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**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON, D.C. 20549**

****

**FORM 10-Q**

**(Mark One)**

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

**FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2005**

**OR**

£**  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES 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 L.L.C.(A New Jersey Limited Liability Company)80 Park Plaza—T20Newark, New Jersey 07102-4194973 430-7000http://www.pseg.com** |   | **42-1544079** |   |

      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 £

      As of October 24, 2005, Public Service Enterprise Group Incorporated had outstanding 239,296,281 shares of its sole class of Common Stock, without par value.

      As of October 24, 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.

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

      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 L.L.C.                  | Yes £ |      | No S |   |

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**TABLE OF CONTENTS**
    **Page****FORWARD-LOOKING      STATEMENTS     ii **PART      I. FINANCIAL INFORMATION    
Item        1.
    Financial      Statements    
          
          Public      Service Enterprise Group Incorporated     1 
          
          Public      Service Electric and Gas Company     5 
          
          PSEG      Power LLC     9 
          
          PSEG      Energy Holdings L.L.C.     12 
          
    Notes to Condensed      Consolidated Financial Statements    
          
          Note      1. Organization and Basis of Presentation     16 
          
          Note      2. Recent Accounting Standards     19 
          
          Note      3. Discontinued Operations, Dispositions and Acquisitions     21 
          
          Note      4. Earnings Per Share (EPS)     24 
          
          Note      5. Commitments and Contingent Liabilities     24 
          
          Note      6. Risk Management     36 
          
          Note      7. Comprehensive Income (Loss), Net of Tax     40 
          
          Note      8. Changes in Capitalization     41 
          
          Note      9. Other Income and Deductions     42 
          
          Note      10. Income Taxes     44 
          
          Note      11. Financial Information by Business Segments     45 
          
          Note      12. Related-Party Transactions     46 
          
          Note      13. Guarantees of Debt     49 
Item        2.
    Management’s      Discussion and Analysis of Financial Condition and Results of            Operations (MD&A)     52 
          
    Pending Merger     52 
          
    Overview     54 
          
    Results of      Operations     59 
          
    Liquidity      and Capital Resources     69 
          
    Capital Requirements     75 
          
    Accounting      Matters     76 
Item        3.
    Qualitative      and Quantitative Disclosures About Market Risk     76 
Item        4.
    Controls      and Procedures     82 
**PART II. OTHER INFORMATION**
    
Item        1.
    Legal Proceedings     83 
Item        5.
    Other Information     84 
Item        6.
    Exhibits     87 
Signatures
       88 
i

**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 “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. PublicService Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings L.L.C. (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**
•business conditions, financial market, credit rating, regulatory and other risks resulting from the pending merger with Exelon Corporation; •credit, commodity, interest rate, counterparty and other financial market risks; •liquidity and the ability to access capital 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 make 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; •operating performance or cash flow from investments falling below projected levels; •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, particularly in view of the pending merger with Exelon Corporation; •acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG's, PSE&G's, Power's and Energy Holdings' strategy or structure; •business combinations among competitors and major customers; •general economic conditions, including inflation or deflation; •regulatory issues that significantly impact operations;
ii

•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 recover investments or service debt as a result of any of the risks or uncertainties mentioned herein;
**PSEG, PSE&G and Energy Holdings**
•ability to obtain adequate and timely rate relief;
**PSEG, 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; •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;
**PSEG and Power**
•changes in regulation and safety and security measures at nuclear facilities;
**PSEG and Energy Holdings**
•changes in political regimes in foreign countries; •international developments negatively impacting business; •changes in foreign currency exchange rates; •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.

iii

**PART I. FINANCIAL INFORMATION**

**ITEM 1. FINANCIAL STATEMENTS**

**PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS**
  **For The QuartersEndedSeptember 30,** **For The Nine MonthsEndedSeptember 30,**  **2005** **2004** **2005** **2004**  **(Millions, except for share data)(Unaudited)**
OPERATING REVENUES
    $3,376     $2,749     $9,127     $8,262 
OPERATING EXPENSES
                
Energy Costs
     1,999      1,418      5,213      4,498 
Operation and Maintenance
     560      527      1,734      1,604 
Depreciation and Amortization
     207      190      572      525 
Taxes Other Than Income Taxes
     34      30      105      103                          
Total Operating Expenses
     2,800      2,165      7,624      6,730                          
Income from Equity Method Investments
     29      31      96      92                          
OPERATING INCOME
     605      615      1,599      1,624 
Other Income
     91      45      166      152 
Other Deductions
     (36)     (23)     (64)     (63)
Interest Expense
     (216)     (207)     (631)     (627)
Preferred Stock Dividends
     (1)     (1)     (3)     (3)                         
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
     443      429      1,067      1,083 
Income Tax Expense
     (183)     (177)     (414)     (422)                         
INCOME FROM CONTINUING OPERATIONS
     260      252      653      661 
Loss from Discontinued Operations, including Loss on Disposal, net of tax benefit of $4, $5, $136 and $18 for the quarter and nine months ended 2005 and 2004, respectively
     (7)     (8)     (197)     (22)                         
NET INCOME
    $253     $244     $456     $639                          
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
                
BASIC
     239,034      237,269      238,696      236,724                          
DILUTED
     244,286      237,728      243,212      237,883                          
EARNINGS PER SHARE:
                
BASIC
                
INCOME FROM CONTINUING OPERATIONS
    $1.08     $1.06     $2.73     $2.79 
NET INCOME
    $1.06     $1.03     $1.91     $2.70                          
DILUTED
                
INCOME FROM CONTINUING OPERATIONS
    $1.06     $1.06     $2.68     $2.78 
NET INCOME
    $1.03     $1.03     $1.87     $2.69                                          
See Notes to Condensed Consolidated Financial Statements.

1

**PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONDENSED CONSOLIDATED BALANCE SHEETS**
  **September 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**ASSETS**
        
CURRENT ASSETS
        
Cash and Cash Equivalents
    $608     $279 
Accounts Receivable, net of allowances of $32 and $35 in 2005 and 2004, respectively
     1,764      1,621 
Unbilled Revenues
     227      340 
Fuel
     797      633 
Materials and Supplies
     279      255 
Energy Trading Contracts
     705      161 
Prepayments
     244      122 
Restricted Funds
     82      50 
Assets of Discontinued Operations
     —      511 
Other
     93      203              
Total Current Assets
     4,799      4,175              
      
        
PROPERTY, PLANT AND EQUIPMENT
     19,076      18,620 
Less: Accumulated Depreciation and Amortization
     (5,600)     (5,355)             
Net Property, Plant and Equipment
     13,476      13,265              
NONCURRENT ASSETS
        
Regulatory Assets
     4,960      5,127 
Long-Term Investments
     4,326      4,181 
Nuclear Decommissioning Trust (NDT) Funds
     1,123      1,086 
Other Special Funds
     514      488 
Goodwill and Other Intangibles
     608      630 
Other
     309      292              
Total Noncurrent Assets
     11,840      11,804              
TOTAL ASSETS
    $30,115     $29,244                      
See Notes to Condensed Consolidated Financial Statements.

2

**PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONDENSED CONSOLIDATED BALANCE SHEETS**
  **September 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**LIABILITIES AND CAPITALIZATION**
        
CURRENT LIABILITIES
        
Long-Term Debt Due Within One Year
    $1,453     $386 
Commercial Paper and Loans
     371      638 
Accounts Payable
     1,089      1,362 
Derivative Contracts
     538      207 
Energy Trading Contracts
     287      125 
Accrued Interest
     228      154 
Accrued Taxes
     58      54 
Clean Energy Program
     93      82 
Other
     554      484              
Total Current Liabilities
     4,671      3,492              
NONCURRENT LIABILITIES
        
Deferred Income Taxes and Investment Tax Credits (ITC)
     4,229      4,350 
Regulatory Liabilities
     1,101      545 
Nuclear Decommissioning Liabilities
     331      310 
Other Postretirement Benefit (OPEB) Costs
     585      563 
Clean Energy Program
     261      324 
Environmental Costs
     338      366 
Derivative Contracts
     560      238 
Other
     310      307              
Total Noncurrent Liabilities
     7,715      7,003              
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
        
CAPITALIZATION
        
LONG-TERM DEBT
        
Long-Term Debt
     8,206      8,414 
Securitization Debt
     1,926      1,939 
Project Level, Non-Recourse Debt
     1,198      1,371 
Debt Supporting Trust Preferred Securities
     814      1,201              
Total Long-Term Debt
     12,144      12,925              
SUBSIDIARIES' PREFERRED SECURITIES
        
Preferred Stock Without Mandatory Redemption,$100 par value, 7,500,000 authorized; issued and outstanding, 2005 and 2004—795,234 shares
     80      80              
COMMON STOCKHOLDERS' EQUITY
        
Common Stock, no par, authorized 500,000,000 shares; issued; 2005—265,057,913 shares and 2004—264,128,807 shares
     4,581      4,569 
Treasury Stock, at cost; 2005—25,775,063 shares; 2004—26,029,740 shares
     (968)     (978)
Retained Earnings
     2,480      2,425 
Accumulated Other Comprehensive Loss
     (588)     (272)             
Total Common Stockholders' Equity
     5,505      5,744              
Total Capitalization
     17,729      18,749              
TOTAL LIABILITIES AND CAPITALIZATION
    $30,115     $29,244                      
See Notes to Condensed Consolidated Financial Statements.

3

**PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONSOLIDATED STATEMENTS OF CASH FLOWS**
  **For The Nine Months EndedSeptember 30,**  **2005** **2004**  **(Millions)(Unaudited)**
CASH FLOWS FROM OPERATING ACTIVITIES
        
Net Income
    $456     $639 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Loss (Gain) on Disposal of Discontinued Operations, net of tax
     178      (5)
Gain on Disposition of Property, Plant and Equipment
     (5)     (1)
Write-Down of Project Investments
     22      6 
Depreciation and Amortization
     572      525 
Amortization of Nuclear Fuel
     69      63 
Provision for Deferred Income Taxes (Other than Leases) and ITC
     155      56 
Non-Cash Employee Benefit Plan Costs
     175      161 
Leveraged Lease Losses (Income), Adjusted for Rents Received and Deferred Taxes
     9      (88)
Gain on Sale of Investments
     (50)     (31)
Undistributed Earnings from Affiliates
     (40)     (8)
Foreign Currency Transaction (Gain) Loss
     (1)     9 
Unrealized Losses on Energy Contracts and Other Derivatives
     4      2 
Over Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs
     75      95 
Under Recovery of Societal Benefits Charge (SBC)
     (94)     (31)
Net Realized Gains and Income from NDT Funds
     (94)     (96)
Other Non-Cash Charges
     41      36 
Net Change in Certain Current Assets and Liabilities
     (447)     (124)
Employee Benefit Plan Funding and Related Payments
     (159)     (154)
Proceeds from the Withdrawal of Partnership Interests and Other Distributions
     63      121 
Other
     (22)     79              
Net Cash Provided By Operating Activities
     907      1,254              
CASH FLOWS FROM INVESTING ACTIVITIES
        
Additions to Property, Plant and Equipment
     (751)     (887)
Investments in Joint Ventures, Partnerships and Capital Leases
     —      (15)
Proceeds from Sale of Property, Plant and Equipment
     226      — 
Proceeds from the Sale of Investments and Return of Capital from Partnerships
     26      306 
Proceeds from Collection of Notes Receivable
     132      — 
Restricted Funds
     (47)     (92)
Other
     8      (5)             
Net Cash Used In Investing Activities
     (406)     (693)             
CASH FLOWS FROM FINANCING ACTIVITIES
        
Net Change in Commercial Paper and Loans
     (267)     361 
Issuance of Long-Term Debt
     728      1,398 
Issuance of Non-Recourse Debt
     4      15 
Issuance of Common Stock
     55      63 
Redemptions of Long-Term Debt
     (230)     (2,129)
Repayment of Non-Recourse Debt
     (20)     — 
Cash Dividends Paid on Common Stock
     (401)     (391)
Other
     (42)     (14)             
Net Cash Used In Financing Activities
     (173)     (697)             
Effect of Exchange Rate Change
     1      —              
Net Increase (Decrease) in Cash and Cash Equivalents
     329      (136)
Cash and Cash Equivalents at Beginning of Period
     279      452              
Cash and Cash Equivalents at End of Period
    $608     $316              
Supplemental Disclosure of Cash Flow Information:
        
Income Taxes Paid
    $102     $95 
Interest Paid, Net of Amounts Capitalized
    $618     $558         
See Notes to Condensed Consolidated Financial Statements.

4

**PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS**
  **For The Quarters EndedSeptember 30,** **For The Nine Months EndedSeptember 30,**  **2005** **2004** **2005** **2004**  **(Millions)(Unaudited)**
OPERATING REVENUES
    $1,934     $1,636     $5,559     $5,236 
OPERATING EXPENSES
                
Energy Costs
     1,195      960      3,472      3,203 
Operation and Maintenance
     276      261      839      797 
Depreciation and Amortization
     155      140      418      393 
Taxes Other Than Income Taxes
     35      30      106      103                          
Total Operating Expenses
     1,661      1,391      4,835      4,496                          
OPERATING INCOME
     273      245      724      740 
Other Income
     3      4      7      10 
Other Deductions
     (1)     —      (2)     (1)
Interest Expense
     (86)     (86)     (256)     (273)                         
INCOME BEFORE INCOME TAXES
     189      163      473      476 
Income Tax Expense
     (74)     (70)     (191)     (195)                         
NET INCOME
     115      93      282      281 
Preferred Stock Dividends
     (1)     (1)     (3)     (3)                         
EARNINGS AVAILABLE TO PUBLICSERVICE ENTERPRISE GROUPINCORPORATED
    $114     $92     $279     $278                                          
See disclosures regarding Public Service Electric and Gas Companyincluded in the Notes to Condensed Consolidated Financial Statements.

5

**PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONDENSED CONSOLIDATED BALANCE SHEETS**
  **September 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**ASSETS**
        
CURRENT ASSETS
        
Cash and Cash Equivalents
    $292     $6 
Accounts Receivable, net of allowances of $34 in 2005 and $32 in 2004
     784      745 
Accounts Receivable—Affiliated Companies, net
     240      — 
Unbilled Revenues
     227      340 
Materials and Supplies
     52      45 
Prepayments
     152      61 
Restricted Cash
     7      5 
Other
     20      19              
Total Current Assets
     1,774      1,221              
PROPERTY, PLANT AND EQUIPMENT
     10,466      10,159 
Less: Accumulated Depreciation and Amortization
     (3,583)     (3,471)             
Net Property, Plant and Equipment
     6,883      6,688              
NONCURRENT ASSETS
        
Regulatory Assets
     4,960      5,127 
Long-Term Investments
     142      138 
Other Special Funds
     289      278 
Other
     124      134              
Total Noncurrent Assets
     5,515      5,677              
TOTAL ASSETS
    $14,172     $13,586                      
See disclosures regarding Public Service Electric and Gas Companyincluded in the Notes to Condensed Consolidated Financial Statements.

6

**PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONDENSED CONSOLIDATED BALANCE SHEETS**
  **September 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**LIABILITIES AND CAPITALIZATION**
        
CURRENT LIABILITIES
        
Long-Term Debt Due Within One Year
    $478     $271 
Commercial Paper and Loans
     185      105 
Accounts Payable
     320      250 
Accounts Payable—Affiliated Companies, net
     —      404 
Accrued Interest
     43      59 
Clean Energy Program
     93      82 
Other
     382      311              
Total Current Liabilities
     1,501      1,482              
NONCURRENT LIABILITIES
        
Deferred Income Taxes and ITC
     2,582      2,653 
Other Postretirement Benefit (OPEB) Costs
     551      534 
Regulatory Liabilities
     1,101      545 
Clean Energy Program
     261      324 
Environmental Costs
     283      309 
Other
     41      82              
Total Noncurrent Liabilities
     4,819      4,447              
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
        
CAPITALIZATION
        
LONG-TERM DEBT
        
Long-Term Debt
     2,866      2,938 
Securitization Debt
     1,926      1,939              
Total Long-Term Debt
     4,792      4,877              
PREFERRED SECURITIES
        
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding,2005 and 2004—795,234 shares
     80      80              
COMMON STOCKHOLDER'S EQUITY
        
Common Stock; 150,000,000 shares authorized, 132,450,344 sharesissued and outstanding
     892      892 
Contributed Capital
     171      170 
Basis Adjustment
     986      986 
Retained Earnings
     935      656 
Accumulated Other Comprehensive Loss
     (4)     (4)             
Total Common Stockholder's Equity
     2,980      2,700              
Total Capitalization
     7,852      7,657              
TOTAL LIABILITIES AND CAPITALIZATION
    $14,172     $13,586                      
See disclosures regarding Public Service Electric and Gas Companyincluded in the Notes to Condensed Consolidated Financial Statements.

7

**PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS**
  **For the Nine Months EndedSeptember 30,**  **2005** **2004**  **(Millions)(Unaudited)**
CASH FLOWS FROM OPERATING ACTIVITIES
        
Net Income
    $282     $281 
Adjustments to Reconcile Net Income to Net Cash Flows fromOperating Activities:
        
Depreciation and Amortization
     418      393 
Provision for Deferred Income Taxes and ITC
     (77)     (103)
Non-Cash Employee Benefit Plan Costs
     124      118 
Non-Cash Interest Expense
     13      11 
Employee Benefit Plan Funding and Related Payments
     (104)     (104)
Over Recovery of Electric Energy Costs (BGS and NTC)
     81      42 
(Under) Over Recovery of Gas Costs
     (6)     53 
Under Recovery of SBC
     (94)     (31)
Other Non-Cash Credits
     3      2 
Gain on Sale of Property, Plant and Equipment
     —      (1)
Net Changes in Certain Current Assets and Liabilities:
        
Accounts Receivable and Unbilled Revenues
     (166)     125 
Materials and Supplies
     (7)     — 
Prepayments
     (91)     (103)
Accrued Taxes
     (21)     (5)
Accrued Interest
     (16)     (26)
Accounts Payable
     (334)     (258)
Other Current Assets and Liabilities
     102      (74)
Residential Gas Hedges
     437      86 
Other
     (80)     4              
Net Cash Provided By Operating Activities
     464      410              
CASH FLOWS FROM INVESTING ACTIVITIES
        
Additions to Property, Plant and Equipment
     (372)     (290)
Proceeds from the Sale of Property, Plant and Equipment
     —      1 
Restricted Funds
     (3)     (98)             
Net Cash Used In Investing Activities
     (375)     (387)             
CASH FLOWS FROM FINANCING ACTIVITIES
        
Net Change in Short-Term Debt
     80      285 
Issuance of Long-Term Debt
     250      710 
Redemption of Securitization Debt
     (105)     (99)
Redemption of Long-Term Debt
     (125)     (891)
Issuance of Securitization Debt
     103      — 
Deferred Issuance Costs
     (3)     — 
Cash Dividends Paid on Common Stock
     —      (100)
Preferred Stock Dividends
     (3)     (3)             
Net Cash Provided By (Used In) Financing Activities
     197      (98)             
Net Increase (Decrease) In Cash and Cash Equivalents
     286      (75)
Cash and Cash Equivalents at Beginning of Period
     6      140              
Cash and Cash Equivalents at End of Period
    $292     $65              
Supplemental Disclosure of Cash Flow Information:
        
Income Taxes Paid
    $249     $301 
Interest Paid, Net of Amounts Capitalized
    $250     $281         
See disclosures regarding Public Service Electric and Gas Companyincluded in the Notes to Condensed Consolidated Financial Statements.

8

**PSEG POWER LLCCONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS**
  **For the Quarters EndedSeptember 30,** **For the Nine Months EndedSeptember 30,**  **2005** **2004** **2005** **2004**  **(Millions)(Unaudited)**
OPERATING REVENUES
    $1,444     $1,130     $4,234     $3,818 
OPERATING EXPENSES
                
Energy Costs
     983      636      2,941      2,544 
Operation and Maintenance
     223      211      685      672 
Depreciation and Amortization
     34      29      96      78                          
Total Operating Expenses
     1,240      876      3,722      3,294                          
OPERATING INCOME
     204      254      512      524 
Other Income
     74      36      135      140 
Other Deductions
     (13)     (13)     (33)     (44)
Interest Expense
     (32)     (33)     (86)     (85)                         
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
     233      244      528      535 
Income Tax Expense
     (101)     (105)     (225)     (216)                         
INCOME FROM CONTINUING OPERATIONS
     132      139      303      319 
Loss from Discontinued Operations, net of tax benefit of $4, $5, $13 and $18 for the quarter and nine months ended 2005 and 2004, respectively
     (6)     (8)     (19)     (27)
Loss on Disposal of Discontinued Operations, net of tax benefit of $0 and $123 for the quarter and nine months ended 2005
     (1)     —      (178)     —                          
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
    $125     $131     $106     $292                                          
See disclosures regarding PSEG Power LLCincluded in the Notes to Condensed Consolidated Financial Statements.

9

**PSEG POWER LLCCONDENSED CONSOLIDATED BALANCE SHEETS**
  **September 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**ASSETS**
        
CURRENT ASSETS
        
Cash and Cash Equivalents
    $19     $10 
Accounts Receivable
     829      740 
Accounts Receivable—Affiliated Companies, net
     —      324 
Short-Term Loan to Affiliate
     62      — 
Fuel
     788      621 
Materials and Supplies
     195      175 
Energy Trading Contracts
     705      161 
Assets of Discontinued Operations
     —      511 
Other
     88      61              
Total Current Assets
     2,686      2,603              
PROPERTY, PLANT AND EQUIPMENT
     6,385      6,073 
Less: Accumulated Depreciation and Amortization
     (1,576)     (1,482)             
Net Property, Plant and Equipment
     4,809      4,591              
NONCURRENT ASSETS
        
Deferred Income Taxes and Investment Tax Credits (ITC)
     71      — 
Nuclear Decommissioning Trust (NDT) Funds
     1,123      1,086 
Goodwill and Other Intangibles
     65      107 
Other Special Funds
     130      121 
Other
     146      99              
Total Noncurrent Assets
     1,535      1,413              
TOTAL ASSETS
    $9,030     $8,607              
**LIABILITIES AND MEMBER'S EQUITY**
        
CURRENT LIABILITIES
        
Long-Term Debt Due Within One Year
    $500     $— 
Accounts Payable
     644      992 
Accounts Payable—Affiliated Companies, net
     290      — 
Short-Term Loan from Affiliate
     —      98 
Energy Trading Contracts
     287      125 
Derivative Contracts
     490      151 
Accrued Interest
     96      42 
Other
     129      113              
Total Current Liabilities
     2,436      1,521              
NONCURRENT LIABILITIES
        
Deferred Income Taxes and Investment Tax Credits (ITC)
     —      96 
Nuclear Decommissioning Liabilities
     331      310 
Derivative Contracts
     470      119 
Other
     182      162              
Total Noncurrent Liabilities
     983      687              
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
        
LONG-TERM DEBT
        
Total Long-Term Debt
     2,817      3,316              
MEMBER'S EQUITY
        
Contributed Capital
     2,000      2,000 
Basis Adjustment
     (986)     (986)
Retained Earnings
     2,224      2,118 
Accumulated Other Comprehensive Loss
     (444)     (49)             
Total Member's Equity
     2,794      3,083              
TOTAL LIABILITIES AND MEMBER'S EQUITY
    $9,030     $8,607                      
See disclosures regarding PSEG Power LLCincluded in the Notes to Condensed Consolidated Financial Statements.

