of any structural degradation caused by the leakage. The investigation should take approximately one year. If any significant degradation is identified, the repair costs could be material. The NRC issued Information Notice 2004-05 in March 2004 concerning this emerging industry issue and Power cannot predict what further actions the NRC may take on this matter.

      Elevated concentrations of tritium in the shallow groundwater near Salem Unit 1 were detected in early 2003. This information was reported to the NJDEP and the NRC, as required. Power conducted a comprehensive investigation in accordance with NJDEP site remediation regulations to determine the source and extent of the tritium in the groundwater. Power is conducting remedial pilot studies and received approval of a remedial action workplan from the NJDEP in November 2004 for the proposed remedy. The costs necessary to address this groundwater contamination issue have not been determined, however, such costs are not expected to be material.

**Other**

      **PSEG, PSE&G, Power and Energy Holdings**

      ***Merger Agreement***

      In connection with the merger agreement with Exelon Generation, there are certain commitments and contingencies relating to termination fees and operating service contracts. See Note 25. Merger Agreement for further information.

155

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      **PSEG and PSE&G**

      ***Investment Tax Credits (ITC)***

      As of June 1999, the Internal Revenue Service (IRS) had issued several private letter rulings that concluded that the refunding of excess deferred tax and ITC balances to utility customers was permitted only over the related assets' regulatory lives, which were terminated upon New Jersey's electric industry restructuring. Based on this fact, PSEG and PSE&G reversed the deferred tax and ITC liability relating to PSE&G's generation assets that were transferred to Power and recorded a $235 million reduction of the extraordinary charge in 1999 due to the restructuring of the utility industry in New Jersey. PSE&G was directed by the BPU to seek a ruling from the IRS to determine if the ITC included in the impairment write-down of generation assets could be credited to customers without violating the taxnormalization rules of the Internal Revenue Code. PSE&G filed a private letter ruling request with the IRS in 2002, which is still pending.

      In 2003, the IRS proposed regulations for comment that, if adopted, would allow utilities to elect retroactive application over periods equivalent to the ones in place prior to deregulation. While PSEG cannot predict the outcome of this matter, a requirement to refund such amounts to customers could have a material adverse impact on PSEG's and PSE&G's financial condition, results of operations and net cash flows.

      **PSEG and Energy Holdings**

      ***Leveraged Lease Investments***

      In 1996 through 2002, PSEG, through its indirect wholly-owned subsidiary, Resources, entered into a number of leveraged leasing transactions in the ordinary course of PSEG's business. The IRS is likely to argue that certain of those transactions are of a type that it has announced its intention to challenge, and PSEG understands that similar transactions entered into by other companies have been the subject of review and challenge by the IRS. As of December 31, 2004, Resources' total gross investment in such transactions was approximately $1.3 billion. The IRS is presently reviewing the tax returns of PSEG and its subsidiaries for tax years 1997 through 2000, years when Resources entered into these transactions. The IRS is aware of these lease transactions and has requested information and documents associated withthem. To date, the IRS has not proposed to disallow any deductions claimed relative to these transactions, but may propose such disallowances in the future. If the tax benefits associated with the lease transactions were successfully challenged by the IRS, PSEG would be assessed interest and possibly penalties in addition to any underpayments of tax. During the time period of 1997 through 2000, these transactions reduced current tax liabilities of PSEG by approximately $240 million and during the subsequent time period of 2001 though 2004, these and similar transactions reduced the current tax liabilities of PSEG by approximately $301 million. Interest that would be assessed on these potential deficiencies, if associated deductions were disallowed, would be approximately $100 million through December 31, 2004. It is presently unclear the extent to which the IRS will seek to disallow deductionsassociated with lease transactions, if at all, and, if it were to do so, the extent to which any such challenge would be successful. If deductions associated with these transactions entered into by PSEG were successfully challenged by the IRS, it could have a material adverse impact on PSEG's and Energy Holdings financial position, results of operations and net cash flows and could impact future returns on these transactions. PSEG believes that its tax position related to these transactions is proper based on applicable statutes, regulations and case law, and believes that it should prevail with respect to an IRS challenge, if presented, although no assurances can be given.

      The FASB    is currently considering a modification to GAAP for leveraged leases. Under    present GAAP, a tax settlement with the IRS that results merely in a change    in the timing of tax liabilities would not require an accounting repricing    of the lease investment. As such, income from the lease would continue to    accrue at the original economic yield computed for the lease and there wouldbe no write-down of the lease investment.

      A modification    currently being considered by the FASB could require a lease to be repriced    in the event a change in the timing of tax liabilities has a significant    impact on the economic yield of the lease and to be retested to determine    if it qualifies for leveraged lease accounting. If this or a similar modification    were to be adopted by the FASB, a successful challenge by the IRS to the    tax treatment of the leases referred to above,

156

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

or a settlement with the IRS, could trigger    a lease repricing. Further, such a successful challenge or settlement may    cause the lease to fail to qualify for leveraged lease accounting. It is    presently unclear what modifications, if any, will be adopted by the FASB,    the timing of any such modification and the effect of any such modification    on the operating results or financial position of PSEG or Energy Holdings.

      **PSEGandPSE&G**

      ***Placement of Gas Meters***

      In 2003, a proposed class action lawsuit was filed against PSE&G and PSEG in the Superior Court of New Jersey alleging that PSE&G's installation of outdoor gas meters within three feet of driveways or garages at residential locations is negligent. The suit also requested the court to order PSE&G to establish a fund for the purpose of remediating the allegedly improper meter installations. In June 2004, the parties to the lawsuit entered into a settlement in which PSE&G committed to enhance the protection of certain identified outdoor gas meter sets over a three-year period. PSE&G anticipates that the cost of such work will not be material. As a result of this settlement, the claims were dismissed with prejudice.

      ***Energy Holdings***

      ***Electroandes***

      In November 2002, the Peruvian Government created a subsidy in favor of the construction of the Camisea gas pipeline, in the form of a surcharge to the electric transmission tariffs paid by all end users. Two of Electroandes' largest customers (representing about 67% of its contracted capacity) refused to pay the surcharge, thus preventing Electroandes, in its role as collection agent, from transferring the associated funds to the beneficiaries of the surcharge. In July 2003, Electroandes made a filing with the courts to determine which party was responsible for payment of this subsidy. Subsequent to this filing, the dispute was favorably resolved with the customers and the local electric regulatory agency. Electroandes requested a withdrawal of its filing, which was granted during the first quarter of 2004, effectivelyputting an end to the issue.

      ***RGE***

      The governing tax authority in Brazil has claimed past due taxes from RGE plus penalties and interest for the periods 1998 to 2004 primarily related to claims that the goodwill tax amortization period used by RGE for several years resulted in higher than allowed tax deductions. Global's share of the maximum claim amount related to these tax issues is approximately $30 million. RGE believes it has valid legal defenses to these claims, although no assurances can be given.

      ***LDS***

      The Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, has claimed past due taxes for the period between 1999-2001, plus penalties and interest, resulting from an interpretation of the law that allowed LDS to restate its assets to fair market value for tax purposes and take advantage of the resulting higher tax deductions from depreciation. SUNAT also claimed past due taxes, penalties and interest for the 1996-1998 periods related to this issue.

      SUNAT claimed that the revaluation appraisal, performed in 1994, was not performed correctly and was therefore invalid. It is LDS's position that laws and regulations did not define the methodology to be used in these matters and its study was based on generally accepted practices and the only constraint was not to exceed market value. Global's share of the net unrecorded potential liability related to the claim by SUNAT is estimated at $8 million. LDS has not accepted the SUNAT valuation, but has challenged SUNAT's study that included no value for large components of LDS's system and under valued other components in LDS's view. The Fiscal Court ruled on December 7, 2004 and notified LDS on January 4, 2005 that a decision could not be based on the SUNAT studies and ordered another valuation study tobe performed by Consejo Nacional de Tasaciones (CONATA), a Government Agency in Peru. LDS believes that it will prevail, however, no assurances can be given as to the ultimate outcome of this matter.

157

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      ***Dhofar Power Company S.A.O.C. (Dhofar Power)***

      Since commencing operations in Oman in May 2003, Dhofar Power has experienced a number of service interruptions, including four service interruptions in the first half of 2004, which resulted from a combination of force majeure events and breaches of general warranties of the contractors that installed equipment at Dhofar Power. The Concession Agreement includes a provision for penalties to be paid in some circumstances to the Government of Oman for certain types of service interruptions. Dhofar Power and the Government of Oman are in dispute regarding both the applicability and extent of any such penalties arising from the service interruptions in question here. Dhofar Power and the Government of Oman are pursuing alternative dispute resolution and it is expected that the matter will be resolved in 2005. Dhofar Power believesthat cash retentions, letters of credit and a guarantee bond provided by the contractors should be sufficient to cover the potential penalty claims.

      Dhofar Power and the Government of Oman are in a disagreement on the calculation of certain monthly allowances to be paid to the Dhofar Power to compensate for enhancements and extensions of the transmission and distribution system in Salalah. Dhofar Power maintains that, according to the Concession Agreement, these allowances should be calculated based on actual contracted value of the services executed and the Government of Oman maintains that they should be calculated based on the lower estimated executed value. Dhofar Power is accruing this revenue at the values it calculated according to contract terms. Dhofar Power and the Government of Oman are pursuing alternative dispute resolution and it is expected that the matter will be resolved within the next 12 months. In the event the Government of Oman prevails, the annualloss of revenue to Dhofar Power would be approximately $0.6 million (at current exchange rate) for 15 years from December 28, 2003.

**Minimum Lease Payments**

      **PSEG, PSE&G, Services and Energy Holdings**

      PSE&G, Services and Energy Holdings lease administrative office space under various operating leases. For the years ended December 31, 2004, 2003 and 2002, PSEG's lease expenses were approximately $10 million per year, primarily related to Energy Holdings. Total future minimum lease payments as of December 31, 2004 are:
   **2005** **2006** **2007** **2008** **2009** **After2009** **Total**   **(Millions)**      
**PSE&G**
    $3     $3     $2     $1     $—     $—     $9       
**Services**
     1      1      1      1      1      2      7       
**Energy Holdings**
     3      2      2      2      2      4      15                                                                                     
**Total PSEG**
    $7     $6     $5     $4     $3     $6     $31                                             
      Power and Services have entered into capital leases for administrative office space. The total future minimum payments and present value of these capital leases as of December 31, 2004 are:
   **Services** **Power**   **(Millions)**            
2005
    $7     $1             
2006
     7      1             
2007
     7      2             
2008
     7      2             
2009
     7      2             
Thereafter
     44      9                           
Total Minimum Lease Payments
    $79     $17             
Less: Imputed Interest
     (41)     (5)                          
Present Value of Net Minimum Lease Payments
    $38     $12               
158

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Note 15. Nuclear Decommissioning**

**Power**

      In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning.

      For information relating to cost responsibility for nuclear decommissioning subsequent to July 31, 2003, see Note 3. Asset Retirement Obligations.

      Power maintains the external master nuclear decommissioning trust previously established by PSE&G. This trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a “qualified” fund. In the most recent study of the total cost of decommissioning, Power's share related to its five nuclear units was estimated at approximately $2.1 billion, including contingencies.

      Power's policy is that, except for investments tied to market indexes or other non-nuclear sector common trust funds or mutual funds (e.g., an S&P 500 mutual fund), assets of the trust shall not be invested in the securities or other obligations of PSEG or its affiliates, or its successors or assigns; and assets shall not be invested in securities of any entity owning one or more nuclear power plants.

      Effective January 1, 2003, Power began accounting for the assets in the NDT Funds under SFAS 115. Power classifies investments in the NDT Funds as available-for-sale under SFAS 115. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the NDT Funds.
  **As of December 31, 2004**  **Cost** **GrossUnrealizedGains** **GrossUnrealizedLosses** **EstimatedFairValue**  **(Millions)**
Equity Securities
    $488     $200     $(8)    $680 
Debt Securities
                
Government Obligations
     166      4      (1)     169 
Other Debt Securities
     172      8      (2)     178                          
Total Debt Securities
     338      12      (3)     347                          
Other Securities
     59      1      (1)     59                          
Total Available-for-Sale Securities
    $885     $213     $(12)    $1,086                            **As of December 31, 2003**  **Cost** **GrossUnrealizedGains** **GrossUnrealizedLosses** **EstimatedFairValue**  **(Millions)**
Equity Securities
    $447     $186     $(14)    $619 
Debt Securities
                
Government Obligations
     136      3      (1)     138 
Other Debt Securities
     200      11      (5)     206                          
Total Debt Securities
     336      14      (6)     344                          
Other Securities
     25      —      (3)     22                          
Total Available-for-Sale Securities
    $808     $200     $(23)    $985                          
159

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
   **Years EndedDecember 31,**   **2004** **2003** **2002**   **(Millions)**            
Proceeds from Sales
    $2,637     $1,229     $491             
Gross Realized Gains
    $126     $115     $45             
Gross Realized Losses
    $43     $64     $62 
      Net realized gains of $83 million were recognized in Other Income and Other Deductions on Power's Consolidated Statement of Operations for the year ended December 31, 2004. Net unrealized gains of $101 million were recognized in OCI on Power's Consolidated Balance Sheet as of December 31, 2004. Of the $12 million of the gross 2004 unrealized losses, $8 million has been in an unrealized loss position for less than twelve months. The available-for-sale debt securities held as of December 31, 2004, had the following maturities: $45 million less than one year, $70 million one to five years, $126 million five to 10 years, $31 million 10 to 15 years, $12 million 15 to 20 years, and $63 million over 20 years. The cost of these securities was determined on the basis of specific identification.

      The fair    value of securities in an unrealized loss position as of December 31,    2004 was approximately $172 million. The unrealized losses were primarily    caused by interest rate movements and fluctuations in the market. Based on    Power's evaluations and its ability and intentto hold such investments for a reasonable period of time sufficient for an projectedrecovery of fair value, Power does not consider these investments to be other-than-temporarilyimpaired as of December 31, 2004.

160

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Note 16. Other Income and Deductions
**Other Income**
  **PSE&G** **Power** **EnergyHoldings** **Other(A)** **ConsolidatedTotal**  **(Millions)**
**For the Year Ended December 31, 2004:**
                    
Interest Income
    $10     $9     $—     $—     $19 
NDT Fund Realized Gains
     —      126      —      —      126 
NDT Interest and Dividend Income
     —      28      —      —      28 
Other
     2      3      4      (6)     3                                
Total Other Income
    $12     $166     $4     $(6)    $176                                
**For the Year Ended December 31, 2003:**
                    
Interest Income
    $(7)    $8     $—     $3     $4 
Gain on Disposition of Property
     12      —      —      —      12 
NDT Fund Realized Gains
     —      115      —      —      115 
NDT Interest and Dividend Income
     —      26      —      —      26 
Foreign Currency Gains
     —      —      16      —      16 
Other
     1      —      4      —      5                                
Total Other Income
    $6     $149     $20     $3     $178                                
**For the Year Ended December 31, 2002:**
                    
Interest Income
    $4     $1     $—     $—     $5 
Gain on Disposition of Property
     10      —      —      —      10 
Change in Derivative Fair Value
     —      —      11      —      11 
Gain on Early Retirement of Debt
     —      —      14      —      14 
Minority Interest
     —      —      —      1      1 
Other
     1      —      1      (4)     (2)                               
Total Other Income
    $15     $1     $26     $(3)    $39                                
161

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
                    
**Other Deductions**
  **PSE&G** **Power** **EnergyHoldings** **Other(A)** **ConsolidatedTotal**  **(Millions)**
**For the Year Ended December 31, 2004:**
                    
Donations
    $1     $—     $—     $—     $1 
NDT Fund Realized Losses and Expenses
     —      49      —      —      49 
Loss on Disposition of Property
     —      1      —      —      1 
Loss on Early Retirement of Debt
     —      —      3      —      3 
Foreign Currency Losses
     —      —      27      —      27 
Minority Interest
     —      —      —      1      1 
Change in Derivative Fair Value
     —      —      3      —      3 
Other
     —      7      —      1      8                                
Total Other Deductions
    $1     $57     $33     $2     $93                                
**For the Year Ended December 31, 2003:**
                    
Donations
    $1     $—     $—     $4     $5 
NDT Fund Realized Losses and Expenses
     —      77      —      —      77 
Minority Interest
     —      —      —      13      13 
Change in Derivative Fair Value
     —      —      5      —      5 
Other
     —      1      —      —      1                                
Total Other Deductions
    $1     $78     $5     $17     $101                                
**For the Year Ended December 31, 2002:**
                    
Donations
    $2     $1     $—     $—     $3 
Foreign Currency Losses
     —      —      77      —      77                                
Total Other Deductions
    $2     $1     $77     $—     $80                                                       (A)   Other primarily consists of activity at PSEG (parent company), Services and intercompany eliminations.
162

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Note 17. Income Taxes
      A reconciliation of reported income tax expense with the amount computed by multiplying pre-tax income by the statutory Federal income tax rate of 35% is as follows:
  **PSE&G** **Power** **EnergyHoldings** **Other** **ConsolidatedTotal**  **(Millions)**
**2004**
                    
Net Income (Loss)
    $342     $308     $125     $(49)    $726 
Gain from Discontinued Operations, (Including Gain on Disposal)
     —      —      5      —      5 
Minority Interest in Earnings of Subsidiaries
     —      —      (1)     —      (1)                               
Income from Continuing Operations, less Preferred Dividends
     342      308      121      (49)     722 
Preferred Dividends (net)
     (4)     —      (16)     16      (4)                               
Income (Loss) from Continuing Operations excluding Minority Interest and Preferred Dividends
    $346     $308     $137     $(65)    $726                                
**Income Taxes:**
                    
Federal—Current
     255      3      (92)     (35)     131 
             Deferred
     (67)     142      164      3      242 
             ITC
     (3)     —      (1)     —      (4)                               
Total Federal
     185      145      71      (32)     369                                
State—Current
     72      15      4      —      91 
          Deferred
     (11)     26      (40)     (2)     (27)                               
Total State
     61      41      (36)     (2)     64                                
Foreign—Deferred
     —      —      13      —      13                                
Total Foreign
     —      —      13      —      13                                
Total
     246      186      48      (34)     446                                
Pre-tax Income
    $592     $494     $185     $(99)    $1,172                                
Tax computed at the statutory rate
    $207     $173     $65     $(35)    $410 
Increase (decrease) attributable to flow through of certain tax adjustments:
                    
