UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549



**F****ORM10-Q**

(Mark One)

SQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934

FOR
  THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2006

OR

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

FOR THE TRANSITION PERIOD FROM  TO

|                      |  |                                                                                                                                                                                                             |  |                                  
|--------------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ---------------------------------
|                     
|CommissionFile Number |  | Registrants, State of Incorporation,Address, and Telephone Number                                                                                                                                           |  | I.R.S. EmployerIdentification No.
|001-09120             |  | PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
        (A New Jersey Corporation)
        80 Park Plaza, P.O. Box 1171
        Newark, New Jersey 07101-1171
        973 430-7000
        http://www.pseg.com |  |                                  
|001-00973             |  | PUBLIC SERVICE ELECTRIC AND GAS COMPANY
        (A New Jersey Corporation)
        80 Park Plaza, P.O. Box 570
        Newark, New Jersey 07101-0570
        973 430-7000
        http://www.pseg.com       |  |                                  
|000-49614             |  | PSEG POWER LLC
        (A Delaware Limited Liability Company)
        80 Park Plaza—T25
        Newark, New Jersey 07102-4194
        973 430-7000
        http://www.pseg.com                              |  |                                  
|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                                                            |  |                                  



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. YesSNo£

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the
  Exchange Act.(Check one):

|                                             |  |                          |  |                    |  |                       
|-------------------------------------------- |  | ------------------------ |  | ------------------ |  | ----------------------
|Public Service Enterprise Group Incorporated |  | Large accelerated filerS |  | Accelerated filer£ |  | Non-accelerated filer£
|Public Service Electric and Gas Company      |  | Large accelerated filer£ |  | Accelerated filer£ |  | Non-accelerated filerS
|PSEG Power LLC                               |  | Large accelerated filer£ |  | Accelerated filer£ |  | Non-accelerated filerS
|PSEG Energy Holdings L.L.C.                  |  | Large accelerated filer£ |  | Accelerated filer£ |  | Non-accelerated filerS

Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes£NoS

As
  of October 31, 2006, Public Service Enterprise Group Incorporated had outstanding
  252,203,353 shares of its sole class of Common Stock, without par value.

As of October 31, 2006, 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.





---

TABLE OF CONTENTS
PageFORWARD-LOOKING
        STATEMENTS
    
    
    
    iiPART
        I. FINANCIAL INFORMATIONItem
        1.
    
    Financial
        StatementsPublic
        Service Enterprise Group Incorporated
    
    
    
    1Public
        Service Electric and Gas Company
    
    
    
    5PSEG Power
        LLC
    
    
    
    9PSEG Energy
        Holdings L.L.C.
    
    
    
    13Notes
        to Condensed Consolidated Financial StatementsNote 1.
        Organization and Basis of Presentation
    
    
    
    17Note 2.
        Recent Accounting Standards
    
    
    
    19Note 3.
        Discontinued Operations, Dispositions and Acquisitions
    
    
    
    22Note 4.
        Earnings Per Share (EPS)
    
    
    
    24Note 5.
        Commitments and Contingent Liabilities
    
    
    
    25Note 6.
        Financial Risk Management Activities
    
    
    
    39Note 7.
        Comprehensive Income (Loss), Net of Tax
    
    
    
    42Note 8.
        Changes in Capitalization
    
    
    
    43Note 9.
        Other Income and Deductions
    
    
    
    44Note
        10. Income Taxes
    
    
    
    46Note
        11. Financial Information by Business Segments
    
    
    
    47Note
        12. Stock-Based Compensation
    
    
    
    48Note
        13. Related-Party Transactions
    
    
    
    52Note
        14. Guarantees of Debt
    
    
    
    55Note
        15. Subsequent Events
    
    
    
    57Item
        2.
    
    Management’s
        Discussion and Analysis of Financial Condition and Results of Operations
        (MD&A)
    
    
    
    58Termination
        of Merger Agreement
    
    
    
    58Overview
        of 2006 and Future Outlook
    
    
    
    58Results
        of Operations
    
    
    
    63Liquidity
        and Capital Resources
    
    
    
    72Capital
        Requirements
    
    
    
    78Off-Balance
        Sheet Arrangements
    
    
    
    78Accounting
        Matters
    
    
    
    78Item
        3.
    
    Qualitative
        and Quantitative Disclosures About Market Risk
    
    
    
    79Item
        4.
    
    Controls
        and Procedures
    
    
    
    83PART
        II. OTHER INFORMATIONItem
        1.
    
    Legal
        Proceedings
    
    
    
    84Item
        5.
    
    Other
        Information
    
    
    
    85Item
        6.
    
    Exhibits
    
    
    
    94Signatures
    
    
    
    95i

FORWARD-LOOKING STATEMENTS
Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are
  subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and
  information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,” variations of
  such words and similar expressions are intended to identify forward-looking statements. 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 affect 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:
•
    
    
    
    regulatory issues that significantly impact operations;•
    
    
    
    ability to attain satisfactory regulatory results;•
    
    
    
    operating performance or cash flow from investments falling below projected levels;•
    
    
    
    credit, commodity, interest rate, counterparty and other financial market risks;•
    
    
    
    liquidity and the ability to access capital and maintain adequate credit ratings;•
    
    
    
    adverse or unanticipated weather conditions that significantly impact costs and/or operations, including generation;•
    
    
    
    ability to implement successful succession planning, attract and retain management and other key employees;•
    
    
    
    changes in the electric industry, including changes to power pools;•
    
    
    
    changes in energy policies and regulation;•
    
    
    
    changes in demand;•
    
    
    
    changes in the number of market participants and the risk profiles of such participants;•
    
    
    
    availability of power transmission facilities that impact the ability to deliver output to customers;•
    
    
    
    growth in costs and expenses;•
    
    
    
    environmental regulations that significantly impact operations;•
    
    
    
    changes in rates of return on overall debt and equity markets that could adversely impact the value of pension and other postretirement benefits assets and liabilities and the Nuclear
      Decommissioning Trust Funds;•
    
    
    
    changes in political conditions, recession, acts of war or terrorism;•
    
    
    
    changes in technology that make generation, transmission and/or distribution assets less competitive;•
    
    
    
    continued availability of insurance coverage at commercially reasonable rates;•
    
    
    
    involvement in lawsuits, including liability claims and commercial disputes;•
    
    
    
    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;•
    
    
    
    changes in tax laws and regulations;•
    
    
    
    changes to accounting standards or accounting principles generally accepted in the U.S., which may require adjustments to financial statements;ii

•
    
    
    
    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
•
    
    
    
    inability to effectively manage portfolios of electric generation assets, gas supply contracts and electric and gas supply obligations;•
    
    
    
    inability to meet generation operating performance expectations;•
    
    
    
    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;•
    
    
    
    adverse market developments or changes in market rules, including delays or impediments to implementation of reasonable capacity markets;•
    
    
    
    surplus of energy capacity and excess supply;•
    
    
    
    substantial competition in the domestic and worldwide energy markets;•
    
    
    
    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 construction and development;•
    
    
    
    delay in market rules;PSEG and Power
•
    
    
    
    changes in regulation and safety and security measures at nuclear facilities;•
    
    
    
    ability to maintain nuclear operating performance at projected levels;PSEG and Energy Holdings
•
    
    
    
    changes in foreign currency exchange rates;•
    
    
    
    deterioration in the credit of lessees and their ability to adequately service lease rentals;•
    
    
    
    ability to realize tax benefits;•
    
    
    
    changes in political regimes in foreign countries; and•
    
    
    
    international developments negatively impacting business.Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements and PSEG, PSE&G, Power and Energy Holdings cannot assure you that the results or
  developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on, PSEG, PSE&G, Power and Energy Holdings or their respective business
  prospects, financial condition or results of operations. Undue reliance should not be placed on these forward-looking statements in making any investment decision. Each of PSEG, PSE&G, Power and
  Energy Holdings expressly disclaims any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or
  are anticipated to occur or arise after the date hereof. In making any investment decision regarding PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities, PSEG, PSE&G, Power and Energy Holdings
  are not making, and you should not infer, any representation about the likely existence of any particular future set of facts or circumstances. The forward-looking statements contained in this report are
  intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
iii

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Quarters EndedSeptember 30,
    
    For the Nine Months EndedSeptember 30,2006
    
    2005
    
    2006
    
    2005(Millions)(Unaudited)OPERATING REVENUES
    
    
    $
    
    3,392
    
    
    
    $
    
    3,324
    
    
    
    $
    
    9,516
    
    
    
    $
    
    8,940OPERATING EXPENSESEnergy Costs
    
    
    
    1,809
    
    
    
    
    1,979
    
    
    
    
    5,400
    
    
    
    
    5,144Operation and Maintenance
    
    
    
    541
    
    
    
    
    537
    
    
    
    
    1,705
    
    
    
    
    1,661Write-down of Project Investments
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    263
    
    
    
    
    —Depreciation and Amortization
    
    
    
    234
    
    
    
    
    204
    
    
    
    
    645
    
    
    
    
    562Taxes Other Than Income Taxes
    
    
    
    32
    
    
    
    
    34
    
    
    
    
    100
    
    
    
    
    105Total Operating Expenses
    
    
    
    2,616
    
    
    
    
    2,754
    
    
    
    
    8,113
    
    
    
    
    7,472Income from Equity Method Investments
    
    
    
    30
    
    
    
    
    30
    
    
    
    
    93
    
    
    
    
    90OPERATING INCOME
    
    
    
    806
    
    
    
    
    600
    
    
    
    
    1,496
    
    
    
    
    1,558Other Income
    
    
    
    51
    
    
    
    
    92
    
    
    
    
    153
    
    
    
    
    169Other Deductions
    
    
    
    (44
    )
    
    
    
    
    (31
    )
    
    
    
    
    (91
    )
    
    
    
    
    (66
    )Interest Expense
    
    
    
    (209
    )
    
    
    
    
    (208
    )
    
    
    
    
    (617
    )
    
    
    
    
    (606
    )Preferred Stock Dividends
    
    
    
    (1
    )
    
    
    
    
    (1
    )
    
    
    
    
    (3
    )
    
    
    
    
    (3
    )INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
    
    
    
    603
    
    
    
    
    452
    
    
    
    
    938
    
    
    
    
    1,052Income Tax Expense
    
    
    
    (229
    )
    
    
    
    
    (183
    )
    
    
    
    
    (379
    )
    
    
    
    
    (412
    )INCOME FROM CONTINUING OPERATIONS
    
    
    
    374
    
    
    
    
    269
    
    
    
    
    559
    
    
    
    
    640(Loss) Income from Discontinued Operations, including Gain (Loss) on Disposal, net of tax expense (benefit) of $0, $0, $142, and ($138) for the
      quarter and nine months ended 2006 and 2005, respectively
    
    
    
    —
    
    
    
    
    (16
    )
    
    
    
    
    227
    
    
    
    
    (184
    )NET INCOME
    
    
    $
    
    374
    
    
    
    $
    
    253
    
    
    
    $
    
    786
    
    
    
    $
    
    456WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):BASIC
    
    
    
    251,747
    
    
    
    
    239,034
    
    
    
    
    251,471
    
    
    
    
    238,696DILUTED
    
    
    
    252,329
    
    
    
    
    244,286
    
    
    
    
    252,161
    
    
    
    
    243,212EARNINGS PER SHARE:BASICINCOME FROM CONTINUING OPERATIONS
    
    
    $
    
    1.48
    
    
    
    $
    
    1.12
    
    
    
    $
    
    2.22
    
    
    
    $
    
    2.68NET INCOME
    
    
    $
    
    1.48
    
    
    
    $
    
    1.06
    
    
    
    $
    
    3.12
    
    
    
    $
    
    1.91DILUTEDINCOME FROM CONTINUING OPERATIONS
    
    
    $
    
    1.48
    
    
    
    $
    
    1.10
    
    
    
    $
    
    2.22
    
    
    
    $
    
    2.63NET INCOME
    
    
    $
    
    1.48
    
    
    
    $
    
    1.03
    
    
    
    $
    
    3.12
    
    
    
    $
    
    1.87DIVIDENDS PAID PER SHARE OF COMMON STOCK
    
    
    $
    
    0.57
    
    
    
    $
    
    0.56
    
    
    
    $
    
    1.71
    
    
    
    $
    
    1.68See Notes to Condensed Consolidated Financial Statements.
1

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONDENSED CONSOLIDATED BALANCE SHEETS
September 30,2006
    
    December 31,2005(Millions)(Unaudited)ASSETSCURRENT ASSETSCash and Cash Equivalents
    
    
    $
    
    292
    
    
    
    $
    
    288Accounts Receivable, net of allowances of $45 and $44 in 2006 and 2005, respectively
    
    
    
    1,337
    
    
    
    
    1,936Unbilled Revenues
    
    
    
    222
    
    
    
    
    394Fuel
    
    
    
    853
    
    
    
    
    812Materials and Supplies
    
    
    
    311
    
    
    
    
    277Energy Trading Contracts
    
    
    
    62
    
    
    
    
    327Prepayments
    
    
    
    224
    
    
    
    
    129Restricted Funds
    
    
    
    98
    
    
    
    
    76Derivative Contracts
    
    
    
    37
    
    
    
    
    50Assets of Discontinued Operations
    
    
    
    —
    
    
    
    
    498Assets Held for Sale
    
    
    
    21
    
    
    
    
    —Other
    
    
    
    37
    
    
    
    
    41Total Current Assets
    
    
    
    3,494
    
    
    
    
    4,828PROPERTY, PLANT AND EQUIPMENT
    
    
    
    19,634
    
    
    
    
    18,896Less: Accumulated Depreciation and Amortization
    
    
    
    (5,950
    )
    
    
    
    
    (5,560
    )Net Property, Plant and Equipment
    
    
    
    13,684
    
    
    
    
    13,336NONCURRENT ASSETSRegulatory Assets
    
    
    
    5,028
    
    
    
    
    5,053Long-Term Investments
    
    
    
    3,890
    
    
    
    
    4,077Nuclear Decommissioning Trust (NDT) Funds
    
    
    
    1,191
    
    
    
    
    1,133Other Special Funds
    
    
    
    569
    
    
    
    
    559Goodwill and Other Intangibles
    
    
    
    597
    
    
    
    
    608Energy Trading Contracts
    
    
    
    19
    
    
    
    
    42Derivative Contracts
    
    
    
    59
    
    
    
    
    —Other
    
    
    
    183
    
    
    
    
    177Total Noncurrent Assets
    
    
    
    11,536
    
    
    
    
    11,649TOTAL ASSETS
    
    
    $
    
    28,714
    
    
    
    $
    
    29,813See Notes to Condensed Consolidated Financial Statements.
2

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONDENSED CONSOLIDATED BALANCE SHEETS
September 30,2006
    
    December 31,2005(Millions)(Unaudited)LIABILITIES AND CAPITALIZATIONCURRENT LIABILITIESLong-Term Debt Due Within One Year
    
    
    $
    
    672
    
    
    
    $
    
    1,536Commercial Paper and Loans
    
    
    
    555
    
    
    
    
    100Accounts Payable
    
    
    
    806
    
    
    
    
    1,154Derivative Contracts
    
    
    
    186
    
    
    
    
    425Energy Trading Contracts
    
    
    
    237
    
    
    
    
    200Accrued Interest
    
    
    
    191
    
    
    
    
    152Accrued Taxes
    
    
    
    112
    
    
    
    
    141Clean Energy Program
    
    
    
    114
    
    
    
    
    96Liabilities of Discontinued Operations
    
    
    
    —
    
    
    
    
    436Other
    
    
    
    430
    
    
    
    
    515Total Current Liabilities
    
    
    
    3,303
    
    
    
    
    4,755NONCURRENT LIABILITIESDeferred Income Taxes and Investment Tax Credits (ITC)
    
    
    
    4,646
    
    
    
    
    4,248Regulatory Liabilities
    
    
    
    668
    
    
    
    
    720Asset Retirement Obligations
    
    
    
    618
    
    
    
    
    585Other Postretirement Benefit (OPEB) Costs
    
    
    
    632
    
    
    
    
    597Clean Energy Program
    
    
    
    160
    
    
    
    
    233Environmental Costs
    
    
    
    396
    
    
    
    
    420Derivative Contracts
    
    
    
    214
    
    
    
    
    637Energy Trading Contracts
    
    
    
    40
    
    
    
    
    19Other
    
    
    
    263
    
    
    
    
    218Total Noncurrent Liabilities
    
    
    
    7,637
    
    
    
    
    7,677COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)CAPITALIZATIONLONG-TERM DEBTLong-Term Debt
    
    
    
    7,436
    
    
    
    
    7,849Securitization Debt
    
    
    
    1,758
    
    
    
    
    1,879Project Level, Non-Recourse Debt
    
    
    
    855
    
    
    
    
    891Debt Supporting Trust Preferred Securities
    
    
    
    660
    
    
    
    
    660Total Long-Term Debt
    
    
    
    10,709
    
    
    
    
    11,279SUBSIDIARIES’ PREFERRED SECURITIESPreferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2006 and 2005—795,234 shares
    
    
    
    80
    
    
    
    
    80COMMON STOCKHOLDERS’ EQUITYCommon Stock, no par, authorized 500,000,000 shares; issued; 2006—266,123,571 shares; 2005—265,332,746 shares
    
    
    
    4,644
    
    
    
    
    4,618Treasury Stock, at cost; 2006—14,024,505 shares; 2005—14,169,560 shares
    
    
    
    (527
    )
    
    
    
    
    (532
    )Retained Earnings
    
    
    
    2,901
    
    
    
    
    2,545Accumulated Other Comprehensive Loss
    
    
    
    (33
    )
    
    
    
    
    (609
    )Total Common Stockholders’ Equity
    
    
    
    6,985
    
    
    
    
    6,022Total Capitalization
    
    
    
    17,774
    
    
    
    
    17,381TOTAL LIABILITIES AND CAPITALIZATION
    
    
    $
    
    28,714
    
    
    
    $
    
    29,813See Notes to Condensed Consolidated Financial Statements.
3

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For The Nine Months
      EndedSeptember 30,2006
    
    2005(Millions)(Unaudited)CASH FLOWS FROM OPERATING ACTIVITIESNet Income
    
    
    $
    
    786
    
    
    
    $
    
    456Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:(Gain) Loss on Disposal of Discontinued Operations, net of tax
    
    
    
    (228
    )
    
    
    
    
    178Gain on Disposition of Property, Plant and Equipment
    
    
    
    (1
    )
    
    
    
    
    (5
    )Write-Down of Project Investments
    
    
    
    —
    
    
    
    
    22Depreciation and Amortization
    
    
    
    645
    
    
    
    
    572Amortization of Nuclear Fuel
    
    
    
    73
    
    
    
    
    69Provision for Deferred Income Taxes (Other than Leases) and ITC
    
    
    
    (5
    )
    
    
    
    
    155Non-Cash Employee Benefit Plan Costs
    
    
    
    178
    
    
    
    
    175Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes
    
    
    
    32
    
    
    
    
    9Loss (Gain) on Sale of Investments
    
    
    
    255
    
    
    
    
    (50
    )Undistributed Earnings from Affiliates
    
    
    
    (45
    )
    
    
    
    
    (40
    )Foreign Currency Transaction Loss (Gain)
    
    
    
    4
    
    
    
    
    (1
    )Unrealized (Gains) Losses on Energy Contracts and Other Derivatives
    
    
    
    (47
    )
    
    
    
    
    4Over Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs
    
    
    
    112
    
    
    
    
    75Under Recovery of Societal Benefits Charge (SBC)
    
    
    
    (89
    )
    
    
    
    
    (94
    )Net Realized Gains and Income from NDT Funds
    
    
    
    (54
    )
    
    
    
    
    (94
    )Other Non-Cash Charges
    
    
    
    25
    
    
    
    
    26Net Change in Certain Current Assets and Liabilities
    
    
    
    73
    
    
    
    
    (439
    )Employee Benefit Plan Funding and Related Payments
    
    
    
    (127
    )
    
    
    
    
    (159
    )Proceeds from the Withdrawal of Partnership Interests and Other Distributions
    
    
    
    7
    
    
    
    
    63Other
    
    
    
    (150
    )
    
    
    
    
    (19
    )Net Cash Provided By Operating Activities
    
    
    
    1,444
    
    
    
    
    903CASH FLOWS FROM INVESTING ACTIVITIESAdditions to Property, Plant and Equipment
    
    
    
    (748
    )
    
    
    
    
    (751
    )Proceeds from Collection of Notes Receivable
    
    
    
    —
    
    
    
    
    132Proceeds from Sale of Discontinued Operations
    
    
    
    494
    
    
    
    
    220Proceeds from Sale of Property, Plant and Equipment
    
    
    
    3
    
    
    
    
    6Proceeds from the Sale of Investments and Return of Capital from Partnerships
    
    
    
    186
    
    
    
    
    26Proceeds from NDT Funds Sales
    
    
    
    1,056
    
    
    
    
    2,751Investment in NDT Funds
    
    
    
    (1,069
    )
    
    
    
    
    (2,769
    )Restricted Funds
    
    
    
    (22
    )
    
    
    
    
    (47
    )NDT Funds Interest and Dividends
    
    
    
    29
    
    
    
    
    25Other
    
    
    
    18
    
    
    
    
    13Net Cash Used In Investing Activities
    
    
    
    (53
    )
    
    
    
    
    (394
    )CASH FLOWS FROM FINANCING ACTIVITIESNet Change in Commercial Paper and Loans
    
    
    
    452
    
    
    
    
    (267
    )Issuance of Long-Term Debt
    
    
    
    —
    
    
    
    
    728Issuance of Non-Recourse Debt
    
    
    
    —
    
    
    
    
    4Issuance of Common Stock
    
    
    
    56
    
    
    
    
    55Redemptions of Long-Term Debt
    
    
    
    (1,246
    )
    
    
    
    
    (230
    )Repayment of Non-Recourse Debt
    
    
    
    (37
    )
    
    
    
    
    (20
    )Redemption of Debt Underlying Trust Securities
    
    
    
    (154
    )
    
    
    
    
    —Cash Dividends Paid on Common Stock
    
    
    
    (430
    )
    
    
    
    
    (401
    )Other
    
    
    
    (26
    )
    
    
    
    
    (42
    )Net Cash Used In Financing Activities
    
    
    
    (1,385
    )
    
    
    
    
    (173
    )Effect of Exchange Rate Change
    
    
    
    (2
    )
    
    
    
    
    1Net Increase in Cash and Cash Equivalents
    
    
    
    4
    
    
    
    
    337Cash and Cash Equivalents at Beginning of Period
    
    
    
    288
    
    
    
    
    263Cash and Cash Equivalents at End of Period
    
    
    $
    
    292
    
    
    
    $
    
    600Supplemental Disclosure of Cash Flow Information:Income Taxes Paid
    
    
    $
    
    312
    
    
    
    $
    
    102Interest Paid, Net of Amounts Capitalized
    
    
    $
    
    510
    
    
    
    $
    
    618See Notes to Condensed Consolidated Financial Statements.
4

PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For The Quarters EndedSeptember 30,
    
    For The Nine Months EndedSeptember 30,2006
    
    2005
    
    2006
    
    2005(Millions)(Unaudited)OPERATING REVENUES
    
    
    $
    
    2,017
    
    
    
    $
    
    1,934
    
    
    
    $
    
    5,901
    
    
    
    $
    
    5,559OPERATING EXPENSESEnergy Costs
    
    
    
    1,296
    
    
    
    
    1,195
    
    
    
    
    3,872
    
    
    
    
    3,472Operation and Maintenance
    
    
    
    278
    
    
    
    
    276
    
    
    
    
    855
    
    
    
    
    839Depreciation and Amortization
    
    
    
    174
    
    
    
    
    155
    
    
    
    
    476
    
    
    
    
    418Taxes Other Than Income Taxes
    
    
    
    32
    
    
    
    
    35
    
    
    
    
    100
    
    
    
    
    106Total Operating Expenses
    
    
    
    1,780
    
    
    
    
    1,661
    
    
    
    
    5,303
    
    
    
    
    4,835OPERATING INCOME
    
    
    
    237
    
    
    
    
    273
    
    
    
    
    598
    
    
    
    
    724Other Income
    
    
    
    6
    
    
    
    
    3
    
    
    
    
    18
    
    
    
    
    7Other Deductions
    
    
    
    —
    
    
    
    
    (1
    )
    
    
    
    
    (2
    )
    
    
    
    
    (2
    )Interest Expense
    
    
    
    (86
    )
    
    
    
    
    (86
    )
    
    
    
    
    (254
    )
    
    
    
    
    (256
    )INCOME BEFORE INCOME TAXES
    
    
    
    157
    
    
    
    
    189
    
    
    
    
    360
    
    
    
    
    473Income Tax Expense
    
    
    
    (69
    )
    
    
    
    
    (74
    )
    
    
    
    
    (160
    )
    
    
    
    
    (191
    )NET INCOME
    
    
    
    88
    
    
    
    
    115
    
    
    
    
    200
    
    
    
    
    282Preferred Stock Dividends
    
    
    
    (1
    )
    
    
    
    
    (1
    )
    
    
    
    
    (3
    )
    
    
    
    
    (3
    )EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
    
    
    $
    
    87
    
    
    
    $
    
    114
    
    
    
    $
    
    197
    
    
    
    $
    
    279See disclosures regarding Public Service Electric and Gas Companyincluded in the Notes to Condensed Consolidated Financial Statements.
5

PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONDENSED CONSOLIDATED BALANCE SHEETS
September 30,2006
    
    December 31,2005(Millions)(Unaudited)ASSETSCURRENT ASSETSCash and Cash Equivalents
    
    
    $
    
    76
    
    
    
    $
    
    159Accounts Receivable, net of allowances of $42 in 2006 and $41 in 2005
    
    
    
    770
    
    
    
    
    959Unbilled Revenues
    
    
    
    222
    
    
    
    
    394Materials and Supplies
    
    
    
    49
    
    
    
    
    49Prepayments
    
    
    
    151
    
    
    
    
    49Restricted Funds
    
    
    
    15
    
    
    
    
    14Other
    
    
    
    33
    
    
    
    
    32Total Current Assets
    
    
    
    1,316
    
    
    
    
    1,656PROPERTY, PLANT AND EQUIPMENT
    
    
    
    11,023
    
    
    
    
    10,636Less: Accumulated Depreciation and Amortization
    
    
    
    (3,827
    )
    
    
    
    
    (3,627
    )Net Property, Plant and Equipment
    
    
    
    7,196
    
    
    
    
    7,009NONCURRENT ASSETSRegulatory Assets
    
    
    
    5,028
    
    
    
    
    5,053Long-Term Investments
    
    
    
    147
    
    
    
    
    144Other Special Funds
    
    
    
    310
    
    
    
    
    315Other
    
    
    
    117
    
    
    
    
    114Total Noncurrent Assets
    
    
    
    5,602
    
    
    
    
    5,626TOTAL ASSETS
    
    
    $
    
    14,114
    
    
    
    $
    
    14,291See disclosures regarding Public Service Electric and Gas Companyincluded in the Notes to Condensed Consolidated Financial Statements.
6

PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONDENSED CONSOLIDATED BALANCE SHEETS
September 30,2006
    
    December 31,2005(Millions)(Unaudited)LIABILITIES AND CAPITALIZATIONCURRENT LIABILITIESLong-Term Debt Due Within One Year
    
    
    $
    
    282
    
    
    
    $
    
    485Commercial Paper and Loans
    
    
    
    327
    
    
    
    
    —Accounts Payable
    
    
    
    290
    
    
    
    
    286Accounts Payable—Affiliated Companies, net
    
    
    
    403
    
    
    
    
    391Accrued Interest
    
    
    
    41
    
    
    
    
    59Clean Energy Program
    
    
    
    114
    
    
    
    
    96Derivative Contracts
    
    
    
    9
    
    
    
    
    6Other
    
    
    
    269
    
    
    
    
    370Total Current Liabilities
    
    
    
    1,735
    
    
    
    
    1,693NONCURRENT LIABILITIESDeferred Income Taxes and ITC
    
    
    
    2,523
    
    
    
    
    2,608Other Postretirement Benefit (OPEB) Costs
    
    
    
    586
    
    
    
    
    561Regulatory Liabilities
    
    
    
    668
    
    
    
    
    720Clean Energy Program
    
    
    
    160
    
    
    
    
    233Environmental Costs
    
    
    
    341
    
    
    
    
    365Asset Retirement Obligations
    
    
    
    218
    
    
    
    
    210Derivative Contracts
    
    
    
    23
    
    
    
    
    6Other
    
    
    
    27
    
    
    
    
    27Total Noncurrent Liabilities
    
    
    
    4,546
    
    
    
    
    4,730COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)CAPITALIZATIONLONG-TERM DEBTLong-Term Debt
    
    
    
    2,754
    
    
    
    
    2,866Securitization Debt
    
    
    
    1,758
    
    
    
    
    1,879Total Long-Term Debt
    
    
    
    4,512
    
    
    
    
    4,745PREFERRED SECURITIESPreferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2006 and 2005—795,234 shares
    
    
    
    80
    
    
    
    
    80COMMON STOCKHOLDER’S EQUITYCommon Stock; 150,000,000 shares authorized, 132,450,344 shares issued and outstanding
    
    
    
    892
    
    
    
    
    892Contributed Capital
    
    
    
    170
    
    
    
    
    170Basis Adjustment
    
    
    
    986
    
    
    
    
    986Retained Earnings
    
    
    
    1,197
    
    
    
    
    1,000Accumulated Other Comprehensive Loss
    
    
    
    (4
    )
    
    
    
    
    (5
    )Total Common Stockholder’s Equity
    
    
    
    3,241
    
    
    
    
    3,043Total Capitalization
    
    
    
    7,833
    
    
    
    
    7,868TOTAL LIABILITIES AND CAPITALIZATION
    
    
    $
    
    14,114
    
    
    
    $
    
    14,291See disclosures regarding Public Service Electric and Gas Companyincluded in the Notes to Condensed Consolidated Financial Statements.
7

PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For The Nine Months EndedSeptember 30,2006
    
    2005(Millions)(Unaudited)CASH FLOWS FROM OPERATING ACTIVITIESNet Income
    
    
    $
    
    200
    
    
    
    $
    
    282Adjustments to Reconcile Net Income to Net Cash Flows fromOperating Activities:Depreciation and Amortization
    
    
    
    476
    
    
    
    
    418Provision for Deferred Income Taxes and ITC
    
    
    
    (69
    )
    
    
    
    
    (77
    )Non-Cash Employee Benefit Plan Costs
    
    
    
    127
    
    
    
    
    124Non-Cash Interest Expense
    
    
    
    14
    
    
    
    
    13Employee Benefit Plan Funding and Related Payments
    
    
    
    (81
    )
    
    
    
    
    (104
    )Over Recovery of Electric Energy Costs (BGS and NTC)
    
    
    
    39
    
    
    
    
    81Over (Under) Recovery of Gas Costs
    
    
    
    73
    
    
    
    
    (6
    )Under Recovery of SBC
    
    
    
    (89
    )
    
    
    
    
    (94
    )Other Non-Cash Charges
    
    
    
    6
    
    
    
    
    3Net Changes in Certain Current Assets and Liabilities:Accounts Receivable and Unbilled Revenues
    
    
    
    361
    
    
    
    
    74Materials and Supplies
    
    
    
    —
    
    
    
    
    (7
    )Prepayments
    
    
    
    (102
    )
    
    
    
    
    (91
    )Accrued Taxes
    
    
    
    (25
    )
    
    
    
    
    (21
    )Accrued Interest
    
    
    
    (18
    )
    
    
    
    
    (16
    )Accounts Payable
    
    
    
    4
    
    
    
    
    70Accounts Receivable/Payable-Affiliated Companies, net
    
    
    
    (337
    )
    
    
    
    
    (207
    )Other Current Assets and Liabilities
    
    
    
    (77
    )
    
    
    
    
    102Other
    
    
    
    (79
    )
    
    
    
    
    (80
    )Net Cash Provided By Operating Activities
    
    
    
    423
    
    
    
    
    464CASH FLOWS FROM INVESTING ACTIVITIESAdditions to Property, Plant and Equipment
    
    
    
    (392
    )
    
    
    
    
    (372
    )Restricted Funds
    
    
    
    (1
    )
    
    
    
    
    (3
    )Net Cash Used In Investing Activities
    
    
    
    (393
    )
    
    
    
    
    (375
    )CASH FLOWS FROM FINANCING ACTIVITIESNet Change in Short-Term Debt
    
    
    
    327
    
    
    
    
    80Issuance of Long-Term Debt
    
    
    
    —
    
    
    
    
    250Redemption of Securitization Debt
    
    
    
    (115
    )
    
    
    
    
    (105
    )Redemption of Long-Term Debt
    
    
    
    (322
    )
    
    
    
    
    (125
    )Issuance of Securitization Debt
    
    
    
    —
    
    
    
    
    103Deferred Issuance Costs
    
    
    
    —
    
    
    
    
    (3
    )Preferred Stock Dividends
    
    
    
    (3
    )
    
    
    
    
    (3
    )Net Cash (Used In) Provided by Financing Activities
    
    
    
    (113
    )
    
    
    
    
    197Net (Decrease) Increase In Cash and Cash Equivalents
    
    
    
    (83
    )
    
    
    
    
    286Cash and Cash Equivalents at Beginning of Period
    
    
    
    159
    
    
    
    
    6Cash and Cash Equivalents at End of Period
    
    
    $
    
    76
    
    
    
    $
    
    292Supplemental Disclosure of Cash Flow Information:Income Taxes Paid
    
    
    $
    
    187
    
    
    
    $
    
    249Interest Paid, Net of Amounts Capitalized
    
    
    $
    
    251
    
    
    
    $
    
    250See disclosures regarding Public Service Electric and Gas Companyincluded in the Notes to Condensed Consolidated Financial Statements.
8

PSEG POWER LLCCONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For The Quarters
      EndedSeptember 30,
    
    For The Nine Months
      EndedSeptember 30,2006
    
    2005
    
    2006
    
    2005(Millions)(Unaudited)OPERATING REVENUES
    
    
    $
    
    1,489
    
    
    
    $
    
    1,444
    
    
    
    $
    
    4,591
    
    
    
    $
    
    4,234OPERATING EXPENSESEnergy Costs
    
    
    
    830
    
    
    
    
    983
    
    
    
    
    2,992
    
    
    
    
    2,941Operation and Maintenance
    
    
    
    222
    
    
    
    
    223
    
    
    
    
    721
    
    
    
    
    685Depreciation and Amortization
    
    
    
    41
    
    
    
    
    34
    
    
    
    
    116
    
    
    
    
    96Total Operating Expenses
    
    
    
    1,093
    
    
    
    
    1,240
    
    
    
    
    3,829
    
    
    
    
    3,722OPERATING INCOME
    
    
    
    396
    
    
    
    
    204
    
    
    
    
    762
    
    
    
    
    512Other Income
    
    
    
    38
    
    
    
    
    74
    
    
    
    
    113
    
    
    
    
    135Other Deductions
    
    
    
    (27
    )
    
    
    
    
    (13
    )
    
    
    
    
    (60
    )
    
    
    
    
    (33
    )Interest Expense
    
    
    
    (47
    )
    
    
    
    
    (32
    )
    
    
    
    
    (131
    )
    
    
    
    
    (86
    )INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
    
    
    
    360
    
    
    
    
    233
    
    
    
    
    684
    
    
    
    
    528Income Tax Expense
    
    
    
    (155
    )
    
    
    
    
    (101
    )
    
    
    
    
    (290
    )
    
    
    
    
    (225
    )INCOME FROM CONTINUING OPERATIONS
    
    
    
    205
    
    
    
    
    132
    
    
    
    
    394
    
    
    
    
    303Loss from Discontinued Operations, net of tax benefit of $4 and $13 for the quarter and nine months ended 2005, respectively
    
    
    
    —
    
    
    
    
    (6
    )
    
    
    
    
    —
    
    
    
