---

---

## UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549




# FORM10-Q

#### (Mark One)

[X]QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

#### FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003

#### OR

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

#### FOR THE TRANSITION PERIOD FROM                  TO

|Commission
File Number | Registrants, State of Incorporation,
Address, and Telephone Number | I.R.S. Employer
Identification No.
|---------------------- | ------------------------------------------------------------------ | ----------------------------------
|                       | 001-09120                                                          |                                   
|                       | 001-00973                                                          |                                   
|                       | 000-49614                                                          |                                   
|                       | 000-32503                                                          |                                   




Indicate
  by check mark whether the registrants (1) have filed all reports required to
  be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
  the preceding 12 months (or for such shorter period that the registrants were
  required to file such reports) and (2) have been subject to such filing
  requirements for the past 90 days. Yes[X]No[  ]

As of July 25, 2003, Public Service Enterprise Group Incorporated had outstanding 226,367,848 shares of its sole class of Common Stock, without par value.

As of July 25, 2003, 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 LLC are wholly-owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q and are filing their respective Quarterly Reports on Form 10-Q with the reduced disclosure format authorized by General Instruction H.

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

| | Public Service Enterprise Group Incorporated | Yes[X]  | No[  ]
| | -------------------------------------------- | ------- | ------
| | Public Service Electric and Gas Company      | Yes[  ] | No[X] 
| | PSEG Power LLC                               | Yes[  ] | No[X] 
| | PSEG Energy Holdings LLC                     | Yes[  ] | No[X] 



#### TABLE OF CONTENTS

|                              |  |                                                                                       |    | Page
|----------------------------- |  | ------------------------------------------------------------------------------------- | -- | ----
|FORWARD-LOOKING STATEMENTS    |  |                                                                                       | ii |     
|PART I. FINANCIAL INFORMATION |  |                                                                                       |    |     
|Item 1.                       |  | Financial Statements                                                                  |    |     
|                              |  | Public Service Enterprise Group Incorporated                                          |    |     
|                              |  | Public Service Electric and Gas Company                                               |    |     
|                              |  | PSEG Power LLC                                                                        |    |     
|                              |  | PSEG Energy Holdings LLC                                                              |    |     
|                              |  | Notes to Consolidated Financial Statements                                            |    |     
|                              |  | Note 1. Organization and Basis of Presentation                                        |    |     
|                              |  | Note 2. New Accounting Standards                                                      |    |     
|                              |  | Note 3. Adoption of SFAS 143                                                          |    |     
|                              |  | Note 4. Earnings Per Share                                                            |    |     
|                              |  | Note 5. Discontinued Operations                                                       |    |     
|                              |  | Note 6. Regulatory Assets and Liabilities                                             |    |     
|                              |  | Note 7. Commitments and Contingent Liabilities                                        |    |     
|                              |  | Note 8. Risk Management                                                               |    |     
|                              |  | Note 9. Comprehensive Income                                                          |    |     
|                              |  | Note 10. Other Income and Deductions                                                  |    |     
|                              |  | Note 11. Income Taxes                                                                 |    |     
|                              |  | Note 12. Financial Information by Business Segment                                    |    |     
|                              |  | Note 13. Stock-Based Compensation                                                     |    |     
|                              |  | Note 14. Related-Party Transactions                                                   |    |     
|                              |  | Note 15. Guarantees of Debt                                                           |    |     
|                              |  | Note 16. Subsequent Events                                                            |    |     
|Item 2.                       |  | Management's Discussion and Analysis of Financial Condition and Results of Operations |    |     
|                              |  | Overview                                                                              |    |     
|                              |  | Results of Operations                                                                 |    |     
|                              |  | Liquidity and Capital Resources                                                       |    |     
|                              |  | Capital Requirements                                                                  |    |     
|                              |  | Accounting Issues                                                                     |    |     
|Item 3.                       |  | Qualitative and Quantitative Disclosures About Market Risk                            |    |     
|Item 4.                       |  | Controls and Procedures                                                               |    |     
|PART II. OTHER INFORMATION    |  |                                                                                       |    |     
|Item 1.                       |  | Legal Proceedings                                                                     |    |     
|Item 5.                       |  | Other Information                                                                     |    |     
|Item 6.                       |  | Exhibits and Reports on Form 8-K                                                      |    |     
|Signatures                    |  |                                                                                       | 83 |     

i



---

FORWARD-LOOKING STATEMENTS
Except for the historical information contained herein, certain of the matters discussed in this report constitute ''forward-looking statements'' within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used herein, the words ''will'', ''anticipate'', ''intend'', ''estimate'', ''believe'', ''expect'', ''plan'', ''hypothetical'', ''potential'', ''forecast'', ''projections'', variations of such words and similar expressions are intended to identify forward-looking statements. Public Service Enterprise Group Incorporated
(PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings LLC (Energy Holdings) undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The following review of factors should not be construed as exhaustive.
In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements discussed above, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:
PSEG, PSE&G, Power and Energy Holdings
•

credit, commodity, interest rate, counterparty and other financial market risks;•

liquidity and the ability to access capital and credit markets;•

acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG's, PSE&G's, Power's and Energy Holdings' structure;•

business combinations among competitors and major customers;•

general economic conditions including inflation;•

changes to accounting standards or accounting principles generally accepted in the U.S., which may require adjustments to financial statements;•

changes in tax laws and regulations;•

energy obligations, available supply and trading risks;•

changes in the electric industry including changes to power pools;•

regulation and availability of power transmission facilities that impact the ability to deliver output to customers;•

growth in costs and expenses;•

environmental regulation that significantly impact operations;•

changes in rates of return on overall debt and equity markets could have an adverse impact on the value of pension assets and the Nuclear Decommissioning Trust Fund;•

changes in political conditions, recession, acts of war or terrorism;•

insufficient insurance coverage;•

involvement in lawsuits including liability claims and commercial disputes could affect profits or the ability to sell and market products;•

inability to attract and retain management and other key employees;•

ability to service debt as a result of any of the aforementioned events;PSE&G and Energy Holdings
•

ability to obtain adequate and timely rate relief;•

regulatory issues that significantly impact operations;ii

Power and Energy Holdings
•

adverse changes in the market place for energy prices;•

excess supply due to overbuild in the industry;•

generation operating performance may fall below projected levels;•

substantial competition from well capitalized participants in the worldwide energy markets;•

inability to effectively manage portfolios of electric generation assets, gas supply contracts and electric and gas supply obligations;•

margin posting requirements;•

availability of fuel at reasonable prices;•

competitive position could be adversely affected by actions involving competitors or major customers;•

changes in product or sourcing mix;•

tardy or unsuccessful acquisition, construction and development;•

changes in technology that make power generation assets less competitive;Power
•

changes in regulation and security measures at nuclear facilities;Energy Holdings
•

adverse international developments that negatively impact its business;•

changes in foreign currency exchange rates;•

substandard operating performance or cash flow from investments could fall below projected levels, adversely impacting the ability to service its debt; and•

credit of lessees to service the leases.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 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 disclaim 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, PSE&G, Power 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 INCORPORATEDCONSOLIDATED STATEMENTS OF OPERATIONS
For
      the Quarter Ended
      June 30,
    
    For
      the Six Months Ended
      June 30,2003
    
    2002
    
    2003
    
    2002(Millions,
      except for Share Data)
      (Unaudited)OPERATING REVENUES
    
    $
    2,419
    
    
    $
    1,415
    
    
    $
    5,725
    
    
    $
    3,298OPERATING EXPENSESEnergy
      Costs
    
    
    1,412
    
    
    
    449
    
    
    
    3,376
    
    
    
    1,189Operation
      and Maintenance
    
    
    487
    
    
    
    457
    
    
    
    1,007
    
    
    
    920Write-down
      of Project Investments
    
    
    —
    
    
    
    506
    
    
    
    —
    
    
    
    506Depreciation
      and Amortization
    
    
    103
    
    
    
    135
    
    
    
    203
    
    
    
    266Taxes
      Other Than Income Taxes
    
    
    28
    
    
    
    26
    
    
    
    72
    
    
    
    64Total
      Operating Expenses
    
    
    2,030
    
    
    
    1,573
    
    
    
    4,658
    
    
    
    2,945Income from Equity
      Method Investments
    
    
    31
    
    
    
    33
    
    
    
    48
    
    
    
    63OPERATING INCOME (LOSS)
    
    
    420
    
    
    
    (125
    )
    
    
    1,115
    
    
    
    416Other
      Income
    
    
    30
    
    
    
    7
    
    
    
    88
    
    
    
    9Other
      Deductions
    
    
    (21
    )
    
    
    (27
    )
    
    
    (64
    )
    
    
    (70
    )Interest
      Expense
    
    
    (190
    )
    
    
    (188
    )
    
    
    (377
    )
    
    
    (379
    )Preferred
      Securities Dividends
    
    
    (18
    )
    
    
    (14
    )
    
    
    (36
    )
    
    
    (28
    )INCOME (LOSS) FROM
      CONTINUING OPERATIONS BEFORE INCOME TAXES
    
    
    221
    
    
    
    (347
    )
    
    
    726
    
    
    
    (52
    )Income Taxes
    
    
    (71
    )
    
    
    120
    
    
    
    (255
    )
    
    
    6INCOME (LOSS) FROM
      CONTINUING OPERATIONS
    
    
    150
    
    
    
    (227
    )
    
    
    471
    
    
    
    (46
    )Loss from Discontinued
      Operations, including Loss on Disposal, net of tax
    
    
    (2
    )
    
    
    (37
    )
    
    
    (17
    )
    
    
    (38
    )INCOME (LOSS) BEFORE
      EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A
            CHANGE IN ACCOUNTING PRINCIPLE
    
    
    148
    
    
    
    (264
    )
    
    
    454
    
    
    
    (84
    )Extraordinary Item,
      net of tax benefit of $12
    
    
    (18
    )
    
    
    —
    
    
    
    (18
    )
    
    
    —Cumulative Effect
      of a Change in Accounting Principle, net of tax (expense) benefit of ($255)
      and $66 in
            2003 and 2002, respectively
    
    
    —
    
    
    
    —
    
    
    
    370
    
    
    
    (120
    )NET INCOME (LOSS)
    
    $
    130
    
    
    $
    (264
    )
    
    $
    806
    
    
    $
    (204
    )WEIGHTED AVERAGE COMMON
      SHARES OUTSTANDINGBASIC
    
    
    225,910
    
    
    
    206,246
    
    
    
    225,627
    
    
    
    206,049DILUTED
    
    
    226,582
    
    
    
    206,927
    
    
    
    226,108
    
    
    
    206,631EARNINGS PER SHARE:BASICINCOME
      (LOSS) FROM CONTINUING OPERATIONS
    
    $
    0.67
    
    
    $
    (1.10
    )
    
    $
    2.09
    
    
    $
    (0.22
    )NET
      INCOME (LOSS)
    
    $
    0.58
    
    
    $
    (1.28
    )
    
    $
    3.57
    
    
    $
    (0.99
    )DILUTEDINCOME
      (LOSS) FROM CONTINUING OPERATIONS
    
    $
    0.66
    
    
    $
    (1.10
    )
    
    $
    2.09
    
    
    $
    (0.22
    )NET
      INCOME (LOSS)
    
    $
    0.57
    
    
    $
    (1.28
    )
    
    $
    3.57
    
    
    $
    (0.99
    )DIVIDENDS PAID PER
      SHARE OF COMMON STOCK
    
    $
    0.54
    
    
    $
    0.54
    
    
    $
    1.08
    
    
    $
    1.08See Notes to Consolidated Financial Statements.
1

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONSOLIDATED BALANCE SHEETS
June 30,
2003

December 31,
2002(Millions)
(Unaudited)ASSETSCURRENT ASSETSCash and Cash Equivalents

$
150


$
165Accounts Receivable, net of allowances of $86 and $34 in 2003 and 2002, respectively


1,377



1,370Unbilled Electric and Gas Revenues


171



275Fuel


416



412Materials and Supplies


226



208Energy Trading Contracts


155



157Restricted Cash


37



32Assets Held for Sale


72



83Prepayments


297



60Current Assets of Discontinued Operations


31



107Other


37



75Total Current Assets


2,969



2,944PROPERTY, PLANT AND EQUIPMENT


17,329



16,571Less: Accumulated Depreciation and Amortization


(5,193
)


(5,113
)Net Property, Plant and Equipment


12,136



11,458NONCURRENT ASSETSRegulatory Assets


4,975



5,002Long-Term Investments


4,687



4,580Nuclear Decommissioning Trust (NDT) Funds


869



766Other Special Funds


91



72Goodwill


442



452Other Intangibles


206



206Energy Trading Contracts


23



21Other


172



201Total Noncurrent Assets


11,465



11,300TOTAL
      ASSETS

$
26,570


$
25,702See Notes to Consolidated Financial Statements.
2

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONSOLIDATED BALANCE SHEETS
June 30,
      2003
    
    December
      31,
      2002(Millions)
      (Unaudited)LIABILITIES
      AND CAPITALIZATIONCURRENT LIABILITIESLong-Term
      Debt Due Within One Year
    
    $
    733
    
    
    $
    749Commercial
      Paper and Loans
    
    
    1,070
    
    
    
    762Accounts
      Payable
    
    
    1,117
    
    
    
    1,115Energy
      Trading Contracts
    
    
    85
    
    
    
    101Accrued
      Taxes
    
    
    72
    
    
    
    229Current
      Liabilities of Discontinued Operations
    
    
    31
    
    
    
    83Other
    
    
    762
    
    
    
    755Total
      Current Liabilities
    
    
    3,870
    
    
    
    3,794NONCURRENT LIABILITIESDeferred
      Income Taxes and Investment Tax Credits (ITC)
    
    
    3,526
    
    
    
    2,918Regulatory
      Liabilities
    
    
    362
    
    
    
    252Nuclear
      Decommissioning Liabilities
    
    
    273
    
    
    
    766Other
      Postemployment Benefit (OPEB) Costs
    
    
    513
    
    
    
    501Accrued
      Pension Costs
    
    
    297
    
    
    
    336Cost
      of Removal
    
    
    —
    
    
    
    131Other
    
    
    639
    
    
    
    634Total
      Noncurrent Liabilities
    
    
    5,610
    
    
    
    5,538COMMITMENTS AND CONTINGENT
      LIABILITIES (See Note 7)CAPITALIZATIONLONG-TERM
      DEBTLong-Term
      Debt
    
    
    7,060
    
    
    
    7,116Securitization
      Debt
    
    
    2,160
    
    
    
    2,222Project
      Level, Non-Recourse Debt
    
    
    1,808
    
    
    
    1,653Total
      Long-Term Debt
    
    
    11,028
    
    
    
    10,991SUBSIDIARIES' PREFERRED
      SECURITIESPreferred
      Stock Without Mandatory Redemption
    
    
    80
    
    
    
    80Preferred
      Stock With Mandatory Redemption
    
    
    460
    
    
    
    460Guaranteed
      Preferred Beneficial Interest in Subordinated Debentures
    
    
    860
    
    
    
    860Total
      Subsidiaries' Preferred Securities
    
    
    1,400
    
    
    
    1,400COMMON STOCKHOLDERS'
      EQUITYCommon
      Stock, issued; 2003—252,460,006 shares
                  2002—251,385,937
      shares
    
    
    4,100
    
    
    
    4,056Treasury
      Stock, at cost; 2003 and 2002—26,118,590 shares
    
    
    (981
    )
    
    
    (981
    )Retained
      Earnings
    
    
    2,160
    
    
    
    1,601Accumulated
      Other Comprehensive Loss
    
    
    (617
    )
    
    
    (697
    )Total
      Common Stockholders' Equity
    
    
    4,662
    
    
    
    3,979Total
      Capitalization
    
    
    17,090
    
    
    
    16,370TOTAL
      LIABILITIES AND CAPITALIZATION
    
    $
    26,570
    
    
    $
    25,702See Notes to Consolidated Financial Statements.
3

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDCONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended
June 30,2003

2002(Millions)
(Unaudited)CASH FLOWS FROM OPERATING ACTIVITIESNet Income (Loss)

$
806


$
(204
)Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:Extraordinary Item, net of tax


18



—Write-Down of Project Investments


—



506Loss on Disposal of Discontinued Operations, net of tax


9



34Cumulative Effect of a Change in Accounting Principle, net of tax


(370
)


120Depreciation and Amortization


203



266Amortization of Nuclear Fuel


46



42Provision for Deferred Income Taxes (Other than Leases) and ITC


59



(154
)Non-Cash Employee Benefit Plan Costs


126



97Leveraged Lease Income, Adjusted for Rents Received


35



48Undistributed Earnings from Affiliates


(3
)


(17
)Foreign Currency Transaction Loss


—



69Unrealized Losses (Gains) on Energy Contracts and Other Derivatives


7



(37
)(Under) Over Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs


(51
)


2Over Recovery of SBC


91



34Net Realized Gains and Income from NDT Fund


(28
)


—Other Non-Cash Charges


5



31Net Change in Certain Current Assets and Liabilities


(176
)


(143
)Employee Benefit Plan Funding and Related Payments


    (153
)


(130
)Proceeds from the Withdrawal of Partnership Interests and Other Distributions


47



4Other


    (43
)


(32
)Net Cash Provided By Operating Activities


628



536CASH FLOWS FROM INVESTING ACTIVITIESAdditions to Property, Plant and Equipment


(715
)


(889
)Investments in Joint Ventures, Partnerships and Capital Leases


(17
)


(183
)Proceeds from the Sale of Investments and Return of Capital from Partnerships