10

**PSEG POWER LLCCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS**
  **For the Nine EndedSeptember 30,**  **2005** **2004**  **(Millions)(Unaudited)**
CASH FLOWS FROM OPERATING ACTIVITIES
        
Net Income
    $106     $292 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Loss        on Disposal of Discontinued operations, net of tax benefit
     178      — 
Gain on Disposition of Property, Plant and Equipment
     (5)     — 
Depreciation and Amortization
     96      78 
Amortization of Nuclear Fuel
     69      63 
Interest Accretion on NDT Liability
     21      19 
Provision for Deferred Income Taxes and ITC
     239      134 
Unrealized (Gains) Losses on Energy Contracts and Other Derivatives
     (2)     2 
Non-Cash Employee Benefit Plan Costs
     34      29 
Net Realized Gains and Income from NDT Fund
     (94)     (96)
Net Change in Certain Current Assets and Liabilities:
        
Fuel, Materials and Supplies
     (187)     (174)
Accounts Receivable
     235      176 
Accounts Payable
     (58)     (174)
Other Current Assets and Liabilities
     61      176 
Employee Benefit Plan Funding and Related Payments
     (35)     (36)
Other
     67      85 
Residential Gas Hedges
     (437)     (86)             
Net Cash Provided By Operating Activities
     288      488              
CASH FLOWS FROM INVESTING ACTIVITIES
        
Additions to Property, Plant and Equipment
     (345)     (522)
Sales of Property, Plant and Equipment
     226      — 
Short-Term Loan to Affiliate
     (62)     77 
Other
     —      (4)             
Net Cash Used In Investing Activities
     (181)     (449)             
CASH FLOWS FROM FINANCING ACTIVITIES
        
Issuance of Recourse Long-Term Debt
     —      488 
Redemption of Non-Recourse Long-Term Debt
     —      (800)
Short-Term Loan from Affiliate
     (98)     262              
Net Cash Used In Financing Activities
     (98)     (50)             
Net Increase (Decrease) in Cash and Cash Equivalents
     9      (11)
Cash and Cash Equivalents at Beginning of Period
     10      27              
Cash and Cash Equivalents at End of Period
    $19     $16              
Supplemental Disclosure of Cash Flow Information:
        
Income Taxes Paid
    $9     $19 
Interest Paid, Net of Amounts Capitalized
    $62     $60         
See disclosures regarding PSEG Power LLCincluded in the Notes to Condensed Consolidated Financial Statements.

11

**PSEG ENERGY HOLDINGS L.L.C.CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS**
  **For the Quarters EndedSeptember 30,** **For the Nine Months EndedSeptember 30,**  **2005** **2004** **2005** **2004**  **(Millions)(Unaudited)**
OPERATING REVENUES
                
Electric Generation and Distribution Revenues
    $325     $251     $897     $495 
Income from Capital and Operating Leases
     44      48      136      149 
Other
     10      12      52      57                          
Total Operating Revenues
     379      311      1,085      701                          
OPERATING EXPENSES
                
Energy Costs
     203      148      552      242 
Operation and Maintenance
     58      64      207      163 
Depreciation and Amortization
     14      15      45      40                          
Total Operating Expenses
     275      227      804      445                          
Income from Equity Method Investments
     29      31      96      92                          
OPERATING INCOME
     133      115      377      348 
Other Income
     5      4      14      4 
Other Deductions
     (9)     (8)     (12)     (14)
Interest Expense
     (65)     (66)     (193)     (196)                         
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST
     64      45      186      142 
Income Tax Expense
     (26)     (8)     (43)     (34)
Minority Interests in Earnings of Subsidiaries
     1      (1)     (3)     (3)                         
INCOME FROM CONTINUING OPERATIONS
     39      36      140      105 
Income from Discontinued Operations, including Gain on Disposal, net of tax
     —      —      —      5                          
NET INCOME
     39      36      140      110 
Preference Units Distributions
     —      (3)     (3)     (13)                         
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
    $39     $33     $137     $97                                          
See disclosures regarding PSEG Energy Holdings L.L.C.included in the Notes to Condensed Consolidated Financial Statements.

12

**PSEG ENERGY HOLDINGS L.L.C.CONDENSED CONSOLIDATED BALANCE SHEETS**
  **September 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**ASSETS**
        
CURRENT ASSETS
        
Cash and Cash Equivalents
    $256       $199 
Accounts Receivable:
        
Trade—net of allowances of $0 in 2005 and 2004
     137        114 
Other Accounts Receivable
     13        20 
Affiliated Companies
     —        19 
Notes Receivable:
        
Affiliated Companies
     61        115 
Other
     5        138 
Inventory
     40        47 
Restricted Funds
     75        45 
Other
     7        7                
Total Current Assets
     594        704                
PROPERTY, PLANT AND EQUIPMENT
     1,916        2,084 
Less: Accumulated Depreciation and Amortization
     (252)       (227)               
Net Property, Plant and Equipment
     1,664        1,857                
NONCURRENT ASSETS
        
Leveraged Leases, net
     2,926        2,851 
Corporate Joint Ventures
     992        894 
Partnership Interests
     212        219 
Goodwill and Other Intangibles
     537        517 
Other
     119        153                
Total Noncurrent Assets
     4,786        4,634                
TOTAL ASSETS
    $7,044       $7,195                        
See disclosures regarding PSEG Energy Holdings L.L.C.included in the Notes to Condensed Consolidated Financial Statements.

13

**PSEG ENERGY HOLDINGS L.L.C.CONDENSED CONSOLIDATED BALANCE SHEETS**
  **September 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**LIABILITIES AND MEMBER'S EQUITY**
        
CURRENT LIABILITIES
        
Long-Term Debt Due Within One Year
    $39       $66 
Accounts Payable:
        
Trade
     58        59 
Affiliated Companies
     3        2 
Derivative Contracts
     36        37 
Accrued Interest
     74        51 
Other
     53        71                
Total Current Liabilities
     263        286                
NONCURRENT LIABILITIES
        
Deferred Income Taxes and Investment and Energy Tax Credits
     1,702        1,587 
Derivative Contracts
     71        88 
Other
     76        56                
Total Noncurrent Liabilities
     1,849        1,731                
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
        
MINORITY INTERESTS
     30        35                
LONG-TERM DEBT
        
Project Level, Non-Recourse Debt
     1,198        1,371 
Senior Notes
     1,754        1,756                
Total Long-Term Debt
     2,952        3,127                
MEMBER'S EQUITY
        
Ordinary Unit
     1,713        1,813 
Preference Units
     —        184 
Retained Earnings
     365        228 
Accumulated Other Comprehensive Loss
     (128)       (209)               
Total Member's Equity
     1,950        2,016                
TOTAL LIABILITIES AND MEMBER'S EQUITY
    $7,044       $7,195                        
See disclosures regarding PSEG Energy Holdings L.L.C.included in the Notes to Condensed Consolidated Financial Statements.

14

**PSEG ENERGY HOLDINGS L.L.C.CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS**
  **For the Nine Months EndedSeptember 30,**  **2005** **2004**  **(Millions)(Unaudited)**
CASH FLOWS FROM OPERATING ACTIVITIES
        
Net Income
    $140     $110 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Gain on Disposal of Discontinued Operations, net of tax
     —      (5)
Depreciation and Amortization
     45      40 
Demand Side Management Amortization
     6      6 
Investment Write-off
     22      — 
Deferred Income Taxes (Other than Leases)
     (7)     22 
Leveraged Lease Expense (Income), Adjusted for Rents Received and Deferred Income Taxes
     9      (88)
Undistributed Earnings from Affiliates
     (40)     (8)
Gain on Sale of Investments
     (50)     (31)
Unrealized (Gain) Loss on Investments
     (1)     1 
Foreign Currency Transaction (Gain) Loss
     (1)     9 
Change in Fair Value of Derivative Financial Instruments
     6      (1)
Other Non-Cash Charges
     4      7 
Net Changes in Certain Current Assets and Liabilities:
        
Accounts Receivable
     (3)     229 
Inventory
     4      (5)
Accounts Payable
     18      (38)
Other Current Assets and Liabilities
     6      (4)
Proceeds from Withdrawal of Partnership Interests and Other Distributions
     63      121 
Other
     (1)     3              
Net Cash Provided By Operating Activities
     220      368              
CASH FLOWS FROM INVESTING ACTIVITIES
        
Additions to Property, Plant and Equipment
     (26)     (64)
Investments in Joint Ventures, Partnerships, and Leveraged Lease Agreements
     —      (15)
Proceeds from the Sale of Investments and Return of Capital from Partnerships
     26      77 
Proceeds from Termination of Capital Leases
     —      229 
Short-Term Loan Receivable—Affiliated Company
     54      155 
Restricted Funds
     (44)     6 
Proceeds from Collection of Notes Receivable
     132      — 
Other
     3      1              
Net Cash Provided By Investing Activities
     145      389              
CASH FLOWS FROM FINANCING ACTIVITIES
        
Repayment of Senior Notes
     —      (311)
Proceeds from Project-Level Non-Recourse Long-Term Debt
     4      15 
Repayment of Project-Level Non-Recourse Long-Term Debt
     (20)     (28)
Return of Capital Contributed
     (100)     (75)
Cash Distributions Paid on Preference Units
     (3)     (13)
Redemptions of Preference Units
     (184)     (225)
Other
     (6)     —              
Net Cash Used In Financing Activities
     (309)     (637)             
Effect of Exchange Rate Change
     1      —              
Net Increase In Cash and Cash Equivalents
     57      120 
Cash and Cash Equivalents at Beginning of Period
     199      104              
Cash and Cash Equivalents at End of Period
    $256     $224              
Supplemental Disclosure of Cash Flow Information:
        
Income Taxes Paid (Received)
    $4     $(173)
Interest Paid, Net of Amounts Capitalized
    $203     $127         
See disclosures regarding PSEG Energy Holdings L.L.C.included in the Notes to Condensed Consolidated Financial Statements.

15

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

      This combined Form 10-Q 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 L.L.C. (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 representations as to any other company.

**Note 1. Organization and Basis of Presentation**

**Organization**

      **PSEG**

      PSEG has four principal direct wholly owned subsidiaries: PSE&G, Power, Energy Holdings and PSEG Services Corporation (Services).

      As previously disclosed, 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.

      The Merger Agreement has been unanimously approved by both companies' Boards of Directors. On June 30, 2005, the Federal Energy Regulatory Commission (FERC) approved the Merger. On July 19, 2005, shareholders of PSEG voted to approve the Merger and on July 22, 2005, shareholders of Exelon voted to approve the issuance of common shares to PSEG shareholders to effect the Merger.

      Completion of the Merger is subject to approval by a number of governmental authorities, some of which have already been obtained. The authorities may impose conditions on completion of the Merger, require changes to the terms of the Merger or fail to approve the Merger.

      **PSE&G**

      PSE&G is an operating public utility engaged principally in the transmission of electric energy 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 FERC.

      PSE&G also owns PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), bankruptcy-remote entities that purchased certain transition property from PSE&G and issued transition bonds secured by such property. The transition property consists principally of the right to receive electricity consumption-based per kilowatt hour charges from PSE&G electric distribution customers, which represents the irrevocable right to receive amounts sufficient to recover certain of PSE&G's transition costs related to deregulation, as approved by the BPU.

      **Power**

      Power is a multi-regional, 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 and Nuclear is subject to regulation by the Nuclear Regulatory Commission (NRC).

16

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

      **Energy Holdings**

      Energy Holdings  has two principal direct wholly owned subsidiaries: PSEG Global L.L.C. (Global),  which owns and operates international and domestic projects engaged in the generation  and distribution of energy, including power production facilities and electric  distribution companies and PSEG Resources L.L.C. (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.

      **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, records 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.

**Basis of Presentation**

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

      The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with and update and supplement matters discussed in PSEG's, PSE&G's, Power's and Energy Holdings' respective Annual Reports on Form 10-K for the year ended December 31, 2004 and Quarterly Reports on Form 10-Qfor the quarters ended March 31, 2005 and June 30, 2005.

      The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2004. Certain reclassifications of prior period data have been made to conform with the current presentation.

**Pension and Other Postretirement Benefits (OPEB)**

      **PSEG**

      PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG and its participating affiliates' current and former employees who meet certain eligibility criteria. As a result of union negotiations, certain changes to the pension plans and OPEB plans were made and communicated in March 2005. These include increases to the benefit formula in the pension plan, supplemental pension benefits and certain other changes to OPEB. Substantially all changes to the pension plans became effective May 1, 2005 and the majority of changes to the OPEB plans will be effective January 1, 2006 or July 1, 2006. The pension benefits and OPEB obligations, as well as the asset values, have been re-measured as of March 31, 2005 to reflect the effect of the plan changes. With these assumptionchanges and based on a discount rate of 6.0%, the new pension projected benefit obligation and accumulated benefit obligation as of March 31, 2005 were $3.5 billion and $2.9 billion, respectively. The new OPEB accumulated benefit obligation as of March 31, 2005 was $1.1 billion. The

17

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

annual net periodic pension benefit costs for 2005 increase by approximately $2 million or 2% and the 2005 annual net OPEB costs increase by approximately $11 million or 11% from costs that would have been expensed in 2005 had the plans' provisions remained unchanged.

      The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension plans and OPEB plans on an aggregate basis:
  **Pension Benefits** **OPEB** **Pension Benefits** **OPEB**  **Quarters EndedSeptember 30,** **Quarters EndedSeptember 30,** **Nine Months EndedSeptember 30,** **Nine Months EndedSeptember 30,**  **2005** **2004** **2005** **2004** **2005** **2004** **2005** **2004**  **(Millions)**                                
***Components of Net Periodic Benefit Costs:***
                                
Service Cost
    $22     $21     $4     $5     $67     $62     $13     $17 
Interest Cost
     52      49      16      13      155      147      46      41 
Expected Return on Plan Assets
     (62)     (58)     (2)     (2)     (187)     (174)     (7)     (6)
Amortization of Net
                                
Transition Obligation
     —      —      7      7      —      —      21      21 
Prior Service Cost
     4      4      3      —      12      12      6      — 
Loss
     12      9      —      —      35      28      2      —                                                  
Net Periodic Benefit Costs
     28      25      28      23      82      75      81      73 
Effect of Regulatory Asset
     —      —      5      5      —      —      15      15                                                  
Total Benefit Costs
    $28     $25     $33     $28     $82     $75     $96     $88                                                                                  
      **PSEG, PSE&G, Power and Energy Holdings**

      Pension costs and OPEB costs for PSEG, PSE&G, Power, Energy Holdings and Services are detailed as follows:
  **Pension Benefits** **OPEB** **Pension Benefits** **OPEB**  **Quarters EndedSeptember 30,** **Quarters EndedSeptember 30,** **Nine Months EndedSeptember 30,** **Nine Months EndedSeptember 30,**  **2005** **2004** **2005** **2004** **2005** **2004** **2005** **2004**  **(Millions)**                                
PSE&G
    $14     $13     $29     $25     $41     $39     $84     $79 
Power
     8      8      3      2      24      23      9      6 
Energy Holdings
     1      1      —      —      2      2      —      — 
Services
     5      3      1      1      15      11      3      3                                                  
Total Benefit Costs
    $28     $25     $33     $28     $82     $75     $96     $88                                                                                  
**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.

      PSEG also grants restricted stock and performance units to certain key executives and employees. In 2005, 270,000 shares of restricted stock have been granted under the 2004 Long-Term Incentive Plan to certain key executives and employees. These shares vest on a staggered schedule beginning in January 2006 and become fully vested in January 2008, except for accelerated vesting in the case of retirement or involuntary separation without cause. Compensation expense on the restricted stock grants is recorded ratably over the vesting period. Compensation expense for performance units is measured and recognized once it can be determined that the performance goals will be achieved.

18

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

      The following table illustrates the effect on Net Income and Earnings Per Share if PSEG had applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation,” (SFAS 123) to stock-based employee compensation:
  **Quarters EndedSeptember 30,** **Nine Months EndedSeptember 30,**  **2005** **2004** **2005** **2004**  **(Millions, except for share data)**                
Net Income, as reported
    $253     $244     $456     $639 
Add: Total stock-based compensation expensed during the period, net of related tax effects
     1      1      3      1 
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects
     (2)     (2)     (5)     (4)                         
Pro forma Net Income
    $252     $243     $454     $636                          
Earnings Per Share:
                
Basic—as reported
    $1.06     $1.03     $1.91     $2.70 
Basic—pro forma
    $1.05     $1.02     $1.90     $2.68 
Diluted—as reported
    $1.03     $1.03     $1.87     $2.69 
Diluted—pro forma
    $1.03     $1.02     $1.87     $2.67                 
      See Note 4. Earnings Per Share for further information.

**Note 2. Recent Accounting Standards**

**SFAS No. 154, “Accounting Changes and Error Corrections” (SFAS 154)**

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

      In May 2005, the Financial Accounting Standards Board (FASB) issued SFAS  154, which is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. SFAS 154 requires retrospective application to prior periods' financial statements of voluntary changes in accounting principles unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change.

      SFAS 154  requires that a change in depreciation, amortization or depletion method for  long-lived non-financial assets be accounted for as a change in accounting estimate  effected by a change in accounting principle. The adoption of SFAS 154  is not expected to have a material effect on PSEG, PSE&G, Power or Energy  Holdings.

**SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS 123R)**

      **PSEG**

      In December 2004, the FASB issued SFAS 123R, which revises 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 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). Adoption of SFAS 123R is not expected to have a material effect on PSEG's financial statements.

19

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

**FASB Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47)**

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

      In March 2005, the FASB issued FIN 47 to clarify the term “conditional asset retirement obligation” as used in SFAS No. 143, “Accounting for Asset Retirement Obligations.” Conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditionalasset retirement obligation should be recognized when incurred - generally, upon acquisition, construction, development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. PSEG, PSE&G, Power and Energy Holdings are currently evaluating the impact that adoption of FIN 47 may have on their respective financial statements.

**FSP No. 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 asa special deduction in accordance with SFAS 109 and not as a tax rate reduction. PSEG, Power and Energy Holdings do not believe that the manufacturer's deduction or the application of FSP 109-1 will have a material effect on their respective financial statements.

**FSP No. 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.

      PSEG has approved Domestic Reinvestment Plans, which provided for the repatriation of approximately $182 million through October 2005, of which approximately $140 million was eligible for the reduced tax rate pursuant to the Jobs Act. The tax expense associated with such repatriation totaled approximately $9 million and was recorded in the quarter ended September 30, 2005. In addition, Global's projections indicate that additional earnings could be generated by its international investments over the balance of 2005 that could increase the amount of funds that could reasonably be

20

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

considered for repatriation in 2005 by approximately $50 million, which would result in an additional $2 million of tax expense. Other than amounts discussed above, Global has made no change in its current intention to indefinitely reinvest accumulated earnings of its foreign subsidiaries.

**Proposed Standards**

      **PSEG and Energy Holdings**

      In July 2005, the FASB issued proposed guidance concerning the accounting for uncertain tax positions and the accounting for the timing of cash flows relating to income taxes generated by leveraged lease transactions.

      The proposal concerning uncertain tax positions would require that an uncertain tax position meet a probable recognition threshold based on the merits of the position in order for the benefit to be recognized in the financial statements. The proposal also addresses the accrual of interest and penalties related to tax uncertainties and the classification of liabilities on the balance sheet. If implemented in its present form, the impact of this proposal on PSEG and Energy Holdings could be material.

      The proposal concerning leveraged leases would require a lessor to perform a recalculation of a leveraged lease when there is a change in the timing of the realization of tax benefits generated by the lease. It would also require a lessor to re-evaluate classification as a leveraged lease when a recalculation of the lease is performed. If implemented in its present form, the impact of this proposal on PSEG and Energy Holdings could be material.

**Note 3. Discontinued Operations, Dispositions and Acquisitions**

**Discontinued Operations**

      **Power**

      ***Waterford Generation Facility (Waterford)***

      On May 27, 2005, Power entered into an agreement to sell its electric generation facility located in Waterford, Ohio to a subsidiary of American Electric Power Company, Inc. Since commencing construction of the project, the dramatic increase in natural gas prices relative to the price increase of coal and the failure to receive capacity compensation for the facility caused Power to consider alternatives for the project. After reviewing the alternatives in conjunction with other strategic and financial considerations, Power concluded that the value to be received from the sale of Waterford represented a means to accelerate the realization of the plant's value. The sale price for the facility and inventory was $220 million.

      During 2005, Power recognized a loss on disposal of $178 million, net of tax. Power completed the sale of Waterford on September 28, 2005. The proceeds of the sale, together with an anticipated reduction in tax liability, are approximately $320 million, which will be used to retire debt at Power.

      Waterford's operating results for the quarters and nine months ended September 30, 2005 and 2004 are summarized below:
   **Quarters EndedSeptember 30,** **Nine Months EndedSeptember 30,**   **2005** **2004** **2005** **2004**   **(Millions)**                            
Operating Revenues
    $13     $3     $18     $4       
Loss Before Income Taxes
    $(10)    $(12)    $(32)    $(44)      
Net Loss
    $(6)    $(8)    $(19)    $(27)                      
21

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

      The carrying amounts of the assets of Waterford as of December 31, 2004 are summarized in the following table:
   **As ofDecember 31,2004**   **(Millions)**                              
Current Assets
    $4              
Noncurrent Assets
     507                      
Total Assets of Discontinued Operations
    $511                          
      **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 December 2003, Global also 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, which offset CPC's Net Income for the quarter ended March 31, 2004. In May 2004, Global completed the sale of CPC for approximately $43 million in cash and recognized a gain on disposal of $5 million.

      The operating results of CPC for the nine months ended September 30, 2004 are summarized below:
   **Nine Months EndedSeptember 30, 2004**   **(Millions)**                              
Operating Revenues
    $38              
Pre-Tax Operating Income
    $2              
Net Income
    $2 
**Dispositions**

      **Energy Holdings**

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

      In December 2004, Global closed on the sale of its 50% equity interest in MPC to BTU Power Company for approximately $236 million, of which $100 million was paid in cash. The balance of approximately $136 million was provided in the form of a secured promissory note due on March 31, 2005, which was later amended to extend the maturity date to April 2005 and increase the amount due. The sale resulted in an after-tax gain of approximately $2 million, which was recorded in the fourth quarter of 2004. Global received payments of $38 million and $99 million in January 2005 and April 2005, respectively, representing the full payment of the outstanding receivable.

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

      In April 2004, Global sold a portion of its indirect ownership 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 which is recorded in Income from Equity Method Investments on the Condensed Consolidated Statements of Operations.

22

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

      ***Solar Electric Generating Systems (SEGS) Projects***

      In January 2005, Resources and Global sold their minority limited partner interests in three SEGS projects for proceeds of approximately $7 million resulting in an after-tax gain of $4 million.

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

      In April 2005, Global sold a 35% interest in Dhofar Power through a public offering on the Omani stock exchange as required under the Concession Agreement, reducing Global's ownership in Dhofar Power from 81% to 46%. Net proceeds from the sale approximated $25 million, resulting in a modest gain. As a result, Global's investment in Dhofar Power has been accounted for under the equity method following the sale. Global's investment in Dhofar Power was $20 million and $53 million as of September 30, 2005 and December 31, 2004, respectively.

      ***Resources***

      Resources was the lessor of a Boeing B767 to United Airlines (UAL). In December 2002, UAL filed for Chapter 11 bankruptcy protection. On June 13, 2005, Resources received a notice from the Trustee under the UAL lease that the lenders had terminated the lease and repossessed the aircraft. Upon receipt of this notice, Resources recorded a $15 million charge, after-tax, in June 2005 to eliminate its carrying value of this investment since management believes that there will be insufficient proceeds to recover any of the recorded amount of the investment due to the termination.