    
    (19
    )Loss on Disposal of Discontinued Operations, net of tax benefit of $0 and $123 for the quarter and nine months ended 2005, respectively
    
    
    
    —
    
    
    
    
    (1
    )
    
    
    
    
    —
    
    
    
    
    (178
    )EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
    
    
    $
    
    205
    
    
    
    $
    
    125
    
    
    
    $
    
    394
    
    
    
    $
    
    106See disclosures regarding PSEG Power LLCincluded in the Notes to Condensed Consolidated Financial Statements.
9

PSEG POWER LLCCONDENSED CONSOLIDATED BALANCE SHEETS
September 30,2006
    
    December 31,2005(Millions)(Unaudited)ASSETSCURRENT ASSETSCash and Cash Equivalents
    
    
    $
    
    5
    
    
    
    $
    
    8Accounts Receivable
    
    
    
    450
    
    
    
    
    862Accounts Receivable—Affiliated Companies, net
    
    
    
    335
    
    
    
    
    288Fuel
    
    
    
    852
    
    
    
    
    812Materials and Supplies
    
    
    
    218
    
    
    
    
    201Energy Trading Contracts
    
    
    
    62
    
    
    
    
    327Derivative Contracts
    
    
    
    15
    
    
    
    
    50Other
    
    
    
    35
    
    
    
    
    27Total Current Assets
    
    
    
    1,972
    
    
    
    
    2,575PROPERTY, PLANT AND EQUIPMENT
    
    
    
    6,694
    
    
    
    
    6,457Less: Accumulated Depreciation and Amortization
    
    
    
    (1,698
    )
    
    
    
    
    (1,577
    )Net Property, Plant and Equipment
    
    
    
    4,996
    
    
    
    
    4,880NONCURRENT ASSETSDeferred Income Taxes and Investment Tax Credits (ITC)
    
    
    
    —
    
    
    
    
    70Nuclear Decommissioning Trust (NDT) Funds
    
    
    
    1,191
    
    
    
    
    1,133Goodwill and Other Intangibles
    
    
    
    62
    
    
    
    
    63Other Special Funds
    
    
    
    155
    
    
    
    
    143Energy Trading Contracts
    
    
    
    19
    
    
    
    
    42Derivative Contracts
    
    
    
    25
    
    
    
    
    —Other
    
    
    
    53
    
    
    
    
    39Total Noncurrent Assets
    
    
    
    1,505
    
    
    
    
    1,490TOTAL ASSETS
    
    
    $
    
    8,473
    
    
    
    $
    
    8,945LIABILITIES AND MEMBER’S EQUITYCURRENT LIABILITIESLong-Term Debt Due Within One Year
    
    
    $
    
    —
    
    
    
    $
    
    500Accounts Payable
    
    
    
    403
    
    
    
    
    745Short-Term Loan from Affiliate
    
    
    
    68
    
    
    
    
    202Energy Trading Contracts
    
    
    
    237
    
    
    
    
    200Derivative Contracts
    
    
    
    165
    
    
    
    
    403Accrued Interest
    
    
    
    81
    
    
    
    
    41Other
    
    
    
    83
    
    
    
    
    86Total Current Liabilities
    
    
    
    1,037
    
    
    
    
    2,177NONCURRENT LIABILITIESDeferred Income Taxes and Investment Tax Credits (ITC)
    
    
    
    271
    
    
    
    
    —Asset Retirement Obligations
    
    
    
    398
    
    
    
    
    373Energy Trading Contracts
    
    
    
    40
    
    
    
    
    19Derivative Contracts
    
    
    
    167
    
    
    
    
    597Environmental Costs
    
    
    
    55
    
    
    
    
    55Other
    
    
    
    74
    
    
    
    
    70Total Noncurrent Liabilities
    
    
    
    1,005
    
    
    
    
    1,114COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)LONG-TERM DEBTTotal Long-Term Debt
    
    
    
    2,817
    
    
    
    
    2,817MEMBER’S EQUITYContributed Capital
    
    
    
    2,000
    
    
    
    
    2,000Basis Adjustment
    
    
    
    (986
    )
    
    
    
    
    (986
    )Retained Earnings
    
    
    
    2,704
    
    
    
    
    2,310Accumulated Other Comprehensive Loss
    
    
    
    (104
    )
    
    
    
    
    (487
    )Total Member’s Equity
    
    
    
    3,614
    
    
    
    
    2,837TOTAL LIABILITIES AND MEMBER’S EQUITY
    
    
    $
    
    8,473
    
    
    
    $
    
    8,945See disclosures regarding PSEG Power LLCincluded in the Notes to Condensed Consolidated Financial Statements.
10

PSEG POWER LLCCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For The Nine Months Ended
      September 30,2006
    
    2005(Millions)
      (Unaudited)CASH
        FLOWS FROM OPERATING ACTIVITIESNet
        Income
    
    
    $
    
    394
    
    
    
    $
    
    106Adjustments
        to Reconcile Net Income to Net Cash Flows from Operating Activities:Loss
        on Disposal of Discontinued operations, net of tax
    
    
    
    —
    
    
    
    
    178Gain
        on Disposition of Property, Plant and Equipment
    
    
    
    (1
    )
    
    
    
    
    (5
    )Depreciation
        and Amortization
    
    
    
    116
    
    
    
    
    96Amortization
        of Nuclear Fuel
    
    
    
    73
    
    
    
    
    69Interest
        Accretion on Asset Retirement Obligations
    
    
    
    25
    
    
    
    
    21Provision
        for Deferred Income Taxes and ITC
    
    
    
    74
    
    
    
    
    239Unrealized
        Losses (Gains) on Energy Contracts and Other Derivatives
    
    
    
    2
    
    
    
    
    (2
    )Non-Cash
        Employee Benefit Plan Costs
    
    
    
    35
    
    
    
    
    34Net
        Realized Gains and Income from NDT Funds
    
    
    
    (54
    )
    
    
    
    
    (94
    )Net
        Change in Certain Current Assets and Liabilities:Fuel,
        Materials and Supplies
    
    
    
    (57
    )
    
    
    
    
    (187
    )Accounts
        Receivable
    
    
    
    412
    
    
    
    
    (89
    )Accounts
        Payable
    
    
    
    (325
    )
    
    
    
    
    (348
    )Accounts
        Receivable/Payable—Affiliated Companies, net
    
    
    
    303
    
    
    
    
    177Accrued
        Interest Payable
    
    
    
    39
    
    
    
    
    —Other
        Current Assets and Liabilities
    
    
    
    25
    
    
    
    
    61Employee
        Benefit Plan Funding and Related Payments
    
    
    
    (34
    )
    
    
    
    
    (35
    )Other
    
    
    
    (107
    )
    
    
    
    
    55Net
        Cash Provided By Operating Activities
    
    
    
    920
    
    
    
    
    276CASH
        FLOWS FROM INVESTING ACTIVITIESAdditions
        to Property, Plant and Equipment
    
    
    
    (316
    )
    
    
    
    
    (345
    )Sales
        of Property, Plant and Equipment
    
    
    
    1
    
    
    
    
    226Proceeds
        from NDT Funds Sales
    
    
    
    1,056
    
    
    
    
    2,751NDT
        Funds Interest and Dividends
    
    
    
    29
    
    
    
    
    25Investment
        in NDT Funds
    
    
    
    (1,069
    )
    
    
    
    
    (2,769
    )Short-Term
        Loan—Affiliated Company, net
    
    
    
    —
    
    
    
    
    (62
    )Other
    
    
    
    10
    
    
    
    
    5Net
        Cash Used In Investing Activities
    
    
    
    (289
    )
    
    
    
    
    (169
    )CASH
        FLOWS FROM FINANCING ACTIVITIESRedemption
        of Long-Term Debt
    
    
    
    (500
    )
    
    
    
    
    —Short-Term
        Loan—Affiliated Company, net
    
    
    
    (134
    )
    
    
    
    
    (98
    )Net
        Cash Used In Financing Activities
    
    
    
    (634
    )
    
    
    
    
    (98
    )Net
        (Decrease) Increase in Cash and Cash Equivalents
    
    
    
    (3
    )
    
    
    
    
    9Cash
        and Cash Equivalents at Beginning of Period
    
    
    
    8
    
    
    
    
    10Cash
        and Cash Equivalents at End of Period
    
    
    $
    
    5
    
    
    
    $
    
    19Supplemental
        Disclosure of Cash Flow Information:Income
        Taxes Paid
    
    
    $
    
    200
    
    
    
    $
    
    9Interest
        Paid, Net of Amounts Capitalized
    
    
    $
    
    92
    
    
    
    $
    
    62See disclosures regarding PSEG Power LLCincluded in the Notes to Condensed Consolidated Financial Statements.
11

[THIS PAGE INTENTIONALLY LEFT BLANK]

PSEG ENERGY HOLDINGS L.L.C.CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For The QuartersEndedSeptember 30,
    
    For The Nine MonthsEndedSeptember 30,2006
    
    2005
    
    2006
    
    2005(Millions)(Unaudited)OPERATING REVENUESElectric Generation and Distribution Revenues
    
    
    $
    
    358
    
    
    
    $
    
    280
    
    
    
    $
    
    939
    
    
    
    $
    
    728Income from Leveraged and Operating Leases
    
    
    
    38
    
    
    
    
    44
    
    
    
    
    115
    
    
    
    
    136Other
    
    
    
    5
    
    
    
    
    10
    
    
    
    
    26
    
    
    
    
    53Total Operating Revenues
    
    
    
    401
    
    
    
    
    334
    
    
    
    
    1,080
    
    
    
    
    917OPERATING EXPENSESEnergy Costs
    
    
    
    195
    
    
    
    
    184
    
    
    
    
    583
    
    
    
    
    484Operation and Maintenance
    
    
    
    49
    
    
    
    
    41
    
    
    
    
    150
    
    
    
    
    151Write-down of Project Investments
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    263
    
    
    
    
    —Depreciation and Amortization
    
    
    
    14
    
    
    
    
    10
    
    
    
    
    38
    
    
    
    
    35Total Operating Expenses
    
    
    
    258
    
    
    
    
    235
    
    
    
    
    1,034
    
    
    
    
    670Income from Equity Method Investments
    
    
    
    30
    
    
    
    
    30
    
    
    
    
    93
    
    
    
    
    90OPERATING INCOME
    
    
    
    173
    
    
    
    
    129
    
    
    
    
    139
    
    
    
    
    337Other Income
    
    
    
    14
    
    
    
    
    5
    
    
    
    
    33
    
    
    
    
    18Other Deductions
    
    
    
    (16
    )
    
    
    
    
    (3
    )
    
    
    
    
    (27
    )
    
    
    
    
    (17
    )Interest Expense
    
    
    
    (50
    )
    
    
    
    
    (56
    )
    
    
    
    
    (151
    )
    
    
    
    
    (168
    )INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST
    
    
    
    121
    
    
    
    
    75
    
    
    
    
    (6
    )
    
    
    
    
    170Income Tax (Expense) Benefit
    
    
    
    (20
    )
    
    
    
    
    (27
    )
    
    
    
    
    31
    
    
    
    
    (42
    )Minority Interests in Earnings of Subsidiaries
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (1
    )
    
    
    
    
    (1
    )INCOME FROM CONTINUING OPERATIONS
    
    
    
    101
    
    
    
    
    48
    
    
    
    
    24
    
    
    
    
    127(Loss) Income from Discontinued Operations, net of tax benefit (expense) of $0, $(4), $0 and $2 for the quarter and nine months ended 2006
      and 2005, respectively
    
    
    
    —
    
    
    
    
    (9
    )
    
    
    
    
    (1
    )
    
    
    
    
    13Gain on Disposal of Discontinued Operations, net of tax expense of $142 for the nine months ended 2006
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    228
    
    
    
    
    —NET INCOME
    
    
    
    101
    
    
    
    
    39
    
    
    
    
    251
    
    
    
    
    140Preference Units Distributions
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (3
    )EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
    
    
    $
    
    101
    
    
    
    $
    
    39
    
    
    
    $
    
    251
    
    
    
    $
    
    137See disclosures regarding PSEG Energy Holdings L.L.C.included in the Notes to Condensed Consolidated Financial Statements.
13

PSEG ENERGY HOLDINGS L.L.C.CONDENSED CONSOLIDATED BALANCE SHEETS
September 30,2006
    
    December 31,2005(Millions)(Unaudited)ASSETSCURRENT ASSETSCash and Cash Equivalents
    
    
    $
    
    102
    
    
    
    $
    
    68Accounts Receivable:Trade—net of allowances of $4 and $3 in 2006 and 2005, respectively
    
    
    
    103
    
    
    
    
    101Other Accounts Receivable
    
    
    
    12
    
    
    
    
    14Affiliated Companies
    
    
    
    2
    
    
    
    
    —Notes Receivable:Affiliated Companies
    
    
    
    374
    
    
    
    
    409Other
    
    
    
    —
    
    
    
    
    5Inventory
    
    
    
    45
    
    
    
    
    27Restricted Funds
    
    
    
    83
    
    
    
    
    62Assets of Discontinued Operations
    
    
    
    —
    
    
    
    
    498Assets Held for Sale
    
    
    
    21
    
    
    
    
    —Derivative Contracts
    
    
    
    21
    
    
    
    
    —Other
    
    
    
    10
    
    
    
    
    7Total Current Assets
    
    
    
    773
    
    
    
    
    1,191PROPERTY, PLANT AND EQUIPMENT
    
    
    
    1,674
    
    
    
    
    1,560Less: Accumulated Depreciation and Amortization
    
    
    
    (290
    )
    
    
    
    
    (237
    )Net Property, Plant and Equipment
    
    
    
    1,384
    
    
    
    
    1,323NONCURRENT ASSETSLeveraged Leases, net
    
    
    
    2,779
    
    
    
    
    2,720Corporate Joint Ventures and Partnership Interests
    
    
    
    920
    
    
    
    
    1,180Goodwill and Other Intangibles
    
    
    
    531
    
    
    
    
    540Derivative Contracts
    
    
    
    34
    
    
    
    
    3Other
    
    
    
    104
    
    
    
    
    98Total Noncurrent Assets
    
    
    
    4,368
    
    
    
    
    4,541TOTAL ASSETS
    
    
    $
    
    6,525
    
    
    
    $
    
    7,055See 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 BALANCE SHEETS
September 30,2006
    
    December 31,2005(Millions)(Unaudited)LIABILITIES AND MEMBER’S EQUITYCURRENT LIABILITIESLong-Term Debt Due Within One Year
    
    
    $
    
    341
    
    
    
    $
    
    348Accounts Payable:Trade
    
    
    
    53
    
    
    
    
    50Affiliated Companies
    
    
    
    76
    
    
    
    
    11Derivative Contracts
    
    
    
    8
    
    
    
    
    13Accrued Interest
    
    
    
    48
    
    
    
    
    42Liabilities of Discontinued Operations
    
    
    
    —
    
    
    
    
    436Other
    
    
    
    73
    
    
    
    
    83Total Current Liabilities
    
    
    
    599
    
    
    
    
    983NONCURRENT LIABILITIESDeferred Income Taxes and Investment and Energy Tax Credits
    
    
    
    1,839
    
    
    
    
    1,705Derivative Contracts
    
    
    
    18
    
    
    
    
    27Other
    
    
    
    103
    
    
    
    
    66Total Noncurrent Liabilities
    
    
    
    1,960
    
    
    
    
    1,798COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)MINORITY INTERESTS
    
    
    
    24
    
    
    
    
    15LONG-TERM DEBTProject Level, Non-Recourse Debt
    
    
    
    855
    
    
    
    
    891Senior Notes
    
    
    
    1,149
    
    
    
    
    1,448Total Long-Term Debt
    
    
    
    2,004
    
    
    
    
    2,339MEMBER’S EQUITYOrdinary Unit
    
    
    
    1,288
    
    
    
    
    1,713Retained Earnings
    
    
    
    568
    
    
    
    
    317Accumulated Other Comprehensive Income (Loss)
    
    
    
    82
    
    
    
    
    (110
    )Total Member’s Equity
    
    
    
    1,938
    
    
    
    
    1,920TOTAL LIABILITIES AND MEMBER’S EQUITY
    
    
    $
    
    6,525
    
    
    
    $
    
    7,055See disclosures regarding PSEG Energy Holdings L.L.C.included in the Notes to Condensed Consolidated Financial Statements.
15

PSEG ENERGY HOLDINGS L.L.C.CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For The Nine Months Ended
      September 30,2006
    
    2005(Millions)(Unaudited)CASH FLOWS FROM OPERATING ACTIVITIESNet Income
    
    
    $
    
    251
    
    
    
    $
    
    140Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:Depreciation and Amortization
    
    
    
    38
    
    
    
    
    45Demand Side Management Amortization
    
    
    
    2
    
    
    
    
    6Investment Write-off
    
    
    
    —
    
    
    
    
    22Deferred Income Taxes (Other than Leases)
    
    
    
    (8
    )
    
    
    
    
    (7
    )Leveraged Lease Income, Adjusted for Rents Received and Deferred Income Taxes
    
    
    
    32
    
    
    
    
    9Undistributed Earnings from Affiliates
    
    
    
    (45
    )
    
    
    
    
    (40
    )Loss (Gain) on Sale of Investments
    
    
    
    255
    
    
    
    
    (50
    )Gain on Sale of Discontinued Operations
    
    
    
    (228
    )
    
    
    
    
    —Foreign Currency Transaction Loss (Gain)
    
    
    
    4
    
    
    
    
    (1
    )Change in Fair Value of Derivative Financial Instruments
    
    
    
    (49
    )
    
    
    
    
    6Other Non-Cash Charges
    
    
    
    3
    
    
    
    
    4Net Changes in Certain Current Assets and Liabilities:Accounts Receivable
    
    
    
    (23
    )
    
    
    
    
    (3
    )Inventory
    
    
    
    (15
    )
    
    
    
    
    4Accounts Payable
    
    
    
    (58
    )
    
    
    
    
    18Other Current Assets and Liabilities
    
    
    
    (21
    )
    
    
    
    
    15Proceeds from Withdrawal of Partnership Interests and Other Distributions
    
    
    
    7
    
    
    
    
    63Other
    
    
    
    4
    
    
    
    
    (2
    )Net Cash Provided By Operating Activities
    
    
    
    149
    
    
    
    
    229CASH FLOWS FROM INVESTING ACTIVITIESAdditions to Property, Plant and Equipment
    
    
    
    (37
    )
    
    
    
    
    (26
    )Proceeds from Sale of Discontinued Operations
    
    
    
    494
    
    
    
    
    —Proceeds from the Sale of Investments
    
    
    
    186
    
    
    
    
    26Short-Term Loan Receivable—Affiliated Company, net
    
    
    
    34
    
    
    
    
    54Restricted Funds
    
    
    
    (21
    )
    
    
    
    
    (44
    )Proceeds from Collection of Notes Receivable
    
    
    
    —
    
    
    
    
    137Additions to other assets
    
    
    
    (5
    )
    
    
    
    
    (11
    )Other
    
    
    
    8
    
    
    
    
    9Net Cash Provided By Investing Activities
    
    
    
    659
    
    
    
    
    145CASH FLOWS FROM FINANCING ACTIVITIESProceeds from Non-Recourse Long-Term Debt
    
    
    
    —
    
    
    
    
    4Repayment of Non-Recourse Long-Term Debt
    
    
    
    (37
    )
    
    
    
    
    (20
    )Repayment of Senior Notes
    
    
    
    (309
    )
    
    
    
    
    —Return of Capital Contributed
    
    
    
    (425
    )
    
    
    
    
    (100
    )Redemptions Preference Units
    
    
    
    —
    
    
    
    
    (184
    )Cash Distributions Paid on Preference Units
    
    
    
    —
    
    
    
    
    (3
    )Other
    
    
    
    (1
    )
    
    
    
    
    (6
    )Net Cash Used In Financing Activities
    
    
    
    (772
    )
    
    
    
    
    (309
    )Effect of Exchange Rate Change
    
    
    
    (2
    )
    
    
    
    
    1Net Increase In Cash and Cash Equivalents
    
    
    
    34
    
    
    
    
    66Cash and Cash Equivalents at Beginning of Period
    
    
    
    68
    
    
    
    
    183Cash and Cash Equivalents at End of Period
    
    
    $
    
    102
    
    
    
    $
    
    249Supplemental Disclosure of Cash Flow Information:Income Taxes (Received) Paid
    
    
    $
    
    (86
    )
    
    
    
    $
    
    4Interest Paid, Net of Amounts Capitalized
    
    
    $
    
    108
    
    
    
    $
    
    203See disclosures regarding PSEG Energy Holdings L.L.C.included in the Notes to Condensed Consolidated Financial Statements.
16

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) providing for a merger of PSEG with and
  into Exelon (Merger). On September 14, 2006, PSEG received from Exelon a formal notice of termination of the Merger under the provisions of the Merger Agreement.
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 in certain areas of New Jersey. PSE&G is subject to
  regulation by the BPU and the Federal Energy Regulatory Commission (FERC).
PSE&G also owns PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), bankruptcy-remote entities that purchased certain transition
  property from PSE&G and issued transition bonds secured by such property. The transition property consists principally of the rights to receive electricity consumption-based per kilowatt-hour (kWh) charges
  from PSE&G electric distribution customers, which represent irrevocable rights to receive amounts sufficient to recover certain of PSE&G’s transition costs related to deregulation, as approved by the BPU.
Power
Power is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments 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 Power’s portfolio. Fossil, Nuclear and ER&T are subject to
  regulation by FERC and Nuclear is also 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 invested primarily in energy-related leveraged leases.
  Energy Holdings also owns Enterprise Group Development Corporation (EGDC), a commercial real estate property management business.
Services
Services provides management and administrative services to PSEG and its subsidiaries. These include accounting, legal, communications, human resources, information technology, treasury and
17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
financial services, investor relations, stockholder services, real estate, environmental, health and safety, insurance, risk management, tax, library, records and information services, security, corporate
  secretarial and certain planning, budgeting and forecasting services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to the terms and conditions of
  intercompany service agreements.
Basis of Presentation
PSEG, PSE&G, Power and Energy Holdings
The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for Quarterly Reports on Form 10-Q.
  Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed
  or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction
  with, and update and supplement matters discussed in PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective Annual Reports on Form 10-K for the year ended December 31, 2005 and Quarterly
  Reports on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006.
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, 2005.
Pension and Other Postretirement Benefits (OPEB)
PSEG
PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. In
  September 2006, PSEG contributed $50 million to its pension plans and $12 million to its OPEB plans. PSEG does not anticipate making any further contributions to the plans in 2006. The following table
  provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis. OPEB costs are presented net of the federal subsidy expected
  for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003.
18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Pension Benefits
    
    OPEB
    
    Pension Benefits
    
    OPEBQuarters EndedSeptember 30,
    
    Quarters EndedSeptember 30,
    
    Nine Months EndedSeptember 30,
    
    Nine Months EndedSeptember 30,2006
    
    2005
    
    2006
    
    2005
    
    2006
    
    2005
    
    2006
    
    2005(Millions)Components of Net
      Periodic Benefit Costs:Service Cost
    
    
    $
    
    22
    
    
    
    $
    
    22
    
    
    
    $
    
    4
    
    
    
    $
    
    4
    
    
    
    $
    
    65
    
    
    
    $
    
    67
    
    
    
    $
    
    13
    
    
    
    $
    
    13Interest Cost
    
    
    
    53
    
    
    
    
    52
    
    
    
    
    17
    
    
    
    
    16
    
    
    
    
    158
    
    
    
    
    155
    
    
    
    
    51
    
    
    
    
    46Expected Return on Plan
      Assets
    
    
    
    (65
    )
    
    
    
    
    (62
    )
    
    
    
    
    (2
    )
    
    
    
    
    (2
    )
    
    
    
    
    (199
    )
    
    
    
    
    (187
    )
    
    
    
    
    (8
    )
    
    
    
    
    (7
    )Amortization of NetTransition Obligation
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    7
    
    
    
    
    7
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    21
    
    
    
    
    21Prior Service Cost
    
    
    
    3
    
    
    
    
    4
    
    
    
    
    4
    
    
    
    
    3
    
    
    
    
    8
    
    
    
    
    12
    
    
    
    
    10
    
    
    
    
    6Loss
    
    
    
    14
    
    
    
    
    12
    
    
    
    
    2
    
    
    
    
    —
    
    
    
    
    41
    
    
    
    
    35
    
    
    
    
    6
    
    
    
    
    2Net Periodic Benefit
      Costs
    
    
    
    27
    
    
    
    
    28
    
    
    
    
    32
    
    
    
    
    28
    
    
    
    
    73
    
    
    
    
    82
    
    
    
    
    93
    
    
    
    
    81Effect of Regulatory
      Asset
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    4
    
    
    
    
    5
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    14
    
    
    
    
    15Total Benefit Costs
    
    
    $
    
    27
    
    
    
    $
    
    28
    
    
    
    $
    
    36
    
    
    
    $
    
    33
    
    
    
    $
    
    73
    
    
    
    $
    
    82
    
    
    
    $
    
    107
    
    
    
    $
    
    96PSE&G, Power, Energy Holdings and Services
Pension costs and OPEB costs for PSE&G, Power, Energy Holdings and Services are detailed as follows:
Pension Benefits
    
    OPEB
    
    Pension Benefits
    
    OPEBQuarters EndedSeptember 30,
    
    Quarters EndedSeptember 30,
    
    Nine Months EndedSeptember 30,
    
    Nine Months EndedSeptember 30,2006
    
    2005
    
    2006
    
    2005
    
    2006
    
    2005
    
    2006
    
    2005(Millions)PSE&G
    
    
    $
    
    14
    
    
    
    $
    
    14
    
    
    
    $
    
    31
    
    
    
    $
    
    29
    
    
    
    $
    
    37
    
    
    
    $
    
    41
    
    
    
    $
    
    91
    
    
    
    $
    
    84Power
    
    
    
    8
    
    
    
    
    8
    
    
    
    
    4
    
    
    
    
    3
    
    
    
    
    22
    
    
    
    
    24
    
    
    
    
    12
    
    
    
    
    9Energy Holdings
    
    
    
    1
    
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    2
    
    
    
    
    2
    
    
    
    
    —
    
    
    
    
    —Services
    
    
    
    4
    
    
    
    
    5
    
    
    
    
    1
    
    
    
    
    1
    
    
    
    
    12
    
    
    
    
    15
    
    
    
    
    4
    
    
    
    
    3Total Benefit Costs
    
    
    $
    
    27
    
    
    
    $
    
    28
    
    
    
    $
    
    36
    
    
    
    $
    
    33
    
    
    
    $
    
    73
    
    
    
    $
    
    82
    
    
    
    $
    
    107
    
    
    
    $
    
    96Note 2. Recent Accounting Standards
The following accounting standards were issued by the Financial Accounting Standards Board (FASB), or the SEC but have not yet been adopted by PSEG.
Statement of Financial Accounting Standards (SFAS) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158)
PSEG, PSE&G, Power and Energy Holdings
In September 2006, the FASB issued SFAS 158, which requires companies to record the under or over funded positions of defined benefit pension and OPEB plans on the balance sheet. For under
  funded plans, the liability would be equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected
  benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, the statement requires that the total unrecognized costs for defined benefit
  pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (OCI), a separate component of Stockholder’s Equity. However, for PSE&G, because the
  amortization of the unrecognized costs is being collected from customers, the accumulated
19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
unrecognized costs at adoption will be recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses, prior service costs and transition obligations arising from the adoption of
  the current pension and OPEB accounting standards, which have not been expensed.
Current accounting guidance requires that unrecognized costs be presented in a footnote to the financial statements as part of a reconciliation of a plan’s funded status to amounts recorded in the
  financial statements. The unrecognized costs are amortized as a component of net periodic pension or OPEB expense. Under the new standard, for Power and Energy Holdings, the charge to OCI will be
  amortized and recorded as net periodic pension cost on the Statement of Operations. For PSE&G, the Regulatory Asset will be amortized and recorded as net periodic pension cost on the Statement of
  Operations.
SFAS 158 is effective for fiscal periods ending after December 15, 2006 and will cause changes to the balance sheet at December 31, 2006 as described above. Assuming a year-end discount rate of
  6.25% and an asset return rate of 8.75%, PSEG expects its aggregate under funded status at December 31, 2006 for both its defined benefit pension plans and its OPEB plans will be approximately
  $1.4 billion. This amount would be recorded in Non-current liabilities on the Balance Sheet. The aggregate unrecognized costs are projected to be approximately $1.1 billion. Of this amount, approximately
  $700 million relates to PSE&G and will be recorded as an increase in regulatory assets. The balance of approximately $400 million will be recorded, net of deferred taxes of approximately $150 million, as a
  charge to OCI. PSEG, PSE&G, Power and Energy Holdings continue to evaluate the impact of this statement, which is expected to have a material impact on PSEG’s, PSE&G’s and Power’s respective
  financial positions. SFAS 158 is not expected to have a material impact on Energy Holding’s financial position.
SFAS No. 157, “Fair Value Measurements” (SFAS 157)
PSEG, PSE&G, Power and Energy Holdings
In September 2006, the FASB issued SFAS 157, which provides a single definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements.
  Prior to SFAS 157, guidance for applying fair value was incorporated into several accounting pronouncements. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific
  measurement, and sets out a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources (observable inputs) and those based on an entity’s own
  assumptions (unobservable inputs). Under SFAS 157, fair value measurements are disclosed by level within that hierarchy, with the highest priority being quoted prices in active markets. While this
  statement does not require any new fair value measurements, the application of this statement will change current practice for some fair value measurements.
This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. PSEG, PSE&G, Power and Energy Holdings are
  evaluating the impact of this new accounting pronouncement.
FIN 48, “Accounting for Uncertainty in Income Taxes ‐ an Interpretation of FASB Statement 109” (FIN 48)
PSEG, PSE&G, Power and Energy Holdings
In July 2006, the FASB issued FIN 48, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that the company
  has taken or expects to take on a tax return. Under FIN 48, the financial statements will reflect expected future tax consequences of such positions presuming the tax authorities’ full knowledge of the
  position and all relevant facts. FIN 48 will require an entity to recognize the benefit of tax positions when it is “more likely-than-not” that the position is sustainable based on the merits of the
20

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
position. FIN 48 also addresses the accrual of interest and penalties related to tax uncertainties and the classification of liabilities on the balance sheet.
FIN 48 is effective as of the beginning of fiscal years that start after December 15, 2006. A company will record the change in net assets that result from the application of FIN 48 as an adjustment to
  Retained Earnings. PSEG, PSE&G, Power and Energy Holdings are evaluating this guidance, which could have a material impact on their respective earnings and financial position.
FSP No. FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction” (FSP 13-2)
PSEG and Energy Holdings
In July 2006, the FASB issued FSP 13-2, which addresses how a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction affects the
  accounting by a lessor for that lease. The FSP amends SFAS No. 13, “Accounting for Leases,” stating that a change in the timing of the above referenced cash flows must be reviewed at least annually. If a
  change in timing has occurred, or is projected to occur, the rate of return and the allocation of income to positive investment years must be recalculated from the inception of the lease.
The guidance in this FSP shall be applied to fiscal years beginning after December 15, 2006. The cumulative effect of applying the provisions of this FSP shall be reported as an adjustment to the
  beginning balance of retained earnings as of the beginning of the period in which this FSP is adopted. PSEG and Energy Holdings are evaluating this guidance, which could have a material impact on their
  respective earnings and financial positions.
The following new accounting standards were adopted by PSEG during 2006.
SFAS No. 123R, “Share-Based Payment, revised 2004” (SFAS 123R)
PSEG
Effective January 1, 2006, PSEG adopted SFAS 123R, which replaces SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS 123) and supersedes Accounting Principles Board (APB)
  Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25). SFAS 123R focuses primarily on accounting for share-based awards to employees in exchange for services, and it requires entities to
  recognize compensation expense for these awards. The cost for equity-based awards is expensed based on their grant date fair value, and liability awards are expensed based on their fair value, which is re-
  measured each reporting period. The pro forma disclosure previously permitted under SFAS 123 is no longer an alternative to financial statement recognition.
Prior to January 1, 2006, PSEG accounted for stock-based awards under the intrinsic value method of APB 25. In accordance with APB 25, PSEG did not record compensation expense related to its
  stock option grants because the strike price was equal to the fair value of the underlying stock on the grant date; however, it did record compensation expense over the requisite service period for restricted
  stock grants and performance unit awards.
SFAS 123R is applicable to all of PSEG’s outstanding unvested share-based payment awards as of January 1, 2006 and all prospective awards using the modified prospective method. Accordingly, the
  financial results for prior periods were not retroactively adjusted to reflect the effects of SFAS 123R. The compensation expense recorded as a result of adopting SFAS 123R was not material. For additional
  information, see Note 12. Stock-Based Compensation.
21

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Note 3. Discontinued Operations, Dispositions and Acquisitions
Discontinued Operations
Power
Waterford Generation Facility (Waterford)
In September 2005, Power completed the sale of its electric generation facility located in Waterford, Ohio to a subsidiary of American Electric Power Company, Inc. In May 2005, Power recognized an
  estimated loss on disposal of $177 million, net of tax benefit of $123 million. In the third quarter of 2005, Power completed the sale of Waterford and recognized an additional loss on disposal of $1 million,
  net of tax. The proceeds of the sale, together with the anticipated reduction in tax liability, were approximately $320 million and were used to retire debt at Power.
Waterford’s operating results for the quarter and nine months ended September 30, 2005, which were reclassified to Discontinued Operations, are summarized below:
Quarter EndedSeptember 30,2005
    
    Nine MonthsEndedSeptember 30,2005(Millions)Operating Revenues
    
    
    $
    
    13
    
    
    
    $
    
    18Loss Before Income Taxes
    
    
    $
    
    10
    
    
    
    $
    
    32Net Loss
    
    
    $
    
    6
    
    
    
    $
    
    19Energy Holdings
Elektrocieplownia Chorzow Elcho Sp. Z o.o. (Elcho) and Elektrownia Skawina SA (Skawina)
On January 31, 2006, Global entered into an agreement with CEZ a.s. to sell its interest in two coal-fired plants in Poland, Elcho and Skawina. The sale was completed on May 29, 2006. Proceeds, net of
  transaction costs, were $476 million, resulting in a gain of $228 million net of tax expense of $142 million. This gain is included in Discontinued Operations. The 2006 operating results for Global’s assets in
  Poland have been reclassified to Discontinued Operations.
Elcho’s and Skawina’s operating results for the quarter ended September 30, 2005 and nine months ended September 30, 2006 and 2005 are summarized below:
Quarter EndedSeptember 30,
    
    Nine Months Ended September 30,2005
    
    2006
    
    2005Elcho
    
    Skawina
    
    Elcho
    
    Skawina
    
    Elcho
    
    Skawina(Millions)Operating Revenues
    
    
    $
    
    21
    
    
    
    $
    
    25
    
    
    
    $
    
    39
    
    
    
    $
    
    44
    
    
    
    $
    
    78
    
    
    
    $
    
    91(Loss) Income Before Income Taxes
    
    
    $
    
    (8
    )
    
    
    
    $
    
    (1
    )
    
    
    
    $
    
    (3
    )
    
    
    
    $
    
    2
    
    
    
    $
    
    12
    
    
    
    $
    
    2Net (Loss) Income
    
    
    $
    
    (9
    )
    
    
    
    $
    
    (1
    )
    
    
    
    $
    
    (2
    )
    
    
    
    $
    
    1
    
    
    
    $
    
    11
    
    
    
    $
    
    222

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
The carrying amounts of the assets of Elcho and Skawina as of December 31, 2005 are summarized in the following table:
As ofDecember 31,2005Elcho
    
    Skawina(Millions)Current Assets
    
    
    $
    
    41
    
    
    
    $
    
    27Noncurrent Assets
    
    
    
    319
    
    
    
    
    111Total Assets of Discontinued Operations
    
    
    $
    
    360
    
    
    
    $
    
    138Current Liabilities
    
    
    $
    
    27
    
    
    