2



90Other


7



(96
)Net Cash Used In Investing Activities


(723
)


(1,078
)CASH FLOWS FROM FINANCING ACTIVITIESNet Change in Short-Term Debt


422



361Issuance of Long-Term Debt


476



733Issuance of Non-Recourse Debt


350



141Issuance of Common Stock


42



36Redemptions of Long-Term Debt


(933
)


(424
)Cash Dividends Paid on Common Stock


(244
)


(223
)Other


(33
)


(1
)Net Cash Provided By Financing Activities


80



623Effect of Exhange Rate Change


—



(2
)Net Change In Cash and Cash Equivalents


(15
)


79Cash and Cash Equivalents at Beginning of Period


165



167Cash and Cash Equivalents at End of Period

$
150


$
246Supplemental Disclosure of Cash Flow Information:Income Taxes Paid

$
150


$
145Interest Paid, Net of Amounts Capitalized

$
383


$
391See Notes to Consolidated Financial Statements.
4

PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONSOLIDATED STATEMENTS OF OPERATIONS
For The Quarter Ended
June 30,

For The Six Months EndedJune 30,2003

2002

2003

2002(Millions)
(Unaudited)OPERATING REVENUES

$
1,342


$
1,230


$
3,490


$
2,889OPERATING EXPENSESEnergy Costs


919



758



2,426



1,817Operation and Maintenance


224



239



510



493Depreciation and Amortization


63



97



129



192Taxes Other Than Income Taxes


28



26



72



64Total Operating Expenses


1,234



1,120



3,137



2,566OPERATING INCOME


108



110



353



323Other Income


3



2



13



2Other Deductions


—



(1
)


(1
)


(1
)Interest Expense


(94
)


(100
)


(188
)


(200
)Preferred Securities Dividends


(3
)


(3
)


(6
)


(6
)INCOME BEFORE INCOME TAXES AND EXTRAORDINARY ITEM


14



8



171



118Income Benefit (Taxes)


8



—



(48
)


(42
)INCOME BEFORE EXTRAORDINARY ITEM


22



8



123



76Extraordinary Item, net of tax benefit of $12


(18
)


—



(18
)


—NET INCOME


4



8



105



76Preferred Stock Dividends


(1
)


(1
)


(2
)


(2
)EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

$
3


$
7


$
103


$
74See disclosures regarding Public Service Electric and Gas Company
included in the Notes to Consolidated Financial Statements.
5

PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONSOLIDATED BALANCE SHEETS
June 30,
2003

December 31,
2002(Millions)
(Unaudited)ASSETSCURRENT ASSETSCash and Cash Equivalents

$
22


$
35Accounts Receivable, net of allowances of $42 and $32 in 2003 and 2002, respectively


697



755Unbilled Revenues


171



275Materials and Supplies


57



45Prepayments


230



25Restricted Cash


14



14Other


25



16Total Current Assets


1,216



1,165PROPERTY, PLANT AND EQUIPMENT


9,785



9,581Less: Accumulated Depreciation and Amortization


(3,596
)


(3,604
)Net Property, Plant and Equipment


6,189



5,977NONCURRENT ASSETSRegulatory Assets


4,975



5,002Long-Term Investments


127



123Other Special Funds


45



44Intangibles


60



60Other


59



58Total Noncurrent Assets


5,266



5,287TOTAL ASSETS

$
12,671


$
12,429See disclosures regarding Public Service Electric and Gas Company
included in the Notes to Consolidated Financial Statements.
6

PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONSOLIDATED BALANCE SHEETS
June 30,
2003

December 31,
2002(Millions)
(Unaudited)LIABILITIES AND CAPITALIZATIONCURRENT LIABILITIESLong-Term Debt Due Within One Year

$
419


$
429Commercial Paper and Loans


502



224Accounts Payable


513



724Other


336



315Total Current Liabilities


1,770



1,692NONCURRENT LIABILITIESDeferred Income Taxes and ITC


2,458



2,436Regulatory Liabilities


362



252OPEB Costs


495



486Accrued Pension Costs


151



175Other


181



209Total Noncurrent Liabilities


3,647



3,558COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)CAPITALIZATIONLONG-TERM DEBTLong-Term Debt


2,491



2,627Securitization Debt


2,160



2,222Total Long-Term Debt


4,651



4,849PREFERRED SECURITIESPreferred Stock Without Mandatory Redemption


80



80Subsidiaries' Preferred Securities With Mandatory Redemption


155



155Total Preferred Securities


235



235COMMON STOCKHOLDER'S EQUITYCommon Stock; 150,000,000 shares authorized,
      132,450,344 shares issued and outstanding


892



892Contributed Capital


170



—Basis Adjustment


986



986Retained Earnings


492



389Accumulated Other Comprehensive Loss


(172
)


(172
)Total Common Stockholder's Equity


2,368



2,095Total Capitalization


7,254



7,179TOTAL LIABILITIES AND CAPITALIZATION

$
12,671


$
12,429See disclosures regarding Public Service Electric and Gas Company
included in the Notes to Consolidated Financial Statements.
7

PUBLIC SERVICE ELECTRIC AND GAS COMPANYCONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended
June 30,2003

2002(Millions)
(Unaudited)CASH FLOWS FROM OPERATING ACTIVITIESNet Income

$
105


$
76Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:Extraordinary Item, net of tax


18



—Depreciation and Amortization


129



192Provision for Deferred Income Taxes and ITC


(11
)


(25
)Non-Cash Employee Benefit Plan Costs


88



72Non-Cash Interest Expense


16



1(Under) Over Recovery of Electric Energy Costs (BGS and NTC)


(95
)


76Over (Under) Recovery of Gas Costs


44



(74
)Over Recovery of SBC


91



34Gain on the Sale of Property, Plant and Equipment


(8
)


(1
)Other Non-Cash Regulatory Credits


(9
)


—Net Changes in Certain Current Assets and Liabilities:Accounts Receivable and Unbilled Revenues


162



167Natural Gas


—



415Fuel and Materials and Supplies


(12
)


(6
)Prepayments


(205
)


(235
)Accounts Payable


(211
)


(138
)Other Current Assets and Liabilities


5



4Employee Benefit Plan Funding and Related Payments


(95
)


(89
)Other


(40
)


21Net Cash (Used In) Provided By Operating Activities


(28
)


490CASH FLOWS FROM INVESTING ACTIVITIESAdditions to Property, Plant and Equipment


(229
)


(196
)Proceeds from the Sale of Property, Plant and Equipment


9



1Net Cash Used In Investing Activities


(220
)


(195
)CASH FLOWS FROM FINANCING ACTIVITIESNet Change in Short-Term Debt


278



—Issuance of Long-Term Debt


150



—Redemption of Securitization Debt


(58
)


(51
)Redemption of Long-Term Debt


(300
)


—Contributed Capital


170



—Dividends on Common Stock


—



(150
)Other


(5
)


(5
)Net Cash Provided By (Used In) Financing Activities


235



(206
)Net Change In Cash and Cash Equivalents


(13
)


89Cash and Cash Equivalents at Beginning of Period


35



102Cash and Cash Equivalents at End of Period

$
22


$
191Supplemental Disclosure of Cash Flow Information:Income Taxes Paid

$
73


$
117Interest Paid, Net of Amounts Capitalized

$
183


$
202See disclosures regarding Public Service Electric and Gas Company
included in the Notes to Consolidated Financial Statements.
8
PSEG POWER LLCCONSOLIDATED STATEMENTS OF OPERATIONS
For the Quarter Ended
June 30,

For the Six Months Ended
June 30,2003

2002

2003

2002(Millions)
(Unaudited)OPERATING REVENUES

$
1,236


$
673


$
3,065


$
1,249OPERATING EXPENSESEnergy Costs


788



284



2,078



423Operation and Maintenance


228



189



430



375Depreciation and Amortization


24



27



47



50Total Operating Expenses


1,040



500



2,555



848OPERATING INCOME


196



173



510



401Other Income


27



—



74



—Other Deductions


(12
)


—



(45
)


—Interest Expense


(28
)


(28
)


(56
)


(56
)INCOME BEFORE INCOME
      TAXES AND CUMULATIVE EFFECT OF A CHANGE IN 
            ACCOUNTING PRINCIPLE


183



145



483



345Income Taxes


(74
)


(62
)


(197
)


(142
)INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE


109



83



286



203Cumulative Effect of a Change in Accounting Principle, net of tax of $255


—



—



370



—EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

$
109


$
83


$
656


$
203See disclosures regarding PSEG Power LLC
included in the Notes to Consolidated Financial Statements.
9

PSEG POWER LLCCONSOLIDATED BALANCE SHEETS
June 30,
2003

December 31,
2002(Millions)
(Unaudited)ASSETSCURRENT ASSETSCash and Cash Equivalents

$
25


$
26Accounts Receivable, net of allowances of $31 and $0 in 2003 and 2002, respectively


525



499Accounts Receivable—Affiliated Companies


80



238Fuel


409



406Materials and Supplies


158



148Energy Trading Contracts


155



157Other


13



44Total Current Assets


1,365



1,518PROPERTY, PLANT AND EQUIPMENT


5,686



5,342Less: Accumulated Depreciation and Amortization


(1,365
)


(1,302
)Net Property, Plant and Equipment


4,321



4,040NONCURRENT ASSETSDeferred Income Taxes and Investment Tax Credits (ITC)


176



547Nuclear Decommissioning Trust Funds


869



766Intangibles


141



141Energy Trading Contracts


23



21Other


104



143Total Noncurrent Assets


1,313



1,618TOTAL ASSETS

$
6,999


$
7,176LIABILITIES AND MEMBER'S EQUITYCURRENT LIABILITIESAccounts Payable

$
678


$
670Short-Term Loan from Affiliate


4



239Energy Trading Contracts


85



101Other


272



283Total Current Liabilities


1,039



1,293NONCURRENT LIABILITIESNuclear Decommissioning Liabilities


273



766Cost of Removal


—



131Accrued Pension Costs


88



101Other


128



130Total Noncurrent Liabilities


489



1,128COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)LONG-TERM DEBTProject Level, Non-Recourse Debt


800



800Long-Term Debt


2,516



2,516Total Long-Term Debt


3,316



3,316MEMBER'S EQUITYContributed Capital


1,550



1,550Basis Adjustment


(986
)


(986
)Retained Earnings


1,622



966Accumulated Other Comprehensive Loss


(31
)


(91
)Total Member's Equity


2,155



1,439TOTAL LIABILITIES AND MEMBER'S EQUITY

$
6,999


$
7,176See disclosures regarding PSEG Power LLC
included in the Notes to Consolidated Financial Statements.
10
PSEG POWER LLCCONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended
June 30,2003

2002(Millions)
(Unaudited)CASH FLOWS FROM OPERATING ACTIVITIESNet Income

$
656


$
203Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:Cumulative Effect of a Change in Accounting Principle, net of tax


(370
)


—Depreciation and Amortization


47



50Amortization of Nuclear Fuel


46



42Interest Accretion on NDT Liability


12



—Provision for Deferred Income Taxes


78



23Unrealized Gains on Energy Trading Contracts


(5
)


(35
)Non-Cash Employee Benefit Plan Costs


26



16Net Realized Gains and Income on NDT Fund


(28
)


—Net Changes in Certain Current Assets and Liabilities:Fuel, Materials and Supplies


(13
)


(287
)Accounts Receivable


132



(116
)Accounts Payable


8



207Other Current Assets and Liabilities


11



46Benefit Plan Funding Payments


(37
)


(29
)Other


17



(45
)Net Cash Provided By Operating Activities


580



75CASH FLOWS FROM INVESTING ACTIVITIESAdditions to Property, Plant and Equipment


(330
)


(545
)Proceeds from the Sale of Property, Plant and Equipment


—



47Short-Term Loan—Affiliate


—



(22
)Other


(16
)


(16
)Net Cash Used In Investing Activities


(346
)


(536
)CASH FLOWS FROM FINANCING ACTIVITIESIssuance of Long-Term Debt


—



629Short-Term Loan—Affiliate


(235
)


(164
)Net Cash (Used In) Provided By Financing Activities


(235
)


465Net Change In Cash and Cash Equivalents


(1
)


4Cash and Cash Equivalents at Beginning of Period


26



9Cash and Cash Equivalents at End of Period

$
25


$
13Supplemental Disclosure of Cash Flow Information:Income Taxes Paid

$
94


$
65Interest Paid, Net of Amounts Capitalized

$
108


$
87See disclosures regarding PSEG Power LLC
included in the Notes to Consolidated Financial Statements.
11
PSEG ENERGY HOLDINGS LLCCONSOLIDATED STATEMENTS OF OPERATIONS
For The Quarter Ended
June 30,

For The Six Months Ended
June 30,2003

2002

2003

2002(Millions)
(Unaudited)OPERATING REVENUESElectric Generation and Distribution Revenues

$
122


$
60


$
235


$
131Income from Capital and Operating Leases


54



59



110



116Gain on Withdrawal from/Sale of Partnerships


—



40



45



47Net Investment Gains (Losses)


6



(33
)


(5
)


(38
)Other


6



7



12



13Total Operating Revenues


188



133



397



269OPERATING EXPENSESEnergy Costs


52



28



99



58Operation and Maintenance


41



37



76



64Write-down of Project Investments


—



506



—



506Depreciation and Amortization


14



6



24



14Total Operating Expenses


107



577



199



642Income from Equity Method Investments


31



33



48



63OPERATING INCOME (LOSS)


112



(411
)


246



(310
)Other Income


—



—



1



1Other Deductions


(8
)


(26
)


(12
)


(69
)Interest Expense


(54
)


(54
)


(104
)


(108
)INCOME (LOSS) BEFORE INCOME
      TAXES, MINORITY INTEREST, DISCONTINUED
	        OPERATIONS
      AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE


50



(491
)


131



(486
)Income Taxes


(16
)


177



(33
)


177Minority Interests in (Earnings) Losses of Subsidiaries


(1
)


4



(6
)


5INCOME (LOSS) BEFORE DISCONTINUED
      OPERATIONS AND CUMULATIVE EFFECT OF A
	        CHANGE
      IN ACCOUNTING PRINCIPLE


33



(310
)


92



(304
)DISCONTINUED OPERATIONSLoss From Discontinued Operations, net of tax


(2
)


(3
)


(8
)


(4
)Loss on Disposal of Discontinued Operations, net of tax


—



(34
)


(9
)


(34
)INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE


31



(347
)


75



(342
)Cumulative Effect of a Change in Accounting Principle, net of tax benefit of $66


—



—



—



(120
)NET INCOME (LOSS)


31



(347
)


75



(462
)Preference Units Distributions/Preferred Stock Dividends


(5
)


(5
)


(11
)


(11
)EARNINGS (LOSS) AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

$
26


$
(352
)

$
64


$
(473
)See disclosures regarding PSEG Energy Holdings LLC
included in the Notes to Consolidated Financial Statements.
12

PSEG ENERGY HOLDINGS LLCCONSOLIDATED BALANCE SHEETS
June 30,
2003

December 31,
2002(Millions)
(Unaudited)ASSETSCURRENT ASSETSCash and Cash Equivalents

$
102


$
104Accounts Receivable:Trade—net of allowances of $13 and $0 in 2003 and 2002, respectively


121



91Other Accounts Receivable


118



24Assets Held for Sale


72



83Notes Receivable:Affiliated Companies


131



62Other


7



11Inventory


18



22Prepayments


4



4Restricted Cash


23



18Current Assets of Discontinued Operations


31



107Total Current Assets


627



526PROPERTY, PLANT AND EQUIPMENT


1,758



1,548Less: Accumulated Depreciation and Amortization


(162
)


(139
)Net Property, Plant and Equipment


1,596



1,409INVESTMENTSCapital Leases—net


2,929



2,844Corporate Joint Ventures


1,061



1,003Partnership Interests


471



484Other Investments


33



38Total Investments


4,494



4,369OTHER ASSETSGoodwill


426



436Other


80



86Total Other Assets


506



522TOTAL ASSETS

$
7,223


$
6,826See disclosures regarding PSEG Energy Holdings LLC
included in the Notes to Consolidated Financial Statements.
13

PSEG ENERGY HOLDINGS LLCCONSOLIDATED BALANCE SHEETS
June 30, 2003

December 31, 2002(Millions)
(Unaudited)LIABILITIES AND MEMBER'S EQUITYCURRENT LIABILITIESLong-Term Debt Due Within One Year

$
314


$
320Accounts Payable


224



257Notes Payable


67



137Current Liabilities of Discontinued Operations


31



95Total Current Liabilities


636



809NONCURRENT LIABILITIESDeferred Income Taxes and Investment and Energy Tax Credits


1,252



1,038Other Noncurrent Liabilities


216



179Total Noncurrent Liabilities


1,468



1,217COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)MINORITY INTERESTS


113



103LONG-TERM DEBTProject Level, Non-Recourse Debt


1,008



853Senior Notes


1,800



1,725Total Long-Term Debt


2,808



2,578MEMBER'S EQUITYOrdinary Unit


1,888



1,888Preference Units


509



509Retained Earnings


171



107Accumulated Other Comprehensive Loss


(370
)


(385
)Total Member's Equity


2,198



2,119TOTAL LIABILITIES AND MEMBER'S EQUITY

$
7,223


$
6,826See disclosures regarding PSEG Energy Holdings LLC
included in the Notes to Consolidated Financial Statements.
14

PSEG ENERGY HOLDINGS LLCCONSOLIDATED STATEMENTS OF CASH FLOWS
For The Six Months Ended
June 30,2003