      In January 2005, the KKR Fund sold its investment in KinderCare Learning Centers, Inc. and Resources received proceeds of approximately $17 million resulting in an after-tax gain of approximately $1 million.

      In March 2004, Resources entered into an agreement with Midwest Generation LLC, an indirect subsidiary of Edison Mission Energy, to terminate its lease investment in the Collins generating facility in Illinois. In March 2004, Resources recorded a $17 million pre-tax charge to reduce its carrying value of the Collins Lease. In April 2004, Resources closed on the termination of the lease agreement and received gross proceeds of approximately $184 million. The actual loss on the termination of the lease was $11 million, after-tax. As a result of the sale, Resources paid approximately $100 million in taxes.

      In January 2004, Resources terminated two lease transactions with Qantas Airways and China Eastern Airlines Co., Ltd resulting from the lessees exercising their respective purchase options. Resources received aggregate gross cash proceeds of approximately $45 million and recorded an after-tax gain of $4 million. As a result of the sale, Resources paid approximately $36 million in taxes.

**Acquisitions**

      **Energy Holdings**

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

      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 owns 100% of TIE and consolidated this investment beginning July 1, 2004.

      Energy Holdings' consolidated Operating Revenues for the nine months ended September 30, 2004 would have increased from $701 million to $961 million had the acquisition of TIE occurred at the beginning of 2004. Energy Holdings' consolidated Net Income for the nine months ended September 30, 2004 would have increased from $110 million to $112 million had the acquisition of TIE occurred at the beginning of 2004. This 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.

23

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

**Note 4. 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:
  **Quarters Ended September 30,** **Nine Months Ended September 30,**  **2005** **2004** **2005** **2004**  **Basic** **Diluted** **Basic** **Diluted** **Basic** **Diluted** **Basic** **Diluted**                                
**EPS Numerator:**
                                
**Earnings (Millions)**
                                
Continuing Operations
    $260     $260     $252     $252     $653     $653     $661     $661 
Discontinued Operations
     (7)     (7)     (8)     (8)     (197)     (197)     (22)     (22)                                                 
**Net Income**
    $253     $253     $244     $244     $456     $456     $639     $639                                                  
**EPS Denominator (Thousands):**
                                
Weighted Average Common Shares Outstanding
     239,034      239,034      237,269      237,269      238,696      238,696      236,724      236,724 
Effect of Stock Options
     —      1,052      —      303      —      1,044      —      445 
Effect of Stock Performance Units
     —      36      —      18      —      36      —      18 
Effect of Participating Units
     —      4,164      —      138      —      3,436      —      696                                                  
Total Shares
     239,034      244,286      237,269      237,728      238,696      243,212      236,724      237,883                                                  
**EPS:**
                                
Continuing Operations
    $1.08     $1.06     $1.06     $1.06     $2.73     $2.68     $2.79     $2.78 
Discontinued Operations
     (0.02)     (0.03)     (0.03)     (0.03)     (0.82)     (0.81)     (0.09)     (0.09)                                                 
**Net Income**
    $1.06     $1.03     $1.03     $1.03     $1.91     $1.87     $2.70     $2.69                                                                                  
      There were approximately 5.3 million and 2.9 million stock options excluded from the weighted average common shares calculation used for diluted EPS due to their antidilutive effect for the quarter and nine months ended September 30, 2004, respectively. No stock options had an antidilutive effect for the quarter and nine months ended September 30, 2005.

      Dividend payments on common stock for the quarters ended September 30, 2005 and 2004 were $0.56 and $0.55 per share, respectively, and totaled approximately $134 million and $131 million, respectively. Dividend payments on common stock for the nine months ended September 30, 2005 and 2004 were $1.68 and $1.65 per share, respectively, and totaled approximately $401 million and $391 million, respectively.

**Note 5. Commitments and Contingent Liabilities**

**Guaranteed Obligations**

      **Power**

      Power has unconditionally guaranteed payments 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 for 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 September 30, 2005 and December 31, 2004 was $1.7 billion and $1.6billion, 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

24

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

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 are 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 $687 million and $507 million as of September 30, 2005 and December 31, 2004, respectively.

      Power is subject to collateral calls related to commodity contracts that are bilateral and is subject to certain creditworthiness standards as guarantor under performance guarantees for ER&T’s agreements. There has been a significant increase in commodity prices, including fuel, emission allowances and electric. Over the last year, both natural gas prices and electric prices in PJM have more than doubled. These price increases can have an impact on contract terms and conditions, as margin calls on contracts entered into in the normal course of business will increase with price increases. As of September 30, 2005, Power had paid cash margin of approximately $251 million and received cash margin of approximately $99 million. In addition, as of September 30, 2005, letters of credit issued by Power wereoutstanding in the amount of approximately $705 million (including $205 million issued to PSE&G) to satisfy trading collateral obligations and support various contractual and environmental obligations. Assuming no changes in energy prices and positions, Power’s collateral requirements can be expected to decline over time as its contracts expire. In the event of a deterioration of Power’s credit rating to below investment grade, many of these agreements allow the counterparty to demand that ER&T provide further performance assurance, generally in the form of a letter of credit or cash. As of September 30, 2005, if Power were to lose its investment grade rating and, assuming all counterparties to which ER&T is “out-of-the-money” were contractually entitled to demand, and demanded, performance assurance, ER&T could be required to post additional collateralin an amount equal to approximately $1.2 billion. PSEG and Power entered into additional credit agreements in October 2005 increasing available liquidity by $500 million. Power believes that it has sufficient access to liquidity to post such collateral, as may be necessary.

      **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.

      The contingent obligations as of September 30, 2005 and December 31, 2004 are as follows:
        **As of****Subsidiaries/Affiliates**    **Location**    **Description**  **ExpirationDate** **September 30,2005** **December 31,2004**        **(Millions)**
Elektrownia Skawina S.A. (Skawina)
    Poland    Equity commitment  August 2007  $9   $26 
PSEG Global Funding II LLC
    Delaware    Contingent guarantee related to debt service obligations associated with Chilquinta  April 2011   25    25 
Elektrocieplownia Chorzow Sp. Z o.o. (ELCHO)
    Poland    Contingent guarantee related to debt service obligations  October 2009   32    — 
Prisma 2000 S.p.A. (Prisma)
    Italy    Leasing agreement guarantee  N/A   22    35 
PSEG Energy Technologies Asset Management Company LLC
    New Jersey    Performance guarantees  N/A   7    13 
Other
    Various    Various  N/A   45    39               
Total Contingent Obligations
        $140   $138                             
25

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

      In September 2003, Energy Holdings completed the sale of PSEG Energy Technologies Inc. (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 shown in the table above for PSEG Energy Technologies Asset Management Company LLC. As of September 30, 2005, there were $29 million of such bonds outstanding, which are related to uncompleted construction projects. These performance bonds are not included in the $140 million of guaranteed obligations 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 or 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 is not currently estimable. However, neither PSE&G nor Power anticipates that compliance with these regulations will havea material adverse effect on their respective financial positions, results of operations or net cash flows.

      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 electric generating station (Essex Site), one former generating station and four former Manufactured Gas Plants (MGPs). PSE&G’s costs to clean up former MGPs are recoverable from utility customers through the Societal Benefits Clause (SBC). PSE&G has sold the site of the former generating station and obtained releases and indemnities for liabilitiesarising out of the site in connection with the sale. The Essex Site was transferred to 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 had been 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

26

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

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. 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 43 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 Remediation Program in 1988 through September 30, 2005, PSE&G had expenditures of approximately $329 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, a liability of $321 million and $356 million was recorded at September 30, 2005 and December 31, 2004, respectively, which represents the difference between the low end of the total program cost estimate of $650 million and the total incurred costs through September 30, 2005 and December 31, 2004 of $329 million and $294 million, respectively. Of this amount, $38 million and $47 million were recorded in Other Current Liabilities and $283 million and $309 million were recorded in Other Noncurrent Liabilities on its Condensed Consolidated Balance Sheetsas of September 30, 2005 and December 31, 2004, respectively. The costs associated with the MGP Remediation Program have historically been recovered through the SBC charges to PSE&G ratepayers. As such, a $321 million and a $356 million Regulatory Asset was also recorded as of September 30, 2005 and December 31, 2004, respectively.

      Costs for the MGP Remediation Program were approximately $13 million and $35 million for the quarter and nine months ended September 30, 2005, respectively. PSE&G anticipates spending $45 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 funding requirement for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2005 to 2008. The liability for the funding requirement has been recorded at the discounted present value. The costs associated with this program will be recovered from PSE&G ratepayers over the four years and therefore a Regulatory Asset was also recorded. The current and noncurrent liability for the funding requirement as of September 30, 2005 and December 31, 2004 was $354 million and $406 million, respectively.

27

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

      **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 the NJDEP and the EPA to resolve allegations of noncompliance with PSD/NSR regulations. Under that agreement, over the course of 10 years, Power agreed to install advanced air pollution controls to reduce emissions of Sulfur Dioxide (SO2), Nitrogen Oxide (NOx), particulate matter and mercury from the coal-burningunits at the Mercer and Hudson generating stations. The estimated cost of the program as of September 30, 2005 includes approximately $110 million for installation of selective catalytic reduction systems (SCRs) at Mercer, which has been spent, as well as approximately $300 million to $350 million at Hudson 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. Power will be unable to complete the installation of the pollution control equipment by the December 31, 2006 deadline. Power believes that system reliability concerns that PJM Interconnection L.L.C. (PJM) previously identified in the area and its discussions with NJDEP may result in the unit continuing to operate after December 31, 2006. Power cannot estimate additional costs, including any penalties, that may be associated with the continued operation of the Hudson unit beyond December 31, 2006, but such costs could be material. The costs associatedwith the pollution control modifications for the Hudson unit have not been included in Power’s capital expenditure projections.

      ***New Jersey Industrial Site Recovery Act (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. Power had a $51 million liability as of September 30, 2005 and December 31, 2004 related to these obligations, which is included in Other Noncurrent Liabilities on Power’s Condensed Consolidated Balance Sheets and Environmental Costs on PSEG’s Condensed Consolidated Balance Sheets.

**New Generation and Development**

      **Power**

      In July 2005, Power completed construction of the Bethlehem Energy Center near Albany, New York. Total costs for this project were approximately $596 million (including interest capitalized during construction (IDC) of $70 million). The plant was put into commercial operation on July 18, 2005.

28

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

      Power is constructing a natural gas-fired generation plant in Linden, New Jersey. Power anticipates that construction will be completed in the second quarter of 2006. Total costs are estimated at approximately $1 billion with expenditures through September 30, 2005 of approximately $968 million (including IDC of $180 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 in 2003 and gained 24 megawatts (MW). Phase II of the replacement is currently scheduled for 2008 concurrent with steam generator replacement and is anticipated to increase capacity by 26 MW. Salem Unit 1 completed its turbine replacement in 2004 and gained 63 MW. Hope Creek completed Phase I of its turbine replacement in January 2005 and gained 15 MW. Phase II is expected to be completed in 2007 along with the thermal power uprate and is expected to add approximately 120 MW. Power’s expenditures to date approximate $200 million (includingIDC of $16 million) with an aggregate estimated share of total costs for these projects of $247 million (including IDC of $27 million). Timing, costs and results of these projects are dependent on timely completion of work, timely approval from the NRC and various other factors.

      Completion of the projects discussed above 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 entered into a long-term contractual services agreement with a vendor in September 2003 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 S.A. (Electroandes)***

      There is a 35 MW expansion project on an existing hydro station under development at Electroandes, a generating facility in Peru. Construction on this project is expected to begin in the first half of 2006 with expected completion in 2007 at a total cost of $29 million. The project is expected to be financed by Electroandes with cash and non-recourse debt.

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

      **PSE&G and Power**

      PSE&G is required to obtain all electric supply requirements for customers that do not purchase electric supply from third-party suppliers through the annual New Jersey BGS auctions. The BGS auction process is a statewide process in which all of the New Jersey Electric Distribution Companies (EDCs) participate. The BGS auctions are “declining clock” auctions, where the EDCs accept offers for the amount of electric supply bidders are willing to offer with higher prices at the beginning of the auction. The auction proceeds when the amount of supply bid exceeds what is needed. The offer price is subsequently lowered and the process continues in a series of steps. When the amount of supply bid by the prospective suppliers matches an EDC’s electric supply needs, the auction ends. The BPU renders a decisionon the auction results within two business days.

      PSE&G enters into the Supplier Master Agreement (SMA) with the winners of these BGS auctions within three business days of the BPU’s approval. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s anticipated load requirements. The winners of the auction are responsible for fulfilling all the requirements of a PJM Load Serving Entity (LSE) including capacity, energy, ancillary services, transmission and any other

29

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

services required by PJM. Suppliers assume any migration risk and must satisfy New Jersey’s renewable portfolio standards.

      The BPU  permits recovery of the cost of gas hedging up to 115 billion cubic feet or  approximately 80% of PSE&G’s residential gas supply annually through  the BGSS tariff. For the 2005/06 winter season, Power has hedged approximately  71% of the 115 billion cubic feet allowed at an average price of $7.74  per decatherm (dth). Together with its current volumes in inventory as of September 30,  2005, Power has secured the majority of the anticipated residential volume for  the 2005/06 winter season at prices that are lower than current market. Approximately  22% of the allowed residential gas volume has been hedged for the 2006 summer  season at an average price of $7.62 per dth. As of September 30, 2005 and  December 31, 2004, the fair value of the contract was $462 million and  $25 million, respectively. PSE&G recorded an affiliate receivable from Power  related to the fair market value of the contract with an offsetting Regulatory  Liability. Power recorded a derivative asset with an offsetting affiliate payable  to PSE&G. The change in the fair value of the contract is primarily related  to significant increases in natural gas prices as previously discussed.

      **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 EDCs 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 and Connecticut, as well as other 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 $809 million through 2012.

      Power has various multi-year requirements-based purchase commitments that total approximately $103 million per year to meet Salem’s and Hope Creek’s nuclear fuel needs, of which Power’s share is approximately $76 million per year through 2010. Power has been advised by Exelon Generation Company, LLC (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 $27 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 September 30, 2005, the total minimum requirements under these contracts were approximately $988 million through 2016.

      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 have entered into gas supply agreements for their anticipated fuel requirements to satisfy obligations under their forward energy sales contracts. As of September 30, 2005, the Guadalupe and Odessa plants, which total approximately 2,000 MW of capacity, had forward energy sale contracts in place for approximately 75% of its expected output for the remainder of 2005,

30

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

approximately one-third of its expected output  for 2006 and expect to term up additional load during the fourth quarter of  2005. TIE had fuel purchase commitments totaling $253 million to fully support  such contracts.

**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 Hope Creek and Salem nuclear generating stations. The OSC requires Exelon Generation to 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 continues as the license holder with exclusive legal authority to operate and maintain the plants, retains responsibility for management oversight and has full authority with respect to the marketing of its share of the output from the facilities. Exelon Generation is entitled to receive reimbursement of its costs in dischargingits obligations, an annual operating services fee and incentive fees up to $12 million annually based on attainment of goals relating to safety, capacity factor and operation and maintenance expenses. The OSC has a term of two years, subject to earlier termination in certain circumstances. 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 twelve months if Nuclear determines that additional time 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’sspent fuel 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 was reduced by approximately $18 million through August 31, 2002, at which point credits were fully utilized and covered the cost of Exelon Generation’s on-site 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

31

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

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. In August 2004, Exelon Generation advised Nuclear that it reached a settlement with the U.S. Department of Justice, under which Exelon Generation would be reimbursed for costs associated with the storage of spent nuclear fuel at the Peach Bottom facility, a portion of which would be paid to Nuclear as a co-owner of Peach Bottom. Future costs incurred resulting from DOE delays in accepting spent fuel will 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 the third quarter of 2004.

      In September 2001, Power filed a complaint in the U.S. Court of Federal Claims seeking damages caused by the DOE not taking possession of spent nuclear fuel in 1998. On October 14, 2004, an order to show cause was issued regarding whether the U.S. Court of Federal Claims 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 in the U.S. 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. 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 is scheduled to be completed by the end of 2005. 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 actions to address the contamination, in accordance with a remedial action workplan approved by the NJDEP in November 2004. The remedial actions are expected to be ongoing for several years. 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**

      ***Minimum Pension Liability***

      Due to the  potential for a lower required discount rate and reduced earnings on the pension  plan investments through September 30, 2005, PSEG, PSE&G, Power and Energy  Holdings may be required to record a minimum pension liability on their respective  Consolidated Balance Sheets as of December 31, 2005. As calculated under SFAS  No. 87 “Employers Accounting for Pensions, a minimum pension liability exists and must be recorded when the accumulated  benefit obligation (ABO) of the plan exceeds the fair value of the plan assets  as of its annual measurement date. The minimum pension liability is reduced  or reversed when funding occurs, or when the fair value of the pension plan  assets grow to a level above that of the ABO. At this time, PSEG is monitoring  the fair market value of its investments and its ABOand is evaluating options  available with respect to this issue. Since PSEG’s measurement date is  December 31, 2005, management

32

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

is unable to predict what the impact could be, however the impact could be material to PSEG’s, PSE&G’s, Power’s and Energy Holdings’ financial position and, more specifically, could result in the recognition of a minimum pension liability on the Condensed Consolidated Balance Sheets and a decrease in equity since a majority of the offset to the minimum pension liability would be recorded in Accumulated Other Comprehensive Loss (OCL).

      **PSEG and PSE&G**

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

      As of June 1999, the 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 tax normalization rulesof 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.

      ***BPU 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 July 31, 2003 was released by the consultant to the BPU in April 2005. The draft report addresses the SBC, Market Transition Charge (MTC) and Non-Utility Generation (NUG) deferred balances. The BPU released the report on May 13, 2005.

      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 on 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.

      **PSEG and Energy Holdings**

      ***Leveraged Lease Investments***

      From 1996 through 2002, PSEG, through its indirect wholly owned subsidiary, Resources, entered into a number of leveraged lease transactions in the ordinary course of business. Certain of those transactions that were previously entered into are similar to a type that the IRS subsequently

33

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

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 September 30, 2005 and December 31, 2004, Resources’ total gross investment in such transactions was approximately $1.4 billion and $1.3 billion, respectively. The IRS is presently reviewing the tax returns of PSEG and its subsidiaries for tax years 1997 through 2000, years when Resources entered into some of these transactions.

      On September 27, 2005, the IRS proposed to disallow PSEG’s deductions associated with certain of these leveraged leases which have been designated by the IRS as listed transactions. Other lease transactions within the audit period are still under the IRS’s review. The IRS may propose additional disallowances in the future. If deductions associated with these lease transactions entered into by PSEG are 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 respectto any IRS challenge, although no assurances can be given.

      If the tax benefits associated with the above referenced lease transactions were completely disallowed by the IRS, approximately $650 million of PSEG’s deferred tax liabilities that have been recorded under leveraged lease accounting through September 30, 2005 could become currently payable. In addition, interest expense of approximately $80 million, after-tax, and penalties could be assessed. Although Energy Holdings believes that such an outcome is unlikely, in the event that such a payment is required, Energy Holdings believes that, assuming certain asset monetizations of its investment portfolio, it has the financial capacity to meet this potential obligation.

      The FASB is currently considering a modification to GAAP for leveraged leases. Under present GAAP, a tax settlement with the IRS that results 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 would be no write-down of the lease investment. See Note 2. Recent Accounting Standards for additional information.

      **Power**

      ***Restructuring Charge***

      In June  2005, Power implemented a plan, approved by management, to reduce its Nuclear  workforce by approximately 200 positions. The plan includes voluntary and involuntary  separations offered to both represented and non-represented employees. The major  cost associated with the restructuring relates to payments to the employees  who are terminated. Power’s $14 million share of the estimated total cost  was recorded in 2005, none of which had been paid as of September 30, 2005.

      **Energy Holdings**

      ***Rio Grande Energia S.A. (RGE)***

      In December 2004, the governing tax authority in Brazil 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. RGE used a 10-year amortization period. The tax authority maintains that the amortization period should coincide with the concession period of 30 years. Global's share of the maximum claim amount related to these tax issues is approximately $8 million. RGE believes it has valid legal defenses to these claims. The court of first instance has ruled against RGE and RGE has appealed the lower court ruling. Although RGE believes its defenses to these claims are valid and will continue to vigorously contest this matter, no assurancescan be given regarding the outcome.

34

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

      Sul Geradora Participações Ltda. (SGP) is a wholly owned subsidiary of RGE. The Brazilian tax authority has filed a tax assessment against SGP relating to a loan entered into between SGP and BankBoston N.A. denying the characterization of the loan as a withholding-free transaction for 2000, 2001 and 2002. The original amount of the assessment is $15 million, including tax, penalty and interest. Global, as an approximate 33% indirect owner of SGP may be responsible for approximately $5 million relating to the claim. SGP believes it has valid defenses to these claims and has filed an appeal of the assessment, although no assurances can be given regarding the outcome.

      ***LDS***

      The Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, has claimed past due taxes for the periods between 1996-1998 and 1999-2001, plus penalties and interest, resulting from LDS’s interpretation of tax law that permitted restatement of assets to fair market value for tax purposes resulting in higher tax deductions for depreciation. LDS did not accept the SUNAT valuation and appealed. The Fiscal Court notified LDS on January 4, 2005 that a proper decision could not be based on the existing SUNAT studies and ordered another valuation study to be performed by Consejo Nacional de Tasaciones (CONATA), a Government Agency in Peru. CONATA completed the valuation of LDS assets in April 2005 and concluded that the asset value of LDS is higher than those originally usedby LDS for its tax deductions for depreciation.

      In September 2005, the SUNAT accepted the Fiscal Court’s decision which validated the methodology used by LDS in revaluating its assets to market value in accordance with the then prevailing law. LDS has received a final assessment for the years 1996-1999 which will result in a refund. Since the Fiscal Court determined in its written decision the base amounts to be used for the asset revaluation, these amounts are valid for the remaining years in dispute by the SUNAT (2000 and 2001), thus limiting any additional tax exposure related to this issue.

      ***Electroandes***

      In July 2005, Electroandes received a notice from the SUNAT claiming past due taxes for 2002 totaling approximately $2 million related to certain interest deductions. Electroandes has taken similar interest deductions subsequent to 2002. The total cumulative amount, including potential associated interest and penalties, is approximately $5 million through September 30, 2005. Electroandes believes it has valid legal defenses to these claims, although no assurances can be given.

      ***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. Dhofar Power and the Government of Oman been in a dispute regarding the applicability and extent of any penalties under Dhofar Power’s Concession Agreement arising from these service interruptions. On July 14, 2005, the expert engaged by the parties recommended no penalties be assessed for the 2003 service interruptions and agreed with Dhofar Power’s interpretation of the Concession Agreement with respect to the criteria to be utilized in assessing penalties. The Government of Oman hasexercised its right to appeal the expert’s determination to a full arbitration panel. Dhofar Power believes this matter will be favorably resolved in 2006, although no assurances can be given.