Plant Related Items
     5      —      —      —      5 
Amortization of investment tax credits
     (3)     —      (1)     —      (4)
Tax Reserves
     —      (18)     17      —      (1)
Other
     (3)     4      (1)     2      2 
Lease Rate Differential
     —      —      (8)     —      (8)
State Income Tax (net of Federal Income Tax)
     40      27      (24)     (1)     42                                
Subtotal
     39      13      (17)     1      36                                
Total income tax provisions
    $246     $186     $48     $(34)    $446                                
Effective income tax rate
     41.6%     37.6%     25.9%     34.3%     38.1%
163

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
                      **PSE&G** **Power** **EnergyHoldings** **Other** **ConsolidatedTotal**  **(Millions)**
**2003**
                    
Net Income (Loss)
    $225     $844     $122     $(31)    $1,160 
Extraordinary Item, net of tax benefit
     (18)     —      —      —      (18)
Loss from Discontinued Operations, (Including Loss on Disposal, net of tax benefit—$8)
     —      —      (44)     —      (44)
Cumulative Effect of a Change in Accounting Principle, (net of tax expense—$255)
     —      370      —      —      370 
Minority Interest in Earnings of Subsidiaries
     —      —      (13)     —      (13)                               
Income from Continuing Operations, less Preferred Dividends
     243      474      179      (31)     865 
Preferred Dividends (net)
     (4)     —      (23)     23      (4)                               
Income (Loss) from Continuing Operations excluding Minority Interest and Preferred Dividends
    $247     $474     $202     $(54)    $869                                
**Income Taxes:**
                    
Federal—Current
     1      134      (299)     (43)     (207)
             Deferred
     91      121      331      4      547 
             ITC
     (2)     —      (1)     —      (3)                               
Total Federal
     90      255      31      (39)     337                                
State—Current
     (2)     41      (57)     (10)     (28)
          Deferred
     41      30      70      (1)     140                                
Total State
     39      71      13      (11)     112                                
Foreign—Deferred
     —      —      15      —      15                                
Total Foreign
     —      —      15      —      15                                
Total
     129      326      59      (50)     464                                
Pre-tax Income
    $376     $800     $261     $(104)    $1,333                                
Tax computed at the statutory rate
    $131     $280     $91     $(36)    $466 
Increase (decrease) attributable to flow through of certain tax adjustments:
                    
Plant Related Items
     (18)     —      —      —      (18)
Amortization of investment tax credits
     (2)     —      (1)     —      (3)
Other
     (8)     (1)     1      (7)     (15)
Tax Effects Attributable to Foreign Operations
     —      —      (40)     —      (40)
State Income Tax (net of Federal Income Tax)
     26      47      8      (7)     74                                
Subtotal
     (2)     46      (32)     (14)     (2)                               
Total income tax provisions
    $129     $326     $59     $(50)    $464                                
Effective income tax rate
     34.3%     40.8%     22.6%     48.1%     34.8%
164

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
                      **PSE&G** **Power** **EnergyHoldings** **Other** **ConsolidatedTotal**  **(Millions)**
**2002**
                    
Net Income (Loss)
    $201     $468     $(413)    $(21)    $235 
Loss from Discontinued Operations, (Including Loss on Disposal, net of tax benefit—$28)
     —      —      (49)     —      (49)
Cumulative Effect of a Change in Accounting Principle, (net of tax benefit—$66)
     —      —      (121)     —      (121)
Minority Interest in Earnings of Subsidiaries
     —      —      1      —      1                                
Income from Continuing Operations, less Preferred Dividends
     201      468      (244)     (21)     404 
Preferred Dividends (net)
     (4)     —      (23)     23      (4)                               
Income (Loss) from Continuing Operations excluding Minority Interest and Preferred Dividends
    $205     $468     $(221)    $(44)    $408                                
**Income Taxes:**
                    
Federal—Current
     99      182      (102)     (25)     154 
             Deferred
     (22)     71      (24)     2      27 
             ITC
     (2)     —      (2)     —      (4)                               
Total Federal
     75      253      (128)     (23)     177                                
State—Current
     17      41      (1)     (7)     50 
          Deferred
     23      19      (27)     —      15                                
Total State
     40      60      (28)     (7)     65                                
Foreign—Current
     —      —      1      —      1 
             Deferred
     —      —      11      —      11                                
Total Foreign
     —      —      12      —      12                                
Total
     115      313      (144)     (30)     254                                
Pre-tax Income
    $320     $781     $(365)    $(74)    $662                                
Tax computed at the statutory rate
    $112     $273     $(128)    $(26)    $231 
Increase (decrease) attributable to flow through of certain tax adjustments:
                    
Plant Related Items
     (15)     —      —      —      (15)
Amortization of investment tax credits
     (2)     —      (1)     —      (3)
Other
     (6)     1      (4)     —      (9)
Tax Effects Attributable to Foreign Operations
     —      —      (2)     —      (2)
State Income Tax (net of Federal Income Tax)
     26      39      (9)     (4)     52                                
Subtotal
     3      40      (16)     (4)     23                                
Total income tax provisions
    $115     $313     $(144)    $(30)    $254                                
Effective income tax rate
     35.9%     40.1%     39.5%     40.5%     38.4%                    
165

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**PSEG, PSE&G, Power and Energy Holdings**

      Each of PSEG, PSE&G, Power and Energy Holdings provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from PSE&G's customers in the future. Accordingly, an offsetting regulatory asset was established. As of December 31, 2004, PSE&G had a regulatory asset of $366 million representing the tax costs expected to be recovered through rates based upon established regulatory practices which permit recovery of current taxes payable. This amount was determinedusing the enacted Federal income tax rate of 35% and State income tax rate of 9%.

      Energy    Holdings' effective tax rate differs from the statutory Federal income    tax rate of 35% primarily due to the imposition of state taxes and the fact    that Global accounts for many of its investments using the equity method    of accounting. As allowed under APB 23, “Accounting for Income Taxes—Special    Areas” and SFAS 109, Management has maintained a permanent reinvestment    strategy as it relates to Global's international investments. If Management    were to change that strategy, a deferred tax expense and deferred tax liability    would need to be recorded to reflect the expected taxes that would need to    be paid on Global's offshore earnings. As of December 31,    2004, undistributed foreign earnings were approximately $256 million. The    determination of the amount of unrecognized U.S. Federal deferred income    tax liabilityfor undistributed earnings is not practicable.

      The Jobs    Act, as discussed further in Note 2. Recent Accounting Standards, provides    a one-year window to repatriate earnings from foreign investments and claim    a special 85% dividends received tax deduction on such distributions. The    range of undistributed earnings that PSEG could consider for possible repatriation    under the Jobs Act is between $0 and $256 million, which would result in    additional income tax expense between $0 and $15 million. On January 13,    2005 the IRS published Notice 2005-10, which discusses some of the rules    that    pertain    to this deduction.    Whether PSEG will ultimately take advantage of this provision, all or in    part, depends on a number of factors including but not limited to evaluating    the impact of Notice 2005-10 and any future authoritative guidance. Management    has made no change in its current intention to indefinitely reinvest  accumulated    earnings of its foreign subsidiaries. PSEG and Energy Holdings are currently    evaluating the impacts of the entire Act, which could have a material impact    on their financial condition, results of operations and cash flows.

      As of December 31, 2004, there is a capital loss carryforward of $78 million which will expire by 2007 unless utilized by PSEG. Since PSEG expects to fully realize this amount, no valuation allowance is necessary.

166

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

The following is an analysis of deferred income taxes:
  **PSE&G** **Power** **EnergyHoldings** **Other** **Consolidated**  **2004** **2003** **2004** **2003** **2004** **2003** **2004** **2003** **2004** **2003**  **(Millions)**
**Deferred Income Taxes**
                                        
Assets:
                                        
Current (net)
  $19   $17   $—   $—   $—   $—   $—   $—   $19   $17                                          
Noncurrent:
                                        
Unrecovered Investment Tax Credits
   18    19    —    —    —    —    —    —    18    19 
SFAS 133
   —    —    103    21    33    47    8    7    144    75 
Other Comprehensive Income
   2    2    —    —    —    (1)   2    2    4    3 
New Jersey Corporate Business Tax
   182    189    75    102    (42)   (60)   —    (1)   215    230 
OPEB
   129    110    —    —    —    —    (2)   —    127    110 
Cost of Removal
   —    —    51    51    —    —    —    —    51    51 
Conservation Costs
   30    —    —    —    —    —    —    —    30    — 
Investment Related Adjustment
   —    12    —    —    32    118    —    —    32    130 
Development Fees
   —    —    —    —    17    18    —    —    17    18 
Foreign Currency Translation
   —    —    —    —    31    35    —    —    31    35 
Contractual Liabilities and Environmental Costs
   —    —    35    35    —    —    —    —    35    35 
Market Transition Charge
   11    11    —    —    —    —    —    —    11    11 
Other
   —    (1)   —    18    23    —    4    —    27    17                                          
Total Noncurrent
   372    342    264    227    94    157    12    8    742    734                                          
Total Assets
   391    359    264    227    94    157    12    8    761    751                                          
Liabilities:
                                        
Noncurrent:
                                        
Plant Related Items
   1,382    1,295    (82)   (156)   —    —    2    —    1,302    1,139 
Nuclear Decommissioning
   —    —    74    18    —    —    —    —    74    18 
Securitization
   1,323    1,414    —    —    —    —    —    —    1,323    1,414 
Leasing Activities
   —    —    —    —    1,564    1,509    —    —    1,564    1,509 
Partnership Activities
   —    —    —    —    48    96    —    —    48    96 
Conservation Costs
   —    68    —    —    —    —    —    —    —    68 
Energy Clause Recoveries
   33    —    —    —    —    —    —    —    33    — 
Pension Costs
   77    75    19    (3)   —    —    23    17    119    89 
SFAS 143
   —    —    325    337    —    —    —    —    325    337 
Taxes Recoverable Through Future Rates (net)
   155    156    —    —    —    —    —    —    155    156 
Income from Foreign Operations
   —    —    —    —    63    31    —    —    63    31 
Other
   5    18    16    2    —    1    —    5    21    26                                          
Total Noncurrent
   2,975    3,026    352    198    1,675    1,637    25    22    5,027    4,883                                          
Total Liabilities
   2,975    3,026    352    198    1,675    1,637    25    22    5,027    4,883                                          
Summary—Accumulated Deferred Income Taxes:
                                        
Net Current Assets
   19    17    —    —    —    —    —    —    19    17 
Net Noncurrent Liability
   2,603    2,684    88    (29)   1,581    1,480    13    14    4,285    4,149                                          
Total
  $2,584   $2,667   $88   $(29)  $1,581   $1,480   $13   $14   $4,266   $4,132                                          
ITC
   50    53    6    7    6    7    —    —    62    67 
Current Portion of FAS 109 Transferred
   19    17    —    —    —    —    —    —    19    17                                          
Total Deferred Income Taxes and ITC
  $2,653   $2,737   $94   $(22)  $1,587   $1,487   $13   $14   $4,347   $4,216                                          
167

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
                                        
**Note 18. Pension, Other Postretirement Benefits (OPEB) and Savings Plans**

**PSEG**

      PSEG sponsors    several qualified and nonqualified pension plans and other postretirement    benefit plans covering PSEG's    and its participating affiliates, current and former employees who meet certaineligibility criteria.

      **Plan Assets**

      The following table provides the percentage of fair value of total plan assets for each major category of plan assets held as of the measurement date, December 31.
   **As of December 31,**      **Investments** **2004** **2003**      
Equity Securities
     64%          63%       
Fixed Income Securities
     28%          29%       
Real Estate Assets
     5%          5%       
Other Investments
     3%          3%                         
Total Percentage
     100%          100%                                 
      PSEG utilizes    an independent pension consultant to forecast returns, risk, and correlation    of all asset classes in order to develop an optimal portfolio, which is designed    to produce the maximum return opportunity per unit of risk. In 2002, PSEG    completed its latest asset/liability study. The results from the study indicated    that, in order to achieve the optimal risk/return portfolio, target allocations    of 62% equity securities, 30% fixed income securities, 5% real estate investments,    and 3% for other investments should be maintained. Derivative financial instruments    are used by the plans' investment managers primarily to rebalance the fixed    income/equity allocation of the portfolio and hedge the currency risk component    of the foreign investments.

      The expected    long-term rate of return on plan assets was 8.75% as of December 31,    2004. For 2005, the expected long-term rate of return on plan assets will    remain at 8.75%. This expected return was determined based on the study discussed    above and considered the plans' historical annualized rate of return    since inception of the plans, which was an annualized return of 10.3%.

      **Plan Contributions**

      PSEG anticipates contributing approximately $83 million into its qualified pension plans for calendar year 2005.

      **Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Medicare Act)**

      For information relating to the accounting impacts of the Medicare Act, see Note 2. Recent Accounting Standards.

      **Accumulated Benefit Obligations**

      The accumulated benefit obligations of all PSEG's defined benefit pension plans as of December 31,2004 and 2003 were $3.0 billion and $2.7 billion, respectively.

168

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      The following table provides a reconciliation of the changes in the fair value of plan assets over each of the two years in the period ended December 31, 2004 and a reconciliation of the funded status at the end of both years.

      **Pension and Other Postretirement Benefit Plans**
  **Pension Benefits** **Other Benefits**  **2004** **2003** **2004** **2003**  **(Millions)**
*Change in Benefit Obligation:*
                
Benefit Obligation at Beginning of Year
    $3,235     $2,968     $916     $777 
Service Cost
     82      74      22      21 
Interest Cost
     197      195      55      51 
Actuarial Loss
     216      158      47      117 
Benefits Paid
     (178)     (160)     (52)     (50)                         
Benefit Obligation at End of Year
     3,552      3,235      988      916                          
*Change in Plan Assets:*
                
Fair Value of Assets at Beginning of Year
     2,696      2,131      77      51 
Actual Return on Plan Assets
     306      514      10      13 
Employer Contributions
     96      211      66      63 
Benefits Paid
     (178)     (160)     (52)     (50)                         
Fair Value of Assets at End of Year
     2,920      2,696      101      77                          
*Reconciliation of Funded Status:*
                
Funded Status
     (632)     (539)     (887)     (839)
Unrecognized Net
                
Transition Obligation
     —      —      194      221 
Prior Service Cost
     71      94      —      — 
Loss
     894      784      131      87                          
Net Amount Recognized
    $333     $339     $(562)    $(531)                         
*Amounts Recognized in Statement of Financial Position:*
                
Prepaid Benefit Cost
    $383     $379     $—     $— 
Accrued Cost
     (82)     (67)     (562)     (531)
Intangible Asset
     11      14      N/A      N/A 
Accumulated Other Comprehensive Income (pre-tax)
     21      13      N/A      N/A                          
Net Amount Recognized
    $333     $339     $(562)    $(531)                         
*Separate Disclosure for Pension Plans With an Accumulated Benefit Obligation in Excess of Plan Assets:*
                
Projected Benefit Obligation at End of Year
    $91     $86         
Accumulated Benefit Obligation at End of Year
    $81     $67         
Fair Value of Assets at End of Year
    $—     $—         
169

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
                
      The pension  benefits table above provides information relating to the funded status of all  qualified and nonqualified pension plans and other postretirement benefit plans  on an aggregate basis. The nonqualified pension plans are partially funded with  Rabbi Trusts. In accordance with SFAS 87, the plan assets in the table above  do not include the assets held in the Rabbi Trust. The fair value of these assets  are included on the Consolidated Balance Sheets. For additional information,  see Rabbi Trusts, below.
  **Pension Benefits** **Other Benefits**  **2004** **2003** **2002** **2004** **2003** **2002**  **(Millions)**
*Components of Net Periodic Benefit Cost:*
                        
Service Cost
    $82     $74     $69     $22     $21     $19 
Interest Cost
     197      195      188      55      51      47 
Expected Return on Plan Assets
     (231)     (193)     (206)     (7)     (5)     (4)
Amortization of Net
                        
Transition Obligation
     —      5      8      27      27      27 
Prior Service Cost
     16      17      17      —      —      — 
Loss/(Gain)
     38      49      13      —      (3)     (4)                                     
Net Periodic Benefit Cost
    $102     $147     $89     $97     $91     $85                                      
*Components of Total Benefit Expense:*
                        
Net Periodic Benefit Cost
    $102     $147     $89     $97     $91     $85 
Effect of Regulatory Asset
     —      —      —      19      19      19                                      
Total Benefit Expense Including Effect of Regulatory Asset
    $102     $147     $89     $116     $110     $104                                      
*Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31:*
                        
Discount Rate
     6.25%     6.75%     7.25%     6.25%     6.75%     7.25%
Expected Return on Plan Assets
     8.75%     9.00%     9.00%     8.75%     9.00%     9.00%
Rate of Compensation Increase
     4.69%     4.69%     4.69%     4.69%     4.69%     4.69%
*Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31:*
                        
Discount Rate
     6.00%     6.25%     6.75%     6.00%     6.25%     6.75%
Rate of Compensation Increase
     4.69%     4.69%     4.69%     4.69%     4.69%     4.69%
Rate of Increase in Health Benefit Costs
                        
Administrative Expense
                 5.00%     5.00%     5.00%
Dental Costs
                 6.00%     6.00%     6.00%
Pre-65 Medical Costs
                        
Immediate Rate
                 10.00%     9.00%     9.00%
Ultimate Rate
                 5.00%     6.00%     6.00%
Year Ultimate Rate Reached
                 2010      2009      2008 
Post-65 Medical Costs
                        
Immediate Rate
                 11.00%     7.00%     7.00%
Ultimate Rate
                 5.00%     6.00%     6.00%
Year Ultimate Rate Reached
                 2011      2005      2004 
*Effect of a Change in the Assumed Rate of Increase in Health Benefit Costs:*
                        
Effect of a 1% Increase On
                        
Total of Service Cost and Interest Cost
                $4     $4     $5 
Postretirement Benefit Obligation
                $57     $51     $46 
Effect of a 1% Decrease On
                        
Total of Service Cost and Interest Cost
                $(3)    $(5)    $(4)
Postretirement Benefit Obligation
                $(50)    $(59)    $(39)
170

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
                        
**Cash Flows**

      **Estimated Future Benefit Payments (Reflecting Expected Future Service)**

      The following benefit payments, which reflect expected future service, are expected to be paid:
            **Year** **PensionBenefits** **OtherBenefits**   **(Millions)**            
2005
    $174     $65             
2006
     179      65             
2007
     184      68             
2008
     190      71             
2009
     197      74             
2010–2014
     1,121      391                           
Total
    $2,045     $734                                   
      **Rabbi Trusts**

      PSEG maintains certain unfunded, nonqualified benefit plans for which certain assets have been set aside in grantor trusts commonly known as “Rabbi Trusts” to provide supplemental retirement and deferred compensation benefits to certain of its and its subsidiaries' key employees and directors.