2002(Millions)
(Unaudited)CASH FLOWS FROM OPERATING ACTIVITIESNet Income (Loss)

$
75


$
(462
)Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:Write-down of Project Investment


—



506Cumulative Effect of a Change in Accounting Principle, net of tax


—



120Loss on Disposal of Discontinued Operations, net of tax


9



34Depreciation and Amortization


29



20Deferred Income Taxes (Other than Leases)


(8
)


(177
)Leveraged Lease Income, Adjusted for Rents Received


35



48Investment Distributions


2



4Change in Fair Value of Derivative Financial Instruments


12



(2
)Undistributed Earnings from Affiliates


(3
)


(17
)Net Gain on Investments


(40
)


(9
)Foreign Currency Transaction (Gain) Loss


(1
)


69Proceeds on Withdrawal from Partnership


45



47Net Changes in Certain Current Assets and Liabilities:Accounts Receivable


11



(105
)Accounts Payable


(97
)


(38
)Other Current Assets and Liabilities


23



(25
)Other


11



11Net Cash Provided By Operating Activities


103



24CASH FLOWS FROM INVESTING ACTIVITIESAdditions to Property, Plant and Equipment


(152
)


(183
)Investments in Joint Ventures and Partnerships


(17
)


(152
)Investment in Capital Leases


—



(31
)Return of Capital from Partnerships


2



90Change in Note Receivable—Affiliated Company


(69
)


—Other


15



(83
)Net Cash Used In Investing Activities


(221
)


(359
)CASH FLOWS FROM FINANCING ACTIVITIESProceeds from Capital Contributions


—



200Net Change in Short-Term Debt


45



21Cash Dividends Paid


(11
)


(11
)Net Decrease in Short-Term Affiliate Borrowings


—



(38
)Proceeds from Project-Level Non-Recourse Long-Term Debt


322



111Proceeds from Sale of Senior Notes


343



134Repayment of Medium-Term and Project-Level Non-Recourse Debt


(575
)


(98
)Other


(8
)


2Net Cash Provided By Financing Activities


116



321Effect of Exchange Rate Changes


—



(2
)Net Change In Cash and Cash Equivalents


(2
)


(16
)Cash and Cash Equivalents at Beginning of Period


104



54Cash and Cash Equivalents at End of Period

$
102


$
38Supplemental Disclosure of Cash Flow Information:Income Tax Receipts

$
(42
)

$
(14
)Interest Paid, Net of Amounts Capitalized

$
57


$
87See disclosures regarding PSEG Energy Holdings LLC
included in the Notes to Consolidated Financial Statements.
15
NOTES TO 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 LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and makes no representations as to any other company.
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).
PSE&G
PSE&G is an operating public utility providing electric and gas transmission and distribution service in certain areas within the State of New Jersey. PSE&G owns PSE&G Transition Funding LLC, a bankruptcy remote entity established for the purpose of purchasing intangible transition property and issuing transition bonds.
Power
Power
  is a multi-regional wholesale energy supply business that optimizes the value
  of its portfolio of electric generation assets, gas supply contracts and electric
  and gas supply obligations by integrating the management of this portfolio with
  its energy trading and risk management functions. Power has three principal
  direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC
  (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Power also has
  a finance company subsidiary, PSEG Power Capital Investment Co., which provides
  certain financing for Power and its subsidiaries.
Energy Holdings
Energy Holdings is the parent of PSEG Global LLC (Global), which invests and participates in the development and operation of international and domestic projects in the generation and distribution of energy, which include cogeneration and independent power production facilities and electric distribution companies; PSEG Resources LLC (Resources), which makes investments primarily in energy-related leveraged leases; PSEG Energy Technologies Inc. (Energy Technologies), presented as discontinued operations, which provided energy-related services and construction to industrial and commercial customers; Enterprise Group Development Corporation (EGDC), a commercial real estate property management business which has been conducting a controlled exit from this business since 1993; PSEG Capital Corporation (PSEG Capital), which
served as a financing vehicle for Energy Holdings' subsidiaries and is in the process of dissolution; and Enterprise Capital Funding Corporation, which is currently inactive and is also in the process of dissolution.
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 generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. However, in the opinion of management, the disclosures herein are adequate to make the information presented not misleading. These consolidated financial statements and Notes
16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
to Consolidated Financial Statements (Notes) should be read in conjunction with and update and supplement matters discussed in the respective 2002 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2003.
The unaudited 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 consolidated balance sheets were derived from the audited consolidated financial statements included in the 2002 Annual Report on Form 10-K. Certain reclassifications of prior period data have been made to conform with the current presentation.
Note 2. New Accounting Standards
Statement of Financial Accounting Standards (SFAS) No. 142, ''Goodwill and Other Intangible Assets'' (SFAS 142)
PSEG, PSE&G, Power and Energy Holdings
On January 1, 2002, PSEG, PSE&G, Power and Energy Holdings each adopted SFAS 142. Under this standard, PSEG, PSE&G, Power and Energy Holdings were required to complete an impairment analysis of goodwill before June 30, 2002 and record any required impairment retroactive to January 1, 2002. Under SFAS 142, goodwill is considered a nonamortizable asset and is subject to an annual review for impairment and an interim review when certain events or changes in circumstances occur. At the time of adoption, PSE&G had no goodwill. The effect of no longer amortizing goodwill on an annual basis was not material to PSEG's or Power's financial position and results of operations upon adoption.
Power and Energy Holdings evaluated the recoverability of the recorded amount of goodwill based on certain operating and financial factors. Such impairment testing included discounted cash flow tests, which require broad assumptions and significant judgment to be exercised by management.
In addition to goodwill, PSEG's total intangible assets as of June 30, 2003 and December 31, 2002 were $206 million, all of which are not subject to amortization, including $114 million, $52 million and $40 million related to defined benefit pension plans, emissions allowances, which are expensed as used, and various access rights, respectively.
PSE&G
As of June 30, 2003 and December 31, 2002, PSE&G had intangible assets relating to its defined benefit pension plans totaling $60 million. These intangible assets are not subject to amortization.
Power
In addition to goodwill, as of June 30, 2003 and December 31, 2002, Power's intangible assets were $125 million, of which $33 million, $52 million and $40 million, related to its defined benefit pension plans, emissions allowances, which are expensed as used, and various access rights at its Albany Station, respectively.
Energy Holdings
On January 1, 2002, Energy Holdings recorded the results of its evaluation of the effect of SFAS 142. The total amount of goodwill impairments was $120 million, net of tax of $66 million.
As of June 30, 2003 and December 31, 2002, the remaining carrying value of Energy Holdings' goodwill was $426 million and $436 million, respectively, as displayed in the table below.
As of
  June 30, 2003 and December 31, 2002, Energy Holdings' pro-rata share of the
  remaining goodwill included on the balance sheets of its equity method investees
  totaled $300 million and $287 million, respectively. In accordance with generally
  accepted accounting principles, such goodwill is not consolidated on the Energy
  Holdings' Consolidated Balance Sheets.
17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
In addition to goodwill, Energy Holdings has an intangible asset related to its defined benefit pension plans, which is not subject to amortization. This intangible asset totaled $5 million as of June 30, 2003 and December 31, 2002.
Power and Energy Holdings
As of June 30, 2003 and December 31, 2002, Power and Energy Holdings' goodwill and pro-rata share of goodwill in equity method investments was as follows:
As ofJune 30,
2003

December 31,
2002(Millions)Consolidated InvestmentsEnergy Holdings—GlobalSociedad Austral de Electricidad S.A. (SAESA) (A)

$
287


$
290Empresa de Electricidad de los Andes S.A. (Electroandes)(B)


133



140Elektrocieplownia Chorzow Sp. Z o.o. (ELCHO)


6



6Total Energy Holdings—Global


426



436Power—Albany Steam Station


16



16Total PSEG Consolidated Goodwill


442



452Pro-Rata Share of Equity Method InvestmentsEnergy Holdings—GlobalRio Grande Energia (RGE) (A)


72



60Chilquinta Energia S.A. (Chilquinta)


164



163Luz del Sur S.A.A


39



39Kalaeloa


25



25Pro-Rata Share of Equity Investment Goodwill


300



287Total PSEG Goodwill

$
742


$
739
(A)

Changes in goodwill relate to changes in foreign exchange rates.(B)

Changes in goodwill at Electroandes relate to purchase price allocation adjustments.SFAS No. 143, ''Accounting for Asset Retirement Obligations'' (SFAS 143)
PSEG, PSE&G, Power and Energy Holdings
Effective January 1, 2003, PSEG, PSE&G, Power and Energy Holdings each adopted SFAS 143. SFAS 143 addresses accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract.
Under SFAS 143, a company must initially recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred and concurrently capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. A company is required to subsequently accrete that asset retirement cost to expense over its useful life. In periods subsequent to initial measurement, an entity is required to recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either the timing or the amount of the originally estimated cash flows. Changes in the liability due to accretion will be charged to Operation and Maintenance expense on the Consolidated Statements of Operations, whereas
18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
changes due to the timing or amount of cash flows will be an adjustment to the carrying amount of the related asset. See Note 3. Adoption of SFAS 143 for additional information.
Emerging Issues Task Force (EITF) Issue No. 02-3, ''Accounting for Contracts Involved in Energy Trading and Risk Management Activities'' (EITF 02-3)
PSEG and Power
EITF 02-3 requires all gains and losses on energy trading derivatives to be reported on a net basis. Also, energy trading contracts that are not derivatives will no longer be marked to market. Instead, settlement accounting will be used. EITF 02-3 was effective for new contracts entered into on or after October 25, 2002. For contracts entered into prior to October 25, 2002, EITF 02-3 was effective January 1, 2003. Substantially all of Power's energy contracts qualify as derivatives under SFAS No. 133, ''Accounting for Derivative Instruments and Hedging Activities'' (SFAS 133) and will therefore continue to be marked to market. The impact of implementing these rules had no effect on PSEG's or Power's earnings.
Financial Interpretation (FIN) No. 46, ''Consolidation of Variable Interest Entities (VIE)'' (FIN 46)
PSEG, PSE&G, Power and Energy Holdings
FIN 46 clarifies the application of Accounting Research Bulletin No. 51, ''Consolidated Financial Statements'', to certain entities in which equity investors do not have the characteristics of a controlling financial interest. Because a controlling financial interest in an entity may be achieved through arrangements that do not involve voting interests, FIN 46 sets forth specific requirements with respect to consolidation, measurement and disclosure of such relationships. Disclosure requirements for existing qualifying entities are effective for financial statements issued after January 31, 2003. All enterprises with VIEs created after February 1, 2003, are required to apply the provisions of FIN 46 no later than the beginning of the first interim period beginning after June 15, 2003. PSEG, PSE&G, Power and Energy
Holdings are still evaluating this guidance.
SFAS No. 149, ''Amendment of Statement 133 on Derivative Instruments and Hedging Activities'' (SFAS 149)
PSEG, PSE&G, Power and Energy Holdings
SFAS 149 amends and clarifies the accounting guidance for derivative instruments (including certain derivative instruments embedded in other contracts) and hedging activities that fall within the scope of SFAS 133.
In particular, SFAS 149 clarifies circumstances under which a contract with an initial net investment meets the characteristic of a derivative discussed in SFAS 133, clarifies when a derivative contains a financing component and amends the definition of an underlying to conform it to language used in FIN No. 45, ''Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others''.
Additionally, SFAS 149 amends SFAS 133's criteria for electing the normal purchase and sale exception, which exempts certain derivatives that meet the normal purchase and sales criteria, from fair value reporting. The new guidance allows ''normal'' treatment for a power purchase or sale agreement (whether a forward, an option or combination of both) that is a capacity contract, as defined, even if the contract is closed out before maturity. However, any non-power commodity contract (e.g. gas contracts) and non-capacity power contract closed out before maturity will be ineligible for ''normal'' treatment and could result in those contracts being marked to market.
19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. Although PSEG, PSE&G, Power and Energy Holdings do not expect a material impact on their respective financial statements due to the adoption of these rules, no assurances can be given.
SFAS No. 150, ''Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity'' (SFAS 150)
PSEG and PSE&G
SFAS 150, which is effective July 1, 2003, establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. Many of these instruments that were previously presented as equity or as mezzanine instruments (between the liabilities and the equity section) will now be recorded as liabilities. SFAS 150 requires an issuer to classify qualifying instruments issued in the form of shares that are mandatorily redeemable as liabilities. Those items will no longer be presented as mezzanine instruments on the Consolidated Balance Sheets.
As of June 30, 2003, the following instruments are included in Preferred Securities on PSEG's and PSE&G's respective Consolidated Balance Sheets between Long-Term Debt and Common Equity.
Shares
Outstanding

As of
June 30, 2003(Millions)PSEG (Parent)PSEG Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures7.44%


9,000,000


$
225Floating Rate


150,000



1507.25%


6,000,000



1508.75%


7,200,000



180PSEG Participating Units10.25%


9,200,000



460Total PSEG (Parent)






1,165PSE&GPSE&G 8.00% Monthly Guaranteed Preferred Beneficial Interest in Subordinated Debentures


2,400,000



60PSE&G Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's 8.125% Subordinated            Debentures


3,800,000



95Total PSE&G






155Total PSEG Consolidated





$
1,320Effective July 1, 2003, these instruments will be presented separately in Noncurrent Liabilities on the Consolidated Balance Sheets and dividend payments on these instruments will be recorded as Interest Expense on the Consolidated Statements of Operations and be included in the Interest Paid supplemental disclosure on the Consolidated Statements of Cash Flows.
Other
PSEG, PSE&G, Power and Energy Holdings
In January 2001, PSEG, PSE&G, Power and Energy Holdings each adopted SFAS 133. In accordance with SFAS 133, all derivative instruments are recognized on the balance sheet at their fair values. In relation to this standard, the Financial Accounting Standards Board (FASB) Derivative Implementation Group (DIG) issued certain interpretive guidance, including DIG Issue C-11 that
20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
relates to contracts which include broad market indices (e.g., Consumer Price Index). That interpretation sets forth the guidelines under which a contract could qualify as a normal purchase or sale under SFAS 133. In 2003, the FASB issued DIG Issue C-20 to amend the previous interpretation stating that the phrase ''not clearly and closely related to the asset being sold or purchased'' should involve an analysis of both qualitative and quantitative considerations. PSE&G, Power and Energy Holdings have reviewed their respective contracts and each have determined that there will be no impact resulting from the adoption of this interpretation.
Note 3. Adoption of SFAS 143
PSEG, PSE&G and Power
In the first quarter of 2003, Power completed its review of potential obligations under SFAS 143 and determined that these obligations are primarily related to the decommissioning of its nuclear power plants. Power's liability as of December 31, 2002 was approximately $766 million, which equaled the balance of its Nuclear Decommissioning Trust (NDT) Fund, as discussed below. As of January 1, 2003, as calculated under SFAS 143, the liability was approximately $261 million and the asset was approximately $50 million. This asset and liability were calculated using a probability-weighted average of multiple scenarios. The scenarios were each based on estimated cash flows, which were discounted using Power's risk-adjusted interest rate at the required effective date of the standard and considering the expected time period
of the cash outflows. The scenarios included estimates for inflation, contingencies and assumptions related to the timing of decommissioning costs, using the current license lives for each unit as well as early shutdown and license extensions scenarios. Management believes that these assumptions, which had a material impact on the calculation of the liability, and therefore the cumulative effect adjustment resulting from the adoption of this new accounting standard, were reasonable and appropriate.
In addition to the $261 million nuclear decommissioning liability, Power identified certain other legal obligations that meet certain of the criteria of SFAS 143, which at this time are not quantifiable but could be material in the future. These obligations relate to certain industrial establishments subject to the New Jersey Industrial Site Recovery Act (ISRA), underground storage tanks subject to closure requirements, permits and authorizations, the restoration of an area to be occupied by a reservoir at the end of its useful life, an obligation to retire certain plants prior to the start up of a new plant and the demolition and restoration of certain other plant sites once they are no longer in service.
Power also had $131 million of cost of removal liabilities, as of December 31, 2002, which did not meet the requirements of an asset retirement obligation (ARO) and were therefore reversed and included in the Cumulative Effect of a Change in Accounting Principle recorded in the first quarter of 2003.
As a result of reducing the existing nuclear decommissioning and cost of removal liabilities to their fair value and recording an ARO asset, PSEG and Power recorded a Cumulative Effect of a Change in Accounting Principle of $370 million after-tax in the first quarter of 2003. Of this amount, $292 million (after-tax) relates to Nuclear and $78 million (after-tax) relates to the cost of removal liabilities for the fossil units being reversed.
In July 2003, the New Jersey Board of Public Utilities (BPU) issued an oral decision determining that PSE&G's customers will no longer pay, and do not have responsibility for nuclear decommissioning costs after July 31, 2003. Beginning August 1, 2003, the responsibility rests with the owners of the nuclear power plants. The BPU also indicated in the oral decision that PSE&G is required to refund $30 million, pre-tax, related to revenues previously collected through the SBC for nuclear decommissioning, however, the refund will not affect any previously collected funds deposited into external trusts. For additional information relating to the oral decision issued in connection with PSE&G's Electric Base Rate Case, see Note 16. Subsequent Events.
21