      Dhofar Power and the Government of Oman are also in disagreement on the basis of the calculation of certain monthly allowances to be paid to compensate Dhofar Power for the capital investment costs associated with the enhancements and extensions of the transmission and distribution system in Salalah. On August 24, 2005, the expert engaged by the parties found in favor of Dhofar Power with respect to the criteria to be used in determining the monthly allowances. It is uncertain at

35

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

this time whether the Government will exercise its right to appeal the expert’s determination to a full arbitration panel. If the Government of Oman prevails, the loss of revenue to PSEG would be approximately $1 million annually for 15 years retroactive to December 2003. PSEG believes it has valid defenses to the Government’s claim and will vigorously contest this matter. Dhofar Power believes that this matter will be favorably resolved in 2006, although no assurances can be given.

      ***TIE***

      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 the Electric Reliability Council of Texas (ERCOT), in its function as the Independent System Operator for the Texas energy market. The action filed in the U.S. District Court for the Southern District of Texas (District Court), Civil Action No. C-03-249 alleges price-fixing, predatory pricing and certain common law claims. Automated Power Exchange, Inc. (APX), a named defendant, acting as the qualified scheduling entity, submitted bids on behalf of Guadalupe Power Partners, LP (Guadalupe) and Odessa-Ector Power Partners, L.P. (Odessa), as well as several other generatorsin the ERCOT energy market. In this connection, APX has submitted a demand for indemnification from Guadalupe and Odessa. On February 3, 2004, TCE amended its complaint and named TIE, Guadalupe, Odessa and others as additional defendants. On May 20, 2004, the 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 (Fifth Circuit). On July 19, 2004, TCE filed a Notice of Appeal, and the parties subsequently filed briefs and reply briefs. On June 17, 2005, a two-judge panel of the Fifth Circuit issued its decision affirming the District Court’s dismissal of TCE’s state and federal antitrust claims. TCE subsequently filed a Petition seeking a rehearing before the entire panel of the Fifth Circuit. On July 19,2005, the Fifth Circuit decided not to grant TCE’s request. On October 14, 2005, TCE filed a Petition for Certification of this matter to the U.S. Supreme Court. 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, Guadalupe and Odessa, based  on facts similar to those alleged in the TCE litigation. The new action, filed  in the District Court also alleges price-fixing, predatory pricing and various  other claims. The District Court issued a stay of action pending the outcome  of the TCE appeal and the stay continued until the TCE request to the Fifth  Circuit was determined. The District Court originally lifted the stay for the  sole purpose of permitting motions to dismiss to be filed but has now allowed  the case to proceed to discovery and eventual trial. The defendants’ motion  to dismiss was heard by the Court on October 18, 2005. The Court has not indicated  when a decision can be expected. Although the District Court is still considering  the defendants’ motion to dismiss, discovery is continuing and a trial  date of April 3, 2006 has been set. Global continues to believe there are valid  defenses to these claims, which will continue to be vigorously asserted.

**Note 6. 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

36

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

by creating a relationship in which gains or losses on derivative instruments are expected to counterbalance the 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, financial 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. To that end, Power’s objective is  to enter into contracts for at least 75% of its anticipated generation output  over an 18-month to 24-month horizon. There have been significant increases  in commodity prices over the last year. The resultant changes in market values  for energy and related contracts that qualify for hedge accounting have resulted  in significant increases to OCL. For additional information, see Note 5. Commitments  and Contingent Liabilities. Power continues to believe that hedging at least  75% of its anticipated generation output is an appropriate way to reduce the  volatility of its earnings.

      Power marks its derivative energy trading contracts to market in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted (SFAS 133), with changes in fair value charged to the Condensed Consolidated Statements 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.

      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.

37

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

      ***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 of September 30, 2005, the fair value of these hedges was $(886) million. These hedges, along with realized gains on hedges of $10 million retained in OCL, result in a $(518) million after-tax impact on OCL. As of December 31, 2004, the fair value of these hedges was $(248) million, $(145) million after-tax. During the next 12 months, $263 million of net unrealized and realized losses (after-tax) on these commodityderivatives is expected to be reclassified to earnings. Approximately $166 million of unrealized losses (after-tax) on these commodity derivatives in OCL is expected to be reclassified to earnings for the twelve months ended September 30, 2007. Ineffectiveness associated with 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 Condensed Consolidated Statements of Operations. The net fair value of these instruments as of September 30, 2005 and December 31, 2004 was $23 million and $14 million, respectively.

      ***Energy Holdings***

      ***Other Derivatives***

      TIE, a wholly owned subsidiary of Energy Holdings and Global, also enters into certain other contracts in connection with its merchant generation business 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 Condensed Consolidated Statements of Operations. The net fair value of these instruments as of September 30, 2005 was $(6) million.

**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 September 30, 2005 and December 31,

38

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

2004, the fair value of the hedge was $(9) million and $(3) million, respectively, 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 swaps are fully offset by the fair value changes in the underlying debt. As of September 30, 2005 and December 31, 2004, the fair value of these hedges was $(5) million and $(3) million, respectively, and there was no ineffectiveness related to these hedges.

      **Cash Flow Hedges**

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

      PSEG, PSE&G  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 Accumulated Other Comprehensive Income. As of September 30,  2005, the fair value of these cash flow hedges was $(98) million, including  $(6) million, $(16) million and $(76) million at PSEG, PSE&G and Energy  Holdings, respectively. 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. The  $(16) million and $(34) million at PSE&G as of September 30, 2005 and  December 31, 2004, respectively, is not included in OCL, as it is deferred  as a Regulatory Asset and is expected to be recovered from PSE&G's customers.  During the next 12 months, $22 million of unrealized losses (net of taxes) on  interest rate derivatives in OCL is expected to be reclassified to earnings,  including $2 million and $20 million at PSEG and Energy Holdings, respectively.  As of September 30, 2005, hedge ineffectiveness associated with these hedges  was immaterial.

      **Other Derivatives**

      ***Energy Holdings***

      Energy Holdings has cross currency interest rate swaps whose changes in fair value were recorded in Income from Equity Method Investments on the Condensed Consolidated Statements of Operations. The fair value of these swaps was approximately $(2) million and $(4) million as of September 30, 2005 and December 31, 2004, respectively.

**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. With respect to theforeign currency risk associated with the Brazilian Real, there has been a significant devaluation

39

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

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.

      For the nine months ended September 30, 2005, the Chilean Peso, Brazilian Real and the Peruvian Nuevo Sol appreciated significantly relative to the U.S. Dollar, increasing Energy Holdings' Member's Equity by approximately $73 million and largely offsetting prior years' reductions in equity. As a result, the net cumulative foreign currency devaluations had reduced the total amount of Energy Holdings' Member's Equity by $56 million as of September 30, 2005.

      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 Real, 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. Due to the rise in local currency value relative to the U.S. Dollar, which increases the value of the foreign investments' earnings in U.S Dollar terms, these options did not have value.

**Hedges of Net Investments in Foreign Operations**

      **Energy Holdings**

      In March 2004 and April 2004, Energy Holdings entered into four cross-currency interest rate swap agreements. The swaps are designed to hedge the net investment in a foreign subsidiary associated with the exposure in the U.S. Dollar to Chilean Peso exchange rate. The fair value of the cross-currency swaps was $(28) million and $(21) million as of September 30, 2005 and December 31, 2004, respectively. The effective portion of the change in fair value is recorded in Cumulative Translation Adjustment within Accumulated Other Comprehensive Loss.

**Note 7. Comprehensive Income (Loss), Net of Tax**
  **PSE&G** **Power (A)** **EnergyHoldings (B)** **Other (C)** **ConsolidatedTotal**  **(Millions)**
**For the Quarter Ended September 30, 2005:**
                    
Net Income (Loss)
    $115     $125     $39     $(26)    $253 
Other Comprehensive (Loss) Income
     —      (291)     101      (7)     (197)                               
Comprehensive Income (Loss)
    $115     $(166)    $140     $(33)    $56                                
**For the Quarter Ended September 30, 2004:**
                    
Net Income (Loss)
    $93     $131     $36     $(16)    $244 
Other Comprehensive (Loss) Income
     —      (46)     45      (4)     (5)                               
Comprehensive Income (Loss)
    $93     $85     $81     $(20)    $239                                
**For the Nine Months Ended September 30, 2005:**
                    
Net Income (Loss)
    $282     $106     $140     $(72)    $456 
Other Comprehensive (Loss) Income
     —      (395)     81      (2)     (316)                               
Comprehensive Income (Loss)
    $282     $(289)    $221     $(74)    $140                                
**For the Nine Months Ended September 30, 2004:**
                    
Net Income (Loss)
    $281     $292     $110     $(44)    $639 
Other Comprehensive Loss
     (1)     (236)     (34)     (2)     (273)                               
Comprehensive Income (Loss)
    $280     $56     $76     $(46)    $366                                                    
**
   (A)   Changes at Power primarily relate to SFAS 133 net unrealized losses on derivative contracts that qualify for hedge accounting. As discussed previously, there have been significant increases in
*(footnotes continued on next page)*

40

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

*(footnotes continued from previous page)*
    commodity prices over the last year. The increases have resulted in significant increases to OCL related to changes in market values for energy and related contracts that qualify for hedge accounting. See Note 5. Commitments and Contingent Liabilities for additional information. Power's changes also include changes in unrealized gains and losses on Nuclear Decommissioning Trust (NDT) Funds.   (B)   Changes at Energy Holdings primarily relate to foreign currency translation adjustments and unrealized gains and losses on various derivative transactions.   (C)   Other primarily consists of activity at PSEG (as parent company), Services and intercompany eliminations.
**Note 8. Changes in Capitalization**

      **PSE&G**

      In September  2005, PSEG issued $375 million of floating rate senior unsecured debt due 2008,  callable at par after one year. The proceeds were used to redeem PSEG's  subordinated debt underlying $225 million of Enterprise Capital Trust I,  7.44% Series A and $150 million of Enterprise Capital Trust III, 7.25%  Series C Preferred Securities in October 2005.

      **PSE&G**

      In September 2005, Transition Funding II issued approximately $103 million of its Transition Bonds, Series 2005-1, in four classes. Proceeds were used to purchase from PSE&G the rights to collect a transition bond charge from electric customers as approved by the BPU. PSE&G used those proceeds to reduce short-term debt.

      In July 2005, PSE&G issued $250 million of its 5.25% Secured Medium-Term Notes Series D due 2035. The proceeds were used to redeem $125 million of PSE&G's First and Refunding Mortgage Bonds, 9.125% Series BB due July 2005 and to reduce short-term debt.

      For the nine months ended September 30, 2005, Transition Funding repaid approximately $105 million of its transition bonds.

      **Energy Holdings**

      In May 2005, Energy Holdings redeemed the remaining $184 million of its Preference Units held by PSEG. In February 2005, Energy Holdings made a $100 million cash distribution to PSEG in the form of a return of capital. Also during 2005, Energy Holdings made cash distributions of $3 million in the form of preference unit distributions.

41

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

**Note 9. Other Income and Deductions**
  **PSE&G** **Power** **EnergyHoldings** **Other (A)** **ConsolidatedTotal**  **(Millions)**
**Other Income:**
                    
**For the Quarter Ended September 30, 2005:**
                    
Interest Income
    $2     $—     $—     $—     $2 
Disposition        of Property
     —      5      —      —      5 
Gain on Investments
     —      —      —      8      8 
NDT Fund Realized Gains
     —      60      —      —      60 
NDT Interest and Dividend Income
     —      9      —      —      9 
Foreign Currency Gains
     —      —      4      —      4 
Other
     1      —      1      1      3                                
Total Other Income
    $3     $74     $5     $9     $91                                
**For the Quarter Ended September 30, 2004:**
                    
Interest Income
    $1     $1     $—     $—     $2 
Disposition        of Property
     3      —      —      —      3 
NDT Fund Realized Gains
     —      26      —      —      26 
NDT Interest and Dividend Income
     —      6      —      —      6 
Foreign Currency Gains
     —      —      3      —      3 
Other
     —      3      1      1      5                                
Total Other Income
    $4     $36     $4     $1     $45                                
**For the Nine Months Ended September 30, 2005:**
                    
Interest Income
    $6     $4     $—     $2     $12 
Disposition        of Property
     —      4      —      —      4 
Gain on Investments
     —      —      1      8      9 
NDT Fund Realized Gains
     —      99      —      —      99 
NDT Interest and Dividend Income
     —      26      —      —      26 
Change in Derivative Fair Value
     —      —      1      —      1 
Foreign Currency Gains
     —      —      9      —      9 
Other
     1      2      3      —      6                                
Total Other Income
    $7     $135     $14     $10     $166                                
**For the Nine Months Ended September 30, 2004:**
                    
Interest Income
    $8     $3     $—     $—     $11 
NDT Fund Realized Gains
     —      114      —      —      114 
NDT Interest and Dividend Income
     —      20      —      —      20 
Change in Derivative Fair Value
     —      —      1      —      1 
Other
     2      3      3      (2)     6                                
Total Other Income
    $10     $140     $4     $(2)    $152                                                    
42

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**
  **PSE&G** **Power** **EnergyHoldings** **Other (A)** **ConsolidatedTotal**  **(Millions)**                    
**Other Deductions:**
                    
**For the Quarter Ended September 30, 2005:**
                    
Donations
    $—     $—     $—     $13     $13 
Foreign Currency Losses
     —      —      7      —      7 
NDT Fund Realized Losses and Expenses
     —      13      —      —      13 
Other
     1      —      2      —      3                                
Total Other Deductions
    $1     $13     $9     $13     $36                                
**For the Quarter Ended September 30, 2004:**
                    
NDT Fund Realized Losses and Expenses
    $—     $13     $—     $—     $13 
Foreign Currency Losses
     —      —      6      —      6 
Change        in Derivative Fair Value
     —      —      2      —      2 
Minority        Interest
     —      —      —      1      1 
Other
     —      —      —      1      1                                
Total Other Deductions
    $—     $13     $8     $2     $23                                
**For the Nine Months Ended September 30, 2005:**
                    
Donations
    $1     $1     $—     $13     $15 
Foreign Currency Losses
     —      —      8      —      8 
Change in Derivative Fair Value
     —      —      2      —      2 
NDT Fund Realized Losses and Expenses
     —      32      —      —      32 
Minority Interest
     —      —      —      3      3 
Other
     1      —      2      1      4                                
Total Other Deductions
    $2     $33     $12     $17     $64                                
**For the Nine Months Ended September 30, 2004:**
                    
Donations
    $1     $—     $—     $—     $1 
NDT Fund Realized Losses and Expenses
     —      38      —      —      38 
Foreign Currency Losses
     —      —      9      —      9 
Loss on Early Extinguishment of Debt
     —      —      3      —      3 
Minority Interest
     —      —      —      3      3 
Other
     —      6      2      1      9                                
Total Other Deductions
    $1     $44     $14     $4     $63                                                       (A)   Other consists of reclassifications for minority interests in PSEG's consolidated results of operations and intercompany eliminations at PSEG (as parent company).
43

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

**Note 10. Income Taxes**

      An analysis of the tax provision expense is as follows:
  **PSE&G** **Power** **EnergyHoldings** **Other (A)** **ConsolidatedTotal**  **(Millions)**
**For the Quarter Ended September 30, 2005:**
                    
Income (Loss) from Continuing Operations before Income Taxes
    $189     $233     $64     $(43)    $443 
Tax computed at the statutory rate
     67      82      22      (15)     156 
Increase (decrease) attributable to flow through of certain tax adjustments:
                    
State Income Taxes after Federal Benefit
     13      13      (1)     —      25 
Rate Differential of Foreign Operations
     —      —      (4)     —      (4)
Repatriation
     —      —      9      —      9 
Plant Related Items
     (5)     —      —      —      (5)
Other
     (1)     6      —      (3)     2                                
Total Income Tax Expense (Benefit)
    $74     $101     $26     $(18)    $183                                
Effective income tax rate
     39.2%     43.3%     40.6%     41.9%     41.3%                               
**For the Quarter Ended September 30, 2004:**
                    
Income (Loss) from Continuing Operations before Income Taxes
    $163     $244     $45     $(23)    $429 
Tax computed at the statutory rate
     57      85      16      (6)     152 
Increase (decrease) attributable to flow through of certain tax adjustments:
                    
State Income Taxes after Federal Benefit
     12      14      —      —      26 
Rate Differential of Foreign Operations
     —      —      (8)     —      (8)
Plant Related Items
     1      —      —      —      1 
Lease Rate Differential
     —      —      1      —      1 
Other
     —      6      (1)     —      5                                
Total Income Tax Expense (Benefit)
    $70     $105     $8     $(6)    $177                                
Effective income tax rate
     42.9%     43.0%     17.8%     26.1%     41.3%                               
**For the Nine Months Ended September 30, 2005:**
                    
Income (Loss) from Continuing Operations before Income Taxes
    $473     $528     $186     $(120)    $1,067 
Tax computed at the statutory rate
     166      185      65      (42)     374 
Increase (decrease) attributable to flow through of certain tax adjustments:
                    
State Income Taxes after Federal Benefit
     33      30      (3)     (1)     59 
Rate Differential of Foreign Operations
     —      —      (32)     —      (32)
Repatriation
     —      —      9      —      9 
Plant Related Items
     (4)     —      —      —      (4)
Lease Rate Differential
     —      —      2      —      2 
Other
     (4)     10      2      (2)     6                                
Total Income Tax Expense (Benefit)
    $191     $225     $43     $(45)    $414                                
Effective income tax rate
     40.4%     42.6%     23.1%     37.5%     38.8%                               
**For the Nine Months Ended September 30, 2004:**
                    
Income (Loss) from Continuing Operations before Income Taxes
    $476     $535     $142     $(70)    $1,083 
Tax computed at the statutory rate
     167      187      50      (23)     381 
Increase (decrease) attributable to flow through of certain tax adjustments:
                    
State Income Taxes after Federal Benefit
     34      31      12      (3)     74 
Rate Differential of Foreign Operations
     —      —      (17)     —      (17)
Plant Related Items
     (1)     —      —      —      (1)
Lease Rate Differential
     —      —      (9)     —      (9)
Other
     (5)     (2)     (2)     3      (6)                               
Total Income Tax Expense (Benefit)
    $195     $216     $34     $(23)    $422                                
Effective income tax rate
     41.0%     40.4%     23.9%     32.9%     39.0%                                                   
44

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

**Note 11. Financial Information by Business Segments**

      Information related to the segments of PSEG and its subsidiaries is detailed below:
          **Energy Holdings**          **PSE&G** **Power** **Resources** **Global** **Other (A)** **Other (B)** **ConsolidatedTotal**  **(Millions)**
**For the Quarter Ended September 30, 2005:**
                            
Total Operating Revenues
    $1,934    $1,444    $52    $325    $2     (381)   $3,376 
Income (Loss) from Continuing Operations
     115     132     17     22     —     (26)    260 
Loss        from Discontinued Operations, including Loss on Disposal, net of tax benefit
     —     (7)    —     —     —     —     (7)
Net Income (Loss)
     115     125     17     22     —     (26)    253 
Preferred Securities Dividends/Preference Unit Distributions
     (1)    —     —     —     —     1     — 
Segment Earnings (Loss)
     114     125     17     22     —     (25)    253 
Gross Additions to Long-Lived Assets
     133     118     —     8     —     12     271 
**For the Quarter Ended September 30, 2004:**
                            
Total Operating Revenues
    $1,636    $1,130    $57    $252    $2     (328)   $2,749 
Income (Loss) from Continuing Operations
     93     139     18     20     (2)    (16)    252 
Loss from Discontinued Operations,net of tax
     —     (8)    —     —     —     —     (8)
Net Income (Loss)
     93     131     18     20     (2)    (16)    244 
Preferred Securities Dividends/Preference Unit Distributions
     (1)    —     —     (3)    —     4     — 
Segment Earnings (Loss)
     92     131     18     17     (2)    (12)    244 
Gross Additions to Long-Lived Assets
     107     186     —     16     —     4     313 
**For the Nine Months Ended September 30, 2005:**
                            
Total Operating Revenues
    $5,559    $4,234    $141    $937    $7    $(1,751)   $9,127 
Income (Loss) from Continuing Operations
     282     303     39     104     (3)    (72)    653 
Loss        from Discontinued Operations, including Loss on Disposal, net of tax benefit
     —     (197)    —     —     —     —     (197)
Net Income (Loss)
     282     106     39     104     (3)    (72)    456 
Preferred Securities Dividends/Preference Unit Distributions
     (3)    —     —     (3)    —     6     — 
Segment Earnings (Loss)
     279     106     39     101     (3)    (66)    456 
Gross Additions to Long-Lived Assets
     372     345     3     23     —     8     751 
**For the Nine Months Ended September 30, 2004:**
                            
Total Operating Revenues
    $5,236    $3,818    $152    $542    $7    $(1,493)   $8,262 
Income (Loss) from Continuing Operations
     281     319     33     79     (7)    (44)    661 
(Loss) Income from Discontinued Operations, including Gain on Disposal, net of tax
     —     (27)    —     5     —     —     (22)
Net Income (Loss)
     281     292     33     84     (7)    (44)    639 
Preferred Securities Dividends/Preference
     (3)    —     (2)    (11)    —     16     — 
Unit Distributions
                            
Segment Earnings (Loss)
     278     292     31     73     (7)    (28)    639 
Gross Additions to Long-Lived Assets
     290     522     10     69     —     11     902 
**As of September 30, 2005:**
                            
Total Assets
    $14,172    $9,030    $3,058    $3,973    $13    $(131)   $30,115 
Investments in Equity Method Subsidiaries
    $—    $—    $24    $1,141    $—    $—    $1,165 
**As of December 31, 2004:**
                            
Total Assets
    $13,586    $8,607    $2,999    $4,144    $52    $(144)   $29,244 
Investments in Equity Method Subsidiaries
    $—    $—    $41    $1,072    $—    $—    $1,113                             
(A)
 Energy Holdings' other activities include amounts applicable to Energy Holdings (as parent company) and EGDC. The net losses primarily relate to financing and certain administrative and general costs of Energy Holdings. *(footnote continued on next page)*
45

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

*(footnote continued from previous page)*

(B)
 PSEG's other activities include amounts applicable to PSEG (as 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 12. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at PSEG, as parent corporation.
**Note 12. Related-Party Transactions**

      The majority of the following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process.

**BGSS and BGS Contracts**

      **PSE&G and Power**

      PSE&G has 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 through March 2007.

      Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.

      The amounts which Power charged to PSE&G for BGS and BGSS are presented below:
   **Power's Billings for the**   **Quarters EndedSeptember 30,** **Nine Months EndedSeptember 30,**   **2005** **2004** **2005** **2004**   **(Millions)**                                          
BGS
    $172     $168     $395     $250              
BGSS
    $203     $157     $1,325     $1,240                              
      As of September 30, 2005 and December 31, 2004, Power had net receivables from PSE&G of approximately $125 million and $357 million, respectively, primarily related to the BGS and BGSS contracts. These transactions were properly recognized on each company's stand-alone financial statements.

      In addition, as of September 30, 2005 and December 31, 2004, PSE&G had a receivable from Power of approximately $462 million and $25 million, respectively, related to gas supply hedges Power entered into for BGSS. For additional information, see Note 5. Commitments and Contingent Liabilities.

**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

46

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

each of the operating companies. The billings for administrative services and payables are presented below:
  **Services' Billings for the**          **Quarters EndedSeptember 30,** **Nine Months EndedSeptember 30,** **Payable to Services as of**  **2005** **2004** **2005** **2004** **September 30,2005** **December 31,2004**  **(Millions)**                        
PSE&G
    $51     $52     $154     $152     $34     $38 
Power
    $39     $36     $114     $110     $19     $23 
Energy Holdings
    $4     $5     $13     $13     $1     $2                         
      These transactions were properly recognized on each company's stand-alone financial statements and were eliminated when preparing PSEG's Condensed Consolidated Financial Statements. PSEG, PSE&G, Power and Energy Holdings each believes that the costs of services provided by Services approximates market value for such services.