      Effective January 1, 2003, PSEG began accounting for the assets in the Rabbi Trusts under SFAS 115. PSEG classifies investments in the Rabbi Trusts as available-for-sale under SFAS 115. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trusts.
  **As of December 31, 2004**  **Cost** **GrossUnrealizedGains** **GrossUnrealizedLosses** **EstimatedFair Value**  **(Millions)**
Equity Securities
    $11     $1     $—     $12 
Debt Securities
                
Government Obligations
     57      —      —      57 
Other Debt Securities
     26      —      —      26                          
Total Debt Securities
     83      —      —      83                          
Other Securities
     11      —      —      11                          
Total Available-for-Sale Securities
    $105     $1     $—     $106                                            **As of December 31, 2003**  **Cost** **GrossUnrealizedGains** **GrossUnrealizedLosses** **EstimatedFair Value**  **(Millions)**
Equity Securities
    $9     $2     $—     $11 
Debt Securities
                
Government Obligations
     72      1      —      73 
Other Debt Securities
     —      —      —      —                          
Total Debt Securities
     72      1      —      73                          
Other Securities
     9      —      —      9                          
Total Available-for-Sale Securities
    $90     $3     $—     $93                          
171

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
                   **Years EndedDecember 31,**   **2004** **2003** **2002**   **(Millions)**      
Proceeds from Sales
    $95     $15     $74       
Gross Realized Gains
    $3     $—     $—       
Gross Realized Losses
    $1     $—     $—                   
      Net realized gains of $2 million were recognized in Other Income and Other Deductions on PSEG's Consolidated Statement of Operations for the year ended December 31, 2004. Net unrealized gains of $1 million were recognized in OCI on PSEG's Consolidated Balance Sheet as of December 31, 2004. The available-for-sale debt securities held as of December 31, 2004, had the following maturities: $12 million less than one year, $25 million one to five years, $18 million five to 10 years, $7 million 10 to 15 years, $4 million 15 to 20 years, and $26 million over 20 years. The cost of these securities was determined on the basis of specific identification.

      The estimated  fair values of the Rabbi Trusts related to PSEG, PSE&G, Power and Energy Holdings  are detailed as follows:

 

**As        of**

**December        31,**

 

**2004**

 

**2003**

PSE&G 

$

49

 

$

45

Power                                                                                                                                                                                                                                                                                                                                                            

 

20

** **

 

15

Energy Holdings                                                                                                                                                                                                                                                                                                   

 

9

** **

 

9

Services                                                                                                                                                                                                                                                                                                                                                

 

28

** **

 

24

Total                                                                                                                                                                                                                                                                                                                                                                 

$

106

** **

$

93

 

      **401(k) Plans**

      PSEG sponsors two 401(k) plans, which are Employee Retirement Income Security Act (ERISA) defined contribution plans. Eligible represented employees of PSE&G, Power and Services participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSE&G, Power, Energy Holdings and Services participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans. Employee contributions up to 7% for Savings Plan participants and up to 8% for Thrift Plan participants are matched with Employer contributions of cash equal to 50% of such employee contributions. For periods prior to March 1, 2002, Employer contributions, related to participant contributions in excess of 5% and up to 7%, were made in sharesof PSEG Common Stock for Savings Plan participants. For periods prior to March 1, 2002, Employer contributions, related to participant contributions in excess of 6% and up to 8%, were made in shares of PSEG Common Stock for Thrift Plan participants. The shares for these contributions were purchased in the open market. Since that time, all Employer contributions have been made in cash. The amount paid for Employer matching contributions to the plans for PSEG, PSE&G, Power and Energy Holdings are detailed as follows:
   **Thrift Plan and Savings Plan**   **Years EndedDecember 31,**   **2004** **2003** **2002**      
PSE&G
    $15     $13     $13       
Power
     8      9      8       
Energy Holdings
     1      1      1       
Services
     3      2      3                           
Total Employer matching contributions
    $27     $25     $25                                       
172

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      **PSEG, PSE&G, Power and Energy Holdings**

      Eligible employees of PSE&G, Power, Energy Holdings and Services participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG's two defined contribution plans described above. Pension costs and OPEB costs for PSEG, PSE&G, Power and Energy Holdings are detailed as follows:
   **Pension Benefits** **Other Benefits**   **Years EndedDecember 31,** **Years EndedDecember 31,**   **2004** **2003** **2002** **2004** **2003** **2002**   **(Millions)**         
PSE&G
    $52     $79     $46     $104     $100     $95          
Power
     31      46      26      9      8      6          
Energy Holdings
     2      4      2      —      —      —          
Services
     17      18      15      3      2      3                                                
Total Benefit Expense
    $102     $147     $89     $116     $110     $104                                                                        
**Note 19. Stock Options and Employee Stock Purchase Plan**

**PSEG**

      **Stock Options**

      As approved at the Annual Meeting of Stockholders in 2004, PSEG's 2004 Long-Term Incentive Plan (2004 LTIP) replaced prior Long-Term Incentive Plans (the 1989 LTIP and 2001 LTIP). The 2004 LTIP is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as qualified and non-qualified stock options, stock appreciation rights, performance shares and restricted stock.

      Under the 2004 LTIP, non-qualified options to acquire shares of PSEG Common Stock may be granted to officers and other key employees of PSEG, PSE&G, Power, Energy Holdings, Services and their respective subsidiaries selected by the Organization and Compensation Committee of PSEG's Board of Directors, the plan's administrative committee (Committee). There were approximately 12.9 million shares of Common Stock available for future grants under the prior plans, and those shares were made available under the 2004 LTIP. Approval of the 2004 LTIP did not increase the number of shares available for use in long-term incentive compensation. Grants of stock options with respect to approximately 7.1 million shares of Common Stock remain outstanding under the prior plans.

      Payment by option holders upon exercise of an option may be made in cash or, with the consent of the Committee, by delivering previously acquired shares of PSEG Common Stock. In instances where an optionee tenders shares acquired from a grant previously exercised that were held for a period of less than six months, an expense will be recorded for the difference between the fair market value at exercise date and the option price. Options are exercisable over a period of time designated by the Committee (but not prior to one year or longer than 10 years from the date of grant) and are subject to such other terms and conditions as the Committee determines. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control. Options may not be transferred during the lifetime of a holder.

      As of December 31, 2004, there were 12.4 million shares available for future awards under the 2004 LTIP.

      PSEG purchases shares on the open market to meet the exercise of stock options. The difference between the cost of the shares (generally purchased on the date of exercise) and the exercise price of the options has been reflected in Stockholders' Equity, except where otherwise discussed.

173

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

Changes in common shares under option for the three fiscal years in the period ended December 31, 2004 are summarized as follows:
   **2004** **2003** **2002**   **Options** **WeightedAverageExercisePrice** **Options** **WeightedAverageExercisePrice** **Options** **WeightedAverageExercisePrice**      
Beginning of year
     8,734,931     $39.37      9,192,631     $39.32      7,652,463     $41.22       
Granted
     863,700      43.87      706,300      37.35      1,890,000      31.62       
Exercised
     (1,539,966)     38.49      (541,767)     32.76      (157,332)     36.28       
Canceled
     (367,763)     41.26      (622,233)     42.01      (192,500)     41.94                                             
End of year
     7,690,902     $39.97      8,734,931     $39.37      9,192,631     $39.32                                             
Exercisable at end of year
     5,612,528     $40.05      5,822,196     $40.44      4,542,165     $40.24                                             
Weighted average fair value of options granted during the year
        $6.58         $5.73         $4.37                                                                   
      The following table provides information about options outstanding as of December 31, 2004:
      **Options Outstanding** **Options Exercisable** **Range ofExercise Prices**  **Outstanding atDecember 31,2004** **WeightedAverageRemainingContractualLife** **WeightedAverageExercisePrice** **Exercisable atDecember 31,2004** **WeightedAverageExercisePrice**      
$
25.03–$30.02    115,000           3.0          $29.56           115,000          $29.56       
$
30.03–$35.03    2,141,733           7.4           32.18           1,421,825           32.14       
$
35.04–$40.03    388,500           4.0           39.31           388,500           39.31       
$
40.04–$45.04    2,932,169           7.4           41.74           2,048,203           41.46       
$
45.05–$50.05    2,113,500           6.5           46.09           1,639,000           46.06                                                               
$
25.03–$50.05    7,690,902           6.9          $39.97           5,612,528          $40.05                                                                                      
      The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for grants in 2004, 2003 and 2002, respectively: expected volatility of 26.74%, 29.68% and 30.24%, risk free interest rates of 3.09%, 2.86% and 2.82%, expected lives of 4.0 years, 4.4 years and 4.0 years. There was a weighted average dividend yield of 5.00% in 2004, 5.82% in 2003 and 6.84% in 2002.

**Stock Compensation**

      **Executive Officers**

      In June 1998, the Committee granted 150,000 shares of restricted Common Stock to a key executive. An additional 60,000 shares of restricted stock was granted to this executive in November 2001. These shares are subject to restrictions on transfer and subject to risk of forfeiture until earned by continued employment. The shares vest on a staggered schedule beginning on March 31, 2002 and become fully vested on March 31, 2007. As the shares vest, the earned compensation is recorded as compensation expense in the Consolidated Statements of Operations. The unearned compensation related to this restricted stock grant as of December 31, 2004 was approximately $1 million and is included in Stockholders' Equity on the Consolidated Balance Sheets.

      In addition, in July 2001, the Committee granted 100,000 shares of restricted common stock to another key executive. These shares are subject to restrictions on transfer and subject to risk of forfeiture until earned by continued employment. The shares were fully vested on July 1, 2004.

      During the second quarter of 2004, 94,400 shares of restricted PSEG Common Stock were granted under the 2004 LTIP to certain key executives. These shares are subject to restrictions on transfer and subject to risk of forfeiture until vested by continued employment. The shares vest on a staggered schedule beginning

174

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

on December 31, 2004 and become fully vested on December 31, 2006. The unearned compensation related to these restricted stock grants as of December 31, 2004 was approximately $3 million and is included in Common Stockholders' Equity on the Consolidated Balance Sheets.

      In addition, 94,400 performance units were granted to certain key executives, which provide for payment in shares of PSEG Common Stock within 45 days of January 1, 2007 based on achievement of certain financial goals. The performance units are credited with dividend equivalents in an amount equal to dividends paid on PSEG Common Stock up until January 1, 2007. As of December 31, 2004, approximately 92,203 performance units were outstanding.

      **Outside Directors**

      During 2004, each director who was not an officer of PSEG or its subsidiaries and affiliates was paid an annual retainer of $40,000. Pursuant to the Compensation Plan for Outside Directors, a certain percentage, currently 50%, of the annual retainer is paid in PSEG Common Stock. In January 2003, PSEG amended the Compensation Plan for Outside Directors to provide for 100,000 shares of Common Stock to be used for awards to directors of PSEG who are not employees of PSEG or its subsidiaries.

      PSEG also maintains a Stock Plan for Outside Directors pursuant to which directors of PSEG who are not employees of PSEG or its subsidiaries receive a restricted stock award, currently 1,000 shares per year, for each year of service as a director. The restrictions on the stock granted under the Stock Plan for Outside Directors provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director's service were terminated after a “change in control” as defined in the Plan or if the director were to die in office. PSEG also has the ability to waive this restriction for good cause shown. Restricted stock may not be sold or otherwise transferredprior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director who has the right to vote the shares. The fair value of these shares is recorded as compensation expense in the Consolidated Statements of Operations.

      **Employee Stock Purchase Plan**

      PSEG maintains an employee stock purchase plan for all eligible employees of PSEG, PSE&G, Power, Energy Holdings and Services. Under the plan, shares of the PSEG Common Stock may be purchased at 95% of the fair market value through payroll deductions. Employees may purchase shares having a value not exceeding 10% of their base pay. During 2004, 2003 and 2002, employees purchased 85,766, 102,532 and 104,627 shares at an average price of $42.51, $40.00 and $36.41 per share, respectively. As of December 31, 2004, 1,965,809 shares were available for future issuance under this plan.

**Note 20. Financial Information by Business Segment**

**Basis of Organization**

      **PSEG, PSE&G, Power and Energy Holdings**

      The reportable segments were determined by management in accordance with SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information” (SFAS 131). These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how it allocates resources to each business.

      **Power**

      Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load serving entities and by bidding energy, capacity and ancillary services into the markets for these products. Power also enters into trading contracts for energy, capacity, firm transmission rights, gas, emission allowances and other energy related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations.

175

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      **PSE&G**

      PSE&G earns revenue from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.

      **Energy Holdings**

      ***Global***

      Global earns revenues from its investment in and operation of projects in the generation and distribution of energy, both domestically and internationally. Global has ownership interests in four distribution companies and has developed or acquired interests in electric generation facilities which sell energy, capacity and ancillary services to numerous customers. The generation plants sell power under long-term agreements as well as on a merchant basis while the distribution companies are rate-regulated enterprises. Revenues include revenues of consolidated investments.

      ***Resources***

      Resources earns revenues from its passive investments in leveraged leases, limited partnerships, leveraged buyout funds and marketable securities. Over 86% of Resources' investments are in energy industry related leveraged leases. DSM Investments were transferred to Resources on December 31, 2002 and earn revenues primarily from monthly payments from utilities, representing shared electricity savings from the installation of energy efficient equipment. Resources operates both domestically and internationally; however, revenues from all international investments are denominated in U.S. Dollars.

      ***Other***

      Energy Holdings' other activities include amounts applicable to Energy Holdings (parent company), the HVAC/operating companies of Energy Technologies, which were reclassified into discontinued operations in 2002 and sold in 2003, and EGDC. The net losses primarily relate to financing and certain administrative and general costs at the Energy Holdings parent corporation.

      **Other**

      PSEG's other activities include amounts applicable to PSEG (parent corporation), and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 23. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at the PSEG parent corporation.

176

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      Information    related to the segments of PSEG and its subsidiaries is detailed below:
          **Energy Holdings**          **Power** **PSE&G** **Resources** **Global** **Other** **Other** **ConsolidatedTotal**  **(Millions)**
**For the Year Ended December 31, 2004:**
                            
Total Operating Revenues
    $5,173     $6,972     $187     $831     $9     $(2,176)    $10,996 
Depreciation and Amortization
     121      523      5      52      —      18      719 
Income from Equity Method Investments
     —      —      1      125      —      —      126 
Operating Income (Loss)
     527      943      154      328      (13)     8      1,947 
Interest Income
     9      10      —      —      —      —      19 
Net Interest Charges
     142      362      81      170      4      100      859 
Income (Loss) Before Income Taxes
     494      592      71      128      (14)     (104)     1,167 
Income Taxes
     186      246      4      49      (5)     (34)     446 
Income (Loss) From Continuing Operations
     308      346      68      78      (10)     (69)     721 
Income from Discontinued Operations, net of tax
     —      —      —      5      —      —      5 
Net Income (Loss)
     308      346      68      83      (10)     (69)     726 
Segment Earnings (Loss)
     308      342      65      69      (9)     (49)     726 
Gross Additions to Long-Lived Assets
    $725     $428     $11     $89     $—     $16     $1,269 
**As of December 31, 2004:**
                            
Total Assets
    $8,597     $13,586     $2,999     $4,144     $52     $(171)    $29,207 
Investments in Equity Method Subsidiaries
    $—     $—     $41     $1,075     $—     $—     $1,116 
**For the Year Ended December 31, 2003:**
                            
Total Operating Revenues
    $5,613     $6,740     $238     $476     $11     $(1,939)    $11,139 
Depreciation and Amortization
     102      372      5      38      1      9      527 
Income from Equity Method Investments
     —      —      1      113      —      —      114 
Operating Income (Loss)
     843      761      206      263      (5)     11      2,079 
Interest Income
     8      (7)     —      —      —      3      4 
Net Interest Charges
     114      390      96      119      3      114      836 
Income (Loss) Before Income Taxes
     800      376      109      157      (5)     (121)     1,316 
Income Taxes
     326      129      37      23      (1)     (50)     464 
Income (Loss) From Continuing Operations
     474      247      72      121      (4)     (58)     852 
Loss from Discontinued Operations, net of tax
     —      —      —      (23)     (21)     —      (44)
Extraordinary Item, net of tax
     —      (18)     —      —      —      —      (18)
Cumulative Effect of a Change in AccountingPrinciple, net of tax
     370      —      —      —      —      —      370 
Net Income (Loss)
     844      229      72      98      (25)     (58)     1,160 
Segment Earnings (Loss)
     844      225      66      81      (25)     (31)     1,160 
Gross Additions to Long-Lived Assets
    $699     $411     $1     $306     $1     $21     $1,439 
**As of December 31, 2003:**
                            
Total Assets
    $7,735     $13,177     $3,278     $3,818     $368     $(292)    $28,084 
Investments in Equity Method Subsidiaries
    $—     $—     $94     $1,233     $4     $—     $1,331 
**For the Year Ended December 31, 2002:**
                            
Total Operating Revenues
    $3,640     $5,919     $248     $352     $9     $(1,948)    $8,220 
Depreciation and Amortization
     108      409      5      22      1      20      565 
Income from Equity Method Investments
     —      —      (1)     120      —      —      119 
Operating Income (Loss)
     903      713      213      (300)     (10)     4      1,523 
Interest Income
     1      4      —      —      —      —      5 
Net Interest Charges
     122      406      98      118      1      74      819 
Income (Loss) Before Income Taxes
     781      320      122      (476)     (11)     (77)     659 
Income Taxes
     313      115      38      (178)     (4)     (30)     254 
Income (Loss) From Continuing Operations
     468      205      84      (297)     (7)     (48)     405 
Loss        from Discontinued Operations, netof tax
     —      —      —      (9)     (40)     —      (49)
Cumulative Effect of a Change in AccountingPrinciple, net of tax
     —      —      —      (88)     (33)     —      (121)
Net Income (Loss)
     468      205      84      (395)     (79)     (48)     235 
Segment Earnings (Loss)
     468      201      78      (411)     (80)     (21)     235 
Gross Additions to Long-Lived Assets
    $1,046     $447     $32     $294     $14     $14     $1,847 
177

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
                            
      Geographic information for PSEG is disclosed below. The foreign assets and operations noted below relate solely to Energy Holdings.
  **Revenues** **Assets(A)**  **December 31,** **December 31,**  **2004** **2003** **2002** **2004** **2003**  **(Millions)**
United States
    $10,341     $10,588     $7,740     $24,923     $23,475 
Foreign Countries
     655      551      480      4,284      4,605                                
Total
    $10,996     $11,139     $8,220     $29,207     $28,080                                                    
**Identifiable assets in foreign countries include:**
        
Chile
    $1,279     $1,151 
Netherlands
     1,113      1,060 
Poland
     511      473 
Peru
     449      475 
Tunisia
     —      300 
China(B)
     —      202 
Oman
     269      282 
Brazil
     178      164 
Other
     485      498              
Total
    $4,284     $4,605                      
   (A)   Total assets are net of foreign      currency translation adjustment of $(129) million (after-tax) as of December 31,      2004 and $(193) million (after-tax) as of December 31, 2003.   (B)   Does not include the $136 million promissory note received from the sale of MPC. See Note 4. Discontinued Operations, Dispositions and Acquisitions.

