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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 JUNE 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 July 27, 2005, Public Service Enterprise Group Incorporated had outstanding 239,023,863 shares of its sole class of Common Stock, without par value.

      As of July 27, 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     25                     Note 6. Risk Management     36                     Note 7. Comprehensive Income (Loss), Net of Tax     40                     Note 8. Changes in Capitalization     40                     Note 9. Other Income and Deductions     41                     Note 10. Income Taxes     42                     Note 11. Financial Information by Business Segments     44                     Note 12. Related-Party Transactions     45                     Note 13. Guarantees of Debt     48 Item 2.    Management's Discussion and Analysis of Financial Condition and Results of      Operations (MD&A)     51               Pending Merger     51               Overview     52               Results of Operations     56               Liquidity and Capital Resources     65               Capital Requirements     71               Accounting Matters     71 Item 3.    Qualitative and Quantitative Disclosures About Market Risk     71 Item 4.    Controls and Procedures     78 **PART II. OTHER INFORMATION**    Item 1.    Legal Proceedings     79 Item 4.    Submission of Matters to a Vote of Security Holders     80 Item 5.    Other Information     81 Item 6.    Exhibits     86 Signatures     87 
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 “will,” “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-lookingstatements. Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings 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**
•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 credit markets and maintain adequate credit ratings; •adverse or unanticipated weather conditions that significantly impact costs and/or operations, including generation; •changes in the electric industry, including changes to power pools; •changes in the number of market participants and the risk profiles of such participants; •changes in technology that 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 QuartersEndedJune 30,** **For The Six MonthsEndedJune 30,**  **2005** **2004** **2005** **2004**  **(Millions, except for share data)(Unaudited)**
OPERATING REVENUES
    $2,442     $2,285     $5,751     $5,513 
OPERATING EXPENSES
                
Energy Costs
     1,340      1,250      3,214      3,080 
Operation and Maintenance
     578      534      1,174      1,077 
Depreciation and Amortization
     179      167      365      335 
Taxes Other Than Income Taxes
     28      28      71      73                          
Total Operating Expenses
     2,125      1,979      4,824      4,565                          
Income from Equity Method Investments
     30      33      67      61                          
OPERATING INCOME
     347      339      994      1,009 
Other Income
     41      80      84      111 
Other Deductions
     (21)     (26)     (37)     (44)
Interest Expense
     (206)     (208)     (415)     (420)
Preferred Stock Dividends
     (1)     (1)     (2)     (2)                         
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
     160      184      624      654 
Income Tax Expense
     (59)     (57)     (231)     (245)                         
INCOME FROM CONTINUING OPERATIONS
     101      127      393      409 
Loss from Discontinued Operations, including Loss on Disposal, net of tax benefit of $127, $5, $132 and $13 for the quarter and six months ended 2005 and 2004, respectively
     (183)     (3)     (190)     (14)                         
NET (LOSS) INCOME
    $(82)    $124     $203     $395                          
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
                
BASIC
     238,732      236,705      238,524      236,449                          
DILUTED
     243,019      238,001      242,632      238,321                          
EARNINGS PER SHARE:
                
BASIC
                
INCOME FROM CONTINUING OPERATIONS
    $0.42     $0.53     $1.65     $1.73 
NET (LOSS) INCOME
    $(0.34)    $0.52     $0.85     $1.67                          
DILUTED
                
INCOME FROM CONTINUING OPERATIONS
    $0.42     $0.53     $1.62     $1.72 
NET (LOSS) INCOME
    $(0.34)    $0.52     $0.84     $1.66                                          
See Notes to Condensed Consolidated Financial Statements.

1

**PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONDENSED CONSOLIDATED BALANCE SHEETS**
  **June 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**ASSETS**
        
CURRENT ASSETS
        
Cash and Cash Equivalents
    $294     $279 
Accounts Receivable, net of allowances of $37 and $35 in 2005 and 2004, respectively
     1,355      1,621 
Unbilled Revenues
     218      340 
Fuel
     517      633 
Materials and Supplies
     265      255 
Energy Trading Contracts
     198      161 
Prepayments
     338      122 
Restricted Funds
     37      50 
Assets of Discontinued Operations
     220      511 
Other
     61      203              
Total Current Assets
     3,503      4,175              
PROPERTY, PLANT AND EQUIPMENT
     18,727      18,620 
Less: Accumulated Depreciation and Amortization
     (5,455)     (5,355)             
Net Property, Plant and Equipment
     13,272      13,265              
NONCURRENT ASSETS
        
Regulatory Assets
     4,961      5,127 
Long-Term Investments
     4,234      4,181 
Nuclear Decommissioning Trust (NDT) Funds
     1,098      1,086 
Other Special Funds
     535      488 
Goodwill and Other Intangibles
     616      630 
Other
     254      292              
Total Noncurrent Assets
     11,698      11,804              
TOTAL ASSETS
    $28,473     $29,244                      
See Notes to Condensed Consolidated Financial Statements.

2

**PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONDENSED CONSOLIDATED BALANCE SHEETS**
  **June 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**LIABILITIES AND CAPITALIZATION**
        
CURRENT LIABILITIES
        
Long-Term Debt Due Within One Year
    $1,198     $386 
Commercial Paper and Loans
     731      638 
Accounts Payable
     977      1,362 
Derivative Contracts
     238      207 
Energy Trading Contracts
     96      125 
Accrued Interest
     147      154 
Accrued Taxes
     95      54 
Clean Energy Program
     89      82 
Other
     472      484              
Total Current Liabilities
     4,043      3,492              
NONCURRENT LIABILITIES
        
Deferred Income Taxes and Investment Tax Credits (ITC)
     4,221      4,350 
Regulatory Liabilities
     585      545 
Nuclear Decommissioning Liabilities
     324      310 
Other Postretirement Benefit (OPEB) Costs
     587      563 
Clean Energy Program
     280      324 
Environmental Costs
     343      366 
Other
     611      545              
Total Noncurrent Liabilities
     6,951      7,003              
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
        
CAPITALIZATION
        
LONG-TERM DEBT
        
Long-Term Debt
     7,587      8,414 
Securitization Debt
     1,868      1,939 
Project Level, Non-Recourse Debt
     1,166      1,371 
Debt Supporting Trust Preferred Securities
     1,201      1,201              
Total Long-Term Debt
     11,822      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—264,782,458 shares and 2004—264,128,807 shares
     4,575      4,569 
Treasury Stock, at cost; 2005 —25,772,065 shares; 2004—26,029,740 shares
     (968)     (978)
Retained Earnings
     2,361      2,425 
Accumulated Other Comprehensive Loss
     (391)     (272)             
Total Common Stockholders' Equity
     5,577      5,744              
Total Capitalization
     17,479      18,749              
TOTAL LIABILITIES AND CAPITALIZATION
    $28,473     $29,244                      
See Notes to Condensed Consolidated Financial Statements.

3

**PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONSOLIDATED STATEMENTS OF CASH FLOWS**
  **For The Six Months EndedJune 30,**  **2005** **2004**  **(Millions)(Unaudited)**
CASH FLOWS FROM OPERATING ACTIVITIES
        
Net Income
    $203     $395 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Loss (Gain) on Disposal of Discontinued Operations, net of tax
     177      (3)
Investment        write-off 
     22      — 
Depreciation and Amortization
     365      335 
Amortization of Nuclear Fuel
     45      41 
Provision for Deferred Income Taxes (Other than Leases) and ITC
     16      34 
Non-Cash Employee Benefit Plan Costs
     114      106 
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes
     (19)     (113)
Gain on Sale of Investments
     (49)     (46)
Undistributed Earnings from Affiliates
     (28)     17 
Foreign Currency Transaction (Gain) Loss
     (5)     6 
Unrealized Gains on Energy Contracts and Other Derivatives
     (3)     (24)
Over Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs
     9      41 
Under Recovery of Societal Benefits Charge (SBC)
     (49)     (5)
Net Realized Gains and Income from NDT Funds
     (37)     (75)
Other Non-Cash Charges
     25      44 
Net Change in Certain Current Assets and Liabilities
     (137)     70 
Employee Benefit Plan Funding and Related Payments
     (121)     (33)
Proceeds from the Withdrawal of Partnership Interests and Other Distributions
     63      93 
Other
     (19)     (51)             
Net Cash Provided By Operating Activities
     572      832              
CASH FLOWS FROM INVESTING ACTIVITIES
        
Additions to Property, Plant and Equipment
     (480)     (579)
Investments in Joint Ventures, Partnerships and Capital Leases
     —      (14)
Proceeds from the Sale of Investments and Return of Capital from Partnerships
     26      292 
Proceeds from Collection of Notes Receivable
     132      — 
Other
     3      5              
Net Cash Used In Investing Activities
     (319)     (296)             
CASH FLOWS FROM FINANCING ACTIVITIES
        
Net Change in Commercial Paper and Loans
     93      474 
Issuance of Long-Term Debt
     —      683 
Issuance of Non-Recourse Debt
     7      — 
Issuance of Common Stock
     37      42 
Issuance of Treasury Stock
     —      3 
Redemptions of Long-Term Debt
     (66)     (1,643)
Repayment of Non-Recourse Debt
     (12)     — 
Cash Dividends Paid on Common Stock
     (267)     (260)
Other
     (28)     (33)             
Net Cash Used In Financing Activities
     (236)     (734)             
Effect of Exchange Rate Change
     (2)     (1)             
Net Increase in Cash and Cash Equivalents
     15      (199)
Cash and Cash Equivalents at Beginning of Period
     279      452              
Cash and Cash Equivalents at End of Period
    $294     $253              
Supplemental Disclosure of Cash Flow Information:
        
Income Taxes Paid
    $101     $84 
Interest Paid, Net of Amounts Capitalized
    $431     $456         
See Notes to Condensed Consolidated Financial Statements.

4

**PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS**
  **For The Quarters EndedJune 30,** **For The Six Months EndedJune 30,**  **2005** **2004** **2005** **2004**  **(Millions)(Unaudited)**
OPERATING REVENUES
    $1,441     $1,418     $3,625     $3,600 
OPERATING EXPENSES
                
Energy Costs
     853      824      2,277      2,243 
Operation and Maintenance
     268      258      563      536 
Depreciation and Amortization
     128      126      263      253 
Taxes Other Than Income Taxes
     28      28      71      73                          
Total Operating Expenses
     1,277      1,236      3,174      3,105                          
OPERATING INCOME
     164      182      451      495 
Other Income
     2      3      4      6 
Other Deductions
     —      —      (1)     (1)
Interest Expense
     (86)     (91)     (170)     (187)                         
INCOME BEFORE INCOME TAXES
     80      94      284      313 
Income Tax Expense
     (31)     (31)     (117)     (125)                         
NET INCOME
     49      63      167      188 
Preferred Stock Dividends
     (1)     (1)     (2)     (2)                         
EARNINGS AVAILABLE TO PUBLICSERVICE ENTERPRISE GROUP INCORPORATED
    $48     $62     $165     $186                                          
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**
  **June 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**ASSETS**
        
CURRENT ASSETS
        
Cash and Cash Equivalents
    $22     $6 
Accounts Receivable, net of allowances of $34 in 2005 and 2004
     725      745 
Unbilled Revenues
     218      340 
Materials and Supplies
     50      45 
Prepayments
     275      61 
Restricted Funds
     3      5 
Other
     19      19              
Total Current Assets
     1,312      1,221              
PROPERTY, PLANT AND EQUIPMENT
     10,333      10,159 
Less: Accumulated Depreciation and Amortization
     (3,526)     (3,471)             
Net Property, Plant and Equipment
     6,807      6,688              
NONCURRENT ASSETS
        
Regulatory Assets
     4,961      5,127 
Long-Term Investments
     141      138 
Other Special Funds
     300      278 
Other
     120      134              
Total Noncurrent Assets
     5,522      5,677              
TOTAL ASSETS
    $13,641     $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**
  **June 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**LIABILITIES AND CAPITALIZATION**
        
CURRENT LIABILITIES
        
Long-Term Debt Due Within One Year
    $598     $271 
Commercial Paper and Loans
     370      105 
Accounts Payable
     317      250 
Accounts Payable—Affiliated Companies, net
     122      404 
Accrued Interest
     57      59 
Clean Energy Program
     89      82 
Other
     308      311              
Total Current Liabilities
     1,861      1,482              
NONCURRENT LIABILITIES
        
Deferred Income Taxes and ITC
     2,597      2,653 
Other Postretirement Benefit (OPEB) Costs
     555      534 
Regulatory Liabilities
     585      545 
Clean Energy Program
     280      324 
Environmental Costs
     287      309 
Other
     46      82              
Total Noncurrent Liabilities
     4,350      4,447              
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
        
CAPITALIZATION
        
LONG-TERM DEBT
        
Long-Term Debt
     2,617      2,938 
Securitization Debt
     1,868      1,939              
Total Long-Term Debt
     4,485      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
     170      170 
Basis Adjustment
     986      986 
Retained Earnings
     821      656 
Accumulated Other Comprehensive Loss
     (4)     (4)             
Total Common Stockholder's Equity
     2,865      2,700              
Total Capitalization
     7,430      7,657              
TOTAL LIABILITIES AND CAPITALIZATION
    $13,641     $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 Six Months EndedJune 30,**  **2005** **2004**  **(Millions)(Unaudited)**
CASH FLOWS FROM OPERATING ACTIVITIES
        
Net Income
    $167     $188 
Adjustments to Reconcile Net Income to Net Cash Flows fromOperating Activities:
        
Depreciation and Amortization
     263      253 
Provision for Deferred Income Taxes and ITC
     (57)     (81)
Non-Cash Employee Benefit Plan Costs
     81      79 
Non-Cash Interest Expense
     4      7 
Employee Benefit Plan Funding and Related Payments
     (73)     (22)
Over (Under) Recovery of Electric Energy Costs(BGS and NTC)
     16      (2)
(Under) Over Recovery of Gas Costs
     (7)     43 
Under Recovery of SBC
     (49)     (5)
Other Non-Cash Credits
     3      5 
Gain on Sale of Property, Plant and Equipment
     —      (1)
Net Changes in Certain Current Assets and Liabilities:
        
Accounts Receivable and Unbilled Revenues
     142      146 
Materials and Supplies
     (5)     — 
Prepayments
     (214)     (215)
Accrued Taxes
     (25)     — 
Accounts Payable
     (215)     (146)
Other Current Assets and Liabilities
     27      (39)
Other
     (2)     (31)             
Net Cash Provided By Operating Activities
     56      179              
CASH FLOWS FROM INVESTING ACTIVITIES
        
Additions to Property, Plant and Equipment
     (239)     (187)
Proceeds from the Sale of Property, Plant and Equipment
     —      1 
Restricted Funds
     2      —              
Net Cash Used In Investing Activities
     (237)     (186)             
CASH FLOWS FROM FINANCING ACTIVITIES
        
Net Change in Short-Term Debt
     265      222 
Issuance of Long-Term Debt
     —      175 
Redemption of Securitization Debt
     (66)     (62)
Redemption of Long-Term Debt
     —      (445)
Preferred Stock Dividends
     (2)     (2)             
Net Cash Provided By (Used In) Financing Activities
     197      (112)             
Net Change In Cash and Cash Equivalents
     16      (119)
Cash and Cash Equivalents at Beginning of Period
     6      140              
Cash and Cash Equivalents at End of Period
    $22     $21              
Supplemental Disclosure of Cash Flow Information:
        
Income Taxes Paid
    $197     $227 
Interest Paid, Net of Amounts Capitalized
    $158     $181         
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 EndedJune 30,** **For the Six Months EndedJune 30,**  **2005** **2004** **2005** **2004**  **(Millions)(Unaudited)**
OPERATING REVENUES
    $1,060     $990     $2,790     $2,688 
OPERATING EXPENSES
                
Energy Costs
     688      677      1,958      1,908 
Operation and Maintenance
     235      234      462      461 
Depreciation and Amortization
     32      26      62      49                          
Total Operating Expenses
     955      937      2,482      2,418                          
OPERATING INCOME
     105      53      308      270 
Other Income
     30      73      61      104 
Other Deductions
     (12)     (17)     (20)     (31)
Interest Expense
     (26)     (22)     (54)     (52)                         
INCOME FROM CONTINUING OPERATIONSBEFORE INCOME TAXES
     97      87      295      291 
Income Tax Expense
     (41)     (27)     (124)     (111)                         
INCOME FROM CONTINUING OPERATIONS
     56      60      171      180 
Loss from Discontinued Operations, including Loss on Disposal, net of tax benefit of $127, $5, $132 and $13 for the quarter and six months ended 2005 and 2004, respectively
     (183)     (8)     (190)     (19)                         
(LOSS) EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
    $(127)    $52     $(19)    $161                                          
See disclosures regarding PSEG Power LLCincluded in the Notes to Condensed Consolidated Financial Statements.