    $
    
    24Noncurrent Liabilities
    
    
    
    336
    
    
    
    
    49Total Liabilities of Discontinued Operations
    
    
    $
    
    363
    
    
    
    $
    
    73Elcho’s and Skawina’s total non-recourse debt amounted to $287 million and $26 million, respectively, as of December 31, 2005.
Dispositions
Energy Holdings
Rio Grande Energia (RGE)
On May 10, 2006, Global entered into an agreement with Companhia Paulista de Force Luz (CPFL) to sell its 32% ownership interest in RGE, a Brazilian electric distribution company. The transaction
  closed on June 23, 2006 and gross proceeds of $185 million were received. The transaction resulted in an after-tax loss of $178 million, primarily related to the devaluation of the Brazilian Real subsequent
  to Global’s acquisition of its interests in RGE in 1997.
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 an after-tax gain of approximately $1 million. Following the sale, Global’s investment in Dhofar Power
  has been accounted for under the equity method.
On May 15, 2006, Global signed an agreement to sell its remaining 46% interest in Dhofar Power to Oman Technical Partners Ltd. (Oman), a consortium formed by The GCC Energy Fund of Dubai,
  Darbat Power of Oman and Malakoff Berhad of Malaysia; therefore, Energy Holdings reclassified the investment to Assets Held for Sale on the Condensed Consolidated Balance Sheet. The sale, which is
  contingent upon obtaining consents from Dhofar Power’s lenders and receiving no objections from the Government of Oman, is expected to close in the fourth quarter of 2006 and generate proceeds of
  approximately $33 million, which is the approximate book value of the investment.
Meiya Power Company Limited (MPC)
In January and April 2005, Global received payments of approximately $38 million and $99 million, respectively, representing the full payment of the receivable relating to the sale of its 50% equity
  interest in MPC in December 2004.
23

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Resources
In January 2005, a KKR Fund, in which Resources had invested, 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.
On October 16, 2006, Resources entered into an agreement under which Puget Sound Energy, Inc. will purchase Whitehorn Units Nos. 2 and 3 from Resources on the current lease expiration date of
  February 2, 2009 for a cash price of approximately $23 million. This transaction is expected to produce incremental after-tax income and cash flow for Resources of approximately $3 million and $17 million
  respectively, at such time.
Acquisitions
Energy Holdings
Prisma 2000 S.p.A. (Prisma)
In May 2006, Global forgave the guarantees of its partner in the Prisma investment of certain loans Global had made to Prisma and converted such loans totaling $38 million into additional equity in
  Prisma, thereby increasing its ownership interest from 50% to 85% and giving Global voting control of the project. As a result, Energy Holdings began consolidating this investment in May 2006 and
  reclassified the investment balance to Property, Plant and Equipment of approximately $62 million, Long-Term Investments of approximately $13 million, Capital Lease Obligations of approximately
  $40 million and certain other assets and liabilities on Energy Holdings’ Condensed Consolidated Balance Sheet. Although the purchase price allocation has not been finalized due to the recent acquisition,
  Energy Holdings recorded certain immaterial purchase accounting adjustments to reflect the plant, contracts and investment in Biomasse Italia S.p.A. (Biomasse) at fair value. The consolidation of Prisma is
  expected to add approximately $45 million of annual revenue to Energy Holdings’ financial statements, and the additional ownership interest is expected to result in a modest increase to Energy Holdings’
  earnings.
Prisma indirectly owns and operates three biomass generation plants in Italy through its ownership of 100% of San Marco Bioenergie S.p.A., which owns a 20 MW plant, and 50% of Biomasse, a
  partnership with Api Holding S.p.A., which owns two plants totaling 60 MW. Global records Prisma’s investment in Biomasse as an equity method investment due to Global’s approximate 43% indirect
  ownership in Biomasse. The output of the plants is sold under power purchase agreements with the Italian national grid (CIP contracts), which include a premium for the renewable energy output. These
  contracts expire from 2009 through 2012.
Note 4. Earnings Per Share (EPS)
PSEG
Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding under
  PSEG’s stock option plans, upon payment of performance units and upon conversion of Participating Units.
24

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
The following table shows the effect of these stock options, performance units and Participating Units on the weighted average number of shares outstanding used in calculating diluted EPS:
Quarters Ended September 30,
    
    Nine Months Ended September 30,2006
    
    2005
    
    2006
    
    2005Basic
    
    Diluted
    
    Basic
    
    Diluted
    
    Basic
    
    Diluted
    
    Basic
    
    DilutedEPS Numerator:Earnings (Millions)Continuing Operations
    
    
    $
    
    374
    
    
    
    $
    
    374
    
    
    
    $
    
    269
    
    
    
    $
    
    269
    
    
    
    $
    
    559
    
    
    
    $
    
    559
    
    
    
    $
    
    640
    
    
    
    $
    
    640Discontinued Operations
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (16
    )
    
    
    
    
    (16
    )
    
    
    
    
    227
    
    
    
    
    227
    
    
    
    
    (184
    )
    
    
    
    
    (184
    )Net Income
    
    
    $
    
    374
    
    
    
    $
    
    374
    
    
    
    $
    
    253
    
    
    
    $
    
    253
    
    
    
    $
    
    786
    
    
    
    $
    
    786
    
    
    
    $
    
    456
    
    
    
    $
    
    456EPS Denominator (Thousands):Weighted Average Common Shares Outstanding
    
    
    
    251,747
    
    
    
    
    251,747
    
    
    
    
    239,034
    
    
    
    
    239,034
    
    
    
    
    251,471
    
    
    
    
    251,471
    
    
    
    
    238,696
    
    
    
    
    238,696Effect of Stock Options
    
    
    
    —
    
    
    
    
    490
    
    
    
    
    —
    
    
    
    
    1,052
    
    
    
    
    —
    
    
    
    
    599
    
    
    
    
    —
    
    
    
    
    1,044Effect of Stock Performance Units
    
    
    
    —
    
    
    
    
    92
    
    
    
    
    —
    
    
    
    
    36
    
    
    
    
    —
    
    
    
    
    91
    
    
    
    
    —
    
    
    
    
    36Effect of Participating Units
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    4,164
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    3,436Total Shares
    
    
    
    251,747
    
    
    
    
    252,329
    
    
    
    
    239,034
    
    
    
    
    244,286
    
    
    
    
    251,471
    
    
    
    
    252,161
    
    
    
    
    238,696
    
    
    
    
    243,212Earnings Per Share:Continuing Operations
    
    
    $
    
    1.48
    
    
    
    $
    
    1.48
    
    
    
    $
    
    1.12
    
    
    
    $
    
    1.10
    
    
    
    $
    
    2.22
    
    
    
    $
    
    2.22
    
    
    
    $
    
    2.68
    
    
    
    $
    
    2.63Discontinued Operations
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (0.06
    )
    
    
    
    
    (0.07
    )
    
    
    
    
    0.90
    
    
    
    
    0.90
    
    
    
    
    (0.77
    )
    
    
    
    
    (0.76
    )Net Income
    
    
    $
    
    1.48
    
    
    
    $
    
    1.48
    
    
    
    $
    
    1.06
    
    
    
    $
    
    1.03
    
    
    
    $
    
    3.12
    
    
    
    $
    
    3.12
    
    
    
    $
    
    1.91
    
    
    
    $
    
    1.87No stock options had an antidilutive effect for the quarters and nine months ended September 30, 2006 and 2005.
Dividend payments on common stock for the quarters ended September 30, 2006 and 2005 were $0.57 and $0.56 per share, respectively, and totaled approximately $144 million and $134 million,
  respectively. Dividend payments on common stock for the nine months ended September 30, 2006 and 2005 were $1.71 and $1.68 per share, respectively, and totaled approximately $430 million and
  $401 million, respectively.
Note 5. Commitments and Contingent Liabilities
Guaranteed Obligations
Power
Power has unconditionally guaranteed payments by its subsidiaries, ER&T and PSEG Power New York Inc. (Power New York) in commodity-related transactions in the ordinary course of business.
  These payment guarantees are provided to counterparties in order to obtain credit under physical and financial agreements for gas, power, pipeline capacity, transportation, oil, electricity and related
  commodities and services. These payment guarantees support the current exposure, interest and other costs on sums due and payable by ER&T and Power New York. Under these agreements, guarantees
  offered for trading and marketing cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. The face value of the
  guarantees outstanding as of September 30, 2006 and December 31, 2005 was approximately $1.4 billion and $1.6 billion, respectively. In order for Power to incur a liability for the face value of the
  outstanding guarantees, ER&T and Power New York 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 and Power New
  York’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 and Power New York being
  simultaneously “out-of-the-money” is highly unlikely due to offsetting positions within the portfolio. 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
25

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
receivable and accounts payable and the forward value on open positions, less any margins posted. The current exposure from such liabilities was $304 million and $549 million as of September 30, 2006 and
  December 31, 2005, respectively.
Power is subject to collateral calls related to commodity contracts that are bilateral and are subject to certain creditworthiness standards as guarantor under performance guarantees for ER&T’s
  agreements. Changes in commodity prices, including fuel, emissions allowances and electricity, can have a material impact on margin requirements under such contracts that are entered into in the normal
  course of business. As of September 30, 2006, Power had posted margin of approximately $59 million, including approximately $49 million in the form of letters of credit, and received margin of
  approximately $67 million, including approximately $65 million in the form of letters of credit, to satisfy collateral obligations and support various contractual and environmental obligations. As of
  December 31, 2005, Power had posted margin of approximately $1.2 billion, including approximately $1 billion in the form of letters of credit, and received margin of approximately $168 million, including
  approximately $115 million in the form of letters of credit.
Collateral obligations may be posted in the form of cash or letters of credit. Assuming no changes in forward energy prices and positions, Power’s collateral requirements can be expected to decline
  over time as its contracts expire.
Power also routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, such future contracts require a deposit of cash
  margin, the amount of which is subject to change based on market movement and in accordance with exchange rules. As of September 30, 2006 and December 31, 2005, Power had deposited margin of
  approximately $171 million and $176 million, respectively, related to exchange-traded transactions that are margined and monitored separately from physical trading activity.
In the event of a deterioration of Power’s credit rating to below investment grade, which represents a two level downgrade from its current ratings, many of these agreements allow the counterparty to
  demand that ER&T provide further performance assurance, generally in the form of a letter of credit or cash. As of September 30, 2006, if Power were to lose its investment grade rating and, assuming all
  counterparties to which ER&T is “out-of-the-money” were contractually entitled to demand, and demanded, performance assurance, ER&T could be required to post additional collateral in an amount equal to
  approximately $509 million. Power believes that it has sufficient liquidity to post such collateral, if necessary.
26

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 September 30, 2006 and December 31, 2005 are as follows:
As ofSubsidiaries/Affiliates
    
    Location
    
    Description
    
    Expiration
      Date
    
    September 30,
      2006
    
    December 31,
      2005(Millions)Skawina
        (a)
    
    Poland
    
    Equity commitment
    
    August 2007
    
    $  6
    
    $    9PSEG
        Global Funding II LLC
    
    Delaware
    
    Contingent guarantee related to debt service obligations associated with Chilquinta
      Energia S.A. (Chilquinta)
    
    April 2011
    
    25
    
    25Prisma
    
    Italy
    
    Leasing agreement guarantee
    
    N/A
    
    19
    
    20Texas
        Independent Energy L.P. (TIE) - Guadalupe
    
    Guadalupe
    
    Interest Rate Swap Guarantee
    
    December 2009
    
    21
    
    33Elcho
        (b)
    
    Poland
    
    Debt Service Reserve Backup
    
    October 2006
    
    —
    
    32PSEG
        Energy Technologies Asset Management Company LLC
    
    New Jersey
    
    Performance guarantee
    
    N/A
    
    3
    
    6Other
    
    Various
    
    Various
    
    N/A
    
    10
    
    13Total
        Contingent Obligations
    
    
    
    
    
    
    
    $84
    
    $138

(a)
    
    
    
    Sold in May 2006. The guaranteed amount has been indemnified by the purchaser, CEZ a.s. For further information, see Note 3. Discontinued Operations, Dispositions and Acquisitions.(b)
    
    
    
    Global’s obligation was terminated as a result of the sale.In September 2003, Energy Holdings completed the sale of PSEG Energy Technologies Inc. (Energy Technologies) and nearly all of its assets. However, Energy Holdings retained certain outstanding
  construction and warranty obligations related to ongoing construction projects previously performed by Energy Technologies. These construction obligations have performance bonds issued by insurance
  companies for which exposure is adequately supported by the outstanding letters of credit shown in the table above for PSEG Energy Technologies Asset Management Company LLC. As of September 30,
  2006, there were $14 million of such bonds outstanding related to uncompleted construction projects and other obligations. These performance bonds are not included in the $84 million of guaranteed
  obligations above.
Environmental Matters
PSEG, PSE&G and Power
Hazardous Substances
The New Jersey Department of Environmental Protection (NJDEP) has regulations in effect concerning site investigation and remediation that require an ecological evaluation of potential damages to
  natural resources in connection with an environmental investigation of contaminated sites. These regulations may substantially increase the costs of environmental investigations and necessary remediation,
  particularly at sites situated on surface water bodies. PSE&G, Power and respective predecessor companies own or owned and/or operate or operated certain facilities situated on surface water bodies, certain
  of which are currently the subject of remedial activities. The financial impact of these regulations is not currently estimable. However, neither PSE&G nor Power anticipates that compliance with these
  regulations will have a material adverse effect on their respective financial positions, results of operations or net cash flows.
27

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
  liabilities arising 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 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 has provided notice to insurers concerning this potential claim.
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 61 other
  PRPs, have entered into an agreement with the EPA or have indicated their intention to enter an agreement that provides for sharing the costs of the $20 million study between the government
  organizations and the PRPs. The EPA recently has notified the PRPs that the cost of the study will greatly exceed the $20 million initially estimated and offered to the PRPs the opportunity to conduct the
  study themselves rather than reimburse the government for the additional costs it incurs. The PRP group is considering the offer and has engaged in discussions with the EPA. Whether the PRP group, or
  some number of the PRPs, agree to assume responsibility for the study will depend upon many factors, including a revised estimated cost of the study, the number of parties who agree to participate and the
  manner in which the parties divide the costs among themselves. 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 requiring some level of remedial action. In addition, the NJDEP has announced initiatives to accelerate the investigation and subsequent remediation of the riverbeds underlying surface
  water bodies that have been impacted by hazardous substances from adjoining sites. Specifically, in 2005, the NJDEP initiated a program on the Delaware River aimed at identifying the 10 most significant
  sites for cleanup. One of the sites identified is a former MGP facility located in Camden, New Jersey. The Remediation Program is periodically reviewed and the estimated costs are revised by
28

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
PSE&G based on regulatory requirements, experience with the program and available remediation technologies. Since the inception of the Remediation Program in 1988 through September 30, 2006, PSE&G
  had expenditures of approximately $366 million.
During the fourth quarter of 2005, PSE&G refined the detailed site estimates. The cost of remediating all sites to completion, as well as the anticipated costs to address MGP-related material discovered
  in two rivers adjacent to former MGP sites, could range between $751 million and $796 million. No amount within the range was considered to be most likely. Therefore, $385 million was accrued as of
  September 30, 2006, which represents the difference between the low end of the total program cost estimate of $751 million and the total incurred costs through September 30, 2006 of $366 million. Of this
  amount, approximately $44 million was recorded in Other Current Liabilities and $341 million was reflected in Other Noncurrent Liabilities. The costs associated with the MGP Remediation Program have
  historically been recovered through the SBC charges to PSE&G ratepayers. As such, a $385 million Regulatory Asset was recorded. PSE&G anticipates spending $44 million in 2006, $45 million in 2007 and an
  average of $36 million per year through 2016 to remediate MGP-related environmental conditions.
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 may order companies 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 requests for information and, in January 2002, reached an agreement with the NJDEP and the EPA to
  resolve allegations of noncompliance with PSD/NSR regulations. Under that agreement, over the course of 10 years, Power agreed to install advanced air pollution controls to reduce emissions of Sulfur
  Dioxide (SO2), Nitrogen Oxide (NOx), particulate matter and mercury from the coal-burning units at the Mercer and Hudson generating stations to ensure compliance with PSD/NSR. The cost of the
  program was approximately $112 million for selective catalytic reduction systems (SCRs) which have been installed at Mercer, as well as additional capital expenditures of approximately $400 million to
  $500 million at Hudson and $150 million to $250 million at Mercer for other pollution control equipment to be installed between December 31, 2006 and December 31, 2012. Power has spent over $6 million
  on supplemental environmental projects and paid a $1.4 million civil penalty. 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 at Hudson by the December 31, 2006 deadline. Power
  has proposed to the NJDEP and the EPA an alternate pollution reduction plan to permit Hudson to continue to operate on coal beyond December 31, 2006. The proposal would require Power to
  compensate for emission reductions contemplated under the 2002 agreement through other emission control technology, operational measures and the retirement of emission allowances until the originally
  specified controls are installed on Hudson or the unit is shutdown. Discussions relating to this issue are ongoing. Power believes that the unit will likely continue to operate after December 31, 2006;
29

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
however, no assurances can be given. Power provided notice to PJM, pursuant to the requirements of its tariff, that Power may be required to deactivate Hudson Unit 2 if an agreement is not reached with
  environmental regulators. The additional capital expenditures referenced above are incremental to the capital expenditure forecast included in the Annual Report on Form 10-K for the year ended
  December 31, 2005.
As a result of ongoing discussions, Power has increased its environmental reserves by approximately $15 million to account for potential civil penalties and other costs. PSEG and Power recorded the
  charge in Other Deductions on their respective Condensed Consolidated Statements of Operations.
Mercury Regulation
New Jersey and Connecticut have adopted standards for the reduction of emissions of mercury from coal-fired electric generating units. The Connecticut legislation requires coal-fired power plants in
  Connecticut to achieve either an emissions limit or a 90% mercury removal efficiency through technology installed to control mercury emissions effective in July 2008. The regulations in New Jersey require
  coal-fired electric generating units in New Jersey to meet certain emissions limits or reduce emissions by 90% by December 15, 2007. Under the New Jersey regulations, companies that are parties to multi-
  pollutant reduction agreements are permitted to postpone such reductions on half of their coal-fired electric generating capacity until December 15, 2012. Power has a multi-pollutant reduction agreement
  with the NJDEP as a result of a consent decree that resolved issues arising out of the PSD and the NSR air pollution control programs at the Hudson, Mercer and Bergen facilities. The estimated costs of
  technology believed to be capable of meeting these emissions limits at Power’s coal-fired unit in Connecticut and at its Mercer Station are included in Power’s capital expenditures forecast. Total estimated
  costs for each project are between $150 million and $200 million.
On September 12, 2006, Connecticut released proposed revisions to mercury regulations that encompass “Permit Requirements for Mercury Emissions from Coal-Fired Electric Generating Units”.
  Power is evaluating these proposed revisions; however, it cannot predict the impact of these proposed revisions.
New Jersey Industrial Site Recovery Act (ISRA)
In the second quarter of 1999, a study was conducted pursuant to ISRA and potential environmental liabilities related to subsurface contamination at certain generating stations were identified. Power
  had a $51 million liability as of September 30, 2006 and December 31, 2005 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.
Permit Renewals
In June 2001, the NJDEP issued a renewed New Jersey Pollutant Discharge Elimination System (NJPDES) permit for Salem Nuclear Generating Station (Salem), which expired in July 2006, allowing
  for the continued operation of Salem with its existing cooling water system. A renewal application prepared in accordance with the new Phase II 316(b) rule was filed with the NJDEP that allows the station
  to continue operating under its existing NJPDES permit until a new permit is issued. Power believes that its application to renew Salem’s NJPDES permit demonstrates that the station meets the Phase II
  316(b) rule’s performance standards for reduction of impingement mortality and entrainment through the station’s existing cooling water intake technology and operations plus implemented restoration
  measures. Power believes that the application further demonstrates that the station meets the Phase II 316(b) rule’s site-specific determination standards without the benefits of restoration. If the NJDEP
  were to require the installation of technologies at the Salem facility to reduce cooling water
30

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
intake flow commensurate with closed-cycle cooling as a result of an unfavorable decision in the litigation that has been filed challenging the Phase II 316(b) rule or otherwise, Power estimates that the costs
  associated with cooling towers for Salem are approximately $1 billion, of which Power’s share would be approximately $575 million. These costs are not included in Power’s currently forecasted capital
  expenditures.
Energy Holdings
Prisma
As
  previously disclosed, Global became a majority owner of Prisma in May 2006.
  During the third quarter of 2006, Global became aware of an investigation concerning
  certain allegations of violations with respect to air emissions at Prisma’s
  20 MW San Marco biomass generating facility. Such alleged violations appear
  to consist primarily of the failure to appropriately monitor and report emissions
  and exceeding certain air emission limits. Global is conducting an investigation
  of the allegations, including the scope and timing of the potential violations,
  and is cooperating with Italian authorities in their investigation. Global believes
  that the plant is currently monitoring and reporting emissions in accordance
  with applicable regulations. In the event that future operations are not in
  compliance with air emissions regulations and associated prescribed limits,
  Italian law may permit the local prosecutor to close the plant to prevent any
  such future violations. If the alleged environmental violations have occurred,
  financial penalties could be assessed, operating restrictions on the plant could
  be implemented by the prosecutor and/or the regulators, including closure, the
  impact of which could be material to Energy Holdings’ results of operations,
  financial position and cash flows. Global expects to complete its investigation
  of the allegations in the fourth quarter of 2006 and discuss the appropriate
  remedies, if any, with the authorities.
New Generation and Development
Power
Power 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. Phase II of the Salem Unit 2 turbine replacement is currently scheduled for 2008 concurrent with steam generator replacement and is anticipated to increase capacity by 26 MW. Phase
  II of the Hope Creek turbine replacement is expected to be completed in 2007 along with the thermal power uprate and is expected to add approximately 125 MW. Power’s expenditures to date
  approximate $217 million (including Interest Capitalized During Construction (IDC) of $20 million) with an aggregate estimated share of total costs for these projects of $244 million (including IDC of
  $24 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.
Energy Holdings
Electroandes S.A. (Electroandes)
A 35 MW expansion project of an existing hydro station at Electroandes, a generating facility in Peru, is under review. Construction has been indefinitely postponed as the project is being re-evaluated.
  No construction funds have been disbursed on the project thus far and capital expenditures related to this project have been removed from Energy Holdings’ forecast.
31

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)
Power
Power seeks to mitigate volatility in its results by contracting in advance for its anticipated electric output as well as its anticipated fuel needs.
As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey Electric Distribution Companies (EDCs) with a portion of their respective BGS requirements
  through the New Jersey BGS auction process, described below. In addition to the BGS-related contracts, Power has entered into firm supply contracts with EDCs in Pennsylvania and Connecticut, as well as
  other firm sales and trading positions and commitments.
PSE&G and Power
PSE&G is required to obtain all electric supply requirements for customers that do not purchase electric supply from third-party suppliers through the annual New Jersey BGS auctions. The BGS auction
  process is a statewide process in which all of the New Jersey EDCs participate. The BGS auctions are “descending 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 the EDCs’ electric supply needs, the auction ends. The BPU renders a decision whether or not to accept
  the auction results within two business days of its conclusion.
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 Interconnection,
  L.L.C. (PJM) Load Serving Entity (LSE) including capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume any migration risk and must satisfy New
  Jersey’s renewable portfolio standards.
Through the BGS auctions, PSE&G has contracted for its anticipated BGS-Fixed Price load, as follows:
Term EndingMay 2006(a)
    
    May 2007(b)
    
    May 2008(c)
    
    May 2009(d)Term
    
    34 months
    
    36 months
    
    36 months
    
    36 monthsLoad (MW)
    
    
    
    2,900
    
    
    
    
    2,840
    
    
    
    
    2,840
    
    
    
    
    2,882$ per kWh
    
    
    $
    
    0.05560
    
    
    
    $
    
    0.05515
    
    
    
    $
    
    0.06541
    
    
    
    $
    
    0.10251

(a)
    
    
    
    Prices set in the February 2003 BGS auction.(b)
    
    
    
    Prices set in the February 2004 BGS auction.(c)
    
    
    
    Prices set in the February 2005 BGS auction.(d)
    
    
    
    Prices set in the February 2006 BGS auction, which became effective on June 1, 2006.PSE&G entered into a full requirements contract through 2007 with Power to meet the supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of its anticipated BGSS
  obligations, as permitted by the BPU. The BPU permits recovery of the cost of gas hedging up to 115 billion cubic feet or approximately 80% of PSE&G’s residential gas supply annually through the BGSS
  tariff. For additional information, see Note 13. Related-Party Transactions.
32

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Minimum Fuel Purchase Requirements
Power
Power purchases coal for certain of its fossil generation stations through various long-term commitments. The total minimum purchase requirements included in these commitments amount to
  approximately $634 million through 2012.
Power has various multi-year requirements-based purchase commitments that average approximately $89 million per year to meet Salem’s and Hope Creek’s nuclear fuel needs, of which Power’s share
  is approximately $64 million per year through 2010. Power has been advised by the co-owner and operator of Peach Bottom, Exelon Generation LLC (Exelon Generation), that it has similar purchase
  contracts to satisfy the fuel requirements for Peach Bottom through 2010, of which Power’s share is approximately $31 million per year.
In addition to its fuel requirements, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas, primarily to meet its gas supply obligations to PSE&G.
  As of September 30, 2006, the total minimum requirements under these contracts were approximately $1.2 billion through 2016.
These purchase obligations are aligned with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.
Energy Holdings
TIE
The Guadalupe and Odessa plants of TIE, an indirect, wholly owned subsidiary of Energy Holdings, have entered into gas supply agreements for their anticipated fuel requirements to satisfy
  obligations under their forward energy sales contracts. As of September 30, 2006, the Guadalupe and Odessa plants, which total approximately 2,000 MW of capacity, had forward energy sales contracts in
  place, which support the majority of their margin expectations for the balance of 2006. The plants had fuel purchase commitments totaling $63 million to fully support these contracts. TIE has also entered
  into an agreement to sell approximately 19% of its aggregate capacity for 2007 through 2010.
Chilquinta
Energy
  Holdings has a 50% indirect ownership interest in Chilquinta Energia (Chilquinta)
  which owns a Chilean natural gas distribution company, Energas. Energas has
  various long-term commitments for natural gas and for firm transportation contracts
  with Metrogas and Electrogas, Chilean gas distribution/transport companies,
  which were entered into to support anticipated sales to its customers.
Due to current natural gas restrictions imposed by Metrogas, Energas may have contracted pipeline transport capacity in excess of available gas. Such transport capacity contracts, which are non-
  recourse to Energy Holdings, have an estimated maximum commitment of up to $22 million pre-tax over the next fifteen years (considering Energy Holdings’ ownership percentage in Energas).
Energas
  continues to review anticipated natural gas supply levels and its transport
  capacity contracts relative to its projected customer needs. Energas is also
  attempting to identify additional sources of gas, including liquified natural
  gas (LNG), and is working to mitigate any potential impact through both legal
  and commercial means. These factors will be considered as the future business
  direction of Energas is assessed.
Operating Services Contract (OSC)
Power
Nuclear has entered into an OSC with Exelon Generation, a subsidiary of Exelon, which commenced on January 17, 2005, relating to the operation of the Hope Creek and Salem nuclear
33

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
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 Generation
  operating model, which defines practices that Exelon Generation has used to
  manage the operations of its own nuclear facilities. 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 discharging
  its obligations, an annual operating services fee of $3 million 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 is in full force
  and effect and currently terminates in January 2007. PSEG has provided notice
  to Exelon that it is electing to continue the OSC for two years during which
  time it will move into a transition phase. PSEG has the right to extend the
  transition phase of the OSC for an additional year if it so elects.
PSEG
  is considering various long-term alternatives, ranging from rebuilding its stand-alone
  nuclear capabilities to long-term Exelon operations that could be accompanied
  by a swap of nuclear capacity. PSEG expects to define a long-term strategy well
  before the two-year period is completed.
Maintenance Agreement
Power
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 fossil 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.
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 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 2017.
Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent fuel storage installations located at reactors or away-from-
  reactor sites for at least 30 years beyond the licensed life for reactor operation (which may include the term of a revised or renewed license). Adequate spent fuel storage capacity is estimated to be available
  through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power has commenced construction of an on-site storage facility that will satisfy the spent fuel storage needs of both Salem and Hope
  Creek through the end of their current respective license lives. Exelon Generation has advised Power that it has a licensed and operational on-site storage facility at Peach Bottom that will satisfy Peach
  Bottom’s 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
34

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
$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 previously received credits from the Nuclear Waste Fund. The letter also demanded a total of approximately $1.5 million of accrued interest. In August 2004, Exelon Generation
  advised Nuclear that it reached a settlement with the U.S. Department of Justice, under which Exelon Generation would be reimbursed for costs associated with the storage of spent nuclear fuel at the
  Peach Bottom facility, a portion of which would be paid to Nuclear as a co-owner of Peach Bottom. Future costs incurred resulting from the DOE delays in accepting spent fuel will be reimbursed annually
  until the DOE fulfills its obligation to accept spent nuclear fuel. In addition, Exelon Generation and Nuclear are required to reimburse the DOE for the previously received credits from the Nuclear Waste
  Fund, plus lost earnings. Under this settlement, Power received approximately $27 million for its share of previously incurred storage costs for Peach Bottom, $22 million of which was used for the required
  reimbursement to the Nuclear Waste Fund. Exelon Generation paid Power approximately $5.4 million for its portion of the spent fuel storage costs reimbursed by the DOE in 2005 for costs incurred
  between October 1, 2003 and June 30, 2005.
In September 2001, Power filed a complaint in the U.S. Court of Federal Claims seeking damages for Salem and Hope Creek 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 Court 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. On September 29, 2006, the U.S. Court of Appeals for the Federal Circuit reversed the adverse U.S. Court of Federal
  Claims jurisdicational ruling. Power is seeking reinstatement of claims in the U.S. Court of Federal Claims. 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 system was found to be obstructed at Salem Unit 1. Power developed a solution to maintain the design function of
  the leakage collection system at Salem Unit 1 and investigated the existence of any structural degradation that might have been caused by the obstruction. The concrete and reinforcing steel laboratory tests
  results were completed in March 2006. Test results that have been collected as part of the ongoing testing indicate that no repairs are anticipated. 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 at Salem Unit 1 were detected in early 2003. This information was reported to the NJDEP and the NRC, as required. Power conducted a
  comprehensive investigation in accordance with NJDEP site remediation regulations to determine the source and extent of the tritium in the groundwater. Power is conducting remedial actions to address
  the contamination in accordance with a remedial action workplan approved by the NJDEP in November 2004. The remedial actions are expected to be ongoing for several years. The costs necessary to
  address this on-site groundwater contamination issue are not expected to be material.
35

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Investment Tax Credits (ITC)
PSEG and PSE&G
As of June 1999, the Internal Revenue Service (IRS) had issued several private letter rulings (PLRs) 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 deregulation. 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 PLR 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 the Internal Revenue Code. PSE&G filed a PLR request with the IRS in 2002.
On December 21, 2005, the U.S. Department of the Treasury (Treasury) proposed new regulations for comment addressing the normalization of ITC, replacing regulations originally proposed in 2003.
  The new proposed regulations, if finalized, would not permit retroactive application. Accordingly, the IRS’s conclusions in the above referenced PLRs would continue to remain in effect for all industry
  deregulations prior to December 21, 2005.
On April 26, 2006, the BPU issued an order to PSE&G revoking its previous instruction and directing PSE&G to withdraw its request for a PLR by April 27, 2006. The BPU asserted that the Treasury’s
  proposed regulation project was the more appropriate authority to rely upon in deciding the ITC issue.
On May 1, 2006, PSE&G filed a motion for reconsideration with the BPU requesting that it modify its April 26, 2006 order to PSE&G to withdraw the PLR request. On May 5, 2006, the BPU denied
  PSE&G’s motion for reconsideration and reiterated its order to withdraw the PLR request. On May 8, 2006, PSE&G filed a petition with the Appellate Court of New Jersey challenging the BPU’s order to
  withdraw the PLR.
On May 11, 2006, the IRS issued a PLR to PSE&G. The PLR concluded that none of the generation ITC could be passed to utility customers without violating the normalization rules. While the holding
  in the PLR is a favorable development for PSE&G, the outstanding Treasury regulation project could overturn the holding in the PLR if the Treasury were to alter the position set out in the December 21,
  2005 proposed regulations. The issue cannot be fully resolved until the final Treasury regulations are issued.
On May 16, 2006, the BPU voted in favor of a special investigation and hearing before the BPU concerning PSE&G’s actions leading up to receiving the PLR, specifically its failure to abide by the BPU
  order to withdraw the request. An order detailing such special investigation has not yet been issued and no investigation has begun.
On October 13, 2006, the Appellate Division of the Superior Court of New Jersey granted PSE&G’s motion to dismiss PSE&G’s appeal of the BPU’s order to withdraw the PLR since PSE&G has already
  received the PLR. The court also determined that if the BPU seeks to take future action against PSE&G based on the alleged violation of its order, PSE&G can restart the appeal.
BPU Deferral Audit
PSEG and PSE&G
The BPU Energy and Audit Division conducts periodic audits of utilities’ deferred balances. A draft Deferral Audit—Phase II report relating to PSE&G for the 12-month period ended July 31, 2003 was
  released by the consultant to the BPU in April 2005. The draft report addresses PSE&G’s SBC, Market Transition Charge (MTC) and Non-Utility Generation (NUG) deferred balances. The BPU released
  the report on May 13, 2005.
36

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
While the consultant to the BPU found that PSE&G’s Phase II 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 Phase I and Phase II four-year transition
  period. The amount in dispute is approximately $114 million. 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.
New Jersey Clean Energy Program
The BPU has approved a funding requirement for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2005 to 2008. The liability for the funding
  requirement has been recorded at the discounted present value. The costs associated with this program will be recovered from PSE&G ratepayers through the SBC over a period of four years and, therefore,
  a Regulatory Asset was also recorded. The liability for the funding requirement as of September 30, 2006 and December 31, 2005 was $274 million and $329 million, respectively.
Leveraged Lease Investments
PSEG and Energy Holdings
Resources faces risks with regard to the creditworthiness of certain lessees that collectively comprise a substantial portion of its investment portfolio. Resources also faces risks related to potential
  changes in the current accounting and tax treatment of certain investments in leveraged leases.
From 1996 through 2002, PSEG, through its indirect wholly owned subsidiary, Resources, entered into a number of leveraged lease transactions in the ordinary course of business. Certain of these
  transactions are similar to a type that the IRS subsequently 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 each of September 30, 2006 and December 31, 2005, Resources’ total gross investment in such transactions was approximately $1.5 billion. The IRS is presently
  reviewing the tax returns of PSEG and its subsidiaries for tax years 1997 through 2003, when Resources entered into the transactions.
On September 27, 2005, the IRS proposed to disallow PSEG’s deductions associated with certain of these leveraged leases which have been designated by the IRS as “listed transactions.” On July 8,
  2006, the IRS proposed to disallow deductions associated with another group of these leveraged leases. The IRS may propose additional disallowances in the future. If deductions associated with these lease
  transactions entered into by PSEG are successfully challenged by the IRS, it could have a material adverse impact on PSEG’s and Energy Holdings’ financial position, results of operations and net cash
  flows and could impact future returns on these transactions. PSEG believes that its tax position related to these transactions is proper based on applicable statutes, regulations and case law and believes that
  it should prevail with respect to any IRS challenge, although no assurances can be given.
If the tax benefits associated with all of the listed lease transactions were completely disallowed by the IRS and sustained on appeal, approximately $741 million of PSEG’s deferred tax liabilities that
  have been recorded under leveraged lease accounting through September 30, 2006 would become currently payable. In addition, interest of approximately $115 million, after-tax, and penalties could be
  assessed. Management assessed the probability of various outcomes to this matter and recorded appropriate reserves in accordance with SFAS No. 5 “Accounting for Contingencies.” Management has also
  prepared various sensitivity analyses regarding potential payment obligations, including scenarios
37