**Tax Sharing Agreement**

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

      PSE&G, Power and Energy Holdings had (payables to) receivables from PSEG related to taxes as follows:
   **(Payable to) Receivable from PSEGAs of**   **September 30,2005** **December 31,2004**   **(Millions)**                                  
PSE&G
    $(72)        $(45)             
Power
    $63         $9              
Energy Holdings
    $(2)        $19                      
**Affiliate Loans and Advances**

      **PSEG and Power**

      As of September 30, 2005, Power had a note receivable due from PSEG of approximately $62 million, reflecting the investment of its excess cash with PSEG. As of December 31, 2004, Power had a payable to PSEG of approximately $98 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 September 30, 2005 and December 31, 2004, Energy Holdings had a note receivable due from PSEG of approximately $61 million and $115 million, respectively, reflecting the investment of its excess cash with PSEG. Interest Income related to these borrowings was immaterial.

      **PSE&G and Services**

      As of September 30, 2005 and December 31, 2004, PSE&G had advanced working capital to Services of approximately $33 million. This amount is included in Other Noncurrent Assets on PSE&G's Condensed Consolidated Balance Sheets.

      **Power and Services**

      As of September 30, 2005 and December 31, 2004, Power had advanced working capital to Services of approximately $17 million. This amount is included in Other Noncurrent Assets on Power's Condensed Consolidated Balance Sheets.

47

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

**Other**

      **PSEG and PSE&G**

      As of September 30, 2005 and December 31, 2004, PSE&G had receivables from PSEG of approximately $8 million and $14 million, respectively, related to amounts that PSEG had collected on PSE&G's behalf.

      **PSEG and Power**

      As of September 30, 2005 and December 31, 2004, Power had receivables from PSEG of approximately $4 million related to amounts that PSEG had collected on Power's behalf.

      **Energy Holdings**

      As of September 30, 2005 and December 31, 2004, Global had loans of approximately $60 million and $68 million, respectively, due from Prisma, a joint venture which is 50%-owned by Global and operates several biomass generation plants in Italy. The decrease in the loan balances, which are denominated in Euros, was due to the strengthening of the U.S. dollar relative to the Euro during the first nine months of 2005 and was recorded as a foreign currency loss in Other Deductions. Included in the loan balances as of September 30, 2005 and December 31, 2004 was $24 million of accrued interest. These loans are guaranteed by an affiliate of Global’s partner. Due to insufficient funds at the project level, total payments of $8 million due to Global on June 30, 2005 and September 30, 2005 were notmade. In August 2005, Global began seeking to enforce its rights under the guarantee as it continues to attempt to negotiate a restructuring of the Prisma project with its partner.

48

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

**Note 13. Guarantees of Debt
**Power**

      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.
  **Power** **GuarantorSubsidiaries** **OtherSubsidiaries** **ConsolidatingAdjustments** **Consolidated Total**  **(Millions)**
**For the Quarter Ended September 30, 2005:**
                    
Operating Revenues
  $—  $1,673  $27  $(256) $1,444 
Operating Expenses
   1   1,466   30   (257)  1,240                  
Operating (Loss) Income
   (1)  207   (3)  1   204 
Other Income
   35   74   —   (35)  74 
Other Deductions
   —   (11)  (1)  (1)  (13)
Equity Earnings (Losses) of Subsidiaries
   135   (17)  —   (118)  — 
Interest Expense
   (40)  (13)  (15)  36   (32)
Income Taxes
   (4)  (105)  6   2   (101)
Loss        on Discontinued Operations, Including Loss on Disposal, net of tax benefit
   —   —   (7)  —   (7)                 
Net Income (Loss)
  $125  $135  $(20) $(115) $125                  
**For the Quarter Ended September 30, 2004:**
                    
Operating Revenues
  $—  $1,400  $35  $(305) $1,130 
Operating Expenses
   —   1,155   28   (307)  876                  
Operating Income
   —   245   7   2   254 
Other Income
   28   36   1   (29)  36 
Other Deductions
   —   (12)  —   (1)  (13)
Equity Earnings (Losses) of Subsidiaries
   134   (10)  —   (124)  — 
Interest Expense
   (30)  (20)  (10)  27   (33)
Income Taxes
   (1)  (105)  —   1   (105)
Loss        on Discontinued Operations, net of tax benefit
   —   (1)  (7)  —   (8)                 
Net Income (Loss)
  $131  $133  $(9) $(124) $131                                      
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**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**
  **Power** **GuarantorSubsidiaries** **OtherSubsidiaries** **ConsolidatingAdjustments** **Consolidated Total**  **(Millions)**
**For the Nine Months Ended September 30, 2005:**
                    
Operating Revenues
  $—  $4,900  $98  $(764) $4,234 
Operating Expenses
   1   4,401   84   (764)  3,722                  
Operating (Loss) Income
   (1)  499   14   —   512 
Other Income
   102   135   1   (103)  135 
Other Deductions
   —   (31)  (1)  (1)  (33)
Equity Earnings (Losses) of Subsidiaries
   116   (208)  —   92   — 
Interest Expense
   (110)  (47)  (32)  103   (86)
Income Taxes
   (1)  (231)  7   —   (225)
Loss        on Discontinued Operations, including Loss on Disposal net of tax benefit
   —   —   (197)  —   (197)                 
Net Income (Loss)
  $106  $117   (208) $91  $106                  
**For the Nine Months Ended September 30, 2004:**
                    
Operating Revenues
  $—  $4,509  $84  $(775) $3,818 
Operating Expenses
   —   3,998   72   (776)  3,294                  
Operating Income
   —   511   12   1   524 
Other Income
   66   140   1   (67)  140 
Other Deductions
   —   (38)  (5)  (1)  (44)
Equity Earnings (Losses) of Subsidiaries
   305   (35)  —   (270)  — 
Interest Expense
   (90)  (37)  (24)  66   (85)
Income Taxes
   11   (234)  6   1   (216)
Loss        on Discontinued Operations, net of tax benefit
   —   (1)  (26)  —   (27)                 
Net Income (Loss)
  $292  $306  $(36) $(270) $292                  
**For the Nine Months Ended September 30, 2005:**
                    
Net Cash (Used In) Provided By Operating Activities
  $(1,188) $72  $1,112  $292  $288 
Net Cash Provided By (Used In) Investing Activities
  $88  $174  $(25) $(418) $(181)
Net Cash Provided By (Used In) Financing Activities
  $1,100  $(237) $(1,087) $126  $(98)
**For the Nine Months Ended September 30, 2004:**
                    
Net Cash (Used In) Provided By Operating Activities
  $(70) $35  $84  $439  $488 
Net Cash Provided By (Used In) Investing Activities
  $77  $(199) $(136) $(191) $(449)
Net Cash (Used In) Provided By Financing Activities
  $(7) $(146) $52  $51  $(50)
**As of September 30, 2005:**
                    
Current Assets
  $2,800  $2,919  $166  $(3,199) $2,686 
Property, Plant and Equipment, net
   140   3,129   1,539   1   4,809 
Investment in Subsidiaries
   3,197   451   —   (3,648)  — 
Noncurrent Assets
   200   1,628   16   (309)  1,535                  
Total Assets
  $6,337  $8,127  $1,721  $(7,155) $9,030                  
Current Liabilities
  $668  $3,910  $1,149  $(3,291) $2,436 
Noncurrent Liabilities
   57   1,156   76   (306)  983 
Long-Term Debt
   2,817   —   —   —   2,817 
Member’s Equity
   2,795   3,061   496   (3,558)  2,794                  
Total Liabilities and Member’s Equity
  $6,337  $8,127  $1,721  $(7,155) $9,030                                      
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**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**
  **Power** **GuarantorSubsidiaries** **OtherSubsidiaries** **ConsolidatingAdjustments** **Consolidated Total**  **(Millions)**                    
**As of December 31, 2004:**
                    
Current Assets
  $1,445  $2,058  $578  $(1,478) $2,603 
Property, Plant and Equipment, net
   107   3,021   1,463   —   4,591 
Investment in Subsidiaries
   3,725   646   —   (4,371)  — 
Noncurrent Assets
   1,291   1,286   56   (1,220)  1,413                  
Total Assets
  $6,568  $7,011  $2,097  $(7,069) $8,607                  
Current Liabilities
  $117  $2,701  $269  $(1,566) $1,521 
Noncurrent Liabilities
   51   720   36   (120)  687 
Note Payable—Affiliated Company
   —   —   300   (300)  — 
Long-Term Debt
   3,316   —   800   (800)  3,316 
Member’s Equity
   3,084   3,590   692   (4,283)  3,083                  
Total Liabilities and Member’s Equity
  $6,568  $7,011  $2,097  $(7,069) $8,607                                      
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****ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIALCONDITION AND RESULTS OF OPERATIONS (MD&A)**

      Following are the significant changes in or additions to information reported in the 2004 Annual Report on Form 10-K affecting the consolidated financial condition and the results of operations. This discussion refers to the Condensed Consolidated Financial Statements (Statements) and the related Notes to Condensed Consolidated Financial Statements (Notes) and should be read in conjunction with such Statements and Notes.

      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 L.L.C. (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 representations as to any other company.

**PENDING MERGER**

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

      As previously disclosed, 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 and its subsidiaries 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. On July 19, 2005, shareholders of PSEG voted to approve the Merger, and on July 22, 2005, shareholders of Exelon voted to approve the issuance of common shares to PSEG shareholders to effect the Merger.

      Completion of the Merger is subject to approval by a number of governmental authorities, which may impose conditions on completion of the Merger, require changes to the terms of the Merger or fail to approve the Merger. The imposition of 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 maintain a viable stand-alone business.

      In the first quarter of 2005, Exelon and PSEG filed applications or made filings with the Federal Energy Regulatory Commission (FERC), the New Jersey Board of Public Utilities (BPU), the Pennsylvania Public Utility Commission (PAPUC), the Nuclear Regulatory Commission (NRC), the New York Public Service Commission (NYPSC), the New Jersey Department of Environmental Protection (NJDEP) and the Connecticut Siting Council. Exelon and PSEG also made the filings required under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act) and Exelon filed a private letter ruling on the transfer of nuclear decommissioning funds with the Internal Revenue Service. Additional applications and notices have been filed in subsequent months.

      On June 30, 2005, the FERC voted to approve the Merger. The FERC determined that Exelon's and PSEG's proposed divestitures and other commitments in their original and supplemental filings with FERC, together with their answers to intervenors' questions, met the public interest standard of the Federal Power Act. Exelon and PSEG have committed to divest 4,000 megawatts (MW) of intermediate and peaking generation facilities located primarily in eastern PJM Interconnection L.L.C. (PJM), and to “virtually divest” 2,600 MW of nuclear capacity by effectively transferring control of the output through sales to third parties.

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      A number of parties, including the BPU, the American Public Power Association and the National Rural Electric Cooperative Association, have filed requests for rehearing of the decision made by FERC. In late August 2005, FERC issued a notice that it would respond to the rehearing request.

      During 2005, regulatory approvals or clearances related to the Merger have also been obtained from the Connecticut Siting Council regarding the transfer of PSEG Power Connecticut LLC's Certificate of Environmental Compatibility and Public Need to Exelon Generation Connecticut LLC, the NJDEP under the Industrial Site Recovery Act, the NYPSC and FERC with respect to the transfer of the hydro license for Yards Creek Generating Station. Approval of the transaction has also been obtained from the President of the Competition and Consumer Protection Office in Poland.

      On June 22, 2005, the BPU issued an oral decision stating that Exelon and PSEG will be required to prove that positive benefits flow to PSE&G's customers as a result of the Merger, as well as no adverse impact to competition, employees, customers, rates or reliability due to the Merger. On August 11, 2005, the Administrative Law Judge (ALJ) in the proceeding before the BPU amended a prior pre-hearing order to modify the timetable for the regulatory approval process in New Jersey. The procedural schedule for the BPU proceedings includes opportunities for settlement discussions with the consumer advocacy groups and other interested parties during the course of the proceedings. The order provides for such hearings to commence in late November 2005. On October 7, 2005, the ALJ approved a request from PSEG,Exelon and the BPU staff to delay the hearings until January 4, 2006. The postponement of the hearings does not impact the order's provision for settlement discussions in December 2005 after the positions of the parties involved have been filed or the ALJ to issue an initial decision by March 30, 2006. Thereafter, pursuant to the provisions of the New Jersey Administrative Procedure Act, a decision of the full BPU could reasonably be expected by approximately May 15, 2006.

      In early September 2005, Exelon's wholly owned subsidiary, PECO Energy Company (PECO), filed with the PAPUC a settlement of most issues raised in Pennsylvania's review of the Merger. If the settlement is approved, PECO would provide $120 million over four years in rate discounts for customers and cap its rates through the end of 2010. The settlement also provides substantial funding for alternative energy and environmental projects, economic development, and expanded outreach and assistance for low-income customers. PECO also made commitments for enhanced customer and service reliability and pledges for charitable donations and maintenance of its current headquarters at current staff levels in Philadelphia until the end of 2010. The settlement was reached with consumer, business, environmental and low income consumeradvocates.

      On September 12, 2005, the ALJ in the proceeding before the PAPUC issued a revised pre-hearing order establishing a modified timetable for the regulatory approval process in Pennsylvania. The modified timetable permits parties to comment on PECO's settlement and unresolved issues under the settlement and accelerates the schedule for hearings and briefs. Accordingly, it is anticipated that the ALJ may issue an initial decision earlier than the previously expected date of mid-December 2005. It is possible that the full PAPUC will vote on the case before the end of 2005.

      PSEG and Exelon expect to complete their responses to the information requests of the U.S. Department of Justice (DOJ) under the HSR Act in the fourth quarter of 2005. Once the DOJ has evaluated the information submitted by PSEG, Exelon and others, PSEG and Exelon expect to discuss any suggestions or remedies proposed by the DOJ.

      Commonwealth Edison (ComEd), a wholly owned subsidiary of Exelon, is involved in two regulatory proceedings in Illinois which would culminate for ComEd the restructuring of the electricity business in Illinois commenced in 1997. Pursuant to that restructuring, ComEd's rates were reduced until January 1, 2007 and ComEd divested its electric generating stations to third parties, including to its affiliate, Exelon Generation Company, LLC (Exelon Generation). During the restructuring period, Exelon Generation has been required to supply power to ComEd pursuant to a contract which expires December 31, 2006. One of the current proceedings involves a proposal by ComEd to procure power after January 1, 2007 (Procurement Case) pursuant to an auction similar to the BGS auction in New Jersey. The other proceedingis a rate case (Rate Case) for its distribution operations to establish new distribution rates effective January 1, 2007.

53

      It has been  reported by Exelon that the ICC's final order on the Procurement Case is  expected by January 24, 2006, subject to the resolution of litigation instituted  on September 1, 2005 by the Illinois Attorney General, the Cook County  State's Attorney, the Citizens Utility Board (CUB) and the Environmental  Law and Public Policy Center seeking to block the ICC from approving the Procurement  Case. The Illinois General Assembly has held hearings concerning generation  procurement post-2006, and it may choose to take further action on this issue.  The Governor of Illinois has expressed his opposition to the procurement process  proposed in the Procurement Case. On September 21, 2005, the Governor of  Illinois appointed the former Executive Director of CUB, Mr. Martin Cohen, as  the Chairman of the ICC. On October 5, 2005, ComEd filed a motion with  the ICC formally seeking recusal of Mr. Cohen from the Procurement Case.

      Exelon reports that it cannot predict the results of the Procurement Case or the Rate Case before the ICC or whether the Illinois General Assembly might take action that could have a material impact on the outcome of the regulatory process. However, if the price at which ComEd is allowed to sell energy beginning in 2007 is below ComEd's cost to procure electricity, there may be material adverse consequences to ComEd and possibly Exelon.

      The regulatory and political developments in Illinois may also have an effect on the settlement discussions and proceedings before the BPU and the PAPUC and could delay those regulatory approvals. Some possible outcomes of the developments in Illinois could have an effect on the timing or the closing conditions to the Merger.

      Based on the current status of the regulatory approval process, Exelon and PSEG expect that, assuming all other conditions to completion of the Merger are satisfied, the Merger would be completed in the first quarter of 2006 if the regulatory proceedings before the BPU and the PAPUC are settled and approved before the dates on which those state authorities are expected to rule on the Merger in the absence of a settlement, as discussed above. If early settlements are not reached and approved, then the parties expect that, assuming all other conditions are satisfied, the Merger should be completed in the second quarter of 2006.

      Although Exelon and PSEG believe that the expectations as to timing for the closing of the Merger described above are reasonable, no assurances can be given as to the timing of the receipt of any required regulatory approvals or that all required approvals will be received. In the event the Merger does not close, management believes PSEG will continue to operate successfully, however, inability to close the pending Merger with Exelon could have a material adverse effect on the financial condition, results of operations and cash flows of PSEG, PSE&G, Power and Energy Holdings.

**OVERVIEW**

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

      Prior to the completion of the Merger, PSEG and Exelon, and their respective subsidiaries, will continue to operate as separate entities. The discussion contained in the 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 proposed Merger.

      ***Market Price Environment***

      There has been a significant increase in commodity prices, including fuel, emission allowances and electricity. Over the last year, both natural gas and electric prices in PJM have more than doubled. Price increases of this magnitude are much greater than have been experienced in recent history and could have a considerable effect on PSEG's businesses. For Power, a rising price environment can result in increased cost to produce electricity, particularly with gas-fired generation, higher replacement power costs, including power that must be purchased when unplanned outages occur, potential alteration of the dispatch order of units based upon fuel choice and efficiency, changes to the pricing environment in which companies contract for fuel and electricity and higher liquidity requirements. For PSE&G, a rising commodityprice environment results in higher delivered electric and gas rates for end use

54

customers, and may result in decreased demand by end users of both electricity and gas and greater working capital requirements as the collection of higher commodity costs may be deferred into future periods.

      During the nine months ended September 30, 2005 the rising commodity price environment resulted in increased liquidity requirements for Power's energy sales contracts entered into in the normal course of business (See Liquidity and Capital Resources for additional information). In addition, Accumulated Other Comprehensive Loss (OCL) increased as contracts that qualify for hedge accounting were marked to market (See Other Comprehensive Loss for additional information).

      Over the next few years, management believes that a rising commodity price environment will serve to increase profitability for Power because higher prices should result in greater margin opportunity as existing contracts expire and higher prices are realized, assuming generating plants operate as planned. Management also believes that Power has sufficient liquidity to meet margin requirements associated with forward contracts to sell energy.

**PSEG**

      PSEG's business consists of four reportable segments, which are PSE&G, Power and the two direct subsidiaries of Energy Holdings: PSEG Global L.L.C. (Global) and PSEG Resources L.L.C. (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, significant events that have occurred during the first nine months of 2005 and expectations for the full-year 2005 and beyond.

      For the nine months ended September 30, 2005, PSEG had Income from Continuing Operations of $653 million, or $2.68 diluted per share. PSEG continues to project Income from Continuing Operations for 2005 of $3.15 to $3.35 per share. Included in its projections for 2005 were $60 million to $70 million of expenses at the PSEG parent level, primarily due to financing costs. It is expected that costs associated with the proposed Merger could reduce 2005 results by as much as $0.10 to $0.15 per share, which is not included in the earnings projection noted above.

      For 2006, PSEG expects Income from Continuing Operations to range from $3.45 to $3.75 per share. The increase as compared to current 2005 earnings projections is primarily due to anticipated increased earnings at Power. The projected increase at Power is due to anticipated higher margins through the expiration of existing contracts and the realization of current and anticipated higher market prices. Also assumed in the earnings projections for 2006 are reasonable outcomes to PSE&G's gas and electric rate cases and continued strong contributions from Global's operations in Texas and South America.

**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. For the nine months ended September 30, 2005, PSE&G had Net Income of $282 million. PSE&G expects Income from Continuing Operations to range from $325 million to $345 million for 2005, based on normal weather conditions, expected growth in electricity and natural gas sales and productivity gains, partially offset by operating cost increases.

      PSE&G provides electricity under two types of basic generation service (BGS) through a BPU-administered auction for customers that do not have 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. PSE&G's total BGS-FP load is approximately 8,600 MW. Approximately one-third of this total load is expected to be auctioned off each year for a three-year term. BGS-Commercial and Industrial Energy Price (CIEP) provides supply for larger customers at hourly 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 current load.

55

      In February 2005, the BPU approved the results of New Jersey's annual BGS-FP and BGS-CIEP auctions and PSE&G successfully secured contracts to provide the electricity requirements for its customers' needs.

      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. PSE&G's current pricing is as follows:
  **Term Ending****Term** **May 2005(a)12 months** **May 2006(b)34 months** **May 2007(a)36 months** **May 2008(c)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 first became effective on June 1, 2005.
      On September 30, 2005, PSE&G filed a petition with the BPU seeking an overall 3.78% increase in its gas base rates to appropriately recover the cost of gas delivery and to be effective June 30, 2006. Approximately $55 million of the $132.8 million request is for an increase in book depreciation rates. The balance of the request will cover increased plant investment, higher operating expenses and provide an 11% return on equity. PSE&G's current gas base rates have been in effect since January 2002.

      ***Gas Commodity Prices***

      PSE&G makes no margin on gas commodity sales as the costs are directly passed through to customers. The difference between gas costs incurred and the Basic Gas Supply Service (BGSS) revenues received from customers is deferred and collected from or returned to customers in future periods. However, the significant increase in the price of natural gas, as discussed previously, impacts PSE&G's revenues and expenses in a number of ways.

      ***Gas Supply***

      Gas commodity prices fluctuate monthly for commercial and industrial (C&I) customers so price increases are immediately reflected in the revenues and gas costs for those customers. For example, the majority of BGSS C&I customers paid $1.38 per therm in September 2005, an 83% increase over the $0.75 per therm paid in September 2004. The higher prices have and will continue to negatively impact delivery sales volumes.

      The gas commodity price for residential customers under the BGSS tariff is set annually, usually on October 1. 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 BGSS proceedings. The difference between costs and the amount recovered from customers in revenues is deferred and collected from or returned to customers in future periods.

      On August 19, 2005, the BPU approved an increase for residential customers of 10.6%, which became effective on September 1, 2005. This increase was based on a May 2005 forecast of gas cost through September 2006. The new charge of $0.87 per therm is significantly lower than the C&I commodity rate because PSE&G has hedged a portion of future load at lower prices. PSE&G has the right to increase rates up to 5% on both December 1 and February 1 without BPU approval. Based on the current forecast, if no additional increase is permitted, PSE&G could have a deferred gas balance well in excess of $200 million by September 2006. Even if the two 5% increases were implemented, the deferred gas balance could exceed $100 million by September 2006 with current prices. PSE&G does not recover the carryingcosts on gas under recoveries. PSE&G is working closely with the BPU to address the rising gas costs.

56

      ***Electric Supply***

      The PJM on-peak locational marginal price is directly impacted by higher gas prices. Approximately 84% of PSE&G's load is provided by BGS-FP contracts. One-third of this load is auctioned off each year for a three-year term which dampens the impact of current pricing. The remaining 16% of the load is provided through BGS-CIEP contracts to larger customers at hourly PJM real-time market prices for a term of 12 months so price increases are immediately reflected in the revenues and electric costs for these customers. Both BGS tariffs provide current rate recovery in the next billing period. Therefore, the deferred balance at any given month end is relatively small.