9

**PSEG POWER LLCCONDENSED CONSOLIDATED BALANCE SHEETS**
  **June 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**ASSETS**
        
CURRENT ASSETS
        
Cash and Cash Equivalents
    $20     $10 
Accounts Receivable
     500      740 
Accounts Receivable—Affiliated Companies, net
     14      324 
Short-Term Loan to Affiliate
     93      — 
Fuel
     509      621 
Materials and Supplies
     185      175 
Energy Trading Contracts
     198      161 
Assets of Discontinued Operations
     220      511 
Other
     52      61              
Total Current Assets
     1,791      2,603              
PROPERTY, PLANT AND EQUIPMENT
     6,231      6,073 
Less: Accumulated Depreciation and Amortization
     (1,517)     (1,482)             
Net Property, Plant and Equipment
     4,714      4,591              
NONCURRENT ASSETS
        
Deferred Income Taxes and Investment Tax Credits (ITC)
     26      — 
Nuclear Decommissioning Trust (NDT) Funds
     1,098      1,086 
Goodwill and Other Intangibles
     107      107 
Other Special Funds
     137      121 
Other
     99      99              
Total Noncurrent Assets
     1,467      1,413              
TOTAL ASSETS
    $7,972     $8,607              
**LIABILITIES AND MEMBER'S EQUITY**
        
CURRENT LIABILITIES
        
Long-Term Debt Due Within One Year
    $500     $— 
Accounts Payable
     533      992 
Short-Term Loan from Affiliate
     —      98 
Energy Trading Contracts
     96      125 
Derivative Contracts
     196      151 
Accrued Interest
     41      42 
Other
     104      113              
Total Current Liabilities
     1,470      1,521              
NONCURRENT LIABILITIES
        
Deferred Income Taxes and Investment Tax Credits (ITC)
     —      96 
Nuclear Decommissioning Liabilities
     324      310 
Other
     402      281              
Total Noncurrent Liabilities
     726      687              
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
        
LONG-TERM DEBT
        
Total Long-Term Debt
     2,816      3,316              
MEMBER'S EQUITY
        
Contributed Capital
     2,000      2,000 
Basis Adjustment
     (986)     (986)
Retained Earnings
     2,099      2,118 
Accumulated Other Comprehensive Loss
     (153)     (49)             
Total Member's Equity
     2,960      3,083              
TOTAL LIABILITIES AND MEMBER'S EQUITY
    $7,972     $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 Six Months EndedJune 30,**  **2005** **2004**  **(Millions)(Unaudited)**
CASH FLOWS FROM OPERATING ACTIVITIES
        
Net (Loss) Income
    $(19)    $161 
Adjustments to Reconcile Net (Loss) Income to Net Cash Flows from Operating Activities:
        
Loss on Disposal of Discontinued Operations, net of tax
     177      — 
Depreciation and Amortization
     62      49 
Amortization of Nuclear Fuel
     45      41 
Interest Accretion on NDT Liability
     14      13 
Provision for Deferred Income Taxes and ITC
     77      110 
Unrealized Losses on Energy Contracts and Derivatives
     (4)     (22)
Non-Cash Employee Benefit Plan Costs
     22      19 
Net Realized Gains and Income on NDT Funds
     (37)     (75)
Net Changes in Certain Current Assets and Liabilities:
        
Fuel, Materials and Supplies
     102      53 
Accounts Receivable
     550      52 
Accounts Payable
     (465)     (99)
Other Current Assets and Liabilities
     (76)     108 
Employee Benefit Plan Funding and Other Payments
     (32)     (8)
Other
     12      (25)             
Net Cash Provided By Operating Activities
     428      377              
CASH FLOWS FROM INVESTING ACTIVITIES
        
Additions to Property, Plant and Equipment
     (227)     (336)
Short-Term Loan to Affiliate
     (93)     77 
Other
     —      (7)             
Net Cash Used In Investing Activities
     (320)     (266)             
CASH FLOWS FROM FINANCING ACTIVITIES
        
Issuance of Recourse Long-Term Debt
     —      500 
Redemption of Non-Recourse Long-Term Debt
     —      (800)
Deferred Issuance Costs
     —      (12)
Short-Term Loan from Affiliate
     (98)     191              
Net Cash Used In Financing Activities
     (98)     (121)             
Net Change In Cash and Cash Equivalents
     10      (10)
Cash and Cash Equivalents at Beginning of Period
     10      27              
Cash and Cash Equivalents at End of Period
    $20     $17              
Supplemental Disclosure of Cash Flow Information:
        
Income Taxes Paid
    $10     $36 
Interest Paid, Net of Amounts Capitalized
    $57     $54         
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 EndedJune 30,** **For the Six Months EndedJune 30,**  **2005** **2004** **2005** **2004**  **(Millions)(Unaudited)**
OPERATING REVENUES 
                
Electric Generation and Distribution Revenues
    $293     $118     $572     $244 
Income from Capital and Operating Leases
     45      49      92      101 
Other
     (11)     10      42      45                          
Total Operating Revenues
     327      177      706      390                          
OPERATING EXPENSES
                
Energy Costs
     185      48      349      94 
Operation and Maintenance
     72      50      149      99 
Depreciation and Amortization
     14      12      31      25                          
Total Operating Expenses
     271      110      529      218                          
Income from Equity Method Investments
     30      33      67      61                          
OPERATING INCOME
     86      100      244      233 
Other Income
     8      2      18      4 
Other Deductions
     (8)     (9)     (12)     (10)
Interest Expense
     (62)     (67)     (128)     (130)                         
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST
     24      26      122      97 
Income Tax Expense
     (1)     (5)     (17)     (26)
Minority Interests in Earnings of Subsidiaries
     (1)     —      (4)     (2)                         
INCOME FROM CONTINUING OPERATIONS
     22      21      101      69 
Income from Discontinued Operations, including Gain on Disposal, net of tax
     —      5      —      5                          
NET INCOME
     22      26      101      74 
Preference Units Distributions
     (1)     (5)     (3)     (10)                         
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
    $21     $21     $98     $64                                          
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**
  **June 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**ASSETS**
        
CURRENT ASSETS
        
Cash and Cash Equivalents
    $245       $199 
Accounts Receivable:
        
Trade—net of allowances of $3 and $1 in 2005 and 2004, respectively
     111        114 
Other Accounts Receivable
     18        20 
Affiliated Companies
     —        19 
Notes Receivable:
        
Affiliated Companies
     57        115 
Other
     5        138 
Inventory
     37        47 
Restricted Funds
     34        45 
Other
     5        7                
Total Current Assets
     512        704                
PROPERTY, PLANT AND EQUIPMENT
     1,857        2,084 
Less: Accumulated Depreciation and Amortization
     (227)       (227)               
Net Property, Plant and Equipment
     1,630        1,857                
NONCURRENT ASSETS
        
Leveraged Leases, net
     2,887        2,851 
Corporate Joint Ventures
     930        894 
Partnership Interests
     206        219 
Goodwill and Other Intangibles
     503        517 
Other
     117        153                
Total Noncurrent Assets
     4,643        4,634                
TOTAL ASSETS
    $6,785       $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**
  **June 30,2005** **December 31,2004**  **(Millions)(Unaudited)**
**LIABILITIES AND MEMBER'S EQUITY**
        
CURRENT LIABILITIES
        
Long-Term Debt Due Within One Year
    $51       $66 
Accounts Payable:
        
Trade
     52        59 
Affiliated Companies
     24        2 
Derivative Contracts
     28        37 
Accrued Interest
     44        51 
Other
     54        71                
Total Current Liabilities
     253        286                
NONCURRENT LIABILITIES
        
Deferred Income Taxes and Investment and Energy Tax Credits
     1,636        1,587 
Derivative Contracts
     65        88 
Other
     75        56                
Total Noncurrent Liabilities
     1,776        1,731                
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
        
MINORITY INTERESTS
     26        35                
LONG-TERM DEBT
        
Project Level, Non-Recourse Debt
     1,166        1,371 
Senior Notes
     1,755        1,756                
Total Long-Term Debt
     2,921        3,127                
MEMBER'S EQUITY
        
Ordinary Unit
     1,712        1,813 
Preference Units
     —        184 
Retained Earnings
     326        228 
Accumulated Other Comprehensive Loss
     (229)       (209)               
Total Member's Equity
     1,809        2,016                
TOTAL LIABILITIES AND MEMBER'S EQUITY
    $6,785       $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 Six Months EndedJune 30,**  **2005** **2004**  **(Millions)(Unaudited)**
CASH FLOWS FROM OPERATING ACTIVITIES
        
Net Income
    $101     $74 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Gain on Disposal of Discontinued Operations, net of tax
     —      (3)
Depreciation and Amortization
     31      25 
Demand Side Management Amortization
     4      4 
Investment Write-off
     22      — 
Deferred Income Taxes (Other than Leases)
     (4)     4 
Leveraged Lease Income, Adjusted for Rents Received and Deferred Income Taxes
     (19)     (113)
Undistributed Earnings from Affiliates
     (28)     17 
Gain on Sale of Investments
     (49)     (46)
Unrealized (Gain) Loss on Investments
     (1)     18 
Foreign Currency Transaction (Gain) Loss
     (5)     6 
Change in Fair Value of Derivative Financial Instruments
     1      (2)
Other Non-Cash Charges
     4      5 
Net Changes in Certain Current Assets and Liabilities:
        
Accounts Receivable
     1      181 
Inventory
     6      1 
Accounts Payable
     47      20 
Other Current Assets and Liabilities
     (28)     17 
Proceeds from Withdrawal of Partnership Interests and Other Distributions
     63      93 
Other
     3      (3)             
Net Cash Provided By Operating Activities
     149      298              
CASH FLOWS FROM INVESTING ACTIVITIES
        
Additions to Property, Plant and Equipment
     (18)     (49)
Investments in Joint Ventures, Partnerships, and Leveraged Lease Agreements
     —      (14)
Proceeds from the Sale of Investments and Return of Capital from Partnerships
     26      63 
Proceeds from Termination of Capital Leases
     —      229 
Short-Term Loan Receivable—Affiliated Company
     58      131 
Restricted Cash
     (2)     9 
Proceeds from Collection of Notes Receivable
     132      — 
Other
     1      5              
Net Cash Provided By Investing Activities
     197      374              
CASH FLOWS FROM FINANCING ACTIVITIES
        
Repayment of Senior Notes
     —      (311)
Proceeds from Project-Level Non-Recourse Long-Term Debt
     7      8 
Repayment of Project-Level Non-Recourse Long-Term Debt
     (12)     (25)
Return of Capital Contributed
     (100)     (75)
Cash Distributions Paid on Preference Units
     (3)     (10)
Redemptions of Preference Units
     (184)     (150)
Other
     (6)     —              
Net Cash Used In Financing Activities
     (298)     (563)             
Effect of Exchange Rate Change
     (2)     (1)             
Net Change In Cash and Cash Equivalents
     46      108 
Cash and Cash Equivalents at Beginning of Period
     199      104              
Cash and Cash Equivalents at End of Period
    $245     $212              
Supplemental Disclosure of Cash Flow Information:
        
Income Taxes Paid (Received)
    $26     $(128)
Interest Paid, Net of Amounts Capitalized
    $145     $94         
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.

      On June 30, 2005, the Federal Energy Regulatory Commission (FERC) approved the Merger.

      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.

      **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), a bankruptcy-remote entity that purchased certain intangible transition property from PSE&G and issued certain transition bonds secured by such property.

      **Power**

      Power is a multi-regional, 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).

      **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

16

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

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.

      **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 quarter ended March 31, 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 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. The annual net periodic pension benefitcosts for 2005 will increase by approximately $2 million or 2% and the 2005 annual net OPEB costs will increase by approximately $11 million or 11% from costs that would have been expensed in 2005 had the plans' provisions remained unchanged. The new projected pension 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.

17

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

      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 EndedJune 30,** **Quarters EndedJune 30,** **Six Months EndedJune 30,** **Six Months EndedJune 30,**  **2005** **2004** **2005** **2004** **2005** **2004** **2005** **2004**  **(Millions)**                                
***Components of Net Periodic Benefit Costs:***
                                
Service Cost
    $22     $21     $4     $6     $45     $41     $9     $12 
Interest Cost
     51      49      16      14      103      98      30      28 
Expected Return on Plan Assets
     (62)     (58)     (3)     (2)     (125)     (116)     (5)     (4)
Amortization of Net
                                
Transition Obligation
     —      —      7      7      —      —      14      14 
Prior Service Cost
     4      4      3      —      8      8      3      — 
Loss
     12      9      1      —      23      19      2      —                                                  
Net Periodic Benefit Costs
     27      25      28      25      54      50      53      50 
Effect of Regulatory Asset
     —      —      5      5      —      —      10      10                                                  
Total Benefit Costs
    $27     $25     $33     $30     $54     $50     $63     $60                                                                                  
      **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 EndedJune 30,** **Quarters EndedJune 30,** **Six Months EndedJune 30,** **Six Months EndedJune 30,**  **2005** **2004** **2005** **2004** **2005** **2004** **2005** **2004**  **(Millions)**                                
PSE&G
    $13     $13     $29     $27     $27     $26     $55     $54 
Power
     8      8      3      2      16      15      6      4 
Energy Holdings
     1      1      —      —      1      1      —      — 
Services
     5      3      1      1      10      8      2      2                                                  
Total Benefit Costs
    $27     $25     $33     $30     $54     $50     $63     $60                                                                                  
**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 were 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.

      The following table illustrates the effect on Net (Loss) 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:

18

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**
  **Quarters EndedJune 30,** **Six Months EndedJune 30,**  **2005** **2004** **2005** **2004**  **(Millions, except for share data)**                
Net (Loss) Income, as reported
    $(82)    $124     $203     $395 
Add: Total stock-based compensation expensed during the period, net of related tax effects
     1      —      2      — 
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects
     (2)     (2)     (3)     (2)                         
Pro forma Net (Loss) Income
    $(83)    $122     $202     $393                          
Earnings Per Share:
                
Basic—as reported
    $(0.34)    $0.52     $0.85     $1.67 
Basic—pro forma
    $(0.35)    $0.52     $0.85     $1.66 
Diluted—as reported
    $(0.34)    $0.52     $0.84     $1.66 
Diluted—pro forma
    $(0.34)    $0.51     $0.83     $1.65                 
      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.

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

      **PSEG**

      In December 2004, the FASB issued SFAS 123R, 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). PSEG is evaluating the two proposed methods of adoption allowed by SFAS 123R and does not believe that the adoption of SFAS 123R will have a material effect on its financial statements.

**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

19

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

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 conditional asset 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 entitywould 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.

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

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

      EITF 03-1 provides guidance for disclosure of impaired securities. On June 29, 2005, FASB withdrew EITF-03-1's provisions dealing with the measurement and recognition of other-than-temporary impairments. The remaining provisions of EITF 03-1 that remain intact did not have a material impact on PSEG, PSE&G, Power and Energy Holdings.

**FASB Staff Position (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 as a specialdeduction in accordance with SFAS 109 and not as a tax rate reduction. PSEG, Power and Energy Holdings do not believe that neither the manufacturer's deduction, nor 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.

      As of June 30, 2005, Global had approximately $400 million of unrepatriated earnings and profits associated with its foreign investments. Of this amount, approximately $170 million could reasonably be

20

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

considered for repatriation as of June 30, 2005 based on PSEG's degree of control of its international investments and the availability of funds and capital structures of such investments. 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 considered for repatriation in 2005 to $250 million. If a decision were made to repatriate such an amount, and those earnings and funds were available for repatriation, the tax expense associated with such repatriation would approximate $13 million. Whether PSEG will ultimately take advantage of this provision, all or in part, depends upon a number of factors including, but not limited to, evaluating the impact of Notice 2005-10 and Notice 2005-38 publishedby the Internal Revenue Service (IRS), which discuss some of the rules pertaining to this deduction, as well as any future authoritative guidance. 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, 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.

      The proposal dealing with 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 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. (AEP). 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 is $220 million. The proceeds, together with anticipated reduction in tax liability, are approximately $300million, which will be used to retire debt at Power and PSEG.

      In May 2005, Power 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.

      The sale is subject to various regulatory approvals. It is anticipated that the transaction will close during the second half of 2005.