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
that consider the current position of the IRS regarding these types of listed transactions, and believes that Energy Holdings has the financial capacity to meet such potential obligations, if required.
The FASB recently issued additional guidance for leveraged leases. See Note 2. Recent Accounting Standards for additional information.
Restructuring Charge
Power
In June 2005, Power implemented a plan to reduce its Nuclear workforce by approximately 200 positions. The plan included 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 were terminated. Power’s $14 million share of the estimated total cost was recorded in
  2005, approximately $12 million of which had been paid as of September 30, 2006.
Retention Program
PSEG, PSE&G, Power and Energy Holdings
The Retention Program, effective as of December 20, 2004, provided for payments to be made to certain key employees of PSEG who remained employed from the date of execution of the Merger
  Agreement through the date that would have been 90 days after the consummation of the Merger. The amount of a participant’s retention was between 40% and 150% of the participant’s annual base
  salary. PSEG paid the first installment, equal to half of a participant’s total retention payment, in December 2005. The final installment payments, which were contingent on successful completion of the
  Merger, will not be made.
Other
Energy Holdings
Electroandes
In July 2005, Electroandes received a notice from Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, 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 estimated potential amount for past due taxes,
  including associated interest and penalties, is approximately $8 million through September 30, 2006. Electroandes believes it has valid legal defenses to these claims, and has filed an appeal with SUNAT to
  which it has not yet received a response; however, no assurances can be given regarding the outcome of this matter.
Dhofar Power
Since commencing operations in Oman in May 2003, Dhofar Power has experienced a number of unplanned service interruptions, which resulted from a combination of force majeure events and
  breaches of general warranties of the contractors that installed equipment at Dhofar Power. Dhofar Power and the Government of Oman have been in a dispute regarding the applicability and extent of any
  penalties under Dhofar Power’s Concession Agreement arising from these service interruptions. On July 14, 2005, the expert engaged by the parties recommended no penalties be assessed for the 2003
  service interruptions and agreed with Dhofar Power’s interpretation of the Concession Agreement with respect to the criteria to be utilized in assessing penalties. The Government of Oman has exercised its
  right to appeal the expert’s determination to a full arbitration panel. Penalties have also been assessed for service interruptions for subsequent years, which may be addressed in the same arbitration. While
  Dhofar Power believes this matter will be favorably resolved, no assurances can be given.
38

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Dhofar Power and the Government of Oman are also in disagreement on the basis of the calculation of certain monthly allowances to be paid to compensate Dhofar Power for the capital investment
  costs associated with the enhancements and extensions of the transmission and distribution system in Salalah. On August 24, 2005, the expert engaged by the parties found in favor of Dhofar Power with
  respect to the criteria to be used in determining the monthly allowances. In the view of Dhofar Power, the Government of Oman has failed to timely exercise its right to appeal the expert’s determination to
  a full arbitration panel. The Government of Oman has now paid all sums previously due, totaling approximately $1 million, and is continuing to make payments on the basis of Dhofar Power’s calculations,
  but has not agreed that it is obligated to continue to pay Dhofar Power on the basis recognized by the expert. Dhofar Power will seek to enforce the expert’s determination that it is entitled to
  approximately $1 million annually through December 2018 and believes that this matter will be favorably resolved in 2006, although no assurances can be given.
Note 6. Financial Risk Management Activities
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
  counterbalance the gains or losses on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, PSE&G, Power and Energy Holdings uses derivative instruments as risk
  management tools consistent with its respective business plan and prudent business practices.
Derivative Instruments and Hedging Activities
Power
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.
Energy Trading Contracts (ETCs)
Power
Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, firm transmission rights (FTRs), coal, oil and emissions allowances in the spot, forward and
  futures markets, primarily in PJM, but also in the surrounding region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana, and natural gas in the producing region.
Power marks to market its derivative ETCs in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133), with changes in fair value
  charged to the Condensed Consolidated Statements of Operations. Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market exists,
  modeling techniques are employed using assumptions reflective of current market rates, yield curves
39

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
and forward prices, as applicable, to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results.
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 and futures transactions to hedge the price of fuel to meet its fuel purchase requirements. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of
  September 30, 2006, the fair value of these hedges was $(292) million. These hedges, along with realized losses on hedges of $20 million retained in Accumulated Other Comprehensive Loss (OCL), resulted
  in a $(183) million after-tax impact on OCL. As of December 31, 2005, the fair value of these hedges was $(951) million. These hedges, along with realized gains on hedges of $11 million retained in OCL,
  resulted in a $(558) million after-tax impact on OCL. During the 12 months ending September 30, 2007, $102 million (after-tax) of net unrealized and realized losses on these commodity derivatives is
  expected to be reclassified to earnings. Approximately $90 million of after-tax unrealized losses on these commodity derivatives in OCL is expected to be reclassified to earnings for the 12 months ending
  September 30, 2008. Ineffectiveness associated with these hedges, as defined in SFAS 133, was immaterial at September 30, 2006. The expiration date of the longest-dated cash flow hedge is in 2009.
Other Derivatives
Power also enters into certain other contracts that are derivatives, but do not qualify for hedge accounting under SFAS 133. Most of these contracts are used for fuel purchases for generation
  requirements and for electricity purchases for contractual sales obligations. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs or Operating Revenues, as
  appropriate, on the Condensed Consolidated Statements of Operations. The net fair value of these instruments as of September 30, 2006 was $3 million. The net fair value of these instruments as of
  December 31, 2005 was not material.
Energy Holdings
Other Derivatives
TIE enters into electricity forward and capacity sale contracts to sell its 2,000 MW capacity for portions of the current calendar year and into the daily spot market. TIE also enters into gas purchase
  contracts to specifically match the generation requirements to support the electricity forward sales contracts. Although these contracts fix the amount of revenue, fuel costs and cash flows, and thereby
  provide financial stability to TIE, these contracts are, based on their terms, derivatives that do not meet the specific accounting criteria in SFAS 133 to qualify for the normal purchases and normal sales
  exception, or to be designated as a hedge for accounting purposes. As a result, these contracts must be recorded at fair value. The net fair value of the open positions was approximately $53 million and
  $(7) million as of September 30, 2006 and December 31, 2005, respectively.
40

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Interest Rates
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed and
  floating rate debt and interest rate derivatives.
Fair Value Hedges
PSEG and Power
In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009. PSEG used an interest rate swap to convert Power’s fixed-rate debt into variable-rate debt. The interest rate swap is
  designated and effective as a fair value hedge. The fair value changes of the interest rate swap are fully offset by the fair value changes in the underlying debt. As of September 30, 2006 and December 31,
  2005, the fair value of the hedge was $(9) million and $(10) million, respectively.
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. Except for PSE&G’s cash flow hedges, the fair value changes of these derivatives are initially recorded in
  Accumulated Other Comprehensive Income (Loss). As of September 30, 2006, the fair value of these cash flow hedges was $(6) million, primarily at PSE&G. As of December 31, 2005, the fair value of these
  cash flow hedges was $(17) million, including $(11) million and $(6) million at PSE&G and Energy Holdings, respectively. The $(5) million and $(11) million at PSE&G as of September 30, 2006 and December
  31, 2005, respectively, is not included in OCL, as it is deferred as a Regulatory Asset and is expected to be recovered from PSE&G’s customers. During the 12 months ending September 30, 2007, $2 million of
  unrealized losses (net of taxes) on interest rate derivatives in Accumulated Other Comprehensive Income (Loss) is expected to be reclassified to earnings at PSEG and Energy Holdings. As of September
  30, 2006, there was essentially no hedge ineffectiveness associated with these hedges. The fair value amounts above as of December 31, 2005 do not include approximately $(60) million for the cash flow
  hedges at Elcho, which had been reclassified into Discontinued Operations.
Other Derivatives
Energy Holdings
As of September 30, 2006, Energy Holdings had no cross-currency interest rate swaps where changes in fair values of such swaps are recorded in Income from Equity Method Investments on the
  Condensed Consolidated Statements of Operations. The fair values of these swaps at December 31, 2005 totaled approximately $(2) million.
Foreign Currencies
Energy Holdings
Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of its risks is that some of its foreign
  subsidiaries and affiliates have functional currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, Global and certain of its foreign subsidiaries and affiliates have entered
  into monetary obligations and maintain receipts/receivables in U.S. Dollars or currencies other than their own functional currencies. Global, a U.S. Dollar functional currency entity, is primarily exposed to
41

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
changes in the Euro, the Peruvian Nuevo Sol and the Chilean Peso. Changes in valuation of these currencies can impact the value of Global’s investments. Global has attempted to limit potential foreign
  exchange exposure by entering into revenue contracts that adjust for changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements to manage risk related to
  certain foreign currency fluctuations.
As of September 30, 2006, due to the strengthening of the Chilean Peso relative to the U.S. Dollar, the net cumulative foreign currency revaluations have increased the total amount of Global’s
  Member’s Equity by $115 million.
In November and December 2005, Energy Holdings purchased foreign currency options in order to hedge the majority of its 2006 expected earnings denominated in Brazilian Real, Chilean Pesos and
  Peruvian Nuevo Soles. These options are not considered hedges for accounting purposes under SFAS 133 and, as a result, changes in their fair value are recorded directly to earnings. Energy Holdings
  terminated its remaining Brazilian Real options on June 28, 2006 following its sale of RGE. The fair value of the options outstanding at September 30, 2006 was immaterial. At December 31, 2005, the fair
  value of the options was approximately $2 million.
Hedges of Net Investments in Foreign Operations
Energy Holdings
In March 2004 and April 2004, Energy Holdings entered into four cross-currency interest rate swap agreements. The swaps are designed to hedge the net investment in a foreign subsidiary associated
  with the exposure to the U.S. Dollar to Chilean Peso exchange rate. The fair value of the cross-currency swaps was $(25) million and $(33) million as of September 30, 2006 and December 31, 2005,
  respectively. The change in fair value is recorded net of tax in Cumulative Translation Adjustment within Accumulated Other Comprehensive Income (Loss). As a result, Energy Holdings’ Member’s
  Equity was reduced by $22 million as of September 30, 2006.
Note 7. Comprehensive Income (Loss), Net of Tax
PSE&G
    
    Power (A)
    
    EnergyHoldings (B)
    
    Other (C)
    
    ConsolidatedTotal(Millions)For the Quarter Ended September 30, 2006:Net Income (Loss)
    
    
    $
    
    88
    
    
    
    $
    
    205
    
    
    
    $
    
    101
    
    
    
    $
    
    (20
    )
    
    
    
    $
    
    374Other Comprehensive Income
    
    
    
    1
    
    
    
    
    204
    
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    206Comprehensive Income (Loss)
    
    
    $
    
    89
    
    
    
    $
    
    409
    
    
    
    $
    
    102
    
    
    
    $
    
    (20
    )
    
    
    
    $
    
    580For the Quarter Ended September 30, 2005:Net Income (Loss)
    
    
    $
    
    115
    
    
    
    $
    
    125
    
    
    
    $
    
    39
    
    
    
    $
    
    (26
    )
    
    
    
    $
    
    253Other Comprehensive (Loss) Income
    
    
    
    —
    
    
    
    
    (291
    )
    
    
    
    
    101
    
    
    
    
    (7
    )
    
    
    
    
    (197
    )Comprehensive Income (Loss)
    
    
    $
    
    115
    
    
    
    $
    
    (166
    )
    
    
    
    $
    
    140
    
    
    
    $
    
    (33
    )
    
    
    
    $
    
    56For the Nine Months Ended September 30, 2006:Net Income (Loss)
    
    
    $
    
    200
    
    
    
    $
    
    394
    
    
    
    $
    
    251
    
    
    
    $
    
    (59
    )
    
    
    
    $
    
    786Other Comprehensive Income
    
    
    
    1
    
    
    
    
    383
    
    
    
    
    192
    
    
    
    
    —
    
    
    
    
    576Comprehensive Income (Loss)
    
    
    $
    
    201
    
    
    
    $
    
    777
    
    
    
    $
    
    443
    
    
    
    $
    
    (59
    )
    
    
    
    $
    
    1,362For the Nine Months Ended September 30, 2005:Net Income (Loss)
    
    
    $
    
    282
    
    
    
    $
    
    106
    
    
    
    $
    
    140
    
    
    
    $
    
    (72
    )
    
    
    
    $
    
    456Other Comprehensive (Loss) Income
    
    
    
    —
    
    
    
    
    (395
    )
    
    
    
    
    81
    
    
    
    
    (2
    )
    
    
    
    
    (316
    )Comprehensive Income (Loss)
    
    
    $
    
    282
    
    
    
    $
    
    (289
    )
    
    
    
    $
    
    221
    
    
    
    $
    
    (74
    )
    
    
    
    $
    
    140

(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.42

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
(B)
    
    
    
    Changes at Energy Holdings primarily relate to the realization of losses on Brazilian currency as a result of the sale of RGE 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
PSEG
On September 1, 2006, PSEG began using treasury stock to settle the exercise of stock options. Previously, PSEG had purchased shares on the open market to meet the exercise of stock options.
  Through September 30, 2006, PSEG issued approximately 121,067 shares of its treasury stock in connection with settling the stock options for approximately $5 million.
During the nine months ended September 30, 2006, PSEG issued approximately 790,825 shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Program
  for approximately $51 million.
In February 2006, PSEG redeemed $154 million of its Subordinated Debentures underlying $150 million of Enterprise Capital Trust II, Floating Rate Capital Securities and its common equity
  investment in the trust.
PSE&G
On June 23, 2006, PSE&G repaid at maturity $174 million of its Floating Rate Series A First and Refunding Mortgage Bonds.
On March 1, 2006, PSE&G repaid at maturity $148 million of its 6.75% Series UU First and Refunding Mortgage Bonds.
In September 2006, June 2006 and March 2006, Transition Funding repaid approximately $41 million, $35 million and $36 million, respectively, of its transition bonds.
In June 2006, Transition Funding II repaid approximately $3 million of its transition bonds.
Power
In April 2006, Power repaid at maturity $500 million of its 6.875% Senior Notes.
Energy Holdings
In January 2006, Energy Holdings redeemed $309 million of its 7.75% Senior Notes due in 2007.
On February 17, 2006, the maturity of the Odessa‐Ector Power Partners, L.P (Odessa) debt was extended to December 31, 2009. Interest on the debt is based on a spread (currently 2.25%) above
  LIBOR. On September 29, 2006, an interest rate swap took effect, which converts the floating LIBOR interest rate on approximately 80% of Odessa’s debt to a fixed rate of 5.4275% through December 31,
  2009.
On
  October 23, 2006, Energy Holdings redeemed $300 million of its $507 million
  outstanding 8.625% Senior Notes due in 2008. Additionally, on September 20,
  2006, Energy Holdings made a cash distribution to PSEG of $425 million in the
  form of a return of capital.
During the first nine months of 2006, Energy Holdings’ repaid approximately $37 million of non-recourse debt, of which $30 million was paid by Global, primarily related to Sociedad Austral de
  Electricidad S.A. and TIE, $5 million by Resources and $2 million by EGDC.
43

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Note 9. Other Income and Deductions
PSE&G
    
    Power
    
    EnergyHoldings
    
    Other (A)
    
    ConsolidatedTotal(Millions)Other Income:For the Quarter Ended September 30, 2006:Interest and Dividend Income
    
    
    $
    
    3
    
    
    
    $
    
    3
    
    
    
    $
    
    12
    
    
    
    $
    
    (7
    )
    
    
    
    $
    
    11Disposition of Property
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1NDT Fund Realized Gains
    
    
    
    —
    
    
    
    
    20
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    20NDT Interest and Dividend Income
    
    
    
    —
    
    
    
    
    10
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    10Other
    
    
    
    3
    
    
    
    
    4
    
    
    
    
    2
    
    
    
    
    —
    
    
    
    
    9Total Other Income
    
    
    $
    
    6
    
    
    
    $
    
    38
    
    
    
    $
    
    14
    
    
    
    $
    
    (7
    )
    
    
    
    $
    
    51For the Quarter Ended September 30, 2005:Interest and Dividend Income
    
    
    $
    
    2
    
    
    
    $
    
    1
    
    
    
    $
    
    1
    
    
    
    $
    
    2
    
    
    
    $
    
    6Disposition of Property
    
    
    
    —
    
    
    
    
    5
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    5Gain on Investments
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    8
    
    
    
    
    8NDT Fund Realized Gains
    
    
    
    —
    
    
    
    
    60
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    60NDT Interest and Dividend Income
    
    
    
    —
    
    
    
    
    8
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    8Foreign Currency Gains
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    4
    
    
    
    
    —
    
    
    
    
    4Other
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1Total Other Income
    
    
    $
    
    3
    
    
    
    $
    
    74
    
    
    
    $
    
    5
    
    
    
    $
    
    10
    
    
    
    $
    
    92For the Nine Months Ended September 30, 2006:Interest and Dividend Income
    
    
    $
    
    9
    
    
    
    $
    
    10
    
    
    
    $
    
    22
    
    
    
    $
    
    (11
    )
    
    
    
    $
    
    30Disposition of Property
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1NDT Fund Realized Gains
    
    
    
    —
    
    
    
    
    69
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    69NDT Interest and Dividend Income
    
    
    
    —
    
    
    
    
    29
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    29Foreign Currency Gains
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    4
    
    
    
    
    —
    
    
    
    
    4Change in Derivative Fair Value
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    1Other
    
    
    
    9
    
    
    
    
    4
    
    
    
    
    6
    
    
    
    
    —
    
    
    
    
    19Total Other Income
    
    
    $
    
    18
    
    
    
    $
    
    113
    
    
    
    $
    
    33
    
    
    
    $
    
    (11
    )
    
    
    
    $
    
    153For the Nine Months Ended September 30, 2005:Interest and Dividend Income
    
    
    $
    
    6
    
    
    
    $
    
    4
    
    
    
    $
    
    10
    
    
    
    $
    
    1
    
    
    
    $
    
    21Disposition of Property
    
    
    
    —
    
    
    
    
    5
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    5Gain on Sale of Investments
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    8
    
    
    
    
    9NDT Fund Realized Gains
    
    
    
    —
    
    
    
    
    100
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    100NDT Interest and Dividend Income
    
    
    
    —
    
    
    
    
    25
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    25Foreign Currency Gains
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    5
    
    
    
    
    —
    
    
    
    
    5Change in Derivative Fair Value
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    1Other
    
    
    
    1
    
    
    
    
    1
    
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    3Total Other Income
    
    
    $
    
    7
    
    
    
    $
    
    135
    
    
    
    $
    
    18
    
    
    
    $
    
    9
    
    
    
    $
    
    16944

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
PSE&G
    
    Power
    
    EnergyHoldings
    
    Other (A)
    
    ConsolidatedTotal(Millions)Other Deductions:For the Quarter Ended September 30, 2006:Donations
    
    
    $
    
    —
    
    
    
    $
    
    —
    
    
    
    $
    
    —
    
    
    
    $
    
    1
    
    
    
    $
    
    1Foreign Currency Losses
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    2
    
    
    
    
    —
    
    
    
    
    2Change in Derivative Fair Value
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    1NDT Fund Realized Losses and Expenses
    
    
    
    —
    
    
    
    
    12
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    12Loss on Extinguishment of Debt
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    12
    
    
    
    
    —
    
    
    
    
    12Environmental Reserves
    
    
    
    —
    
    
    
    
    15
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    15Other
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    1Total Other Deductions
    
    
    $
    
    —
    
    
    
    $
    
    27
    
    
    
    $
    
    16
    
    
    
    $
    
    1
    
    
    
    $
    
    44For the Quarter Ended September 30, 2005:Donations
    
    
    $
    
    —
    
    
    
    $
    
    —
    
    
    
    $
    
    —
    
    
    
    $
    
    14
    
    
    
    $
    
    14Foreign Currency Losses
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    1NDT Fund Realized Losses and Expenses
    
    
    
    —
    
    
    
    
    12
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    12Other
    
    
    
    1
    
    
    
    
    1
    
    
    
    
    2
    
    
    
    
    —
    
    
    
    
    4Total Other Deductions
    
    
    $
    
    1
    
    
    
    $
    
    13
    
    
    
    $
    
    3
    
    
    
    $
    
    14
    
    
    
    $
    
    31For the Nine Months Ended September 30, 2006:Donations
    
    
    $
    
    2
    
    
    
    $
    
    —
    
    
    
    $
    
    —
    
    
    
    $
    
    1
    
    
    
    $
    
    3Foreign Currency Losses
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    8
    
    
    
    
    —
    
    
    
    
    8Change in Derivative Fair Value
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    3
    
    
    
    
    —
    
    
    
    
    3NDT Fund Realized Losses and Expenses
    
    
    
    —
    
    
    
    
    44
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    44Minority Interest
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    1Loss on Extinguishment of Debt
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    12
    
    
    
    
    —
    
    
    
    
    12Environmental Reserves
    
    
    
    —
    
    
    
    
    15
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    15Other
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    4
    
    
    
    
    —
    
    
    
    
    5Total Other Deductions
    
    
    $
    
    2
    
    
    
    $
    
    60
    
    
    
    $
    
    27
    
    
    
    $
    
    2
    
    
    
    $
    
    91For the Nine Months Ended September 30, 2005:Donations
    
    
    $
    
    1
    
    
    
    $
    
    1
    
    
    
    $
    
    —
    
    
    
    $
    
    14
    
    
    
    $
    
    16Foreign Currency Losses
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    12
    
    
    
    
    —
    
    
    
    
    12Change in Derivative Fair Value
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    3
    
    
    
    
    —
    
    
    
    
    3NDT Fund Realized Losses and Expenses
    
    
    
    —
    
    
    
    
    31
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    31Minority Interest
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    1Other
    
    
    
    1
    
    
    
    
    1
    
    
    
    
    2
    
    
    
    
    (1
    )
    
    
    
    
    3Total Other Deductions
    
    
    $
    
    2
    
    
    
    $
    
    33
    
    
    
    $
    
    17
    
    
    
    $
    
    14
    
    
    
    $
    
    66

(A)
    
    
    
    Other consists of reclassifications for minority interests in PSEG’s consolidated results of operations and intercompany eliminations at PSEG (as parent company).45

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Note 10. Income Taxes
An analysis of the tax provision expense is as follows:
PSE&G
    
    Power
    
    EnergyHoldings
    
    Other (A)
    
    ConsolidatedTotal(Millions)For the Quarter Ended September 30, 2006:Income (Loss) from Continuing Operations Before Income Taxes
    
    
    $
    
    157
    
    
    
    $
    
    360
    
    
    
    $
    
    121
    
    
    
    $
    
    (35
    )
    
    
    
    $
    
    603Tax Computed at the Statutory Rate
    
    
    
    55
    
    
    
    
    126
    
    
    
    
    42
    
    
    
    
    (12
    )
    
    
    
    
    211Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:State Income Taxes After Federal Benefit
    
    
    
    12
    
    
    
    
    23
    
    
    
    
    (3
    )
    
    
    
    
    (2
    )
    
    
    
    
    30Rate Differential of Foreign Operations
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (21
    )
    
    
    
    
    —
    
    
    
    
    (21
    )Plant Related Items
    
    
    
    4
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    4Other
    
    
    
    (2
    )
    
    
    
    
    6
    
    
    
    
    2
    
    
    
    
    (1
    )
    
    
    
    
    5Total Income Tax Expense (Benefit)
    
    
    $
    
    69
    
    
    
    $
    
    155
    
    
    
    $
    
    20
    
    
    
    $
    
    (15
    )
    
    
    
    $
    
    229Effective Income Tax Rate
    
    
    
    43.9
    %
    
    
    
    
    43.1
    %
    
    
    
    
    16.5
    %
    
    
    
    
    42.9
    %
    
    
    
    
    38.0
    %For the Quarter Ended September 30, 2005:Income (Loss) from Continuing Operations Before Income Taxes
    
    
    $
    
    189
    
    
    
    $
    
    233
    
    
    
    $
    
    75
    
    
    
    $
    
    (45
    )
    
    
    
    $
    
    452Tax Computed at the Statutory Rate
    
    
    
    67
    
    
    
    
    82
    
    
    
    
    26
    
    
    
    
    (16
    )
    
    
    
    
    159Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:State Income Taxes After Federal Benefit
    
    
    
    13
    
    
    
    
    13
    
    
    
    
    (1
    )
    
    
    
    
    —
    
    
    
    
    25Repatriation
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    9
    
    
    
    
    —
    
    
    
    
    9Rate Differential of Foreign Operations
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (7
    )
    
    
    
    
    —
    
    
    
    
    (7
    )Plant Related Items
    
    
    
    (5
    )
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (5
    )Other
    
    
    
    (1
    )
    
    
    
    
    6
    
    
    
    
    —
    
    
    
    
    (3
    )
    
    
    
    
    2Total Income Tax Expense (Benefit)
    
    
    $
    
    74
    
    
    
    $
    
    101
    
    
    
    $
    
    27
    
    
    
    $
    
    (19
    )
    
    
    
    $
    
    183Effective Income Tax Rate
    
    
    
    39.2
    %
    
    
    
    
    43.3
    %
    
    
    
    
    36.0
    %
    
    
    
    
    42.2
    %
    
    
    
    
    40.5
    %For the Nine Months Ended September 30, 2006:Income (Loss) from Continuing Operations Before Income Taxes
    
    
    $
    
    360
    
    
    
    $
    
    684
    
    
    
    $
    
    (6
    )
    
    
    
    $
    
    (100
    )
    
    
    
    $
    
    938Tax Computed at the Statutory Rate
    
    
    
    126
    
    
    
    
    239
    
    
    
    
    (2
    )
    
    
    
    
    (35
    )
    
    
    
    
    328Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:State Income Taxes After Federal Benefit
    
    
    
    27
    
    
    
    
    42
    
    
    
    
    (8
    )
    
    
    
    
    (6
    )
    
    
    
    
    55Rate Differential of Foreign Operations
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (24
    )
    
    
    
    
    —
    
    
    
    
    (24
    )Plant Related Items
    
    
    
    12
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    12Other
    
    
    
    (5
    )
    
    
    
    
    9
    
    
    
    
    3
    
    
    
    
    1
    
    
    
    
    8Total Income Tax Expense (Benefit)
    
    
    $
    
    160
    
    
    
    $
    
    290
    
    
    
    $
    
    (31
    )
    
    
    
    $
    
    (40
    )
    
    
    
    $
    
    379Effective Income Tax Rate
    
    
    
    44.4
    %
    
    
    
    
    42.4
    %
    
    
    
    
    N/A
    
    
    
    
    40.0
    %
    
    
    
    
    40.4
    %For the Nine Months Ended September 30, 2005:Income (Loss) from Continuing Operations Before Income Taxes
    
    
    $
    
    473
    
    
    
    $
    
    528
    
    
    
    $
    
    170
    
    
    
    $
    
    (119
    )
    
    
    
    $
    
    1,052Tax Computed at the Statutory Rate
    
    
    
    166
    
    
    
    
    185
    
    
    
    
    60
    
    
    
    
    (42
    )
    
    
    
    
    369Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:State Income Taxes After Federal Benefit
    
    
    
    33
    
    
    
    
    30
    
    
    
    
    (3
    )
    
    
    
    
    (1
    )
    
    
    
    
    59Repatriation
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    9
    
    
    
    
    —
    
    
    
    
    9Rate Differential of Foreign Operations
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (27
    )
    
    
    
    
    —
    
    
    
    
    (27
    )Plant Related Items
    
    
    
    (4
    )
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (4
    )Lease Rate Differential
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    2
    
    
    
    
    —
    
    
    
    
    2Other
    
    
    
    (4
    )
    
    
    
    
    10
    
    
    
    
    1
    
    
    
    
    (3
    )
    
    
    
    
    4Total Income Tax Expense (Benefit)
    
    
    $
    
    191
    
    
    
    $
    
    225
    
    
    
    $
    
    42
    
    
    
    $
    
    (46
    )
    
    
    
    $
    
    412Effective Income Tax Rate
    
    
    
    40.4
    %
    
    
    
    
    42.6
    %
    
    
    
    
    24.7
    %
    
    
    
    
    38.7
    %
    
    
    
    
    39.2
    %

(A)
    
    
    
    PSEG’s other activities include amounts applicable to PSEG (as parent company) that primarily relate to financing and certain administrative and general costs.46

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:
PSE&G
    
    Power
    
    Energy Holdings
    
    
    
    ConsolidatedTotalResources
    
    Global
    
    Other (A)
    
    Other (B)(Millions)For the Quarter Ended September 30, 2006:Total Operating Revenues
    
    
    $
    
    2,017
    
    
    
    $
    
    1,489
    
    
    
    $
    
    40
    
    
    
    $
    
    358
    
    
    
    $
    
    3
    
    
    
    $
    
    (515
    )
    
    
    
    $
    
    3,392Income (Loss) from Continuing Operations
    
    
    
    88
    
    
    
    
    205
    
    
    
    
    10
    
    
    
    
    92
    
    
    
    
    (1
    )
    
    
    
    
    (20
    )
    
    
    
    
    374Net Income (Loss)
    
    
    
    88
    
    
    
    
    205
    
    
    
    
    10
    
    
    
    
    92
    
    
    
    
    (1
    )
    
    
    
    
    (20
    )
    
    
    
    
    374Preferred Securities Dividends/Preference Unit Distributions
    
    
    
    (1
    )
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    —Segment Earnings (Loss)
    
    
    
    87
    
    
    
    
    205
    
    
    
    
    10
    
    
    
    
    92
    
    
    
    
    (1
    )
    
    
    
    
    (19
    )
    
    
    
    
    374Gross Additions to Long-Lived Assets
    
    
    
    133
    
    
    
    
    123
    
    
    
    
    —
    
    
    
    
    17
    
    
    
    
    —
    
    
    
    
    2
    
    
    
    
    275For the Quarter Ended September 30, 2005:Total Operating Revenues
    
    
    $
    
    1,934
    
    
    
    $
    
    1,444
    
    
    
    $
    
    52
    
    
    
    $
    
    280
    
    
    
    $
    
    2
    
    
    
    $
    
    (388
    )
    
    
    
    $
    
    3,324Income (Loss) from Continuing Operations
    
    
    
    115
    
    
    
    
    132
    
    
    
    
    17
    
    
    
    
    32
    
    
    
    
    (1
    )
    
    
    
    
    (26
    )
    
    
    
    
    269Loss from Discontinued Operations, net of tax
    
    
    
    —
    
    
    
    
    (6
    )
    
    
    
    
    —
    
    
    
    
    (9
    )
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (15
    )Loss on Disposal of Discontinued Operations, net of tax
    
    
    
    —
    
    
    
    
    (1
    )
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (1
    )Net Income (Loss)
    
    
    
    115
    
    
    
    
    125
    
    
    
    
    17
    
    
    
    
    23
    
    
    
    
    (1
    )
    
    
    
    
    (26
    )
    
    
    
    
    253Preferred Securities Dividends/Preference Unit Distributions
    
    
    
    (1
    )
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    —Segment Earnings (Loss)
    
    
    
    114
    
    
    
    
    125
    
    
    
    
    17
    
    
    
    
    23
    
    
    
    
    (1
    )
    
    
    
    
    (25
    )
    
    
    
    
    253Gross Additions to Long-Lived Assets
    
    
    
    133
    
    
    
    
    118
    
    
    
    
    —
    
    
    
    
    7
    
    
    
    
    1
    
    
    
    
    12
    
    
    
    
    271For the Nine Months Ended September 30, 2006:Total Operating Revenues
    
    
    $
    
    5,901
    
    
    
    $
    
    4,591
    
    
    
    $
    
    134
    
    
    
    $
    
    939
    
    
    
    $
    
    7
    
    
    
    $
    
    (2,056
    )
    
    
    
    $
    
    9,516Income (Loss) from Continuing Operations
    
    
    
    200
    
    
    
    
    394
    
    
    
    
    49
    
    
    
    
    (22
    )
    
    
    
    
    (3
    )
    
    
    
    
    (59
    )
    
    
    
    
    559Loss from Discontinued Operations, net of tax
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (1
    )
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (1
    )Income on Disposal of Discontinued Operations, net of tax
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    228
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    228Net Income (Loss)
    
    
    
    200
    
    
    
    
    394
    
    
    
    
    49
    
    
    
    
    205
    
    
    
    
    (3
    )
    
    
    
    
    (59
    )
    
    
    
    
    786Preferred Securities Dividends/Preference Unit Distributions
    
    
    
    (3
    )
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    3
    
    
    
    
    —Segment Earnings (Loss)
    
    
    
    197
    
    
    
    
    394
    
    
    
    
    49
    
    
    
    
    205
    
    
    
    
    (3
    )
    
    
    
    
    (56
    )
    
    
    
    
    786Gross Additions to Long Lived Assets
    
    
    
    392
    
    
    
    
    316
    
    
    
    
    1
    
    
    
    
    36
    
    
    
    
    —
    
    
    
    
    3
    
    
    
    
    748For the Nine Months Ended September 30, 2005:Total Operating Revenues
    
    
    $
    
    5,559
    
    
    
    $
    
    4,234
    
    
    
    $
    
    141
    
    
    
    $
    
    769
    
    
    
    $
    
    7
    
    
    
    $
    
    (1,770
    )
    
    
    
    $
    
    8,940Income (Loss) from Continuing Operations
    
    
    
    282
    
    
    
    
    303
    
    
    
    
    39
    
    
    
    
    91
    
    
    
    
    (3
    )
    
    
    
    
    (72
    )
    
    
    
    
    640(Loss) Income from Discontinued Operations, net of tax
    
    
    
    —
    
    
    
    
    (19
    )
    
    
    
    
    —
    
    
    
    
    13
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (6
    )Loss on Disposal of Discontinued Operations, net of tax
    
    
    
    —
    
    
    
    
    (178
    )
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (178
    )Net Income (Loss)
    
    
    
    282
    
    
    
    
    106
    
    
    
    
    39
    
    
    
    
    104
    
    
    
    
    (3
    )
    
    
    
    
    (72
    )
    
    
    
    
    456Preferred Securities Dividends/Preference Unit Distributions
    
    
    
    (3
    )
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (3
    )
    
    
    
    
    —
    
    
    
    
    6
    
    
    
    
    —Segment Earnings (Loss)
    
    
    
    279
    
    
    
    
    106
    
    
    
    
    39
    
    
    
    
    101
    
    
    
    
    (3
    )
    
    
    
    
    (66
    )
    
    
    
    
    456Gross Additions to Long-Lived Assets
    
    
    
    372
    
    
    
    
    345
    
    
    
    
    2
    
    
    
    
    24
    
    
    
    
    —
    
    
    
    
    8
    
    
    
    
    75147

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
PSE&G
    
    Power
    
    Energy Holdings
    
    
    
    ConsolidatedTotalResources
    
    Global
    
    Other (A)
    
    Other (B)(Millions)As of September 30, 2006:Total Assets
    
    
    $
    
    14,114
    
    
    
    $
    
    8,473
    
    
    
    $
    
    2,985
    
    
    
    $
    
    3,144
    
    
    
    $
    
    396
    
    
    
    $
    
    (398
    )
    
    
    
    $
    
    28,714Investments in Equity Method Subsidiaries
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    5
    
    
    
    
    844
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    849As of December 31, 2005:Total Assets
    
    
    $
    
    14,291
    
    
    
    $
    
    8,945
    
    
    
    $
    
    2,871
    
    
    
    $
    
    3,799
    
    
    
    $
    
    385
    
    
    
    $
    
    (478
    )
    
    
    
    $
    
    29,813Investments in Equity Method Subsidiaries
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    5
    
    
    
    
    1,128
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    1,133

(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.(B)
    
    
    