      As of December    31, 2004, Global and Resources had approximately $2.9 billion and $1.4 billion,    respectively, of international assets. As of December 31, 2004, foreign assets    represented 15% and 60% of PSEG's and Energy Holdings' consolidated    assets, respectively, and the revenues related to those foreign assets contributed    6% and 67% to PSEG's and Energy Holdings' consolidated revenues,    respectively, for the year ended December 31, 2004.

178

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Note 21. Property, Plant and Equipment and Jointly-Owned Facilities**

      Information related to Property, Plant and Equipment as of December 31, 2004 and 2003 is detailed below:
   **PSE&G** **Power** **EnergyHoldings** **Other** **PSEGConsolidated**   **(Millions)**      
**2004**
                          
Generation:
                          
Fossil Production
    $—     $3,828     $1,359     $—     $5,187       
Nuclear Production
     —      399      —      —      399       
Nuclear Fuel in Service
     —      500      —      —      500       
Construction Work in Progress
     —      1,787      52      —      1,839                                       
Total Generation
     —      6,514      1,411      —      7,925                                       
Transmission and Distribution:
                          
Electric Transmission
     1,299      —      —      —      1,299       
Electric Distribution
     4,840      —      464      —      5,304       
Gas Transmission
     74      —      —      —      74       
Gas Distribution
     3,589      —      —      —      3,589       
Construction Work in Progress
     20      —      38      —      58       
Plant Held for Future Use
     21      —      —      —      21       
Other
     68      —      —      —      68                                       
Total Transmission and Distribution
     9,911      —      502      —      10,413                                       
Other
     245      63      171      304      783                                       
Total
    $10,156     $6,577     $2,084     $304     $19,121                                       
**2003**
                          
Generation:
                          
Fossil Production
    $—     $3,019     $719     $—     $3,738       
Nuclear Production
     —      332      —      —      332       
Nuclear Fuel in Service
     —      532      —      —      532       
Construction Work in Progress
     —      2,020      17      —      2,037                                       
Total Generation
     —      5,903      736      —      6,639                                       
Transmission and Distribution:
                          
Electric Transmission
     1,273      —      —      —      1,273       
Electric Distribution
     4,646      —      427      —      5,073       
Gas Transmission
     74      —      —      —      74       
Gas Distribution
     3,430      —      —      —      3,430       
Construction Work in Progress
     2      —      13      —      15       
Plant Held for Future Use
     20      —      —      —      20       
Other
     92      —      —      —      92                                       
Total Transmission and Distribution
     9,537      —      440      —      9,977                                       
Other
     256      77      176      271      780                                       
Total
    $9,793     $5,980     $1,352     $271     $17,396                                 
**PSE&G and Power**

      PSE&G and Power have ownership interests in and are responsible for providing their share of the necessary financing for the following jointly-owned facilities. All amounts reflect the share of PSE&G's and Power's jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses.

179

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
  **OwnershipInterest** **Plant** **AccumulatedDepreciation**      **(Millions)**
**December 31, 2004**
            
**Power:**
            
Coal Generating
            
Conemaugh
     22.50%     $208     $90 
Keystone
     22.84%     $170     $69 
Nuclear Generating
            
Peach Bottom
     50.00%     $248     $112 
Salem
     57.41%     $482     $192 
Nuclear Support Facilities
     Various      $65     $19 
Pumped Storage Facilities
            
Yards Creek
     50.00%     $28     $18 
Merrill Creek Reservoir
     13.91%     $1     $— 
**PSE&G:**
            
Transmission Facilities
     Various      $80     $36 
Linden SNG Plant
     90.00%     $5     $5 
**December 31, 2003**
            
**Power:**
            
Coal Generating
            
Conemaugh
     22.50%     $204     $83 
Keystone
     22.84%     $167     $62 
Nuclear Generating
            
Peach Bottom
     50.00%     $257     $115 
Salem
     57.41%     $435     $202 
Nuclear Support Facilities
     Various      $41     $16 
Pumped Storage Facilities
            
Yards Creek
     50.00%     $28     $16 
Merrill Creek Reservoir
     13.91%     $2     $— 
**PSE&G:**
            
Transmission Facilities
     Various      $80     $35 
Linden SNG Plant
     90.00%     $5     $5 
      **Power**

      Power holds undivided ownership interests in the jointly-owned facilities above, excluding related nuclear fuel and inventories. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power's share of expenses for the jointly-owned facilities is included in the appropriate expense category.

      Power's subsidiary, Nuclear, co-owns Salem and Peach Bottom with Exelon Generation. Nuclear is the owner-operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners reviews/approves major planning, financing and budgetary (capital and operating) decisions. Operating decisions within the above guidelines are made by the owner-operator.

      Reliant Resources is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by all co-owners makes all planning, financing and budgetary (capital and operating) decisions. Operating decisions within the above guidelines are made by Reliant Resources.

      Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. First Energy is also a co-owner and the operator of this facility. First Energy submits separate capital and Operations and Maintenance budgets, subject to the approval of Power.

180

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      Power is a minority owner in the Merrill Creek Reservoir. Merrill Creek Reservoir is the owner-operator of this facility. The operator submits separate capital and Operations and Maintenance budgets, subject to the approval of the non-operating owners.

      All owners receive revenues, Operations and Maintenance and capital allocations based on their ownership percentages. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.

**Note 22. Selected Quarterly Data (Unaudited)**

      The information shown below, in the opinion of PSEG, PSE&G, Power and Energy Holdings, includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts.
  **Calendar Quarter Ended**  **March 31,** **June 30,** **September 30,** **December 31,**  **2004** **2003** **2004** **2003** **2004** **2003** **2004** **2003**  **(Millions, where applicable)**
**PSEG Consolidated:**
                                
Operating Revenues
    $3,224     $3,291     $2,292     $2,403     $2,749     $2,780     $2,731     $2,665 
Operating Income
     663      693      334      418      607      525      343      443 
Income from Continuing Operations
     271      324      119      156      244      208      87      164 
(Loss)/Gain from Discontinued Operations,including Loss on Disposal, net of tax
     —      (13)     5      (5)     —      (1)     —      (25)
Extraordinary Item, net of tax benefit
     —      —      —      (18)     —      —      —      — 
Cumulative Effect of a Change in AccountingPrinciple
     —      370      —      —      —      —      —      — 
Net Income
     271      681      124      133      244      207      87      139 
Earnings Per Share:
                                
(Basic)
                                
Income from Continuing Operations
     1.15      1.44      0.50      0.69      1.03      0.92      0.37      0.70 
Net Income
     1.15      3.02      0.52      0.59      1.03      0.92      0.37      0.59 
(Diluted)
                                
Income from Continuing Operations
     1.14      1.43      0.50      0.69      1.03      0.91      0.36      0.69 
Net Income
     1.14      3.01      0.52      0.59      1.03      0.91      0.36      0.59 
Weighted Average Common Shares Outstanding:
                                
Basic
     236      225      237      226      237      226      238      235 
Diluted
     239      226      238      227      238      228      239      236   **Calendar Quarter Ended**  **March 31,** **June 30,** **September 30,** **December 31,**  **2004** **2003** **2004** **2003** **2004** **2003** **2004** **2003**  **(Millions)**
**PSE&G:**
                                
Operating Revenues
    $2,182     $2,148     $1,418     $1,342     $1,636     $1,530     $1,736     $1,720 
Operating Income
     313      245      182      108      245      202      203      206 
Income from Continuing Operations
     125      101      63      22      93      69      65      55 
Extraordinary Item, net of tax benefit
     —      —      —      (18)     —      —      —      — 
Net Income
     125      101      63      4      93      69      65      55 
Earnings Available to PSEG
     124      100      62      3      92      68      64      54   **Calendar Quarter Ended**  **March 31,** **June 30,** **September 30,** **December 31,**  **2004** **2003** **2004** **2003** **2004** **2003** **2004** **2003**  **(Millions)**
**Power:**
                                
Operating Revenues
    $1,695     $1,833     $995     $1,237     $1,131     $1,256     $1,352     $1,287 
Operating Income
     211      314      47      196      246      202      23      131 
Income from Continuing Operations
     109      177      52      109      131      110      16      78 
Cumulative Effect of a Change in AccountingPrinciple
     —      370      —      —      —      —      —      — 
Net Income
     109      547      52      109      131      110      16      78 
181

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
  **Calendar Quarter Ended**  **March 31,** **June 30,** **September 30,** **December 31,**  **2004** **2003** **2004** **2003** **2004** **2003** **2004** **2003**  **(Millions)**
**Energy Holdings:**
                                
Operating Revenues
    $213     $190     $177     $171     $311     $178     $326     $186 
Operating Income
     133      132      100      110      115      118      121      104 
Income Before Discontinued Operationsand Cumulative Effect of a Change inAccounting Principle
     48      61      21      40      36      43      31      45 
(Loss)/Gain on Disposal of Discontinued Operations, including Loss from Discontinued Operations, net of tax benefit
     —      (13)     5      (5)     —      (1)     —      (25)
Net Income
     48      48      26      35      36      42      31      20 
Earnings Available to PSEG
     43      42      21      29      33      37      28      14 
**Note 23. Related-Party Transactions**

      The majority of the following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.

**BGSS, BGS and MTC**

      **PSE&G and Power**

      Effective May 1, 2002, PSE&G entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G's BGSS and other contractual requirements. For additional information about the BGSS contract, see Note 14. Commitments and Contingent Liabilities.

      Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. For additional information about the BGS contracts, see Note 14. Commitments and Contingent Liabilities. In addition to BGS, Power collected an MTC charge from PSE&G until the end of the four-year transition period on July 31, 2003. The amounts Power charged to PSE&G for BGSS, BGS and MTC are presented below:
   **Billings for the YearsEnded December 31,**   **2004** **2003** **2002**   **(Millions)**                  
BGS
    $359     $30     $1,071                   
BGSS
    $1,784     $1,785     $582                   
MTC
    $—     $111     $98 
      As of December 31, 2004 and 2003, Power had net receivables from PSE&G    of approximately $357 million and $266 million, respectively, primarily relatedto the BGS and BGSS billings.

182

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Services**

      **PSE&G, Power and Energy Holdings**

      Services provides and bills administrative services to PSE&G, Power and Energy Holdings. In addition, PSE&G, Power and Energy Holdings have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. The billings for administrative services and payables are presented below:
   **Administrative Servicesbilled for the YearsEnded December 31,** **Payable toServices as ofDecember 31,**   **2004** **2003** **2002** **2004** **2003**   **(Millions)**      
PSE&G
    $208       $201       $193       $38         $74       
Power
    $150       $124       $149       $23         $22       
Energy Holdings
    $18       $16       $22       $2         $2 
      These transactions were properly recognized on each company's stand-alone financial statements and were eliminated when preparing PSEG's Consolidated Financial Statements. PSEG, PSE&G, Power and Energy Holdings believe that the costs of services provided by Services approximate market value for such services.

**Tax Sharing Agreement**

      **PSEG, PSE&G, Power and Energy Holdings**

      PSEG files a consolidated Federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.

      PSE&G, Power and Energy Holdings had (payables to) receivables from PSEG related to taxes as follows:
   **(Payable to)Receivable fromPSEG as ofDecember 31,**   **2004** **2003**   **(Millions)**            
PSE&G
    $(45)        $(83)            
Power
    $9         $(15)            
Energy Holdings
    $19         $173 
**Affiliate Loans and Advances**

      **PSEG and Power**

      As of December 31, 2004, Power had a payable to PSEG of approximately $98 million for short-term funding needs. As of December 31, 2003, Power had a receivable from PSEG of approximately $77 million for short-term funding needs. Interest Income and Interest Expense relating to these short term funding activities was immaterial.

      **PSEG and Energy Holdings**

      As of December 31, 2004 and 2003, Energy Holdings had a note receivable due from PSEG of $115 million and $300 million, respectively, reflecting the investment of its excess cash with PSEG. Interest Income related to these borrowings was immaterial.

183

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

      **PSE&G and Services**

      As of December 31, 2004 and 2003, PSE&G had advanced working capital to Services of approximately $33 million and $26 million, respectively. These amounts are included in Other Noncurrent Assets on PSE&G's Consolidated Balance Sheets.

      **Power and Services**

      As of December 31, 2004 and 2003, Power had advanced working capital to Services of approximately $17 million and $12 million, respectively. These amounts are included in Other Noncurrent Assets on Power's Consolidated Balance Sheets.

**Changes in Capitalization**

      **PSE&G**

      On January 21, 2003, PSEG contributed $170 million of equity to PSE&G. PSE&G paid a common stock dividend of approximately $100 million, $200 million and $305 million to PSEG in 2004, 2003 and 2002, respectively.

      **Power**

      PSEG contributed capital of approximately $300 million, $150 million and $200 million to Power during 2004, 2003 and 2002, respectively.

      **Energy Holdings**

      During 2004, Energy Holdings made cash distributions to PSEG totaling $491 million in the form of preference unit redemptions, preference unit distributions, ordinary unit distributions and return of capital contributed. In February 2005, Energy Holdings returned an additional $100 million of capital to PSEG in the form of an ordinary unit distribution.

**Asset Purchases and Sales**

      **Power and Energy Holdings**

      Global purchased equipment from Power totaling $47 million in 2002. This amount was sold at book value, thus no gain or loss was recorded on this transaction.

      **PSE&G and Services**

      On July 31, 2003, the BPU approved the sale by PSE&G to Services, of certain non-operating assets related to PSE&G's transmission and distribution operations with a net book value of approximately $53 million, together with associated rights and liabilities. The sale was completed on September 30, 2003 at net book value.

      **Power and Services**

      During the year ended December 31, 2004, Power sold certain maintenance facilities to Services at net book value, resulting in proceeds of approximately $4 million.

**Energy Holdings**

      **Operation and Maintenance and Development Fees**

      Global provides operating, maintenance and other services to and receives management and guaranty fees from various joint ventures and partnerships in which it is an investor. Fees related to the development and construction of certain projects are deferred and recognized when earned. Income from these services of

184

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

$7 million, $6 million and $3 million was included in Operating Revenues in the Consolidated Statements of Operations for the years ended December 31, 2004, 2003, and 2002, respectively.

**Other**

      **PSEG and PSE&G**

      As of December 31, 2004 and 2003, PSE&G had receivables from PSEG of approximately $14 million and $6 million, respectively, related to amounts that PSEG had collected on PSE&G's behalf.

      **PSEG and Power**

      As of December 31, 2004 and 2003, Power had receivables from PSEG of approximately $4 million and $1 million, respectively, related to amounts that PSEG had collected on Power's behalf.

      **PSE&G and Energy Holdings**

      As of December 31, 2003, PSE&G had a receivable from Energy Holdings of approximately $2 million.

      **Global**

      As of December 31, 2004, Global had loans outstanding with its affiliates of approximately $68 million, including $24 million of accrued interest related to its projects in Italy.