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
PSE&G
PSE&G has identified certain other legal obligations that meet the criteria of SFAS 143, which at this time are not quantifiable and therefore are unable to be recorded. These obligations relate to certain industrial establishments subject to the ISRA, underground storage tanks subject to closure requirements, leases and licenses, and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service.
As of January 1, 2003, PSE&G had no legal liabilities, as contemplated under SFAS 143, recorded on its Consolidated Balance Sheets and, therefore, the effect of adoption did not result in an adjustment to the Consolidated Financial Statements. PSE&G does, however, have cost of removal liabilities embedded within Accumulated Depreciation and Amortization pursuant to SFAS No. 71, ''Accounting for the Effects of Certain Types of Regulation'' (SFAS 71). Since PSE&G is a regulated enterprise, these amounts, which total approximately $358 million as of June 30, 2003, continue to be recorded and presented in Accumulated Depreciation and Amortization on the Consolidated Balance Sheets.
Energy Holdings
Energy Holdings has identified certain legal obligations that meet the criteria of SFAS 143. However, it has determined that they are not material to its financial position, results of operations or net cash flows.
Effect on the NDT Fund
Power
Prior to the adoption of SFAS 143, amounts collected from PSE&G customers that have been deposited into the NDT Fund and realized and unrealized gains and losses in the trust were all recorded as changes in the NDT Fund with an offsetting charge to the nuclear decommissioning liability. Due to the oral decision issued by the BPU that PSE&G's customers will no longer fund the NDT Fund, deferral accounting is no longer appropriate. In anticipation of this decision, beginning January 1, 2003, realized gains and losses were recorded in earnings and unrealized gains and losses were recorded as a component of Other Comprehensive Income (OCI), as appropriate under SFAS No. 115, ''Accounting for Certain Investments in Debt and Equity Securities'' (SFAS 115). Additionally, because deferral accounting was no longer appropriate,
as of January 1, 2003, Power had expensed approximately $40 million of the $68 million of pre-tax unrealized losses on securities in the NDT Fund which were other than temporarily impaired and recorded this amount against earnings in the Cumulative Effect of a Change in an Accounting Principle.
Note 4. Earnings Per Share
PSEG
Diluted earnings per share are 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. The following table shows the effect of these stock
22

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
options on the weighted average number of shares outstanding used in calculating diluted earnings per share:
Quarter Ended June 30,

Six Months Ended June 30,2003

2003

2002

2002

2003

2003

2002

2002Basic

Diluted

Basic

Diluted

Basic

Diluted

Basic

DilutedEPS Numerator:Earnings (Loss) (Millions)Continuing Operations

$
150


$
150


$
(227
)

$
(227
)

$
471


$
471


$
(46
)

$
(46
)Discontinued Operations


(2
)


(2
)


(37
)


(37
)


(17
)


(17
)


(38
)


(38
)Extraordinary Item


(18
)


(18
)


—



—



(18
)


(18
)


—



—Cumulative Effect of a Change in Accounting Principle


—



—



—



—



370



370



(120
)


(120
)Net Income (Loss)

$
130


$
130


$
(264
)

$
(264
)

$
806


$
806


$
(204
)

$
(204
)EPS Denominator (Thousands):Weighted Average Common Shares Outstanding


225,910



225,910



206,246



206,246



225,627



225,627



206,049



206,049Effect of Stock Options


—



672



—



681



—



481



—



582Total Shares


225,910



226,582



206,246



206,927



225,627



226,108



206,049



206,631Earnings (Loss) per share:Continuing Operations

$
0.67


$
0.66


$
(1.10
)

$
(1.10
)

$
2.09


$
2.09


$
(0.22
)

$
(0.22
)Discontinued Operations


(0.01
)


(0.01
)


(0.18
)


(0.18
)


(0.08
)


(0.08
)


(0.19
)


(0.19
)Extraordinary Item


(0.08
)


(0.08
)


—



—



(0.08
)


(0.08
)


—



—Cumulative Effect of a Change in Accounting Principle


—



—



—



—



1.64



1.64



(0.58
)


(0.58
)Net Income (Loss)

$
0.58


$
0.57


$
(1.28
)

$
(1.28
)

$
3.57


$
3.57


$
(0.99
)

$
(0.99
)There
  were approximately 5.4 million stock options and 9.2 million participating units
  not included in the weighted average common shares calculation used for diluted
  earnings per share due to their antidilutive effect for the quarter ended June
  30, 2003.
Note 5. Discontinued Operations
Energy Holdings
Energy Technologies' Investments
Energy Technologies is comprised primarily of its remaining heating, ventilating and air conditioning (HVAC) and mechanical operating companies. In June 2002, Energy Holdings adopted a plan to sell its HVAC/mechanical operating companies. The HVAC/mechanical operating companies meet the criteria for classification as components of discontinued operations and all prior periods have been reclassified to conform to the current year's presentation.
Energy Holdings continues to re-evaluate the carrying value of Energy Technologies' assets and liabilities to determine if current market conditions require additional write-downs to fair value less cost to sell. For the six months ended June 30, 2003, Energy Holdings recorded an additional loss on disposal of Energy Technologies of $9 million, net of a $2 million tax benefit. Of the 11 HVAC companies held for sale in 2002, eight were sold by June 30, 2003. In July 2003 two additional companies were sold at book value and a letter of intent has been entered into to sell the final company. The sale of the remaining company has been delayed due to market conditions, however, Energy Holdings expects the sale to be completed by the end of the third quarter of 2003.
Energy Holdings' remaining investment position in Energy Technologies as of June 30, 2003 consists of $86 million in assets and $49 million in liabilities. Of the $86 million in assets approximately $31 million relates to tax assets associated with tax benefits from the sale of the HVAC companies, with the remaining balance relating primarily to its investment in the remaining three HVAC companies.
23

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
The revenues and results of operations of Energy Technologies for the quarter and six months ended June 30, 2003 and 2002 are displayed below:
Quarter Ended
June 30,

Six Months Ended
June 30,2003

2002

2003

2002(Millions)Operating Revenues

$
12


$
91


$
61


$
186Pre-Tax Operating Loss

$
(4
)

$
(9
)

$
(13
)

$
(15
)Net Loss

$
(2
)

$
(5
)

$
(8
)

$
(9
)The carrying amounts of the assets and liabilities of the HVAC/mechanical operating companies, as of June 30, 2003 and December 31, 2002 are summarized in the following table:
As ofJune 30,
2003

December 31,
2002(Millions)Current Assets

$
10


$
82Noncurrent Assets


21



25Total Assets

$
31


$
107Current Liabilities

$
15


$
85Noncurrent Liabilities


5



5Long-Term Debt


11



5Total Liabilities

$
31


$
95Tanir Bavi Power Company Ltd. (Tanir Bavi)
In the fourth quarter of 2002, Global sold its 74% interest in the Tanir Bavi generating facility in India for approximately $45 million. The facility met the criteria for classification as a component of discontinued operations and all prior periods were reclassified to conform to that presentation. The operating results of Tanir Bavi for the quarter and six months ended June 30, 2002 are summarized below.
Quarter Ended
June 30, 2002

Six Months Ended
June 30, 2002(Millions)Operating Revenues

$
32


$
61Pre-Tax Operating Income

$
3


$
9Net Income

$
2


$
524

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 6. Regulatory Assets and Liabilities
PSEG and PSE&G
As of June 30, 2003 and December 31, 2002, respectively, PSEG and PSE&G had deferred the following regulatory assets and liabilities on the Consolidated Balance Sheets:
As ofJune 30,
2003

December 31,
2002

Recovery/Refund Period(Millions)Regulatory AssetsSecuritized Stranded Costs

$
3,782


$
3,885



Through December 2015(1)(2)Deferred Income Taxes


371



326



VariousOPEB-Related Costs


183



193



Through December 2012(2)Manufactured Gas Plant Remediation Costs


115



115



Various(2)Unamortized Loss on Reacquired Debt and Debt Expense


84



86



Over remaining debt life(1)Underrecovered Gas Costs


110



154



Through September 2004(1)Non-Utility Generation Transition Charge (NTC)


68



—



Through December 31, 2005(1)Unrealized Losses on Interest Rate Swap


73



66



Through December 2015(2)Repair Allowance Taxes


97



93



Through August 2013(1)(2)Decontamination and Decommissioning Costs


21



21



Through December 2007(2)Plant and Regulatory Study Costs


24



25



Through December 2021(2)Regulatory Restructuring Costs


42



33



Through August 2013(1)(2)Other


5



5Total Regulatory Assets

$
4,975


$
5,002Regulatory LiabilitiesExcess Depreciation Reserve

$
179


$
171



Through December 31, 2005(2)NTC


—



27



Through December 31, 2005(1)Societal Benefits Charges (SBC)


177



50



Through December 31, 2005(1)(2)Other


6



4



Various(1)Total Regulatory Liabilities

$
362


$
252(1)
    
    Recovered/Refunded with
      interest(2)
    
    Recoverable/Refundable
      per specific rate orderIn July 2003, the BPU issued an oral decision in PSE&G's Electric Base Rate Case. The descriptions below supplement the information contained in Note 7. Regulatory Assets and Liabilities in the 2002 Annual Report on Form 10-K to reflect the effects of changes resulting from the oral decision. For additional information relating to the oral decision, see Note 16. Subsequent Events.
SBC:The SBC, as authorized by the BPU and the Energy Competition Act, includes costs related to PSE&G's electric and gas business as follows: 1) the universal service fund; 2) nuclear plant decommissioning; 3) demand side management (DSM) programs; 4) social programs which include bad debt expense; 5) consumer education; and 6) Market Transition Charge (MTC) over recovery. All components except for MTC accrue interest. Effective August 1, 2003, nuclear plant decommissioning will no longer be included in the electric SBC.
NTC:This clause was established by the Energy Competition Act to account for above market costs related to non-utility generation (NUG) contracts, as approved by the BPU. Costs or benefits associated with the restructuring of these contracts are deferred. This clause also includes Basic Generation Service (BGS) costs in excess of current rates, as approved by the BPU.
Repair Allowance Taxes:This represents tax, interest and carrying charges relating to disallowed tax deductions for repair allowance as authorized by the BPU with recovery over 10 years effective August 1, 2003.
Regulatory Restructuring Costs:These are costs related to the restructuring of the energy industry in New Jersey through the Energy Competition Act and include such items as the system design work
25

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
necessary to transition PSE&G to a transmission and distribution only company, as well as costs incurred to transfer and establish the generation function as a separate corporate entity with recovery over 10 years beginning August 1, 2003.
Excess Depreciation Reserve:As required by the BPU in 1999, PSE&G reduced its depreciation reserve for its electric distribution assets and recorded such amount as a regulatory liability. The remaining amount of the original liability as of June 30, 2003 is $24 million, which will be amortized in July 2003. In June 2003, PSE&G recorded an additional $155 million liability as a result of the oral decision issued by the BPU in PSE&G's Electric Base Rate Case. This $155 million will be amortized from August 1, 2003 through December 31, 2005.
Note 7. Commitments and Contingent Liabilities
Guaranteed Obligations
Power
Power has guaranteed certain commodity related transactions for its subsidiary, ER&T, which is involved in energy marketing activities. These guarantees were provided to counterparties in order to facilitate physical and financial agreements in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. These Power guarantees support the current exposure, interest and other costs on sums due and payable by ER&T under these agreements. Guarantees offered for trading and marketing cover the granting of lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can go either direction. The face value of the guarantees outstanding on June 30, 2003 and December 31, 2002 was $1.5 billion and $1.1 billion, respectively. In order
for Power to experience a liability of $1.5 billion, ER&T would have to fully utilize the credit granted to it by every counterparty to whom Power has provided a guarantee and all of ER&T's contracts would have to be ''out-of-the-money'' (if the contracts are terminated, Power would owe money to the counterparties). The probability of all contracts at ER&T being simultaneously ''out-of-the-money'' is highly unlikely. For this reason, the current exposure at any point in time is a more meaningful representation of the potential liability to Power under these guarantees. The current exposure consists of the net of accounts receivable and accounts payable (AR/AP) and the forward value on open positions, less any margins posted. The current exposure from such liabilities was $313 million and $268 million as of June 30, 2003 and December 31, 2002, respectively. Of the $313
million, $240 million is recorded on Power's Consolidated Balance Sheets as of June 30, 2003. A significant portion of the current exposure under such guarantees is attributable to the load contracts that expire on July 31, 2003 and the overlap of the mark-to-market exposure of those contracts and the contracts recently signed through the auction for the period beginning August 1, 2003. The load contracts are accounted for on a settlement basis. As energy is delivered under all of these contracts, the portion of Power's exposure under such guarantees will decrease.
In addition,
  all Master Agreements and other supply contracts, including Power's BGS-related
  load contracts, contain margin and/or other collateral requirements that, as
  of June 30, 2003, could require Power to post additional collateral of
  approximately $353 million if a) Power were to lose its investment grade credit
  rating, and b) all counterparties with whom Power is ''out-of-the money'' under
  such contracts, were entitled to and called for collateral.
In addition, Power has issued an approximate $40 million guarantee on behalf of a third party's performance under a BGS contract expiring in July 2003. Because Power supplies the third party with the energy needed for performance under the guarantee, it is highly unlikely Power would incur any liabilities in connection with the guarantee. As of June 30, 2003, there were no amounts recorded in connection with the guarantee.
Also, Power has issued a guarantee relating to potential future environmental liabilities at its Connecticut facilities to the State regulatory bodies.
26

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
As of June 30, 2003, letters of credit issued by Power were outstanding in the amount of approximately $86 million in support of various contractual obligations, environmental liabilities and to satisfy trading collateral obligations.
Power has also guaranteed equity contributions by its subsidiaries relating to the construction of its Lawrenceburg, Indiana and Waterford, Ohio facilities. Should Power lose its investment grade credit rating, it would be required to post $128 million in letters of credit for those projects. Such guarantees will be cancelled upon satisfaction of Power's equity commitments, which are included in its anticipated capital expenditures for the remainder of 2003.
Energy Holdings
Energy Holdings and/or Global have guaranteed certain obligations of their subsidiaries or affiliates, including the successful completion, performance or other obligations related to certain projects in an aggregate amount of approximately $261 million as of June 30, 2003. The guarantees include a $61 million equity commitment for ELCHO in Poland, a $49 million standby equity commitment for Skawina CHP Plant in Poland (Skawina), $17 million of various guarantees for Dhofar Power Company in Oman, and a $25 million contingent guarantee related to debt service obligations of Chilquinta Energia Finance LLC in connection with electric distribution companies in Chile and Peru. Additional guarantees consist of a $38 million leasing agreement guarantee for Prisma in Italy and various other guarantees comprising the remaining
$71 million. Approximately $61 million of such guarantees will be cancelled upon satisfaction of Global's equity commitments, which are included in Energy Holdings' anticipated capital expenditures for the remainder of 2003.
In the normal course of business, Energy Technologies secures construction obligations with performance bonds issued by insurance companies. As of June 30, 2003, Energy Technologies had $209 million of such bonds outstanding, of which $34 million related to ongoing construction projects. The performance bonds are not included in the $261 million of guaranteed obligations discussed above. In January 2003, Energy Holdings provided an indemnification agreement and $31 million of letters of credit in support of Energy Technologies' obligations. As of June 30, 2003, $25 million in letters of credit remain, including obligations relating to certain of the HVAC companies that have been previously sold. These amounts are expected to decrease over time as each of the HVAC companies completes the work in process
or transfers ownership to other companies.
Environmental Matters
PSE&G and Power
Hazardous Waste
The New Jersey Department of Environmental Protection (NJDEP) regulations concerning site investigation and remediation require an ecological evaluation of potential injuries to natural resources in connection with a remedial investigation of contaminated sites. The NJDEP is presently working with the energy industry to develop procedures for implementing these regulations. These regulations may substantially increase the costs of remedial investigations and remediations, where necessary, particularly at sites situated on surface water bodies. PSE&G, Power and predecessor companies own or owned and/or operate or operated certain facilities situated on surface water bodies, certain of which are currently the subject of remedial activities. The financial impact of these regulations on these projects is not currently
estimable. PSE&G and Power do not anticipate that the 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 CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
PSE&G
PSE&G Manufactured Gas Plant (MGP) Remediation Program
PSE&G is currently working with the NJDEP under a program (Remediation Program) to assess, investigate and, if necessary, remediate environmental conditions at PSE&G's former MGP sites. To date, 38 sites have been identified. The Remediation Program is periodically reviewed and revised by PSE&G based on regulatory requirements, experience with the Remediation Program and available remediation technologies. The long-term costs of the Remediation Program cannot be reasonably estimated, but experience to date indicates that at least $20 million per year could be incurred over a period of about 30 years since inception of the program in 1988 and that the overall cost could be material. The costs for this remediation effort are recovered through SBC charges to utility customers.
As of June 30, 2003, PSE&G's estimated net liability for remediation costs through 2005 aggregated $115 million. Expenditures beyond 2005 cannot be reasonably estimated and are therefore not accrued.
Passaic River Site
The United States Environmental Protection Agency (EPA) has determined that a nine 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 and that, to date, at least thirteen corporations, including PSE&G, may be potentially liable for performing required remedial actions to address potential environmental pollution in the Passaic River ''facility.''
PSE&G and certain of its predecessors conducted industrial operations at properties within the Passaic River facility. The operations included one operating electric generating station, one former generating station and four former MGPs. PSE&G's costs to clean up former MGPs are recoverable from utility customers through the SBC. PSE&G has sold the site of the former generating station and obtained releases and indemnities for liabilities arising out of the site in connection with the sale. The operating generating station was transferred to Power in August 2000. PSE&G cannot predict what action, if any, the EPA or any third party may take against PSE&G with respect to this matter, or in such an event, what costs may be incurred to address any such claims. However, such costs may be material.
Power
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
The EPA and the NJDEP issued a demand in March 2000 under the Federal Clean Air Act (CAA) requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal burning units were implemented in accordance with applicable PSD/NSR regulations. Power completed its response to the information request in November 2000. In January 2002, Power reached an agreement with New Jersey and the federal government to resolve allegations of noncompliance with federal and New Jersey PSD/NSR regulations. Under that agreement, over the course of 10 years, Power must install advanced air pollution controls that are designed to reduce emissions of Nitrogen Oxide (NOx), Sulfur Dioxide (SO2), particulate matter and mercury.
The estimated cost of the program at the time of the settlement was $337 million to be incurred through 2011. Power also paid a $1.4 million civil penalty and has agreed to spend up to $6 million on supplemental environmental projects. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved the dispute over Bergen 2 regarding the applicability of PSD requirements and allowed construction of the unit to be completed and operation to commence.
Power has notified the EPA and the NJDEP that it is evaluating the continued operation of the Hudson coal unit beyond 2006, in light of changes in the energy and capacity markets and increases in the cost of pollution control equipment and other necessary modifications. Power is also exploring the
28