    PSEG’s other activities include amounts applicable to PSEG (as parent company) 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 13. Related-Party Transactions. The net losses primarily relate to financing
      and certain administrative and general costs at PSEG, as parent company.Note 12. Stock-Based Compensation
PSEG
As approved at the Annual Meeting of Stockholders in 2004, PSEG’s 2004 Long-Term Incentive Plan (2004 LTIP) replaced prior Long-Term Incentive Plans (the 1989 LTIP and 2001 LTIP). The 2004
  LTIP is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance shares,
  restricted stock, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIPs are non-qualified options to purchase
  shares of PSEG’s common stock, restricted stock awards and performance unit awards. However, since 2004, only restricted stock has been granted.
The 2004 LTIP currently provides for the issuance of equity awards with respect to approximately 13.0 million shares of common stock. As of September 30, 2006, there were 11.8 million shares
  available for future awards under the 2004 LTIP.
Stock Options
Under the 2004 LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees of PSEG and its subsidiaries selected by the Organization
  and Compensation Committee of PSEG’s Board of Directors, the plan’s administrative committee (Committee). Option awards are granted with an exercise price equal to the market price of PSEG’s
  common stock at the grant date. The options generally vest based on three to five years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-
  in-control, retirement, death or disability. Options are exercisable over a period of time designated by the Committee (but not prior to one year or longer than 10 years from the date of grant) and are
  subject to such other terms and conditions as the Committee determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the Committee, by delivering
  previously acquired shares of PSEG common stock.
48

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
On September 1, 2006, PSEG began using treasury stock to settle the exercise of stock options. Prior to September 1, 2006, PSEG had purchased shares on the open market to meet the exercise of
  stock options.
Restricted Stock
Under the 2004 LTIP, PSEG has granted restricted stock awards to officers and other key employees. These shares are subject to risk of forfeiture until vested by continued employment. Restricted
  stock generally vests annually over three years, but is considered outstanding at the time of grant, as the recipients are entitled to dividends and voting rights. Vesting may be accelerated upon certain
  events, such as change in control (unless substituted with an equity award of equal value), retirement, death or disability.
In addition, from 1998 to 2001, PSEG granted 210,000 shares of restricted stock to a key executive, which are subject to risk of forfeiture until vested by continued employment. The shares vest on a
  staggered schedule through March 2007.
PSEG issues restricted stock from treasury stock.
Performance Units
Under the 2004 LTIP, performance units were granted to certain key executives, which provide for payment in shares of PSEG common stock based on achievement of certain financial goals over the
  three-year period from 2004 through 2006. The payout varies from 0% to 200% of the number of performance units granted depending on PSEG’s performance compared to the performance of other
  companies in the Dow Jones Utilities Index. The performance units are credited with dividend equivalents in an amount equal to dividends paid on PSEG common stock up until January 1, 2007. Vesting
  may be accelerated upon certain events such as change in control, retirement, death or disability.
Stock-Based Compensation
Effective January 1, 2006, PSEG adopted SFAS 123R. See Note 2. Recent Accounting Standards for a description of the adoption of SFAS 123R. As a result, all outstanding unvested stock options as
  of January 1, 2006 are being expensed based on their grant date fair values, which were determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific
  basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest.
Prior to the adoption of SFAS 123R, PSEG recognized compensation expense for restricted stock over the vesting period based on the grant date fair market value of the shares. PSEG will continue to
  recognize compensation expense over the vesting term.
Also prior to the adoption of SFAS 123R, PSEG recognized compensation expense for performance units. The fair value of each performance unit was based on the grant date fair value of PSEG
  common stock. The accrual of compensation cost was based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. The current accrual is
  estimated at 100% of the original grant. The accrual is adjusted for subsequent changes in the estimated or actual outcome.
Compensation cost from options, restricted stock and performance units is included in Operation and Maintenance Expense on PSEG’s Condensed Consolidated Statements of Operations and
  amounted to approximately $3.4 million and $1.5 million for the quarters ended September 30, 2006 and 2005, respectively, and approximately $10.0 million and $4.9 million for the nine months ended
  September 30, 2006 and 2005, respectively. The total income tax benefit recognized on PSEG’s Condensed Consolidated Statements of Operations was approximately $1.4 million and $0.6 million for the
  quarters ended September 30, 2006 and 2005, respectively, and approximately $4.1 million and
49

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
$2.0 million for the nine months ended September 30, 2006 and 2005, respectively. Compensation cost capitalized as part of Property, Plant and Equipment was less than $0.1 million for each of the quarters
  ended September 30, 2006 and 2005 and approximately $0.2 million for each of the nine months ended September 30, 2006 and 2005. Of the total compensation cost for the nine months ended September
  30, 2006, approximately $0.8 million, or $0.5 million after-tax, related to the adoption of SFAS 123R, which was primarily due to expensing stock options for the first time. There was no impact on basic and
  diluted earnings per share from the implementation of SFAS 123R because there were a relatively small number of outstanding unvested stock options as of the implementation date.
Prior to the adoption of SFAS 123R, PSEG presented all tax benefits for deductions resulting from the exercise of share-based compensation as operating cash flows on the Condensed Consolidated
  Statement of Cash Flows. SFAS 123R requires the benefits of tax deductions in excess of the taxes expensed on recognized compensation cost to be reported as financing cash flows. There was
  approximately $13.1 million of excess tax benefits included as a financing cash inflow on the September 30, 2006 Condensed Consolidated Statement of Cash Flow. Total cash flow will remain unchanged
  from what would have been reported under prior accounting rules.
The following table illustrates the effect on Net Income and earnings per share if PSEG had applied the fair value recognition provisions of SFAS 123R for the quarter and nine months ended
  September 30, 2005.
Quarter EndedSeptember 30,
    
    Nine Months EndedSeptember 30,2005
    
    2005(Millions, except Share Data)Net Income, as Reported
    
    
    $
    
    253
    
    
    
    $
    
    456Add: Total Stock-Based Compensation Expensed During the Period, net of tax
    
    
    
    1
    
    
    
    
    3Deduct: Total Stock-Based Employee Compensation Expense Determined Under Fair Value-Based Method for All Awards, net of related tax
      effects
    
    
    
    (2
    )
    
    
    
    
    (5
    )Pro Forma Net Income
    
    
    $
    
    252
    
    
    
    $
    
    454Earnings Per Share:Basic—as Reported
    
    
    $
    
    1.06
    
    
    
    $
    
    1.91Basic—Pro Forma
    
    
    $
    
    1.05
    
    
    
    $
    
    1.90Diluted—as Reported
    
    
    $
    
    1.03
    
    
    
    $
    
    1.87Diluted—Pro Forma
    
    
    $
    
    1.03
    
    
    
    $
    
    1.87Prior to the adoption of SFAS 123R, PSEG recognized the compensation cost of stock based awards issued to retirement eligible employees that fully or partially vest upon an employee’s retirement
  over the nominal vesting period of performance, and recognized any remaining compensation cost at the date of retirement. In accordance with SFAS 123R, PSEG recognizes compensation cost of awards
  issued after January 1, 2006 over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests.
50

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
There were no options granted during 2005 or 2006. Changes in stock options for the nine months ended September 30, 2006 are summarized as follows:
Options
    
    Shares
    
    WeightedAverageExercisePrice
    
    WeightedAverageRemainingContractualTerm
    
    AggregateIntrinsicValueOutstanding at January 1, 2006
    
    
    
    3,981,555
    
    
    
    $
    
    41.07Granted
    
    
    
    —
    
    
    
    
    —Exercised
    
    
    
    (1,895,655
    )
    
    
    
    
    39.67Canceled
    
    
    
    (14,266
    )
    
    
    
    
    42.75Outstanding at September 30, 2006
    
    
    
    2,071,634
    
    
    
    $
    
    42.33
    
    
    
    
    5.7
    
    
    
    $
    
    39,064,982Exercisable at September 30, 2006
    
    
    
    1,654,253
    
    
    
    $
    
    42.22
    
    
    
    
    5.3
    
    
    
    $
    
    31,379,460The intrinsic value of options is the difference between the current market price and the exercise price. The total intrinsic value of options exercised during the nine months ended September 30, 2006
  and 2005 was approximately $50 million and $56 million, respectively. During the nine months ended September 30, 2006 and 2005, cash received from stock options exercised was approximately
  $75.2 million and $114.2 million, respectively. The tax benefit realized from stock options exercised during the nine months ended September 30, 2006 and 2005 was approximately $13.1 million and $22.9
  million, respectively.
As of September 30, 2006, there was approximately $0.4 million of unrecognized compensation cost related to stock options, which is expected to be recognized over a weighted average period of seven
  months.
Restricted Stock Information
Changes in restricted stock for the nine months ended September 30, 2006 are summarized as follows:
Options
    
    Shares
    
    WeightedAverageGrantDateFairValue
    
    WeightedAverageRemainingContractualTerm
    
    AggregateIntrinsicValueOutstanding at January 1, 2006
    
    
    
    466,744
    
    
    
    $
    
    56.69Granted
    
    
    
    43,800
    
    
    
    
    66.53Vested
    
    
    
    (87,047
    )
    
    
    
    
    51.90Canceled
    
    
    
    (9,370
    )
    
    
    
    
    59.71Outstanding at September 30, 2006
    
    
    
    414,127
    
    
    
    $
    
    58.67
    
    
    
    
    1.7
    
    
    
    $
    
    25,340,431The weighted average grant date fair value per share was $51.91 for restricted stock awards granted during the nine months ended September 30, 2005.
The total intrinsic value of restricted stock vested during the nine months ended September 30, 2006 was approximately $6.1 million. No restricted shares vested during the nine months ended
  September 30, 2005.
As of September 30, 2006, there was approximately $16.3 million of unrecognized compensation cost related to restricted stock, which is expected to be recognized over a weighted average period of 1.9
  years.
Performance Units Information
As of September 30, 2006, 82,700 performance units were outstanding and unvested, net of 900 units forfeited in the nine-month period then ended. Approximately 8,700 dividend equivalents had
51

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
accrued on these performance units. The grant date fair value of the performance units is $42.75 per unit.
Assuming performance units are paid out at the 100% performance level, the total intrinsic value of performance units outstanding at September 30, 2006 was approximately $5.6 million.
As of September 30, 2006, there was approximately $0.4 million of unrecognized compensation cost related to performance units, which is expected to be recognized over the next three months.
Outside Directors
During 2006, each director who was not an officer of PSEG or its subsidiaries and affiliates will be paid an annual retainer of $50,000. Pursuant to the Compensation Plan for Outside Directors, a
  certain percentage, currently 50%, of the annual retainer is paid in PSEG common stock.
PSEG also maintains a Stock Plan for Outside Directors (Stock Plan) pursuant to which directors of PSEG who are not employees of PSEG or its subsidiaries receive a restricted stock award, currently
  1,000 shares per year, for each year of service as a director. The restrictions on the stock granted under the Stock Plan provide that the shares are subject to forfeiture if the director leaves service at any
  time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director’s service were terminated after a “change in
  control” as defined in the Stock Plan or if the director were to die in office. PSEG also has the ability to waive this restriction for good cause shown. Restricted stock may not be sold or otherwise
  transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director who has the right to vote the shares. The fair value of these shares is recorded
  as compensation expense on the Condensed Consolidated Statements of Operations. Compensation expense for the Stock Plan was less than $0.1 million for each of the quarters ended September 30, 2006
  and 2005 and approximately $0.4 million for each of the nine months ended September 30, 2006 and 2005.
Employee Stock Purchase Plan
PSEG maintains an employee stock purchase plan for all eligible employees of PSEG and its subsidiaries. Under the plan, shares of PSEG common stock may be purchased at 95% of the fair market
  value through payroll deductions. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. During the nine months ended September 30, 2006 and 2005, employees
  purchased 36,380 and 45,657 shares at an average price of $62.12 and $54.65 per share, respectively. As of September 30, 2006, 1.9 million shares were available for future issuance under this plan.
Note 13. Related-Party Transactions
The majority of the following discussion relates to intercompany transactions, which are eliminated during the consolidation process in accordance with GAAP.
BGS and BGSS 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.
52

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
The amounts which Power charged to PSE&G for BGS and BGSS are presented below:
Power’s Billings for theQuarters EndedSeptember 30,
    
    Nine Months EndedSeptember 30,2006
    
    2005
    
    2006
    
    2005(Millions)BGS
    
    
    $
    
    330
    
    
    
    $
    
    172
    
    
    
    $
    
    594
    
    
    
    $
    
    395BGSS
    
    
    $
    
    175
    
    
    
    $
    
    203
    
    
    
    $
    
    1,435
    
    
    
    $
    
    1,325As of September 30, 2006 and December 31, 2005, Power had net receivables from PSE&G of approximately $145 million and $454 million, respectively, primarily related to the BGS and BGSS
  contracts. These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s Condensed Consolidated Financial Statements.
In
  addition, as of September 30, 2006 and December 31, 2005, PSE&G had a payable
  to Power of approximately $198 million and a receivable of approximately $152
  million, respectively, related to gas supply hedges Power entered into for BGSS.
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:
Services’ Billings for theQuarters EndedSeptember 30,
    
    Nine Months EndedSeptember 30,
    
    Payable to Services as of2006
    
    2005
    
    2006
    
    2005
    
    September 30,2006
    
    December 31,2005(Millions)PSE&G
    
    
    $
    
    50
    
    
    
    $
    
    51
    
    
    
    $
    
    158
    
    
    
    $
    
    154
    
    
    
    $
    
    27
    
    
    
    $
    
    34Power
    
    
    $
    
    29
    
    
    
    $
    
    39
    
    
    
    $
    
    99
    
    
    
    $
    
    114
    
    
    
    $
    
    14
    
    
    
    $
    
    21Energy Holdings
    
    
    $
    
    4
    
    
    
    $
    
    4
    
    
    
    $
    
    13
    
    
    
    $
    
    13
    
    
    
    $
    
    1
    
    
    
    $
    
    2These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s Condensed Consolidated Financial Statements. PSE&G,
  Power and Energy Holdings believe that the costs of services provided by Services approximate market value for such services.
Tax Sharing Agreements
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 ofSeptember 30, 2006
    
    December 31, 2005(Millions)PSE&G
    
    
    $
    
    (39
    )
    
    
    
    $
    
    (59
    )Power
    
    
    $
    
    9
    
    
    
    $
    
    4Energy Holdings
    
    
    $
    
    (77
    )
    
    
    
    $
    
    (12
    )53

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Affiliate Loans and Advances
PSEG and Power
As of September 30, 2006 and December 31, 2005, Power had a demand note payable to PSEG of approximately $68 million and $202 million, respectively, for short-term funding needs.
PSEG and Energy Holdings
As of September 30, 2006 and December 31, 2005, Energy Holdings had a demand note receivable due from PSEG of $374 million and $409 million, respectively. These notes reflect the investment of
  Energy Holdings’ excess cash with PSEG.
PSE&G and Services
As of each of September 30, 2006 and December 31, 2005, 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 each of September 30, 2006 and December 31, 2005, 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.
Other
PSEG and PSE&G
As of September 30, 2006 and December 31, 2005, PSE&G had net receivables from PSEG of approximately $3 million and $6 million, respectively, related to amounts that PSEG had collected on
  PSE&G’s behalf.
PSEG and Power
As of September 30, 2006 and December 31, 2005, Power had net receivables from PSEG of approximately $1 million related to amounts that PSEG had collected on Power’s behalf.
PSEG and Energy Holdings
As of September 30, 2006 and December 31, 2005, Energy Holdings had net receivables from PSEG of approximately $3 million and $1 million, respectively, primarily for interest due on the demand
  note receivable from PSEG.
Energy Holdings and PSE&G
As of September 30, 2006 and December 31, 2005, Energy Holdings had a receivable of approximately $2 million and $3 million, respectively, related to efficiency incentive initiatives performed for
  PSE&G’s customers. Energy Holdings recorded revenues for such services of approximately $2 million and $6 million for the quarters ended September 30, 2006 and 2005, respectively, and approximately $9
  million and $18 million for the nine months ended September 30, 2006 and 2005, respectively.
Changes in Capitalization
PSEG and Energy Holdings
On September 20, 2006, Energy Holdings made a cash contribution to PSEG of $425 million in the form of a return of capital.
54

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Note 14. 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
    
    ConsolidatedTotal(Millions)For the Quarter ended September 30, 2006Revenues
    
    
    $
    
    —
    
    
    
    $
    
    1,720
    
    
    
    $
    
    33
    
    
    
    $
    
    (264
    )
    
    
    
    $
    
    1,489Operating Expenses
    
    
    
    —
    
    
    
    
    1,322
    
    
    
    
    32
    
    
    
    
    (261
    )
    
    
    
    
    1,093Operating Income
    
    
    
    —
    
    
    
    
    398
    
    
    
    
    1
    
    
    
    
    (3
    )
    
    
    
    
    396Equity Earnings (Losses) of Subsidiaries
    
    
    
    205
    
    
    
    
    (9
    )
    
    
    
    
    —
    
    
    
    
    (196
    )
    
    
    
    
    —Other Income
    
    
    
    44
    
    
    
    
    49
    
    
    
    
    4
    
    
    
    
    (59
    )
    
    
    
    
    38Other Deductions
    
    
    
    —
    
    
    
    
    (27
    )
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (27
    )Interest Expense
    
    
    
    (45
    )
    
    
    
    
    (42
    )
    
    
    
    
    (19
    )
    
    
    
    
    59
    
    
    
    
    (47
    )Income Taxes
    
    
    
    1
    
    
    
    
    (164
    )
    
    
    
    
    6
    
    
    
    
    2
    
    
    
    
    (155
    )Net Income (Loss)
    
    
    $
    
    205
    
    
    
    $
    
    205
    
    
    
    $
    
    (8
    )
    
    
    
    $
    
    (197
    )
    
    
    
    $
    
    205For the Quarter ended September 30, 2005Revenues
    
    
    $
    
    —
    
    
    
    $
    
    1,673
    
    
    
    $
    
    27
    
    
    
    $
    
    (256
    )
    
    
    
    $
    
    1,444Operating Expenses
    
    
    
    1
    
    
    
    
    1,466
    
    
    
    
    30
    
    
    
    
    (257
    )
    
    
    
    
    1,240Operating (Loss) Income
    
    
    
    (1
    )
    
    
    
    
    207
    
    
    
    
    (3
    )
    
    
    
    
    1
    
    
    
    
    204Equity Earnings (Losses) of Subsidiaries
    
    
    
    135
    
    
    
    
    (17
    )
    
    
    
    
    —
    
    
    
    
    (118
    )
    
    
    
    
    —Other Income
    
    
    
    35
    
    
    
    
    74
    
    
    
    
    —
    
    
    
    
    (35
    )
    
    
    
    
    74Other Deductions
    
    
    
    —
    
    
    
    
    (11
    )
    
    
    
    
    (1
    )
    
    
    
    
    (1
    )
    
    
    
    
    (13
    )Interest Expense
    
    
    
    (40
    )
    
    
    
    
    (13
    )
    
    
    
    
    (15
    )
    
    
    
    
    36
    
    
    
    
    (32
    )Income Taxes
    
    
    
    (4
    )
    
    
    
    
    (105
    )
    
    
    
    
    6
    
    
    
    
    2
    
    
    
    
    (101
    )Loss on Discontinued Operations, Including Loss on Disposal, net of tax benefit
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (7
    )
    
    
    
    
    —
    
    
    
    
    (7
    )Net Income (Loss)
    
    
    $
    
    125
    
    
    
    $
    
    135
    
    
    
    $
    
    (20
    )
    
    
    
    $
    
    (115
    )
    
    
    
    $
    
    12555

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Power
    
    GuarantorSubsidiaries
    
    OtherSubsidiaries
    
    ConsolidatingAdjustments
    
    ConsolidatedTotal(Millions)For the Nine Months ended September 30, 2006Revenues
    
    
    $
    
    —
    
    
    
    $
    
    5,309
    
    
    
    $
    
    103
    
    
    
    $
    
    (821
    )
    
    
    
    $
    
    4,591Operating Expenses
    
    
    
    1
    
    
    
    
    4,545
    
    
    
    
    103
    
    
    
    
    (820
    )
    
    
    
    
    3,829Operating (Loss) Income
    
    
    
    (1
    )
    
    
    
    
    764
    
    
    
    
    —
    
    
    
    
    (1
    )
    
    
    
    
    762Equity Earnings (Losses) of Subsidiaries
    
    
    
    403
    
    
    
    
    (32
    )
    
    
    
    
    —
    
    
    
    
    (371
    )
    
    
    
    
    —Other Income
    
    
    
    126
    
    
    
    
    138
    
    
    
    
    5
    
    
    
    
    (156
    )
    
    
    
    
    113Other Deductions
    
    
    
    —
    
    
    
    
    (59
    )
    
    
    
    
    (1
    )
    
    
    
    
    —
    
    
    
    
    (60
    )Interest Expense
    
    
    
    (142
    )
    
    
    
    
    (88
    )
    
    
    
    
    (57
    )
    
    
    
    
    156
    
    
    
    
    (131
    )Income Taxes
    
    
    
    8
    
    
    
    
    (320
    )
    
    
    
    
    21
    
    
    
    
    1
    
    
    
    
    (290
    )Net Income (Loss)
    
    
    $
    
    394
    
    
    
    $
    
    403
    
    
    
    $
    
    (32
    )
    
    
    
    $
    
    (371
    )
    
    
    
    $
    
    394For the Nine Months ended September 30, 2005Revenues
    
    
    $
    
    —
    
    
    
    $
    
    4,900
    
    
    
    $
    
    98
    
    
    
    $
    
    (764
    )
    
    
    
    $
    
    4,234Operating Expenses
    
    
    
    1
    
    
    
    
    4,401
    
    
    
    
    84
    
    
    
    
    (764
    )
    
    
    
    
    3,722Operating (Loss) Income
    
    
    
    (1
    )
    
    
    
    
    499
    
    
    
    
    14
    
    
    
    
    —
    
    
    
    
    512Equity Earnings (Losses) of Subsidiaries
    
    
    
    116
    
    
    
    
    (208
    )
    
    
    
    
    —
    
    
    
    
    92
    
    
    
    
    —Other Income
    
    
    
    102
    
    
    
    
    135
    
    
    
    
    1
    
    
    
    
    (103
    )
    
    
    
    
    135Other Deductions
    
    
    
    —
    
    
    
    
    (31
    )
    
    
    
    
    (1
    )
    
    
    
    
    (1
    )
    
    
    
    
    (33
    )Interest Expense
    
    
    
    (110
    )
    
    
    
    
    (47
    )
    
    
    
    
    (32
    )
    
    
    
    
    103
    
    
    
    
    (86
    )Income Taxes
    
    
    
    (1
    )
    
    
    
    
    (231
    )
    
    
    
    
    7
    
    
    
    
    —
    
    
    
    
    (225
    )Loss on Discontinued Operations, Including Loss on Disposal, net of tax benefit
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (197
    )
    
    
    
    
    —
    
    
    
    
    (197
    )Net Income (Loss)
    
    
    $
    
    106
    
    
    
    $
    
    117
    
    
    
    $
    
    (208
    )
    
    
    
    $
    
    91
    
    
    
    $
    
    106For the Nine Months ended September 30, 2006Net Cash Provided By Operating Activities
    
    
    $
    
    318
    
    
    
    $
    
    1,303
    
    
    
    $
    
    10
    
    
    
    $
    
    (711
    )
    
    
    
    $
    
    920Net Cash Provided By (Used In) Investing Activities
    
    
    $
    
    182
    
    
    
    $
    
    (1,237
    )
    
    
    
    $
    
    29
    
    
    
    $
    
    737
    
    
    
    $
    
    (289
    )Net Cash Used In Financing Activities
    
    
    $
    
    (500
    )
    
    
    
    $
    
    (69
    )
    
    
    
    $
    
    (39
    )
    
    
    
    $
    
    (26
    )
    
    
    
    $
    
    (634
    )For the Nine Months ended September 30, 2005Net Cash (Used in) Provided By Operating Activities
    
    
    $
    
    (1,188
    )
    
    
    
    $
    
    44
    
    
    
    $
    
    1,112
    
    
    
    $
    
    308
    
    
    
    $
    
    276Net Cash Provided By (Used in) Investing Activities
    
    
    $
    
    88
    
    
    
    $
    
    202
    
    
    
    $
    
    (25
    )
    
    
    
    $
    
    (434
    )
    
    
    
    $
    
    (169
    )Net Cash Provided By (Used In) Financing Activities
    
    
    $
    
    1,100
    
    
    
    $
    
    (237
    )
    
    
    
    $
    
    (1,087
    )
    
    
    
    $
    
    126
    
    
    
    $
    
    (98
    )56

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
Power
    
    GuarantorSubsidiaries
    
    OtherSubsidiaries
    
    ConsolidatingAdjustments
    
    ConsolidatedTotal(Millions)As of September 30, 2006Current Assets
    
    
    $
    
    1,990
    
    
    
    $
    
    3,212
    
    
    
    $
    
    220
    
    
    
    $
    
    (3,450
    )
    
    
    
    $
    
    1,972Property, Plant and Equipment, net
    
    
    
    151
    
    
    
    
    3,357
    
    
    
    
    1,488
    
    
    
    
    —
    
    
    
    
    4,996Investment in Subsidiaries
    
    
    
    4,302
    
    
    
    
    421
    
    
    
    
    —
    
    
    
    
    (4,723
    )
    
    
    
    
    —Noncurrent Assets
    
    
    
    189
    
    
    
    
    1,406
    
    
    
    
    16
    
    
    
    
    (106
    )
    
    
    
    
    1,505Total Assets
    
    
    $
    
    6,632
    
    
    
    $
    
    8,396
    
    
    
    $
    
    1,724
    
    
    
    $
    
    (8,279
    )
    
    
    
    $
    
    8,473Current Liabilities
    
    
    $
    
    116
    
    
    
    $
    
    3,158
    
    
    
    $
    
    1,195
    
    
    
    $
    
    (3,432
    )
    
    
    
    $
    
    1,037Noncurrent Liabilities
    
    
    
    84
    
    
    
    
    936
    
    
    
    
    108
    
    
    
    
    (123
    )
    
    
    
    
    1,005Long-Term Debt
    
    
    
    2,817
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    2,817Member’s Equity
    
    
    
    3,615
    
    
    
    
    4,302
    
    
    
    
    421
    
    
    
    
    (4,724
    )
    
    
    
    
    3,614Total Liabilities and Member’s Equity
    
    
    $
    
    6,632
    
    
    
    $
    
    8,396
    
    
    
    $
    
    1,724
    
    
    
    $
    
    (8,279
    )
    
    
    
    $
    
    8,473As of December 31, 2005Current Assets
    
    
    $
    
    2,584
    
    
    
    $
    
    2,616
    
    
    
    $
    
    251
    
    
    
    $
    
    (2,876
    )
    
    
    
    $
    
    2,575Property, Plant and Equipment, net
    
    
    
    143
    
    
    
    
    3,271
    
    
    
    
    1,466
    
    
    
    
    —
    
    
    
    
    4,880Investment in Subsidiaries
    
    
    
    3,507
    
    
    
    
    453
    
    
    
    
    —
    
    
    
    
    (3,960
    )
    
    
    
    
    —Noncurrent Assets
    
    
    
    179
    
    
    
    
    1,609
    
    
    
    
    17
    
    
    
    
    (315
    )
    
    
    
    
    1,490Total Assets
    
    
    $
    
    6,413
    
    
    
    $
    
    7,949
    
    
    
    $
    
    1,734
    
    
    
    $
    
    (7,151
    )
    
    
    
    $
    
    8,945Current Liabilities
    
    
    $
    
    695
    
    
    
    $
    
    3,213
    
    
    
    $
    
    1,146
    
    
    
    $
    
    (2,877
    )
    
    
    
    $
    
    2,177Noncurrent Liabilities
    
    
    
    63
    
    
    
    
    1,268
    
    
    
    
    96
    
    
    
    
    (313
    )
    
    
    
    
    1,114Long-Term Debt
    
    
    
    2,817
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    2,817Member’s Equity
    
    
    
    2,838
    
    
    
    
    3,468
    
    
    
    
    492
    
    
    
    
    (3,961
    )
    
    
    
    
    2,837Total Liabilities and Member’s Equity
    
    
    $
    
    6,413
    
    
    
    $
    
    7,949
    
    
    
    $
    
    1,734
    
    
    
    $
    
    (7,151
    )
    
    
    
    $
    
    8,945Note 15. Subsequent Events
PSE&G
Gas Base Rate Case
On
  October 27, 2006, PSE&G reached a settlement agreement in the Gas Base Rate
  Case with the BPU Staff, New Jersey Public Advocate (Advocate) and other intervening
  parties. The agreement has been approved by the Office of Administrative Law
  (OAL) and submitted to the BPU for its approval. The agreement provides for
  an annual increase in gas revenues of $40 million or approximately 1.1%. In
  addition, the settlement provides for an adjustment to lower book depreciation
  and amortization expense for PSE&G by approximately $26 million annually
  and the amortization of accumulated cost of removal that will further reduce
  depreciation and amortization expense by $13 million annually for five years.
Electric Distribution Financial Review
On October 27, 2006, PSE&G reached a settlement agreement in the Electric Distribution Financial Review with the BPU Staff, Advocate and other intervening parties concerning the excess
  depreciation rate credit. The agreement, which has been submitted to the BPU for its approval, authorizes a reduction in the credit to $22 million resulting in additional revenue to PSE&G of approximately
  $47 million annually based on current sales volumes.
The settlements above are not final until approved by the BPU and include a restriction against any further base rate changes becoming effective before November 15, 2009. In addition, PSE&G must file
  a joint electric and gas petition for any future base rate increases.
57

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)
Following are the significant changes in or additions to information reported in the 2005 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.
TERMINATION OF MERGER AGREEMENT
PSEG, PSE&G, Power and Energy Holdings
On December 20, 2004, PSEG entered into an Agreement and Plan of Merger (Merger Agreement) with Exelon Corporation (Exelon) providing for a merger of PSEG with and into Exelon (Merger).
  On September 14, 2006, PSEG received from Exelon a formal notice of termination of the Merger under the provisions of the Merger Agreement.
OVERVIEW OF 2006 AND FUTURE OUTLOOK
PSEG
PSEG’s business consists of four reportable segments, which are PSE&G, Power and the two direct subsidiaries of Energy Holdings: PSEG Global L.L.C. (Global) and PSEG Resources L.L.C.
  (Resources). The following is a discussion of the markets in which PSEG and its subsidiaries compete, the corporate strategy for the conduct of PSEG’s businesses within these markets, significant events
  that have occurred during the first nine months of 2006 and expectations for the full year 2006 and beyond.
Throughout the Merger approval process, PSEG maintained a stand-alone business capability in the event the Merger did not close. PSEG took steps to improve its financial stability and reduce risk,
  including opportunistically monetizing certain of its assets that no longer had a strategic fit, reducing international exposure, paying down debt, significantly hedging its future generation business and
  improving the performance and reliability of its nuclear and fossil units.
For the nine months ended September 30, 2006, PSEG had Net Income of $786 million, or $3.12 per share, discussed below in Results of Operations. Included in Net Income is an after-tax gain of $228
  million, or $0.90 per share, related to the sale of two generating stations in Poland, which is included in Income from Discontinued Operations and an after-tax loss of approximately $178 million, or $0.70
  per share, related to the sale of Rio Grande Energia S.A. (RGE), an electric distribution company in Brazil. The loss at RGE primarily related to devaluation of the Brazilian Real subsequent to Global’s
  acquisition of its interests in RGE in 1997. Also included in Net Income for the nine months ended September 30, 2006 are net unrealized gains of approximately $40 million, after tax, or $0.16 per share,
  related to non-trading mark-to-market (MTM) accounting and Merger-related costs of approximately $7 million, after-tax, or $0.03 per share.
In order to provide a more consistent and comparable measure of the performance of its businesses to help shareholders understand performance trends, earnings projections for PSEG and its
  subsidiaries consist of projected Income from Continuing Operations, excluding impacts from asset sales and Merger-related costs and do not contemplate any potential impacts from MTM accounting.
  Excluding such items, PSEG continues to project earnings for 2006 to range from $3.45 to $3.75 per share, although the range of expected earnings from each of PSE&G, Power and Energy Holdings has been
  revised from originally announced projections. PSE&G’s guidance has decreased due to the prolonged lack of rate relief; Power’s guidance has increased due to improved operations and stronger energy
58

markets and Energy Holdings’ guidance has increased due to a strong Texas market. The projections for 2006 also include $60 million to $70 million of expenses at the PSEG parent level, primarily for
  financing costs.
PSEG expects operating cash flows in 2006 and beyond to be sufficient to meet capital needs and dividend requirements and may employ any excess cash to reduce debt, invest in its businesses, increase
  dividends or, in the longer term, repurchase shares. On October 17, 2006, PSEG’s Board of Directors approved a common stock dividend of $0.57 per share for the fourth quarter of 2006, reflecting an
  indicated annual dividend rate of $2.28 per share.
Several key factors that will drive PSEG’s future success are energy, capacity and fuel prices, performance of Power’s and Energy Holdings’ generating facilities and PSE&G’s ability to attain a
  reasonable rate of return under its regulated rate structure. The stability of international economies, Resources’ ability to realize tax benefits associated with its leveraged lease investments and the
  accounting and tax treatment associated with such investments are also key factors that will influence Energy Holdings’ contribution to PSEG’s future success.
PSE&G
PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the New Jersey Board of Public Utilities (BPU) for its distribution operations and by the Federal
  Energy Regulatory Commission (FERC) for its electric transmission and wholesale sales operations. Consequently, PSE&G’s earnings are largely determined by the regulation of its rates by those agencies.
Commodity costs continue to put upward pressure on customer charges and have contributed to flat electric delivery sales and a decline in year-over-year gas delivery sales. On June 1, 2006, new
  electric Basic Generation Service (BGS)-Fixed Price (FP) rates went into effect and residential customers’ bills increased by approximately 14%. While gas prices have stabilized and even declined recently,
  the current cost to a residential Basic Gas Supply Service (BGSS) customer is approximately 24% higher than a year ago. The 1% increase in the New Jersey sales tax on July 15, 2006 also increased
  customer charges. Since sales tax and commodity price increases are passed through to customers, they do not increase PSE&G’s earnings but they can have a negative impact on PSE&G’s earnings if they
  result in reduced customer demand.
PSE&G
  made its 2006/2007 BGSS filing on May 26, 2006. In this filing, PSE&G requested
  a reduction in annual BGSS gas revenues of approximately $19.7 million (excluding
  losses and New Jersey Sales and Use Tax) or approximately a 1.0% decrease to
  be implemented for service rendered on and after October 1, 2006 or earlier.
  Additionally, PSE&G requested an increase in its Balancing Charge. Since
  the time of the filing, prices of gas futures have dropped significantly and
  as a result, additional BGSS data has been requested by and provided to the
  BPU. Settlement discussions with the BPU Staff have been completed and a new
  Stipulation has been executed by the parties. This new Stipulation, which requires
  BPU approval, results in a decrease in annual BGSS revenues of approximately
  $120 million, which is approximately a 6% reduction in a typical residential
  gas customer’s bill. The Stipulation did not include any change in the
  balancing charge, as requested.
On
  September 30, 2005, PSE&G filed a petition with the BPU seeking a $133 million
  increase in annual gas base rates, an overall 3.78% increase. On October 27,
  2006, PSE&G reached a settlement agreement in the Gas Base Rate Case with
  the BPU Staff, New Jersey Public Advocate (Advocate) and other intervening parties.
  The agreement has been approved by the Office of Administrative Law (OAL) and
  submitted to the BPU for its approval. The agreement provides for an annual
  increase in gas revenues of $40 million or approximately 1.1%. In addition,
  the settlement provides for an adjustment to lower book depreciation expense
  for PSE&G by approximately $26 million annually and the amortization of
  accumulated cost of removal that will further reduce depreciation and amortization
  expense by $13 million annually for five years.
On October 27, 2006, PSE&G also reached a settlement agreement in the Electric Distribution Financial Review with the BPU Staff, Advocate and other intervening parties concerning the excess
  depreciation rate credit. The agreement, which has been submitted to the BPU for its approval,
59