21

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

      Waterford's operating results for the quarters and six months ended June 30, 2005 and 2004 are summarized below:
   **Quarters EndedJune 30,** **Six Months EndedJune 30,**   **2005** **2004** **2005** **2004**   **(Millions)**                            
Operating Revenues
    $5     $1     $5     $1       
Pre-Tax Operating Loss
    $(10)    $(13)    $(22)    $(32)      
Net Loss
    $(6)    $(8)    $(13)    $(19)                      
      The carrying amounts of the assets of Waterford as of June 30, 2005 and December 31, 2004 are summarized in the following table:
  **As of**  **June 30,2005** **December 31,2004**  **(Millions)**        
Current Assets
    $8     $4 
Noncurrent Assets
     212      507              
Total Assets of Discontinued Operations
    $220     $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 quarter and six months ended June 30, 2004 are summarized below:
  **Quarter EndedJune 30, 2004** **Six Months EndedJune 30, 2004**  **(Millions)**        
Operating Revenues
    $12     $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

22

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

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 a gain of approximately $5 million in the quarter and six months ended June 30, 2004 related to the LDS sale which is recorded in Income from Equity Method Investments on the Condensed Consolidated Statements of Operations.

      ***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 $29 million and $53 million as of June 30, 2005 and December 31, 2004, respectively.

      ***Resources***

      Resources is the lessor of various aircraft to several domestic airlines, including a Boeing B767 aircraft 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.

23

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

**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 quarter and six months ended June 30, 2004 would have increased from $177 million to $335 million and from $390 million to $650 million, respectively, had the acquisition of TIE occurred at the beginning of 2004. Energy Holdings' consolidated Net Income for the quarter and six months ended June 30, 2004 would have increased from $26 million to $29 million and from $74 million to $76 million, respectively, 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.

**Note 4. Earnings Per Share (EPS)**

**PSEG**

      Diluted EPS is calculated by dividing Net (Loss) 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 June 30,** **Six Months Ended June 30,**  **2005** **2004** **2005** **2004**  **Basic** **Diluted** **Basic** **Diluted** **Basic** **Diluted** **Basic** **Diluted**                                
**EPS Numerator:**
                                
**Earnings (Millions)**
                                
Continuing Operations
    $101     $101     $127     $127     $393     $393     $409     $409 
Discontinued Operations
     (183)     (183)     (3)     (3)     (190)     (190)     (14)     (14)                                                 
**Net (Loss) Income**
    $(82)    $(82)    $124     $124     $203     $203     $395     $395                                                  
**EPS Denominator (Thousands):**
                                
Weighted Average Common Shares Outstanding
     238,732      238,732      236,705      236,705      238,524      238,524      236,449      236,449 
Effect of Stock Options
     —      934      —      707      —      994      —      909 
Effect of Stock Performance Units
     —      110      —      —      —      110      —      — 
Effect of Participating Units
     —      3,243      —      589      —      3,004      —      963                                                  
Total Shares
     238,732      243,019      236,705      238,001      238,524      242,632      236,449      238,321                                                  
**Earnings Per Share:**
                                
Continuing Operations
    $0.42     $0.42     $0.53     $0.53     $1.65     $1.62     $1.73     $1.72 
Discontinued Operations
     (0.76)     (0.76)     (0.01)     (0.01)     (0.80)     (0.78)     (0.06)     (0.06)                                                 
**Net (Loss) Income**
    $(0.34)    $(0.34)    $0.52     $0.52     $0.85     $0.84     $1.67     $1.66                                                                                  
      There were approximately 3.5 million and 3.1 million stock options excluded from the weighted average common shares calculation used for diluted EPS due to their antidilutive effect for the quarter and six months ended June 30, 2004, respectively. No stock options had an antidilutive effect for the quarter and six months ended June 30, 2005.

24

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

      Dividend payments on common stock for the quarters ended June 30, 2005 and 2004 were $0.56 and $0.55 per share, respectively, and totaled approximately $133 million and $130 million, respectively. Dividend payments on common stock for the six months ended June 30, 2005 and 2004 were $1.12 and $1.10 per share, respectively, and totaled approximately $267 million and $260 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 June 30, 2005 and December 31, 2004 was $1.7 billion and $1.6 billion,respectively. In order for Power to incur a liability for the face value of the outstanding guarantees, ER&T would have to fully utilize the credit granted to it by every counterparty to whom Power has provided a guarantee and all of ER&T's contracts would have to be “out-of-the-money” (if the contracts 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 $488 million and $507 million as of June 30,2005 and December 31, 2004, respectively. Of the $488 million exposure, $112 million was recorded on Power's Condensed Consolidated Balance Sheet as of June 30, 2005. Of the $507 million exposure, $193 million was recorded on Power's Condensed Consolidated Balance Sheet as of December 31, 2004.

      Power is subject to collateral calls related to commodity contracts that are bilateral. As of June 30, 2005, Power had recorded margin (cash) paid of approximately $69 million, including $15 million paid to PSE&G, and margin (cash) received of approximately $38 million. Changes in energy prices cause a commensurate impact in collateral requirements for Power. As of June 30, 2005, letters of credit issued by Power were outstanding in the amount of approximately $120 million in support of various contractual obligations, environmental liabilities and to satisfy trading collateral obligations.

      In connection with the management and optimization of Power's asset portfolio, ER&T maintains agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power's credit rating to below investment grade, 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. As of June 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 collateral in an amount equal to approximately $693 million. Providing this support wouldincrease Power's costs of doing business and could restrict the ability of ER&T to manage and optimize Power's asset portfolio.

25

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

      **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 guaranteed obligations as of June 30, 2005 and December 31, 2004 are as follows:
        **As of****Subsidiaries/Affiliates**    **Location**    **Description**  **ExpirationDate** **June 30,2005** **December 31,2004**        **(Millions)**
Elektrownia Skawina S.A. (Skawina)
    Poland    Equity commitment  August 2007  $26   $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    25 
PSEG Energy Technologies Asset Management Company LLC
    New Jersey    Performance guarantees  N/A   7    13 
Other
    Various    Letters of credit  2010   37    39               
Total Guaranteed Obligations
        $149   $128                             
      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 described above for PSEG Energy Technologies Asset Management Company LLC. As of June 30, 2005, there were $30 million of such bonds outstanding, which are related to uncompleted construction projects. These performance bonds are not included in the $149 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 and Global.

**Environmental Matters**

      **PSEG, PSE&G and Power**

      ***Hazardous Substances***

      The New Jersey Department of Environmental Protection (NJDEP) adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. These regulations may substantially increase the costs of environmental investigations and necessary remediation, particularly at sites situated on surface water bodies. PSE&G, Power and respective predecessor companies own or owned and/or operate or operated certain facilities situated on surface water bodies, certain of which are currently the subject of remedial activities. The financial impact of these regulations is not currently estimable. However, neither PSE&G nor Power anticipate that compliance with these regulations will havea material adverse effect on their respective financial positions, results of operations or net cash flows.

26

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

      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 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 40 other PRPs, have executed an agreement with the EPA that provides for sharing the costs of the study between the government organizations and the PRPs. PSEG, PSE&G and Power cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River or natural resource damages. However, such costs could be material.

      **PSE&G**

      ***MGP Remediation Program***

      PSE&G is currently working with the NJDEP under a program to assess, investigate and remediate environmental conditions at PSE&G's former MGP sites (Remediation Program). To date, 38 sites have been identified as sites requiring some level of remedial action. The Remediation Program is periodically reviewed, and the estimated costs are revised by PSE&G based on regulatory requirements, experience with the program and available remediation technologies. Since the inception of the Remediation Program in 1988 through June 30, 2005, PSE&G had expenditures of approximately $316 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, $334 million and $356 million was accrued at June 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 June 30, 2005 and December 31, 2004 of $316 million and $294 million, respectively. Of this amount, approximately $47

27

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

million was recorded in Other Current Liabilities and $287 million and $309 million were recorded in Other Noncurrent Liabilities on its Condensed Consolidated Balance Sheets as of June 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 $334 million and a $356 million Regulatory Asset was also recorded as of June 30, 2005 and December 31, 2004, respectively.

      Costs for the MGP Remediation Program were approximately $12 million and $22 million for the quarter and six months ended June 30, 2005, respectively. PSE&G anticipates spending $47 million in 2005, $35 million in 2006, and an average of $27 million per year through 2016.

      ***New Jersey Clean Energy Program***

      The BPU has approved a funding requirement for each New Jersey utility applicable to 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 June 30, 2005 and December 31, 2004 was $369 million and $406 million, respectively.

      **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 that are designed to reduce emissions of Sulfur Dioxide (SO2), Nitrogen Oxide (NOx), particulatematter and mercury at the Hudson station by December 31, 2006. The estimated cost of the program as of June 30, 2005 includes approximately $110 million for installation of selective catalytic reduction systems (SCRs) at Mercer, of which approximately $102 million 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 will 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

28

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

continued operation of the Hudson unit beyond December 31, 2006, but such costs could be material. The costs associated with 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 June 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 $548 million (including interest capitalized during construction (IDC) of $69 million). The plant was put into commercial operation on July 18, 2005.

      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 June 30, 2005 of approximately $938 million (including IDC of $164 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, primarily due to the replacement. 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$197 million (including IDC of $15 million) with an aggregate estimated share of total costs for these projects of $257 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 at Electroandes with cash and non-recourse debt.

29

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

**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 Basic Generation Service (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 decision on 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 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. Power has hedged approximately 99% of the allowed residential gas volume for the 2005 summer season at an average price of $6.18 per decatherm (dth). Approximately 60% of the allowed residential gas volume has been hedged for the 2005/2006 winter season at an average price of $7.18 per dth. As of June 30, 2005 and December 31, 2004, the fair value of the contracts was $85 million and $25 million, respectively. PSE&G has recorded an intercompany receivable from Power related to the fair market value of the contract with an offsetting Regulatory Liability. Power has recorded a derivative asset with an offsetting intercompany payableto PSE&G.

      **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, Connecticut and Maryland, 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 $875 million through 2009.

      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 $26 million per year.

30

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

      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 June 30, 2005, the total minimum requirements under these contracts were approximately $982 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 June 30, 2005, the Guadalupe and Odessa plants had fuel purchase commitments totaling $144 million under 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

31

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

through the end of their current respective license lives. Exelon Generation has advised Power that it has a licensed and operational on-site storage facility at Peach Bottom that will satisfy Peach Bottom's spent 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 demanding repayment of previouslyreceived 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 costsfor 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

32

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

this groundwater contamination issue have not been determined, however, such costs are not expected to be material.

**Other**

      **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 rules of theInternal 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 PSEG's business. The IRS is likely to argue that certain of those transactions are of a type that it has announced its intention to challenge, and PSEG understands that similar transactions entered into by other companies have been the subject of review and challenge by the IRS. As of June 30, 2005 and December 31, 2004, Resources'

33

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

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 these transactions. The IRS is aware of these lease transactions and has requested information and documents associated with them. To date, the IRS has not proposed to disallow any deductions claimed relative to these transactions, but may propose such disallowances in the future. If the tax benefits associated with the lease transactions were successfully challenged by the IRS, PSEG would be assessed interest and possibly penalties in addition to any underpayments of tax. During the time period of 1997 through 2000, these transactions reduced current tax liabilities of PSEG by approximately $240 million and duringthe subsequent time period of 2001 through the second quarter of 2005, these and similar transactions reduced the current tax liabilities of PSEG by approximately $397 million. Interest that would be assessed on these potential deficiencies, if associated deductions were disallowed, would be approximately $126 million through June 30, 2005. It is presently unclear the extent to which the IRS will seek to disallow deductions associated with these lease transactions, if at all, and, if it were to do so, the extent to which any such challenge would be successful. If deductions associated with these lease transactions entered into by PSEG were successfully challenged by the IRS, it could have a material adverse impact on PSEG's and Energy Holdings' financial position, results of operations and net cash flows and could impact future returns on these transactions. PSEG believes thatits tax position related to these transactions is proper based on applicable statutes, regulations and case law, and believes that it should prevail with respect to an IRS challenge, if presented, although no assurances can be given.

      The FASB is currently considering a modification to GAAP for leveraged leases. Under present GAAP, a tax settlement with the IRS that results 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 170 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 share of the estimated total cost of approximately $10 million was recorded in June 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. Global's share of the maximum claim amount related to these tax issues is approximately $30 million. RGE believes it has valid legal defenses to these claims, although no assurances can be given.

      ***LDS***

      The Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, has claimed past due taxes for the 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. Global's share of the net unrecorded potential liability related to the claim by SUNAT is estimated at $8 million.

34

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

      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 used by LDS for its tax deductions for depreciation. As a result of the CONATA valuation, Global anticipates that the SUNAT will withdraw its claim against LDS, in totality or in large part.

      ***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 $4 million through June 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. The Concession Agreement includes a provision for penalties to be paid in some circumstances to the Government of Oman for certain types of service interruptions. Dhofar Power and the Government of Oman disputed both the applicability and extent of any such penalties arising from these service interruptions. Dhofar Power and the Government of Oman have pursued an alternative dispute resolution. On July 14, 2005, the expert engaged by the parties to determine the dispute found in favor of DhofarPower on both the applicability and extent of the penalties, recommending no penalties to be assessed for the 2004 service interruptions and agreed with Dhofar Power's interpretation of the Concession Agreement with respect to the criteria to be utilized in assessing penalties. It is not known at this time whether the Government of Oman will exercise its right to appeal the expert's determination to a full arbitration panel. Dhofar Power believes this matter will be favorably resolved in 2005, although no assurances can be given.

      See Note 3. Discontinued Operations, Dispositions and Acquisitions for a discussion of the sale by Global of Dhofar Power's shares as required under the Concession Agreement.

      ***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, Civil Action No. C-03-249, alleges price-fixing, predatory pricing and certain common law claims. Automated Power Exchange, Inc. (APX), a named defendant, acted as agent and submitted bids on behalf of Guadalupe Power Partners, L.P. (Guadalupe) and Odessa-Ector Power Partners, L.P. (Odessa), as well as several other generators in the ERCOT balancing energymarket. APX has submitted a demand for indemnification from Guadalupe and Odessa. On February 3, 2004, TCE amended its complaint and named TIE, Guadalupe and Odessa and others as additional defendants. On May 20, 2004, the U.S. District Court granted the defendants' motion to dismiss the state and federal antitrust claims. All collateral claims were to be held in abatement pending an appeal of the ruling to the Fifth Circuit Court of Appeals. On July 19, 2004, TCE filed a Notice of Appeal, and the parties subsequently filed briefs and reply briefs. On June 15, 2005 a two-judge panel of the Fifth Circuit issued its decision affirming the District Court's dismissal of TCE's

35

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

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. It cannot be predicted whether TCE will seek 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, based on facts similar to those alleged in the TCE litigation. The new action, filed in the U.S. District Court for the Southern Division of Texas, also alleges price-fixing, predatory pricing and various other claims. The District Court issued a stay of action pending the outcome of the TCE appeal. That stay had been continued until the TCE request to the Fifth Circuit had been determined. The District Court has issued an order lifting the stay for the sole purpose of permitting motions to dismiss to be filed on or before August 11, 2005. Global continues to believe there are valid defenses to these claims, which will 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 by creating a relationship in which gains or losses on derivative instruments are expected to counterbalancethe gains or losses on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, PSE&G, Power and Energy Holdings uses derivative instruments as risk management tools consistent with its respective business plan and prudent business practices.

**Derivative Instruments and Hedging Activities**

      **Energy Trading Contracts**

      ***Power***

      Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, financial transmission rights (FTRs), coal, oil, weather derivatives and emission allowances in the spot, forward and futures markets, primarily in the 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 to hedge at least 75% of its anticipated generation output over an 18-month to 24-month horizon. The increase in power prices over the past several years has given rise to changes in Other Comprehensive Income (Loss) on Power's CondensedConsolidated Balance Sheet for those contracts treated as accounting hedges equal to the difference between the current market prices for the contract periods and the prices at which power was previously contracted. Power continues to believe that hedging approximately 75% of its anticipated generation output is an appropriate way to reduce the volatility of its earnings.

36

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

      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 Statement of Operations. Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices, as applicable, to interpolate certain prices. The effect of using such modeling techniques is not material to Power's financial results.

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

      **Commodity Contracts**

      ***Power***

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

      ***Cash Flow Hedges***

      Power uses forward sale and purchase contracts, swaps and FTR contracts to hedge forecasted energy sales from its generation stations and to hedge related load obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of June 30, 2005, the fair value of these hedges was $(407) million, $(241) million after-tax. As of December 31, 2004, the fair value of these hedges was $(248) million, $(145) million after-tax. During the next 12 months, $108 million of unrealized losses (after-tax) on these commodity derivatives in Accumulated Other Comprehensive Loss is expected to be reclassified to earnings. Ineffectiveness associated with thesehedges, 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 June 30, 2005 and December 31, 2004 was $33 million and $14 million, respectively.