**Power**

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

      As a result of the increases in market prices, Power expects substantial increases in earnings for 2006. For 2006, Power had entered into contracts for 85% to 90% of its nuclear and coal-fired generation. Also, for 2007 and 2008, Power has been actively terming-up future period sales to capture the value of its nuclear and coal-fired generation, given recent market conditions. As of mid-October, 2005, Power had met its stated objective of contracting at least 75% of its anticipated output over an 18-24 month horizon, including terming-up between 65% and 75% of its anticipated nuclear and coal-fired generation for 2007, and between 35% and 45% of its nuclear and coal-fired generation for 2008. Changes in the operation of Power's generating facilities, fuel and capacity prices, expected contract prices, capacityfactors or other assumptions could materially affect its ability to meet earnings targets.

      Power's objective is to enter into load-serving contracts, firm sales and trading positions for 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 BGS auctions in New Jersey, contracts with local electric distribution companies (EDCs) in Pennsylvania and Connecticut and other firm sales and trading positions. As mentioned above, in February 2005, the BPU approved the results of the BGS auction process for New Jersey customers. Power continues to be a direct supplier of New Jersey EDCs under both the BGS-FP and BGS-CIEP auctions, entering into additional contracts that began on June 1, 2005. Power believes that its obligations under these contracts are reasonably balanced by its available supply. Power continuesto believe that entering into contracts for at least 75% of its anticipated generation output is an appropriate way to reduce the volatility of its earnings.

      On September 28, 2005, Power completed the sale of its electric generation facility located in Waterford, Ohio (Waterford) to a subsidiary of American Electric Power Company, Inc. The sale price for the facility and inventory is $220 million. The proceeds, together with anticipated reduction in tax liability, are approximately $320 million, which will be used to retire debt at Power. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes for further discussion.

      During 2005, Power began collecting a monthly fixed payment amount for reliability services provided by its generating facilities in Connecticut, retroactive to November 18, 2004. Based on a FERC order issued in late April 2005 and effective February 24, 2005, subject to refund and hearing, Power has also begun receiving payments for reliability services provided by the Sewaren Station, Units 1, 2, 3 and 4 and Hudson Station, Unit 1. These payments provide compensation to a generation owner when a unit proposed for retirement must continue operating for reliability purposes. Such payments are net of operating margins at the units in both markets.

      On July 18, 2005, Power's new Bethlehem Energy Center (BEC), a 750 MW, natural gas -fired combined cycle power generation plant near Albany, New York, began commercial operations.

57

      A key factor in Power's ability to achieve its objectives is its capability to operate its nuclear and fossil stations at sufficient capacity factors to avoid the need to purchase higher-priced electricity to satisfy its obligations. Concurrent with the signing of the Merger Agreement, Power entered into an Operating Services Contract (OSC) with Exelon Generation. Under the terms of the OSC, since January 17, 2005, Exelon Generation has provided management personnel and its proprietary management systems under a fee arrangement to Power to operate the Salem and Hope Creek nuclear generating facilities. In May 2005, a scheduled refueling outage at Salem Unit 2 was completed ahead of schedule while meeting self-imposed nuclear safety targets.

      For the nine months ended September 30, 2005, Power had Income from Continuing Operations of $303 million. Power expects Income from Continuing Operations to range from $335 million to $385 million in 2005. For the nine months ended September 30, 2005, Power had Net Income of $106 million, which includes a Loss from Discontinued Operations of $197 million, including Loss on Disposal related to Waterford, discussed above.

**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.

      For the nine months ended September 30, 2005, Energy Holdings had Net Income of $140 million. Based on current earnings, Energy Holdings believes that Income from Continuing Operations for 2005 could exceed its previously projected range of $135 million to $155 million, reflecting improved results from Texas Independent Energy, L.P. (TIE), lower financing costs and the absence of foreign currency losses at Elektrocieplownia Chorzow Sp. z o.o. (ELCHO) which are expected to more than offset the loss of earnings due to the sale of Meiya Power Company Limited (MPC) and the partial sale of Luz del Sur S.A.A. (LDS) in 2004.

      Global continues to limit its capital spending, while focusing on operations and improved performance of existing businesses and is seeking to opportunistically monetize investments that may no longer have a strategic fit. In April 2005, Global sold a 35% interest in Dhofar Power Company S.A.O.C. (Dhofar Power), reducing its ownership interest from 81% to 46%, through a public offering on the Omani stock exchange for net proceeds of approximately $25 million.

      The capital requirements of Global's consolidated subsidiaries are primarily financed from internally generated cash flow within the projects and from local sources on a non-recourse basis or limited discretionary investments by Energy Holdings.

      Under a provision of The American Jobs Creation Act of 2004 (Jobs Act), Global has a one-year window to repatriate earnings from its foreign investments and claim a special one-time 85% dividends received tax deduction on such distributions. To date during 2005, PSEG has approved Domestic Reinvestment Plans which provide for the repatriation of approximately $182 million, of which $140 million is eligible for the reduced tax rate pursuant to the Jobs Act. The tax expense associated with such repatriation totaled approximately $9 million and was recorded in the quarter ended September 30, 2005. In addition, Global's projections indicate that additional earnings could be generated by its international investments over the balance of 2005 that could increase the amount of funds that could reasonably be consideredfor repatriation in 2005 by approximately $50 million, which would result in an additional $2 million of tax expense. Global has made no change in its current intention to indefinitely reinvest accumulated earnings of its foreign subsidiaries.

      Resources is focused 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. Resources' ability to realize tax benefits associated with its leveraged lease investments is dependent upon operating gains generated by its affiliates. Resources' earnings and cash flows are expected to decrease in the future as the investment portfolio matures.

58

      In January 2005, Resources and Global sold their interests in three Solar Electric Generating Systems (SEGS) projects for proceeds of approximately $7 million and Resources received proceeds of approximately $17 million from the KKR Fund's sale of its investment in KinderCare Learning Centers, Inc.

      In June 2005, Resources wrote off its entire investment of approximately $15 million, net of tax, in an aircraft lease to United Airlines (UAL) upon termination of the lease and repossession of the aircraft by the lenders in a bankruptcy proceeding with UAL.

      As of September 30, 2005, Resources has a remaining gross investment in four leased aircraft of approximately $36 million. On September 14, 2005, Delta Airlines (Delta) and Northwest Airlines (Northwest), the lessees for Resources' four remaining aircraft, filed for Chapter 11 bankruptcy protection. This had no material effect on Energy Holdings as it continues to believe that it will be able to fully recover the recorded amount of its investments in these aircraft.

      Resources continues to monitor the accounting and tax treatment of certain leases in its portfolio. For additional information, see Note 5. Commitments and Contingent Liabilities of the Notes.

**RESULTS OF OPERATIONS**

      The results for PSEG, PSE&G, Power and Energy Holdings for the quarter and nine months ended September 30, 2005 and 2004 are presented below:
  **Earnings (Losses)**  **Quarters EndedSeptember 30,** **Nine Months EndedSeptember 30,**  **2005** **2004** **2005** **2004**  **(Millions)**
PSE&G
    $115     $93     $282     $281 
Power
     132      139      303      319 
Energy Holdings:
                
Global
     22      20      104      78 
Resources
     17      18      39      34 
Other (A)
     —      (2)     (3)     (7)                         
Total Energy Holdings
     39      36      140      105 
Other (B)
     (26)     (16)     (72)     (44)                         
**PSEG Income from Continuing Operations**
     260      252      653      661 
Loss from Discontinued Operations, including Loss on Disposal (C)
     (7)     (8)     (197)     (22)                         
**PSEG Net Income**
    **$****253**     **$****244**     **$****456**     **$****639**                                            **Contribution to PSEG Earnings Per Share (Diluted) (D)**  **Quarters EndedSeptember 30,** **Nine Months EndedSeptember 30,**  **2005** **2004** **2005** **2004**
PSE&G
    $0.47     $0.39     $1.16     $1.18 
Power
     0.54      0.59      1.25      1.34 
Energy Holdings:
                
Global
     0.09      0.08      0.43      0.33 
Resources
     0.07      0.08      0.16      0.14 
Other (A)
     —      (0.01)     (0.01)     (0.03)                         
Total Energy Holdings
     0.16      0.15      0.58      0.44 
Other (B)
     (0.11)     (0.07)     (0.31)     (0.18)                         
**PSEG Income from Continuing Operations**
     1.06      1.06      2.68      2.78 
Loss from Discontinued Operations, including Loss on Disposal (C)
     (0.03)     (0.03)     (0.81)     (0.09)                         
**PSEG Net Income**
    **$****1.03**     **$****1.03**     **$****1.87**     **$****2.69**                          *(footnotes on next page)*                
59

*(footnotes from previous page)*
   (A)   Other activities include non-segment amounts of Energy Holdings and its subsidiaries and intercompany eliminations. Specific amounts include interest on certain financing transactions and certain other administrative and general expenses at Energy Holdings.   (B)   Other activities include non-segment amounts of PSEG (as parent company) and intercompany eliminations. Specific amounts include preferred securities dividends/preference unit distributions for PSE&G and Energy Holdings, interest on certain financing transactions and Merger expenses and certain other administrative and general expenses at PSEG (as parent company).   (C)   Includes Discontinued Operations at Power in 2005 and 2004 and Energy Holdings in 2004. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes.   (D)   Earnings per Share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct interest in PSEG's assets and liabilities as a whole.
      The $8 million increase in Income from Continuing Operations for the quarter primarily resulted from an increase in electric commodity revenues at PSE&G due to higher weather-related demand, higher realized gains in Power's Nuclear Decommissioning Trust (NDT) portfolio and improved earnings at Global due to improved operations at TIE and favorable foreign currency exchange rates. Partially offsetting these increases were Merger-related costs of approximately $10 million, net of tax, at PSEG, higher interest expense at the PSEG parent level, higher prices for replacement energy and fuel costs at Power and $9 million of tax expense for one-time dividends that were repatriated from Global's international investments pursuant to the Jobs Act.

      The $8 million decrease in Income from Continuing Operations for the nine months was primarily due to lower earnings at Power, reflecting higher prices for replacement energy and fuel costs partially offset by higher prices from sales of electricity in the spot market and higher Reliability-Must-Run revenues. In addition, Merger-related costs of approximately $26 million, net of tax at PSEG and Power contributed to the overall decline in Income from Continuing Operations. These decreases were substantially offset by higher earnings at Global due to the reasons discussed above.

      The change in Net Income for the nine months ended September 30, 2005 included a decrease of $170 million from the Loss from Discontinued Operations at Power from the sale of Waterford in 2005 and a decrease of $5 million from Income from Discontinued Operations at Energy Holdings from the sale of its majority interest in Carthage Power Company in 2004.

**PSEG**
  **For theQuarters EndedSeptember 30,**         **For theNine MonthsEndedSeptember 30,**          **2005** **2004** **Increase(Decrease)** **%** **2005** **2004** **Increase(Decrease)** **%**      **(Millions)**         **(Millions)**    
Operating Revenues
    $3,376     $2,749     $627      23     $9,127     $8,262     $865      10 
Energy Costs
    $1,999     $1,418     $581      41     $5,213     $4,498     $715      16 
Operation and Maintenance
    $560     $527     $33      6     $1,734     $1,604     $130      8 
Depreciation and Amortization
    $207     $190     $17      9     $572     $525     $47      9 
Income from Equity Method Investments
    $29     $31     $(2)     (6)    $96     $92     $4      4 
Other Income
    $91     $45     $46      N/A     $166     $152     $14      9 
Other Deductions
    $(36)    $(23)    $13      57     $(64)    $(63)    $1      2 
Interest Expense
    $(216)    $(207)    $9      4     $(631)    $(627)    $4      1 
Income Tax Expense
    $(183)    $(177)    $6      3     $(414)    $(422)    $(8)     (2)
Loss from Discontinued Operations, including Loss on Disposal, net of tax benefit
    $(7)    $(8)    $(1)     (13)    $(197)    $(22)    $175      N/A                                 
60

      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 12. 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 theQuarters EndedSeptember 30,**         **For theNine MonthsEndedSeptember 30,**          **2005** **2004** **Increase(Decrease)** **%** **2005** **2004** **Increase(Decrease)** **%**      **(Millions)**         **(Millions)**    
Operating Revenues
    $1,934     $1,636     $298      18     $5,559     $5,236     $323      6 
Energy Costs
    $1,195     $960     $235      24     $3,472     $3,203     $269      8 
Operation and Maintenance
    $276     $261     $15      6     $839     $797     $42      5 
Depreciation and Amortization
    $155     $140     $15      11     $418     $393     $25      6 
Other Income
    $3     $4     $(1)     (25)    $7     $10     $(3)     (30)
Other Deductions
    $(1)    $—     $1      N/A     $(2)    $(1)    $1      100 
Interest Expense
    $(86)    $(86)    $—      —     $(256)    $(273)    $(17)     (6)
Income Tax Expense
    $(74)    $(70)    $4      6     $(191)    $(195)    $(4)     (2)                                
      **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. The $298 million increase for the quarter ended September 30, 2005, as compared to the same period in 2004, was due to an increase of $224 million in commodity revenues, described below, and $72 million in delivery revenues. The $323 million increase for the nine months ended September 30, 2005, as compared to the same period in 2004, was due to increases of $266 million in commodity revenues, described below, $52 million in delivery revenues and $5 million in other operating revenues, primarily related to appliance service contracts.

      ***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 BGSS proceedings. Electric commodity prices are set at the annual BGS auctions.

      The $224 million increase in commodity revenues for the quarter ended September 30, 2005, as compared to the same period in 2004, was due to increases of $171 million in electric commodity revenues, $106 million primarily due to higher BGS prices and $65 million in higher volumes due to weather. Also contributing to the increase was $53 million in increased gas commodity revenues, $38 million primarily due to higher BGSS prices, offset by an $8 million decrease due to the expiration of the Third Party Shopping Incentive on July 1, 2005. There is a corresponding $8 million increase in delivery revenues, described below. Also contributing to the increase is $23 million in higher volumes, primarily due to increased cogeneration operations.

      The $266 million increase in commodity revenues for the nine months ended September 30, 2005, as compared to the same period in 2004, was due to increases of $163 million in electric commodity

61

revenues, $117 million primarily due to higher BGS prices and $46 million in higher volumes due to weather. Also contributing to the increase was $103 million in increased gas commodity revenues, $101 million primarily due to higher BGSS prices, offset by an $8 million decrease due to the expiration of the Third Party Shopping Incentive on July 1, 2005, and a $10 million increase primarily due to increased cogeneration operations.

      ***Delivery***

      The $72 million increase in delivery revenues for the quarter ended September 30, 2005, as compared to the same period in 2004, was due to increases of $67 million in electric revenues and $5 million in gas revenues. The $67 million increase in electric delivery revenues was primarily due to higher volumes due to weather of $69 million offset by decreased prices of $2 million due to decreased distribution prices. The $5 million increase in gas delivery revenues was primarily due to the expiration of the Third Party Shopping Incentive on July 1, 2005, resulting in an increase of $8 million in delivery revenues with a corresponding offset in commodity revenues, described above. This was offset by $2 million in lower volume and demand revenues due to weather and $3 million due to the expiration of the Gas Cost UnderrecoveryAdjustment (GCUA) clause in January 2005.

      The $52 million increase in delivery revenues for the nine months ended September 30, 2005, as compared to the same period in 2004, was due to a $69 million increase in electric delivery revenues, partially offset by a $17 million decrease in gas delivery revenues. The $69 million increase in electric delivery revenues was primarily due to higher volume revenues of $58 million due to weather and $11 million in higher rates. The $17 million decrease in gas delivery revenues was primarily due to a $23 million decrease related to the expiration of the GCUA clause in January 2005 and $12 million in lower volume and demand revenues due to weather. These were offset by a $13 million increase in SBC rates, primarily due to the USF component. SBC rates are recorded with a corresponding offset in Operating Expenses, describedbelow, resulting in no impact to Net Income. Also offsetting the decrease is an $8 million increase due to the expiration of the Third Party Shopping Incentive on July 1, 2005, which is offset in commodity revenues, described above.

      **Operating Expenses**

      ***Energy Costs***

      The $235 million increase for the quarter ended September 30, 2005, as compared to the same period in 2004, was comprised of increases of $179 million in electric costs and $56 million in gas costs. The electric increase was due to a $124 million or 13% increase related to higher prices for BGS and Non-Utility Generation (NUG) purchases and a $55 million increase due to higher BGS volumes. The increase in gas costs was caused by a $41 million or 22% increase in gas prices and an $18 million increase due to higher sales volumes due primarily to higher interruptible sales offset by a $3 million decrease due to the expiration of the GCUA clause in January 2005, described above.

      The $269 million increase for the nine months ended September 30, 2005, as compared to the same period in 2004, was comprised of increases of $180 million in electric costs and $89 million in gas costs. The increase in electric costs was caused by a $167 million or 6% increase due to higher prices for BGS and NUG purchases and a $61 million increase due to higher BGS volumes, partially offset by a decrease of $47 million due to lower NUG volumes. The increased gas costs were due to a $98 million or 9% increase in gas prices and a $13 million increase in sales volumes due primarily to higher sales to cogenerators. These were offset by a $23 million decrease due to the expiration of the GCUA clause in January 2005, described above.

      ***Operation and Maintenance***

      The $15 million increase for the quarter ended September 30, 2005, as compared to the same period in 2004, was due primarily to $7 million in labor and fringe benefits due to increased wages and staffing and increased SBC expenses of $5 million.

      The $42 million increase for the nine months ended September 30, 2005, as compared to the same period in 2004, was due primarily to increased SBC expenses of $26 million and $16 million in labor and fringe benefits, respectively, due to increased wages and staffing.

62

      ***Depreciation and Amortization***

      The $15 million increase for the quarter ended September 30, 2005, as compared to the same period in 2004, was due primarily to a $20 million increase in the amortization of the Securitization regulatory asset. This was offset by a $3 million decrease in software amortization and a $2 million increase in excess depreciation reserve amortization.

      The $25 million increase for the nine months ended September 30, 2005, as compared to the same period in 2004, was due primarily to a $25 million increase in the amortization of the Securitization regulatory asset, a $4 million increase due to additional plant in service and a $3 million increase in the amortization of the Remediation Adjustment Clause (RAC). These were offset by a $5 million decrease in software amortization and a $2 million increase in excess depreciation reserve amortization.

      **Interest Expense**

      The $17 million decrease for the nine months ended September 30, 2005, as compared to the same period in 2004, was due to decreases of $24 million due to lower average interest rates and lower amounts of long-term debt outstanding. This was partially offset by increases of $5 million due to higher short-term interest rates and higher amounts of short-term debt outstanding.

      **Income Taxes**

      The $4 million increase for the quarter ended September 30, 2005, as compared to the same period in 2004, was primarily due to higher pre-tax income of $11 million offset by $4 million in various flow-thru benefits and $3 million in prior period adjustments recorded in 2004.

      The $4 million decrease for the nine months ended September 30, 2005, as compared to the same period in 2004, was due to lower pre-tax income of $1 million and $3 million in prior period adjustments in 2004.

**Power**
  **For theQuarters EndedSeptember 30,**         **For theNine MonthsEndedSeptember 30,**          **2005** **2004** **Increase(Decrease)** **%** **2005** **2004** **Increase(Decrease)** **%**      **(Millions)**             **(Millions)**        
Operating Revenues
    $1,444     $1,130     $314      28     $4,234     $3,818     $416      11 
Energy Costs
    $983     $636     $347      55     $2,941     $2,544     $397      16 
Operation and Maintenance
    $223     $211     $12      6     $685     $672     $13      2 
Depreciation and Amortization
    $34     $29     $5      17     $96     $78     $18      23 
Other Income
    $74     $36     $38      N/A     $135     $140     $(5)     (4)
Other Deductions
    $(13)    $(13)    $—      —     $(33)    $(44)    $(11)     (25)
Interest Expense
    $(32)    $(33)    $(1)     (3)    $(86)    $(85)    $1      1 
Income Tax Expense
    $(101)    $(105)    $(4)     (4)    $(225)    $(216)    $9      4 
Loss from Discontinued Operations, including Loss on Disposal, net of tax benefit
    $(7)    $(8)    $(1)     (13)    $(197)    $(27)    $170      N/A                                 
      **Operating Revenues**

      The $314 million increase for the quarter ended September 30, 2005, as compared to the same period in 2004, was due to increases of $284 million in generation revenues and $61 million in gas supply revenues partially offset by a decrease of $31 million in trading revenues.

      The $416 million increase for the nine months ended September 30, 2005, as compared to the same period in 2004, was due to increases of $299 million in generation revenues and $130 million in gas supply revenues partly offset by a decrease of $13 million in trading revenues.

63

      ***Generation***

      The increase of $284 million in generation revenues for the quarter ended September 30, 2005, as compared to the same period in 2004, was due principally to increases of approximately $70 million from operations in New York, largely due to BEC which began commercial operations on July 18, 2005 and approximately $64 million from sales in the power pools due to favorable weather conditions and pricing. Also contributing to the increase were approximately $39 million from higher load being served and higher pricing under the BGS contracts, $33 million from higher volumes sold under other wholesale contracts, $32 million from increased ancillary services and operating reserves and higher unrealized gains on asset-backed transactions of approximately $42 million.

      The increase of $299 million in generation revenues for the nine months ended September 30, 2005, as compared to the same period in 2004, was primarily due to increases of approximately $43 million related to Reliability Must-Run (RMR) revenues which Power began receiving in 2005 for certain of its generating facilities, approximately $56 million from operations in New York, largely due to BEC's operations which were partially offset by operations of the Albany Steam Station which was operational in 2004 and retired in February 2005, approximately $75 million from new contracts and approximately $33 million from increased sales and higher pricing in the various power pools partially offset by reduced load being served under the fixed-priced BGS contracts. Also contributing to the increase were approximately$45 million from increased ancillary services and operating reserves and higher unrealized gains on asset-backed transactions of approximately $32 million.

      ***Gas Supply***

      The $61 million increase in gas supply revenues for the quarter ended September 30, 2005 as compared to the same period for 2004, was primarily due to increases of approximately $42 million from higher gas prices and higher demand under the BGSS contract with PSE&G and approximately $18 million from higher prices for gas and pipeline capacity sold to other gas distributors partially offset by lower demand from other gas distributors.

      The $130 million increase for the nine months ended September 30, 2005, as compared to the same periods in 2004, was principally due to higher prices for gas and pipeline capacity partially offset by lower demand.

      ***Trading***

      The $31 million and $13 million decrease in trading revenues for the quarter and nine months ended September 30, 2005, respectively, as compared to the same period in 2004, was primarily due to market conditions.

      **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. The $347 million and $397 million increase for the quarter and nine months ended September 30, 2005, respectively, as compared to the same periods in 2004, was primarily due to increased generation and replacement power costs, reflecting higher demand and pricing due to weather conditions, operation of BEC since July 2005 and higher fossil fuel prices as well as higher prices for gas purchased to satisfy Power's BGSS obligations.

      ***Operation and Maintenance***

      The $12 million increase for the quarter ended September 30, 2005, as compared to the same period in 2004, was primarily due to a $12 million settlement received from the U.S. Department of Energy (DOE) in 2004 as reimbursement for nuclear waste storage costs incurred due to the delay in

64

construction of a federal storage facility. See Note 5. Commitments and Contingent Liabilities of the Notes—Nuclear Fuel Disposal.