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
feasibility of installing less costly pollution control equipment at the Hudson coal unit to satisfy the requirements of its agreement with the EPA and the NJDEP. A decision is expected to be made in 2003 as to the Hudson unit's continued operation. The related costs associated with these modifications have not been included in Power's capital expenditure projections.
New Generation and Development
Power and Energy Holdings
Completion of the projects, discussed below, within the estimated time frames and cost estimates cannot be assured. Construction delays, cost increases and various other factors could result in changes in the operational dates or ultimate costs to complete.
Power
Through an indirect, wholly-owned subsidiary, Power is developing the Bethlehem Energy Center, a 763 MW combined-cycle power plant that will replace the 376 MW Albany, NY Steam Station. Total costs for this project are expected to be approximately $500 million with expenditures to date of approximately $248 million. Construction began in 2002 with the expected completion date in 2005.
Power is constructing a 1,220 MW combined-cycle generation plant at Linden, New Jersey. Total costs are estimated at approximately $750 million with expenditures to date of approximately $587 million. Completion is expected in 2005.
Power is constructing, through indirect, wholly-owned subsidiaries, two natural gas-fired combined-cycle electric generation plants in Waterford, Ohio (821 MW) and Lawrenceburg, Indiana (1,096 MW) at an estimated aggregate total cost of $1.2 billion. Total expenditures to date on these projects have been approximately $1.0 billion. The required estimated equity investment in these projects is approximately $400 million, with the remainder being financed with non-recourse bank financing. As of June 30, 2003, approximately $337 million of equity has been invested in these projects. In connection with these projects, ER&T has entered into a five-year tolling agreement pursuant to which it is obligated to purchase the output of these facilities. Based on current prices, the purchase price under this contract
is currently above market. ER&T may terminate the agreement upon repayment of the current financing scheduled for August 2005. Additional equity investments may be required if the proceeds received from ER&T under this tolling agreement are not sufficient to cover the required payments under the bank financing. The Waterford facility is currently scheduled to achieve commercial operation in August 2003. The Lawrenceburg facility is currently scheduled to achieve commercial operation in the fourth quarter of 2003.
Power also has contracts with outside parties to purchase upgraded turbines for the Salem Nuclear Generating Station (Salem) Units 1 and 2 and to purchase upgraded turbines and complete a power uprate for Hope Creek Generating Station (Hope Creek) to increase its generating capacity. The power uprate for Hope Creek is currently scheduled to be completed by 2005, assuming timely approval from the Nuclear Regulatory Commission (NRC). The turbine replacements are currently scheduled to be completed by 2004 for Salem Unit 1 and Hope Creek and 2006 for Salem Unit 2. Power's aggregate estimated costs for these projects are $210 million, with expenditures to date of approximately $61 million.
Power has commitments to purchase gas turbines and/or other services to meet its current plans to develop additional generating capacity. The aggregate amount due under these commitments is approximately $480 million, approximately $370 million of which is included in estimated costs for the projects discussed above. The approximate $110 million remaining relates to obligations to purchase hardware and services that have not been designated to any specific projects. Power is currently discussing the restructuring of these obligations. The negotiation period for restructuring these contracts has been extended from July 2003 to September 30, 2003 and Power has provided a letter of credit to the supplier for the potential penalty amount, which will expire on that date. Power believes that this
29

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
matter will be satisfactorily resolved, however, no assurances can be given. If the negotiations are unsuccessful, Power may be subject to penalties of up to $24 million.
Energy Holdings
California
GWF Energy LLC (GWF Energy), which is jointly owned by Global and Harbinger GWF LLC (Harbinger), owns and operates three peaker plants in California, including the Tracy Peaker Plant, a 170 MW facility that completed construction and achieved commercial operation under GWF Energy's power purchase agreement with the California Department of Water Resources in the second quarter of 2003.
Poland
In 2002, Global acquired a 50% interest in the 590 MW (electric) and 618 MW (thermal) coal-fired Skawina plant, located in Poland. The transaction includes Global's obligation to increase its equity interest in Skawina to approximately 65% and the obligation to offer to purchase an additional 10% from Skawina's employees, increasing Global's potential ownership interest to 75%. Global's total equity investment is expected to be approximately $105 million, including contingencies and equity commitment guarantees. Through June 30, 2003, Global's equity exposure was approximately $37 million at Skawina.
Minimum Fuel Purchase Requirements
Power
Power uses coal for certain of its fossil electric generation stations. Power purchases coal through various contracts and in the spot market for its generation plants. The total minimum purchase requirements included in these contracts amount to approximately $229 million through 2008.
Power has several long-term purchase contracts with uranium suppliers, converters, enrichers and fabricators to meet the currently projected fuel requirements for Salem and Hope Creek nuclear power plants. On average, Power has various multi-year requirements-based purchase commitments that total approximately $88 million per year to meet Salem's and Hope Creek's fuel needs. Power has been advised by Exelon Generation LLC (Exelon), the co-owner and operator of Peach Bottom Atomic Power Station (Peach Bottom), that it has similar purchase contracts to satisfy the fuel requirements for Peach Bottom.
In addition to its fuel requirement, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas. As of June 30, 2003, the total minimum purchase requirements under these contracts was approximately $1.1 billion through 2016.
Nuclear Fuel Disposal
Power
Under the Nuclear Waste Policy Act of 1982, as amended (NWPA), the Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001) per Kilowatt-hour (kWh) of nuclear generation, subject to such escalation as may be required to assure full cost recovery by the Federal government. Under the NWPA, the US 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 to be available earlier than 2010.
30

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
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). The availability of adequate spent fuel storage capacity is estimated through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power presently expects to construct an on-site storage facility that would satisfy the spent fuel storage needs of both Salem and Hope Creek through the end of their respective license lives. This construction will require certain regulatory approvals, the timely receipt of which cannot be assured. Exelon has advised Power that it has
constructed an on-site storage facility at Peach Bottom that is now licensed and operational. This on-site storage facility will satisfy Peach Bottom's fuel storage until at least 2014.
Exelon has advised Power that it had signed an agreement with the DOE applicable to Peach Bottom under which Exelon would be reimbursed for costs incurred resulting from the DOE's delay in accepting spent nuclear fuel. Under this agreement, Power's portion of Peach Bottom's Nuclear Waste Fund fees have been reduced by approximately $18 million through August 31, 2002, at which point the credits were fully utilized and covered the cost of Exelon's storage facility. In 2000, a petition was filed against the DOE in the US Court of Appeals for the Eleventh Circuit, seeking to set aside the receipt of credits by Exelon. In September 2002, the Court issued an opinion upholding the challenge by the petitioners. Under the terms of the agreement, the DOE and Exelon are required to meet and discuss alternative funding
sources for the settlement credits. The Eleventh Circuit's opinion suggests that the federal judgment fund should be available as an alternate source. If such negotiations are unsuccessful, any payments required by Power resulting from a disallowance of the previously reduced fees would be included in Energy Costs on the Consolidated Statements of Operations.
In September 2001, Nuclear filed a complaint in the US Court of Federal Claims seeking damages caused by the DOE not taking possession of spent nuclear fuel in 1998. No assurances can be given as to any damage recovery or the ultimate availability of a disposal facility.
In October 2001, Power filed a complaint in the US Court of Federal Claims, along with a number of other plaintiffs, seeking $28 million in relief from past overcharges by the DOE for enrichment services. No assurances can be given as to any damage recovery.
Other
Energy Holdings
Argentina
The shares formerly held by Global in Empresa Distribuidora La Plata S.A. (EDELAP) have been transferred to The AES Corporation. In connection with that transfer, certain contingent obligations Global had with respect to the project loans relating to EDELAP have been terminated by agreement with the lenders.
India
Global has a 20% interest in a 330 MW plant, PPN Power Generating Station (PPN) in the Indian State of Tamil Nadu. Output from the facility is sold under a long-term Power Purchase Agreement (PPA) with the Tamil Nadu Electricity Board (TNEB) which sells the power to retail end-user customers. TNEB has not made full payment to PPN for the purchase of energy under contract. The past due receivable at PPN as of June 30, 2003 was approximately $85 million, Global's share of which is approximately $8 million, net of a $9 million reserve. Global's exposure to the open receivables is included in the $40 million investment exposure discussed below.
On April 1, 2003, PPN did not receive two expected partial payments from TNEB, which resulted in PPN defaulting on a debt payment of $10 million to its project lenders. Consequently, PPN advised lenders of its inability to make the scheduled debt payment. Also, PPN has not paid working capital
31

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
interest, amounts due under letters of credit covering fuel supplies, gas supply invoices and fuel supply letters of credit due in April 2003. As a result, PPN closed the plant as of April 10, 2003. TNEB was notified of the plant closing resulting from PPN's inability to procure fuel and fund operating expenses due to non-payment by TNEB. Subsequently TNEB made adequate payments in May 2003 to enable PPN to pay its lenders and fuel suppliers. The plant restarted on May 30, 2003 and has been in operation since then. Adequate payments were also made by TNEB in June 2003 to enable PPN to meet its debt payment obligations on June 30, 2003. As a result of these issues, Energy Holdings has performed an impairment test on this investment and determined that no impairment is necessary as of June 30, 2003. If TNEB fails to make
required payments under the PPA, PPN may have further liquidity problems. Negotiations with TNEB are continuing and Energy Holdings cannot predict the outcome of this matter. Energy Holdings' investment exposure is approximately $40 million. An adverse outcome to such negotiations could potentially result in an impairment of this investment, which could be material to PSEG's and Energy Holdings' respective results of operations.
Tunisia
On April 24, 2003, Carthage Power Company (CPC) and Alstom Centrales Energetiques S.A. (Alstom) entered in an agreement settling all liquidated damages caused by the delay in construction. As per this agreement, Alstom paid to CPC an aggregate amount of approximately $17 million composed of approximately $9 million in cash, $3 million in spare parts and Alstom waived payments from Societe Tunisienne de l' Electricite et du Gaz (STEG) for contracts for equipment totaling approximately $5 million. On June 5, 2003, STEG confirmed to CPC its acceptance of the services to be provided by Alstom as settlement of its claims of liquidated damages for the delay in the start of operations.
Note 8. Risk Management
PSEG, PSE&G, Power and Energy Holdings
The operations of PSEG, PSE&G, Power and Energy Holdings are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could affect their results of operations and financial conditions. PSEG, PSE&G, Power and Energy Holdings manage exposure to these market risks through their regular operating and financing activities and, when deemed appropriate, hedge these risks through the use of derivative financial instruments. PSEG, PSE&G, Power and Energy Holdings use the term ''hedge'' to mean a strategy designed to manage risks of volatility in prices or rate movements on certain assets, liabilities or anticipated transactions and by creating a relationship in which gains or losses on derivative instruments are expected to counterbalance the
losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, PSE&G, Power and Energy Holdings use derivative instruments as risk management tools consistent with their respective business plans and prudent business practices.
Derivative Instruments and Hedging Activities
Energy Trading Contracts
Power
Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, fixed transmission rights (FTR), coal and emission allowances, in the spot, forward and futures markets, primarily in the Pennsylvania-New Jersey-Maryland Power Pool (PJM), and also in the surrounding region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana and natural gas in the producing region.
Power maintains a strategy of entering into trading positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. Power does not
32

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
engage in the practice of simultaneous trading for the purpose of increasing trading volume or revenue. 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. These contracts also involve financial transactions including swaps, options and futures.
Power marks to market its energy trading contracts in accordance with SFAS 133. As of June 30, 2003 and December 31, 2002, substantially all of these contracts had terms of two years or less. 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.
Power routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, exchange-traded futures contracts require a deposit of margin cash, the amount of which is subject to change based on market movement and in accordance with exchange rules. The amount of Power's margin deposits as of June 30, 2003 was approximately $18 million.
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 and other events. Power manages its risk of fluctuations of energy price and availability through derivative instruments, such as forward purchase contracts, swaps, options and futures.
Cash Flow Hedges
In order to hedge a portion of its forecasted energy purchases to meet its electric supply requirements, Power enters into forward purchase contracts, futures, options, swaps and FTR contracts. These contracts, in conjunction with owned electric generation capacity, are designed to cover estimated wholesale electric customer commitments. Power also forecasts the energy delivery from its generating stations based on the forward price curve movement of energy and, as a result, it enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of June 30, 2003, the fair value of these hedges was $(12) million. During the next 12 months, $7 million
of unrealized losses (net of gains) on these commodity derivatives accumulated in OCI is expected to be reclassified as earnings. As defined in SFAS 133, there was no ineffectiveness associated with these hedges since the terms of the instruments perfectly match the transaction or risk the instruments are hedging. These hedges will mature through 2004.
Effective with the transfer of PSE&G's gas contracts to Power on May 1, 2002, Power acquired all of the gas-related derivatives entered into by PSE&G. The derivatives used to hedge the forecasted purchase and sale of natural gas are designated and effective as cash flow hedges. Gains or losses from the derivatives entered into to hedge residential customer requirements are deferred and recovered from PSE&G's customers as part of the monthly billing to PSE&G. Unrealized gains or losses on the derivatives entered to hedge commercial and industrial customer requirements are recorded to OCI. There was no ineffectiveness realized on these hedges. As of June 30, 2003, the fair value of hedge instruments associated with hedging residential customer requirements was $38 million. These hedges will mature
through 2005.
33

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Other Derivatives
Power also enters into certain other contracts which are derivatives, but do not qualify for hedge accounting under SFAS 133. Most of these contracts are for fuel purchases for generation requirements. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs on the Consolidated Statements of Operations at the end of each reporting period.
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 rate debt, floating rate debt and interest rate derivatives.
Cash Flow Hedges
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings use interest rate swaps and other interest rate derivatives to manage their exposures to the variability of cash flows, primarily related to variable-rate debt instruments. The interest rate derivatives are designated and effective as cash flow hedges. The fair value changes of these derivatives are initially recorded in OCI. As of June 30, 2003, the fair value of these cash flow hedges was $(268) million, including $(24) million, $(73) million, $(10) million and $(161) million at PSEG, PSE&G, Power and Energy Holdings, respectively. The $(73) million at PSE&G is deferred and will be recovered from PSE&G's customers. During the next 12 months, $25 million of unrealized losses (net of gains) on interest rate derivatives accumulated in OCI is expected to be reclassified
as earnings, including $(4) million, $(3) million and $(18) million at PSEG, Power and Energy Holdings, respectively.
Foreign Currencies
Energy Holdings
Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk is that some of its foreign subsidiaries and affiliates have functional currencies other than the consolidated reporting currency, the US Dollar. Additionally, certain of Global's foreign subsidiaries and affiliates have entered into monetary obligations and maintain receipts/receivables in US Dollars or currencies other than their own functional currencies. Global, a US Dollar functional currency entity, is primarily exposed to changes in the US Dollar against the Brazilian Real, the Euro, the Polish Zloty, the Peruvian Nuevo Sol and the Chilean Peso. With respect to the foreign currency risk associated with the Brazilian Real and the Chilean Peso,
there has already been significant devaluation since the initial acquisition of these investments, which has resulted in reduced US Dollar earnings and cash flows relative to initial projections. Whenever possible, these subsidiaries and affiliates have 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, wherever possible, to manage risk related to certain foreign currency fluctuations.
As of June 30, 2003, net foreign currency devaluations have reduced the total amount of Energy Holdings' Member's Equity by $284 million, of which $181 million and $110 million were caused by the devaluation of the Brazilian Real and the Chilean Peso, respectively.
34

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Cash Flow Hedges
Affiliates of Energy Holdings purchase forward-exchange contracts as hedges of anticipated payments to contractors for projects under construction. These contracts are designed to hedge against the risk that the future cash payments will be adversely affected by changes in foreign currency rates. As of June 30, 2003 Energy Holdings recorded its pro-rata share of the fair value on the forward-exchange contracts as an increase of $2 million in OCI. There was no ineffectiveness associated with these hedges.
Additionally, an affiliate of Energy Holdings entered into a PPA that contains an embedded derivative. This embedded derivative is designated as a cash flow hedge of foreign currency debt exposure. To the extent that the derivative is effective in offsetting foreign currency exposure, the amount is recorded in OCI. Amounts will be reclassified from OCI to earnings over the life of the debt. To the extent that the derivative is provided to hedge a return in US Dollars, the offsetting amount is recorded in earnings, which amounted to approximately $3 million for the six months ended June 30, 2003. As of June 30, 2003, the fair value of the derivative was $13 million. The ineffectiveness associated with this hedge was immaterial to earnings. The maximum term of these cash flow hedges is related to the embedded
derivative, which will expire in 2022.
Equity Securities
Energy Holdings
During the first quarter of 2003, Resources recognized $10 million of other than temporary impairments of non-publicly traded equity securities, which are held within its investment in certain leveraged buyout funds. In the second quarter of 2003, Resources recognized a $6 million gain on the publicly traded equity securities within those funds. These gains and losses are included in Operating Revenues in the Consolidated Statements of Operations. As of June 30, 2003, Resources had investments in leveraged buyout funds of approximately $87 million, of which $29 million was comprised of public securities with available market prices and $58 million was comprised of non-publicly traded securities. As of December 31, 2002, Resources had investments in leveraged buyout funds of approximately $93 million, of which
$24 million was comprised of public securities with available market prices and $69 million was comprised of non-publicly traded securities.
Note 9. Comprehensive Income
PSE&G