authorizes
  a reduction in the credit to $22 million, resulting in additional revenue to
  PSE&G of approximately $47 million annually based on current sales volumes.
The settlements above are not final until approved by the BPU and include a restriction against any further base rate changes becoming effective before November 15, 2009. In addition, PSE&G must file
  a joint electric and gas petition for any future base rate increases.
For
  the nine months ended September 30, 2006, PSE&G had Net Income of $200 million.
  As a result of the substantial decline in earnings at PSE&G as compared
  to 2005 due to the delay in decisions for the Gas Base Rate Case and the Electric
  Distribution Financial Review, PSE&G lowered its earnings guidance from
  a range of $315 million to $335 million to a range of $250 million to $270 million
  in 2006. As disclosed previously, these amounts exclude any Merger-related costs.
The risks to PSE&G’s business generally relate to the treatment of the various rate and other issues by the state and federal regulatory agencies, specifically the BPU and FERC. In 2006 and beyond,
  PSE&G’s success will depend, in part, on its ability to attain a reasonable rate of return, continue cost containment initiatives, maintain system reliability and safety levels and continued recovery, with an
  adequate return, of the regulatory assets it has deferred and the investments it plans to make in its electric and gas transmission and distribution system. Since PSE&G earns no margin on the commodity
  portion of its electric and gas sales through tariff agreements, there is no anticipated commodity price volatility for PSE&G.
Power
Power is an electric generation and wholesale energy marketing and trading company that is focused on a generation market extending from Maine to the Carolinas and the Atlantic Coast to Indiana.
  Power’s principal operating subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) are regulated by FERC. Through its subsidiaries, Power
  seeks to balance its generating capacity, fuel requirements and supply obligations through integrated energy marketing and trading, enhance its ability to produce low-cost energy through efficient nuclear
  operations and pursue modest growth based on market conditions. Changes in the operation of Power’s generating facilities, fuel and capacity prices, expected contract prices, capacity factors or other
  assumptions could materially affect its ability to meet earnings targets and/or liquidity requirements. In addition to the electric generation business described above, Power’s revenues include gas supply
  sales under the BGSS contract with PSE&G.
As a merchant generator, Power’s profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, congestion credits and a
  series of energy-related products that the system operator uses to optimize the operation of the energy grid, known as ancillary services. Accordingly, the prices of commodities, such as electricity, gas, coal
  and emissions, as well as the availability of Power’s diverse fleet of generation units to produce these products, can have a material effect on Power’s profitability.
Power seeks to mitigate volatility in its results by contracting in advance for a significant portion of its anticipated electric output and fuel needs. Power believes this contracting strategy increases
  stability of earnings and cash flow. By keeping some portion of its output uncontracted, Power is able to retain some ability to take advantage of market changes as well as provide some protection in the
  event of unexpected generation outages.
In a changing market environment, this hedging strategy may cause Power’s realized prices to be materially different than current market prices. At the present time, a significant portion of Power’s
  existing contractual obligations, entered into during lower-priced periods, resulted in lower margins than would have been the case if no or little hedging activity had been conducted. Alternatively, in a
  falling price environment, this hedging strategy will tend to create margins in excess of those implied by the then current market.
For Power’s BGSS contracts, commodity costs are passed on to residential customers. Any differences from the BGSS contract prices are deferred by PSE&G for future recovery. For commercial and
  industrial (C&I) customers, a tariff structure is applied that is adjusted monthly based on the current New York Mercantile Exchange (NYMEX) prices. During the first nine months of 2006, market
60

prices for natural gas declined from the historically high price levels experienced in the first nine months of 2005 while the cost of gas in inventory changed less, which reduced Power’s margins as compared
  to 2005.
For the nine months ended September 30, 2006, Power had Net Income of $394 million. Power has raised its earnings guidance from a range of $475 million to $525 million to a range of $500 million to
  $550 million for 2006, reflecting improved results and anticipated continued strong operating performance of its nuclear and fossil stations and attractive contracting opportunities in current energy markets.
  The guidance range does not include Merger-related costs and does not contemplate any potential impacts from MTM accounting. The net unrealized gains (after-tax) related to Power’s non-trading activity
  were $12 million and $2 million for the quarter and nine months ended September 30, 2006, respectively.
A key factor in Power’s ability to achieve its objectives is its capability to operate its nuclear and fossil stations at sufficient capacity factors to limit the need to purchase higher-priced electricity to
  satisfy its obligations. Power’s ability to achieve its objectives will also depend on the implementation of reasonable capacity markets. Power’s ability to benefit from any future increases in market prices
  will depend, to a large extent, on efficient power plant operations, especially for its low-cost nuclear and coal-fired facilities. Power must also be able to effectively manage its construction projects and
  continue to economically operate its generation facilities under increasingly stringent environmental requirements. In addition, with an increase in competition and market complexity and constantly
  changing forward prices, there is no assurance that Power will be able to contract its output at attractive prices. While these increases may have a potentially significant beneficial impact on margins, they
  could also raise any replacement power costs that Power may incur in the event of unanticipated outages, and could also further increase liquidity requirements as a result of contract obligations. For
  additional information on liquidity requirements, see Liquidity and Capital Resources.
Energy Holdings
Energy Holdings’ operations are principally conducted through its subsidiaries: Global, which has invested in international rate-regulated distribution companies and domestic and international
  merchant generation companies, and Resources, which primarily invests in energy-related leveraged leases.
In September 2006, Energy Holdings had accumulated excess cash of over $750 million from the sales of Global’s two investments in generating stations in Poland, the sale of its interest in RGE, a
  distribution company in Brazil and from ongoing operations. Energy Holdings used this cash to return $425 million of capital to PSEG in September 2006 and call $300 million of its outstanding $507 million
  2008 Senior Notes, which were redeemed on October 23, 2006. Including such amounts, Energy Holdings has returned a total of $1.3 billion of capital to PSEG and redeemed $900 million of its Senior
  Notes since 2004. After this redemption, Energy Holdings has $1.15 billion of Senior Notes outstanding with the next maturity of $207 million in 2008.
For the nine months ended September 30, 2006, Energy Holdings had Net Income of $251 million, which includes a net gain of $51 million related to the asset sales discussed above. During the year,
  Energy Holdings’ earnings guidance for 2006, which excludes the $51 million net gain, has been increased from a range of $155 million to $175 million to a range of $185 million to $205 million. The increase
  was largely driven by the performance of the Texas generating stations of Global’s subsidiary, Texas Independent Energy, L.P. (TIE). Spark margins in Texas increased substantially in 2005 and continued
  at high levels through the summer of 2006. The plants’ high availability factors have enabled TIE to benefit from the increased price levels in the marketplace. In addition, during the fall of 2005, TIE
  entered into long-term contracts for a portion of its output that is subject to MTM accounting treatment. The net unrealized gains (after-tax) related to such contracts were $29 million and $38 million for the
  quarter and nine months ended September 30, 2006, respectively. Approximately $11 million, after-tax of the unrealized gains are expected to reverse during the fourth quarter of 2006. Although market
  prices have significantly softened in recent months and are inherently volatile, TIE is expected to continue to be a major contributor to Energy Holdings’ earnings. Stable earnings from Global’s South
  American distribution companies also continue to provide a sustainable platform for Energy Holdings’ business.
61

Global
Although Global continues to produce significant earnings and operating cash flow, the returns on several of the investments in its international portfolio have not been commensurate with the level of
  risk associated with international investments in developing energy markets. As a result, since 2003, Global has refocused its strategy from one of growth to one that places emphasis on increasing the
  efficiency and returns of its existing assets.
In the first half of 2006, Global successfully closed on two major transactions as part of its strategy to opportunistically monetize assets that no longer have a strategic fit. In May 2006, Global completed
  the sale of its ownership interests in two generating facilities in Poland for $476 million, recording an after-tax gain of $228 million, which is included in Income from Discontinued Operations. In June 2006,
  Global completed the sale of its 32% interest in RGE for $185 million, resulting in an after-tax loss of $178 million. Together, Global received gross sales proceeds of $654 million, or approximately
  $612 million after taxes, and recorded a net after-tax gain of approximately $51 million.
In May 2006, Global also entered into an agreement to sell its 46% ownership interest in Dhofar Power Company S.A.O.C. (Dhofar Power), a generation facility and distribution system in Oman, for
  proceeds of approximately $33 million, which is the approximate book value. The sale of Dhofar Power, which is contingent upon attaining consents from Dhofar Power’s lenders and no objections from the
  Government of Oman, is expected to be completed in the fourth quarter of 2006. In May 2006, Global also converted its loans to Prisma 2000 S.p.A. (Prisma) to equity, thereby increasing its ownership
  interest from 50% to 85% and obtaining operating control. Prisma is a joint venture that operates several biomass generation plants in Italy. See Note 3. Discontinued Operations, Dispositions and
  Acquisitions of the Notes for further discussion.
Global’s results are driven by the performance of the domestic and international generation and distribution companies in which it invests. Global’s earnings and cash flows from its investment in
  distribution companies are impacted by the tariffs determined by the regulatory agencies in periodic rate cases and its ability to control costs and maintain reliable operations. With respect to its investment
  in generation companies, Global’s earnings and cash flows are impacted by the operating factors of the plants, including their availability factors, heat rates, fuel costs and environmental restrictions.
  Although some of Global’s investments have long-term power purchase agreements, several of its projects, including its operations in Texas, have a substantial amount of uncontracted capacity and are
  therefore affected by prevailing market prices, which can be volatile. Also, the economic and political conditions in certain countries where Global has investments present risks that may be different or
  more significant than those found in the U.S., including renegotiation or nullification of existing contracts, changes in law or tax policy, nationalization, expropriation and other factors. Operations in foreign
  countries also present risks associated with currency exchange and convertibility, inflation and repatriation of earnings.
Resources
Resources has primarily invested in energy-related leveraged leases. Resources is focused on maintaining its current investment portfolio and does not expect to make any new investments. Resources’
  ability to realize tax benefits associated with its leveraged lease investments is dependent upon taxable income generated by its affiliates. Resources’ earnings and cash flows are expected to decrease in the
  future as the investment portfolio matures. Resources faces risks related to potential changes in the current accounting and tax treatment of certain investments in leveraged leases. For additional
  information on current accounting and tax treatment of Resources’ leveraged lease investments, see Note 2. Recent Accounting Standards and Note 5. Commitments and Contingent Liabilities. Resources
  also faces risks with regard to the creditworthiness of its counterparties, specifically certain lessees that collectively comprise a substantial portion of Resources’ investment portfolio.
62

RESULTS OF OPERATIONS
The results for PSEG, PSE&G, Power and Energy Holdings for the quarter and nine months ended September 30, 2006 and 2005 are presented below:
Earnings (Losses)Quarters EndedSeptember 30,
    
    Nine Months EndedSeptember 30,2006
    
    2005
    
    2006
    
    2005(Millions)PSE&G
    
    
    $
    
    88
    
    
    
    $
    
    115
    
    
    
    $
    
    200
    
    
    
    $
    
    282Power
    
    
    
    205
    
    
    
    
    132
    
    
    
    
    394
    
    
    
    
    303Energy Holdings:Global (D)
    
    
    
    92
    
    
    
    
    32
    
    
    
    
    (22
    )
    
    
    
    
    91Resources
    
    
    
    10
    
    
    
    
    17
    
    
    
    
    49
    
    
    
    
    39Other (A)
    
    
    
    (1
    )
    
    
    
    
    (1
    )
    
    
    
    
    (3
    )
    
    
    
    
    (3
    )Total Energy Holdings
    
    
    
    101
    
    
    
    
    48
    
    
    
    
    24
    
    
    
    
    127Other (B)
    
    
    
    (20
    )
    
    
    
    
    (26
    )
    
    
    
    
    (59
    )
    
    
    
    
    (72
    )PSEG Income from Continuing Operations
    
    
    
    374
    
    
    
    
    269
    
    
    
    
    559
    
    
    
    
    640Income (Loss) from Discontinued Operations, including Gain/(Loss) on Disposal (C)
    
    
    
    —
    
    
    
    
    (16
    )
    
    
    
    
    227
    
    
    
    
    (184
    )PSEG Net Income
    
    
    $
    
    374
    
    
    
    $
    
    253
    
    
    
    $
    
    786
    
    
    
    $
    
    456Contribution to PSEG EarningsPer Share (Diluted) (E)Quarters EndedSeptember 30,
    
    Nine Months EndedSeptember 30,2006
    
    2005
    
    2006
    
    2005PSE&G
    
    
    $
    
    0.35
    
    
    
    $
    
    0.47
    
    
    
    $
    
    0.79
    
    
    
    $
    
    1.16Power
    
    
    
    0.81
    
    
    
    
    0.54
    
    
    
    
    1.56
    
    
    
    
    1.25Energy Holdings:Global
    
    
    
    0.36
    
    
    
    
    0.13
    
    
    
    
    (0.08
    )
    
    
    
    
    0.37Resources
    
    
    
    0.04
    
    
    
    
    0.07
    
    
    
    
    0.19
    
    
    
    
    0.16Other (A)
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    (0.01
    )
    
    
    
    
    (0.01
    )Total Energy Holdings
    
    
    
    0.40
    
    
    
    
    0.20
    
    
    
    
    0.10
    
    
    
    
    0.52Other (B)
    
    
    
    (0.08
    )
    
    
    
    
    (0.11
    )
    
    
    
    
    (0.23
    )
    
    
    
    
    (0.30
    )PSEG Income from Continuing Operations
    
    
    
    1.48
    
    
    
    
    1.10
    
    
    
    
    2.22
    
    
    
    
    2.63Income (Loss) from Discontinued Operations, including Gain/(Loss) on Disposal (C)
    
    
    
    —
    
    
    
    
    (0.07
    )
    
    
    
    
    0.90
    
    
    
    
    (0.76
    )PSEG Net Income
    
    
    $
    
    1.48
    
    
    
    $
    
    1.03
    
    
    
    $
    
    3.12
    
    
    
    $
    
    1.87

(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 interest on certain financing transactions, Merger expenses
      and certain other administrative and general expenses at PSEG (as parent company).(C)
    
    
    
    The Gain on Disposal of Skawina and Elcho is included in 2006 and their Discontinued Operations are included in 2006 and 2005. The Loss on Disposal and Discontinued Operations of
      Waterford, an electric generation facility in Waterford, Ohio that was sold in September 2005, are included in 2005. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the
      Notes.(D)
    
    
    
    Global’s Income from Continuing Operations for 2006 includes the $178 million after-tax loss on the sale of RGE in June 2006.63

(E)
    
    
    
    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 $105 million or $0.38 per share increase in Income from Continuing Operations for the quarter was due to increases of $73 million, $53 million and $6 million at Power, Energy Holdings and PSEG
  (as parent company), respectively, partially offset by a decrease of $27 million at PSE&G. The increase at Power was due principally to higher realized prices from re-contracting its generation portfolio
  combined with improved nuclear performance. Power’s increase was partially offset by lower realized income related to its Nuclear Decommissioning Trust (NDT) Funds, increased costs due to the
  commencement of commercial operations at Linden in May 2006 and a reserve accrual of approximately $15 million related to negotiations regarding the continued operation of its Hudson unit. The
  increase at Energy Holdings was primarily due to its strong operations in Texas, reflecting unrealized gains on forward gas contracts and higher margins due to increased output, partially offset by higher
  Operations and Maintenance expense. PSEG’s increase was attributable to decreased Merger costs and lower Interest Expense. The decrease at PSE&G was mainly due to the full amortization of the excess
  depreciation reserve as of December 31, 2005. Also decreasing PSE&G’s earnings was reduced demand due to higher pricing and weather.
The $81 million or $0.41 per share decrease in Income from Continuing Operations for the nine months ended September 30, 2006, as compared to the same period in 2005, was due to decreases of $103
  million and $82 million at Energy Holdings and PSE&G, respectively, partially offset by an increase of $91 million at Power and an improvement of $13 million at PSEG (as parent company). The decrease at
  Energy Holdings was primarily due to the $178 million after-tax loss on the sale of RGE in June 2006 partially offset by improved operations in Texas discussed above. The changes for PSEG and PSE&G
  were primarily attributable to the same reasons discussed above for the quarter. The increase at Power was due to higher sales volumes in the various power pools, supported by improved nuclear operations
  and the commencement of commercial operations at Linden in May 2006 and at the Bethlehem Energy Center (BEC) in July 2005. Power’s increase was partially offset by lower realized income related to
  its Nuclear Decommissioning Trust (NDT) Funds, increased costs related to Linden and BEC and reduced margins on BGSS as market prices for natural gas declined from the historically high price levels
  experienced in the second half of 2005 while the cost of gas in inventory was relatively stable.
PSEG
For theQuarters EndedSeptember 30,
    
    Increase(Decrease)
    
    %
    
    For theNine MonthsEndedSeptember 30,
    
    
    
    %Increase(Decrease)2006
    
    2005
    
    2006
    
    2005(Millions)
    
    (Millions)Operating Revenues
    
    
    $
    
    3,392
    
    
    
    $
    
    3,324
    
    
    
    $
    
    68
    
    
    
    
    2
    
    
    
    $
    
    9,516
    
    
    
    $
    
    8,940
    
    
    
    $
    
    576
    
    
    
    
    6Energy Costs
    
    
    $
    
    1,809
    
    
    
    $
    
    1,979
    
    
    
    $
    
    (170
    )
    
    
    
    
    (9
    )
    
    
    
    $
    
    5,400
    
    
    
    $
    
    5,144
    
    
    
    $
    
    256
    
    
    
    
    5Operation and Maintenance
    
    
    $
    
    541
    
    
    
    $
    
    537
    
    
    
    $
    
    4
    
    
    
    
    1
    
    
    
    $
    
    1,705
    
    
    
    $
    
    1,661
    
    
    
    $
    
    44
    
    
    
    
    3Write-down of Project Investments
    
    
    $
    
    —
    
    
    
    $
    
    —
    
    
    
    $
    
    —
    
    
    
    
    —
    
    
    
    $
    
    263
    
    
    
    $
    
    —
    
    
    
    $
    
    263
    
    
    
    
    N/ADepreciation and Amortization
    
    
    $
    
    234
    
    
    
    $
    
    204
    
    
    
    $
    
    30
    
    
    
    
    15
    
    
    
    $
    
    645
    
    
    
    $
    
    562
    
    
    
    $
    
    83
    
    
    
    
    15Income from Equity Method Investments
    
    
    $
    
    30
    
    
    
    $
    
    30
    
    
    
    $
    
    —
    
    
    
    
    —
    
    
    
    $
    
    93
    
    
    
    $
    
    90
    
    
    
    $
    
    3
    
    
    
    
    3Other Income and Deductions
    
    
    $
    
    7
    
    
    
    $
    
    61
    
    
    
    $
    
    (54
    )
    
    
    
    
    (89
    )
    
    
    
    $
    
    62
    
    
    
    $
    
    103
    
    
    
    $
    
    (41
    )
    
    
    
    
    (40
    )Interest Expense
    
    
    $
    
    (209
    )
    
    
    
    $
    
    (208
    )
    
    
    
    $
    
    1
    
    
    
    
    —
    
    
    
    $
    
    (617
    )
    
    
    
    $
    
    (606
    )
    
    
    
    $
    
    11
    
    
    
    
    2Income Tax Expense
    
    
    $
    
    (229
    )
    
    
    
    $
    
    (183
    )
    
    
    
    $
    
    46
    
    
    
    
    25
    
    
    
    $
    
    (379
    )
    
    
    
    $
    
    (412
    )
    
    
    
    $
    
    (33
    )
    
    
    
    
    (8
    )Income (Loss) from Discontinued Operations, including Gain/(Loss) on Disposal, net of tax
    
    
    $
    
    —
    
    
    
    $
    
    (16
    )
    
    
    
    $
    
    16
    
    
    
    
    N/A
    
    
    
    $
    
    227
    
    
    
    $
    
    (184
    )
    
    
    
    $
    
    411
    
    
    
    
    N/APSEG’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 13. 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.
64

PSE&G
For theQuarters EndedSeptember 30,
    
    Increase(Decrease)
    
    %
    
    For theNine MonthsEndedSeptember 30,
    
    
    
    %Increase(Decrease)2006
    
    2005
    
    2006
    
    2005(Millions)
    
    (Millions)Operating Revenues
    
    
    $
    
    2,017
    
    
    
    $
    
    1,934
    
    
    
    $
    
    83
    
    
    
    
    4
    
    
    
    $
    
    5,901
    
    
    
    $
    
    5,559
    
    
    
    $
    
    342
    
    
    
    
    6Energy Costs
    
    
    $
    
    1,296
    
    
    
    $
    
    1,195
    
    
    
    $
    
    101
    
    
    
    
    8
    
    
    
    $
    
    3,872
    
    
    
    $
    
    3,472
    
    
    
    $
    
    400
    
    
    
    
    12Operation and Maintenance
    
    
    $
    
    278
    
    
    
    $
    
    276
    
    
    
    $
    
    2
    
    
    
    
    1
    
    
    
    $
    
    855
    
    
    
    $
    
    839
    
    
    
    $
    
    16
    
    
    
    
    2Depreciation and Amortization
    
    
    $
    
    174
    
    
    
    $
    
    155
    
    
    
    $
    
    19
    
    
    
    
    12
    
    
    
    $
    
    476
    
    
    
    $
    
    418
    
    
    
    $
    
    58
    
    
    
    
    14Other Income and Deductions
    
    
    $
    
    6
    
    
    
    $
    
    2
    
    
    
    $
    
    4
    
    
    
    
    N/A
    
    
    
    $
    
    16
    
    
    
    $
    
    5
    
    
    
    $
    
    11
    
    
    
    
    N/AInterest Expense
    
    
    $
    
    (86
    )
    
    
    
    $
    
    (86
    )
    
    
    
    $
    
    —
    
    
    
    
    —
    
    
    
    $
    
    (254
    )
    
    
    
    $
    
    (256
    )
    
    
    
    $
    
    (2
    )
    
    
    
    
    (1
    )Income Tax Expense
    
    
    $
    
    (69
    )
    
    
    
    $
    
    (74
    )
    
    
    
    $
    
    (5
    )
    
    
    
    
    (7
    )
    
    
    
    $
    
    (160
    )
    
    
    
    $
    
    (191
    )
    
    
    
    $
    
    (31
    )
    
    
    
    
    (16
    )Operating Revenues
PSE&G has three sources of revenue: commodity revenues from the sales of energy to customers and in the PJM Interconnection, L.L.C. (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 $83 million increase for the quarter ended September 30, 2006, as compared to the same
  period in 2005, was due to an increase of $115 million in commodity revenues, partially offset by a $32 million decrease in delivery revenues. The $342 million increase for the nine months ended September
  30, 2006, as compared to the same period in 2005, was due to increases of $384 million in commodity revenues, partially offset by a $42 million decrease in delivery revenues.
Commodity
PSE&G makes no margin on commodity sales as the costs are passed through to customers. The difference between gas 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 C&I customers and annually through the
  BGSS tariff for residential customers. In addition, for residential gas customers, PSE&G has the ability to adjust rates upward two additional times and downward at any time, if warranted, between annual
  BGSS proceedings. Electric commodity prices are set at the annual BGS auctions.
The $115 million increase in commodity revenues for the quarter ended September 30, 2006, as compared to the same period in 2005, was due to increases of $118 million in electric commodity
  revenues, partially offset by a $3 million decrease in gas commodity revenues. The increase in electric commodity revenues was primarily due to $149 million in higher BGS revenues (higher auction prices
  of $198 million offset by reduced sales of $49 million) offset by $31 million in lower Non-Utility Generation (NUG) revenues (lower PJM prices of $38 million offset by $7 million for higher volumes due to
  operations). The decrease in gas commodity revenues was primarily due to a $26 million reduction caused by lower volumes due to weather offset by an increase of $23 million due to higher BGSS prices.
The $384 million increase in commodity revenues for the nine months ended September 30, 2006, as compared to the same period in 2005, was due to increases in electric and gas commodity revenues
  of $250 million and $134 million, respectively. The increase in electric commodity revenues was primarily due to $262 million in higher BGS revenues (higher auction prices of $299 million offset by reduced
  sales of $37 million) offset by $12 million in lower NUG revenues (lower PJM prices of $64 million offset by $52 million for higher volumes due to operations). The increase in gas commodity revenues was
  primarily due to $371 million in higher BGSS prices offset by decreases of $179 million in lower volumes due to weather and $58 million due to the expiration of the Third Party Shopping Incentive in July
  2005. There was a corresponding $58 million increase in delivery revenues.
65

Delivery
The $32 million decrease in delivery revenues for the quarter ended September 30, 2006, as compared to the same period in 2005, was due to a $35 million decrease in electric revenues offset by a $3
  million increase in gas revenues. The $35 million decrease in electric revenues was due to $37 million in decreased volumes due to weather and $1 million in lower securitization tariff rates, partially offset
  by $3 million in higher demand revenues. The $3 million increase in gas delivery revenues resulted from $6 million in higher volumes primarily due to weather offset by $3 million in reduced prices.
The $42 million decrease in delivery revenues for the nine months ended September 30, 2006, as compared to the same period in 2005, was due to a $44 million decrease in electric revenues and a
  $2 million increase in gas revenues. The $44 million decrease in electric revenues was due to $37 million in lower volumes due to weather, $4 million due to lower demand revenues and $3 million due to
  lower securitization tariff rates. The $2 million increase in gas delivery revenues was due primarily to $64 million in increased prices, primarily due to the expiration of the Third Party Shopping Incentive in
  July 2005, described above in commodity revenues. This was offset by $56 million in lower volumes due to weather and $6 million due to impacts of price elasticity.
Operating Expenses
Energy Costs
The $101 million increase for the quarter ended September 30, 2006, as compared to the same period in 2005, was comprised of an increase of $102 million in electric costs and a decrease of $1 million in
  gas costs. The increase in electric costs was due to $147 million in higher BGS prices and $6 million in higher NUG volumes, offset by $46 million in lower BGS volumes and $5 million in lower NUG prices.
  The decrease in gas costs was caused by a $31 million decrease in sales volumes due primarily to weather offset by a $30 million or 2% increase in gas prices.
The $400 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was comprised of increases of $207 million in electric costs and $193 million in gas
  costs. The increase in electric costs was due to $208 million in higher BGS prices and $70 million in higher NUG volumes, offset by $34 million in lower BGS volumes and $37 million in lower NUG prices.
  The increase in gas costs was caused by a $382 million or 23% increase in gas prices offset by a $181 million decrease in sales volumes due primarily to weather and an $8 million decrease due to the
  expiration of the Gas Cost Underrecovery Adjustment (GCUA) clause in January 2005.
Operation and Maintenance
The $2 million increase for the quarter ended September 30, 2006, as compared to the same period in 2005, was due primarily to $1 million in increased injuries and damage claims and $1 million in
  increased bad debt expense.
The $16 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was due primarily to $11 million in increased labor and fringe benefits due to increased
  wages and OPEB costs and $7 million in increased bad debt expense. This was offset by a decrease of $2 million in miscellaneous expenses.
Depreciation and Amortization
The $19 million increase for the quarter ended September 30, 2006, as compared to the same period in 2005, was comprised of increases of $21 million from the expiration of an excess depreciation
  credit and $2 million due to additional plant in service offset by a $4 million reduction in amortization of regulatory assets.
The $58 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was comprised of increases of $54 million from the expiration of an excess depreciation
  credit, $7 million due to amortization of regulatory assets and $2 million due to additional plant in service. These increases were offset by decreases of $3 million due to software amortization and $2 million
  due to the amortization of the Remediation Adjustment Clause (RAC).
66

Other Income and Deductions
Other Income and Deductions increased $4 million for the quarter ended September 30, 2006, as compared to the same period in 2005, primarily due to a $3 million income tax gross-up on
  contributions in aid of construction (CIAC) in 2006. CIAC is taxable and PSE&G recognizes the gross-up as income when collected.
Other Income and Deductions increased $11 million for the nine months ended September 30, 2006, as compared to the same period in 2005, due to increases of $7 million due to an income tax gross-
  up on CIAC in 2006 and $4 million due to increased income on investments.
Income Taxes
Income Taxes decreased $5 million for the quarter and $31 million for the nine months ended September 30, 2006, as compared to the same periods in 2005, primarily due to lower pre-tax income.
Power
For theQuarters EndedSeptember 30,
    
    Increase(Decrease)
    
    %
    
    For theNine MonthsEndedSeptember 30,
    
    
    
    %Increase(Decrease)2006
    
    2005
    
    2006
    
    2005(Millions)
    
    (Millions)Operating Revenues
    
    
    $
    
    1,489
    
    
    
    $
    
    1,444
    
    
    
    $
    
    45
    
    
    
    
    3
    
    
    
    $
    
    4,591
    
    
    
    $
    
    4,234
    
    
    
    $
    
    357
    
    
    
    
    8Energy Costs
    
    
    $
    
    830
    
    
    
    $
    
    983
    
    
    
    $
    
    (153
    )
    
    
    
    
    (16
    )
    
    
    
    $
    
    2,992
    
    
    
    $
    
    2,941
    
    
    
    $
    
    51
    
    
    
    
    2Operation and Maintenance
    
    
    $
    
    222
    
    
    
    $
    
    223
    
    
    
    $
    
    (1
    )
    
    
    
    
    —
    
    
    
    $
    
    721
    
    
    
    $
    
    685
    
    
    
    $
    
    36
    
    
    
    
    5Depreciation and Amortization
    
    
    $
    
    41
    
    
    
    $
    
    34
    
    
    
    $
    
    7
    
    
    
    
    21
    
    
    
    $
    
    116
    
    
    
    $
    
    96
    
    
    
    $
    
    20
    
    
    
    
    21Other Income and Deductions
    
    
    $
    
    11
    
    
    
    $
    
    61
    
    
    
    $
    
    (50
    )
    
    
    
    
    (82
    )
    
    
    
    $
    
    53
    
    
    
    $
    
    102
    
    
    
    $
    
    (49
    )
    
    
    
    
    (48
    )Interest Expense
    
    
    $
    
    (47
    )
    
    
    
    $
    
    (32
    )
    
    
    
    $
    
    15
    
    
    
    
    47
    
    
    
    $
    
    (131
    )
    
    
    
    $
    
    (86
    )
    
    
    
    $
    
    45
    
    
    
    
    52Income Tax Expense
    
    
    $
    
    (155
    )
    
    
    
    $
    
    (101
    )
    
    
    
    $
    
    54
    
    
    
    
    53
    
    
    
    $
    
    (290
    )
    
    
    
    $
    
    (225
    )
    
    
    
    $
    
    65
    
    
    
    
    29Loss from Discontinued Operations, including Loss on Disposal, net of tax benefit
    
    
    $
    
    —
    
    
    
    $
    
    (7
    )
    
    
    
    $
    
    7
    
    
    
    
    N/A
    
    
    
    $
    
    —
    
    
    
    $
    
    (197
    )
    
    
    
    $
    
    197
    
    
    
    
    N/AOperating Revenues
The $45 million increase for the quarter ended September 30, 2006, as compared to the same period in 2005, was due to increases of $56 million in generation revenues and $19 million in trading
  revenues, partially offset by a decrease of $30 million in gas supply revenues.
The $357 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was due to increases of $278 million in generation revenues, $47 million in gas supply
  revenues and $32 million in trading revenues.
Generation
The increase of $56 million for the quarter ended September 30, 2006, as compared to the same period in 2005, was primarily due to an increase of $68 million due to higher sales volumes in the various
  power pools, supported by improved nuclear operations and the commencement of the commercial operations of Linden in May 2006 and BEC in July 2005 and an increase of $56 million due to higher
  prices under the BGS contracts. The increases were partially offset by a reduction in load being served under the BGS contracts, $32 million of unrealized losses on asset-backed electric forward contracts
  and a decrease of $30 million due to the maturity of certain wholesale contracts in early 2006.
The increase of $278 million for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily due to $307 million of higher sales volumes in the various power
  pools, supported by improved nuclear operations and the commencement of the commercial operations of Linden and BEC and $59 million of higher prices under the BGS contracts. The increases were
  partially offset by a reduction in load being served under the BGS contracts, $63 million of unrealized losses on asset-backed electric forward contracts and a decrease of $37 million due to the maturity of
  certain wholesale contracts in early 2006 and 2005.
67

Gas Supply
Gas supply revenues decreased $30 million for the quarter ended September 30, 2006, as compared to the same period in 2005, principally due to a decrease of $32 million from lower gas prices and
  reduced demand under the BGSS contract, resulting from customer conservation and warmer winter weather in 2006 and a decrease of $16 million in prices charged to other gas distributors for gas and
  pipeline capacity. These decreases were partially offset by $22 million of gains on derivative forward contracts.
The $47 million increase in gas supply revenues for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily due to increases of $304 million in gas prices
  under the BGSS contract and $13 million in sales prices charged to other gas distributors for gas and pipeline capacity. Increased prices were partially offset by lower demand of $207 million under the
  BGSS contract in 2006 and a reduction of $68 million in sales volume to other gas distributors.
Trading
The $19 million increase in trading revenues for the quarter ended September 30, 2006, as compared to the same period in 2005, was primarily due to higher realized gains related to electric contracts.
The $32 million increase in trading revenues for the nine months ended September 30, 2006, as compared to the same period in 2005, was principally due to higher realized and unrealized gains related
  to electric contracts and emissions credits.
Operating Expenses
Energy Costs
Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS
  contract with PSE&G.
Energy Costs decreased approximately $153 million for the quarter ended September 30, 2006, as compared to the same period in 2005, primarily due to lower generation costs, reflecting decreases of
  $90 million resulting from lower pool prices and a reduction in the volume of purchases from the various power pools due to lower load obligations and $20 million due to favorable pricing of fuel-related
  asset-backed transactions in 2006. In addition, fossil fuel expenses decreased $19 million due to lower load obligations and gas purchased to satisfy Power’s BGSS obligations decreased $39 million due to
  lower prices. These decreases were partially offset by an increase of $16 million in various congestion and transmission costs.
The $51 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily due to increases of $91 million from higher prices on a reduced volume
  of gas purchased to satisfy Power’s BGSS obligations and $85 million from a higher volume of fossil fuel purchases used to support generation by Linden and BEC. These increases were partially offset by a
  decrease of $127 million, representing lower pool prices and a reduction in the volume of purchases from the various power pools.
Operation and Maintenance
Operation and Maintenance expense decreased $1 million and increased $36 million for the quarter and nine months ended September 30, 2006, respectively, as compared to the same periods in 2005.
  The increase of $36 million was principally due to higher maintenance costs of $50 million related to certain of the fossil plants and a scheduled outage at a nuclear unit partially offset by the absence of a
  $14 million restructuring charge incurred in 2005 related to Nuclear’s workforce realignment plan.
68

Depreciation and Amortization
The $7 million and $20 million increases for the quarter and nine months ended September 30, 2006, respectively, as compared to the same periods in 2005, was primarily due to Linden and BEC being
  placed into service.
Other Income and Deductions
Other Income and Deductions decreased $50 million and $49 million for the quarter and nine months ended September 30, 2006, respectively, as compared to the same periods in 2005, primarily due to
  decreased net realized income related to the NDT Funds of $37 million and $39 million for the quarter and year-to-date periods, respectively. Also contributing to the decrease for the quarter and nine
  months was an environmental reserve of approximately $15 million recorded in the third quarter of 2006 for potential penalties and other costs related to ongoing negotiations for an alternate pollution
  reduction plan for Power’s Hudson unit. These decreases were partially offset by higher interest income of $2 million and $6 million for the quarter and nine months ended September 30, 2006, respectively,
  as compared to the same period in 2005.
Interest Expense
Interest Expense increased $15 million and $45 million for the quarter and nine months ended September 30, 2006, respectively, as compared to the same periods in 2005, due primarily to lower
  capitalized interest costs in 2006 related to commencement of operations of the BEC and Linden facilities.
Income Taxes
Income Taxes increased $54 million for the quarter and $65 million for the nine months ended September 30, 2006, as compared to the same periods in 2005, primarily due to higher pre-tax income.
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. On September 28, 2005, Power completed the sale of Waterford and recognized an additional loss of $1 million. The proceeds,
  together with anticipated reduction in tax liability, were approximately $320 million, which was used to retire debt at Power. The loss from the discontinued operating results of Waterford was $6 million and
  $19 million for the quarter and nine months ended September 30, 2005, respectively. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information.
69