      The $13 million increase for the nine months ended September 30, 2005, as compared to the same period in 2004, was primarily due to the $12 million DOE settlement in 2004, a $14 million restructuring charge recorded in 2005 related to Nuclear's workforce realignment plan, and higher costs of approximately $10 million related to Hope Creek's outage to complete Phase I of its turbine replacement in January 2005 and the Hope Creek outages for equipment repairs in March, June and August 2005. These increases were partially offset by $9 million of lower real estate taxes and $8 million of lower co-owner billings related to Power's jointly-owned facilities.

      ***Depreciation and Amortization***

      The $5 million and $18 million increase for the quarter and nine months ended September 30, 2005, respectively, as compared to the same periods in 2004, was due to BEC facility being placed into service in July 2005 and a higher depreciable asset base in 2005 at Nuclear. The increase for the nine months ended September 30, 2005 also included the Lawrenceburg facility being placed into service in June 2004.

      **Other Income**

      The $38 million increase in Other Income for the quarter ended September 30, 2005, as compared to the same period in 2004, was primarily due to higher realized gains of approximately $34 million from the NDT Funds and a $5 million gain from the sale in September 2005 of four gas turbine generators located in Burlington, New Jersey.

      The $5 million decrease in Other Income for the nine months ended September 30, 2005, as compared to the same period in 2004, was primarily due to decreased realized gains and income related to the NDT Funds partially offset by a $5 million gain from the sale in September 2005 of four gas turbine generators located in Burlington, New Jersey.

      **Other Deductions**

      The $11 million decrease for the nine months ended September 30, 2005, as compared to the same period in 2004, was primarily due to a write-off of $5 million of unamortized issuance costs related to the extinguishment of non-recourse project financing related to the Lawrenceburg facility in the first quarter of 2004 and decreased losses and expenses related to the NDT Funds.

      **Income Taxes**

      The $4 million decrease for the quarter ended September 30, 2005, as compared to the same period in 2004, was primarily due to lower pre-tax income.

      The $9 million increase for nine months ended September 30, 2005, as compared to the same period in 2004, was due to a decrease in taxes on pre-tax income of $3 million offset by increases in taxes of $12 million, due primarily from recording prior period adjustments in 2004 and recording taxes for the NDT Funds.

      **Loss from Discontinued Operations, including Loss on Disposal, net of tax**

      On May 27, 2005, Power reached an agreement to sell its Waterford generation facility for approximately $220 million and recognized an estimated loss on disposal of $177 million, net of tax, for the initial write-down of its carrying amount of Waterford to its fair value less cost to sell. On September 28, 2005, Power completed the sale of Waterford and recognized an additional loss of $1 million. The proceeds, together with anticipated reduction in tax liability, are approximately $320 million, which will be used to retire debt at Power. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information.

65

**Energy Holdings**
  **For theQuarters EndedSeptember 30,**         **For theNine MonthsEndedSeptember 30,**          **2005** **2004** **Increase(Decrease)** **%** **2005** **2004** **Increase(Decrease)** **%**      **(Millions)**             **(Millions)**        
Operating Revenues
    $379     $311     $68    22     $1,085     $701     $384    55 
Energy Costs
    $203     $148     $55    37     $552     $242     $310    N/A 
Operation and Maintenance
    $58     $64     $(6)   (9)    $207     $163     $44    27 
Depreciation and Amortization
    $14     $15     $(1)   (7)    $45     $40     $5    13 
Income from Equity Method Investments
    $29     $31     $(2)   (6)    $96     $92     $4    4 
Other Income
    $5     $4     $1    25     $14     $4     $10    N/A 
Other Deductions
    $(9)    $(8)    $1    13     $(12)    $(14)    $(2)   14 
Interest Expense
    $(65)    $(66)    $(1)   (2)    $(193)    $(196)    $(3)   (2)
Income Tax Expense
    $(26)    $(8)    $18    N/A     $(43)    $(34)    $9    26 
Income from Discontinued Operations, including Gain on Disposal, net of tax
    $—     $—     $—    —     $—     $5     $(5)   (100)                                
      The variances in Operating Revenues, Energy Costs, Operation and Maintenance, Depreciation and Amortization 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, increased revenues at TIE in the third quarter of 2005 compared to same period in 2004 due to a stronger market and stronger spark spread (the difference between the market price of electricity and its cost of gas production) and Global's sale of a 35% interest in Dhofar Power through a public offering on the Omani Stock Exchange in April 2005, reducing its ownership interest to 46% and thus accounting for the investment under the equity method of accounting following the sale. For additional information, see Note 3. DiscontinuedOperations, Dispositions and Acquisitions of the Notes.

      **Operating Revenues**

      The $68 million increase for the quarter ended September 30, 2005, as compared to the same period in 2004, was due to higher revenues at Global of $73 million, including a $58 million increase due to higher revenues at TIE related to increased output and higher market prices, a $25 million increase related to Sociedad Austral de Electricidad S.A. (SAESA) in Chile due to higher energy sales volumes offset by a $16 million decrease related to the deconsolidation of Dhofar Power. Offsetting the increase were lower revenues at Resources of $5 million primarily due to a reduction in leveraged lease income related to the termination of the Lovelock LNG leveraged lease in December 2004.

      The $384 million increase for the nine months ended September 30, 2005, as compared to the same period in 2004, was due to higher revenues at Global of $395 million, including a $279 million increase related to the consolidation of TIE commencing July 1, 2004 and $58 million due to higher revenues at TIE in the third quarter of 2005, a $49 million increase related to SAESA due to higher energy sales volumes, a $22 million increase related to Electrownia Skawina S.A. (Skawina) and a $12 million increase related to Global's investment in ELCHO, both due to higher energy sales in the spot market and higher Polish Zloty foreign exchange rates offset by a $28 million decrease related to the deconsolidation of Dhofar Power. Offsetting the increase were lower revenues at Resources of $11 million primarily due to a $22million pre-tax write-off of its UAL Lease investment and a $5 million reduction in leveraged lease income offset by the absence of a $17 million pre-tax charge recorded in 2004 to reduce the carrying value of the Collins lease.

66

      **Operating Expenses**

      ***Energy Costs***

      The $55 million increase for the quarter ended September 30, 2005, as compared to the same period in 2004, was primarily due to a $37 million increase related to TIE due to higher gas prices in 2005 compared to 2004, a $19 million increase related to SAESA due to significant increases in energy costs related to higher sales volumes and a $3 million increase related to Skawina due to higher energy sales in the spot market and higher Polish Zloty foreign exchange rates, offset by a $4 million decrease related to the deconsolidation of Dhofar Power.

      The $310 million increase for the nine months ended September 30, 2005, as compared to the same period in 2004, was primarily due to a $219 million increase related to the consolidation of TIE commencing July 1, 2004, a $37 million increase in energy costs at TIE in the third quarter of 2005, a $40 million increase related to SAESA due to significant increases in energy costs and a $17 million increase related to Skawina due to higher energy sales in the spot market and higher Polish Zloty foreign exchange rates, offset by an $8 million decrease related to the deconsolidation of Dhofar Power.

      ***Operation and Maintenance***

      The $6 million decrease for the quarter ended September 30, 2005, as compared to the same period in 2004, was primarily due to a $3 million decrease in administration and general expenses.

      The $44 million increase for the nine months ended September 30, 2005, as compared to the same period in 2004, was primarily due to a $41 million increase related to the consolidation of TIE commencing July 1, 2004 offset by a $4 million decrease related to the deconsolidation of Dhofar Power.

      ***Depreciation and Amortization***

      The $1 million decrease for the quarter ended September 30, 2005, as compared to the same period in 2004, was primarily due to the deconsolidation of Dhofar Power.

      The $5 million increase for the nine months ended September 30, 2005, as compared to the same period in 2004, was primarily due to a $9 million increase related to the consolidation of TIE commencing July 1, 2004 offset by a $5 million decrease related to the deconsolidation of Dhofar Power.

      **Income from Equity Method Investments**

      The $2 million decrease for the quarter ended September 30, 2005, as compared to the same period in 2004, was primarily due to a $5 million decrease related to the loss of earnings associated with the sale of Global's equity interest in MPC in December 2004 and a $5 million decrease related to Global's investment in Prisma 2000 S.p.A. (Prisma), offset by an $8 million increase due to stronger results in South America.

      The $4 million increase for the nine months ended September 30, 2005, as compared to the same period in 2004, was primarily due to an $11 million increase due to stronger results in South America, the absence of a $3 million loss recognized in the nine months of 2004 from TIE, which was accounted for under the equity method of accounting until July 1, 2004, and a $1 million increase related to the deconsolidation of Dhofar Power, thus accounting for the investment under the equity method of accounting following the sale, offset by an $8 million decrease related to the loss of earnings associated with the sale of Global's equity interest in MPC in December 2004 and a $3 million decrease related to Global's investment in Prisma.

      **Other Income**

      The $1 million increase for the quarter ended September 30, 2005, as compared to the same period in 2004, was primarily due to foreign currency transaction gains.

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      The $10 million increase for the nine months ended September 30, 2005, as compared to the same period in 2004, was primarily due to foreign currency transaction gains of $9 million due to strengthening of the U.S. Dollar relative to the Polish Zloty on Global's investment in ELCHO.

      **Other Deductions**

      The $1 million increase for the quarter ended September 30, 2005, as compared to the same period in 2004, was primarily due to foreign currency transaction losses of $1 million on Global's investment in ELCHO.

      The $2 million decrease for the nine months ended September 30, 2005, as compared to the same period in 2004, was primarily due to the absence of a loss on early extinguishment of debt of $3 million that was recognized in 2004 offset by a $1 million change in derivative fair values.

      **Interest Expense**

      The $1 million and $3 million decrease for the quarter and nine months ended September 30, 2005, respectively, as compared to the same periods in 2004, was primarily due to the deconsolidation of Dhofar Power.

      **Income Taxes**

      The $18 million and $9 million increase for the quarter and nine months ended September 30, 2005, respectively, as compared to the same periods in 2004, was primarily due to the recording of $9 million of U.S. tax associated with repatriation of funds under the American Jobs Creation Act of 2004 and a change in the mix of domestic and international earnings for Global.

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

      See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information.

**Other**

      To supplement the Condensed 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 Quarterly Report.

      ***Global***

      The following table summarizes Global's capital at risk, net contributions to EBIT and non-recourse interest expense in the following regions as of September 30, 2005 and December 31, 2004 and for the quarters and nine months ended September 30, 2005 and 2004.

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          **For the Quarters EndedSeptember 30,** **For the Nine Months EndedSeptember 30,**  **Total Capitalat Risk (A)As of** **EBIT (B)** **Non-RecourseInterest (C)** **EBIT (B)** **Non-RecourseInterest (C)**  **September 30,2005** **December 31,2004** **2005** **2004** **2005** **2004** **2005** **2004** **2005** **2004**  **(Millions)**                                        
**Region:**
                                        
North America
  $467   $427   $51   $27   $6   $7   $119   $91   $16   $7 
South America
   1,635    1,581    40    31    10    4    114    101    28    14 
Europe
   181    209    (2)   5    8    8    34    25    26    24 
India and Oman
   64    94    —    5    —    4    10    15    4    12 
Asia Pacific
   6    6    —    5    —    —    5    13    —    — 
Global G&A—Unallocated
   —    —    (5)   (6)   —    —    (19)   (22)   —    —                                          
Total
  $2,353   $2,317   $84   $67   $24   $23   $263   $223   $74   $57                                          
Total Global EBIT
          $84   $67           $263   $223         
Interest Expense
           (45)   (46)           (133)   (123)        
Income Taxes
           (18)   —            (23)   (19)        
Minority Interest
           1    (1)           (3)   (3)                                                 
Income from Continuing Operations
          $22   $20           $104   $78                                                                                          (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 Tax Expense.(C) Non-Recourse Interest is Interest Expense on debt that is non-recourse to Global.
**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.

**Operating Cash Flows**

      **PSEG**

      For the nine months ended September 30, 2005, PSEG's operating cash flow decreased by approximately $347 million from $1.3 billion to $907 million, as compared to the same period in 2004, due to net decreases from its subsidiaries as discussed below.

      **PSE&G**

      PSE&G's operating cash flow increased approximately $54 million from $410 million to $464 million for the nine months ended September 30, 2005, as compared to the same period in 2004, primarily due to increased customer deposits received from BGS suppliers offset by higher deferred balances due to significantly increased commodity prices.

      **Power**

      Power's operating cash flow decreased approximately $200 million from $488 million to $288 million for the nine months ended September 30, 2005, as compared to the same period in 2004, primarily due to increased margin requirements because of significantly increased commodity prices.

      **Energy Holdings**

      Energy Holdings’ operating cash flow decreased approximately $148 million from $368 million to $220 million for the nine months ended September 30, 2005, as compared to the same period in 2004, due primarily to the absence of tax benefits and payments associated with the termination of certain leases in 2004.

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**Common Stock Dividends**

      Dividend payments on common stock for the quarters ended September 30, 2005 and 2004 were $0.56 and $0.55 per share, respectively, and totaled approximately $134 million and $131 million, respectively. Dividend payments on common stock for the nine months ended September 30, 2005 and 2004 were $1.68 and $1.65 per share, respectively, and totaled approximately $401 million and $391 million, respectively. Future dividends declared will be dependent upon PSEG’s future earnings, cash flows, financial requirements, alternative investment opportunities and other factors. On October 18, 2005, PSEG’ s Board of Directors approved a common stock dividend of $0.56 per share for the third quarter of 2005, reflecting an indicated annual dividend rate of $2.24 per share.

**Short-Term Liquidity**

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

      As of September 30, 2005, PSEG and its subsidiaries had a total of approximately $2.7 billion of committed credit facilities with approximately $1.6 billion of available liquidity under these facilities. In addition, PSEG and PSE&G have access to certain uncommitted credit facilities. As of September 30, 2005, there were no loans outstanding under these uncommitted credit facilities for either PSEG or PSE&G.

      All of the credit facilities below have been modified or structured to accommodate the potential merger with Exelon. Each of the facilities is restricted to availability and use to the specific companies as listed below.
**Company**    **ExpirationDate** **TotalFacility**    **PrimaryPurpose** **Usage as ofSeptember 30,2005** **AvailableLiquidity as ofSeptember 30,2005**  **(Millions)**
**PSEG:**
                
4-year Credit Facility
    April 2008    $450     CP Support/Funding/Lettersof Credit    $187     $263 
5-year Credit Facility
    May 2010    $650     CP Support/Funding/Lettersof Credit    $—     $650 
Uncommitted Bilateral Agreement
    N/A     N/A     Funding    $—      N/A 
**PSE&G:**
                
5-year Credit Facility
    June 2009    $600     CP Support/Funding/Lettersof Credit    $85     $515 
Bilateral Term Loan(A)
    May 2006    $100     Funding    $100     $— 
Uncommitted Bilateral Agreement
    N/A     N/A     Funding    $—      N/A 
**PSEG and Power:**
                
3-year Credit Facility(B)
    April 2007    $600     CP Support/Funding/Lettersof Credit    $567(C)    $33 
**Power:**
                
Bilateral Credit Facility
    March 2010    $100     Funding/Lettersof Credit    $100(C)    $— 
**Energy Holdings:**
                
5-year Credit Facility(D)
    June 2010    $150     Funding/Lettersof Credit    $58(C)    $92                 
(A) Terminated in October 2005.

(B) PSEG/Power co-borrower facility.

(C) These amounts relate to letters of credit outstanding.

(D) Energy Holdings/Global/Resources joint and several co-borrowed facility.

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      **PSEG**

      PSEG believes it has sufficient liquidity to fund its short-term cash needs. On May 31, 2005, PSEG established a new five-year $650 million revolving credit facility that replaced the $280 million credit facility that expired in March 2005 and the $350 million credit facility that was scheduled to expire in December 2005.

      On April 29, 2005, PSEG’s $75 million bilateral term loan facility and $25 million bilateral revolver facility expired.

      **PSE&G**

      PSE&G believes it has sufficient liquidity to fund its short-term cash needs. In May 2005, PSE&G entered into a bilateral agreement for a $100 million term loan. PSE&G terminated this agreement in October 2005.

      **Power**

      As of September 30, 2005, Power had loaned $62 million of excess cash to PSEG.

      On August 31, 2005, Power’s $25 million credit facility expired.

      During the  nine months ended September 30, 2005, the increase in commodity prices has reduced  available liquidity as Power was required to post additional margin for sales  contracts entered into in the normal course of business. Should commodity prices  continue to rise, additional margin calls may be necessary relative to existing  power sales contracts. As these contract obligations are fulfilled, liquidity  requirements are reduced. With the addition of the PSEG and Power joint and  several facilities listed below, Power believes that it has sufficient liquidity  to fund its short-term cash needs.

      In addition,  ER&T maintains agreements that require Power, as its guarantor under performance  guarantees, to satisfy certain creditworthiness standards. Many of these agreements  allow the counterparty to demand that ER&T provide performance assurance,  generally in the form of a letter of credit or cash, in the event of a downgrade  of Power’s credit rating to below investment grade. While Power believes  that a downgrade to below investment grade is unlikely, management believes  that Power could meet collateral requirements with current credit facilities,  including the new credit agreements listed below, and its ability to access  additional sources of liquidity through bank lending and/or capital market transactions.  See Note 5. Commitments and Contingent Liabilities of the Notes for further  information.

      **PSEG and Power**

In October 2005, PSEG and Power entered into the following credit agreements:
      **ExpirationDate** **TotalFacility**    **PrimaryPurpose**   **(Millions)**      
**PSEG**
              
Bilateral Credit Agreement
    May 2006    $100     Funding/Letters of Credit      
**PSEG and Power (A)**
              
Bilateral Credit Agreement
    April 2006    $100     Funding/Letters of Credit      
Bilateral Credit Agreement
    July 2006    $100     Funding/Letters of Credit      
Bilateral Credit Agreement
    October 2006    $200     Letters of Credit              
(A) PSEG/Power co-borrower facility

      **Energy Holdings**

      As of September 30, 2005, Energy Holdings had loaned $61 million of excess cash to PSEG. In addition, Energy Holdings and its subsidiaries had $256 million in cash, including $192 million invested

71

offshore. See Note 2. Recent Accounting  Standards of the Notes regarding repatriation of certain portions of these funds  in October 2005.

      On June 30, 2005, Energy Holdings entered into a $150 million five-year bank revolving credit agreement. This bank revolving credit agreement replaced a $200 million three-year bank revolving credit agreement that was scheduled to expire in October 2006.

**External Financings**

      **PSEG**

      For the nine months ended September 30, 2005, PSEG issued approximately 929,000 shares under its Dividend Reinvestment Program and Employee Stock Purchase Plan for approximately $55 million.

      On August 8, 2005, the 6.25% trust preferred securities that were issued in November 2002 in connection with PSEG’s Participating Units (PEPS) were remarketed. The PEPS consist of a forward purchase contract for PSEG common stock and a trust preferred security. The remarketing reset the coupon on the trust preferred security to 5.381%, which will mature in November 2007. The PEPS investors will use the proceeds from the remarketing as collateral to be used for settling the forward purchase contract on November 16, 2005. Upon settlement, PSEG will receive cash proceeds of approximately $460 million and issue 11.4 million shares of common stock assuming its stock price is above $40.248 per share**.**

      In September  2005, PSEG issued $375 million of floating rate senior unsecured debt due in  2008, callable at par after one-year. The proceeds were used to redeem PSEG’s  subordinated debt underlying $225 million of Enterprise Capital Trust I, 7.44%  Series A and $150 million of Enterprise Capital Trust III, 7.25% Series C Preferred  Securities in October 2005.

      **PSE&G**

      In September 2005, PSE&G Transition Funding II LLC (Transition Funding II) issued approximately $103 million of its Transition Bonds, Series 2005-1, in four classes. Proceeds were used to purchase from PSE&G the rights to collect a transition bond charge from electric customers pursuant to a BPU order. PSE&G used those proceeds to reduce short-term debt.

      In July 2005, PSE&G issued $250 million of its 5.25% Secured Medium-Term Notes Series D due 2035. The proceeds were used to redeem $125 million of PSE&G’s First and Refunding Mortgage Bonds, 9.125% Series BB due July 2005 and to reduce short-term debt.

      For the nine months ended September 30, 2005, PSE&G Transition Funding LLC (Transition Funding) repaid approximately $105 million of its transition bonds.

      **Energy Holdings**

      During 2005, Energy Holdings made cash distributions to PSEG totaling $287 million, including a $100 million return of capital in February 2005, a $184 million preference unit redemption in May 2005 and $3 million of preference unit distributions.

**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

72

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 Financial Accounting Standards Board Interpretation No. 46, “Consolidation of Variable Interest Entities”, is not included as debt when calculating these ratios, as provided for in the various credit agreements. As discussed previously, the rise in commodity prices has increased margin requirements and has resulted in increased Accumulated Other Comprehensive Loss (OCL), which reduces total equity. This has resulted in increases to the debt to capitalization ratios at PSEG and Power. These ratios could be further increased due to additional OCL resulting from the potential need to recognize an additional minimum pension liability(see Other Comprehensive Loss below), however, PSEG, PSE&G, Power and Energy Holdings expect to continue to meet the financial covenant requirements, discussed below.

      **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 September 30, 2005, PSEG’s ratio of debt to capitalization (as defined above) was 60.3%.

      **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 September 30, 2005, PSE&G’s ratio of long-term debt to total capitalization (as defined above) was 48.4%.

      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 September 30, 2005, PSE&G’s Mortgage coverage ratio was 4.96 to 1 and the Mortgage would permit up to approximately $1.7 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. This facility has a 70% debt to total capitalization covenant for PSEG (see definition under PSEG financial covenants) and a 65% debt to total capitalization covenant for Power. For the purposes of calculating the Power ratio, debt (including loans, certain letters of credit and similar instruments) to total capitalization, adjusted for the $986 million Basis Adjustment (see Condensed 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 September 30, 2005, Power’s ratio of debt to capitalization (as defined above) was 51.6%.

      **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

73

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 $150 million five-year bank revolving credit agreement in June 2005 with a covenant requiring the ratio of Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) to fixed charges to be greater than 1.75. This bank revolving credit agreement replaced a $200 million three-year bank revolving credit agreement that was entered into in October 2003. As of September 30, 2005, Energy Holdings’ coverage of this covenant was 2.77. Additionally, Energy Holdings must maintain a ratio of net debt to EBITDA of less than 5.25. As of September 30, 2005, Energy Holdings’ ratio under this covenant was 4.02. 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 ofEnergy Holdings’ membership interest in Global, restrictions on the use of proceeds related to material sales of assets and the satisfaction of certain financial covenants. Net 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. Net cash proceeds from asset sales during any 12-month period in excess of 10% of total assets must be retained by Energy Holdings or used to repay the debt of Energy Holdings, Global or Resources.

**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 byan agency should 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      
Senior Unsecured Debt
    Baa2    BBB–(WD)    BBB (P)      
**PSE&G:**
            
Mortgage Bonds
    A3    A–(WD)    A      
Preferred Securities
    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.
* *

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      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**

      **PSEG, Power and Energy Holdings**

      For the nine months ended September 30, 2005, PSEG, Power and Energy Holdings had an Other Comprehensive Loss/(Gain) of $316 million, $395 million and $(81) million, respectively, due primarily to net unrealized losses on derivatives accounted for as hedges in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (SFAS 133), unrealized gains and losses in the NDT Funds at Power and foreign currency translation adjustments at Energy Holdings.