Power (A)

Energy
Holdings (B)

Other (C)

Consolidated
Total(Millions)For the Quarter Ended June 30, 2003:Net Income (Loss)

$
4


$
109


$
31


$
(14
)

$
130Other Comprehensive Income


1



    24



34



    3



62Comprehensive Income (Loss)

$
5


$
    133


$
65


$
    (11
)

$
192For the Quarter Ended June 30, 2002:Net Income (Loss)

$
8


$
83


$
(347
)

$
(8
)

$
(264
)Other Comprehensive Income (Loss)


—



(14
)


34



(5
)


15Comprehensive Income (Loss)

$
8


$
69


$
(313
)

$
(13
)

$
(249
)For the Six Months Ended June 30, 2003:Net Income (Loss)

$
105


$
656


$
75


$
(30
)

$
806Other Comprehensive Income


—



60



    14



    6



80Comprehensive Income (Loss)

$
105


$
716


$
    89


$
    (24
)

$
886For the Six Months Ended June 30, 2002:Net Income (Loss)

$
76


$
203


$
(462
)

$
(21
)

$
(204
)Other Comprehensive Income (Loss)


(1
)


(7
)


(38
)


(4
)


(50
)Comprehensive Income (Loss)

$
75


$
196


$
(500
)

$
(25
)

$
(254
)
(A)

Changes at Power primarily relate to unrealized gains and losses in the NDT Fund in 2003.(B)

Changes at Energy Holdings primarily relate to foreign currency translation adjustments.(C)

Other primarily consists of activity at PSEG (parent company), Services and intercompany eliminations.35

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 10. Other Income and Deductions
PSE&G

Power

Energy
Holdings

Other (A)

Consolidated
Total(Millions)Other Income:For the Quarter Ended June 30, 2003:Interest Income

$
2


$
4


$
—


$
—


$
6NDT Fund Realized Gains


—



21



—



—



21NDT Dividend Income


—



2



—



—



2Other


1



—



—



—



1Total Other Income

$
3


$
27


$
—


$
—


$
30For the Quarter Ended June 30, 2002:Interest Income

$
1


$
—


$
—


$
—


$
1Gain on Disposition of Property


1



—



—



—



1Minority Interest


—



—



—



4



4Other


—



—



—



1



1Total Other Income

$
2


$
—


$
—


$
5


$
7For the Six Months Ended June 30, 2003:Interest Income

$
4


$
9


$
—


$
—


$
13Gain on Disposition of Property


8



—



—



—



8NDT Fund Realized Gains


—



60



—



—



60NDT Dividend Income


—



5



—



—



5Other


1



—



1



—



2Total Other Income

$
13


$
74


$
1


$
—


$
88For the Six Months Ended June 30, 2002:Interest Income

$
1


$
—


$
—


$
—


$
1Gain on Disposition of Property


1



—



—



—



1Change in Derivative Fair Value


—



—



1



—



1Minority Interest


—



—



—



5



5Other


—



—



—



1



1Total Other Income

$
2


$
—


$
1


$
6


$
9PSE&G

Power

Energy
Holdings

Other (A)

Consolidated
Total(Millions)Other Deductions:For the Quarter Ended June 30, 2003:NDT Fund Realized Losses and Expenses

$
—


$
12


$
—


$
—


$
12Minority Interest


—



—



—



1



1Change in Derivative Fair Value


—



—



6



—



6Foreign Currency Losses


—



—



2



—



2Total Other Deductions

$
—


$
12


$
8


$
1


$
21For the Quarter Ended June 30, 2002:Donations

$
1


$
—


$
—


$
—


$
1Change in Derivative Fair Value


—



—



9



—



9Foreign Currency Losses


—



—



17



—



17Total Other Deductions

$
1


$
—


$
26


$
—


$
27For the Six Months Ended June 30, 2003:Donations

$
1


$
—


$
—


$
—


$
1NDT Fund Realized Losses and Expenses


—



45



—



—



45Minority Interest


—



—



—



6



6Change in Derivative Fair Value


—



—



12



—



12Total Other Deductions

$
1


$
45


$
12


$
6


$
64For the Six Months Ended June 30, 2002:Donations

$
1


$
—


$
—


$
—


$
1Foreign Currency Losses


—



—



69



—



69Total Other Deductions

$
1


$
—


$
69


$
—


$
70
(A)

Other consists of reclassifications for minority interests in PSEG's consolidated results of operations.36

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 11. Income Taxes
An analysis of the tax provision expense is as follows:
PSE&G (A)

Power

Energy
Holdings

Other (B)

Consolidated
Total(Millions)For the Quarter Ended June 30, 2003:Income (Loss) before Income Taxes

$
14


$
183


$
50


$
(26
)

$
221Tax computed at the statutory rate


5



64



18



(9
)


78Increase (decrease) attributable to flow through of certain tax adjustments:State Income Taxes after Federal Benefit


3



10



—



(1
)


12Rate Differential of Foreign Operations


—



—



(1
)


—



(1
)Plant Related Items


(14
)


—



—



—



(14
)Other


(2
)


—



(1
)


(1
)


(4
)Total Income Tax Expense

$
(8
)

$
74


$
16


$
(11
)

$
71Effective income tax rate


(57.1
)%


40.4
%


32.0
%


42.3
%


32.1
%For the Quarter Ended June 30, 2002:Income (Loss) before Income Taxes

$
8


$
145


$
(491
)

$
(9
)

$
(347
)Tax computed at the statutory rate


2



51



(172
)


(3
)


(122
)Increase (decrease) attributable to flow through of certain tax adjustments:State Income Taxes after Federal Benefit


1



10



—



(1
)


10Rate Differential of Foreign Operations


—



—



(6
)


—



(6
)Plant Related Items


(5
)


—



—



—



(5
)Other


2



1



1



(1
)


3Total Income Tax Expense

$
—


$
62


$
(177
)

$
(5
)

$
(120
)Effective income tax rate


0.0
%


42.8
%


36.0
%


55.6
%


34.6
%For the Six Months Ended June 30, 2003:Income (Loss) before Income Taxes

$
171


$
483


$
131


$
(59
)

$
726Tax computed at the statutory rate


60



169



46



(21
)


254Increase (decrease) attributable to flow through of certain tax adjustments:State Income Taxes after Federal Benefit


14



28



—



(3
)


39Rate Differential of Foreign Operations


—



—



(13
)


—



(13
)Plant Related Items


(26
)


—



—



—



(26
)Other


—



—



—



1



1Total Income Tax Expense

$
48


$
197


$
33


$
(23
)

$
255Effective income tax rate


28.1
%


40.8
%


25.2
%


39.0
%


35.1
%For the Six Months Ended June 30, 2002:Income (Loss) before Income Taxes

$
118


$
345


$
(486
)

$
(29
)

$
(52
)Tax computed at the statutory rate


41



121



(170
)


(10
)


(18
)Increase (decrease) attributable to flow through of certain tax adjustments:State Income Taxes after Federal Benefit


10



20



1



(2
)


29Rate Differential of Foreign Operations


—



—



(9
)


—



(9
)Plant Related Items


(7
)


—



—



—



(7
)Other


(2
)


1



1



(1
)


(1
)Total Income Tax Expense

$
42


$
142


$
(177
)

$
(13
)

$
(6
)Effective income tax rate


35.6
%


41.2
%


36.4
%


44.8
%


11.5
%
(A)

For the quarters ended June 30, 2003 and 2002, regulatory accounting differences, primarily plant-related items, are proportionally higher relative to pre-tax income resulting in relatively low or negative effective tax rates.(B)

PSEG's other activities include amounts applicable to PSEG (parent corporation) that primarily relate to financing and certain administrative and general costs.37

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 12. Financial Information by Business Segments
Information related to the segments of PSEG and its subsidiaries is detailed below:
Energy HoldingsPSE&G

Power

Resources

Global

Other (A)

Other (B)

Consolidated
Total(Millions)For the Quarter Ended June 30, 2003:Total Operating Revenues

$
1,342


$
1,236


$
67


$
122


$
(1
)

$
(347
)

$
2,419Income (Loss) from Continuing Operations


22



109



23



11



(1
)


(14
)


150Loss from Discontinued Operations, net of tax


—



—



—



—



(2
)


—



(2
)Extraordinary Item, net of tax


(18
)


—



—



—



—



—



(18
)Net Income (Loss)


4



109



23



11



(3
)


(14
)


130Segment Earnings (Loss)


3



109



22



7



(3
)


(8
)


130Gross Additions to Long-Lived Assets


132



177



—



62



1



(2
)


370For the Six Months Ended June 30, 2003:Total Operating Revenues

$
3,490


$
3,065


$
118


$
279


$
—


$
(1,227
)

$
5,725Income (Loss) from Continuing Operations


123



286



37



57



(2
)


(30
)


471Loss from Discontinued Operations, net of tax


—



—



—



—



(17
)


—



(17
)Extraordinary Item, net of tax


(18
)


—



—



—



—



—



(18
)Cumulative Effect of a Change In Accounting Principle, net of tax


—



370



—



—



—



—



370Net Income (Loss)


105



656



37



57



(19
)


(30
)


806Segment Earnings (Loss)


103



656



34



49



(19
)


(17
)


806Gross Additions to Long-Lived Assets


229



330



—



167



2



4



732As of June 30, 2003:Total Assets

$
12,671


$
6,999


$
3,177


$
3,967


$
79


$
(323
)

$
26,570Investments in Equity Method Subsidiaries

$
—


$
—


$
111


$
1,344


$
20


$
—


$
1,475For the Quarter Ended June 30, 2002:Total Operating Revenues

$
1,230


$
673


$
32


$
101


$
—


$
(621
)

$
1,415Income (Loss) from Continuing Operations


8



83



(3
)


(305
)


(2
)


(8
)


(227
)Loss from Discontinued Operations, net of tax


—



—



—



(11
)


(26
)


—



(37
)Net Income (Loss)


8



83



(3
)


(316
)


(28
)


(8
)


(264
)Segment Earnings (Loss)


7



83



(4
)


(320
)


(28
)


(2
)


(264
)Gross Additions to Long-Lived Assets


120



267



1



177



8



32



605For the Six Months Ended June 30, 2002:Total Operating Revenues

$
2,889


$
1,249


$
90


$
179


$
—


$
(1,109
)

$
3,298Income (Loss) from Continuing Operations


76



203



14



(314
)


(4
)


(21
)


(46
)Loss from Discontinued Operations, net of tax


—



—



—



(9
)


(29
)


—



(38
)Cumulative Effect of a Change In Accounting Principle, net of tax


—



—



—



(89
)


(31
)


—



(120
)Net Income (Loss)


76



203



14



(412
)


(64
)


(21
)


(204
)Segment Earnings (Loss)


74



203



11



(420
)


(64
)


(8
)


(204
)Gross Additions to Long-Lived Assets


196



545



6



406



6



(7
)


1,152As of December 31, 2002:Total Assets

$
12,429


$
7,176


$
3,086


$
3,790


$
(50
)

$
(729
)

$
25,702Investments in Equity Method Subsidiaries

$
—


$
—


$
118


$
1,305


$
20


$
—


$
1,443
(A)

    Energy Holdings' other
      activities include amounts applicable to Energy Holdings (parent company),
      the HVAC/operating companies of Energy Technologies, which were reclassified
      into discontinued operations in 2002, and EGDC. The net losses primarily
      relate to financing and certain administrative and general costs at the
      Energy Holdings parent corporation. For a38

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
discussion of the charges
      relating to Discontinued Operations at Energy Technologies, see Note 5.
      Discontinued Operations.(B)

PSEG's other activities include amounts applicable to PSEG (parent corporation), and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions, rather, all intercompany transactions are at cost or, in the case of the BGS and Basic Gas Supply Service (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 14. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at the PSEG parent corporation.Note 13. Stock-Based Compensation
PSEG applies Accounting Principles Board (APB) Opinion No. 25, ''Accounting for Stock Issued to Employees,'' and related interpretations in accounting for stock-based compensation plans. Accordingly, no compensation cost has been recognized for fixed stock option grants since the exercise price of the stock options equaled the market price of the underlying stock on the date of grant.
The following table illustrates the effect on net income and earnings per share if PSEG had applied the fair value recognition provisions of SFAS No. 123, ''Accounting for Stock-Based Compensation,'' to stock-based employee compensation:
Quarter Ended June 30,

Six Months Ended June 30,2003

2002

2003

2002(Millions, except Share Data)Net Income (Loss), as reported

$
130


$
(264
)

$
806


$
(204
)Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects


(2
)


(3
)


(4
)


(5
)Pro forma Net Income (Loss)

$
128


$
(267
)

$
802


$
(209
)Earnings per share:Basic—as reported

$
0.58


$
(1.28
)

$
3.57


$
(0.99
)Basic—pro forma

$
0.57


$
(1.29
)

$
3.55


$
(1.01
)Diluted—as reported

$
0.57


$
(1.28
)

$
3.57


$
(0.99
)Diluted—pro forma

$
0.56


$
(1.29
)

$
3.55


$
(1.01
)Note 14. Related-Party Transactions
BGSS and BGS Contracts
PSE&G and Power
Effective May 1, 2002, PSE&G transferred its gas supply contracts and gas inventory requirements to Power. On the same date, PSE&G entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G's BGSS requirements.
For the quarter ended June 30, 2003 and 2002, Power billed PSE&G approximately $293 and $97 million, respectively, for BGSS. For the six months ended June 30, 2003 and 2002, Power billed PSE&G approximately $1.1 billion and $97 million, respectively, for BGSS. As of June 30, 2003 and December 31, 2002, PSE&G's payable to Power related to the BGSS contract was approximately $67 million and $241 million, respectively.
Power charged PSE&G for the energy and capacity provided to meet its BGS requirements through July 31, 2002. Power also charges PSE&G for the MTC through July 31, 2003. For the quarters ended June 30, 2003 and 2002, Power charged PSE&G approximately $53 million and $488 million,
39

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
respectively, for the MTC and BGS. For the six months ended June 30, 2003 and 2002, Power charged PSE&G approximately $101 million and $948 million, respectively, for the MTC and BGS. As of June 30, 2003 and December 31, 2002, PSE&G's payable to Power relating to these costs was approximately $14 million and $2 million, respectively.
For the quarter and six months ended June 30, 2002, PSE&G sold energy and capacity to Power at the market price of approximately $35 million and $63 million, respectively, which PSE&G purchased under various NUG contracts at costs above market prices.
Affiliate Loans
PSEG and Power
As of June 30, 2003 and December 31, 2002, Power had a payable to PSEG of approximately $4 million and $239 million, respectively, for short-term funding needs. There was no interest expense related to these borrowings for the quarter ended June 30, 2003, as compared to $2.9 million for the quarter ended June 30, 2002.
PSEG and Energy Holdings
As of June 30, 2003 and December 31, 2002, Energy Holdings had a receivable due from PSEG of $131 million and $62 million, respectively, for short-term funding needs. Interest Income related to this intercompany transaction was immaterial.
Energy Holdings
Loans to Texas Independent Energy, L.P. (TIE)
Global and its partner, Panda Energy International, Inc. (Panda), own and operate two electric generation facilities in Texas through TIE, a 50/50 joint venture. In January 2003, Panda indirectly transferred 50% of its interest in TIE to Teco Power Services (Teco). As of June 30, 2003, Global's investment in TIE was approximately $238 million including $72 million of loans that earn interest at an annual rate of 12% and that are scheduled to be repaid in quarterly installments through 2012. The quarterly loan installments due to Global are expected to be repaid out of the project cash flows or additional contributions from project partners in the event of insufficient project cash flows. For the quarter and six months ended June 30, 2003, Global recorded approximately $3 million and $5 million, respectively, of interest
income related to this loan.
In March 2003, Global funded $14 million of convertible preferred equity to the two TIE projects as part of its negotiations with project lenders to amend the projects' credit agreements. The convertible preferred equity has a 15% coupon and is convertible at Global's option into an approximate 13% equity interest in TIE if not repaid in full by June 2004.
Loans to GWF Energy
As of June 30, 2003, Global has provided GWF Energy $4 million of working capital loans to fund construction costs pending completion of permanent project financing. The loan earns interest at 20% per annum and is not convertible into equity. Global's ownership interest in GWF Energy was approximately 76% as of June 30, 2003. Harbinger has the right to buy back from Global up to one-half of the reduction of its equity ownership in GWF Energy from the 50% ownership level.
As of
  June 30, 2003, Global's equity investment in GWF Energy was $212 million and
  its ownership interest in GWF Energy was approximately 76%. Global and Harbinger
  are currently in arbitration over allegations that Global wrongfully diluted
  Harbinger's ownership percentage interest in GWF Energy. Global and Harbinger
  agreed on June 4, 2003 that the issues and claims raised by Harbinger will be
  determined in arbitration and that the deadline for Harbinger to buy back from
  Global up to
40