185

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Note 24. Guarantees of Debt
      Each series of Power's Senior Notes and Pollution Control Notes is fully and unconditionally and jointly and severally guaranteed by Fossil, Nuclear and ER&T. The following table presents condensed financial information for the guarantor subsidiaries as well as Power's non-guarantor subsidiaries as of December 31, 2004 and 2003 and for the years ended December 31, 2004, 2003 and 2002:
  **Power** **GuarantorSubsidiaries** **OtherSubsidiaries** **ConsolidatingAdjustments** **Total**  **(Millions)****For the Year Ended December 31, 2004:**                    
Revenues
    $—     $6,145     $122     $(1,094)    $5,173 
Operating Expenses
     —      5,610      128      (1,092)     4,646                                
Operating Income (Loss)
     —      535      (6)     (2)     527 
Equity Earnings in Subsidiaries
     295      (55)     —      (240)     — 
Other Income
     101      160      1      (96)     166 
Other Deductions
     —      (49)     (7)     (1)     (57)
Interest Expense
     (118)     (57)     (64)     97      (142)
Income Taxes
     30      (238)     22      —      (186)                               
**Net Income (Loss)**
    $308     $296     $(54)    $(242)    $308                                
**As of December 31, 2004:**
                    
Current Assets
    $1,445     $2,027     $84     $(1,459)    $2,097 
Property, Plant and Equipment, net
     107      3,021      1,950      —      5,078 
Investment in Subsidiaries
     3,720      642      —      (4,362)     — 
Noncurrent Assets
     1,290      1,294      33      (1,195)     1,422                                
**Total Assets**
    $6,562     $6,984     $2,067     $(7,016)    $8,597                                
Current Liabilities
    $117     $2,679     $270     $(1,548)    $1,518 
Noncurrent Liabilities
     50      719      10      (94)     685 
Note Payable—Affiliated Company
     —      —      300      (300)     — 
Long-Term Debt
     3,316      —      800      (800)     3,316 
Member's Equity
     3,079      3,586      687      (4,274)     3,078                                
**Total Liabilities and Member's Equity**
    $6,562     $6,984     $2,067     $(7,016)    $8,597                                
**For the Year Ended December 31, 2004:**
                    
Net Cash Provided By Operating Activities
    $125     $39     $79     $254     $497 
Net Cash Provided By (Used In) Investing Activities
    $(125)    $(251)    $(171)    $(53)    $(600)
Net Cash Provided By (Used In) Financing Activities
    $—     $(104)    $92     $98     $86 
**For the Year Ended December 31, 2003:**
                    
Revenues
    $—     $6,437     $134     $(958)    $5,613 
Operating Expenses
     —      5,635      93      (958)     4,770                                
Operating Income (Loss)
     —      802      41      —      843 
Equity Earnings in Subsidiaries
     928      21      —      (949)     — 
Other Income
     15      155      116      (137)     149 
Other Deductions
     —      (77)     —      (1)     (78)
Interest Expense
     (160)     (81)     (11)     138      (114)
Income Taxes
     61      (327)     (60)     —      (326)
Cumulative Change in Accounting Principle
     —      366      4      —      370                                
**Net Income (Loss)**
    $844     $859     $90     $(949)    $844                                
**As of December 31, 2003:**
                    
Current Assets
    $1,994     $2,021     $101     $(2,331)    $1,785 
Property, Plant and Equipment, net
     46      2,723      1,812      —      4,581 
Investment in Subsidiaries
     3,330      679      —      (4,009)     — 
Noncurrent Assets
     465      1,211      90      (397)     1,369                                
**Total Assets**
    $5,835     $6,634     $2,003     $(6,737)    $7,735                                
Current Liabilities
    $371     $2,952     $168     $(2,421)    $1,070 
Noncurrent Liabilities
     42      487      11      (96)     444 
Note Payable—Affiliated Company
     —      —      300      (300)     — 
Long-Term Debt
     2,816      —      800      —      3,616 
Member's Equity
     2,606      3,195      724      (3,920)     2,605                                
**Total Liabilities and Member's Equity**
    $5,835     $6,634     $2,003     $(6,737)    $7,735                                
186

                    
**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
  **Power** **GuarantorSubsidiaries** **OtherSubsidiaries** **ConsolidatingAdjustments** **Total**  **(Millions)**
**For the Year Ended December 31, 2003:**
                    
Net Cash Provided By (Used In) Operating Activities
    $2,171     $262     $(120)    $(1,689)    $624 
Net Cash Provided By (Used In) Investing Activities
    $(1,985)    $(548)    $(255)    $1,956     $(832)
Net Cash Provided By (Used In) Financing Activities
    $(186)    $587     $374     $(566)    $209 
**For the Year Ended December 31, 2002:**
                    
Revenues
    $2     $4,503     $42     $(907)    $3,640 
Operating Expenses
     —      3,603      41      (907)     2,737                                
Operating Income
     2      900      1      —      903 
Equity Earnings in Subsidiaries
     574      (3)     —      (571)     — 
Other Income
     —      9      —      (8)     1 
Other Deductions
     —      —      —      (1)     (1)
Interest Expense
     (180)     (69)     118      9      (122)
Income Taxes
     72      (343)     (42)     —      (313)                               
**Net Income (Loss)**
    $468     $494     $77     $(571)    $468                                
**For the Year Ended December 31, 2002:**
                    
Net Cash Provided By (Used In) Operating Activities
    $(182)    $738     $298     $(437)    $417 
Net Cash Provided By (Used In) Investing Activities
    $(695)    $(1,051)    $(625)    $1,072     $(1,299)
Net Cash Provided By (Used In) Financing Activities
    $877     $332     $328     $(638)    $899                     
**Note 25. Merger Agreement
      On December 20, 2004, PSEG and Exelon Corporation (Exelon), a public utility holding company registered under PUHCA which is headquartered in Chicago, Illinois, entered into an agreement and plan of merger (the Merger Agreement) whereby PSEG will be merged with and into Exelon (the 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 contains certain termination rights for both PSEG and Exelon, and further provides that, upon termination of the Merger Agreement under specified circumstances, (1) Exelon may be required to pay PSEG a termination fee of $400 million plus PSEG's transaction expenses up to $40 million and (2) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon's transaction expenses up to $40 million.

      The Merger Agreement has been unanimously approved by both companies' boards of directors but is contingent upon, among other things, the approval by shareholders of both companies, antitrust clearance and a number of regulatory approvals or reviews by federal and state energy authorities. The parties 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. Concurrent with the Merger Agreement, PSEG adopted the Key Executive Severance Plan of PSEG (Severance Plan) and adopted the Retention Program for Key Employees of PSEG (Retention Program).

      **Severance Plan**

      The Severance Plan provides change in control severance benefits to certain elected officers of PSEG whose employment is terminated without “cause” or who resign their employment for “good reason” within two years after a change in control, which would include the consummation of the Merger. Under the Severance Plan, the majority of the participants, if they are terminated without “cause” or resign his or her employment for “good reason” within two years after a change in control, will receive (1) a pro rata bonus based on the participant's target annual incentive compensation, (2) two times the sum of the participant's salary and target incentive bonus, (3) accelerated vesting of equity-based awards, (4) a lump sum payment equal to the actuarialequivalent of the participant's benefits under all of PSEG's retirement plans in which the participant participates calculated as though the participant remained employed for two years beyond the date his or her employment terminates less the actuarial equivalent of such benefits on the date his or her employment terminates, (5) two years continued welfare benefits (the first 18 months of which will be provided through PSEG-paid COBRA continuation coverage), (6) one year of PSEG-paid outplacement

187

services and (7) vesting of any compensation previously deferred. Under the Severance Plan, one participant will receive the same benefits as the other participants, except that the applicable multiplier for salary and target incentive bonus, retirement plan accruals and continuation of welfare benefits is three years instead of two.

**Retention Program**

      The Retention Program, effective as of December 20, 2004, provides for payments to be made to certain key employees of PSEG who remain employed from the date of execution of the Merger Agreement through the date that is 90 days after the consummation of the Merger. The amount of a participant's retention payment may not be less than 40% or more than 150% of the participant's annual base salary. Retention payments under the Retention Program may not exceed $10 million in the aggregate.

      PSEG will pay the first installment, equal to half of a participant's total retention payment, within 60 days after the first anniversary of the date of execution of the Merger Agreement. PSEG will pay the participant's remaining retention payment on the business day following the date that is 90 days after the consummation of the Merger. No participant whose employment terminates for any reason other than involuntary termination without “cause” will receive any subsequent installment of the retention payment. A participant whose employment is terminated without “cause” on or prior to the consummation of the Merger will be treated as if he or she remained employed through the date that is 90 days after the consummation of the Merger for all purposes under the Retention Program.

188

**ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE**

**PSEG**

      None.

**PSE&G**

      None.

**Power**

      None.

**Energy Holdings**

      None.

**ITEM 9A. CONTROLS AND PROCEDURES**

**Disclosure Controls and Procedures**

      **PSEG, PSE&G, Power and Energy Holdings**

      PSEG, PSE&G, Power and Energy Holdings have established and maintain disclosure controls and procedures which are designed to provide reasonable assurance that material information relating to each company, including their respective consolidated subsidiaries, is made known to the Chief Executive Officer and Chief Financial Officer of each company by others within those entities. PSEG, PSE&G, Power and Energy Holdings have established a disclosure committee which is made up of several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer of each respective company. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectivenessof the disclosure controls and procedures as of December 31, 2004 and, based on this evaluation, have concluded that the disclosure controls and procedures were effective in providing reasonable assurance during the period covered in these annual reports.

**Internal Controls**

      **PSEG, PSE&G, Power and Energy Holdings**

      PSEG has  conducted an assessment of its internal control over financial reporting as  of December 31, 2004 as required by Section 404 of the Sarbanes-Oxley Act. Management's  report on PSEG's internal control over financial reporting is included on  page 190. The Independent Registered Public Accounting Firm's report with  respect to management's assessment of the effectiveness of internal control  over financial reporting and the effectiveness of PSEG's internal control  over financial reporting is included on pages 191 and 192. Management has concluded  that internal control over financial reporting is effective as of December 31,  2004.

      During the fourth quarter of 2004, PSEG, PSE&G, Power and Energy Holdings made enhancements to internal controls to enable PSEG to meet the requirements of the Sarbanes-Oxley Act as of December 31, 2004. These enhancements included significant changes to internal controls, including enhanced policies and procedures in the wholesale energy trading and information technology processes, in order to improve the design and operational effectiveness of PSEG's control processes and systems for financial reporting. It should be noted that the design of any system of controls is based, in part, on certain assumptions about the likelihood of future events, and provides reasonable assurance that the internal control system will succeed in achieving its stated objectives.

189

**MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING**

      Management of Public Service Enterprise Group (PSEG) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and implemented by the company's management and other personnel, with oversight by the Audit Committee of the Board of Directors to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposesin accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).

      PSEG's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSEG's assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSEG are being made only in accordance with authorizations of PSEG's management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG's assets that could have a material effect on the financial statements.

      In connection with the preparation of PSEG's annual financial statements, management of PSEG has undertaken an assessment, which includes the design and operational effectiveness of PSEG's internal control over financial reporting using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.

      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

      Based on the assessment performed, management has concluded that PSEG's internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG's financial reporting and the preparation of its financial statements as of December 31, 2004 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2004.

      PSEG's external auditors, Deloitte & Touche LLP, have audited PSEG's financial statements for the year ended December 31, 2004 included in this annual report on Form 10-K and, as part of that audit, have issued a report on management's assessment of internal control over financial reporting, a copy of which is included in this annual report on Form 10-K.
/s/ E. JAMES FERLANDChief Executive Officer                                                                /s/ THOMAS M. O'FLYNNChief Financial Officer                                                                
February 28, 2005

190

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

To the Stockholders and Board of Directors ofPUBLIC SERVICE ENTERPRISE GROUP INCORPORATED:

      We have audited management's assessment, included in the accompanying Management Report on Internal Control Over Financial Reporting, that Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on the criteria established in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company'sinternal control over financial reporting based on our audit.

      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

      A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactionsare recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

      Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

      In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission.

191

      We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), consolidated balance sheet of the Company as of December 31, 2004, the related consolidated statements of operations, common stockholders' equity and cash flows for the year then ended, and consolidated financial statement schedule listed in the Index at Item 15, and our report dated February 22, 2005 expressed an unqualified opinion on those financial statements and financial statement schedule and included explanatory paragraphs regarding the adoption of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” and Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

DELOITTE & TOUCHE LLP

Parsippany, New JerseyFebruary 28, 2005

192

**PART III
**ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
**Executive Officers**

      The Executive Officers of each of PSEG, PSE&G, Power and Energy Holdings, respectively, are set forth below, as indicated for each individual.
**Name** **Age as ofDecember 31,2004** **Office**    **Effective DateFirst Elected toPresent Position**E. James Ferland(1)(2)(3)(4)  62  Chairman of the Board, President and Chief Executive Officer (PSEG)    July 1986 to present      Chairman of the Board and Chief Executive Officer (PSE&G)    July 1986 to present      Chairman of the Board and Chief Executive Officer (Energy Holdings)    June 1989 to present      Chairman of the Board and Chief Executive Officer (Power)    June 1999 to present      Chairman of the Board and Chief Executive Officer (Services)    November 1999 to presentThomas M. O'Flynn(1)(3)(4)  44  Executive Vice President and Chief Financial Officer (PSEG)    July 2001 to present      Executive Vice President—Finance (Services)    July 2001 to present      Executive Vice President and Chief Financial Officer (Energy Holdings)    August 2002 to present      Executive Vice President and Chief Financial Officer (Power)    February 2002 to present      Managing Director—Global Power and Utility Investment Banking Division Group (Morgan Stanley)    December 1997 to May 2001Robert J. Dougherty, Jr.(1)(4)  53  President and Chief Operating Officer (Energy Holdings)    January 1997 to present      Vice President (PSEG)    March 1995 to present      President (Global)    August 2003 to presentRalph Izzo(1)(2)  47  President and Chief Operating Officer (PSE&G)    October 2003 to present      Vice President—Utility Operations (PSE&G)    June 2002 to October 2003      Vice President—Special Projects (Services)    September 2001 to June 2002      Vice President—Appliance Service (PSE&G)    April 2000 to September 2001      Vice President—Corporate Planning (PSEG)    March 1998 to April 2000R. Edwin Selover(1)(2)  59  Senior Vice President and General Counsel (PSEG)    April 2002 to present      Vice President and General Counsel (PSEG)    April 1988 to April 2002      Senior Vice President and General Counsel (PSE&G)    January 1988 to present      Senior Vice President and General Counsel (Services)    November 1999 to presentPatricia A. Rado(1)(2)(3)(4)  62  Vice President and Controller (PSEG)    April 1993 to present      Vice President and Controller (PSE&G)    April 1993 to present      Vice President and Controller (Power)    June 1999 to present      Vice President and Controller (Energy Holdings)    April 2004 to present      Vice President and Controller (Services)    November 1999 to presentRobert E. Busch(1)(2)  58  President & Chief Operating Officer (Services)    April 2001 to present      Senior Vice President-Finance and Chief Financial Officer (Services)    November 1999 to April 2001      Senior Vice President and Chief Financial Officer (PSE&G)    June 1998 to present
193

**Name** **Age as ofDecember 31,2004** **Office**    **Effective DateFirst Elected toPresent Position**Harold W. Borden Jr.(3)  60  Vice President and General Counsel (Power)    June 1999 to present      Vice President—Law (PSE&G)    April 1995 to July 1999Morton A. Plawner(3)  57  Treasurer (PSEG)    April 1998 to present      Vice President and Treasurer (PSE&G)    April 1998 to present      Vice President and Treasurer (Power)    June 1999 to presentFrank Cassidy(1)(3)  58  President and Chief Operating Officer (Power)    June 1999 to present      President (Energy Technologies)    November 1996 to June 1999Steven R. Teitelman(3)  58  President (ER&T)    June 1999 to present      Vice President—Energy Resources and Trading (PSE&G)    August 1997 to August 2002Michael J. Thomson(3)  46  President (Fossil)    August 2003 to present      President (Global)    January 1997 to July 2003Eileen A. Moran(4)  50  President (Resources)    May 1990 to present      President (EGDC)    January 1997 to presentMiriam E. Gilligan(4)  53  Vice President—Finance and Treasurer (Energy Holdings)    December 2001 to present      Vice President (Services)    December 2001 to present      Treasurer (Energy Holdings)    1997 to December 2001   (1)   Executive Officer of PSEG   (2)   Executive Officer of PSE&G   (3)   Executive Officer of Power   (4)   Executive Officer of Energy Holdings
**Directors**

      **PSEG**

      The information required by Item 10 of Form 10-K with respect to (i) present directors of PSEG who are nominees for election as directors at PSEG's 2005 Annual Meeting of Stockholders, and directors whose terms will continue beyond the meeting, and (ii) compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth under the headings “Election of Directors” and Section 16(a) “Beneficial Ownership Reporting Compliance” in PSEG's definitive Proxy Statement for such Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about April 30, 2005 and which information set forth under said heading is incorporated herein by this reference thereto.

      **PSE&G**

      CAROLINE DORSA has been a director of PSE&G since February 2003. Age 45. Director of PSEG. Has been Vice President and Treasurer of Merck & Co., Inc., Whitehouse Station, New Jersey (discovers, develops, manufactures and markets human and animal health products) since December 1996. Was Treasurer from January 1994 to November 1996 and Executive Director of the U.S. Human Health Marketing subsidiary of Merck & Co., Inc. from June 1992 to January 1994. Director of Readington Holdings, Inc.

      E. JAMES FERLAND has been a director of PSE&G since July 1986. Age 62. For additional information, see Executive Officers table above.

      ALBERT R. GAMPER, JR. has been a director of PSE&G since December 2000. Age 62. Director of PSEG. Was Chairman of the Board and Chief Executive Officer of The CIT Group, Inc., Livingston, New Jersey (commercial finance company) from September 2003 to December 2004. Was Chairman of the Board, President and Chief Executive Officer from June 2002 to September 2003. Was President and Chief Executive Officer from February 2002 to June 2002. Was President and Chief Executive Officer of Tyco Capital Corporation from June 2001 to February 2002. Was Chairman of the Board, President and Chief Executive Officer of The CIT Group, Inc., from January 2000 to June 2001. Was President and Chief Executive Officer of The CIT Group, Inc. from December 1989 to December 1999.

194

      CONRAD K. HARPER has been a director of PSE&G since May 1997. Age 64. Director of PSEG. Of counsel to the law firm of Simpson Thacher & Bartlett LLP, New York, New York since January 2003. Was a partner from October 1996 to December 2002 and from October 1974 to May 1993. Was Legal Adviser, U.S. Department of State from May 1993 to June 1996. Director of New York Life Insurance Company.

      **Power**

      ROBERT E. BUSCH has been a director of Power since December 2000. For additional information, see Executive Officers table above.

      FRANK CASSIDY has been a director of Power since June 1999. For additional information, see Executive Officers table above.

      ROBERT J. DOUGHERTY, JR. has been a director of Power since June 1999. For additional information, see Executive Officers table above.

      E. JAMES FERLAND has been a director of Power since June 1999. For additional information, see Executive Officers table above.

      THOMAS M. O'FLYNN has been a director of Power since July 2001. For additional information, see Executive Officers table above.

      R. EDWIN SELOVER has been a director of Power since July 1999. For additional information, see Executive Officers table above.

      **Energy Holdings**

      ROBERT E. BUSCH has been a director of Energy Holdings since December 2000. For additional information, see Executive Officers table above.

      FRANK CASSIDY has been a director of Energy Holdings since January 2000. For additional information, see Executive Officers table above.

      ROBERT J. DOUGHERTY, JR. has been a director of Energy Holdings since January 2000. For additional information, see Executive Officers table above.

      E. JAMES FERLAND has been a director of Energy Holdings since June 1989. For additional information, see Executive Officers table above.

      THOMAS M. O'FLYNN has been a Director of Energy Holdings since July 2001. For additional information, see Executive Officers table above.

      R. EDWIN SELOVER has been a Director of Energy Holdings since January 2000. For additional information, see Executive Officers table above.

**PSEG, PSE&G, Power and Energy Holdings**

      **Code of Ethics**

      PSEG has adopted a code of ethics entitled Standards of Integrity (Standards) applicable to it and its subsidiaries, including PSE&G, Power and Energy Holdings. The Standards are an integral part of PSEG's business conduct compliance program and embody the commitment of PSEG and its subsidiary companies to conduct operations in accordance with the highest legal and ethical standards. The Standards apply to all PSEG directors, employees (including PSEG's, PSE&G's, Power's and Energy Holdings' respective principal executive officer, principal financial officer, principal accounting officer or Controller and persons performing similar functions), contractors and consultants, worldwide. Each is responsible for understanding and complying with the Standards.