Energy Holdings
For theQuarters EndedSeptember 30,
    
    Increase(Decrease)
    
    %
    
    For theNine Months
      EndedSeptember 30,
    
    
    
    %Increase(Decrease)2006
    
    2005
    
    2006
    
    2005(Millions)
    
    
    
    
    
    
    
    (Millions)Operating Revenues
    
    
    $
    
    401
    
    
    
    $
    
    334
    
    
    
    $
    
    67
    
    
    
    
    20
    
    
    
    $
    
    1,080
    
    
    
    $
    
    917
    
    
    
    $
    
    163
    
    
    
    
    18Energy Costs
    
    
    $
    
    195
    
    
    
    $
    
    184
    
    
    
    $
    
    11
    
    
    
    
    6
    
    
    
    $
    
    583
    
    
    
    $
    
    484
    
    
    
    $
    
    99
    
    
    
    
    20Operation and Maintenance
    
    
    $
    
    49
    
    
    
    $
    
    41
    
    
    
    $
    
    8
    
    
    
    
    20
    
    
    
    $
    
    150
    
    
    
    $
    
    151
    
    
    
    $
    
    (1
    )
    
    
    
    
    (1
    )Write-down of Project Investments
    
    
    $
    
    —
    
    
    
    $
    
    —
    
    
    
    $
    
    —
    
    
    
    
    —
    
    
    
    $
    
    263
    
    
    
    $
    
    —
    
    
    
    $
    
    263
    
    
    
    
    N/ADepreciation and Amortization
    
    
    $
    
    14
    
    
    
    $
    
    10
    
    
    
    $
    
    4
    
    
    
    
    40
    
    
    
    $
    
    38
    
    
    
    $
    
    35
    
    
    
    $
    
    3
    
    
    
    
    9Income from Equity Method Investments
    
    
    $
    
    30
    
    
    
    $
    
    30
    
    
    
    $
    
    —
    
    
    
    
    —
    
    
    
    $
    
    93
    
    
    
    $
    
    90
    
    
    
    $
    
    3
    
    
    
    
    3Other Income and Deductions
    
    
    $
    
    (2
    )
    
    
    
    $
    
    2
    
    
    
    $
    
    (4
    )
    
    
    
    
    N/A
    
    
    
    $
    
    6
    
    
    
    $
    
    1
    
    
    
    $
    
    5
    
    
    
    
    N/AInterest Expense
    
    
    $
    
    (50
    )
    
    
    
    $
    
    (56
    )
    
    
    
    $
    
    (6
    )
    
    
    
    
    (11
    )
    
    
    
    $
    
    (151
    )
    
    
    
    $
    
    (168
    )
    
    
    
    $
    
    (17
    )
    
    
    
    
    (10
    )Income Tax (Expense) Benefit
    
    
    $
    
    (20
    )
    
    
    
    $
    
    (27
    )
    
    
    
    $
    
    (7
    )
    
    
    
    
    (26
    )
    
    
    
    $
    
    31
    
    
    
    $
    
    (42
    )
    
    
    
    $
    
    (73
    )
    
    
    
    
    N/AIncome (Loss) from Discontinued Operations, including Gain/ (Loss) on Disposal, net of tax
    
    
    $
    
    —
    
    
    
    $
    
    (9
    )
    
    
    
    $
    
    (9
    )
    
    
    
    
    (100
    )
    
    
    
    $
    
    227
    
    
    
    $
    
    13
    
    
    
    $
    
    214
    
    
    
    
    N/AOperating Revenues
The $67 million increase for the quarter ended September 30, 2006, as compared to the same period in 2005, was primarily due to higher revenues at Global of $78 million, which was primarily related
  to a $60 million increase at TIE. The increase at TIE included an increase of $63 million related to unrealized gains on forward contracts and $13 million due to increased output available for sale, partially
  offset by lower prices of $16 million driven by lower gas costs. Also included in the increase at Global were a $9 million increase due to the consolidation of Prisma which began in May 2006 when Global
  increased its ownership interest from 50% to 85% and an $8 million increase at Sociedad Austral de Electricidad S.A. (SAESA) in Chile due to increased tariff prices and volume, offset by a decrease of
  revenues at Resources of $12 million primarily due to $8 million of lower lease income.
The $163 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily due to higher revenues at Global of $171 million, which was primarily
  related to a $163 million increase at TIE. The increase at TIE included increases of $115 million related to unrealized gains on forward contracts, $27 million due to increased output available for sale and
  $21 million due to price increases. Also contributing to the increase at Global was a $48 million increase at SAESA due to increased tariffs and volume and a $17 million increase due to the consolidation of
  Prisma, partially offset by decreased revenues due to the absence of $37 million of income received in 2005 from withdrawal from Eagle Point Cogeneration Partnership (EPCP) and a $23 million decrease
  related to the deconsolidation of Dhofar Power. The deconsolidation of Dhofar Power resulted from 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. The increase at Global was partially offset
  by an $8 million decrease in revenues at Resources primarily due to the reduction in leveraged lease income of $25 million, offset by the $21 million write-off of its leveraged lease investment with United
  Airlines in 2005.
Operating Expenses
Energy Costs
The
  $11 million increase for the quarter ended September 30, 2006, as compared to
  the same period in 2005, was primarily due to increases of $4 million at SAESA
  due to increased volume and increases in energy costs due to higher spot prices,
  $3 million due to the consolidation of Prisma and $3 million at TIE resulting
  from an increase of $13 million in gas purchases offset primarily by lower fuel
  costs of $10 million.
The $99 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily due to a $64 million increase at TIE resulting mainly from an increase in
70

unrealized losses on gas purchases of $51 million coupled with a $13 million increase in fuel purchases. Also contributing to the increase was a $33 million increase at SAESA due to increased volume and
  increases in energy costs due to higher spot prices and a $6 million increase due to the consolidation of Prisma. These increases were partially offset by a $5 million decrease related to the deconsolidation of
  Dhofar Power.
Operation and Maintenance
The
  $8 million increase for the quarter ended September 30, 2006, as compared to
  the same period in 2005, was primarily due to a $7 million increase at SAESA
  resulting from repairs of a gas turbine for which it has filed a claim for insurance
  recovery.
Write-down of Project Investments
The $263 million increase in the write-down of project investments relates to Global’s sale of its 32% indirect ownership interest in RGE to its partner. See Note 3. Discontinued Operations,
  Dispositions and Acquisitions of the Notes.
Income from Equity Method Investments
The $3 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily due to the consolidation of Prisma generating an increase in earnings of
  $5 million and stronger results from Global’s investments in Hawaii (Kalaeloa) and California (GWF) totaling $3 million, offset by a reduction of $5 million in the equity from investments in Latin America
  due to the sale of Global’s 32% indirect interest in RGE.
Other Income and Deductions
The
  $4 million decrease for the quarter ended September 30, 2006 compared to the
  same period in the prior year, was primarily due to a loss recorded on the extinguishment
  of debt, which was partially offset by higher interest income and lower losses
  in foreign currency transactions.
The
  $5 million increase for the nine months ended September 30, 2006, as compared
  to the same period in 2005, was primarily due to an increase in interest income
  and lower losses in foreign currency transactions which was partially offset
  by the loss recorded on the extinguishment of debt.
Interest Expense
The $6 million and $17 million decreases for the quarter and nine months ended September 30, 2006, respectively, as compared to the same periods in 2005, was primarily due to a decrease in Energy
  Holdings’ debt outstanding.
Income Taxes
The $7 million decrease for the quarter ended September 30, 2006, as compared to the same period in 2005, was primarily attributable to a $9 million U.S. tax associated with repatriation of funds
  recorded in 2005. The $73 million decrease for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily attributable to a tax benefit resulting from Global’s sale of
  its 32% indirect ownership interest in RGE.
Income from Discontinued Operations, including Gain on Disposal, net of tax
In May 2006, Global completed the sale of its interest in two coal-fired plants in Poland, Elcho and Skawina. The sale resulted in an after-tax gain of $228 million. Income (Loss) from Discontinued
  Operations related to Elcho and Skawina for the quarters ended September 30, 2006 and 2005 was $0 million and $9 million, respectively. Income (Loss) from Discontinued Operations related to Elcho and
  Skawina for the nine months ended September 30, 2006 and 2005 was $(1) million and $13 million,
71

respectively. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of liquidity and capital resources is on a consolidated basis for PSEG, noting the uses and contributions of PSEG’s three direct operating subsidiaries, PSE&G, Power and Energy
  Holdings.
Operating Cash Flows
PSEG
For the nine months ended September 30, 2006, PSEG’s operating cash flow increased approximately $541 million from $903 million to $1,444 million, as compared to the same period in 2005, primarily
  due to net increases from its subsidiaries as discussed below.
PSE&G
PSE&G’s operating cash flow decreased approximately $41 million from $464 million to $423 million for the nine months ended September 30, 2006, as compared to the same period in 2005, primarily
  due to a decrease in customer deposits partially offset by higher over recovery of gas costs resulting from lower commodity prices in 2006.
Power
Power’s operating cash flow increased approximately $644 million from $276 million to $920 million for the nine months ended September 30, 2006, as compared to the same period in 2005, due to
  decreases in accounts receivable and fuel inventory, largely resulting from decreased commodity prices.
Energy Holdings
Energy
  Holdings’ operating cash flow decreased approximately $80 million from
  $229 million to $149 million for the nine months ended September 30, 2006, as
  compared to the same period in 2005. The $80 million decrease is primarily due
  to the timing of net tax payments associated with the net gain on the sale of
  Elcho, Skawina and RGE during 2006 as well as higher distributions from partnerships
  during 2005 due to the withdrawal from EPCP. The proceeds from the Elcho, Skawina
  and RGE sales are included in Investing Activities on Energy Holdings’
  Condensed Consolidated Statements of Cash Flows.
Common Stock Dividends
PSEG
Dividend payments on common stock for the quarters ended September 30, 2006 and 2005 were $0.57 and $0.56 per share, respectively, and totaled approximately $144 million and $134 million,
  respectively. Dividend payments on common stock for the nine months ended September 30, 2006 and 2005 were $1.71 and $1.68 per share, respectively, and totaled approximately $430 million and
  $401 million, respectively. Future dividends declared will be dependent upon PSEG’s future earnings, cash flows, financial requirements, alternative investment opportunities and other factors. On
  October 17, 2006, PSEG’s Board of Directors approved a common stock dividend of $0.57 per share for the fourth quarter of 2006, reflecting an indicated annual dividend rate of $2.28 per share.
72

Short-Term Liquidity
PSEG, PSE&G, Power and Energy Holdings
As of September 30, 2006, PSEG and its subsidiaries had a total of approximately $3.7 billion of committed credit facilities with approximately $3.1 billion of available liquidity under these facilities. In
  addition, PSEG and PSE&G have access to certain uncommitted credit facilities. Each of the facilities is restricted to availability and use to the specific companies as listed below.
Company
    
    ExpirationDate
    
    TotalFacility
    
    PrimaryPurpose
    
    Usage as ofSeptember 30,2006
    
    AvailableLiquidity as ofSeptember 30,2006(Millions)PSEG:4-year Credit Facility
    
    April 2008
    
    
    $
    
    450
    
    
    CP Support/Funding/Lettersof Credit
    
    
    $
    
    125
    
    
    
    $
    
    3255-year Credit Facility
    
    May 2010
    
    
    $
    
    650
    
    
    CP Support/Funding/Lettersof Credit
    
    
    $
    
    3
    (C)
    
    
    
    $
    
    647Bilateral Term Loan
    
    May 2007
    
    
    $
    
    100
    
    
    Funding
    
    
    $
    
    100
    
    
    
    $
    
    —Uncommitted BilateralAgreement
    
    N/A
    
    
    
    N/A
    
    
    Funding
    
    
    $
    
    —
    
    
    
    
    N/APSE&G:5-year Credit Facility
    
    June 2009
    
    
    $
    
    600
    
    
    CP Support/Funding/Lettersof Credit
    
    
    $
    
    327
    
    
    
    $
    
    273Uncommitted Bilateral
      Agreement
    
    N/A
    
    
    
    N/A
    
    
    Funding
    
    
    $
    
    —
    
    
    
    
    N/APSEG and Power: (A)3-year Credit Facility
    
    April 2007
    
    
    $
    
    600
    
    
    CP Support/Funding/Lettersof Credit
    
    
    $
    
    20
    (C)
    
    
    
    $
    
    580Bilateral Credit Facility
    
    Oct 2006(D)
    
    
    $
    
    100
    
    
    Funding/Lettersof Credit
    
    
    $
    
    —
    
    
    
    $
    
    100Bilateral Credit Facility
    
    Dec 2006(D)
    
    
    $
    
    100
    
    
    Funding/Lettersof Credit
    
    
    $
    
    —
    
    
    
    $
    
    100Bilateral Credit Facility
    
    Dec 2006(D)
    
    
    $
    
    150
    
    
    Funding/Lettersof Credit
    
    
    $
    
    10
    (C)
    
    
    
    $
    
    140Bilateral Credit Facility
    
    Dec 2006(D)
    
    
    $
    
    150
    
    
    Funding/Lettersof Credit
    
    
    $
    
    —
    
    
    
    $
    
    150Bilateral Credit Facility
    
    June 2007
    
    
    $
    
    200
    
    
    Funding/Lettersof Credit
    
    
    $
    
    8
    (C)
    
    
    
    $
    
    192Bilateral Credit Facility
    
    Dec 2006(D)
    
    
    $
    
    50
    
    
    Funding/Lettersof Credit
    
    
    $
    
    1
    (C)
    
    
    
    $
    
    49Bilateral Credit Facility
    
    Dec 2006(D)
    
    
    $
    
    275
    
    
    Letters of Credit
    
    
    $
    
    2
    (C)
    
    
    
    $
    
    273Power:Bilateral Credit Facility
    
    March 2010
    
    
    $
    
    100
    
    
    Funding/Lettersof Credit
    
    
    $
    
    8
    (C)
    
    
    
    $
    
    92Energy Holdings:5-year Credit Facility (B)
    
    June 2010
    
    
    $
    
    150
    
    
    Funding/Lettersof Credit
    
    
    $
    
    7
    (C)
    
    
    
    $
    
    143

(A)
    
    
    
    PSEG/Power joint and several co-borrower facilities.(B)
    
    
    
    Energy Holdings/Global/Resources joint and several co-borrower facility.(C)
    
    
    
    These amounts relate to letters of credit outstanding.(D)
    
    
    
    These facilities are expected to be replaced with a new syndicated facility in the fourth quarter of 2006.73

PSEG and PSE&G
PSEG and PSE&G believe sufficient liquidity exists to fund their short-term cash needs.
Power
As of September 30, 2006, Power had borrowed $68 million from PSEG in the form of an intercompany loan.
During the third quarter of 2006, Power’s required margin postings decreased for sales contracts entered into in the normal course of business as commodity prices declined. The required margin
  postings will fluctuate based on volatility in commodity prices. Should commodity prices rise, additional margin calls may be necessary relative to existing power sales contracts. As Power’s contract
  obligations are fulfilled, liquidity requirements are reduced. Power believes that it has sufficient liquidity to fund its short-term cash needs.
In addition, ER&T maintains agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power’s credit
  rating to below investment grade, which represents at least a two level downgrade from its current ratings, 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
Energy Holdings and its subsidiaries had $102 million in cash, including $19 million invested offshore as of September 30, 2006. In addition, as of September 30, 2006, Energy Holdings had an
  outstanding demand loan receivable from PSEG of $374 million. See External Financings—Energy Holdings below for Energy Holdings’ additional use of its excess cash.
External Financings
PSEG
On September 1, 2006, PSEG began using treasury stock to settle the exercise of stock options. Prior to September 1, 2006, PSEG had purchased shares on the open market to meet the exercise of
  stock options. As of September 30, 2006, PSEG issued approximately 121,067 shares of its common treasury stock in connection with settling stock options for approximately $5 million.
During the nine months ended September 30, 2006, PSEG issued approximately 790,825 shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Program
  for approximately $51 million.
In February 2006, PSEG redeemed $154 million of its Subordinated Debentures underlying $150 million of Enterprise Capital Trust II, Floating Rate Capital Securities and its common equity
  investment in the trust.
PSE&G
On June 23, 2006, PSE&G repaid at maturity $174 million of its Floating Rate Series A First and Refunding Mortgage Bonds.
On March 1, 2006, PSE&G repaid at maturity $148 million of its 6.75% Series UU First and Refunding Mortgage Bonds.
In September 2006, June 2006 and March 2006, PSE&G Transition Funding LLC (Transition Funding) repaid approximately $41 million, $35 million and $36 million, respectively, of its transition bonds.
74

In June 2006, PSE&G Transition Funding II LLC (Transition Funding II) repaid approximately $3 million of its transition bonds.
Power
In April 2006, Power repaid at maturity $500 million of its 6.875% Senior Notes.
Energy Holdings
In January 2006, Energy Holdings redeemed all $309 million of its 7.75% Senior Notes due in 2007.
On February 17, 2006, the maturity of the Odessa‐Ector Power Partners, L.P. (Odessa) debt was extended to December 31, 2009. Interest on the debt is based on a spread (currently 2.25%) above
  LIBOR. On September 29, 2006, an interest rate swap took effect which converts the floating LIBOR interest rate on approximately 80% of Odessa’s debt to a fixed rate of 5.4275% through December 31,
  2009.
On October 23, 2006, Energy Holdings redeemed $300 million of its $507 million outstanding 8.625% Senior Notes due in 2008. Additionally, on September 20, 2006, Energy Holdings made a cash
  distribution to PSEG of $425 million in the form of a return of capital.
During
  the first nine months of 2006, Energy Holdings repaid approximately $37 million
  of non-recourse debt, of which $30 million was paid by Global, primarily related
  to SAESA and TIE, $5 million by Resources and $2 million by EGDC.
Contractual Obligations
PSEG, PSE&G, Power and Energy Holdings
As of September 30, 2006, contractual cash obligations and other commercial commitments have not changed significantly from those reported in the Capital Requirements section of Management’s
  Discussion and Analysis included in the 2005 Annual Report on Form 10K, except for the debt redemptions discussed above in External Financings.
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 can refuse to advance loans in the event of a material
  adverse change in the borrower’s business or financial condition.
As explained in more detail below, these credit agreements may 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.
PSEG
Financial covenants contained in PSEG’s credit facilities include a ratio of debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including
  commercial paper and loans, certain letters of credit and similar instruments) to total capitalization (including preferred securities outstanding) covenant. This covenant requires that at the end of any
  quarterly financial period, such ratio not be more than 70.0%. As of September 30, 2006, PSEG’s ratio of debt to capitalization (as defined above) was 52.8%.
75

PSE&G
Financial covenants contained in PSE&G’s credit facilities include a ratio of long-term debt (excluding securitization debt, long-term debt maturing within one year and short-term debt) to total
  capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio will not be more than 65.0%. As of September 30, 2006, PSE&G’s ratio of long-term debt to total
  capitalization (as defined above) was 45.3%.
In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of
  earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of September 30, 2006, PSE&G’s Mortgage coverage ratio was 4.5 to 1 and the
  Mortgage would permit up to approximately $1.9 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 70.0% debt to total
  capitalization covenant for PSEG (calculated as set forth above) and a 65.0% debt to total capitalization covenant for Power. The Power ratio is the same debt to total capitalization calculation as set forth
  above for PSEG except common equity is adjusted for the $986 million Basis Adjustment (see Condensed Consolidated Balance Sheets). This covenant requires that at the end of any quarterly financial
  period, such ratio will not exceed 65.0%. As of September 30, 2006, Power’s ratio of debt to total capitalization (as defined above) was 39.3%.
Energy Holdings
Energy Holdings’ revolving credit agreement has a covenant requiring the ratio of Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) to fixed charges to be greater than or
  equal to 1.75. As of September 30, 2006, Energy Holdings’ coverage of this covenant was 3.94. Additionally, Energy Holdings must maintain a ratio of net debt (recourse debt offset by funds loaned to
  PSEG) to EBITDA of less than 5.25. As of September 30, 2006, Energy Holdings’ ratio under this covenant was 2.11. Energy Holdings is a co-borrower under this facility with Global and Resources, which
  are joint and several obligors. The terms of the agreement include a pledge of Energy Holdings’ membership interest in Global, restrictions on the use of proceeds related to material sales of assets and the
  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
On September 15, 2006, following the termination of the Merger Agreement, credit ratings remained unchanged as shown in the table below. Standard & Poor’s (S&P) affirmed its ‘BBB’ corporate credit
  rating for PSEG, Power, and PSE&G. S&P revised its outlook from watch developing to negative. Moody’s Investors Service (Moody’s) affirmed its credit ratings for PSEG and PSE&G while revising the
  outlooks from stable to negative. The ratings and outlooks for Power and Energy Holdings were unchanged by Moody’s. Fitch Ratings (Fitch) announced there would be no immediate impact on ratings
  and outlooks for PSEG and its subsidiaries. The agencies noted that the ratings below are predicated on continued improvement in financial metrics, specifically operating cash flows and ongoing
  deleveraging, as well as continued strong operating performance from Power’s generating units and reasonable outcomes to PSE&G’s pending electric and gas rate cases.
76

If the rating agencies lower or withdraw the credit ratings, such revisions may adversely affect the market price of PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities and serve to materially
  increase those companies’ cost of capital and limit their access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). 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 agency should be evaluated
  independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.
Moody’s (A)
    
    S&P (B)
    
    Fitch (C)PSEG:Outlook
    
    Neg
    
    Neg
    
    PosPreferred Securities
    
    Baa3
    
    BB+
    
    BBB‐Commercial Paper
    
    P2
    
    A3
    
    F2Senior Unsecured Debt
    
    Baa2
    
    BBB‐
    
    BBBPSE&G:Outlook
    
    Neg
    
    Neg
    
    StableMortgage Bonds
    
    A3
    
    A‐
    
    APreferred Securities
    
    Baa3
    
    BB+
    
    BBB+Commercial Paper
    
    P2
    
    A3
    
    F2Power:Outlook
    
    Stable
    
    Neg
    
    PosSenior Notes
    
    Baa1
    
    BBB
    
    BBBEnergy Holdings:Outlook
    
    Neg
    
    Neg
    
    NegSenior Notes
    
    Ba3
    
    BB‐
    
    BB

(A)
    
    
    
    Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.(B)
    
    
    
    S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.(C)
    
    
    
    Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F1 (highest) to D (lowest) for short-term securities.Other Comprehensive Income (OCI)
PSEG, Power and Energy Holdings
For the nine months ended September 30, 2006, PSEG, Power and Energy Holdings had OCI of $576 million, $383 million and $192 million, respectively, due primarily to a reduction in the net
  unrealized losses on derivatives accounted for as hedges in accordance with SFAS 133 at Power and foreign currency translation adjustments at Energy Holdings.
During the nine months ended September 30, 2006, Power’s Accumulated Other Comprehensive Loss (OCL) decreased from $487 million to $104 million. The primary cause was a decrease of
  approximately $374 million related to energy and related contracts that qualify for hedge accounting that were entered into by Power in the normal course of business. During the nine months ended
  September 30, 2006, the decrease in gas and electric prices resulted in a reduction in unrealized losses on many of those contracts, which are recorded in OCL.
During the nine months ended September 30, 2006, Energy Holdings’ Accumulated Other Comprehensive (Loss) Income increased from $(110) million to $82 million. The primary cause was the
  realization of losses on Brazilian currency as a result of the sale of RGE.
77

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, 2005, with the exception of the indefinite postponement of the $30 million Electroandes hydro-expansion project at Energy Holdings which was planned
  for 2006 and 2007. For further information see Note 5. Commitments and Contingent Liabilities of the Notes.
PSE&G
During the nine months ended September 30, 2006, PSE&G made approximately $392 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $392 million
  excludes approximately $26 million spent on cost of removal.
Power
During the nine months ended September 30, 2006, Power made approximately $233 million of capital expenditures (excluding $83 million for nuclear fuel), primarily related to various projects at
  Fossil and Nuclear.
Energy Holdings
During the nine months ended September 30, 2006, Energy Holdings incurred approximately $37 million of capital expenditures, of which approximately $18 million related to SAESA.
OFF-BALANCE SHEET ARRANGEMENTS
PSEG, Power and Energy Holdings
For
  a description of off-balance sheet arrangements, see Management’s Discussion
  and Analysis in the 2005 Annual Report on Form 10-K. PSEG’s pro rata share
  of the debt appearing on the consolidated financial statements of companies
  for which Global accounts under the equity method of investment was approximately
  $463 million as of September 30, 2006 as compared to $577 million as of December
  31, 2005. The decrease related principally to Energy Holdings’ sale of
  RGE in June 2006 and the change since May 2006 in Energy Holdings’ accounting
  for Prisma from the equity method to full consolidation. There has been no material
  change in the amount of Resources’ leveraged lease investments since December
  31, 2005. See Note 5. Commitments and Contingent Obligations of the Notes for
  an update of Power’s guarantees related to certain of its energy trading
  activities and Energy Holdings’ guarantees of certain obligations of its
  subsidiaries or affiliates related to certain projects.
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.
78

ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURESABOUT MARKET RISK
PSEG, PSE&G, Power and Energy Holdings
The market risk inherent in PSEG’s, PSE&G’s, Power’s and Energy Holdings’ market-risk sensitive instruments and positions is the potential loss arising from adverse changes in foreign currency
  exchange rates, commodity prices, equity security prices and interest rates as discussed in the Notes to Condensed Consolidated Financial Statements (Notes). It is the policy of each entity to use derivatives
  to manage risk consistent with its respective business plans and prudent practices. PSEG, PSE&G, Power and Energy Holdings have a Risk Management Committee (RMC) comprised of executive officers
  who utilize an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices.
Additionally, PSEG, PSE&G, Power and Energy Holdings are exposed to counterparty credit losses in the event of non-performance or non-payment. PSEG has a credit management process, which is
  used to assess, monitor and mitigate counterparty exposure for PSEG and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact
  on PSEG and its subsidiaries’ financial condition, results of operations or net cash flows.
Except as discussed below, there were no material changes from the disclosures in the Annual Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31,
  2005 or Quarterly Reports on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006.
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 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. These contracts, in conjunction with demand obligations, help reduce risk and 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.
Under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (SFAS 133), changes in the fair value of qualifying cash flow hedge transactions are recorded in
  Accumulated Other Comprehensive Loss (OCL), and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet
  hedge criteria under SFAS 133 and the ineffective portion of hedge contracts are recognized in earnings currently. Additionally, changes in the fair value attributable to fair value hedges are similarly
  recognized in earnings.
Many non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133 and are accounted for upon settlement.
Trading
Power maintains a strategy of entering into trading positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in
  physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. In
  addition, Power has non-asset based trading activities, which have significantly decreased over the
79

past year. These contracts also involve financial transactions including swaps, options and futures. These activities are marked to market in accordance with SFAS 133 with gains and losses recognized in
  earnings.
Value-at-Risk (VaR) Models
Power
Power uses VaR models to assess the market risk of its commodity businesses. The portfolio VaR model for Power includes its owned generation and physical contracts, as well as fixed price sales
  requirements, load requirements and financial derivative instruments. VaR represents the potential gains or losses, under normal market conditions, for instruments or portfolios due to changes in market
  factors, for a specified time period and confidence level. Power estimates VaR across its commodity businesses.
Power manages its exposure at the portfolio level. Its portfolio consists of owned generation, load-serving contracts (both gas and electric), fuel supply contracts and energy derivatives designed to
  manage the risk around generation and load. While Power manages its risk at the portfolio level, it also monitors separately the risk of its trading activities and its hedges. Non-trading mark-to-market
  (MTM) VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The MTM derivatives that are not hedges are included in the trading VaR.
The VaR models used by Power are variance/covariance models adjusted for the delta of positions with a 95% one-tailed confidence level and a one-day holding period for the MTM trading and non-
  trading activities and a 95% one-tailed confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods, whereas Power actively
  manages its portfolio.
As of September 30, 2006 and December 31, 2005, trading VaR was less than $1 million.
Trading VaR
    
    Non-TradingMTM VaR(Millions)For the Quarter Ended September 30, 200695% Confidence Level, One-Day Holding Period, One-Tailed:Period End
    
    
    $
    
    —
    
    
    
    $
    
    49Average for the Period
    
    
    $
    
    —
    
    
    
    $
    
    51High
    
    
    $
    
    —
    
    
    
    $
    
    69Low
    
    
    $
    
    —
    
    
    
    $
    
    4099% Confidence Level, One-Day Holding Period, Two-Tailed:Period End
    
    
    $
    
    —
    
    
    
    $
    
    76Average for the Period
    
    
    $
    
    —
    
    
    
    $
    
    79High
    
    
    $
    
    —
    
    
    
    $
    
    108Low
    
    
    $
    
    —
    
    
    
    $
    
    63Other 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
  and nine months ended September 30, 2006. Normal operations and hedging activities represent the marketing of electricity available from Power’s owned or contracted generation sold into the wholesale
  market. As the information in this table highlights, MTM activities represent a small portion of the total Operating Revenues for Power. Activities accounted for under the accrual method, including normal
  purchases and sales, account for the majority of the revenue. The MTM activities reported here are those relating to changes in fair value due to external movement in prices.
80

Operating RevenuesFor the Quarter Ended September 30, 2006
NormalOperations andHedging (A)
    
    Trading
    
    Total(Millions)MTM Activities:Unrealized MTM Gains (Losses)Changes in Fair Value of Open Positions
    
    
    $
    
    10
    
    
    
    $
    
    2
    
    
    
    $
    
    12Origination Unrealized Gain at Inception
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —Changes in Valuation Techniques and Assumptions
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —Realization at Settlement of Contracts
    
    
    
    (4
    )
    
    
    
    
    —
    
    
    
    
    (4
    )Total Change in Unrealized Fair Value
    
    
    
    6
    
    
    
    
    2
    
    
    
    
    8Realized Net Settlement of Transactions Subject to MTM
    
    
    
    4
    
    
    
    
    1
    
    
    
    
    5Broker Fees and Other Related Expenses
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —Net MTM Gains
    
    
    
    10
    
    
    
    
    3
    
    
    
    
    13Accrual ActivitiesAccrual Activities—Revenue, Including Hedge
    
    
    
    1,476
    
    
    
    
    —
    
    
    
    
    1,476Reclassifications
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —Total Operating Revenues
    
    
    $
    
    1,486
    
    
    
    $
    
    3
    
    
    
    $
    
    1,489Operating RevenuesFor the Nine Months Ended September 30, 2006
NormalOperations andHedging (A)
    
    Trading
    
    Total(Millions)MTM Activities:Unrealized MTM Gains (Losses)Changes in Fair Value of Open Positions
    
    
    $
    
    7
    
    
    
    $
    
    25
    
    
    
    $
    
    32Origination Unrealized Gain at Inception
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —Changes in Valuation Techniques and Assumptions
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —Realization at Settlement of Contracts
    
    
    
    (26
    )
    
    
    
    
    (30
    )
    
    
    
    
    (56
    )Total Change in Unrealized Fair Value
    
    
    
    (19
    )
    
    
    
    
    (5
    )
    
    
    
    
    (24
    )Realized Net Settlement of Transactions Subject to MTM
    
    
    
    26
    
    
    
    
    31
    
    
    
    
    57Broker Fees and Other Related Expenses
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —Net MTM Gains
    
    
    
    7
    
    
    
    
    26
    
    
    
    
    33Accrual ActivitiesAccrual Activities—Revenue, Including Hedge
    
    
    
    4,558
    
    
    
    
    —
    
    
    
    
    4,558Reclassifications
    
    
    
    —
    
    
    
    
    —
    
    
    
    
    —Total Operating Revenues
    
    
    $
    
    4,565
    
    
    
    $
    
    26
    
    
    
    $
    
    4,591

(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
  offset 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.
81

Energy Contract Net Assets/LiabilitiesAs of September 30, 2006
NormalOperationsand Hedging
    
    Trading
    
    Total(Millions)MTM Energy AssetsCurrent Assets
    
    
    $
    
    56
    
    
    
    $
    
    37
    
    
    
    $
    
    93Noncurrent Assets
    
    
    
    27
    
    
    
    
    11
    
    
    
    
    38Total MTM Energy Assets
    
    
    
    83
    
    
    
    
    48
    
    
    
    
    131MTM Energy LiabilitiesCurrent Liabilities
    
    
    $
    
    (374
    )
    
    
    
    $
    
    (42
    )
    
    
    
    $
    
    (416
    )Noncurrent Liabilities
    
    
    
    (188
    )
    
    
    
    
    (14
    )
    
    
    
    
    (202
    )Total MTM Current Liabilities
    
    
    
    (562
    )
    
    
    
    
    (56
    )
    
    
    
    
    (618
    )Total MTM Energy Contract Net Liabilities
    
    
    $
    
    (479
    )
    
    
    
    $
    
    (8
    )
    
    
    
    $
    
    (487
    )The following table presents the maturity of net fair value of MTM energy trading contracts.
Maturity of Net Fair Value of MTM Energy Trading ContractsAs of September 30, 2006
Maturities within2006
    
    2007
    
    2008-2009
    
    Total(Millions)Trading
    
    
    $
    
    (4
    )
    
    
    
    $
    
    (6
    )
    
    
    
    $
    
    2
    
    
    
    $
    
    (8
    )Normal Operations and Hedging
    
    
    
    (117
    )
    
    
    
    
    (239
    )
    
    
    
    
    (123
    )
    
    
    
    
    (479
    )Total Net Unrealized Losses on MTM Contracts
    
    
    $
    
    (121
    )
    
    
    
    $
    
    (245
    )
    
    
    
    $
    
    (121
    )
    
    
    
    $
    
    (487
    )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 OCL, a separate component of equity. Power uses forward sale and purchase contracts, swaps and firm transmission rights
  (FTRs) contracts to hedge forecasted energy sales from its generation stations and its contracted supply obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel
  to meet its fuel purchase requirements for generation. PSEG, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage
  interest rate risk through the use of fixed rate debt, floating rate debt and interest rate derivatives. The table also provides an estimate of the losses that are expected to be reclassified out of OCL and into
  earnings over the next 12 months.
Cash Flow Hedges Included in Accumulated Other Comprehensive LossAs of September 30, 2006
AccumulatedOtherComprehensiveLoss
    
    Portion Expectedto be Reclassifiedin next 12 months(Millions)Commodities
    
    
    $
    
    (183
    )
    
    
    
    $
    
    (102
    )Interest Rates
    
    
    
    (9
    )
    
    
    
    
    (1
    )Foreign Currency
    
    
    
    —
    
    
    
    
    —Net Cash Flow Hedge Loss
    
    
    $
    
    (192
    )
    
    
    
    $
    
    (103
    )82

Power
Credit Risk
The following table provides information on Power’s credit exposure, net of collateral, as of September 30, 2006. Credit exposure is defined as any positive results of netting accounts
  receivable/accounts payable and the forward value on open positions. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to
  individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties.
Schedule of Credit Risk Exposure on Energy Contracts Net AssetsAs of September 30, 2006
Rating
    
    CurrentExposure
    
    SecuritiesHeld asCollateral
    
    NetExposure
    
    NumberCounterparties>10%
    
    NetExposure ofCounterparties>10%(Millions)
    
    
    
    
    
    (Millions)Investment Grade—External Rating
    
    
    $
    
    275
    
    
    
    $
    
    59
    
    
    
    $
    
    274
    
    
    
    
    2
    (A)
    
    
    
    $
    
    144Non-Investment Grade—External Rating
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    1
    
    
    
    
    —
    
    
    
    
    —Investment Grade—No External Rating
    
    
    