**Interest Rates**

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

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

37

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

      **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 June 30, 2005 and December 31, 2004, the fair value of the hedge was $(5) 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 June 30, 2005 and December 31, 2004, the fair value of these hedges was $(4) 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 June 30, 2005, the fair value of these cash flow hedges was $(121) million, including $(9) million, $(25) million and $(87) 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 $(25) million and $(34)million at PSE&G as of June 30, 2005 and December 31, 2004, respectively, is not included in Accumulated Other Comprehensive Loss, as it is deferred as a Regulatory Asset and is expected to be recovered from PSE&G's customers. During the next 12 months, $21 million of unrealized losses (net of taxes) on interest rate derivatives in Accumulated Other Comprehensive Loss is expected to be reclassified to earnings, including $2 million and $19 million at PSEG and Energy Holdings, respectively. As of June 30, 2005, hedge ineffectiveness associated with these hedges was not material.

      **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 Income Statements. The fair value of these swaps was approximately $6 million and $4 million as of June 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

38

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

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

      As of June 30, 2005, net cumulative foreign currency devaluations had reduced the total amount of Energy Holdings' Member's Equity by $149 million as compared to $129 million as of December 31, 2004.

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

      In January 2005 and March 2005, Energy Holdings purchased three foreign currency option agreements to sell U.S. Dollars at 2.99 Polish Zloty/Dollar through December 30, 2005. The options hedge the SFAS No. 52, “Foreign Currency Translation”, exposure on the Polish Zloty denominated debt and a portion of the Polish Zloty denominated interest rate swap at Global's Polish investment, ELCHO, which is accounted for as a U.S. Dollar functional currency entity and is therefore exposed to foreign currency gains or losses on Polish Zloty denominated monetary assets and liabilities. 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, which would largely offset any potential foreign currency losses on the PolishZloty denominated monetary liabilities. The fair value of these instruments as of June 30, 2005 was not material.

**Hedges of Net Investments in Foreign Operations**

      **Energy Holdings**

      In March 2004 and April 2004, Energy Holdings entered into three 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 $(13) million and $(21) million as of June 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.

**Equity Securities**

      **Energy Holdings**

      As of June 30, 2005, Resources had an investment in a leveraged buyout fund of approximately $12 million, which is comprised of one public security with an available market price. As of December 31, 2004, Resources had investments in leveraged buyout funds of approximately $27 million.

39

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

**Note 7. Comprehensive Income (Loss), Net of Tax**
  **PSE&G** **Power (A)** **EnergyHoldings (B)** **Other (C)** **ConsolidatedTotal**  **(Millions)**
**For the Quarter Ended June 30, 2005:**
                    
Net Income (Loss)
    $49     $(127)    $22     $(26)    $(82)
Other Comprehensive Income
     —      6      31      3      40                                
Comprehensive Income (Loss)
    $49     $(121)    $53     $(23)    $(42)                               
**For the Quarter Ended June 30, 2004:**
                    
Net Income (Loss)
    $63     $52     $26     $(17)    $124 
Other Comprehensive (Loss) Income
     (1)     (59)     (30)     4      (86)                               
Comprehensive Income (Loss)
    $62     $(7)    $(4)    $(13)    $(38)                               
**For the Six Months Ended June 30, 2005:**
                    
Net Income (Loss)
    $167     $(19)    $101     $(46)    $203 
Other Comprehensive (Loss) Income
     —      (104)     (20)     5      (119)                               
Comprehensive Income (Loss)
    $167     $(123)    $81     $(41)    $84                                
**For the Six Months Ended June 30, 2004:**
                    
Net Income (Loss)
    $188     $161     $74     $(28)    $395 
Other Comprehensive Loss
     (1)     (190)     (79)     (2)     (272)                               
Comprehensive Income (Loss)
    $187     $(29)    $(5)    $(30)    $123                                                       (A)   Changes at Power primarily relate to SFAS 133 unrealized losses on derivative contracts that qualify for hedge accounting and unrealized gains and losses on Nuclear Decommissioning Trust (NDT) Funds. The increase in power prices over the past several years has given rise to changes in Other Comprehensive Income (Loss) on Power’s Consolidated Balance Sheet for those contracts treated as accounting hedges equal to the difference between the current market prices for the contract periods and the prices at which power was previously contracted.   (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 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.

      In June 2005 and March 2005, Transition Funding repaid approximately $32 million and $34 million, respectively, 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.

40

**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 June 30, 2005:**
                    
Interest Income
    $2     $2     $—     $—     $4 
NDT Fund Realized Gains
     —      17      —      —      17 
NDT Interest and Dividend Income
     —      10      —      —      10 
Foreign Currency Gains
     —      —      8      —      8 
Other
     —      1      —      1      2                                
Total Other Income
    $2     $30     $8     $1     $41                                
**For the Quarter Ended June 30, 2004:**
                    
Interest Income
    $2     $1     $—     $1     $4 
NDT Fund Realized Gains
     —      64      —      —      64 
NDT Interest and Dividend Income
     —      8      —      —      8 
Change in Derivative Fair Value
     —      —      1      —      1 
Other
     1      —      1      1      3                                
Total Other Income
    $3     $73     $2     $2     $80                                
**For the Six Months Ended June 30, 2005:**
                    
Interest Income
    $4     $3     $—     $—     $7 
Gain on Sale of Investments
     —      —      1      —      1 
NDT Fund Realized Gains
     —      39      —      —      39 
NDT Interest and Dividend Income
     —      17      —      —      17 
Change in Derivative Fair Value
     —      —      1      —      1 
Foreign Currency Gains
     —      —      14      —      14 
Other
     —      2      2      1      5                                
Total Other Income
    $4     $61     $18     $1     $84                                
**For the Six Months Ended June 30, 2004:**
                    
Interest Income
    $8     $2     $—     $(4)    $6 
Disposition of Property
     (3)     —      —      —      (3)
NDT Fund Realized Gains
     —      88      —      —      88 
NDT Interest and Dividend Income
     —      14      —      —      14 
Change in Derivative Fair Value
     —      —      2      —      2 
Foreign Currency Gains
     —      —      1      —      1 
Other
     1      —      1      1      3                                
Total Other Income
    $6     $104     $4     $(3)    $111                                                    
41

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**
  **PSE&G** **Power** **EnergyHoldings** **Other (A)** **ConsolidatedTotal**  **(Millions)**                    
**Other Deductions:**
                    
**For the Quarter Ended June 30, 2005:**
                    
Donations
    $—     $1     $—     $—     $1 
Foreign Currency Losses
     —      —      6      —      6 
Change in Derivative Fair Value
     —      —      2      —      2 
NDT Fund Realized Losses and Expenses
     —      11      —      —      11 
Minority Interest
     —      —      —      1      1                                
Total Other Deductions
    $—     $12     $8     $1     $21                                
**For the Quarter Ended June 30, 2004:**
                    
NDT Fund Realized Losses and Expenses
    $—     $16     $—     $—     $16 
Foreign Currency Losses
     —      —      6      —      6 
Loss on Early Extinguishment of Debt
     —      —      3      —      3 
Other
     —      1      —      —      1                                
Total Other Deductions
    $—     $17     $9     $—     $26                                
**For the Six Months Ended June 30, 2005:**
                    
Donations
    $1     $1     $—     $—     $2 
Foreign Currency Losses
     —      —      10      —      10 
Change in Derivative Fair Value
     —      —      2      —      2 
NDT Fund Realized Losses and Expenses
     —      18      —      —      18 
Minority Interest
     —      —      —      4      4 
Other
     —      1      —      —      1                                
Total Other Deductions
    $1     $20     $12     $4     $37                                
**For the Six Months Ended June 30, 2004:**
                    
Donations
    $1     $—     $—     $—     $1 
NDT Fund Realized Losses and Expenses
     —      26      —      —      26 
Foreign Currency Losses
     —      —      6      —      6 
Loss on Early Extinguishment of Debt
     —      —      3      —      3 
Minority Interest
     —      —      —      2      2 
Other
     —      5      1      —      6                                
Total Other Deductions
    $1     $31     $10     $2     $44                                                       (A)   Other consists of reclassifications for minority interests in PSEG’s consolidated results of operations and intercompany eliminations at PSEG (as parent company).
**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 June 30, 2005:**
                    
Income (Loss) from Continuing Operations before Income Taxes
    $80     $97     $24     $(41)    $160 
Tax computed at the statutory rate
     28      34      8      (14)     56 
Increase (decrease) attributable to flow through of certain tax adjustments:
                    
State Income Taxes after Federal Benefit
     6      5      5      —      16 
Rate Differential of Foreign Operations
     —      —      (16)     —      (16)
Lease Rate Differential
     —      —      2      —      2 
Other
     (3)     2      2      —      1                                
Total Income Tax Expense (Benefit)
    $31     $41     $1     $(14)    $59                                
Effective income tax rate
     38.8%     42.3%     4.2%     34.1%     36.9%                                                   
42

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**
  **PSE&G** **Power** **EnergyHoldings** **Other (A)** **ConsolidatedTotal**  **(Millions)**
**For the Quarter Ended June 30, 2004:**
                    
Income (Loss) from Continuing Operations before Income Taxes
    $94     $87     $26     $(23)    $184 
Tax computed at the statutory rate
     33      30      9      (8)     64 
Increase (decrease) attributable to flow through of certain tax adjustments:
                    
State Income Taxes after Federal Benefit
     7      4      12      (1)     22 
Rate Differential of Foreign Operations
     —      —      (2)     —      (2)
Plant Related Items
     (1)     —      —      —      (1)
Lease Rate Differential
     —      —      (12)     —      (12)
Other
     (8)     (7)     (2)     3      (14)                               
Total Income Tax Expense (Benefit)
    $31     $27     $5     $(6)    $57                                
Effective income tax rate.
     33.0%     31.0%     19.2%     26.1%     31.0%                               
**For the Six Months Ended June 30, 2005:**
                    
Income (Loss) from Continuing Operations before Income Taxes
    $284     $295     $122     $(77)    $624 
Tax computed at the statutory rate
     99      103      43      (27)     218 
Increase (decrease) attributable to flow through of certain tax adjustments:
                    
State Income Taxes after Federal Benefit
     20      17      (2)     (1)     34 
Rate Differential of Foreign Operations
     —      —      (28)     —      (28)
Plant Related Items
     1      —      —      —      1 
Lease Rate Differential
     —      —      2      —      2 
Other
     (3)     4      2      1      4                                
Total Income Tax Expense (Benefit)
    $117     $124     $17     $(27)    $231                                
Effective income tax rate
     41.2%     42.0%     13.9%     35.1%     37.0%                               
**For the Six Months Ended June 30, 2004:**
                    
Income (Loss) from Continuing Operations before Income Taxes
    $313     $291     $97     $(47)    $654 
Tax computed at the statutory rate
     110      102      34      (17)     229 
Increase (decrease) attributable to flow through of certain tax adjustments:
                    
State Income Taxes after Federal Benefit
     22      15      12      (3)     46 
Rate Differential of Foreign Operations
     —      —      (9)     —      (9)
Plant Related Items
     (2)     —      —      —      (2)
Lease Rate Differential
     —      —      (10)     —      (10)
Other
     (5)     (6)     (1)     3      (9)                               
Total Income Tax Expense (Benefit)
    $125     $111     $26     $(17)    $245                                
Effective income tax rate
     39.9%     38.1%     26.8%     36.2%     37.5%                                                   (A) PSEG’s other activities include amounts applicable to PSEG (as parent corporation) that primarily relate to financing and certain administrative and general costs.
43

**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 June 30, 2005:**
                            
Total Operating Revenues
    $1,441    $1,060    $28    $297    $2    $(386)   $2,442 
Income (Loss) from Continuing Operations
     49     56     (1)    25     (2)    (26)    101 
Loss from Discontinued Operations, including Loss on Disposal, net of tax
     —     (183)    —     —     —     —     (183)
Net Income (Loss)
     49     (127)    (1)    25     (2)    (26)    (82)
Preferred Securities Dividends/Preference Unit Distributions
     (1)    —     —     (1)    —     2     — 
Segment Earnings (Loss)
     48     (127)    (1)    24     (2)    (24)    (82)
Gross Additions to Long-Lived Assets
     144     138     1     5     (1)    (6)    281 
**For the Quarter Ended June 30, 2004:**
                            
Total Operating Revenues
    $1,418    $990    $57    $117    $3    $(300)   $2,285 
Income (Loss) from Continuing Operations
     63     60     14     9     (2)    (17)    127 
Loss (Income) from Discontinued Operations, including Loss on Disposal, net of tax
     —     (8)    —     5     —     —     (3)
Net Income (Loss)
     63     52     14     14     (2)    (17)    124 
Preferred Securities Dividends/Preference Unit Distributions
     (1)    —     (1)    (4)    —     6     — 
Segment Earnings (Loss)
     62     52     13     10     (2)    (11)    124 
Gross Additions to Long-Lived Assets
     112     189     10     39     (1)    6     355 
**For the Six Months Ended June 30, 2005:**
                            
Total Operating Revenues
    $3,625    $2,790    $89    $612    $5    $(1,370)   $5,751 
Income (Loss) from Continuing Operations
     167     171     22     82     (3)    (46)    393 
Loss from Discontinued Operations, including Loss on Disposal, net of tax
     —     (190)    —     —     —     —     (190)
Net Income (Loss)
     167     (19)    22     82     (3)    (46)    203 
Preferred Securities Dividends/Preference Unit Distributions
     (2)    —     —     (3)    —     5     — 
Segment Earnings (Loss)
     165     (19)    22     79     (3)    (41)    203 
Gross Additions to Long-Lived Assets
     239     227     2     17     (1)    (4)    480 
**For the Six Months Ended June 30, 2004:**
                            
Total Operating Revenues
    $3,600    $2,688    $95    $290    $5    $(1,165)   $5,513 
Income (Loss) from Continuing Operations
     188     180     16     58     (5)    (28)    409 
Loss (Income) from Discontinued Operations, including Loss on Disposal, net of tax
     —     (19)    —     5     —     —     (14)
Net Income (Loss)
     188     161     16     63     (5)    (28)    395 
Preferred Securities Dividends/Preference Unit Distributions
     (2)    —     (3)    (7)    —     12     — 
Segment Earnings (Loss)
     186     161     13     56     (5)    (16)    395 
Gross Additions to Long-Lived Assets
     187     336     11     52     —     7     593 
**As of June 30, 2005:**
                            
Total Assets
    $13,641    $7,972    $3,022    $3,758    $5    $75    $28,473 
Investments in Equity Method Subsidiaries
    $—    $—    $24    $1,074    $—    $—    $1,098 
**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.
*(footnotes continued on next page)*

44

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

(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 Ended June 30,** **Six Months Ended June 30,**   **2005** **2004** **2005** **2004**   **(Millions)**                                          
BGS
    $110     $63     $223     $82              
BGSS
    $174     $236     $1,036     $1,083                              
      As of June 30, 2005 and December 31, 2004, Power had net receivables from PSE&G of approximately $129 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 June 30, 2005 and December 31, 2004, PSE&G had a receivable from Power of approximately $85 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 each of the operating companies. The billings for administrative services and payables are presented below:

45

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**
  **Services' Billings for the**          **Quarters EndedJune 30,** **Six Months EndedJune 30,** **Payable to Services as of**  **2005** **2004** **2005** **2004** **June 30, 2005** **December 31, 2004**  **(Millions)**                        
PSE&G
    $53     $53     $103     $100     $33     $38 
Power
    $37     $40     $75     $74     $19     $23 
Energy Holdings
    $5     $5     $9     $8     $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**   **June 30, 2005** **December 31, 2004**   **(Millions)**                                  
PSE&G
    $(47)    $(45)             
Power
    $(14)    $9              
Energy Holdings
    $(24)    $19                      
**Affiliate Loans and Advances**

      **PSEG and Power**

      As of June 30, 2005, Power had a note receivable due from PSEG of approximately $93 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 June 30, 2005 and December 31, 2004, Energy Holdings had a note receivable due from PSEG of approximately $57 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 June 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 June 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.

46

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

**Other**

      **PSEG and PSE&G**

      As of June 30, 2005 and December 31, 2004, PSE&G had receivables from PSEG of approximately $1 million and $14 million, respectively, related to amounts that PSEG had collected on PSE&G’s behalf.