      The Standards establish a set of common expectations for behavior that each employee must adhere to in dealings with investors, customers, fellow employees, competitors, vendors, government officials, the media and all others who may associate their words and actions with PSEG. They have been developed to provide reasonable assurance that, in conducting PSEG's business, employees behave ethically and in accordance with the law and do not take advantage of investors, regulators or customers through manipulation, abuse of confidential information or misrepresentation of material facts.

      Any amendment (other than technical, administrative or non-substantive) to or a waiver from the Standards that applies to PSEG's, PSE&G's, Power's or Energy Holdings' principal executive officer, principal financial officer, principal accounting officer or Controller, or persons performing similar functions

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and that relates to any element enumerated by the SEC, will be posted on PSEG's website, www.pseg.com/investor/governance.

**ITEM 11. EXECUTIVE COMPENSATION
**PSEG**

      The information required by Item 11 of Form 10-K is set forth under the heading "Executive Compensation' in PSEG's definitive Proxy Statement for the 2005 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about April 30, 2005 and such information set forth under such heading is incorporated herein by this reference thereto.

**PSE&G**

      Information regarding the compensation of the Chief Executive Officer and the four most highly compensated executive officers of PSE&G as of December 31, 2004 is set forth below. Amounts shown were paid or awarded for all services rendered to PSEG and its subsidiaries and affiliates including PSE&G.

**Summary Compensation Table**
              **Long-Term Compensation**      **Annual Compensation** **Awards**    **Name and Principal Position** **Year** **Salary $** **Bonus/Annual Incentive Award ($)(1)** **Restricted Stock ($)(2)** **Options(#)(3)** **All Other Compensation ($)(4)**
E. James Ferland      Chairman of the Board and Chief Executive Officer
   200420032002    1,081,1381,006,227971,358    735,2001,440,000713,000    949,05000       135,0000350,000    6,1526,0026,002 
Ralph Izzo(5)      President and Chief Operating Officer
   200420032002    465,562304,051273,973    350,500282,80079,800    235,12500       33,000250,00035,000    8,2048,0035,500 
R. Edwin Selover      Senior Vice President and General Counsel
   200420032002    439,698403,487388,544    211,200287,000125,500    141,07500       22,000080,000    8,2028,0048,004 
Robert E. Busch      Senior Vice President and Chief Financial Officer
   200420032002    398,315370,610358,654    195,200279,000153,200    128,25000       20,000065,000    8,2068,0038,006 
Patricia A. Rado      Vice President and Controller
   200420032002    256,577227,148219,178    113,400102,40053,600    53,43700       7,600025,000    8,3945,5095,593    (1)   Amounts awarded were earned under the Restated and Amended Management Incentive Compensation Plan and determined and paid in the following year based on individual performance and financial and operating performance of PSEG and PSE&G, including comparison to other companies.   (2)   Value as of original award date, based on the closing price of $42.75 on the New York Stock Exchange on November 20, 2001, with one-third of the shares vesting on each of December 31, 2004, December 31, 2005 and December 31, 2006. Dividends on the entire grant are paid in cash from the date of award. The fair market value of the PSEG Common Stock at the time of vesting of the first one-third of the shares was $52.31.   (3)   All grants of options to purchase shares of PSEG Common Stock were non-qualified options.   (4)   Represents employer contribution to the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan).   (5)   Mr. Izzo was elected to his present position effective October 18, 2003.
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**Option Grants in Last Fiscal Year (2004)**
  **Option Grants in Last Fiscal Year**    **Name** **Number ofSecuritiesUnderlyingOptionsGranted(1)** **% of TotalOptionsGranted toEmployees inFiscal Year** **Exercise orBase Price($/Sh)** **ExpirationDate** **Grant DatePresent Value($)(2)**
E. James Ferland
     135,000      15.6      42.75      5/3/14      900,450 
Ralph      Izzo
     33,000      3.8      42.75      5/3/14      220,110 
R. Edwin Selover
     22,000      2.5      42.75      5/3/14      146,740 
Robert E. Busch
     20,000      2.3      42.75      5/3/14      133,400 
Patricia A. Rado
     7,600      0.9      42.75      5/3/14      50,692                        (1)   Granted under the 2004 Long-Term Incentive Plan (LTIP) with exercisability commencing January 1, 2005, January 1, 2006 and January 1, 2007 and, respectively, with respect to one-third of the options at each such date.   (2)   Determined using the Black-Scholes model, incorporating the following material assumptions and adjustments: (a) exercise price of $42.75, equal to the fair market value of the underlying PSEG Common Stock on the date of grant; (b) an option term of ten years on all grants; (c) interest rate of 4.72% that represent the interest rates on U.S. Treasury securities on the date of grant with a maturity date corresponding to that of the option terms; (d) volatility of 26.91% calculated using daily PSEG Common Stock prices for the one-year period prior to the grant date; (e) dividend yield of 5.15% and (f) reductions of approximately 7.79% to reflect the probability of forfeiture due to termination prior to vesting, and approximately 10.24% to reflect the probability of a shortened option term due to termination of employment prior to the option expirationdates. Actual values which may be realized, if any, upon any exercise of such options, will be based on the market price of PSEG Common Stock at the time of any such exercise and thus are dependent upon future performance of PSEG Common Stock. There is no assurance that any such value realized will be at or near the value estimated by the Black-Scholes model utilized.
**Aggregated Option Exercises in Last Fiscal Year (2004) andFiscal Year End Option Values (12/31/04)**
          **Number of UnexercisedOptions at FY-End(#)(1)** **Value of UnexercisedIn-the-Money OptionsAt FY-End($)(3)****Name** **SharesAcquiredon Exercise(#)(1)** **ValueRealized($)(2)** **Exercisable(#)** **Unexercisable(#)** **Exercisable($)(3)** **Unexercisable($)(3)**
E. James Ferland
     —      —      1,348,333      251,667      18,402,793      3,590,707 
Ralph Izzo
     —      —      156,333      244,667      1,191,266      2,734,967 
R. Edwin Selover
     10,000      121,379      233,333      48,667      3,046,406      740,847 
Robert E. Busch
     40,000      444,588      298,333      141,667      2,655,043      1,175,107 
Patricia A. Rado
     31,334      395,805      48,333      15,933      529,856      238,045                            (1)   Reflects any options exercised through year-end (12/31/04).   (2)   Represents difference between exercise price and market price of PSEG Common Stock on date of exercise.   (3)   Represents difference at fiscal year end (12/31/04) between market price of PSEG Common Stock ($52.31) and the respective exercise prices of the options. Such amounts may not necessarily be realized. Actual values which may be realized, if any, upon any exercise of such options will be based on the market price of PSEG Common Stock at the time of any such exercise and thus are dependent upon future performance of PSEG Common Stock.
      **Employment Contracts and Arrangements**

      PSEG entered into an employment agreement dated as of June 16, 1998 and amended as of November 20, 2001 with Mr. Ferland (together, the “Original Ferland Employment Agreement”), as

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amended on December 20, 2004 (the “Second Amendment”) covering his employment as Chief Executive Officer through March 31, 2007. The Original Ferland Employment Agreement provides that Mr. Ferland will be renominated for election as a director during his employment under the Original Ferland Employment Agreement. The Original Ferland Employment Agreement also provides that Mr. Ferland's base salary, target annual incentive bonus and long-term incentive bonus will be determined based on compensation practices for Chief Executive Officers (CEOs) of similar companies and that his annual salary will not be reduced during the term of the Original Ferland Employment Agreement. The Original Ferland Employment Agreement also provides for an award to him of 150,000 shares of restricted PSEG Common Stock as of June 16, 1998 and 60,000 sharesof restricted PSEG Common Stock as of November 20, 2001, with 60,000 shares vesting in 2002; 20,000 shares vesting in 2003; 30,000 shares vesting in 2004; 40,000 shares vesting in 2005; 30,000 shares vesting in 2006; and 30,000 shares vesting in 2007. The Original Ferland Employment Agreement provides for the granting of 22 years of pension credit for Mr. Ferland's prior service, which was awarded at the time of his initial employment.

      The Second Amendment provides that, as of completion of the Merger with Exelon, Mr. Ferland will serve solely as the Chairman of the Exelon board of directors. Mr. Ferland will not have any executive duties after completion of the Merger. Mr. Ferland's term of employment continues through March 31, 2007, at which time he has agreed to retire. During the term of employment, Mr. Ferland's annual salary, target annual incentive bonus and target long-term incentive bonus will be set by the Exelon board of directors, but will not be less than the amounts paid to him or the targets set for him immediately prior to completion of the Merger. Mr. Ferland waived his right to resign his employment for “good reason” as a result of the Merger because: (1) of the changes to his title, authority, duties, responsibilitiesand reporting lines; (2) he is not appointed to the position of Chief Executive Officer of Exelon; and (3) another individual is appointed to the position of Chief Executive Officer of Exelon. Further, Mr. Ferland acknowledged that the changes in his title, authority, duties, responsibilities and reporting lines do not constitute a termination of his employment without “cause.” Otherwise, the provisions of the Original Ferland Employment Agreement, as amended, providing for severance payments on the termination of his employment without “Cause” or on the resignation of his employment for “good reason,” remain in effect.

      When Mr. Ferland retires at the end of his term of employment on March 31, 2007, he will be fully vested in any outstanding shares of restricted stock and any other equity awards he received as a long-term incentive bonus and he will be paid any previously deferred compensation. He will not receive any special severance payments on retirement.

      The Second Amendment only becomes effective if the Merger is completed.

      PSEG has entered into an employment agreement with Mr. Izzo dated as of October 18, 2003 and Mr. Busch dated as of April 24, 2001, covering the respective employment of each in the position listed in the Summary Compensation Table through October 17, 2008 for Mr. Izzo and April 24, 2006 for Mr. Busch. The agreements are essentially identical and provide that the base salary, target annual incentive bonus and long-term incentive bonus will be determined based on compensation practices of similar companies and that their annual salary will not be reduced during the term of the agreement, and awarded to Mr. Izzo 250,000 options on PSEG Common Stock, 50,000 of which vest each October 18 and expire on October 18, 2013 and awarded to Mr. Busch 250,000 options on PSEG Common Stock, 50,000 of which vest each April 24 and expireon April 24, 2011 in each case provided that the individual has remained continuously employed by PSEG through such date. The agreement for Mr. Busch also provides for the grant of additional years of credited service for retirement purposes in light of allied work experience of fifteen years.

      Each of the agreements discussed above further provides that if the individual is terminated without “Cause” or resigns for “good reason” (as those terms are defined in each agreement) during the term of such agreement, the respective entire restricted stock award and/or entire option award becomes vested, the individual will be paid a benefit of two times base salary and target bonus, and his welfare benefits will be continued for two years unless he is sooner employed. In the event such a termination occurs after a “change in control” (also as defined in each agreement), the payment to the individual becomes three times the sum of salary and target bonus, continuation of welfare benefits for three years unless sooner reemployed, payment of the net present value of providing three yearsadditional service under PSEG's retirement plans, and a gross-up for excise taxes on any termination payments due under the Internal Revenue Code. Each of the agreements provides that the individual is prohibited for one year (two years for Mr. Ferland) from competing with and for two years from recruiting employees from, PSEG or its subsidiaries or affiliates, after termination of employment. Violation of these provisions requires a forfeiture of the respective restricted stock and option grants and certain benefits.

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      Under the Merger Agreement, PSEG has reserved the right to renew these agreements for a term not to exceed two years following the closing of the Merger.

      **Compensation Committee Interlocks and Insider Participation**

      PSE&G does not have a compensation committee. Decisions regarding compensation of PSE&G's executive officers are made by the Organization and Compensation Committee of PSEG. Hence, during 2004 the PSE&G Board of Directors did not have, and no officer, employee or former officer of PSE&G participated in any deliberations of such Board, concerning executive officer compensation.

      **Compensation of Directors and Certain Business Relationships**

      During 2004, each director who was not an officer of PSEG or its subsidiaries and affiliates, including PSE&G, was paid an annual retainer of $40,000 (increased to $50,000 for 2005) and a fee of $1,500 for attendance at any Board or committee meeting, inspection trip, conference or other similar activity relating to PSEG or PSE&G. Pursuant to the Compensation Plan for Outside Directors, a certain percentage, currently fifty percent, of the annual retainer is paid in PSEG Common Stock. No additional retainer is paid for service as a director of PSE&G. Each PSEG Committee Chair received an additional annual retainer of $5,000 except for the Chair of the Audit Committee, who received $10,000. In addition, each member of the Audit Committee received an additional annual retainer of $5,000.

      PSEG also maintains a Stock Plan for Outside Directors pursuant to which directors who are not employees of PSEG or its subsidiaries and affiliates receive shares of restricted stock for each year of service as a director. For 2004, this amount was 800 shares. This amount was increased to 1,000 shares for 2005. Such shares held by each non-employee director are included in the table below under Item 12. Security Ownership of Certain Beneficial Owners and Management.

      The restrictions on the stock granted under the Stock Plan for Outside Directors provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director's service were terminated after a “change in control” as defined in the Plan or if the director were to die in office. PSEG also has the ability to waive these restrictions for good cause shown. Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director and the director has the right to vote the shares.

      **Compensation Pursuant to Pension Plans**

      The table below illustrates annual retirement benefits for executive officers expressed in terms of single life annuities based on the average final compensation and service shown and retirement at age 65. A person's annual retirement benefit is based upon a percentage that is equal to years of credited service plus 30, but not more than 75%, times average final compensation at the earlier of retirement, attainment of age 65 or death. These amounts are reduced by Social Security benefits and certain retirement benefits from other employers. Pensions in the form of joint and survivor annuities are also available.
   **Length of Service**            **Average FinalCompensation** **30 Years** **35 Years** **40 Years** **45 Years**            
$  300,000
    $180,000       $195,000       $210,000       $225,000                 400,000     240,000        260,000        280,000        300,000                 500,000     300,000        325,000        350,000        375,000                 600,000     360,000        390,000        420,000        450,000                 700,000     420,000        455,000        490,000        525,000                 800,000     480,000        520,000        560,000        600,000                 900,000     540,000        585,000        630,000        675,000              1,000,000     600,000        650,000        700,000        750,000              1,100,000     660,000        715,000        770,000        825,000              1,200,000     720,000        780,000        840,000        900,000              1,300,000     780,000        845,000        910,000        975,000              1,400,000     840,000        910,000        980,000        1,050,000              1,500,000     900,000        975,000        1,050,000        1,125,000                             
      Average final compensation, for purposes of retirement benefits of executive officers, is generally equivalent to the average of the aggregate of the salary and bonus amounts reported in the Summary

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Compensation Table above under “Annual Compensation” for the five years preceding retirement, not to exceed 150% of the average annual salary for such five year period. Messrs. Ferland, Selover, Busch, Izzo and Mrs. Rado will have accrued approximately 48, 43, 34, 36, and 29 years of credited service, respectively, as of age 65.

**Power**

      Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

**Energy Holdings**

      Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

**ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND                MANAGEMENT**

**PSEG**

      The information required by Item 12 of Form 10-K with respect to directors, executive officers and certain beneficial owners is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners” in PSEG's definitive Proxy Statement for the 2005 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about April 30, 2005, and such information set forth under such heading is incorporated herein by this reference thereto.

      The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2004:
**Plan Category** **Number of Securitiesto be Issued UponExercise ofOutstanding Options,Warrants and Rights** **Weighted-AverageExercise Price ofOutstanding Options,Warrants and Rights** **Number of SecuritiesRemaining Availablefor Future IssuanceUnder EquityCompensation Plans**
Equity compensation plans approved by security holders
     5,719,402     $39.89      12,481,313 
Equity compensation plans not approved by security holders
     1,971,500     $40.19      1,965,809(A)                   
Total
     7,690,902     $39.97      14,447,122                               
(A) Shares issuable under the PSEG Employees Stock Purchase Plan.

      For additional discussion of specific plans concerning equity-based compensation, see Note 19. Stock Options and Employee Stock Purchase Plan of the Notes, Item 11. Executive Compensation for PSE&G, above, and the information set forth under the heading “Executive Compensation” in PSEG's definitive Proxy Statement for the 2005 Annual Meeting of Stockholders and expected to be filed with the SEC on or about April 30, 2005, which information set forth under such heading is incorporated herein by this reference thereto.

**PSE&G**

      All of PSE&G's, 132,450,344 outstanding shares of Common Stock are owned beneficially and of record by PSE&G's parent, PSEG, 80 Park Plaza, P.O. Box 1171, Newark, New Jersey.

      The following    table sets forth beneficial ownership of PSEG Common Stock, including options,    by the directors and executive officers named below as of January 18, 2005.    None of these amounts exceed 1% of the PSEG Common Stock outstanding at such    date,    except for the amount for all directors and executive officers as a group,    which constitutes approximately 1.36%. No director or executive officer ownsany of PSE&G's Preferred Stock of any class.

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      **Name** **Amount andNature ofBeneficial Ownership**      
Robert E. Busch
     452,182(1)      
Caroline Dorsa
     4,363(2)      
E. James Ferland
     1,982,111(3)      
Albert R. Gamper, Jr.
     6,134(4)      
Conrad K. Harper
     7,817(5)      
Ralph Izzo
     423,463(6)      
Patricia A. Rado
     71,537(7)      
R. Edwin Selover
     294,361(8)      
All directors and executive officers as a group (8 persons)
     3,241,968(9)          
   (1)   Includes the equivalent of 192 shares held under the Thrift Plan. Includes options to purchase 440,000 shares, 298,333 of which are currently exercisable. Includes 9,500 shares of restricted stock.   (2)   Includes 2,400 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors. Includes 500 shares held jointly with spouse.   (3)   Includes the equivalent of 15,710 shares held under the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Includes options to purchase 1,600,000 shares, 1,393,333 of which are currently exercisable. Includes 100,000 shares of restricted stock. Includes 110,000 shares held in a trust. Includes 76,601 shares held jointly with spouse.   (4)   Includes 2,800 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors.   (5)   Includes 4,600 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors.   (6)   Includes the equivalent of 328 shares held under the Thrift Plan. Includes 19,667 shares of restricted stock awarded pursuant to the 2004 LTIP. Includes options to purchase 401,000 shares, 167,333 of which are currently exercisable.   (7)   Includes options to purchase 64,266 shares, 48,333 of which are currently exercisable. Includes 3,933 shares of restricted stock.   (8)   Includes the equivalent of 11 shares held under the Thrift Plan. Includes options to purchase 272,000 shares, 233,333 of which are currently exercisable. Includes 11,300 shares of restricted stock.   (9)   Includes the equivalent of 16,241 shares held under the Thrift Plan. Includes options to purchase 2,777,266 shares, 2,095,665 of which are currently exercisable. Includes 234,000 shares of restricted stock. Includes 110,000 shares held in a trust.
**Power**

      Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

**Energy Holdings**

      Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

**ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS**

**PSEG**

      The information required by Item 13 of Form 10-K is set forth under the heading “Executive Compensation” in PSEG's definitive Proxy Statement for the 2005 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about April 30, 2005. Such information set forth under such heading is incorporated herein by this reference thereto.