      During the nine months ended September 30, 2005, Power's OCL has increased from $49 million to $444 million. The primary cause was an increase of approximately $370 million related to the change in market value, net of taxes, of energy and related contracts that qualify for hedge accounting that were previously entered into by Power in the normal course of business. During the nine months ended September 30, 2005, the increase in gas and electric prices has resulted in unrealized losses on many of those contracts, which are recorded in OCL as a reduction to equity.

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

      ***Minimum  Pension Liability***

       Due  to the potential for a lower required discount rate and reduced earnings on  the pension plan investments through September 30, 2005, PSEG, PSE&G,  Power and Energy Holdings may be required to record a minimum pension liability  on their respective Consolidated Balance Sheets as of December 31, 2005. As  calculated under SFAS No. 87 “Employers Accounting for Pensions”,  a minimum pension liability exists and must be recorded when the accumulated  benefit obligation (ABO) of the plan exceeds the fair value of the plan assets  as of its annual measurement date. The minimum pension liability is reduced  or reversed when funding occurs, or when the fair value of the pension plan  assets grow to a level above that of the ABO. At this time, PSEG is monitoring  the fair market value of its investments and its ABO and is evaluating options  available with respect to this issue. Since PSEG's measurement date is December 31,  2005, management is unable to predict what the impact could be, however the  impact could be material to PSEG's, PSE&G's, Power's and Energy  Holdings' financial position and, more specifically, could result in a decrease  in equity since a majority of the offset to the minimum pension liability would  be recorded in OCL.

**CAPITAL REQUIREMENTS**

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

      It is expected that the majority of funding for capital requirements of PSE&G, Power and Energy Holdings will come from their respective internally generated funds. The balance will be provided by the issuance of debt at the respective subsidiary or project level and, for PSE&G and Power, equity contributions from PSEG. PSEG does not expect to contribute any additional equity to Energy Holdings. Projected construction and investment expenditures approved in the current business plans for PSEG, PSE&G, Power and Energy Holdings are consistent with amounts disclosed in the Annual

75

Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31, 2004.

      **PSE&G**

      During the nine months ended September 30, 2005, PSE&G made approximately $372 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $372 million excludes approximately $25 million spent on cost of removal, net of salvage.

      **Power**

      During the nine months ended September 30, 2005, Power made approximately $290 million of capital expenditures (excluding $55 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.

      **Energy Holdings**

      During the nine months ended September 30, 2005, Energy Holdings incurred approximately $26 million of capital expenditures, primarily related to capital projects at SAESA, Dhofar Power and Skawina.

**ACCOUNTING MATTERS**

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

      For information related to recent accounting matters, see Note 2. Recent Accounting Standards of the Notes.

**ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURESABOUT 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 Condensed 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.

      Except as discussed below, there were no material changes from the disclosures in the Annual Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31, 2004 or Quarterly Reports on Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005.

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**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 Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted (SFAS 133), its amendments and related guidance. Changes in the fair value of qualifying cash flow hedge transactions are recorded in Accumulated Other Comprehensive Income (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.

      Many non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133 and are accounted for upon settlement.

      ***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, which have significantly decreased. 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.

      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 its hedges. Non-trading mark-to-market (MTM) VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The MTM derivatives that are not hedges are included in the trading VaR. The trading VaR and Non-Trading MTM VaR are presented in the table below.

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      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 MTM 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 September 30, 2005 and December 31, 2004, trading VaR was approximately $1 million and $2 million, respectively.
  **Trading VaR** **Non-TradingMTM VaR**  **(Millions)**
**For the Quarter Ended September 30, 2005**
        
*95% Confidence Level, One-Day Holding Period, One-Tailed:*
        
Period End
    $1     $60 
Average for the Period
    $1     $42 
High
    $3     $84 
Low
    $—     $17 
*99% Confidence Level, One-Day Holding Period, Two-Tailed:*
        
Period End
    $1     $92 
Average for the Period
    $2     $65 
High
    $4     $130 
Low
    $1     $27         
**Credit Risk**

      **Energy Holdings**

      As of September 30, 2005, Resources has a remaining gross investment in four leased aircraft of approximately $36 million. On September 14, 2005, Delta Airlines (Delta) and Northwest Airlines (Northwest), the lessees for Resources’ four remaining aircraft, filed for Chapter 11 bankruptcy protection. Energy Holdings continues to believe that it will be able to fully recover its investments in these aircraft.

**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 6. 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 Condensed Consolidated Statement of Operations for the quarter ended September 30, 2005. 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, MTM 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 MTM activities reported here are those relating to changes in fair value due to external movement in prices.

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**Operating RevenuesFor the Quarter Ended September 30, 2005**
  **NormalOperations andHedging (A)** **Trading** **Total**  **(Millions)**            
**Mark-to-Market Activities:**
            
Unrealized Mark-to-Market Gains (Losses)
            
Changes in Fair Value of Open Positions
    $20     $(15)    $5 
Origination Unrealized Gain at Inception
     —      —      — 
Changes in Valuation Techniques and Assumptions
     —      —      — 
Realization at Settlement of Contracts
     (30)     12      (18)                   
Total Change in Unrealized Fair Value
     (10)     (3)     (13)
Realized Net Settlement of Transactions Subject to Mark-to-Market
     30      (12)     18 
Broker Fees and Other Related Expenses
     —      (2)     (2)                   
Net Mark-to-Market Gains (Losses)
     20      (17)     3 
**Accrual Activities**
            
Accrual Activities—Revenue, Including Hedge Reclassifications
     1,441      —      1,441                    
**Total Operating Revenues**
    $1,461     $(17)    $1,444                                
**Operating RevenuesFor the Nine Months Ended September 30, 2005**
  **NormalOperations andHedging (A)** **Trading** **Total**  **(Millions)**            
**Mark-to-Market Activities:**
            
Unrealized Mark-to-Market Gains (Losses)
            
Changes in Fair Value of Open Positions
    $57     $(2)    $55 
Origination Unrealized Gain at Inception
     —      —      — 
Changes in Valuation Techniques and Assumptions
     —      —      — 
Realization at Settlement of Contracts
     (48)     (16)     (64)                   
Total Change in Unrealized Fair Value
     9      (18)     (9)
Realized Net Settlement of Transactions Subject to Mark-to-Market
     48      16      64 
Broker Fees and Other Related Expenses
     —      (6)     (6)                   
Net Mark-to-Market Gains (Losses)
     57      (8)     49 
**Accrual Activities**
            
Accrual Activities—Revenue, Including Hedge Reclassifications
     4,185      —      4,185                    
**Total Operating Revenues**
    $4,242     $(8)    $4,234                                (A) Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply, all asset-backed transactions 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 asset-backed transactions 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 Condensed Consolidated Balance Sheets since balances with many counterparties are subject to offset and are shown net on the Condensed Consolidated Balance Sheets regardless of the portfolio in which they are included.

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**Energy Contract Net Assets/LiabilitiesAs of September 30, 2005**
  **NormalOperationsandHedging** **Trading** **Total**  **(Millions)**
Mark-to-Market Energy Assets
            
Current Assets
    $611     $218     $829 
Noncurrent Assets
     65      24      89                    
Total Mark-to-Market Energy Assets
    $676     $242     $918                    
Mark-to-Market Energy Liabilities
            
Current Liabilities
    $(611)    $(228)    $(839)
Noncurrent Liabilities
     (479)     (29)     (508)                   
Total Mark-to-Market Energy Liabilities
    $(1,090)    $(257)    $(1,347)                   
**Total Mark-to-Market Energy Contract Net Liabilities**
    $(414)    $(15)    $(429)                               
      The following table presents the maturity of net fair value of MTM energy trading contracts.

**Maturity of Net Fair Value of Mark-to-Market Energy Trading ContractsAs of September 30, 2005**
  **Maturities within**  **2005** **2006** **2007** **2008-2009** **Total**  **(Millions)**
Trading
    $(13)    $1     $(5)    $2     $(15)
Normal Operations and Hedging
     82      (102)     (263)     (131)     (414)                               
**Total Net Unrealized Losses on Mark-to-Market Contracts**
    $69     $(101)    $(268)    $(129)    $(429)                                                   
      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 (OCL), 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 tobe reclassified out of OCL and into earnings over the next 12 months.

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**Cash Flow Hedges Included in Accumulated Other Comprehensive LossAs of September 30, 2005**
  **AccumulatedOtherComprehensiveLoss** **Portion Expectedto be Reclassifiedin next 12 months**  **(Millions)**
**Cash Flow Hedges Included in Accumulated Other Comprehensive Loss**
        
Commodities
    $(518)    $(263)
Interest Rates
     (66)     (22)
Foreign Currency
     —      —              
**Net Cash Flow Hedge Loss Included in Accumulated Other Comprehensive Loss**
    $(584)    $(285)                     
      **Power**

      ***Credit Risk***

      The following table provides information on Power’s credit exposure, net of collateral, as of September 30, 2005. 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 September 30, 2005**
**Rating** **CurrentExposure** **SecuritiesHeld asCollateral** **NetExposure** **Number ofCounterparties>10%** **NetExposure ofCounterparties>10%**      **(Millions)**         **(Millions)**                    
Investment Grade—External Rating
    $526     $89     $505    1   $79 
Non-Investment Grade—External Rating
     109      55      65    —    — 
Investment Grade—No External Rating
     2      —      1    —    — 
Non-Investment Grade—No External Rating
     43      —      43    —    —                            
Total
    $680     $144     $614    1   $79                                                
      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. Net exposure to non-investment grade companies is primarily to coal and other fuel suppliers. Counterparties for whom there is no external rating include privately held companies, foreign entities and municipal utilities. These entities are rated by PSEG using an internal model.

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**ITEM 4. CONTROLS AND PROCEDURES**

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

      **Disclosure Controls and Procedures**

      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 September 30, 2005 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 quarterly reports.

      **Internal Controls**

      During the third quarter of 2005, PSEG, PSE&G, Power and Energy Holdings each made enhancements to internal controls. These enhancements, which will improve the design and operational effectiveness of control processes for financial reporting, included significant changes to internal controls including enhanced policies and procedures in the wholesale energy transacting processes.

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**PART II. OTHER INFORMATION**

**ITEM 1. LEGAL PROCEEDINGS**

      Certain information reported under Item 3 of Part I of the 2004 Annual Report on Form 10-K and under Item 1 of Part II of the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005 is updated below.

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

      In addition, 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 26. (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.      
(2)
    Page 27. (PSE&G) PSE&G's MGP Remediation Program instituted by NJDEP's Coal Gasification Facility Sites letter dated March 25, 1988.      
(3)
    Page 31. (Power) Filing of Complaint by Nuclear against the DOE on September 26, 2001 in the U.S. Court of Federal Claims, Docket No. 01-0551C seeking damages caused by DOE's failure to take possession of spent nuclear fuel. The complaint was amended to include PSE&G as a prior owner in interest.      
(4)
    Page 33. (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.      
(5)
    Page 34. (Energy Holdings) DRF Porto Alegre RS claim for past due taxes at RGE. Case No. 2004-47.      
(6)
    Page 35. (Energy Holdings) Peru's Internal Revenue Agency's (SUNAT) claim for past due taxes at LDS, Resolution No. 0150150000030, dated July 10, 2003.      
(7)
    Page 35. (Energy Holdings) SUNAT's claim for past due taxes at Electroandes. Resolution No. 012-003-0007374.      
(8)
    Page 35. (Energy Holdings) Dhofar Power Company SAOC v. Ministry of Housing, Electricity and Water (Sultanate of Oman), ICC Reference EXP/233.      
(9)
    Page 36. (Energy Holdings) Utility Choice L.P. and Cirro Group, Inc. v. TXU Corp. d/b/a TXM Energy, et al. Civic Action No. 4:05-cv-00573.      
(10)
    Page 84. (Power) PJM Interconnection L.L.C. filing with the FERC on November 2, 2004, Docket No. EL03-236-003 to amend Tariff and Operating Agreement to request Reliability Must-Run (RMR) compensation.      
(11)
    Page 85. (PSEG, PSE&G and Power) PJM Reliability Pricing Model filed with FERC on August 31, 2005, Docket Nos. ER05-1410-000 and EL05-148-000.      
(12)
    Page 85 (PSEG, PSE&G and Power) PPL v. Exelon Corporation v. PPL Electric Utilities Corporation (PPL) et al., Settlement filed with FERC on September 14, 2005, Docket No. EL05-49-000.      
(13)
    Page 85 (PSEG, PSE&G and Power) Notice of Inquiry issued by FERC on September 16, 2005 to prevent undue discrimination and preference in the provisions of transmission service. Docket No. RM05-25-000.      
(14)
    Page 86 (PSEG and PSE&G) BPU proceeding on August 1, 2005 relating to ratepayer protections due to repeal of PUHCA under the Energy Policy Act of 2005. Docket No. AX05070641.      
(15)
    Page 86 (PSE&G) PSE&G Petition for increase of gas base rates filed with BPU on September 30, 2005. Docket No. GR05100845.
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**ITEM 5. OTHER INFORMATION**

      Certain information reported under the 2004 Annual Report on Form 10-K and the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005 are updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2004 Annual Report on Form 10-K and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005. References are to the related pages on the Form 10-K and Forms 10-Q as printed and distributed.

**Federal Regulation**

      **PSEG**

      ***ReliabilityFirst***

      On September 27, 2005, PSEG submitted an application to join ReliabilityFirst, a reliability organization that is seeking to consolidate certain independent regional reliability councils that currently promote the reliability of the electric system throughout the Mid-Atlantic and Central United States. Pursuant to the Energy Policy Act of 2005, which became law on August 8, 2005, FERC now possesses the authority to empower such an organization to propose and enforce reliability standards, and issued a Notice of Proposed Rulemaking in this regard on September 15, 2005. When FERC designates ReliabilityFirst as such an Electric Reliability Organization, PSEG may be subject to additional regulation.

      **Power**

      ***Reliability Must-Run (RMR) Status in PJM***

      ***2004 Form 10-K, Page 16, March 31, 2005 Form 10-Q, Page 70 and June 30, 2005 Form 10-Q, Page 81.*** 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 February 24, 2005, Power requested that the FERC approve such cost-of-service rate treatment for the Sewaren 1, 2, 3 and 4 and Hudson 1 units. If approved, the rates would provide approximately $23 million and $17 million of annual revenues for the Sewaren and Hudson units, respectively, plus reimbursements of Power's expenditures in connection with certain construction at the units that are necessary to maintain reliability, offsetby certain revenues earned in PJM's energy market.

      On April 25, 2005, the FERC issued an order accepting the February 24, 2005 filing, subject to refund and hearing, effective February 24, 2005, but establishing settlement procedures and a hearing on certain issues. Effective February 24, 2005, subject to refund and hearing, Power began to collect a monthly fixed payment of $3.3 million, net of operating margins at the units. On August 9, 2005, the parties reached a settlement in principle of the issues that FERC set for hearing. A detailed settlement was filed with FERC on September 23, 2005, which will be subject to FERC review. The settlement permits Power to recover annual fixed costs of approximately $19 million and $14.5 million for the Sewaren and Hudson units, respectively, plus reimbursements of Power's expenditures in connection withcertain construction at the units that are necessary to maintain reliability, offset by certain revenues earned in PJM's energy market.

      ***Market Power***

      ***2004 Form 10-K, Page 17 and June 30, 2005 Form 10-Q, page 82.***On July 5, 2005, FERC issued an order accepting the updated market power analysis that PSEG Lawrenceburg submitted on August 30, 2004, as supplemented on February 7, 2005 and February 15, 2005. FERC's acceptance allows the Lawrenceburg facility to continue to sell wholesale power at market-based rates. FERC's order requires Lawrenceburg to file a revised market power analysis within 30 days of the pending merger with Exelon and to treat Exelon as an affiliate for purposes of Exelon's market-based rate codes of conduct, which are on file with FERC to guard against cross-subsidization between business units. The order also requires Lawrenceburg to file an additional compliance filingwithin 30 days of the order

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to revise their codes of conduct to state that they cannot sell power to affiliates without first receiving FERC authorization to do so. Lawrenceburg made the required filing on August 2, 2005, and FERC accepted this filing on September 15, 2005.

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

      ***PJM Reliability Pricing Model (RPM)***

      On August 31, 2005, PJM filed its RPM with FERC. The RPM constitutes a locational installed capacity market design for the PJM region, including a forward auction for installed capacity priced according to a downward-sloping demand curve and a transitional implementation of the market design. PJM requested that FERC issue an order on the proposal by January 1, 2006 in order to permit implementation of the RPM by June 1, 2006. Comments, interventions and protests of the filing were due to FERC by October 19, 2005. PSE&G and Power filed comments generally supporting the RPM and requesting limited modifications in specific areas. Numerous other parties filed comments and protests. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding.

      ***Settlement of Exelon Corporation (Exelon) v. PPL Electric Utilities Corporation (PPL) et al.***

      On September 14, 2005, Exelon and PPL filed with FERC an offer of settlement regarding a dispute that arose in 2004 regarding an error by PJM that incorrectly charged Exelon for transmission congestion charges that PJM should have attributed to PPL. The settlement requires PPL to pay Exelon $33 million and allocates the remaining $8 million to all PJM members. Comments, interventions and protests regarding the settlement were due to FERC by October 4, 2005. Several parties, including PSE&G and Power, protested the settlement, which is currently pending before FERC. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding.

      ***FERC Order No. 888***

      On September 16, 2005, FERC issued a Notice of Inquiry seeking comments on whether reforms are needed to the protections that FERC established in its Order No. 888 in order to prevent undue discrimination and preference in the provision of transmission service. If FERC ultimately adopts structural remedies such as further separating the ownership of generation and transmission, PSEG, PSE&G and Power's results of operations could be negatively affected.

      ***PJM Long-Term Transmission Rate Design***

      ***June 30, 2005 Form 10-Q, Page 83.***On May 31, 2005, FERC issued an order addressing the recovery of costs for transmission upgrades designated through PJM's Regional Transmission Expansion Plan (RTEP) process. Among other matters, FERC's order responded to a proposal to continue PJM's current zonal rate design. FERC concluded that the existing rate design may not be just and reasonable, and established a hearing to examine the justness and reasonableness of continuing PJM's modified zonal rate design. Under the schedule for this proceeding, which was adopted by the Presiding Administrative Law Judge following a prehearing conference on June 23, 2005, this hearing will commence in April 2006. The May 31, 2005 order also accepts the tariff sheets filed by certainPJM transmission owners to establish the general procedures for filing to recover the costs incurred under the RTEP process, subject to further compliance filings. In accordance with the schedule for this proceeding, certain entities filed proposals with FERC on September 30, 2005 for alternative rate designs for the PJM region. If FERC adopts one or a combination of these alternatives, PSEG, PSE&G, or Power's results of operations could be negatively affected. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding.

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**State Regulation**

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

      ***Ratepayer Protection***

      On August 1, 2005, the BPU initiated a new proceeding to consider whether ratepayer protections are necessary in light of the repeal of Public Utility Holding Company Act of 1935, as amended (PUHCA) under the Energy Policy Act of 2005, which became law on August 8, 2005. In its order, the BPU requested information from each New Jersey public utility regarding its financial and organizational structure, and the BPU indicated that it was in the process of preparing a formal rulemaking recommendation to address these issues. On October 7, 2005, the BPU initiated an informal stakeholder process in this proceeding and requested comments from New Jersey's public utilities regarding the BPU's access to utility records, limits on utility diversification, restrictions on the transfer of capital by utilities to their corporateparents or affiliates, affiliate transactions, and the prevention of cross-subsidization. If the BPU ultimately adopts additional ratepayer protections, PSEG's and PSE&G's results of operations could be negatively affected. PSEG, PSE&G, Power and Energy Holdings are not able to predict the outcome of this proceeding at this time.

      **PSE&G**

      ***Remediation Adjustment Clause (RAC) Filing***

      ***2004  Form 10-K, Page 21 and March 31, 2005 Form 10-Q, Page 72.***On  April 25, 2005, PSE&G filed its RAC-12 filing with the BPU to recover  approximately $18 million of remediation program expenditures for the period  from August 1, 2003 through July 31, 2004. PSE&G believes that its expenditures  for RAC-12 were reasonable and that its current rates should be continued  to recover the RAC-12 costs. On October 6, 2005 PSE&G signed a settlement  agreement with the Ratepayer Advocate and the BPU. The settlement agreement,  which provides for PSE&G to recover substantially all of the $18 million  requested, is now awaiting approval from the Administrative Law Judge (ALJ).  A BPU order approving the settlement is expected shortly thereafter.

      ***Gas Base Rate Case***

On September 30, 2005, PSE&G filed a petition with the BPU seeking an overall 3.78% increase in its gas base rates to cover the cost of gas delivery to be effective June 30, 2006.Approximately $55 million of the $132.8 million request is for an increase in book depreciation rates. The balance of the request will cover increased plant investment, higher operating expenses and provide an 11% return on equity. PSE&G's current gas base rates have been in effect since January 2002.

**Environmental Matters**

      **Power**

      ***Carbon Dioxide (CO****2****) Emissions***

      ***2004 Form 10-K, Page 25.***The environmental and regulatory staff members from the nine states in the Northeast that are participating in the Regional Greenhouse Gas Initiative (RGGI), including New Jersey, New York and Connecticut, issued a proposal in August 2005 that would cap CO2 emissions from electric generating units greater than 25 megawatts in the states participating in RGGI. The RGGI proposal also features a multi-state cap-and-trade program with market-based emissions trading. The proposal is currently being evaluated by each of the states' environmental and utility commissions for possible implementation. The Governor of New Jersey, referencing the state's participation inRGGI, executed new regulations in October 2005 that designate CO2 as an air contaminant potentially subject to regulation. The ultimate outcome of this initiative, and its impact on Power, if any, cannot be determined at this time.

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**ITEM 6. EXHIBITS**

**A listing of exhibits being filed with this document is as follows:**

      a. PSEG:

                Exhibit 12: Computation of Ratios of Earnings to Fixed Charges

                Exhibit 31: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

                Exhibit 31.1: Certification by Thomas M. O'Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

                Exhibit 32: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

                Exhibit 32.1: 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 12.1: Computation of Ratios of Earnings to Fixed Charges

                Exhibit 12.2: Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements

                Exhibit 31.2: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

                Exhibit 31.3: Certification by Robert E. Busch Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

                Exhibit 32.2: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

                Exhibit 32.3: Certification by Robert E. Busch Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

      c. Power:

                Exhibit 12.3: Computation of Ratios of Earnings to Fixed Charges

                Exhibit 31.4: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

                Exhibit 31.5: Certification by Thomas M. O'Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

                Exhibit 32.4: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

                Exhibit 32.5: 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 12.4: Computation of Ratios of Earnings to Fixed Charges

                Exhibit 31.6: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

                Exhibit 31.7: Certification by Thomas M. O'Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

                Exhibit 32.6: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

                Exhibit 32.7: 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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**SIGNATURE**

      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**(Registrant)                   By:       /s/ PATRICIA A. RADO      Patricia A. RadoVice President and Controller(Principal Accounting Officer)  
Date: October 28, 2005

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**SIGNATURE**

      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 ELECTRIC AND GAS COMPANY**(Registrant)                   By:       /s/ PATRICIA A. RADO      Patricia A. RadoVice President and Controller(Principal Accounting Officer)  
Date: October 28, 2005

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**SIGNATURE**

      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**(Registrant)                   By:       /s/ PATRICIA A. RADO      Patricia A. RadoVice President and Controller(Principal Accounting Officer)  
Date: October 28, 2005

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**SIGNATURE**

      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 L.L.C.**(Registrant)                   By:       /s/ PATRICIA A. RADO      Patricia A. RadoController(Principal Accounting Officer)  
Date: October 28, 2005

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