      **PSEG and Power**

      As of June 30, 2005 and December 31, 2004, Power had receivables from PSEG of approximately $3 million and $4 million, respectively, related to amounts that PSEG had collected on Power’s behalf.

      **Energy Holdings**

      As of June 30, 2005 and December 31, 2004, Global had loans of approximately $59 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 six months of 2005 and was recorded as a foreign currency loss in Other Deductions. Included in the loan balances as of June 30, 2005 and December 31, 2004 were $23 million and $24 million, respectively, of accrued interest. These loans are guaranteed by an affiliate of Global’s partner. Due to insufficient funds at the project level, a $4 million payment due to Global on June 30, 2005 was not made. Global is currentlynegotiating a restructuring of the Prisma project with its partner and has not called on the guarantee of the loan payment during the negotiation process. If a restructuring is not successfully completed, Global will call on its rights under the guarantee.

47

**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 June 30, 2005:**
                    
Operating Revenues
  $—  $1,278  $37  $(255) $1,060 
Operating Expenses
   —   1,182   28   (255)  955                  
Operating Income
   —   96   9   —   105 
Other Income
   36   30   1   (37)  30 
Other Deductions
   —   (12)  —   —   (12)
Equity (Losses) Earnings of Subsidiaries
   (127)  (182)  —   309   — 
Interest Expense
   (38)  (17)  (6)  35   (26)
Income Taxes
   2   (41)  —   (2)  (41)
Loss on Discontinued Operations, Including Loss on Disposal, Net of tax
   —   —   (183)  —   (183)                 
Net (Loss) Income
  $(127) $(126) $(179) $305  $(127)                 
**For the Quarter Ended June 30, 2004:**
                    
Operating Revenues
  $—  $1,200  $27  $(237) $990 
Operating Expenses
   —   1,148   24   (235)  937                  
Operating Income (Loss)
   —   52   3   (2)  53 
Other Income
   25   73   —   (25)  73 
Other Deductions
   —   (17)  —   —   (17)
Equity Earnings (Losses) of Subsidiaries
   50   (11)  —   (39)  — 
Interest Expense
   (27)  (8)  (11)  24   (22)
Income Taxes
   4   (36)  5   —   (27)
Loss on Discontinued Operations, Net of tax
   —   —   (8)  —   (8)                 
Net (Loss) Income
  $52  $53  $(11) $(42) $52                                      
48

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**
  **Power** **GuarantorSubsidiaries** **OtherSubsidiaries** **ConsolidatingAdjustments** **Consolidated Total**  **(Millions)**
**For the Six Months Ended June 30, 2005:**
                    
Operating Revenues
  $—  $3,227  $71  $(508) $2,790 
Operating Expenses
   —   2,935   54   (507)  2,482                  
Operating Income (Loss)
   —   292   17   (1)  308 
Other Income
   67   61   1   (68)  61 
Other Deductions
   —   (20)  —   —   (20)
Equity Earnings (Losses) of Subsidiaries
   (19)  (191)  —   210   — 
Interest Expense
   (70)  (34)  (17)  67   (54)
Income Taxes
   3   (126)  1   (2)  (124)
Loss on Discontinued Operations, including Loss on Disposal Net of tax
   —   —   (190)  —   (190)                 
Net Income (Loss)
  $(19) $(18)  (188) $206  $(19)                 
**For the Six Months Ended June 30, 2004:**
                    
Operating Revenues
  $—  $3,109  $49  $(470) $2,688 
Operating Expenses
   —   2,843   44   (469)  2,418                  
Operating Income (Loss)
   —   266   5   (1)  270 
Other Income
   38   104   —   (38)  104 
Other Deductions
   —   (26)  (5)  —   (31)
Equity Earnings (Losses) of Subsidiaries
   171   (25)  —   (146)  — 
Interest Expense
   (60)  (17)  (14)  39   (52)
Income Taxes
   12   (129)  6   —   (111)
Loss on Discontinued Operations, Net of tax
   —   —   (19)  —   (19)                 
Net Income (Loss)
  $161  $173  $(27) $(146) $161                  
**For the Six Months Ended June 30, 2005:**
                    
Net Cash (Used In) Provided By Operating Activities
  $(1,306) $246  $1,103  $385  $428 
Net Cash Provided By (Used In) Investing Activities
  $208  $34  $(48) $(514) $(320)
Net Cash Provided By (Used In) Financing Activities
  $1,100  $(273) $(1,054) $129  $(98)
**For the Six Months Ended June 30, 2004:**
                    
Net Cash Provided By (Used In) Operating Activities
  $42  $657  $(77) $(245) $377 
Net Cash Provided By (Used In) Investing Activities
  $258  $(586) $(103) $165  $(266)
Net Cash (Used In) Provided By FinancingActivities
  $(300) $(50) $181  $48  $(121)
**As of June 30, 2005:**
                    
Current Assets
  $2,748  $2,654  $291  $(3,902) $1,791 
Property, Plant and Equipment, net
   139   3,074   1,500   1   4,714 
Investment in Subsidiaries
   3,353   456   —   (3,809)  — 
Noncurrent Assets
   206   1,367   113   (219)  1,467                  
Total Assets
  $6,446  $7,551  $1,904  $(7,929) $7,972                  
Current Liabilities
  $615  $3,454  $1,393  $(3,992) $1,470 
Noncurrent Liabilities
   55   878   9   (216)  726 
Long-Term Debt
   2,816   —   —   —   2,816 
Member’s Equity
   2,960   3,219   502   (3,721)  2,960                  
Total Liabilities and Member’s Equity
  $6,446  $7,551  $1,904  $(7,929) $7,972                                      
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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                                      
50

**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 and the New Jersey Department of Environmental Protection (NJDEP). Exelon and PSEG also made the filings required under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR) and Exelon filed a private letter ruling on the transfer of nuclear decommissioning funds with the Internal Revenue Service. Additional applications and notices will be filed in the upcoming 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.

      The BPU scheduled public hearings starting in October 2005 in accordance with a timetable for the regulatory approval process that was established by an order of the Administrative Law Judge (ALJ) in

51

a proceeding on April 5, 2005. The timetable provides for the ALJ to issue an initial decision by February 26, 2006. Thereafter, pursuant to the provisions of the New Jersey Administrative Procedure Act, a decision from the BPU could reasonably be expected by March 23, 2006. 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 PSE&G's competition, employees, customers, rates or reliability due to the Merger.

      On June 30, 2005, intervenors filed testimony with the PAPUC regarding the proposed Merger in accordance with a timetable for the regulatory approval process in Pennsylvania that had been established by an order of the ALJ in a proceeding before the PAPUC. The current timetable provides for a hearing to commence on September 12, 2005 and it is expected that the ALJ will issue an initial decision on or after November 7, 2005. Thereafter, a decision from the PAPUC can be expected in January 2006 or February 2006 if the case is not settled at an earlier date.

      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 near future. 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.

      The procedural schedules for both the PAPUC and BPU proceedings include opportunities for settlement discussions with the consumer advocacy groups and other interested parties during the course of the proceedings. Exelon and PSEG will endeavor to settle differences of opinion among the administrative litigants during the course of the proceedings if they are able to do so on satisfactory terms.

      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 should 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. 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.

**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 six months of 2005 and expectations for the full-year 2005 and beyond.

      For the six months ended June 30, 2005, PSEG had Income from Continuing Operations of $393 million, or $1.62 diluted per share. PSEG continues to project Income from Continuing Operations for 2005 of $3.15 to $3.35 per share, reflecting improved operations at Power's generating facilities as

52

compared to 2004 and margin improvements through the expiration of existing sales contracts and the realization of current and anticipated higher market prices. PSEG expects Earnings Per Share in 2005 to be reduced by additional shares outstanding primarily due to the impact of the issuance of shares of common stock in November 2005 related to its participating equity securities. 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.

**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.

      PSE&G provides electricity under two types of basic generation service (BGS) for customers who 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.

      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.
      The cost of energy supply for both gas and electricity is passed through by PSE&G to its customers. On October 5, 2004, the BPU approved a 3% increase, effective for one year commencing October 1, 2004, in PSE&G's residential gas commodity charge to cover the higher cost of natural gas. PSE&G activated a 2.5% self-implementing increase effective February 1, 2005. On May 27, 2005, PSE&G filed a motion with the BPU seeking increases in its residential gas commodity charge to cover the higher cost of natural gas and in its balancing charge to cover the cost of providing storage and peaking services. The combined increase, if approved, would be approximately 10.6% and would be effective October 1, 2005.

      On April 24, 2005, PSE&G placed a new third bank of transformers into service at its Branchburg, New Jersey switching station. The operational limits, or ratings, of the existing banks of transformers had been reduced in March 2004 to avoid overheating in the units. Prior to the reduction, the two existing transformer banks had a capacity of approximately 1,600 MW. The additional bank increased the total capacity at Branchburg to 2,150 MW.

      For the six months ended June 30, 2005, PSE&G had Net Income of $167 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.

53

**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, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) are regulated by the FERC. Through its subsidiaries, Power seeks to balance the output of its generating capacity, fuel requirements and supply obligations through integrated energy marketing and trading, enhance its ability to produce low-cost energy through efficient nuclear operations and pursue modest growth in the Region based on market conditions.

      Power's objective is to enter into load-serving contracts, firm sales and trading positions sufficient to hedge at least 75% of its anticipated output over an 18-month to 24-month horizon. Power has achieved this objective through a combination of contracts related to the BGS auctions, contracts 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 will continue 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 continues to believe that hedging approximately75% of its anticipated generation output is an appropriate way to reduce the volatility of its earnings.

      On May 27, 2005, Power entered into an agreement to sell its electric generation facility located in Waterford, Ohio (Waterford) to a subsidiary of American Electric Power Company, Inc. (AEP). 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 is $220 million. The proceeds, together with anticipated reduction in tax liability, areapproximately $300 million, which will be used to retire debt at Power and PSEG. 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 will also receive payments for reliability services provided by the Sewaren Station, Units 1, 2, 3 and 4 and Hudson Station, Unit 1. Such payments will be net of operating margins at the units.

      Effective June 1, 2005, Power retired its oil-fired, steam Units 7 and 8 in Kearny, New Jersey as it no longer considered them to be economically viable and the PJM System Operator concluded that the units were no longer needed for system reliability.

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

      A key factor in Power's ability to achieve its objectives is its capability to operate its nuclear and fossil stations at sufficient capacity to avoid the need to purchase higher-priced electricity to satisfy its obligations. Concurrently with the signing of the Merger Agreement, Power entered into an Operating Services Contract (OSC) with Exelon Generation, LLC (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 its 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.

      Beyond 2005, Power believes that the rise in power prices over the past several years has created a favorable environment to enter into future power sales contracts. This should result in growth in gross margin, and should help support earnings growth over the next several years.

      For the six months ended June 30, 2005, Power had Income from Continuing Operations of $171 million. Power expects Income from Continuing Operations to range from $335 million to $385 million

54

in 2005. This increase as compared to 2004 reflects anticipated improvements in Power's Nuclear and Fossil operations, anticipated higher margins as existing contracts expire, the realization of current and anticipated higher market prices and additional generation going into service. It is expected that these improvements will be partially offset by higher depreciation expense. For the six months ended June 30, 2005, Power had a Net Loss of $19 million, which includes a Loss from Discontinued Operations of $190 million related to Waterford, discussed above. It is expected that costs associated with the proposed Merger could reduce 2005 results, which is not included in the earnings projection noted 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 first half of 2005, Energy Holdings had Net Income of $101 million. Energy Holdings expects Income from Continuing Operations for 2005 to range from $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.

      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.

      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 June 30, 2005, Resources' gross investment in leased aircraft is approximately $36 million.

      Resources continues to monitor credit concerns with respect to certain lessees in its portfolio. In addition, Resources is monitoring issues regarding the accounting and tax treatment of certain leases in its portfolio. For additional information, see Note 5. Commitments and Contingent Liabilities of the Notes.

55

**RESULTS OF OPERATIONS**

      The results for PSEG, PSE&G, Power and Energy Holdings for the quarter and six months ended June 30, 2005 and 2004 are presented below:
  **Earnings (Losses)**  **Quarters EndedJune 30,** **Six Months EndedJune 30,**  **2005** **2004** **2005** **2004**  **(Millions)**
PSE&G
    $49     $63     $167     $188 
Power
     56      60      171      180 
Energy Holdings:
                
Global
     25      9      82      58 
Resources
     (1)     14      22      16 
Other (A)
     (2)     (2)     (3)     (5)                         
Total Energy Holdings
     22      21      101      69 
Other (B)
     (26)     (17)     (46)     (28)                         
**PSEG Income from Continuing Operations**
     101      127      393      409 
Loss from Discontinued Operations, including Loss on Disposal (C)
     (183)     (3)     (190)     (14)                         
**PSEG Net (Loss) Income**
    **$****(82****)**    **$****124**     **$****203**     **$****395**                                            **Contribution to PSEG Earnings Per Share (Diluted) (D)**  **Quarters EndedJune 30,** **Six Months EndedJune 30,**  **2005** **2004** **2005** **2004**
PSE&G
    $0.20     $0.26     $0.69     $0.79 
Power
     0.23      0.25      0.70      0.76 
Energy Holdings:
                
Global
     0.10      0.04      0.34      0.24 
Resources
     —      0.06      0.09      0.06 
Other (A)
     (0.01)     (0.01)     (0.01)     (0.01)                         
Total Energy Holdings
     0.09      0.09      0.42      0.29 
Other (B)
     (0.10)     (0.07)     (0.19)     (0.12)                         
**PSEG Income from Continuing Operations**
     0.42      0.53      1.62      1.72 
Loss from Discontinued Operations, including Loss on Disposal (C)
     (0.76)     (0.01)     (0.78)     (0.06)                         
**PSEG Net (Loss) Income**
    **$****(0.34****)**    **$****0.52**     **$****0.84**     **$****1.66**                                             (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 $26 million or $0.11 per share decrease in Income from Continuing Operations for the quarter was primarily due to lower demand from commercial and industrial customers and higher operations and maintenance costs at PSE&G, a $15 million, after-tax, write-off at Resources for its UAL lease

56

investment and lower gains realized on the Nuclear Decommissioning Trust Funds at Power. In addition, Merger-related costs of approximately $14 million, net of tax, at PSEG and Power and higher interest expense at the PSEG parent level contributed to the decline in Income from Continuing Operations. Partially offsetting the decreases were an overall improvement in operations at Power, reflecting less congestion and nuclear plant outage days in 2005 and improved earnings at Global from its South American distribution investments and stronger foreign currency exchange rates.

      The $16 million or $0.10 per share decrease in Income from Continuing Operations for the six months was primarily due to lower earnings at PSE&G and Power, as discussed above, as well as to Merger-related costs of approximately $16 million, net of tax at PSEG and Power. Partly offsetting the decreases were higher earnings at Global due to improved operations and increased ownership at TIE, as well as the reasons discussed above, and the absence of a $17 million write-down in 2004 of the carrying value of the leveraged lease investment in the Collins generation facility at Resources which more than offset the $15 million write-off of the UAL lease investment in June 2005.

      The decreases in Net Income for the quarter and six months ended June 30, 2005 included changes of $175 million and $171 million, respectively, from the Loss from Discontinued Operations at Power for the sale of Waterford and a decrease of $5 million in both the second quarter and six month period ended June 30, 2005 from Income from Discontinued Operations at Energy Holdings from the sale of its majority interest in Carthage Power Company in 2004.

**PSEG**
  **For theQuarters EndedJune 30,**         **For theSix MonthsEndedJune 30,**          **2005** **2004** **Increase(Decrease)** **%** **2005** **2004** **Increase(Decrease)** **%**      **(Millions)**         **(Millions)**    
Operating Revenues
    $2,442     $2,285     $157      7     $5,751     $5,513     $238      4 
Energy Costs
    $1,340     $1,250     $90      7     $3,214     $3,080     $134      4 
Operation and Maintenance
    $578     $534     $44      8     $1,174     $1,077     $97      9 
Depreciation and Amortization
    $179     $167     $12      7     $365     $335     $30      9 
Income from Equity Method Investments
    $30     $33     $(3)     (9)    $67     $61     $6      10 
Other Income
    $41     $80     $(39)     (49)    $84     $111     $(27)     (24)
Other Deductions
    $(21)    $(26)    $(5)     (19)    $(37)    $(44)    $(7)     (16)
Interest Expense
    $(206)    $(208)    $(2)     (1)    $(415)    $(420)    $(5)     (1)
Income Tax Expense
    $(59)    $(57)    $2      4     $(231)    $(245)    $(14)     (6)
Loss from Discontinued Operations, including Loss on Disposal, net of tax benefit
    $(183)    $(3)    $(180)     N/A     $(190)    $(14)    $(176)     N/A                                                                 
      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.