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**PSE&G**

      None.

**Power**

      Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

**Energy Holdings**

      Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

**ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES**

      The information required by Item 14 of Form 10-K is set forth under the heading “Fees Billed to PSEG by Deloitte & Touche LLP for 2004 and 2003” in PSEG's definitive Proxy Statement for the 2005 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about April 30, 2005. Such information set forth under such heading is incorporated herein by this reference thereto.

**PART IV**

**ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES**
(A) The following Financial Statements are filed as a part of this report:   a.  Public Service Enterprise Group      Incorporated's Consolidated Balance Sheets as of December 31, 2004 and      2003 and the related Consolidated Statements of Operations, Cash Flows and      Common Stockholders' Equity for the three years ended December 31, 2004      on page 94, 93, 95 and 96, respectively.   b.  Public Service Electric and      Gas Company's Consolidated Balance Sheets as of December 31, 2004 and      2003 and the related Consolidated Statements of Operations, Cash Flows and      Common Stockholder's Equity for the three years ended December 31, 2004      on page 98, 97, 99 and 100, respectively.   c.  PSEG Power LLC Consolidated      Balance Sheets as of December 31, 2004 and 2003 and the related Consolidated      Statements of Operations, Cash Flows and Capitalization and Member's      Equity for the three years ended December 31, 2004 on page 102, 101, 103      and 104, respectively.   d.  PSEG Energy Holdings LLC Consolidated      Balance Sheets as of December 31, 2004 and 2003 and the related Consolidated      Statements of Operations, Cash Flows and Member's/Common Stockholder's      Equity for the three years ended December 31, 2004 on page 106, 105, 107      and 108, respectively.(B) The following documents are filed as a part of this report:   a.  PSEG Financial Statement Schedules:     Schedule II—Valuation      and Qualifying Accounts for each of the three years in the period ended      December 31, 2004 (page 213).   b.  PSE&G Financial Statement Schedules:     Schedule II—Valuation      and Qualifying Accounts for each of the three years in the period ended      December 31, 2004 (page 214).   c.  Power's Financial Statement Schedules:     Schedule II—Valuation      and Qualifying Accounts for each of the three years in the period ended      December 31, 2004 (page 214).   d.  Energy Holdings' Financial Statement Schedules:     Schedule II—Valuation      and Qualifying Accounts for each of the three years in the period ended      December 31, 2004 (page 215).      Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
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(C) The following documents are filed as part of this report:
**LIST OF EXHIBITS:**
** a.****      **    **PSEG:** 3a          Certificate of Incorporation Public Service Enterprise Group Incorporated1 3b          By-Laws of Public Service Enterprise Group Incorporated2 3c          Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 23, 19873 3d          Amended and Restated Trust Agreement for Enterprise Capital Trust I4 3e          Amended and Restated Trust Agreement for Enterprise Capital Trust II5 3f          Amended and Restated Trust Agreement for Enterprise Capital Trust III6 3g          Amended and Restated Trust Agreement for PSEG Funding Trust I7 3h          Amended and Restated Trust Agreement for PSEG Funding Trust II8 4a(1)    Indenture between Public Service Enterprise Group Incorporated and First Union National Bank (now, Wachovia Bank, National Association), as Trustee, dated January 1, 1998 providing for Deferrable Interest Subordinated Debentures in Series (relating to Quarterly Preferred Securities)9 4a(2)    First Supplemental Indenture to Indenture dated as of January 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank (now, Wachovia Bank, National Association), as Trustee, dated June 1, 1998 providing for the issuance of Floating Rate Deferrable Interest Subordinated Debentures, Series B (relating to Trust Preferred Securities)10 4a(3)    Second Supplemental Indenture to Indenture dated as of January 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank (now, Wachovia Bank, National Association), as Trustee, dated July 1, 1998 providing for the issuance of Deferrable Interest Subordinated Debentures, Series C (relating to Trust Preferred Securities)11 4b          Indenture dated as of November 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank (now, Wachovia Bank, National Association) providing for the issuance of Senior Debt Securities12 4c          First Supplemental Indenture to Indenture dated as of November 1, 1998 between Public Service Enterprise Group Incorporated and Wachovia Bank, National Association, as Trustee, dated September 10, 2002 providing for the issuance of Senior Deferrable Notes (Senior Debt Securities)13 4d          Indenture dated as of December 17, 2002 between Public Service Enterprise Group Incorporated and Wachovia Bank, National Association providing for the issuance of Debentures in Series including 8.75% Deferrable Interest Junior Subordinated Debentures, Series D14 9          Inapplicable10a(1)    Deferred Compensation Plan for Directors1510a(2)    Deferred Compensation Plan for Certain Employees1610a(3)    Amended and Restated Limited Supplemental Benefits Plan for Certain Employees1710a(4)    Mid Career Hire Supplemental Retirement Income Plan1810a(5)    Retirement Income Reinstatement Plan for Non-Represented Employees1910a(6)    1989 Long-Term Incentive Plan, as amended2010a(7)    2001 Long-Term Incentive Plan2110a(8)    Restated and Amended Management Incentive Compensation Plan2210a(9)     Employment Agreement with E. James Ferland dated June 16, 19982310a(10)    Amendment to Employment Agreement with E. James Ferland dated November 20, 20012410a(11)    Second Amendment to Employment Agreement with E. James Ferland dated December 20, 200425
203

10a(12)    Employment Agreement with Thomas M. O'Flynn dated April 18, 20012610a(13)    Amendment to Employment Agreement with Thomas M. O'Flynn dated December 21, 20012710a(14)    Letter Agreement with Patricia A. Rado dated March 24, 19932810a(15)    Employment Agreement with Ralph Izzo dated October 18, 20032910a(16)    Employment Agreement with Frank Cassidy dated October 17, 20003010a(17)    Employment Agreement with Robert J. Dougherty, Jr. dated October 17, 20003110a(18)    Stock Plan for Outside Directors, as amended3210a(19)    Employment Agreement with Robert E. Busch dated April 24, 20013310a(20)    Employee Stock Purchase Plan3410a(21)    Compensation Plan for Outside Directors3510a(22)    2004 Long-Term Incentive Plan3610a(23)    Schedule of Directors' Compensation10a(24)    Key Executive Severance Plan3710a(25)    Retention Program for Key Employees3810b(1)    Agreement and Plan of Merger3910b(2)    Operating Services Contract4011          Inapplicable12          Computation of Ratios of Earnings to Fixed Charges13          Inapplicable14          Code of Ethics8716          Inapplicable18          Inapplicable21          Subsidiaries of the Registrant22          Inapplicable23          Independent Auditors' Consent24          Inapplicable31a          Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act31b          Certification by Thomas M. O'Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act32a          Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code32b          Certification by Thomas M. O'Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code** b.****      **    **PSE&G:** 3a(1)    Restated Certificate of Incorporation of PSE&G41 3a(2)    Certificate of Amendment of Certificate of Restated Certificate of Incorporation of PSE&G filed February 18, 1987 with the State of New Jersey adopting limitations of liability provisions in accordance with an amendment to New Jersey Business Corporation Act42 3a(3)    Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed June 17, 1992 with the State of New Jersey, establishing the 7.44% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock43 3a(4)    Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed March 11, 1993 with the State of New Jersey, establishing the 5.97% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock44
204

 3a(5)    Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed January 27, 1995 with the State of New Jersey, establishing the 6.92% Cumulative Preferred Stock ($100 Par) and the 6.75% Cumulative Preferred Stock—$25 Par as series of Preferred Stock45 3b(1)    Copy of By-Laws of PSE&G46 4a(1)    Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924, securing First and Refunding Mortgage Bond47           Indentures between PSE&G and First Fidelity Bank, National Association (now, Wachovia Bank, National Association), as Trustee, supplemental to Exhibit 4a(1), dated as follows: 4a(2)    April 1, 192748 4a(3)    June 1, 193749 4a(4)    July 1, 193750 4a(5)    December 19, 193951 4a(6)    March 1, 194252 4a(7)    July 1, 1990 (No. 2)53 4a(8)    June 1, 1991 (No. 1)54 4a(9)    July 1, 199355 4a(10)    September 1, 199356 4a(11)    February 1, 199457 4a(12)    March 1, 1994 (No. 2)58 4a(13)    May 1, 199459 4a(14)    October 1, 1994 (No. 2)60 4a(15)    January 1, 1996 (No. 1)61 4a(16)    January 1, 1996 (No. 2)62 4a(17)    May 1, 199863 4a(18)    September 1, 200264 4a(19)    August 1, 200365 4a(20)    December 1, 2003 (No. 1)66 4a(21)    December 1, 2003 (No. 2)67 4a(22)    December 1, 2003 (No. 3)68 4a(23)    December 1, 2003 (No. 4)69 4a(24)    June 1, 200470 4a(25)    August 1, 2004 (No. 1) 4a(26)    August 1, 2004 (No. 2) 4a(27)    August 1, 2004 (No. 3) 4a(28)    August 1, 2004 (No. 4) 4b          Indenture of Trust between PSE&G and Chase Manhattan Bank (National Association) (now, JP Morgan Chase Bank, NA), as Trustee, providing for Secured Medium-Term Notes dated July 1, 199371 4c          Indenture dated as of December 1, 2000 between Public Service and Gas Company and First Union National Bank (now, Wachovia Bank, National Association), as Trustee, providing for Senior Debt Securities7210a(1)    Deferred Compensation Plan for Directors1510a(2)    Deferred Compensation Plan for Certain Employees1610a(3)    Amended and Restated Limited Supplemental Benefits Plan for Certain Employees1710a(4)    Mid Career Hire Supplemental Retirement Income Plan18
205

10a(5)    Retirement Income Reinstatement Plan for Non-Represented Employees1910a(6)    1989 Long-Term Incentive Plan, as amended2010a(7)    2001 Long-Term Incentive Plan2110a(8)    Restated and Amended Management Incentive Compensation Plan2210a(9)    Employment Agreement with E. James Ferland, dated June 16, 19982310a(10)    Amendment to Employment Agreement with E. James Ferland dated November 20, 20012410a(11)    Second Amendment to Employment Agreement with E. James Ferland dated December 20, 20042510a(12)    Letter Agreement with Patricia A. Rado dated March 24, 19932810a(13)    Employment Agreement with Ralph Izzo dated October 18, 20032910a(14)    Employment Agreement with Robert E. Busch dated April 24, 20013310a(15)    Employee Stock Purchase Plan3410a(16)    Stock Plan for Outside Directors, as amended3210a(17)    Compensation Plan for Outside Directors3510a(18)    2004 Long-Term Incentive Plan3610a(19)    Key Executive Severance Plan3710a(20)    Retention Program for Key Employees3811          Inapplicable12a          Computation of Ratios of Earnings to Fixed Charges12b          Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements13          Inapplicable14          Code of Ethics8716          Inapplicable18          Inapplicable19          Inapplicable21a          Inapplicable23a          Independent Auditors' Consent24          Inapplicable31c          Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act31d          Certification by Robert E. Busch pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act32c          Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code32d          Certification by Robert E. Busch, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code** c.****      **    **Power:** 3a          Certificate of Formation of PSEG Power LLC73 3b          PSEG Power LLC Limited Liability Company Agreement74 3c          Trust Agreement for PSEG Power Capital Trust I75 3d          Trust Agreement for PSEG Power Capital Trust II76 3e          Trust Agreement for PSEG Power Capital Trust III77 3f          Trust Agreement for PSEG Power Capital Trust IV78 3g          Trust Agreement for PSEG Power Capital Trust V79
206

4a          Indenture dated April 16, 2001 between and among PSEG Power, PESG Fossil, PSEG Nuclear, PSEG Energy Resources & Trade and The Bank of New York and form of Subsidiary Guaranty included therein804b          First Supplemental Indenture, supplemental to Exhibit 4a, dated as of March 13,    20028110a(1)    Deferred Compensation Plan for Certain Employees1610a(2)    Amended and Restated Limited Supplemental Benefits Plan for Certain Employees1710a(3)    Mid Career Hire Supplemental Retirement Income Plan1810a(4)    Retirement Income Reinstatement Plan for Non-Represented Employees1910a(5)    1989 Long-Term Incentive Plan, as amended2010a(6)    2001 Long-Term Incentive Plan2110a(7)    Restated and Amended Management Incentive Compensation Plan2210a(8)    Employment Agreement with E. James Ferland, dated June 16, 19982310a(9)    Amendment to Employment Agreement with E. James Ferland dated November 20, 20012410a(10)    Second Amendment to Employment Agreement with E. James Ferland dated December 20, 20042510a(11)    Employment Agreement with Thomas M. O'Flynn dated April 18, 20012610a(12)    Amendment to Employment Agreement with Thomas M. O'Flynn dated December 21, 20012710a(13)    Letter Agreement with Patricia A. Rado dated March 24, 19932810a(14)    Employment Agreement with Frank Cassidy dated October 17, 20003010a(15)    Employee Stock Purchase Plan3410a(16)    2004 Long-Term Incentive Plan3610a(17)    Key Executive Severance Plan3710a(18)    Retention Program for Key Employees3810b(1)    Operating Services Contract4011          Inapplicable12c          Computation of Ratio of Earnings to Fixed Charges13          Inapplicable14          Code of Ethics8716          Inapplicable18          Inapplicable19          Inapplicable23          Independent Auditors' Consent24          Inapplicable31e          Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act31f          Certification by Thomas M. O'Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act32e          Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code32f          Certification by Thomas M. O'Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code**d.****      **    **Energy Holdings:**3a          Certificate of Formation of PSEG Energy Holdings L.L.C.823b          Certificate of Amendment to Certificate of Formation of PSEG Energy Holdings L.L.C.833c          Limited Liability Company Agreement of PSEG Energy Holdings L.L.C.84
207