    9
    
    
    
    
    —
    
    
    
    
    9
    
    
    
    
    —
    
    
    
    
    —Non-Investment Grade—No External Rating
    
    
    
    21
    
    
    
    
    —
    
    
    
    
    21
    
    
    
    
    —
    
    
    
    
    —Total
    
    
    $
    
    306
    
    
    
    $
    
    59
    
    
    
    $
    
    305
    
    
    
    
    2
    
    
    
    $
    
    144

(A)
    
    
    
    Counterparty is PSE&G.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. As of September 30, 2006, Power had 129 active counterparties.
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 information required to be
  disclosed is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that material information relating to each company, including their respective
  consolidated subsidiaries, is accumulated and communicated to the respective company’s management, including the Chief Executive Officer and Chief Financial Officer of each company by others within
  those entities to allow timely decisions regarding required disclosure. 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 effectiveness of the disclosure controls and procedures as of September 30, 2006 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
PSEG, PSE&G, Power and Energy Holdings continually review their respective disclosure controls and procedures and make changes, as necessary, to ensure the quality of their financial reporting.
  However, there have been no changes in internal control over financial reporting that occurred during the third quarter of 2006 that have materially affected, or are reasonably likely to materially affect,
  each registrant’s internal control over financial reporting.
83

PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Certain information reported under Item 3 of Part I of the 2005 Annual Report on Form 10-K and under Item 1 of Part II of the Quarterly Reports on Form 10-Q for the quarters ended March 31,
  2006 and June 30, 2006 is updated below.
PSEG, PSE&G, Power and Energy Holdings
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
        28. (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
        28. (Power) PSE&G’s MGP Remediation Program instituted by NJDEP’s
        Coal Gasification Facility Sites letter dated March 25, 1988.(3)
    
    Page
        34. (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
        36. (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
        38. (Energy Holdings) Dhofar Power Company SAOC v. Ministry of Housing,
        Electricity and Water (Sultanate of Oman), ICC Reference EXP/233.(6)
    
    Pages
      57, 59 and 90. (PSE&G) BPU proceeding relating to Electric Distribution
      financial review, Docket No. ER02050303.(7)
    
    Pages
      57, 59 and 91. (PSE&G) PSE&G Petition for increase of gas base rates
      filed with BPU on September 30, 2005, Docket No. GR05100845.(8)
    
    Pages
      59 and 91. (PSE&G) PSE&G’s BGSS Commodity filing with the
      BPU on May 28, 2004, Docket No. GR04050390.(9)
    
    Page
        85. (PSEG, PSE&G Power and Energy Holdings) BPU proceeding on August
        1, 2005 relating to ratepayer protections due to repeal of PUHCA under
        the Energy Policy Act of 2005. Docket No. AX05070641.(10)
    
    Page
        86. (PSEG, PSE&G and Power) PJM Interconnection, L.L.C., Schedule
        12 (Cost Allocation) filing with FERC, Docket No. ER06-456-000.(11)
    
    Page
        86. (PSEG, PSE&G and Power) FERC proceedings with MISO and PJM relating
        to RTOR and SECA methodology, Docket No. ER05-6-000 et al.(12)
    
    Page
        86. (PSEG, PSE&G and Power) PJM Reliability Pricing Model filed with
        FERC on August 31, 2005, Docket Nos. ER05-1410-000 and EL05-148-000.(13)
    
    Page
        87. (PSEG, PSE&G and Power) FERC proceeding relating to PJM Long-Term
        Transmission Rate Design, Docket No. EL05-121-000.(14)
    
    Page
        87. (PSEG, PSE&G and Power) Notice of Inquiry issued by FERC on September
        16, 2005 to prevent undue discrimination and preference in the provisions
        of transmission service. Docket No. RM05-25-000.(15)
    
    Page
        88. (Power) PJM Interconnection, L.L.C. filing with FERC on November 2,
        2004, Docket No. EL03-236-003 to amend Tariff and Operating Agreement
        to request Reliability Must-Run (RMR) compensation.(16)
    
    Page
        88. (PSE&G) Neptune Regional Transmission System, LLC v. PJM Interconnection,
        L.L.C. complaint filed with FERC on December 21, 2004, Docket No. EL05-48-00,
        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.(17)
    
    Page
        89. (PSE&G) JCP&L v. ACE, et al. complaint filed with FERC on
        December 30, 2004, Docket No. EL05-50-000, seeking to terminate its construction
        obligations under the LDV Agreement.84

(18)
    
    Page
        91. (PSE&G) Cost Recovery filing with the BPU on July 1, 2004, Docket
        No. EE04070718.(19)
    
    Page
      92. (PSE&G and Power) BPU review of annual procurement process for BGS,
      Docket No. EO06020119.(20)
    
    Page 93. (PSE&G and Power) EPA request for a Remedial Investigation/Feasibility
        Study on Berry's Creek Study Area.(21)
    
    Page 93. (PSE&G and Power) EPA notice to potentially responsible parties
        with respect to contamination in the Newark Bay Study Area.ITEM 5. OTHER INFORMATION
Certain information reported under the 2005 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006 is updated below.
  Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2005 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarters ended
  March 31, 2006 and June 30, 2006. References are to the related pages on the Form 10-K and Form 10-Q as printed and distributed.
Federal Regulation
Public Utility Holding Company Act
PSEG, PSE&G, Power and Energy Holdings
2005 Form 10-K, Page 15 and June 30, 2006 Form 10-Q, page 85. The Energy Policy Act, which became law on August 8, 2005, repealed the Public Utility Holding Company Act of 1935 (PUHCA)
  as of February 8, 2006 and established PUHCA 2005. FERC has promulgated rules that would waive the accounting and reporting obligations of PUHCA 2005 for PSEG and its subsidiaries. Thus, PSEG,
  PSE&G, Power and Energy Holdings do not expect PUHCA 2005 to materially affect their respective businesses, prospects or properties. For additional information on the impact of PUHCA repeal, see
  State Regulation.
FERC
PSEG, PSE&G, Power and Energy Holdings
Market Power
2005 Form 10-K, Page 16, March 31, 2006 Form 10-Q, Page 78 and June 30, 2006 Form 10-Q, Page 85. On February 28, 2006, PSEG Power Connecticut LLC (Power Connecticut) filed its triennial
  updated market power report with FERC. On October 11, 2006, FERC issued an order accepting Power Connecticut’s triennial market power report. PSE&G and ER&T are required to file their respective
  triennial updated market power reports with FERC by November 30, 2006.
On May 19, 2006, FERC issued a Notice of Proposed Rulemaking (NOPR) concerning the standards to be used by FERC in granting market-based rate authority. The proposed regulations would
  adopt, in most respects, the FERC’s current standards. In its NOPR, FERC suggests certain changes, such as in the areas of cost-based market power mitigation, modifications to the horizontal (generation)
  market power screens, and clarifications to existing vertical market power screens. On September 20, 2006, PSE&G and Power submitted comments in this NOPR proceeding. The outcome of this proceeding
  and its impact on PSEG, PSE&G, Power and Energy Holdings cannot be predicted at this time, but Power does not expect the new rules to disqualify its market-based rate authority. However, no assurances
  can be given.
85

PSEG, PSE&G and Power
PJM Schedule 12 Filing
March 31, 2006 Form 10-Q, Page 78 and June 30, 2006 Form 10-Q, Page 85. On July 19, 2006, FERC consolidated PJM’s January 5, 2006 and May 4, 2006 filings that propose to allocate the costs of
  new transmission projects that PJM has directed to be built through its Regional Transmission Expansion Plan (RTEP) process. These consolidated proceedings are currently in settlement before a FERC
  Administrative Law Judge (ALJ). PSEG is actively participating in this proceeding, as the cost allocation methodology used by PJM may result in a disproportionate allocation of costs to load in the eastern
  portion of PJM. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding at this time.
On July 21, 2006, PJM submitted to FERC a further proposal to allocate the costs of an additional group of new transmission projects that PJM has directed be built through its RTEP. The July 21,
  2006 filing includes allocations for the $850 million, 200-mile 500 kV Loudon transmission line which runs from Allegheny Power’s service territory, through West Virginia to Northern Virginia, as well as
  many other transmission projects in the PJM region. PJM has used the same allocation methodology to identify which load should pay for these new transmission projects through regulated transmission
  rates. PSEG believes that this allocation methodology results in a disproportionate allocation of costs to load in the eastern portion of PJM. Motions to consolidate this proceeding with the filings made in
  January and May are currently pending at FERC.
Assuming continued pass-through of transmission charges to retail customers, neither Power nor PSE&G are expected to be impacted by the allocation of Schedule 12 charges.
Regional through and out rates (RTOR)
2005 Form 10-K, Page 17, March 31, 2006 Form 10-Q, Page 78 and June 30, 2006 Form 10-Q, Page 86. A trial-type hearing, encompassing a review of the actual amount of lost revenues to be
  recovered via the Seams Elimination Charge/Cost Adjustment/Assignment (SECA) mechanism, was held in May 2006. On August 10, 2006, the ALJ issued an initial decision finding that the rate design for
  the recovery of SECA charges is flawed, and that the SECA rate charges are therefore unjust, unreasonable and unduly discriminatory. Exceptions to the initial decision were filed September 11, 2006 and
  reply briefs to the exceptions taken were filed October 10, 2006. The FERC has not yet issued an order on review of the ALJ initial decision. In addition, in March 2006, PSE&G and Power entered into a
  settlement with a limited group of parties in PJM, which settlement was certified to FERC, under which the parties have agreed to pay and collect reductions of SECA revenues. On October 12, 2006, the
  limited settlement agreement was expanded to include additional parties. The FERC has not yet acted to approve either the March or the October SECA settlements. Due to the uncertainty of this
  proceeding, PSE&G has continued to defer the collection of any SECA revenues on its books. At the present time, it is difficult to determine whether, and to what extent, the SECA initial decision, which is
  currently being reviewed by FERC, will have an impact on PSEG, PSE&G and Power.
PJM Reliability Pricing Model (RPM)
2005 Form 10-K, Page 17, March 31, 2006 Form 10-Q, Page 79 and June 30, 2006 Form 10-Q, Page 86. On August 31, 2005, PJM filed its RPM with FERC. The RPM constitutes a locational
  installed capacity market design for the PJM region, including a forward auction for installed capacity priced according to a downward-sloping demand curve, recognition of locational value and a
  transitional implementation of the market design. FERC issued an order on April 20, 2006 that accepted most of the core concepts of the RPM filing with an implementation date of June 1, 2007. The April
  20, 2006 order set certain details of the filing for paper hearing and technical conference procedures including the slope of the demand curve and the mechanism for identification of the locational capacity
  zones. Such hearing and technical conference procedures have now been completed. Also, commencing in June 2006, settlement discussions mediated by a FERC ALJ commenced at the request of certain
  intervenors. A final settlement was filed with FERC on September 29, 2006 with a requested approval date of no later than December 22, 2006. FERC’s adoption of either the original PJM RPM
  mechanism proposed in its August 2005 filing or the settlement proposal of September 2006
86

would be expected to have a favorable impact on generation facilities located in constrained locational zones. The final revenue impact of either of the two proposals on Power, particularly over an extended
  time period, is difficult to quantify. In response to both PJM’s original filing, and the proposed settlement, PSE&G and Power have filed comments supporting the basic structural elements of the RPM
  proposal but nonetheless have requested certain modifications which, in their view, would better promote the adequacy of generation reserves on a cost-effective basis. The April 20, 2006 order remains
  subject to rehearing requests filed by several parties. Given the pending rehearing requests, the pending settlement agreement, and likelihood of eventual judicial appeals, PSEG, PSE&G and Power are
  unable to predict the outcome of this proceeding.
PJM Long-Term Transmission Rate Design
2005 Form 10-K, Page 17 and June 30, 2006 Form 10-Q, Page 86.On July 13, 2006, a FERC ALJ issued a decision concluding that the existing PJM modified zonal rate design for existing facilities
  has been shown to be unjust and unreasonable, and should be replaced with a postage stamp rate design for such facilities to be effective April 1, 2006. To mitigate rate impacts, the ALJ has determined that
  the rate design should be phased in, so that no customer receives greater than a 10% annual rate increase. The ALJ also determined that the existing process for allocating costs of new transmission projects
  pursuant to Schedule 6 of PJM’s Operating Agreement and Schedule 12 of the PJM Tariff was just and reasonable. Briefs on exceptions to the ALJ’s initial decision and reply briefs have been filed in this
  proceeding challenging the decision to find the existing rate design unjust and unreasonable, the appropriateness of imposing a postage stamp rate design, the decision as to the appropriateness of applying
  the current Schedule 6 and Schedule 12 process for allocating costs of new transmission projects and the phase-in of the new rate design. FERC has not yet issued a decision on review of the ALJ’s initial
  decision. Should FERC ultimately approve this postage stamp rate design on review of the ALJ’s initial decision, or adopt one or a combination of the alternative rate designs proposed, PSEG’s, PSE&G’s or
  Power’s results of operations could be adversely impacted. It is not possible to predict the outcome of this proceeding at this time.
FERC Order No. 888 Reform
2005 Form 10-K, Page 18 and June 30, 2006 Form 10-Q, Page 87. On May 18, 2006, FERC issued a NOPR seeking comments on whether reforms are needed to the protections that FERC
  established in its Order No. 888 in order to prevent undue discrimination and preference in the provision of transmission service. FERC’s NOPR solicits input from the industry as to whether it should
  revise the pro forma Open Access Transmission Tariff. Order No. 888 established this tariff to govern the terms and conditions under which transmission owners must provide transmission service to all
  eligible customers. The NOPR addresses issues such as transmission planning, cost allocation issues for transmission projects and re-dispatch. Comments on the NOPR were filed in August 2006 and reply
  comments were filed in September 2006. Moreover, a technical conference on these issues was held at FERC on October 12, 2006. FERC is expected to issue a Final Rule by the end of the year. Any
  significant changes from the current Order 888 rules governing transmission access or transmission service may impact PSEG, PSE&G and Power, but it is difficult to predict the outcome of this proceeding at
  this time.
Locational Installed Capacity (LICAP) Market Settlement in New England
2005 Form 10-K, Page 18 and June 30, 2006 Form 10-Q, Page 87. On January 31, 2006, certain interested market participants in New England agreed to a settlement in principle of litigation
  regarding the design of the region’s market for installed capacity, which would institute a transition period leading to the implementation of a new market design for capacity as early as 2010. Commencing
  in December 2006, all generators in New England would begin to receive fixed capacity payments that escalate gradually over the transition period. RMR contracts, such as Power’s, would continue to be
  effective until the implementation of the new market design. The new market design would consist of a forward auction for installed capacity that is intended to recognize the locational value of generators
  on the system, and contains incentive mechanisms to encourage generator availability during generation shortages. During the transition period, these payments are expected to benefit Power’s Bridgeport
  Harbor 2 plant. The final version of the settlement was filed with FERC on March 6, 2006 and was
87

approved by order dated June 16, 2006 finding that, as a package, the settlement represents a just and reasonable outcome. The settlement was contested by certain parties and it is anticipated that rehearing
  of the June 16, 2006 order will be sought. PSEG and Power are unable to predict the outcome of this proceeding.
Transmission Infrastructure
On September 8, 2006, PJM filed with FERC a proposal that would significantly modify its regional transmission planning process for economic transmission planning. Currently, the PJM RTEP
  identifies transmission that is needed to address reliability and operational performance needs of the PJM region, as well as historic unhedgeable congestion that exceeds certain thresholds and for which a
  market response has not been forthcoming. The PJM proposal seeks to expand the economic portion of the RTEP by forecasting economic congestion over its transmission planning horizon, which, in 2006,
  PJM modified from five to 15 years. PSE&G and Power filed a protest to the PJM proposal requesting that FERC reject PJM’s proposal or set it for hearing. If accepted without modification, the PJM
  proposal may result in the establishment of a preference for rate-based transmission solutions to address congestion, as opposed to reliance on private investment and competitive non-transmission market
  solutions. The outcome of this proceeding and the impact on PSEG, PSE&G and Power cannot be predicted at this time.
On August 8, 2006, the U.S. Department of Energy (DOE) issued a National Electric Transmission Congestion Study (Congestion Study), as directed by Congress in the Energy Policy Act (EP Act).
  This Congestion Study identified two areas in the United States as “critical congestion areas;” one of the areas is the region between New York and Washington, D.C. Under the EP Act, the DOE has the
  ability to designate transmission corridors in these “critical congestion areas,” to which FERC back-stop transmission siting authority will attach. Thus, corridor designation may facilitate the construction of
  rate-based transmission projects to address congestion in these corridors. The DOE has not yet designated any transmission corridors as a result of this Congestion Study but will likely do so by the end of
  this year. PSE&G and Power filed comments to the Congestion Study, in which they contended that the Congestion Study contained several analytical flaws. PSEG, PSE&G and Power are unable to predict the
  outcome of this proceeding at this time.
Power
RMR Status
PJM
2005 Form 10-K, Page 18 and June 30, 2006 Form 10-Q, Page 88.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 for the Sewaren 1, 2, 3 and 4 and Hudson 1 units. A detailed settlement was filed with FERC on September 23, 2005 that permits Power to recover annual fixed costs of approximately $19
  million and $14.5 million for the Sewaren and Hudson units, respectively, plus reimbursements of Power’s expenditures in connection with certain construction at the units that are necessary to maintain
  reliability, offset by certain revenues earned in PJM’s energy market. FERC accepted this settlement retroactive to February 24, 2005. On March 28, 2006, Power filed a refund report with FERC pursuant
  to which Power refunded $11 million to PJM, although most of this refund related to the timing of payments under the settlement agreement and thus will be repaid to Power, with carrying charges, at a
  later date. FERC did not issue a public notice requesting comments on the report and no party has made any objections or other comments with respect to the report. On October 2, 2006, Power provided
  notice to PJM that it may be required to deactivate Hudson Unit 2 if an agreement is not reached with environmental regulators regarding the unit’s satisfaction of emissions reduction requirements that
  would allow it to continue to operate after December 31, 2006. For additional information, see Note 5. Commitments and Contingencies of the Notes.
Neptune Complaint Proceeding
2005 Form 10-K, Page 19 and June 30, 2006 Form 10-Q, Page 88. On December 21, 2004, Neptune filed a complaint with FERC against PJM. Neptune is directly interconnected to the
88

transmission system of FirstEnergy Corporation (FirstEnergy), but upgrades to the PSE&G transmission system are also required to move power across the grid. In its complaint, Neptune alleged that PJM
  impermissibly conducted an interconnection re-study triggered by generator retirements in PJM, which had the effect of increasing Neptune’s cost exposure for network upgrades. On February 10, 2005,
  FERC granted Neptune’s complaint against PJM and then denied rehearing on June 24, 2005. As a result of these orders, Neptune’s interconnection cost responsibility was capped at a level of
  approximately $6 million, and recovery of the remaining $20 million in interconnection costs remains an issue, with potential allocation to PSE&G’s and FirstEnergy’s customers.
On August 15, 2005, PSE&G sought judicial review of FERC’s orders in the U.S. Circuit Court of Appeals. Two additional petitioners also sought judicial review of these orders, and the BPU and Rate
  Payer Advocate (RPA) have intervened in the case. Initial briefs and reply briefs in the case have been filed. The parties have also moved to hold the appeal in abeyance, as the costs at issue in this case are
  now the subject of currently-pending settlement discussions in the PJM Schedule 12 Filing proceeding, discussed above. PSE&G cannot at this time predict the outcome of this appeal.
PSE&G
LDV Complaint Proceeding
June 30, 2006 Form 10-Q, Page 89.On December 30, 2004, Jersey Central Power & Light Company (JCP&L) filed a complaint at FERC against the other four signatories to the Lower Delaware Valley
  (LDV) Transmission System Agreement, including PSE&G. The LDV Agreement, governing the construction of, and investment in, certain 500 kV transmission facilities in New Jersey, was entered into by
  the parties in 1977 and remains in effect until 2027. In the FERC complaint proceeding, JCP&L seeks to terminate its payment obligations to the other contract signatories. PSE&G receives approximately $2.7
  million annually from JCP&L under the LDV Agreement and its related agreements, the term of which does not expire until 2027. On May 6, 2005, FERC issued an order dismissing JCP&L’s complaint.
  Subsequently, in a rehearing order issued December 2, 2005, FERC set certain issues raised by JCP&L for hearing. The matter is now in litigation, with a hearing scheduled to take place in November 2006
  and an initial decision to be rendered by the ALJ in March 2007. In this litigation, JCP&L is not only seeking to terminate its payment obligations but also to receive credit from PSE&G and the other LDV
  Agreement parties for transmission facilities previously constructed by JCP&L in New Jersey; if the ALJ were to accept all of JCP&L’s crediting arguments, PSE&G would owe monies to JCP&L under the LDV
  Agreement. PSE&G cannot predict the outcome of this proceeding at this time.
NRC
Power
Nuclear Safety Issues
2005 Form 10-K, Page 20 and June 30, 2006 Form 10-Q, Page 89. In January 2004, the NRC issued a letter requesting Power to conduct a review of its Salem and Hope Creek nuclear generation
  facilities to assess the workplace environment for raising and addressing safety issues. Power responded to the letter in February 2004 and had independent assessments of the work environment at both
  facilities performed. The results of these assessments were provided to the NRC in May 2004. The assessments concluded that Salem and Hope Creek were safe for continued operations, but also identified
  issues that needed to be addressed.
At an NRC public meeting on June 16, 2004, Power outlined its action plan to address these issues, which focused on a safety-conscious work environment, the corrective action program and work
  management. A letter documenting these plans and commitments was sent to the NRC on June 25, 2004. On July 30, 2004, the NRC provided a letter to Power indicating that it had completed its review.
  The letter indicated that the NRC had not identified any safety violations and that it appeared that the PSEG action plan would address the key findings of both the NRC and Power assessments. On March
  2, 2006, the NRC provided Power with its annual performance reviews of Salem and Hope Creek,
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which detailed the NRC’s plan for enhanced oversight related to the work environment. The letter indicated the NRC plans to continue with this heightened oversight until Power has concluded that
  substantial, sustainable progress has been made, and the NRC has completed a review that confirms Power’s conclusions. On August 31, 2006, the NRC provided Power with a letter, which cleared the
  safety-conscious work environment issue at Salem and Hope Creek. The NRC has restored Salem and Hope Creek to normal oversight levels.
State Regulation
PSEG, PSE&G, Power and Energy Holdings
PUHCA Repeal
2005 Form 10-K, Page 21, March 31, 2006 Form 10-Q, Page 80 and June 30, 2006 Form 10-Q, Page 90.The BPU has issued final regulations addressing the diversification activities of New Jersey
  utilities and the companies owning such utilities. These new rules, which became effective October 2, 2006, impose a requirement that each New Jersey public utility and its holding company ensure that the
  aggregate assets of all nonutility activities in the holding company system do not exceed a defined percentage of the aggregate assets of the utility and utility-related assets in the holding company system.
  The rules broadly define utility-related activities to include such things as the production, generation, transmitting, delivering, storing, selling, marketing of natural gas, propane, electricity and other fuels to
  wholesale or retail customers, energy management services and sale of energy appliances. Both PSE&G and PSEG currently satisfy these requirements and will continue to satisfy them based on the
  companies’ current business plans. However, constant monitoring will be required to ensure that the regulation is satisfied or determine whether relief from the regulation is warranted. The BPU has not yet
  acted on Phase II of its PUHCA rulemaking phase, which addresses broader issues such as corporate governance, access to books and records, and oversight of service agreements between utilities and their
  affiliates.
NJ Energy Master Plan
The Governor of New Jersey has recently directed the BPU, in partnership with other New Jersey agencies, to develop an energy master plan. State law in New Jersey requires that an energy master
  plan be developed every three years, the purpose of which is to ensure safe, secure and reasonably-priced energy supply, foster economic growth and development and protect the environment. In the
  Governor’s directive regarding the energy master plan, the Governor established three specific goals: (1) reduce the State’s projected energy use by 20% by the year 2020; (2) supply 20% of the State’s
  electricity needs with Class 1 renewable energy sources by 2020; and (3) emphasize energy efficiency, conservation and renewable energy resources to meet future increases in New Jersey electric demand
  without increasing New Jersey’s reliance on non-renewable resources. PSEG is supportive and will be actively involved in the development of the plan. Public meetings on the energy master plan will take
  place over the next few months, and a final plan is to be completed by October 2007. The outcome of this proceeding and its impact on PSEG, PSE&G and Power cannot be predicted at this time.
PSE&G
Electric Distribution Financial Review
2005 Form 10-K, Page 22, March 31, 2006 Form 10-Q, Page 81 and June 30, 2006 Form 10-Q, Page 90. Based on the Electric Base Rate Case approved in July 2003, PSE&G recorded a regulatory
  liability in the second quarter of 2003 by reducing its depreciation reserve for its electric distribution assets by $155 million and amortized this liability from August 1, 2003 through December 31, 2005. The
  $64 million annual amortization of this liability resulted in a reduction of Depreciation and Amortization expense. PSE&G filed for the elimination of the $64 million (based on 2003 test year sales volumes)
  electric distribution rate credit effective January 1, 2006, subject to BPU approval, including a review of PSE&G’s earnings and other relevant financial information. Based on current sales volumes, the
  amount approximates $69 million.
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On October 27, 2006, PSE&G reached a settlement agreement in the Electric Distribution Financial Review. For additional information see Note 15. Subsequent Events.
BGSS Filings
2005 Form 10-K, Page 2, March 31, 2006 Form 10-Q, Page 81 and June 30, 2006 Form 10-Q, Page 91. The parties to the 2005/2006 BGSS proceeding entered into a Stipulation in which the parties
  agreed that the BGSS A hearing was held on June 29, 2006 regarding BGSS rates for the 2005/2006 period. Commodity Charge increases of September 1, 2005 and December 15, 2005 that were previously
  approved by the BPU on a provisional basis should become final. The BPU approved the Stipulation. In addition, all the remaining gas contract issues were also resolved and an amended Gas Requirements
  Contract was attached to the Stipulation and also approved by the BPU. The primary changes were the term was extended by five years, and the default provision was changed from three days to one day.
PSE&G made its 2006/2007 BGSS filing on May 26, 2006. In this filing, PSE&G requested a reduction in annual BGSS gas revenues of approximately $19.7 million (excluding losses and New Jersey Sales
  and Use Tax) or approximately a 1.0% decrease to be implemented for service rendered on and after October 1, 2006 or earlier. Additionally, PSE&G requested an increase in its Balancing Charge. The
  combined impact of both changes for the class average residential heating customer is an increase in the winter monthly bills of approximately 0.1%; however, on an annual basis the impact is a decrease of
  approximately 0.2%.
The
  parties entered into a Stipulation to make the filed rates effective October
  1, 2006 on a provisional basis. However, since the time of the filing, prices
  of gas futures have dropped significantly and as a result, additional BGSS data
  has been requested by and provided to the BPU. Settlement discussions with the
  BPU Staff have been completed and a new Stipulation has been executed by the
  parties. This new Stipulation, which requires BPU approval, results in a decrease
  in annual BGSS revenues of approximately $120 million, which is approximately
  a 6% reduction in a typical residential gas customer’s bill. The Stipulation
  did not include any change in the balancing charge, as requested.
Gas Base Rate Case
2005 Form 10-K, Page 23, March 31, 2006 Form 10-Q, Page 81 and June 30, 2006 Form 10-Q, Page 91. On September 30, 2005, PSE&G filed a petition with the BPU seeking an overall 3.78%
  increase in its gas base rates to cover the cost of gas delivery to be effective June 30, 2006. Approximately $55 million of the $133 million request is for an increase in book depreciation rates.
On October 27, 2006, PSE&G reached a settlement agreement in the Gas Base Rate Case. For additional information see Note 15. Subsequent Events.
CAS Cost Recovery Mechanism
2005 Form 10-K, Page 23, March 31, 2006 Form 10-Q, Page 82 and June 30, 2006 Form 10-Q, Page 91. The New Jersey Electric Discount and Energy Competition Act (EDECA) required that the
  BPU provide electric and natural gas customers with the opportunity to choose a supplier for some or all electric or natural gas customer account services (CAS). In July 2004, PSE&G filed a petition with the
  BPU to implement the CAS Cost Recovery Mechanism for both its electric and gas operations to recover $4 million of CAS costs and accumulated interest resulting from implementing PSE&G’s dual billing
  for its delivery costs and for the third-party suppliers’ commodity charges as a result of customer migration from PSE&G. In September 2004, the case was transferred to the OAL as a contested case. A pre-
  hearing conference was held on December 20, 2005 at which time a schedule was established. On April 7, 2006, a settlement agreement was reached and filed with the ALJ.
On May 17, 2006, the BPU issued its Order approving the Initial Decision‐Settlement that fully resolved this matter. The Settlement will allow PSE&G to recover a total of $3.3 million of costs over a
  one-year period. Recovery will begin as of the date of the next base rate change or January 1, 2007, whichever is earlier.
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Power
Connecticut Department of Public Utility Control (DPUC)
To reduce the impact of federally-mandated congestion charges on Connecticut ratepayers, Connecticut has launched a procurement process to facilitate the development of incremental generation
  capacity, as authorized by legislation which permits the DPUC to establish a competitive procurement process intended to encourage new supply-side and demand-side resources. Specifically, the DPUC is
  required to develop and issue a request for proposals (RFP) to solicit the development of long-term projects, with local distribution companies serving as the counterparties to these contracts. The impact of
  this RFP process on Power Connecticut’s assets is unclear at the present time.
Connecticut Windfall Profits Tax
2005 Form 10-K, Page 24.The Connecticut General Assembly may hold a special legislative session in the fourth quarter of 2006 to consider comprehensive energy legislation. A proposal to impose a
  ‘windfall’ profits tax of between 20% and 50% on a power generator’s earnings in excess of 20% is also proposed for enactment and could be introduced and considered in the special session or in the
  regular session commencing in January 2007. Revenues raised by such tax would be dedicated to financing the CEA and for rate relief. Neither PSEG nor Power is able to predict whether any of such
  proposals will be enacted into law or their impact, if any, or whether similar initiatives may be considered in other jurisdictions.
PSE&G and Power
BGS Auction Review
June 30, 2006 Form 10-Q, Page 90.In 2006, the BPU initiated a proceeding to review the annual BGS procurement process as well as the policy issues thereto for all of the New Jersey EDCs. In June
  2006, the BPU ruled on certain issues regarding the acquisition of BGS for the period beginning in June 2007. The BPU agreed that a descending clock auction format should be used for the procurement of
  BGS-FP supply for 2007.
On
  July 10, 2006, PSE&G filed the Joint EDC proposal for the procurement of
  BGS for the period beginning June 1, 2007. This proposal includes a descending
  clock auction format to be held in February 2007 for the procurement of all
  BGS supply. On October 28, 2006, the BPU approved a descending clock auction
  format for BGS-FP and BGS-CIEP supply for the period beginning June 1, 2007.
  The BPU also approved auction rules and Supplier Master Agreements substantially
  similar to those filed by the EDCs on July 10, 2006. The EDCs were ordered to
  make a compliance filing with the BPU by November 3, 2006.
Environmental Matters
Power
Carbon Dioxide (CO2) Emissions
2005 Form 10-K, Page 27, March 31, 2006 Form 10-Q, Page 82 and June 30, 2006 Form 10-Q, Page 92. Several states, primarily in the Northeastern U.S., are developing state-specific or regional
  legislative initiatives to stimulate CO2emissions reductions in the electric power industry. New York initiated the Regional Greenhouse Gas Initiative (RGGI) in April 2003. Currently, in the RGGI, seven
  Northeastern states have signed a memorandum of understanding (MOU) intended to cap and reduce CO2emissions from the electric power sector in the RGGI region. A final model rule was issued on
  August 15, 2006 that embraces MOU commitments and makes recommendations for states to move forward. States are expected to enact legislation and/or regulation representing, at least, the minimum
  requirements stipulated in the MOU. The NJDEP in 2005 finalized amendments to its regulations governing air pollution control that would designate CO2as an air contaminant subject to regulation. The
  RGGI program is scheduled to start in 2009. The outcome of this initiative cannot be determined at this time; however, adoption of stringent CO2emissions reduction requirements in the Northeast could
  materially impact Power’s operation of its fossil fuel-fired electric generating units.
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PSE&G and Power
Remedial Investigation/Feasibility Study
March 31, 2006 Form 10-Q, page 82 and June 30, 2006 Form 10-Q, Page 92. On March 9, 2006, the U.S. Department of Environmental Protection Agency (EPA) sent PSE&G, Power and
  approximately 157 other entities a notice that the EPA considered each of the entities to be a potentially responsible party (PRP) with respect to contamination in Berry’s Creek in Bergen County, New
  Jersey and requesting that the PRPs perform a Remedial Investigation/Feasibility Study (RI/FS) on Berry’s Creek and the connected tributaries and wetlands. Berry’s Creek flows through approximately 6.5
  miles of areas that have been used for a variety of industrial purposes and landfills. The EPA estimates that the study could be completed in approximately five years at a total cost of approximately $18
  million. PSE&G and Power are unable to predict the outcome of this matter; however, the related costs are not expected to be material.
Newark Bay Study Area
On
  August 24, 2006, the EPA sent PSE&G and three other entities a notice that
  the EPA considered each of the entities to be a potentially responsible party
  (PRP) with respect to contamination in the Newark Bay Study Area, which it defined
  as Newark Bay and portions of the Hackensack River, the Arthur Kill, and the
  Kill Van Kull. The notice letter requested that PSE&G participate and fund
  the EPA-approved study in the Newark Bay Study Area and encouraged PSE&G
  to contact Occidental Chemical Corporation (OCC) to discuss participating in
  the RI/FS that OCC is conducting in the Newark Bay Study Area. EPA considers
  the Newark Bay Study Area, along with the Passaic River Study Area, to be part
  of the Diamond Alkali Superfund Site. The notice states EPA’s belief that
  hazardous substances were released from sites owned by PSE&G and located
  on the Hackensack River. The sites included two operating electric generating
  stations (Hudson and Kearny Sites), and one former manufactured gas plant (MGP).
  PSE&G’s costs to clean up former MGPs are recoverable from utility
  customers through the societal benefits clause (SBC). The Hudson and Kearny
  Sites were 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 Hudson and Kearny Sites. Power has
  provided notice to insurers concerning this potential claim. PSE&G and Power
  are unable to estimate the cost of the investigation at this time, but the costs
  are likely to be material.
Other
PSEG
Audit Fees
The aggregate fees billed to PSEG and its subsidiaries by Deloitte & Touche for audit services rendered for the year ended December 31, 2005 totaled $8,501,094. The fees were incurred for audits of the
  annual consolidated financial statements of PSEG and its subsidiaries, including the Annual Report on Form l0-K of PSEG and its subsidiaries, reviews of financial statements included in Quarterly Reports
  on Form 10-Q of PSEG and its subsidiaries and for services rendered in connection with certain financing transactions and fees for accounting consultations related to the application of new accounting
  standards and rules.
Energy Holdings
GWF
June 30, 2006 Form 10-Q, Page 92.In April 2006, GWF Power Systems, L.P. and Hanford L.P., each a partnership 50% owned by Global, executed amendments to their respective power purchase
  agreements to establish fixed price energy sales terms for a five-year period. The California Public Utilities Commission approved the amendments on July 20, 2006; the amendments became effective and
  the five-year term commenced in August 2006.
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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. RADOPatricia
        A. Rado
        Vice President and Controller
        (Principal Accounting Officer)
Date: November 1, 2006
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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/
        PATRICIAA. RADOPatricia
        A. Rado
        Vice President and Controller
        (Principal Accounting Officer)
Date: November 1, 2006
96

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/
        PATRICIAA. RADOPatricia
        A. Rado
        Vice President and Controller
        (Principal Accounting Officer)
Date: November 1, 2006
97

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/
        PATRICIAA. RADOPatricia
        A. Rado
        Controller
        (Principal Accounting Officer)
Date: November 1, 2006
98