57

**PSE&G**
  **For theQuarters EndedJune 30,**         **For theSix MonthsEndedJune 30,**          **2005** **2004** **Increase(Decrease)** **%** **2005** **2004** **Increase(Decrease)** **%**      **(Millions)**         **(Millions)**    
Operating Revenues
    $1,441     $1,418     $23      2     $3,625     $3,600     $25      1 
Energy Costs
    $853     $824     $29      4     $2,277     $2,243     $34      2 
Operation and Maintenance
    $268     $258     $10      4     $563     $536     $27      5 
Depreciation and Amortization
    $128     $126     $2      2     $263     $253     $10      4 
Other Income
    $2     $3     $(1)     (33)    $4     $6     $(2)     (33)
Other Deductions
    $—     $—     $—      —     $(1)    $(1)    $—      — 
Interest Expense
    $(86)    $(91)    $(5)     (5)    $(170)    $(187)    $(17)     (9)
Income Tax Expense
    $(31)    $(31)    $—      —     $(117)    $(125)    $(8)     (6)                                
      **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 $23 million increase for the quarter ended June 30, 2005, as compared to the same period in 2004, was due to an increase of $30 million in commodity revenues, described below, offset by a $7 million decrease in delivery revenues. The $25 million increase for the six months ended June 30, 2005, as compared to the same period in 2004, was due to increases of $41 million in commodity revenues, described below, and $3 million in other operating revenues, primarily related to appliance service contracts, partially offset by a $19 milliondecrease in delivery revenues.

      ***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 Basic Gas Supply Service (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 $30 million increase in commodity revenues for the quarter ended June 30, 2005, as compared to the same period in 2004, was due to a $20 million increase in gas commodity revenues, due primarily to higher BGSS prices and a $10 million increase in electric commodity revenues, primarily due to increased prices.

      The $41 million increase in commodity revenues for the six months ended June 30, 2005, as compared to the same period in 2004, was due to a $49 million increase in gas commodity revenues, due primarily to higher BGSS prices, partially offset by an $8 million decrease in electric commodity revenues, primarily due to decreased prices.

      ***Delivery***

      The $7 million decrease in delivery revenues for the quarter ended June 30, 2005, as compared to the same period in 2004, was due to decreases of $4 million in electric revenues and $3 million in gas revenues. The $4 million decrease in electric delivery revenues was due primarily to lower volumes of $8 million offset by increased prices of $4 million due to increased Societal Benefits Clause (SBC) rates, primarily due to the Universal Service Fund (USF) component. The $3 million decrease in gas delivery revenues was primarily due to $4 million in lower rates due to the expiration of the Gas Cost

58

Underrecovery Adjustment (GCUA) clause in January 2005 and lower volume and demand revenues of $2 million. The GCUA rates are recorded with a corresponding offset in Energy Costs, described below. These decreases were offset by increased SBC revenues of $3 million, primarily due to the USF component. SBC rates are recorded with a corresponding offset in Operating Expenses, described below, resulting in no impact to Net Income.

      The $19 million decrease in delivery revenues for the six months ended June 30, 2005, as compared to the same period in 2004, was due to a $22 million decrease in gas delivery revenues, partially offset by a $3 million increase in electric delivery revenues. The $22 million decrease in gas delivery revenues was primarily due to lower volume and demand revenues of $26 million and $9 million in lower rates due to the expiration of the GCUA clause in January 2005. These decreases were offset by increased SBC revenues of $13 million, primarily due to the USF component, as described above. The $3 million increase in electric delivery revenues was due primarily to increased prices of $10 million due to increased SBC rates, primarily due to the USF component, offset by decreased volumes of $7 million.

      **Operating Expenses**

      ***Energy Costs***

      The $29 million increase for the quarter ended June 30, 2005, as compared to the same period in 2004, was comprised of increases of $18 million in electric costs and $11 million in gas costs. The electric increase is due to a $21 million increase related to higher prices for BGS and Non-Utility Generation (NUG) purchases partially offset by a $3 million decrease due to lower NUG volumes. The increase in gas costs was caused by a $19 million or 16% increase in gas prices offset by a $6 million decrease due to the expiration of the GCUA clause in January 2005, described above, and a $2 million decrease in sales volumes due primarily to lower interruptible sales.

      The $34 million increase for the six months ended June 30, 2005, as compared to the same period in 2004, was comprised of increases of $32 million in gas costs and $2 million in electric costs. The increase in gas costs was caused by a $62 million or 7% increase in gas prices offset by a $20 million decrease due to the expiration of the GCUA clause in January 2005, described above, and an $8 million decrease in sales volumes due primarily to lower sales to cogenerators. The electric increase is due to increases of $12 million due to higher prices for BGS and NUG purchases and $5 million due to higher BGS volumes, partially offset by a decrease of $15 million due to lower NUG volumes.

      ***Operation and Maintenance***

      The $10 million increase for the quarter ended June 30, 2005, as compared to the same period in 2004, was due primarily to increased SBC expenses of $7 million and $6 million in labor and fringe benefits due to increased wages and staffing.

      The $27 million increase for the six months ended June 30, 2005, as compared to the same period in 2004, was due primarily to increased SBC expenses of $22 million and $15 million in labor and fringe benefits due to increased wages and staffing. These were offset by decreases of $11 million in outside service costs due to lower regulatory charges and Demand Side Management expenses due to lower volumes.

      ***Depreciation and Amortization***

      The $2 million increase for the quarter ended June 30, 2005, as compared to the same period in 2004, was due primarily to a $2 million increase due to additional plant in service and a $2 million increase in the amortization of the Securitization regulatory asset offset by a $2 million decrease in software amortization.

      The $10 million increase for the six months ended June 30, 2005, as compared to the same period in 2004, was due primarily to a $6 million increase in the amortization of the Securitization regulatory asset, a $4 million increase due to additional plant in service and a $2 million increase in the amortization of the Remediation Adjustment Clause (RAC). These were offset by a $2 million decrease in software amortization.

59

      **Interest Expense**

      The $5 million decrease for the quarter ended June 30, 2005, as compared to the same period in 2004, was due to decreases of $8 million due to lower average interest rates and lower amounts of long-term debt outstanding. This was offset by increases of $2 million due to higher short-term interest rates and higher amounts of short-term debt outstanding.

      The $17 million decrease for the six months ended June 30, 2005, as compared to the same period in 2004, was due to decreases of $20 million due to lower average interest rates and lower amounts of long-term debt outstanding. This was offset by increases of $4 million due to higher short-term interest rates and higher amounts of short-term debt outstanding.

      **Income Taxes**

      The $8 million decrease for the six months ended June 30, 2005, as compared to the same period in 2004, was primarily due to lower pre-tax income.

**Power**
  **For theQuarters EndedJune 30,**         **For theSix MonthsEndedJune 30,**          **2005** **2004** **Increase(Decrease)** **%** **2005** **2004** **Increase(Decrease)** **%**      **(Millions)**             **(Millions)**        
Operating Revenues
    $1,060     $990     $70      7     $2,790     $2,688     $102      4 
Energy Costs
    $688     $677     $11      2     $1,958     $1,908     $50      3 
Operation and Maintenance
    $235     $234     $1      —     $462     $461     $1      — 
Depreciation and Amortization
    $32     $26     $6      23     $62     $49     $13      27 
Other Income
    $30     $73     $(43)     (59)    $61     $104     $(43)     (41)
Other Deductions
    $(12)    $(17)    $(5)     (29)    $(20)    $(31)    $(11)     (35)
Interest Expense
    $(26)    $(22)    $4      18     $(54)    $(52)    $2      4 
Income Tax Expense
    $(41)    $(27)    $14      52     $(124)    $(111)    $13      12 
Loss from Discontinued Operations, including Loss on Disposal, net of tax benefit
    $(183)    $(8)    $175      N/A     $(190)    $(19)    $171      N/A                                 
      **Operating Revenues**

      The $70 million increase for the quarter ended June 30, 2005, as compared to the same period in 2004, was due to increases of $36 million in generation revenues, $23 million in gas supply revenues and $11 million in trading revenues.

      The $102 million increase for the six months ended June 30, 2005, as compared to the same period in 2004, was due to increases of $15 million in generation revenues, $69 million in gas supply revenues and $18 million in trading revenues.

      ***Generation***

      The increase of $36 million in generation revenues for the quarter ended June 30, 2005, as compared to the same period in 2004, was primarily due to an increase of approximately $27 million related to Reliability Must-Run (RMR) revenues which commenced in 2005 for certain of Power's generating facilities, combined with a net increase of approximately $9 million as revenues from new contracts and increased sales into the various power pools more than offset decreased revenues due to reduced load being served under the fixed-priced BGS contracts.

      The increase of $15 million in generation revenues for the six months ended June 30, 2005, as compared to the same period in 2004, was primarily due to an increase of approximately $34 million

60

related to RMR revenues. This increase was partially offset by a net decrease of approximately $19 million due to reduced load being served under the fixed-priced BGS contracts partially offset by revenues from new contracts and increased sales into the various power pools.

      ***Gas Supply***

      The $23 million and $69 million increase in gas supply revenues for the quarter and six months ended June 30, 2005, respectively, as compared to the same periods in 2004, was primarily due to higher gas prices under the BGSS contract partially offset by decreased sales volumes mainly due to lower demand by PSE&G.

      ***Trading***

      The $11 million and $18 million increase in trading revenues for the quarter and six months ended June 30, 2005, respectively, as compared to the same periods in 2004, was primarily due to improved 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 $11 million and $50 million increase for the quarter and six months ended June 30, 2005, respectively, as compared to the same periods in 2004, was primarily due to higher prices for gas used to satisfy Power's BGSS obligations which were partially offset by decreased costs of generation primarily due to decreased congestion costs as compared to 2004.

      ***Operation and Maintenance***

      The $1 million increase for the quarter ended June 30, 2005, as compared to the same period in 2004, was primarily due to a $10 million restructuring charge recorded in June 2005 related to Nuclear's workforce realignment plan, partially offset by $6 million of lower real estate taxes. For additional information related to the restructuring charge, see Note 5. Commitments and Contingent Liabilities of the Notes.

      The $1 million increase for the six months ended June 30, 2005, as compared to the same period in 2004, was primarily due to a $10 million restructuring charge 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 2005 and June 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 $6 million and $13 million increase for the quarter and six months ended June 30, 2005, respectively, as compared to the same periods in 2004, was primarily due to the Lawrenceburg facility being placed into service in June 2004.

      **Other Income**

      The $43 million decrease in Other Income for each of the quarter and six months ended June 30, 2005, as compared to the same periods in 2004, was primarily due to decreased realized gains related to the NDT Funds.

      **Other Deductions**

      The $5 million decrease for the quarter ended June 30, 2005, as compared to the same period in 2004, was primarily due to decreased losses and expenses related to the NDT Funds.

61

      The $11 million decrease for the six months ended June 30, 2005, as compared to the same period in 2004, was primarily due to a write-off of $4 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.

      **Interest Expense**

      The $4 million increase for the quarter ended June 30, 2005, as compared to the same period in 2004, was primarily due to the Lawrenceburg facility being placed into service in June 2004 resulting in a decrease in capitalized interest.

      The $2 million increase for the six months ended June 30, 2005, as compared to the same period in 2004, was primarily due to a reduction in capitalized interest related to Lawrenceburg, partially offset by lower interest rates on new long-term debt financing that replaced non-recourse project level financing.

      **Income Taxes**

      The $14 million and $13 million increase for the quarter and six months ended June 30, 2005, respectively, as compared to the same periods in 2004, was primarily due to taxes related to higher pre-tax income and prior period adjustments recorded in 2004.

      **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 a loss on disposal of approximately $177 million for the initial write-down of its carrying amount of Waterford to its fair value less cost to sell. It is anticipated that the transaction will close during the second half of 2005. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information.

**Energy Holdings**
  **For theQuarters EndedJune 30,**         **For theSix MonthsEndedJune 30,**          **2005** **2004** **Increase(Decrease)** **%** **2005** **2004** **Increase(Decrease)** **%**      **(Millions)**             **(Millions)**        
Operating Revenues
    $327     $177     $150      85     $706     $390     $316      81 
Energy Costs
    $185     $48     $137      285     $349     $94     $255      271 
Operation and Maintenance
    $72     $50     $22      44     $149     $99     $50      51 
Depreciation and Amortization
    $14     $12     $2      17     $31     $25     $6      24 
Income from Equity Method Investments
    $30     $33     $(3)     (9)    $67     $61     $6      10 
Other Income
    $8     $2     $6      300     $18     $4     $14      350 
Other Deductions
    $(8)    $(9)    $(1)     (11)    $(12)    $(10)    $2      20 
Interest Expense
    $(62)    $(67)    $(5)     (7)    $(128)    $(130)    $(2)     (2)
Income Tax Expense
    $(1)    $(5)    $(4)     (80)    $(17)    $(26)    $(9)     (35)
Income from Discontinued Operations, including Gain on Disposal, net of tax
    $—     $5     $(5)     (100)    $—     $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 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. Discontinued Operations, Dispositions and Acquisitions of the Notes.

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      **Operating Revenues**

      The $150 million increase for the quarter ended June 30, 2005, as compared to the same period in 2004, was due to higher revenues at Global of $180 million, including a $153 million increase related to the consolidation of TIE commencing July 1, 2004, a $14 million increase related to Sociedad Austral de Electricidad S.A. (SAESA) in Chile due to higher energy sales volumes and a $9 million increase related to Electrownia Skawina S.A. (Skawina) in Poland due to higher energy sales in the spot market and higher Polish Zloty foreign exchange rate offset by an $11 million decrease related to the deconsolidation of Dhofar Power. Offsetting the increase were lower revenues at Resources of $29 million primarily due to a $22 million pre-tax write-off of its leveraged lease investment with UAL.

      The $316 million increase for the six months ended June 30, 2005, as compared to the same period in 2004, was due to higher revenues at Global of $322 million, including a $279 million increase related to the consolidation of TIE commencing July 1, 2004, a $24 million increase related to SAESA due to higher energy sales volumes and a $19 million increase related to Skawina due to higher energy sales in the spot market and higher Polish Zloty foreign exchange rates offset by a $12 million decrease related to the deconsolidation of Dhofar Power. Offsetting the increase were lower revenues at Resources of $6 million primarily due to a $22 million pre-tax write-off of its UAL Lease investment offset by a $17 million pre-tax charge recorded in 2004 to reduce the carrying value of the Collins lease.

      **Operating Expenses**

      ***Energy Costs***

      The $137 million increase for the quarter ended June 30, 2005, as compared to the same period in 2004, was primarily due to a $120 million increase related to the consolidation of TIE commencing July 1, 2004, an $11 million increase related to SAESA due to significant increases in energy costs and a $6 million increase related to Skawina, offset by a $4 million decrease related to the deconsolidation of Dhofar Power.

      The $255 million increase for the six months ended June 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 $21 million increase related to SAESA due to significant increases in energy costs and a $14 million increase related to Skawina, offset by a $4 million decrease related to the deconsolidation of Dhofar Power.

      ***Operation and Maintenance***

      The $22 million increase for the quarter ended June 30, 2005, as compared to the same period in 2004, was primarily due to a $17 million increase related to the consolidation of TIE commencing July 1, 2004 a $5 million increase related to SAESA and a $2 million increase related to Skawina, offset by a $2 million decrease related to the deconsolidation of Dhofar Power.

      The $50 million increase for the six months ended June 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, an $8 million increase related to SAESA and a $5 million increase related to Skawina, offset by a $1 million decrease related to the deconsolidation of Dhofar Power.

      ***Depreciation and Amortization***

      The $2 million increase for the quarter ended June 30, 2005, as compared to the same period in 2004, was primarily due to a $4 million increase related to the consolidation of TIE commencing July 1, 2004 offset by a $2 million decrease related to the deconsolidation of Dhofar Power.

      The $6 million increase for the six months ended June 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 $2 million decrease related to the deconsolidation of Dhofar Power.

63

      **Income from Equity Method Investments**

      The $3 million decrease for the quarter ended June 30, 2005, as compared to the same period in 2004, was primarily due to a $2 million decrease related to the sale of Global's equity interest in MPC in December 2004, a $1 million decrease related to the consolidation of TIE commencing July 1, 2004, offset by 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 of a 35% interest which reduced Global's investment to 46% in April 2005.