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
50% of the dilution of its ownership interest in GWF Energy would be extended to 30 days after the issuance of the decision in the arbitration. In addition, Harbinger agreed to dismiss such action with prejudice upon completion of the arbitration. The parties are targeting to complete the arbitration by November 30, 2003 though no assurances can be given.
Changes in Capitalization
PSE&G
On January 21, 2003, PSEG contributed $170 million of equity to PSE&G.
PSEG, PSE&G, Power and Energy Holdings
Services
  provides and bills administrative services to PSE&G, Power and Energy Holdings
  as follows:
Services
      Billings for the Quarter Ended June 30,
    
    Services
      Billings for the Six Months Ended June 30,
    
    Payable
      to Services as of2003
    
    2002
    
    2003
    
    2002
    
    June
      30,
      2003
    
    December
      31,
      2002(Millions)PSE&G
    
    $
    54
    
    
    $
    51
    
    
    $
    100
    
    
    $
    103
    
    
    $
    17
    
    
    $
    16Power
    
    
    27
    
    
    
    31
    
    
    
    54
    
    
    
    66
    
    
    
    6
    
    
    
    2Energy Holdings
    
    
    4
    
    
    
    5
    
    
    
    8
    
    
    
    10
    
    
    
    2
    
    
    
    3These transactions were properly recognized on each company's stand-alone financial statements and eliminated when preparing PSEG's consolidated financial statements. PSEG, PSE&G, Power and Energy Holdings believe that the costs of services provided by Services approximates market value for such services.
41

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 15. Guarantees of Debt
Power
In April 2001, Power issued $500 million of 6.875% Senior Notes due 2006, $800 million of 7.75% Senior Notes due 2011 and $500 million of 8.625% Senior Notes due 2031. Additionally, in June 2002, Power issued $600 million of 6.95% Senior Notes due 2012. Each series of the Senior 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, for the quarters and six months then ended.
Power
    
    
    
    Guarantor
        Subsidaries
    
    
    
    Other
        Subsidaries
    
    
    
    Consolidating
        Adjustments
    
    
    
    Total(Millions)For the Quarter
      Ended June 30, 2003:Operating
      Revenues
    
    $
    —
    
    
    $
    1,488
    
    
    $
    74
    
    
    $
    (326
    )
    
    $
    1,236Operating
      Expenses
    
    
    —
    
    
    
    1,314
    
    
    
    52
    
    
    
    (326
    )
    
    
    1,040Operating
      Income
    
    
    —
    
    
    
    174
    
    
    
    22
    
    
    
    —
    
    
    
    196Other
      Income
    
    
    106
    
    
    
    65
    
    
    
    —
    
    
    
    (144
    )
    
    
    27Other
      Deductions
    
    
    —
    
    
    
    (45
    )
    
    
    —
    
    
    
    33
    
    
    
    (12
    )Interest
      Expense
    
    
    (50
    )
    
    
    (21
    )
    
    
    32
    
    
    
    11
    
    
    
    (28
    )Income
      Taxes
    
    
    54
    
    
    
    (108
    )
    
    
    (19
    )
    
    
    (1
    )
    
    
    (74
    )Net
      Income (Loss)
    
    $
    110
    
    
    $
    65
    
    
    $
    35
    
    
    $
    (101
    )
    
    $
    109For the Six
      Months Ended June 30, 2003:Operating
      Revenues
    
    $
    —
    
    
    $
    3,546
    
    
    $
    144
    
    
    $
    (625
    )
    
    $
    3,065Operating
      Expenses
    
    
    —
    
    
    
    3,070
    
    
    
    110
    
    
    
    (625
    )
    
    
    2,555Operating
      Income (Loss)
    
    
    —
    
    
    
    476
    
    
    
    34
    
    
    
    —
    
    
    
    510Other
      Income
    
    
    677
    
    
    
    80
    
    
    
    —
    
    
    
    (683
    )
    
    
    74Other
      Deductions
    
    
    —
    
    
    
    (45
    )
    
    
    —
    
    
    
    —
    
    
    
    (45
    )Interest
      Expense
    
    
    (91
    )
    
    
    (39
    )
    
    
    63
    
    
    
    11
    
    
    
    (56
    )Income
      Taxes
    
    
    71
    
    
    
    (232
    )
    
    
    (36
    )
    
    
    —
    
    
    
    (197
    )Cumulative
      Effect of a Change in Accounting Principle
    
    
    —
    
    
    
    366
    
    
    
    4
    
    
    
    —
    
    
    
    370Net
      Income (Loss)
    
    $
    657
    
    
    $
    606
    
    
    $
    65
    
    
    $
    (672
    )
    
    $
    656For the Six
      Months Ended June 30, 2003:Net
      Cash Provided By (Used In) Operating Activities
    
    $
    261
    
    
    $
    736
    
    
    $
    8
    
    
    $
    (425
    )
    
    $
    580Net
      Cash (Used In) Provided By Investing Activities
    
    $
    (403
    )
    
    $
    (478
    )
    
    $
    (11
    )
    
    $
    546
    
    
    $
    (346
    )Net
      Cash Provided By (Used In) Financing Activities
    
    $
    142
    
    
    $
    (270
    )
    
    $
    12
    
    
    $
    (119
    )
    
    $
    (235
    )For the Quarter
      Ended June 30, 2002:Operating
      Revenues
    
    $
    1
    
    
    $
    668
    
    
    $
    4
    
    
    $
    —
    
    
    $
    673Operating
      Expenses
    
    
    16
    
    
    
    478
    
    
    
    6
    
    
    
    —
    
    
    
    500Operating
      (Loss) Income
    
    
    (15
    )
    
    
    190
    
    
    
    (2
    )
    
    
    —
    
    
    
    173Other
      Income
    
    
    117
    
    
    
    9
    
    
    
    —
    
    
    
    (126
    )
    
    
    —Interest
      Expense
    
    
    (41
    )
    
    
    (14
    )
    
    
    27
    
    
    
    —
    
    
    
    (28
    )Income
      Taxes
    
    
    22
    
    
    
    (74
    )
    
    
    (10
    )
    
    
    —
    
    
    
    (62
    )Net
      Income (Loss)
    
    $
    83
    
    
    $
    111
    
    
    $
    15
    
    
    $
    (126
    )
    
    $
    83For the Six
      Months Ended June 30, 2002:Operating
      Revenues
    
    $
    1
    
    
    $
    1,242
    
    
    $
    6
    
    
    $
    —
    
    
    $
    1,249Operating
      Expenses
    
    
    36
    
    
    
    802
    
    
    
    10
    
    
    
    —
    
    
    
    848Operating
      (Loss) Income
    
    
    (35
    )
    
    
    440
    
    
    
    (4
    )
    
    
    —
    
    
    
    401Other
      Income
    
    
    273
    
    
    
    13
    
    
    
    —
    
    
    
    (286
    )
    
    
    —Interest
      Expense
    
    
    (82
    )
    
    
    (30
    )
    
    
    56
    
    
    
    —
    
    
    
    (56
    )Income
      Taxes
    
    
    47
    
    
    
    (170
    )
    
    
    (19
    )
    
    
    —
    
    
    
    (142
    )Net
      Income (Loss)
    
    $
    203
    
    
    $
    253
    
    
    $
    33
    
    
    $
    (286
    )
    
    $
    20342

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Power
    
    
    
    Guarantor
        Subsidaries
    
    
    
    Other
        Subsidaries
    
    
    
    Consolidating
        Adjustments
    
    
    
    Total(Millions)For the Six
      Months Ended June 30, 2002:Net
      Cash (Used In) Provided By Operating Activities
    
    $
    (413
    )
    
    $
    714
    
    
    $
    (23
    )
    
    $
    (203
    )
    
    $
    75Net
      Cash (Used In) Provided By Investing Activities
    
    $
    (224
    )
    
    $
    (466
    )
    
    $
    (157
    )
    
    $
    311
    
    
    $
    (536
    )Net
      Cash Provided By (Used In) Financing Activities
    
    $
    637
    
    
    $
    (244
    )
    
    $
    180
    
    
    $
    (108
    )
    
    $
    465As of June 30,
      2003:Current
      Assets
    
    $
    1,255
    
    
    $
    1,498
    
    
    $
    154
    
    
    $
    (1,542
    )
    
    $
    1,365Property,
      Plant and Equipment, net
    
    
    37
    
    
    
    2,567
    
    
    
    1,717
    
    
    
    —
    
    
    
    4,321Noncurrent
      Assets
    
    
    3,675
    
    
    
    1,616
    
    
    
    1,342
    
    
    
    (5,320
    )
    
    
    1,313Total
      Assets
    
    $
    4,967
    
    
    $
    5,681
    
    
    $
    3,213
    
    
    $
    (6,862
    )
    
    $
    6,999Current
      Liabilities
    
    $
    116
    
    
    $
    1,954
    
    
    $
    636
    
    
    $
    (1,667
    )
    
    $
    1,039Noncurrent
      Liabilities
    
    
    97
    
    
    
    433
    
    
    
    24
    
    
    
    (65
    )
    
    
    489Note
      Payable—Affiliated Company
    
    
    79
    
    
    
    1,150
    
    
    
    —
    
    
    
    (1,229
    )
    
    
    —Long-Term
      Debt
    
    
    2,516
    
    
    
    —
    
    
    
    800
    
    
    
    —
    
    
    
    3,316Member's
      Equity
    
    
    2,159
    
    
    
    2,144
    
    
    
    1,753
    
    
    
    (3,901
    )
    
    
    2,155Total
      Liabilities and Member's Equity
    
    $
    4,967
    
    
    $
    5,681
    
    
    $
    3,213
    
    
    $
    (6,862
    )
    
    $
    6,999As of December
      31, 2002:Current
      Assets
    
    $
    1,329
    
    
    $
    1,566
    
    
    $
    102
    
    
    $
    (1,479
    )
    
    $
    1,518Property,
      Plant and Equipment, net
    
    
    42
    
    
    
    2,430
    
    
    
    1,568
    
    
    
    —
    
    
    
    4,040Noncurrent
      Assets
    
    
    3,258
    
    
    
    1,786
    
    
    
    1,360
    
    
    
    (4,786
    )
    
    
    1,618Total
      Assets
    
    $
    4,629
    
    
    $
    5,782
    
    
    $
    3,030
    
    
    $
    (6,265
    )
    
    $
    7,176Current
      Liabilities
    
    $
    367
    
    
    $
    1,907
    
    
    $
    522
    
    
    $
    (1,503
    )
    
    $
    1,293Noncurrent
      Liabilities
    
    
    209
    
    
    
    991
    
    
    
    29
    
    
    
    (101
    )
    
    
    1,128Note
      Payable—Affiliated Company
    
    
    97
    
    
    
    1,150
    
    
    
    —
    
    
    
    (1,247
    )
    
    
    —Long-Term
      Debt
    
    
    2,516
    
    
    
    —
    
    
    
    800
    
    
    
    —
    
    
    
    3,316Member's
      Equity
    
    
    1,440
    
    
    
    1,734
    
    
    
    1,679
    
    
    
    (3,414
    )
    
    
    1,439Total
      Liabilities and Member's Equity
    
    $
    4,629
    
    
    $
    5,782
    
    
    $
    3,030
    
    
    $
    (6,265
    )
    
    $
    7,176There are no restrictions on the ability of Power's subsidiaries to transfer funds in the form of dividends, loans or advances to Power for the periods noted above.
Note 16. Subsequent Events
PSE&G
Electric Base Rate Case
In May 2002, PSE&G filed an Electric Base Rate Case with the BPU requesting an annual $250 million increase for its electric distribution business. In June 2003, a proposed settlement was filed with the Administrative Law Judge (ALJ) who recommended approval of the settlement to the BPU. In July 2003, PSE&G received an oral decision from the BPU approving the proposed settlement with certain modifications. As a result of the oral decision, in the second quarter of 2003, PSE&G has:
•

recorded a regulatory liability by reducing its depreciation reserve for its electric distribution assets by $155 million, which will be amortized from August 1, 2003 through December 31, 2005; and•

    recorded certain adjustments
      in connection with the resolution of various issues relating to the Final
      Order PSE&G received from the BPU in 1999 relating to PSE&G's rate
      unbundling, stranded costs and restructuring proceedings. These amounts
      include a $30 million pre-tax refund related to revenues previously collected
      through the SBC for nuclear decommissioning. Because this amount reflects
      the final accounting for PSEG's generation-related business pursuant to
      the43

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
four year
      transition plan mandated by PSE&G's Final Order received from the BPU
      in 1999 relating to the New Jersey Electric Discount and Energy Competition
      Act, the adjustment has been recorded as an $18 million, after-tax, Extraordinary
      Item as required under APB No. 30, ''Reporting the Results of Operations—Reporting
      the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual
      and Infrequently Occurring Events and Transactions'' (APB 30). Also included
      is an $18 million, pre-tax, increase in MTC overcollections which was recorded
      as a reduction to Operating Revenues and a $4 million, pre-tax, reduction
      in interest capitalized on various deferred balances during the transition
      period which was recorded as a charge to Interest Expense.On July 31, 2003, PSE&G received a summary written order which was substantially consistent with the oral decision.44

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 2002 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, affecting the consolidated financial condition and the results of operations of the registrants. This discussion refers to the registrants' Consolidated Financial Statements (Statements) and the related Notes to 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 LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no representations as to any other company.
OVERVIEW
PSEG
PSEG's business consists of four reportable segments, which are Power, PSE&G, PSEG Global LLC (Global) and PSEG Resources LLC (Resources). The following is a discussion of the major financial statement variances and follows the financial statement presentation as it relates to each of the segments. PSEG's results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power and Energy Holdings. For a more detailed discussion of the changes referenced for PSEG, see the applicable results of operations discussion for each respective subsidiary registrant.
Income from Continuing Operations for the quarter ended June 30, 2003 was $150 million or $0.66 per share. Losses from Continuing Operations for the quarter ended June 30, 2002 were $227 million or $1.10 per share, which included after-tax losses of $343 million or $1.66 per share related to Energy Holdings' abandoned investments in Argentina. Net Income (Loss) for the quarters ended June 30, 2003 and 2002 was $130 million and $(264) million or $0.57 and $(1.28) per share of common stock, respectively.
Income from Continuing Operations for the six month period ended June 30, 2003 was $471 million or $2.09 per share. Losses from Continuing Operations for the six month period ended June 30, 2002 were $46 million or $0.22 per share which included after-tax losses of $374 million or $1.81 per share related to Energy Holdings' abandoned investments in Argentina. Net Income (Loss) for the six month periods ended June 30, 2003 and 2002 was $806 million and $(204) million or $3.57 and $(0.99) per share of common stock, respectively.
Based on these results, PSEG continues to project 2003 Income from Continuing Operations to be within its original range of $3.70 to $3.90 per share. In addition, PSEG has established initial 2004 guidance for Income from Continuing Operations in the range of $3.75 to $3.95 per share. These projected results will depend on several factors, including, but not limited to, the expected benefits from the conclusion of PSE&G's Electric Base Rate Case, Power's ability to continue to effectively manage its portfolio of electric generation assets, gas supply contracts and electric and gas supply obligations, and Power's ability to mitigate against the effects of volatility in energy prices on the outcome of the next Basic Generation Service (BGS) auction and the loss of the market transition charge (MTC) revenues effective
August 1, 2003, and the continued contributions from investments at Resources and Global. PSEG is reviewing its dividend policy and is considering the viability of an increase to its current dividend level as earnings continue to grow, however, a decision is not expected until approximately the end of 2003. This decision will be based on several factors, including a review of PSEG's expected earnings and long-term growth rate, credit quality, dividend payout ratio, anticipated future cash flows and financial requirements and ability to maintain the dividend at a consistent level.
The significant period-to-period increase in Income from Continuing Operations for the quarter and six months ended June 30, 2003, as compared to the same periods in the prior year is due primarily
45
to the absence of losses from Energy Holdings' Argentine investments recorded in 2002. Also contributing to the increase were higher margins at Power from the electric and natural gas portfolio, improved earnings at PSE&G due to favorable weather effects and improvements at Energy Holdings, largely due to the absence of write-downs of securities at Resources held within certain leveraged buyout funds recorded in the second quarter of 2002 combined with improvements in the performance of Resources' lease portfolio. For the quarter ended June 30, 2003, as compared to the same period in 2002, these favorable amounts were partially offset due to the timing of an annual partnership withdrawal installment payment for the Eagle Point Cogeneration Partnership (EPCP) which was received in the first quarter of 2003 compared to the second quarter of 2002.
Additionally, during the first quarter of 2003, PSEG recorded an after-tax benefit to Net Income in the amount of $370 million related to the adoption of Statement of Financial Accounting Standard (SFAS) No. 143, ''Accounting for Asset Retirement Obligations'' (SFAS 143). This benefit was due mainly to the required remeasurement of Power's nuclear decommissioning obligations. Similarly, for the first quarter of 2002, PSEG adopted SFAS No. 142, ''Goodwill and Other Intangible Assets'' (SFAS 142) and incurred an after-tax charge of $120 million related to goodwill impairments at Energy Holdings.
Also contributing to the changes in Net Income was a decrease in Energy Holdings' Loss from Discontinued Operations of $35 million and $21 million for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002, and an $18 million, after-tax, extraordinary charge recorded at PSE&G in the second quarter of 2003 related to the oral decision received from the New Jersey Board of Public Utilities (BPU) in July 2003, discussed below in PSE&G's Overview.
The results for PSEG, PSE&G, Power and Energy Holdings for the quarter and six months ended June 30, 2003 and 2002 are presented below:
Earnings (Losses)