 4a          Indenture dated October 8, 1999 between Energy Holdings and First Union National Bank (now Wachovia Bank, National Association)85 4b          First Supplemental Indenture to Exhibit 4a between Energy Holdings and Wachovia Bank, National Association dated September 30, 20028610a(1)    Deferred Compensation Plan for Certain Employees1610a(2)    Amended and Restated Limited Supplemental Benefits Plan for Certain Employees1710a(3)    Mid Career Hire Supplemental Retirement Income Plan1810a(4)    Retirement Income Reinstatement Plan for Non-Represented Employees1910a(5)    1989 Long-Term Incentive Plan, as amended2010a(6)    2001 Long-Term Incentive Plan2110a(7)    Restated and Amended Management Incentive Compensation Plan2210a(8)    Employment Agreement with E. James Ferland, dated June 16, 19982310a(9)    Amendment to Employment Agreement with E. James Ferland dated November 20, 20012410a(10)    Second Amendment to Employment Agreement with E. James Ferland dated December 20, 20042510a(11)    Employment Agreement with Thomas M. O'Flynn dated April 18, 20012610a(12)    Amendment to Employment Agreement with Thomas M. O'Flynn dated December 21, 20012710a(13)    Employment Agreement with Robert J. Dougherty, Jr. dated October 17, 20003110a(14)    Employee Stock Purchase Plan3410a(15)    2004 Long-Term Incentive Plan3610a(16)    Key Executive Severance Plan3710a(17)    Retention Program for Key Employees3811          Inapplicable12d          Computation of Ratios of Earnings to Fixed Charges13          Inapplicable14          Code of Ethics8716          Inapplicable19          Inapplicable24          Inapplicable31g          Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act31h          Certification by Thomas M. O'Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act32g          Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code32h          Certification by Thomas M. O'Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
**
(1) Filed as Exhibit 3(a) to Registration Statement on Form S-4, No. 33-2935 and incorporated herein by this reference.(2) Filed as Exhibit 4.3 to Registration Statement on Form S-3, No. 333-86372 filed on April 16, 2002 and incorporated herein by this reference.(3) Filed as Exhibit 3(c) with Annual Report on Form 10-K for the year ended December 31, 1987, File No. 001-09120 on April 11, 1988 and incorporated herein by this reference.
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(4) Filed as Exhibit 3(d) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference.(5) Filed as Exhibit 3 with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1998, File No. 001-09120 on August 14, 1998 and incorporated herein by this reference.(6) Filed as Exhibit 3(f) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference.(7) Filed as Exhibit 4.3 with Current Report on Form 8-K, File No. 001-09120 on September 9, 2002 and incorporated herein by this reference.(8) Filed as Exhibit 3(h) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference.(9) Filed as Exhibit 4(f) with Quarterly Report on Form 10-Q for the Quarter ended March 31, 1998, File No. 001-09120 on May 13, 1998 and incorporated herein by this reference.(10) Filed as Exhibit 4(a) with Current Report on Form 8-K, File No. 001-09120 on August 14, 1998 and incorporated herein by this reference.(11) Filed as Exhibit 4(b) with Current Report on Form 8-K, File No. 001-09120 on August 14, 1998 and incorporated herein by this reference.(12) Filed as Exhibit 4(f) with Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-09120 on February 22, 1999 and incorporated herein by this reference.(13) Filed as Exhibit 4(c) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference.(14) Filed as Exhibit 4(d) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference.(15) Filed as Exhibit 10a(1) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference.(16) Filed as Exhibit 10a(2) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference.(17) Filed as Exhibit 10 with Current Report on Form 8-K , File No. 001-09120, on January 24, 2005 and incorporated herein by this reference.(18) Filed as Exhibit 10a(4) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference.(19) Filed as Exhibit 10a(5) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference.(20) Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the Quarter ended September 30, 2002, File No. 001-09120, on November 2, 2002 and incorporated herein by this reference.(21) Filed as Exhibit 10a(7) with Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-09120, on March 6, 2001 and incorporated herein by this reference.(22) Filed as Exhibit 10a(8) with Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-09120, on March 6, 2001 and incorporated herein by this reference.(23) Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1998, File No. 001-09120, on August 14, 1998 and incorporated herein by this reference.(24) Filed as Exhibit 10a(10) with Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-09120, on March 1, 2002 and incorporated herein by this reference.(25) Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120, on December 20, 2004 and incorporated herein by this reference.(26) Filed as Exhibit 10a(24) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001, File No. 001-09120, on August 9, 2001 and incorporated herein by this reference.
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(27) Filed as Exhibit 10a(12) with Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-09120, on March 1, 2002 and incorporated herein by this reference.(28) Filed as Exhibit 10a(14) with Annual Report on Form 10-K for the year ended December 31, 1993, File No. 001-09120, on February 26, 1994 and incorporated herein by this reference.(29) File as Exhibit 10 with Quarterly Report on Form 10-Q for the Quarter ended September 30, 2003, File No. 001-09120, on October 30, 2003 and incorporated herein by this reference.(30) Filed as Exhibit 10a(19) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 2000, File No. 001-09120, on November 13, 2000 and incorporated herein by this reference.(31) Filed as Exhibit 10a(20) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 2000, File No. 001-09120, on November 13, 2000 and incorporated herein by this reference.(32) Filed as Exhibit 10a(17) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.(33) Filed as Exhibit 10a(23) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001, File No. 001-09120, on August 9, 2001 and incorporated herein by this reference.(34) Filed with Registration Statement on Form S-8, File No. 333-106330 filed on June 20, 2003 and incorporated herein by this reference.(35) Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.(36) Filed as Exhibit 10a(21) with Annual Report on Form 10-K for the Year ended December 31, 2003, File No. 001-09120, on February 25, 2004 and incorporated herein by this reference.(37) Filed as Exhibit 10.2 with Current Report on Form 8-K, File No. 001-009120, on December 20, 2004 and incorporated herein by this reference.(38) Filed as Exhibit 10.3 with Current Report on Form 8-K, File No. 001-009120, on December 20, 2004 and incorporated herein by this reference.(39) Filed as Exhibit 2.1 with Current Report on Form 8-K, File No. 001-009120, on December 20, 2004 and incorporated herein by this reference.(40) Filed as Exhibit 99.2 with Current Report on Form 8-K, File No. 001-009120, on December 20, 2004 and incorporated herein by this reference.(41) Filed as Exhibit 3(a) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1986, File No. 001-00973, on August 28, 1986 and incorporated herein by this reference.(42) Filed as Exhibit 3a(2) with Annual Report on Form 10-K for the year ended December 31, 1987, File No. 001-00973, on March 28, 1988 and incorporated herein by this reference.(43) Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.(44) Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.(45) Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.(46) Filed as Exhibit 3b(1) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 2000, No. 001-00973 filed on August 8, 2000 and incorporated herein by this reference.(47) Filed as Exhibit 4b(1) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.(48) Filed as Exhibit 4b(2) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.(49) Filed as Exhibit 4b(3) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.
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(50) Filed as Exhibit 4b(4) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.(51) Filed as Exhibit 4b(5) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.(52) Filed as Exhibit 4b(6) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.(53) Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on July 25, 1990 and incorporated herein by this reference.(54) Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on July 1, 1991 and incorporated herein by this reference.(55) Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on May 25, 1993 and incorporated herein by this reference.(56) Filed as Exhibit 4(i) with Current Report on Form 8-K, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.(57) Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.(58) Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on February 3, 1994 and incorporated herein by this reference.(59) Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on March 15, 1994 and incorporated herein by this reference.(60) Filed as Exhibit 4a(91) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1994, File No. 001-00973, on November 8, 1994 and incorporated herein by this reference.(61) Filed as Exhibit 4a(2) on Form 8-A, File No. 001-00973 on January 26, 1996 and incorporated herein by this reference.(62) Filed as Exhibit 4a(3) on Form 8-A, File No. 001-00973 on January 26, 1996 and incorporated herein by this reference.(63) Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on May 15, 1998 and incorporated herein by this reference.(64) Filed as Exhibit 4a(97) with Annual Report on Form 10-K for the Year ended December 31, 2002, File No. 001-00973 on February 25, 2003 and incorporated herein by this reference.(65) Filed as Exhibit 4a(98) with Annual Report on Form 10-K for the Year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.(66) Filed as Exhibit 4a(99) with Annual Report on Form 10-K for the Year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.(67) Filed as Exhibit 4a(100) with Annual Report on Form 10-K for the Year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.(68) Filed as Exhibit 4a(101) with Annual Report on Form 10-K for the Year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.(69) Filed as Exhibit 4a(102) with Annual Report on Form 10-K for the Year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.(70) Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the Quarter ended June 30, 2004, File No. 001-00973 on August 3, 2004 and incorporated herein by this reference.(71) Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.(72) Filed as Exhibit 4.6 to Registration Statement on Form S-3, No. 333-76020 filed on December 27, 2001 and incorporated herein by this reference.
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(73) Filed as Exhibit 3.1 to Registration Statement on Form S-4, No. 333-69228 filed on October 5, 2001 and incorporated herein by this reference.(74) Filed as Exhibit 3.2 to Registration Statement on Form S-4, No. 333-69228 filed on October 5, 2001 and incorporated herein by this reference.(75) Filed as Exhibit 3.6 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.(76) Filed as Exhibit 3.7 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.(77) Filed as Exhibit 3.8 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.(78) Filed as Exhibit 3.9 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.(79) Filed as Exhibit 3.10 to Registration Statement on Form S-3, No. filed 333-105704 on May 30, 2003 and incorporated herein by this reference.(80) Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-69228 filed on October 5, 2001 and incorporated herein by this reference.(81) Filed as Exhibit 4.7 with Quarterly Report on Form 10-Q for the Quarter ended March 31, 2002, File No. 001-49614, on May 15, 2002 and incorporated herein by this reference.(82) Filed as Exhibit 3 with Current Report on Form 8-K, File No. 000-32503 on October 4, 2002 and incorporated herein by this reference.(83) Filed as Exhibit 3.1 with Current Report on Form 8-K, File No. 000-32503 on October 4, 2002 and incorporated herein by this reference.(84) Filed as Exhibit 3.2 with Current Report on Form 8-K, File No. 000-32503 on October 4, 2002 and incorporated herein by this reference.(85) Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-95697 filed on January 28, 2000 and incorporated herein by this reference.(86) Filed as Exhibit 4 with Current Report on Form 8-K, File No. 000-32503 on October 4, 2002 and incorporated herein by this reference.(87) Filed as Exhibit 14 with Annual Report on Form 10-K for the year ended December 31, 2004, File Nos. 001-09120, 001-00973, 001-49614 and 000-32503, and incorporated herein by reference.
212

**SCHEDULE II**

**PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDSchedule II—Valuation and Qualifying AccountsYears Ended December 31, 2004—December 31, 2002**
**Column A** **Column B** **Column C** **Column D** **Column E**      **Additions**        **Description** **Balance atBeginningof Period** **Charged tocost andexpenses** **Charged tootheraccounts–describe** **Deductions–describe** **Balance atEnd ofPeriod**  **(Millions)**
**2004:**
                    
Allowance for Doubtful Accounts
    $40     $47         $—         $53(A)(K)            $34 
Materials and Supplies Valuation Reserve
     15      —          —          6(B)             9 
Other Reserves
     14      —          —          5(B)             9 
Other Valuation Allowances
     24      —          —          10(F)             14 
**2003:**
                    
Allowance for Doubtful Accounts
    $47     $52         $—         $59(A)(E)            $40 
Materials and Supplies Valuation Reserve
     5      11(I)         —          1(B)             15 
Other Reserves
     12      17(D)(J)         2(G)         17(L)             14 
Other Valuation Allowances
     28      8          —          12(E)(F)             24 
**2002:**
                    
Allowance for Doubtful Accounts
    $40     $58         $—         $51(A)(H)            $47 
Materials and Supplies Valuation Reserve
     2      2          1(C)         —              5 
Other Reserves
     2      10(D)         —          —              12 
Other Valuation Allowances
     29      2          —          3(E)(F)             28                     
   (A)   Accounts Receivable/Investments written off.   (B)   Reduced reserve to appropriate level and to remove obsolete inventory.   (C)   Acquired two Connecticut electric generating stations.   (D)   Includes various liquidity, credit and bad debt reserves.   (E)   Valuation allowances consolidated in connection with the acquisition of SAESA.   (F)   Recorded in connection with the sales of certain properties held by EGDC, $10 million, $1 million and $2 million in 2004, 2003 and 2002, respectively.   (G)   Includes fuel reserve related to Connecticut acquisition.   (H)   Reclassified to Discontinued Operations.   (I)   Increased reserve due to obsolescence, excess and damaged items.   (J)   Reserve established for coal ash disposal costs.   (K)   Valuation allowances reversed      in connection with PETAMC Acccounts Receivable settlement.   (L)   Includes amounts for Enron      settlement.
213

    
**PUBLIC SERVICE ELECTRIC AND GAS COMPANYSchedule II—Valuation and Qualifying AccountsYears Ended December 31, 2004—December 31, 2002**
**Column A** **Column B** **Column C** **Column D** **Column E**      **Additions**        **Description** **Balance atBeginningof Period** **Charged tocost andexpenses** **Charged tootheraccounts–describe** **Deductions–describe** **Balance atEnd ofPeriod**  **(Millions)**
**2004:**
                    
Allowance for Doubtful Accounts
    $34     $47     $—     $47(A)        $34 
**2003:**
                    
Allowance for Doubtful Accounts
    $32     $46     $—     $44(A)        $34 
**2002:**
                    
Allowance for Doubtful Accounts
    $38     $43     $—     $49(A)        $32                        (A)   Accounts Receivable/Investments written off.
**PSEG POWER LLCSchedule II—Valuation and Qualifying AccountsYears Ended December 31, 2004—December 31, 2002**
**Column A** **Column B** **Column C** **Column D** **Column E**      **Additions**        **Description** **Balance atBeginningof Period** **Charged tocost andexpenses** **Charged tootheraccounts–describe** **Deductions–describe** **Balance atEnd ofPeriod**  **(Millions)**
**2004:**
                    
Materials and Supplies Valuation Reserve
    $15     $—     $—     $6(A)    $9 
Other Reserves
     14      —      —      5(A)     9 
**2003:**
                    
Materials and Supplies Valuation Reserve
    $5     $11(E)    $—     $1(A)    $15 
Other Reserves
     12      17(C)(F)     2(D)     17(G)     14 
**2002:**
                    
Materials and Supplies Valuation Reserve
    $2     $2     $1(B)    $—     $5 
Other Reserves
     2      10(C)     —      —      12                        (A)   Reduced reserve to appropriate level and removed obsolete inventory.   (B)   Acquired two Connecticut electric generation stations.   (C)   Includes various liquidity, credit and bad debt reserves.   (D)   Includes fuel reserve related to Connecticut acquisition.   (E)   Increased reserve due to obsolescence, excess and damaged items.   (F)   Reserve established for coal ash disposal costs.   (G)   Includes amounts related to Enron settlement.
214

**PSEG ENERGY HOLDINGS LLCSchedule II—Valuation and Qualifying AccountsYears Ended December 31, 2004—December 31, 2002**
**Column A** **Column B** **Column C** **Column D** **Column E**      **Additions**        **Description** **Balance atBeginningof Period** **Charged tocost andexpenses** **Charged tootheraccounts–describe** **Deductions–describe** **Balance atEnd ofPeriod**  **(Millions)**
**2004:**
                    
Allowance for Doubtful Accounts
    $6     $—     $—     $6(E)    $— 
Other Valuation Allowances
     24      —      —      10(B)     14 
**2003:**
                    
Allowance for Doubtful Accounts
    $15     $6     $—     $15(A)    $6 
Other Valuation Allowances
     28      8      —      12(A)(B)     24 
**2002:**
                    
Allowance for Doubtful Accounts
    $2     $15(C)    $—     $2(D)    $15 
Other Valuation Allowances
     29      2      —      3(A)(B)     28                        (A)   Valuation allowances consolidated in connection with the acquisition of SAESA.   (B)   Recorded in connection with the sales of certain properties held by EGDC, $10 million, $1 million and $2 million in 2004, 2003 and 2002, respectively.   (C)   Reserve established for Accounts Receivable in Argentina.   (D)   Reclassified to Discontinued Operations.   (E)   Valuation allowances reversed      in connection with PETAMC Accounts Receivable settlement.
215

**SIGNATURES**

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
                                                      PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED                                                            By                   /s/ E. JAMES FERLAND                  **E. James FerlandChairman of the Board, President andChief Executive Officer**
Date: February 28, 2005

      Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
**Signature**    **Title**    **Date**                /s/ E. JAMES FERLAND                **E. James Ferland**    Chairman of the Board,President and Chief Executive Officer andDirector (Principal Executive Officer)    February 28, 2005                /s/ THOMAS M. O'FLYNN                **Thomas M. O'Flynn**    Executive Vice President and ChiefFinancial Officer (Principal FinancialOfficer)    February 28, 2005                /s/ PATRICIA A. RADO                **Patricia A. Rado**    Vice President and Controller(Principal Accounting Officer)    February 28, 2005                /s/ CAROLINE DORSA                **Caroline Dorsa**    Director    February 28, 2005                /s/ ERNEST H. DREW                **Ernest H. Drew**    Director    February 28, 2005                /s/ ALBERT R. GAMPER, JR.                **Albert R. Gamper, Jr.**    Director    February 28, 2005                /s/ CONRAD K. HARPER                **Conrad K. Harper**    Director    February 28, 2005                /s/ WILLIAM V. HICKEY                **William V. Hickey**    Director    February 28, 2005                                      **Shirley Ann Jackson**    Director    February 28, 2005                /s/ THOMAS A. RENYI                **Thomas A. Renyi**    Director    February 28, 2005                /s/ RICHARD J. SWIFT                **Richard J. Swift**    Director    February 28, 2005
216

**SIGNATURES**

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
                                                      PUBLIC SERVICE ELECTRIC  AND GAS COMPANY                                                            By                   /s/ RALPH IZZO                  **Ralph IzzoPresident andChief Operating Officer**
Date: February 28, 2005

      Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
**Signature**    **Title**    **Date**                /s/ E. JAMES FERLAND                **E. James Ferland**    Chairman of the Board and ChiefExecutive Officer and Director(Principal Executive Officer)    February 28, 2005                /s/ ROBERT E. BUSCH                **Robert E. Busch**    Senior Vice President—Finance andChief Financial Officer(Principal Financial Officer)    February 28, 2005                /s/ PATRICIA A. RADO                **Patricia A. Rado**    Vice President and Controller(Principal Accounting Officer)    February 28, 2005                /s/ CAROLINE DORSA                **Caroline Dorsa**    Director    February 28, 2005                /s/ ALBERT R. GAMPER, JR.                **Albert R. Gamper, Jr.**    Director    February 28, 2005                /s/ CONRAD K. HARPER                **Conrad K. Harper**    Director    February 28, 2005
217

**SIGNATURES**

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
                                                PSEG POWER LLC                                                      By                   /s/ FRANK CASSIDY                  **Frank CassidyPresident andChief Operating Officer**
Date: February 28, 2005

      Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
**Signature**    **Title**    **Date**                /s/ E. JAMES FERLAND                **E. James Ferland**    Chairman of the Board and ChiefExecutive Officer and Director(Principal Executive Officer)    February 28, 2005                /s/ THOMAS M. O'FLYNN                **Thomas M. O'Flynn**    Executive Vice President and ChiefFinancial Officer and Director(Principal Financial Officer)    February 28, 2005                /s/ PATRICIA A. RADO                **Patricia A. Rado**    Vice President and Controller(Principal Accounting Officer)    February 28, 2005                /s/ ROBERT E. BUSCH                **Robert E. Busch**    Director    February 28, 2005                /s/ FRANK CASSIDY                **Frank Cassidy**    Director    February 28, 2005                  /s/ ROBERT J. DOUGHERTY, JR.                  **Robert J. Dougherty, Jr.**    Director    February 28, 2005                /s/ R. EDWIN SELOVER                **R. Edwin Selover**    Director    February 28, 2005
218

**SIGNATURES**

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
                                                PSEG ENERGY HOLDINGS LLC                                                      By                   /s/ ROBERT J. DOUGHERTY, JR.                  **Robert J. Dougherty, Jr.President andChief Operating Officer**
Date: February 28, 2005

      Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
**Signature**    **Title**    **Date**                /s/ E. JAMES FERLAND                **E. James Ferland**    Chairman of the Board andChief Executive Officer and Manager(Principal Executive Officer)    February 28, 2005                /s/ THOMAS M. O'FLYNN                **Thomas M. O'Flynn**    Executive Vice President andChief Financial Officer and Manager(Principal Financial Officer)    February 28, 2005                /s/ PATRICIA A. RADO                **Patricia A. Rado**    Vice President and Controller(Principal Accounting Officer)    February 28, 2005                /s/ ROBERT E. BUSCH                **Robert E. Busch**    Manager    February 28, 2005                /s/ FRANK CASSIDY                **Frank Cassidy**    Manager    February 28, 2005              /s/ ROBERT J. DOUGHERTY, JR.              **Robert J. Dougherty, Jr.**    Manager    February 28, 2005                /s/ R. EDWIN SELOVER                **R. Edwin Selover**    Manager    February 28, 2005
219

The following documents are filed as a part of this report:

**a.**
**PSEG:**Exhibit 12: Computation of Ratios of Earnings to Fixed ChargesExhibit 21: Subsidiaries of the RegistrantExhibit 23: Independent Auditors' ConsentExhibit 31a: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934Exhibit 31b: Certification by Thomas M. O'Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934Exhibit 32a: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States CodeExhibit 32b: Certification by Thomas M. O'Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
**b.**
**PSE&G:**Exhibit 12a: Computation of Ratios of Earnings to Fixed ChargesExhibit 12b: Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend RequirementsExhibit 21a: Subsidiaries of RegistrantExhibit 23a: Independent Auditors' ConsentExhibit 31c: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934Exhibit 31d: Certification by Robert E. Busch Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934Exhibit 32c: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States CodeExhibit 32d: Certification by Robert E. Busch Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
**c.**
**Power:**Exhibit 12c: Computation of Ratios of Earnings to Fixed ChargesExhibit 23b: Independent Auditors' ConsentExhibit 31e: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934Exhibit 31f: Certification by Thomas M. O'Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934Exhibit 32e: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States CodeExhibit 32f: Certification by Thomas M. O'Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
**d.**
**Energy Holdings:**Exhibit 12d: Computation of Ratios of Earnings to Fixed ChargesExhibit 31g: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934Exhibit 31h: Certification by Thomas M. O'Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934Exhibit 32g: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States CodeExhibit 32h: Certification by Thomas M. O'Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
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