      The $6 million increase for the six months ended June 30, 2005, as compared to the same period in 2004, was primarily due to a $3 million increase due to stronger results in South America, a $3 million loss recognized in the six months of 2004 from TIE, which was accounted for under the equity method of accounting until June 30, 2004, and a $2 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 a $2 million decrease related to the sale of Global's equity interest in MPC in December 2004.

      **Other Income**

      The $6 million increase for the quarter ended June 30, 2005, as compared to the same period in 2004, was primarily due to foreign currency transaction gains of $8 million due to strengthening of the U.S. Dollar relative to the Polish Zloty on Global's investment in ELCHO, offset by a $1 million change in derivative fair value related to foreign exchange forwards at SAESA which expired in 2004.

      The $14 million increase for the six months ended June 30, 2005, as compared to the same period in 2004, was primarily due to foreign currency transaction gains of $13 million due to strengthening of the U.S. Dollar relative to the Polish Zloty on Global's investment in ELCHO.

      **Interest Expense**

      The $5 million decrease for the quarter ended June 30, 2005, as compared to the same period in 2004, was due to a $3 million decrease related to the deconsolidation of Dhofar Power and an $8 million decrease related to Resources, offset by a $5 million increase due to the consolidation of TIE commencing July 1, 2004.

      The $2 million decrease for the six months ended June 30, 2005, as compared to the same period in 2004, was due to a $4 million decrease related to the deconsolidation of Dhofar Power and an $8 million decrease related to Resources, offset by a $10 million increase due to the consolidation of TIE commencing July 1, 2004.

      **Income Taxes**

      The $4 million and $9 million decrease for the quarter and six months ended June 30, 2005, respectively, as compared to the same periods in 2004, was primarily due to a lower effective rate for Global due to a change in mix of domestic and international earnings.

      **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

64

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 June 30, 2005 and December 31, 2004 and for the quarters and six months ended June 30, 2005 and 2004.
          **For the Quarters Ended June 30,** **For the Six Months Ended June 30,**  **Total Capitalat Risk (A)As of** **EBIT (B)** **Non-RecourseInterest (C)** **EBIT (B)** **Non-RecourseInterest (C)**  **June 30,2005** **December 31,2004** **2005** **2004** **2005** **2004** **2005** **2004** **2005** **2004**  **(Millions)**                                        
**Region:**
                                        
North America
  $433   $427   $21   $9   $5   $—   $68   $64   $10   $— 
South America
   1,601    1,581    36    35    8    2    74    70    18    10 
Europe
   206    209    14    7    9    8    36    20    18    16 
India and Oman
   74    94    5    3    1    4    10    10    4    8 
Asia Pacific
   6    6    1    4    —    —    5    8    —    — 
Global G&A—Unallocated
   —    —    (8)   (9)   —    —    (14)   (16)   —    —                                          
Total
  $2,320   $2,317   $69   $49   $23   $14   $179   $156   $50   $34                                          
Total Global EBIT
          $69   $49           $179   $156         
Interest Expense
           (43)   (39)           (88)   (77)        
Income Taxes
           —    (1)           (5)   (19)        
Minority Interest
           (1)   —            (4)   (2)                                                 
Income from Continuing Operations
          $25   $9           $82   $58                                                                                          (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 six months ended June 30, 2005, PSEG's operating cash flow decreased by approximately $260 million from $832 million to $572 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 decreased approximately $123 million from $179 million to $56 million for the six months ended June 30, 2005, as compared to the same period in 2004, primarily due to higher funding for employee benefit plans and higher under recovery of SBC related costs.

65

      **Power**

      Power's operating cash flow increased approximately $51 million from $377 million to $428 million for the six months ended June 30, 2005, as compared to the same period in 2004, due to decreased working capital needs offset by higher funding for employee benefit plans.

      **Energy Holdings**

      Energy Holdings' operating cash flow decreased approximately $149 million from $298 million to $149 million for the six months ended June 30, 2005, as compared to the same period in 2004, due primarily to the timing of tax benefits and payments associated with the termination of certain leases in 2004 and sales of certain Global investments in 2005.

**Common Stock Dividends**

      Dividend payments on common stock for the quarters ended June 30, 2005 and 2004 were $0.56 and $0.55 per share, respectively, and totaled approximately $133 million and $130 million, respectively. Dividend payments on common stock for the six months ended June 30, 2005 and 2004 were $1.12 and $1.10 per share, respectively, and totaled approximately $267 million and $260 million, respectively. Future dividends declared will be dependent upon PSEG's future earnings, cash flows, financial requirements, alternative investment opportunities and other factors. On July 19, 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 June 30, 2005, PSEG and its subsidiaries had a total of approximately $2.7 billion of committed credit facilities with approximately $1.9 billion of available liquidity under these facilities. In addition, PSEG and PSE&G have access to certain uncommitted credit facilities. PSEG had $27 million outstanding and PSE&G had $110 million outstanding under these uncommitted facilities as of June 30, 2005. All of the credit facilities below have been modified or structured to accommodate the potential

66

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 of6/30/2005** **AvailableLiquidity as of6/30/2005**  **(Millions)**
**PSEG:**
                
4-year Credit Facility
    April 2008    $450     CP Support/Funding/Lettersof Credit    $334     $116 
5-year Credit Facility
    May 2010    $650     CP Support/Funding/Lettersof Credit    $—     $650 
Uncommitted Bilateral Agreement
    N/A     N/A     Funding    $27      N/A 
**PSE&G:**
                
5-year Credit Facility
    June 2009    $600     CP Support/Funding/Lettersof Credit    $160     $440 
Bilateral Term Loan
    May 2006    $100     Funding    $100     $— 
Uncommitted Bilateral Agreement
    N/A     N/A     Funding    $110      N/A 
**PSEG and Power:**
                
3-year Credit Facility(A)
    April 2007    $600     CP Support/Funding/Lettersof Credit    $17(B)    $583 
**Power:**
                
3-year Credit Facility
    August 2005    $25     Funding/Lettersof Credit    $—     $25 
Bilateral Credit Facility
    March 2010    $100     Funding/Lettersof Credit    $65(B)    $35 
**Energy Holdings:**
                
5-year Credit Facility(C)
    June 2010    $150     Funding/Lettersof Credit    $55(B)    $95                 
(A) PSEG/Power co-borrower facility.

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

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

      **PSEG**

      PSEG believes it has sufficient liquidity to fund its short-term cash needs. On May 31, 2005, PSEG established a new 5-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. PSEG does not plan to replace these facilities.

      **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 that expires in May 2006.

      **Power**

      As of June 30, 2005, Power had loaned $93 million of excess cash to PSEG.

      In addition, ER&T maintains agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power's

67

credit rating to below investment grade, 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. Providing this support would increase Power's costs of doing business and could restrict the ability of ER&T to manage and optimize Power's asset portfolio. Power believes it has sufficient liquidity to meet any required posting of collateral resulting from a credit rating downgrade. See Note 5. Commitments and Contingent Liabilities of the Notes for further information.

      **Energy Holdings**

      As of June 30, 2005, Energy Holdings had loaned $57 million of excess cash to PSEG. In addition, Energy Holdings and its subsidiaries had $245 million in cash, including $167 million invested offshore.

      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 six months ended June 30, 2005, PSEG issued approximately 654,000 shares under its Dividend Reinvestment Program and Employee Stock Purchase Plan for approximately $37 million.

      **PSE&G**

      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.

      In June 2005 and March 2005, PSE&G Transition Funding LLC (Transition Funding) repaid approximately $32 million and $34 million, respectively, 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 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.

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      **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 June 30, 2005, PSEG's ratio of debt to capitalization (as defined above) was 58.3%. PSEG expects to continue to meet the financial covenants.

      **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 June 30, 2005, PSE&G's ratio of long-term debt to total capitalization (as defined above) was 47.1%.

      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 June 30, 2005, PSE&G's Mortgage coverage ratio was 5.15 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, a 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 June 30, 2005, Power's ratio of debt to capitalization (as defined above) was 46.6%.

      **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 requirements under this test.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.

      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 June 30, 2005, Energy Holdings' coverage of this covenant was 2.67. Additionally, Energy Holdings must maintain a ratio of net debt to EBITDA of less than 5.25. As of June 30, 2005, Energy Holdings' ratio under this covenant was 4.25. 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

69

pledge of Energy 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 by an agencyshould be evaluated independently of the other agencies' ratings. The ratings should not be construed as an indication to buy, hold or sell any security.
      **Moody's (A)**    **S&P (B)**    **Fitch (C)**                  
**PSEG:**
            
Preferred Securities
    Baa3    BB+(WD)    BBB–(P)      
Commercial Paper
    P2    A3(WD)    F2      
**PSE&G:**
            
Mortgage Bonds
    A3    A–(WD)    A      
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.
      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.
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**Other Comprehensive Loss**

      **PSEG, Power and Energy Holdings**

      For the six months ended June 30, 2005, PSEG, Power and Energy Holdings had an Other Comprehensive Loss of $119 million, $104 million and $20 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.

**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 for PSEG, PSE&G, Power and Energy Holdings are consistent with amounts disclosed in the Annual Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31, 2004.

      **PSE&G**

      During the six months ended June 30, 2005, PSE&G made approximately $239 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $239 million excludes approximately $16 million spent on cost of removal, net of salvage.

      **Power**

      During the six months ended June 30, 2005, Power made approximately $208 million of capital expenditures (excluding $19 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 six months ended June 30, 2005, Energy Holdings incurred approximately $18 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 DISCLOSURES ABOUT MARKET RISK**

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

      The market risk inherent in PSEG's, PSE&G's, Power's and Energy Holdings' market risk sensitive instruments and positions is the potential loss arising from adverse changes in foreign currency exchange rates, commodity prices, equity security prices and interest rates as discussed in the Notes to 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,

71

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 Report on Form 10-Q for the quarter ended March 31, 2005.

**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.

      ***Trading***

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

72

**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 MTM VaR consists of mark-to-market derivatives that are economic hedges, some of which qualify for hedge accounting. The mark-to-market derivatives that are not hedges are included in the trading VaR.

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

      As of June 30, 2005 and December 31, 2004, trading VaR was approximately $2 million.
  **Trading VaR** **Non-TradingMTM VaR**  **(Millions)**
**For the Quarter Ended June 30, 2005**
        
*95% Confidence Level, One-Day Holding Period, One-Tailed:*
        
Period End
    $2     $16 
Average for the Period
    $2     $14 
High
    $4     $9 
Low
    $1     $22 
*99% Confidence Level, One-Day Holding Period, Two-Tailed:*
        
Period End
    $3     $25 
Average for the Period
    $4     $22 
High
    $7     $34 
Low
    $1     $14         
**Credit Risk**

      **Energy Holdings**

      ***Resources***

      Resources is the lessor of various aircraft to several domestic airlines, which included a Boeing B767 aircraft to 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, net of tax, charge in June 2005 to write off its entire investment. Following the write off, Resources' remaining gross investment in leased aircraft is approximately $36 million.

73

**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 June 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, mark-to-market activities represent a small portion of the total Operating Revenues for Power. Activities accounted for under the accrual method, including normal purchases and sales, account for the majority of the revenue. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices.

**Operating RevenuesFor the Quarter Ended June 30, 2005**
  **NormalOperations andHedging (A)** **Trading** **Total**  **(Millions)**            
**Mark-to-Market Activities:**
            
Unrealized Mark-to-Market Gains
            
Changes in Fair Value of Open Positions
    $7     $1     $8 
Origination Unrealized Gain at Inception
     —      —      — 
Changes in Valuation Techniques and Assumptions
     —      —      — 
Realization at Settlement of Contracts
     (15)     (1)     (16)                   
Total Change in Unrealized Fair Value
     (8)     —      (8)
Realized Net Settlement of Transactions Subject to Mark-to-Market
     15      1      16 
Broker Fees and Other Related Expenses
     —      (2)     (2)                   
Net Mark-to-Market Gains
     7      (1)     6 
**Accrual Activities**
            
Accrual Activities—Revenue, Including Hedge Reclassifications
     1,054      —      1,054                    
**Total Operating Revenues**
    $1,061     $(1)    $1,060                                
74

**Operating RevenuesFor the Six Months Ended June 30, 2005**
  **NormalOperations andHedging (A)** **Trading** **Total**  **(Millions)**            
**Mark-to-Market Activities:**
            
Unrealized Mark-to-Market Gains
            
Changes in Fair Value of Open Positions
    $37     $13     $50 
Origination Unrealized Gain at Inception
     —      —      — 
Changes in Valuation Techniques and Assumptions
     —      —      — 
Realization at Settlement of Contracts
     (18)     (27)     (45)                   
Total Change in Unrealized Fair Value
     19      (14)     5 
Realized Net Settlement of Transactions Subject to Mark-to-Market
     18      27      45 
Broker Fees and Other Related Expenses
     —      (4)     (4)                   
Net Mark-to-Market Gains
     37      9      46 
**Accrual Activities**
            
Accrual Activities—Revenue, Including Hedge Reclassifications
     2,744      —      2,744                    
**Total Operating Revenues**
    $2,781     $9     $2,790                                (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.

**Energy Contract Net Assets/LiabilitiesAs of June 30, 2005**
  **NormalOperationsandHedging** **Trading** **Total**  **(Millions)**
Mark-to-Market Energy Assets
            
Current Assets
    $148     $90     $238 
Noncurrent Assets
     20      22      42                    
Total Mark-to-Market Energy Assets
    $168     $112     $280                    
Mark-to-Market Energy Liabilities
            
Current Liabilities
    $(220)    $(97)    $(317)
Noncurrent Liabilities
     (236)     (27)     (263)                   
Total Mark-to-Market Energy Liabilities
    $(456)    $(124)    $(580)                   
**Total Mark-to-Market Energy Contract Net Liabilities**
    $(288)    $(12)    $(300)                               
75

      The following table presents the maturity of net fair value of mark-to-market energy trading contracts.

**Maturity of Net Fair Value of Mark-to-Market Energy Trading ContractsAs of June 30, 2005**
  **Maturities within**  **2005** **2006** **2007** **2008-2009** **Total**  **(Millions)**
Trading
    $(10)    $1     $(5)    $2     $(12)
Normal Operations and Hedging
     (36)     (86)     (96)     (70)     (288)                               
**Total Net Unrealized Losses on Mark-to-Market Contracts**
    **$****(46****)**    **$****(85****)**    **$****(101****)**    **$****(68****)**    **$****(300****)**                                                   
      Wherever possible, fair values for these contracts were obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques were employed using assumptions reflective of current market rates, yield curves and forward prices as applicable to interpolate certain prices. The effect of using such modeling techniques is not material to Power's financial results.

      **PSEG, Power and Energy Holdings**

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

**Cash Flow Hedges Included in OCIAs of June 30, 2005**
  **AccumulatedOtherComprehensiveLoss** **Portion Expectedto be Reclassifiedin next 12 months**  **(Millions)**
**Cash Flow Hedges Included in OCI**
        
Commodities
    $(240)    $(108)
Interest Rates
     (79)     (20)
Foreign Currency
     —      —              
**Net Cash Flow Hedge Loss Included in OCI**
    $(319)    $(128)                     
      **Power**

      ***Credit Risk***

      The following table provides information on Power's credit exposure, net of collateral, as of June 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.

76

**Schedule of Credit Risk Exposure on Energy Contracts Net AssetsAs of June 30, 2005**
**Rating** **CurrentExposure** **SecuritiesHeld asCollateral** **NetExposure** **Number ofCounterparties>10%** **NetExposure ofCounterparties>10%**      **(Millions)**         **(Millions)**                    
Investment Grade—External Rating
    $212     $90     $208    1   $60 
Non-Investment Grade—External Rating
     33      27      14    —    — 
Investment Grade—No External Rating
     4      2      3    —    — 
Non-Investment Grade—No External Rating
     47      —      47    1    39                            
Total
    $296     $119     $272    2   $99                                                
      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 June 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 second 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 Report on Form 10-Q for the quarter ended March 31, 2005 is updated below.

**PSE&G**

      ***2004 10-K, page 38.*** On November 15, 2001, Consolidated Edison Company of New York, Inc. (Con Edison) filed a complaint against PSE&G with the FERC asserting that PSE&G had breached agreements covering 1,000 MW of transmission. PSE&G denied the allegations set forth in the complaint. An Initial Decision issued by an ALJ in April 2002 upheld PSE&G’s claim in part but also accepted Con Edison’s contentions in part. On December 9, 2002, the FERC issued an order modifying the Initial Decision and remanding a number of issues to the ALJ for additional hearings, including issues related to the development of protocols to implement the findings of the December 9, 2002 order and regarding Phase II of the complaint. The ALJ issued an Initial Decision on thePhase II issues on June 11, 2003 and on August 2, 2004, the FERC issued its decision on Phase II issues. Those decisions were largely favorable to PSE&G; however, PSE&G did seek rehearing as to certain issues, as did Con Edison. Those rehearing applications are currently pending. The August 2, 2004 order required that PJM, NYISO, Con Edison and PSE&G meet for the purpose of developing operational protocols to implement the FERC’s directives. On February 18, 2005, NYISO, PJM and PSE&G submitted a joint compliance filing pursuant to the FERC’s August 2, 2004 decision. While Con Edison initially opposed the filing, it later withdrew its opposition. FERC approved the joint proposals on May 18, 2005 and they took effect on July 1, 2005. The matter is currently pending before the FERC, and PSEG and PSE&G are unable to predict the outcome of thisproceeding.

**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 34. (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 35. (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.
79

      
(10)
    Page 81. (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 81. (Power) PSEG Power Connecticut's filing with FERC on November 17, 2004, Docket No. ER05-231-000, to request RMR compensation.      
(12)
    Page 83. (PSE&G) JCP&L v. ACE, et. al complaint filed with the FERC on December 30, 2004, Docket No. EL05-50-000, seeking to terminate its construction obligations under the LDV Agreement.      
(13)
    Page 83. (PSE&G) Neptune Regional Transmission System, LLC v. PJM Interconnection, L.L.C. complaint filed with FERC on December 21, 2004, Docket No. EL05-48-000, alleging PJM impermissibly conducted an interconnection re-study triggered by generator retirements in PJM, which had the effect of increasing Neptune's cost exposure for network upgrades from approximately $4 million to $26 million.      
(14)
    Page 85. (Power) Power’s Petition for Review filed in the United States Court of Appeals for the District of Columbia Circuit on July 30, 2004 challenging the final rule of the United States Environmental Protection Agency entitled National Pollutant Discharge Elimination System—Final Regulations to Establish Requirements for Cooling Water Intake Structures at Phase II Existing Facilities,’ now transferred to and venued in the United States Court of Appeals for the Second Circuit with Docket No. 04-6696-ag.
**ITEM 4. SUBMISSION OF MATTERS TO AVOTE OF SECURITY HOLDERS**

      PSEG's Annual Meeting of Stockholders was held on July 19, 2005. Proxies for the meeting were solicited pursuant to Regulation 14A under the Securities Act of 1934. There was no solicitation of proxies in opposition to management's nominees as listed in the proxy statement and all of management's nominees were elected to the Board of Directors. Details of the voting are provided below:
  **Votes For** **VotesWithheld**                        
**Proposal:**
                
**Election of Directors**
                
*Class III–Term expiring in 2008*
                
Conrad K. Harper
     207,285,542      3,976,620         
Shirley Ann Jackson
     196,426,607      14,835,555         
Thomas A. Renyi
     207,305,052      3,957,110                           **Votes For** **VotesAgainst** **Abstentions** **BrokerNon-Votes**                
**Proposal:**
                
Approval of the Agreement and Plan of Merger, dated as of December 20, 2004, between Exelon Corporation (Exelon) and PSEG
     157,736,250      4,651,037      2,544,602      46,621,464 
**Proposal:**
                
Ratification of Appointment of Deloitte & Touche LLP as Independent Auditor
     206,759,730      2,362,071      2,140,361      — 
**Proposal:**
                
Adjournment or Postponement of PSEG Annual Meeting
     157,569,473      44,667,106      9,012,028      — 
**Proposal:**
                
Shareholder Proposal Related to Executive Compensation
     18,171,248      141,271,036      5,198,414      46,621,464                 
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**ITEM 5. OTHER INFORMATION**

      Certain information reported under the 2004 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 is 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 Report on Form 10-Q for the quarter ended March 31, 2005. References are to the related pages on the Form 10-K and Form 10-Q as printed and distributed.

**Federal Regulation**

      **Power**

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

      ***2004 Form 10-K, Page 16 and March 31, 2005 Form 10-Q, Page 70.*** 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, offset by 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. If Power is unable to resolve this matter through settlement discussions, which are currently ongoing, a hearing would likely commence by September 2005. Power currently believes that it has meritorious positions with regard to the remaining issues. The matter is currently pending before the FERC, and Power is not able to predict the outcome of this proceeding.

      ***RMR Status in New England***

      ***2004 Form 10-K, Page 16.*** In the New England electricity market, many owners of generation facilities have filed with FERC for RMR treatment under the NEPOOL Open Access Transmission Tariff. If FERC grants RMR status for a generation facility, the owner is entitled to receive cost-of-service treatment for its facility for the duration of an RMR contract that it enters into with ISO New England Inc. On November 17, 2004, PSEG Power Connecticut LLC (Power Connecticut), a wholly-owned indirect subsidiary of Power, filed a request for RMR treatment for the New Haven Harbor generation station and Unit 2 at the Bridgeport Harbor generation station. Beginning on January 4, 2005, subject to refund and hearing, Power Connecticut began collecting a monthly fixed payment amountof approximately $1.6 million and $3.9 million for reliability services provided by the Bridgeport Harbor Station, Unit 2 and the New Haven Harbor Station, respectively, net of operating margins at the units. On June 17, 2005, Power Connecticut filed revised studies supporting recovery of $1.3 million and $3.3 million monthly for the Bridgeport Harbor and New Haven Harbor units, respectively.

      On June 20, 2005, FERC issued an order on rehearing of its January 14, 2005 order which reversed its prior conclusion to allow the filing to become effective only after a sixty-day notice period. Instead, the rehearing order allowed the filing to become effective as of November 18, 2004, which permits Power Connecticut two additional months of RMR compensation.

      While Power Connecticut was unable to settle the issues that FERC set for hearing, Power Connecticut believes that it has meritorious positions with respect to these issues; however, a final outcome of this process cannot be determined at this time. In addition, it is anticipated that certain parties opposing the filing will seek judicial review of the January 14, 2005 and June 20, 2005 orders. While Power Connecticut does not believe that such challenges are likely to be successful, Power Connecticut cannot predict a final outcome at this time.

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      ***Market Power***

      ***2004 Form 10-K, Page 17.***On July 5, 2005, FERC issued an order accepting the updated market power analysis that PSEG Lawrenceburg and PSEG Waterford submitted on August 30, 2004, as supplemented on February 7, 2005 and February 15, 2005. FERC's acceptance allows PSEG's Lawrenceburg and Waterford facilities to continue to sell wholesale power at market-based rates. FERC's order requires Lawrenceburg and Waterford to file a revised market power analysis within thirty 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 and Waterford to file an additional compliancefiling within 30 days of the order to revise their codes of conduct to state that they cannot sell power to affiliates without first receiving FERC authorization to do so.

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

      ***Regional Through and Out Rate (RTOR) Proceeding***

      ***2004 Form 10-K, Page 17 and March 31, 2005 Form 10-Q, Page 70.*** RTORs are separate transmission rates for transactions where electricity originates in one transmission control area and is transmitted to a point outside that control area. Both the Midwest Independent System Operator, Inc. (MISO) and PJM charged RTORs through December 1, 2004. Under an order dated November 18, 2004, the FERC approved a new regional rate design, which became effective December 1, 2004 for the entire PJM/MISO region, and approved the continuation of license plate rates and a transitional Seams Elimination Charge/Cost Adjustment/Assignment (SECA) methodology effective from December 1, 2004 through March 31, 2006. In December 2004, the various PJM and MISO transmission owners made compliance filingsto permit the collection of this revenue over the proposed transitional period.

      On February 10, 2005, FERC issued an order that accepted the various SECA compliance filings, established December 1, 2004 as the effective date for the SECA rates subject to refund and surcharge, and established hearing procedures to resolve the outstanding factual issues raised in the filings and the responsive pleadings.

      In March 2005, the PJM transmission owners filed revisions to the SECA rates through March 31, 2005 to reflect the integration of Duquesne Light Company into PJM. Also in March, the New Jersey Board of Public Utilities (BPU) authorized the New Jersey electric distribution companies to pass through the SECA-related charges. On April 29, 2005, certain PJM transmission owners including PSE&G filed testimony quantifying the transmission revenues that they expect to lose following elimination of RTORs between PJM and MISO.

      On June 16, 2005, FERC issued an order that accepted certain additional compliance filings made by MISO and PJM transmission owners following the February 10, 2005 order. These compliance filings generally sought to implement the SECA methodology that FERC reinstated in the February 10, 2005 order. The order accepted these compliance filings subject to refund and surcharge, set these compliance filings for hearing, and consolidated these issues with the ongoing hearing regarding the justness and reasonableness of the SECA methodology. These hearing procedures may not conclude until summer 2006 or later. The order also accepted proposals by PJM and MISO to begin billing for the SECA in their May 2005 invoices for service in April 2005, although billing actually commenced in June 2005 with retroactive adjustments for priormonths. The BPU has authorized the pass-through of SECA charges to certain New Jersey ratepayers, so that PSE&G will be able to collect funds from these ratepayers and return them to certain BGS suppliers. As a BGS supplier, Power expects to receive funds from PSE&G to reimburse certain of its SECA expenses. However, BGS-Fixed Price (FP) suppliers, including Power, will not receive any revenue associated with the BPU-authorized pass-through of these costs to retail ratepayers until the applicable FERC orders are final and non-appealable.

      Depending on the outcome of this proceeding, which cannot be predicted at this time, PSEG, PSE&G and/or Power's results of operations could be negatively affected.

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

      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 certain PJM transmission owners to establish the general procedures for filing to recoverthe costs incurred under the RTEP process, subject to further compliance filings. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding.

      **PSE&G**

      ***Lower Delaware Valley (LDV) Complaint Proceeding***

      ***2004 Form 10-K, Page 19.***On December 30, 2004, Jersey Central Power & Light Company (JCP&L) filed a complaint at the FERC against the other four signatories to the LDV Transmission System Agreement (LDV Agreement), including PSE&G. The LDV Agreement, which governs the construction of, and investment in, certain 500 kilovolt transmission facilities, was entered into by the parties in 1977 and remains in effect until 2027. In its complaint, JCP&L sought to terminate its construction obligations under the LDV Agreement and to terminate its payment obligations to the other contract signatories under related agreements. PSE&G receives from JCP&L approximately $2.7 million annually under the LDV Agreement and its related agreements. On May 6, 2005, FERCissued an order that rejected JCP&L's arguments and denied JCP&L's complaint without requiring a hearing and/or settlement process. While the LDV signatories will be required to undertake a “review and adjustment process for payments made by JCP&L under a related agreement, this will be done outside the scope of a formal FERC process, and may result in a net benefit to PSE&G. JCP&L has sought rehearing of the May 6, 2005 order, though PSE&G does not currently expect the FERC to reach a different result on rehearing.

      ***Neptune Regional Transmission System, LLC (Neptune)***

      ***2004 Form 10-K, Page 18.*** On June 24, 2005, in response to requests for rehearing and clarification, FERC issued an order denying rehearing and granting clarification of its February 10, 2005 order, which granted a complaint by Neptune against PJM. FERC's June 24, 2005 order effectively approves Neptune's Interconnection Service Agreement with PJM, in which Neptune's cost responsibility is set at the level of approximately $6 million. Costs arising as a result of generation retirements announced after Neptune received a System Impact Study from PJM, which costs total at least $20 million, may be allocated to PSE&G and First Energy and/or to customers in these zones.

      PSE&G and other parties may seek rehearing and/or judicial review of FERC's orders. PSE&G cannot at this time predict the outcome of these challenges to FERC's orders.

      **PSEG and Power**

      ***Nuclear Regulatory Commission (NRC)***

      ***2004 Form 10-K, Page 19.*** The NRC has issued orders to all nuclear power plants to implement compensatory security measures. Some of the requirements formalize a series of security measures that licensees had taken in response to advisories issued by the NRC in the aftermath of the September 11, 2001 terrorist attacks. Nuclear has evaluated these orders for the Salem, Peach Bottom and Hope Creek facilities and does not expect the cost of implementation of the additional NRC measures to be material. Security measures required to be in place by October 2004 have been completed at Salem, Hope Creek and Peach Bottom. Additional security upgrades were identified and have been implemented following an NRC Force-On-Force security exercise in January 2005. A second Force-On-

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Force exercise was completed in July 2005. NRC preliminary results indicated that PSEG has an effective and well-executed security plan for Salem and Hope Creek.

**State Regulation**

      **PSE&G and Power**

      ***New Jersey RMR Pass-Through***

      ***March 31, 2005 Form 10-Q, Page 72.***On April 11, 2005, PSE&G sought authority from the BPU to pass through to its retail customers the amount of RMR compensation attributable to the PSE&G zone. On June 22, 2005, the BPU approved the pass-through and the mechanism to accomplish the pass-through. As a result, PSE&G's payments to BGS suppliers with contracts entered into in 2004 and 2005 will increase by a commensurate amount. The BPU's decision in this matter will favorably impact Power, since Power is a BGS supplier and will receive increased payments, although the BPU's order remains subject to reconsideration and judicial challenge. BGS-FP suppliers (such as Power) will not receive any revenue associated with the BPU-authorized pass-through of thesecosts to retail ratepayers until the FERC orders are final and non-appealable.

      **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. The filing has been sent to the Office of Administration Law (OAL) for hearings.

      ***Deferred BGS Costs***

      ***March 31, 2005 Form 10-Q, Page 72.***On July 12, 2005, the BPU issued a written order to PSE&G approving the issuance of bonds to securitize approximately $100 million of deferred BGS costs, plus transaction costs. A 45-day appeal period commenced on July 19, 2005, after which PSE&G expects to be able to sell the bonds. PSE&G expects to issue approximately $102.7 million in securitization debt late in the third quarter of 2005.

**Environmental Matters**

      **PSEG, Power and Energy Holdings**

      **Other Air Pollutants**

      ***2004 Form 10-K, Pages 25 and 26 and March 31, 2005 Form 10-Q, Page 72.***On March 15, 2005, the EPA, having previously proposed two alternative options to address emissions of mercury from electric generating sources, selected the second option. Consequently, the EPA rescinded its prior determination to regulate mercury as a HAP through a MACT standard and adopted a cap-and-trade program for the control of mercury to be established by changes to the states' individual NOx State Implementation Plans. The EPA's rescission of its prior determination became effective upon its publication in the Federal Register on March 29, 2005. The adoption of the cap-and-trade program will becomeeffective 60 days following its publication in the Federal Register.

      The EPA also determined to take no action with respect to its proposal to regulate emissions of nickel from oil-fired electric generating units.

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      **PSEG, Power and Energy Holdings**

      ***Water Pollution Control***

      ***2004 Form 10-K, Page 26 and March 31, 2005 Form 10-Q, Page 71.*** The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to waters of the U.S. from point sources, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permit issued by the U.S. Environmental Protection Agency (EPA) or by a state under a federally authorized state program.

      The EPA has adopted regulations under FWPCA Section 316(b), which requires that cooling water intake structures at existing facilities reflect the best technology available (BTA) for minimizing adverse environmental impact. Several environmental groups, the Attorneys General of six Northeastern states, the Utility Water Act Group and several of its members, including Power, are parties to litigation challenging these new regulations. The states and environmental groups are challenging the use of restoration and the regulations' performance standards as well as the availability of site-specific determinations based on cost tests. A decision issued in February 2004 by the U.S. Court of Appeals for the Second Circuit in litigation challenging the Section 316(b) rule applicable to new facilities struck down that rule'sprovision allowing for the use of restoration measures to satisfy the specified performance standards. An unfavorable decision in the litigation challenging the Section 316(b) regulations applicable to existing facilities could have a material impact on Power's ability to renew its New Jersey Pollutant Discharge Elimination System permits at its larger once-through cooled plants without significant upgrades to their existing intake structures and cooling systems.

      **PSEG and Power**

      ***Keystone and Conemaugh***

      Power has been named as one of approximately 21 defendants in a class action lawsuit filed in Ontario, Canada. The lawsuit alleges that the owners and operators of a number of coal-fired electric generating stations, including the Keystone and Conemaugh stations of which Power is a co-owner, have caused emissions of NOx, SO2 and particulate matter that have harmed the residents of Ontario. The lawsuit seeks damages for negligence of approximately $49.1 billion and approximately $4.1 billion per year until the stations cease emitting pollutants or trial of the matter and $1 billion in punitive damages. Power is unable at this time to assess the merits of the lawsuit.

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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: August 1, 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: August 1, 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: August 1, 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. RadoVice President and Controller(Principal Accounting Officer)  
Date: August 1, 2005

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