Earnings (Losses)Quarter Ended
June 30,

Six Months Ended
June 30,2003

2002

2003

2002(Millions)

(Millions)PSE&G

$
22


$
8


$
123


$
76Power


109



83



286



203Energy Holdings:Global (A)


11



(305
)


57



(314
)Resources


23



(3
)


37



14Other (B)


(1
)


(2
)


(2
)


(4
)Total Energy Holdings (A)


33



(310
)


92



(304
)Other (C)


(14
)


(8
)


(30
)


(21
)Income from Continuing Operations (A)

$
150


$
(227
)

$
471


$
(46
)Loss from Discontinued Operations, including Loss on Disposal (D)


(2
)


(37
)


(17
)


(38
)Extraordinary Item (E)


(18
)


—



(18
)


—Cumulative Effect of a Change in Accounting Principle (F)


—



—



370



(120
)PSEG Net Income (A)

$
130


$
(264
)

$
806


$
(204
)46
Contribution to Earnings Per Share (Diluted)

Contribution to Earnings Per
Share (Diluted)Quarter Ended
June 30,

Six Months Ended
June 30,2003

2002

2003

2002PSE&G

$
0.10


$
0.04


$
0.54


$
0.37Power


0.48



0.40



1.27



0.98Energy Holdings:Global (A)


0.05



(1.47
)


0.25



(1.52
)Resources


0.10



(0.02
)


0.16



0.06Other (B)


(0.01
)


(0.01
)


(0.01
)


(0.02
)Total Energy Holdings (A)


0.14



(1.50
)


0.40



(1.48
)Other (C)


(0.06
)


(0.04
)


(0.12
)


(0.09
)Income from Continuing Operations (A)

$
0.66


$
(1.10
)

$
2.09


$
(0.22
)Loss from Discontinued Operations, including Loss on Disposal (D)


(0.01
)


(0.18
)


(0.08
)


(0.19
)Extraordinary Item (E)


(0.08
)


—



(0.08
)


—Cumulative Effect of a Change in Accounting Principle (F)


—



—



1.64



(0.58
)PSEG Net Income (A)

$
0.57


$
(1.28
)

$
3.57


$
(0.99
)
(A)

Includes write-down and losses related to Argentine investments of $343 million and $374 million for the quarter and six months ended June 30, 2002, respectively.(B)

Other activities include non-segment amounts of Energy Holdings, PSEG Energy Technologies Inc. (Energy Technologies), Enterprise Group Development Corporation (EGDC) and intercompany eliminations. Specific amounts include interest on certain financing transactions and certain other administrative and general expenses at Energy Holdings.(C)

Other activities include non-segment amounts of PSEG (parent company) and intercompany eliminations. Specific amounts include preferred securities dividends requirements for PSE&G and Energy Holdings, interest on certain financing transactions and certain other administrative and general expenses at PSEG (parent company).(D)

Includes Discontinued Operations of Energy Technologies in 2003 and 2002 and Global's Tanir Bavi facility in 2002.(E)

Relates to charge recorded in the second quarter of 2003 at PSE&G resulting from the oral decision issued by the BPU in PSE&G's Electric Base Rate Case in July 2003.(F)

Relates to the adoption of SFAS 143 in 2003 and the adoption of SFAS 142 in 2002. See Note 2. New Accounting Standards and Note 3. Adoption of SFAS 143 of the Notes.PSE&G
Income from Continuing Operations increased $14 million and $47 million for the quarter and six month periods ended June 30, 2003, respectively, as compared to the same periods in 2002. PSE&G's Earnings Available to PSEG decreased $4 million or 57% and increased $29 million or 39% for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002. The increases were primarily due to favorable winter weather and lower Operation and Maintenance expenses, as discussed in Results of Operations. Partially offsetting these amounts were certain charges recognized in accordance with the Electric Base Rate Case as discussed further below. These included a pre-tax charge to Operating Revenues of $18 million relating to the MTC and a $30 million pre-tax, $18 million after-tax, extraordinary
charge, discussed below.
In May
  2002, PSE&G filed an Electric Base Rate Case with the BPU requesting an
  annual $250 million increase for its electric distribution business. In June
  2003, a proposed settlement was filed with the Administrative Law Judge (ALJ)
  who subsequently recommended approval of the settlement to the BPU. In July
  2003, PSE&G received an oral decision from the BPU approving the proposed
  settlement with certain modifications and subsequently received a summary written
  order which was substantially consistent with the oral decision.
47
The
  following is a summary of the significant issues provided for in the oral decision
  and summary written order.
•

PSE&G will receive a $159.5 million annual increase in its electric distribution rates commencing August 1, 2003.•

PSE&G will decrease its electric distribution depreciation rates from 3.52% to 2.49%, effective August 1, 2003. This change will reduce depreciation expense by approximately $40 million per year.•

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 will amortize the liability from August 1, 2003 through December 31, 2005. The annual amortization of this liability is $64 million and will result in a reduction of Depreciation and Amortization expense. Subsequent to the amortization of this reserve, the BPU's oral decision allows PSE&G to petition for an additional $64 million annual increase in electric distribution rates effective January 1, 2006, subject to BPU approval, including a review of PSE&G's return on equity and other relevant financial information.•

PSE&G will refund approximately $238 million to ratepayers through the Non-Utility Generation Transition Charge (NTC) and Societal Benefits Charge (SBC), which include amounts related to the resolution of various issues relating to the Final Order PSE&G received from the BPU in 1999 relating to PSE&G's rate unbundling, stranded costs and restructuring proceedings. These amounts include a $30 million pre-tax refund related to revenues previously collected through the SBC for nuclear decommissioning. Because this amount reflects the final accounting for PSEG's generation-related business pursuant to the four year transition plan mandated by PSE&G's Final Order received from the BPU in 1999 relating to the New Jersey Electric Discount and Energy Competition Act (EDECA), the adjustment has been recorded as an $18 million, Extraordinary Item in the second
quarter of 2003, as required under Accounting Principles Board (APB) No. 30, ''Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions'' (APB 30). Also included in the refund amount is an $18 million, pre-tax, increase in the refund for MTC overcollections which was recorded in the second quarter of 2003 as a reduction to Operating Revenues and a $4 million, pre-tax, reduction in interest capitalized on various deferred balances during the transition period which was recorded as a charge to Interest Expense.•

PSE&G will be allowed to recover deferred Repair Allowances and deferred Restructuring Costs over a ten-year period commencing August 1, 2003.•

PSE&G will transfer approximately $80 million of assets, at book value, to PSEG Services Corporation (Services) in the third quarter of 2003.The combined effects of the expiration of the electric rate discounts on July 31, 2003, which had been phased in beginning in August 1999, the refunds through certain reductions and the approved increase in base rates, combined with the effects of the recent BGS auction, will result in rates slightly lower than those in effect prior to the initial electric rate discount on August 1, 1999.
Power
Power's Income from Continuing Operations increased $26 million to $109 million and $83 million to $286 million for the quarter and six months ended June 30, 2003, respectively as compared to the same periods in 2002. The increases were primarily due to higher margins from Power's electric load contracts, which became effective August 1, 2002, and increases in MTC revenues. Power benefited during 2003 from its operation of two generating facilities in Connecticut that were acquired in December 2002. In addition, net gains realized in Power's Nuclear Decommissioning Trust (NDT) Fund were favorable for the periods.
Earnings Available to PSEG were $109 million and $656 million for the quarter and six months ended June 30, 2003, respectively, as compared to $83 million and $203 million for the same periods in 2002. Included in the six months ended June 30, 2003 was the adoption of SFAS 143 resulting in an
48
after-tax benefit of $370 million. The benefit is related to the required remeasurement of Power's asset retirement obligations, mainly nuclear decommissioning, within its businesses.
Energy Holdings
Energy Holdings' Income from Continuing Operations was $33 million and $92 million for the quarter and six months ended June 30, 2003, respectively. Losses from Continuing Operations for the quarter and six months ended June 30, 2002 were $310 million and $304 million, respectively, which included losses of $343 million and $374 million for the quarter and six months ended June 30, 2002, respectively, related to Global's abandoned investments in Argentina. In addition, contributing to the increase for the quarter and six months ended June 30, 2003 was a decrease in other than temporary impairments of non-publicly traded equity securities held within Resources' KKR leveraged buyout funds. Partially offsetting the increase for the quarter ended June 30, 2003 was lower gains recorded due to the timing of a partnership
installment payment from EPCP, which was recorded in the first quarter of 2003 as compared to the second quarter of 2002.
Earnings Available to PSEG was $26 million and $64 million for the quarter and six months ended June 30, 2003, respectively, as compared to Losses Available to PSEG of $352 million and $473 million in the same periods in 2002. The change is largely attributable to losses related to Global's investments in Argentina discussed above, and higher losses in 2002 from Discontinued Operations. The adoption of SFAS 142 in the first quarter of 2002, which resulted in an after-tax charge of $120 million, also contributed to the increase for the six months ended June 30, 2003.
RESULTS OF OPERATIONS
PSEG
Operating Revenues
For the quarter ended June 30, 2003, Operating Revenues increased by $1.0 billion or 71% as compared to the same period in 2002. This was primarily due to a change in the BGS contracing process, discussed below. Also contributing to the increase were PSEG's operating companies including a $270 million increase from Power related to the revenues from new load contracts with third-party wholesale electric suppliers which went into effect August 1, 2002 and increased energy sales into the New England Power Pool resulting from Power's operation of two generation facilities in Connecticut that were acquired in December 2002, a $112 million increase in PSE&G's operating revenues due primarily to increased sales volumes due to weather and price increases mostly due to the rising cost of natural gas as explained below under
PSE&G and a $55 million increase in Energy Holdings' operating revenues relating to Global's generation projects going into operation during the fourth quarter of 2002 and higher investment earnings at Resources, as detailed below under Energy Holdings.
For the six months ended June 30, 2003, Operating Revenues increased by $2.4 billion or 74%. This was due primarily to a change in the BGS contracting process, discussed below. Also contributing to the increase were PSEG's operating companies including a $690 million increase from Power related to the new load contracts mentioned above and increased revenues from the two generation facilities in Connecticut, a $601 million increase in PSE&G's operating revenues due primarily to increased weather-related demand in the first quarter of 2003 as explained below under PSE&G and a $128 million increase in Energy Holdings' operating revenues relating to Global's generation projects going into operation as discussed above and increased revenues at Resources.
In addition, a portion of the increase was due to the fact that Power's electric revenues are not being eliminated in consolidation subsequent to July 2002 by PSEG. Under the prior BGS contract, which terminated on July 31, 2002, Power sold energy directly to PSE&G, which in turn sold this energy to its customers. These revenues were properly recognized on each company's stand-alone financial statements and were eliminated when preparing PSEG's Consolidated Financial Statements. For the BGS contract period beginning August 1, 2002, Power entered into contracts with third parties who are direct suppliers of New Jersey's Electric Distribution Companies (EDCs) and PSE&G purchases the energy for its customers' needs from direct third party suppliers. Due to this change in the BGS model,
49
these revenues are no longer intercompany revenues and therefore are not eliminated in consolidation. For the quarter and six months ended June 30, 2003, PSEG's elimination related to intercompany BGS and MTC revenues decreased by approximately $435 million and $847 million, respectively, as compared to the comparable prior year due primarily to this change. Also related to this change in the BGS model, PSE&G, in August 2002, began selling energy purchased under non-utility generation (NUG) contracts, which it had previously sold to Power, to PJM, with the capacity purchased under these contracts being provided to the BGS suppliers on a pro-rata basis. As a result, for the quarter and six months ended June 30, 2003, PSEG's revenues related to NUG contracts increased by approximately $35 million and $63 million, respectively.
Operating Expenses
Energy Costs
For the quarter ended June 30, 2003 as compared to the quarter ended June 30, 2002, Energy Costs increased approximately $963 million or 214% due primarily to the fact that PSE&G no longer purchases electric energy directly from Power, as discussed above in Operating Revenues. Amounts attributable to this change totaled $470 million between the quarters ended June 30, 2003 and 2002. Also contributing to the increase were a $101 million net increase in natural gas costs, a $250 million increase at Power primarily related to increased energy purchases and third-party wholesale electric supply contracts, discussed further below under Power, a $21 million increase in electric energy costs at PSE&G discussed further below under PSE&G and a $24 million increase at Energy Holdings, relating to projects going into
operation at Global, discussed further below under Energy Holdings.
For the six months ended June 30, 2003 as compared to the six months ended June 30, 2002, Energy Costs increased approximately $2.2 billion or 184% due primarily to the fact that PSE&G no longer purchases electric energy directly from Power, as discussed above in Operating Revenues. Amounts attributable to this change totaled $910 million between the six months ended June 30, 2003 and 2002. Also contributing to the increase were a $501 million net increase in natural gas costs, a $554 million increase at Power primarily related to increased power purchases and third-party wholesale electric supply contracts, discussed further below under Power, a $83 million increase in electric energy costs at PSE&G discussed further below under PSE&G and a $41 million increase at Energy Holdings, relating to projects going
into operation at Global, discussed further below under Energy Holdings.
Operation and Maintenance
For the quarter ended June 30, 2003, Operation and Maintenance expense increased $30 million or 7% as compared to the quarter ended June 30, 2002 due to a $39 million increase at Power primarily due to the acquisition of the generating facilities in Connecticut in December 2002 and higher nuclear refueling outage costs at Power and an increase at Energy Holdings of $4 million, due mainly to costs associated with projects going into operation, offset by a $15 million decrease at PSE&G due primarily to a reduction in real estate tax expense and the reversal of a reserve associated with a regulatory asset, discussed further below under PSE&G.
For the six months ended June 30, 2003, Operation and Maintenance expense increased $87 million or 9% as compared to the six months ended June 30, 2002 due to a $55 million increase at Power primarily due to the acquisition of the generating facilities in Connecticut in December 2002 and a planned refueling outages at Power, an increase at Energy Holdings of $12 million, due mainly to costs associated with projects going into operation and a $17 million increase at PSE&G due primarily to higher Demand Side Management (DSM) amortization and higher pension costs offset by a reduction in real estate tax expense, discussed further below under PSE&G.
Depreciation and Amortization
For the quarter and six months ended June 30, 2003, Depreciation and Amortization decreased by $32 million and $63 million, respectively, as compared to the quarter and six months ended June 30,
50
2002. The decrease was primarily due to an increase in the amortization of the excess depreciation reserve, discussed further below under PSE&G.
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes is comprised of the Transitional Energy Facility Assessment (TEFA) tax at PSE&G. Taxes Other Than Income Taxes increased $2 million and $8 million for the quarter and six months ended June 30, 2003, respectively, as compared to the quarter and six months ended June 30, 2002. The increase was the result of higher TEFA due to higher taxable sales in 2003. Legislation enacted in January 2002 freezes the TEFA unit rate surcharges at the 2001 levels through 2004 and then reduces the rates over the next three years, phasing out the TEFA by 2007.
Income from Equity Method Investments
For the quarter ended June 30, 2003, Income from Equity Method Investments decreased by $2 million or 6% to $31 million from $33 million for the quarter ended June 30, 2002. For the six months ended June 30, 2003 Income from Equity Method Investments decreased $15 million or 24% to $48 million from $63 million for the six months ended June 30, 2002. These decreases were primarily due to lower earnings in 2003 from Rio Grande Energia (RGE), an electric distribution company in Brazil, offset by a change in accounting for GWF Energy which had a loss in 2002 when it was accounted for under the equity method and is now recorded as a consolidated entity due to Energy Holdings' increased ownership percentage.
Other Income
For the quarter ended June 30, 2003, Other Income increased by $23 million, as compared to the quarter ended June 30, 2002, due primarily to a $27 million increase at Power. Power's increase was due primarily to realized gains and the recognition of interest and dividend income in its NDT Fund.
For the six months ended June 30, 2003, Other Income increased by $79 million, as compared to the six months ended June 30, 2002, due primarily to a $74 million increase at Power and an $11 million increase at PSE&G. Power's increase was due to realized gains and the recognition of interest and dividend income in its NDT Fund. The increase at PSE&G was primarily due to gains on the disposal of various electric transmission properties and gains from short-term investments.
Other Deductions
For the quarter ended June 30, 2003, Other Deductions decreased by $6 million, as compared to the quarter ended June 30, 2002, due primarily to $15 million less in foreign currency transaction losses and $3 million less in net derivative losses primarily related to the embedded derivative in the Rades Power Purchase Agreement (PPA). This was partially offset by the recognition of $12 million of realized losses in Power's NDT Fund.
For the six months ended June 30, 2003, Other Deductions decreased by $6 million as compared to the six months ended June 30, 2002, due primarily to $69 million less in foreign currency transaction losses, primarily related to US Dollar debt in Argentina recorded in 2002. This was partially offset by the recognition of $45 million of realized losses in Power's NDT Fund and $12 million in net derivative losses of which $8 million is related to the embedded derivative in the Rades PPA.
Interest Expense
For the quarter ended June 30, 2003, Interest Expense increased by $2 million or 1% as compared to the quarter ended June 30, 2002, primarily due to an $8 million increase at PSEG related to higher levels of debt outstanding, partially offset by a $6 million decrease at PSE&G discussed below.
For the six months ended June 30, 2003, Interest Expense decreased $2 million as compared to the six months ended June 30, 2002, primarily due to a $12 million decrease at PSE&G and a $4 million
51
decrease at Energy Holdings, partially offset by a $14 million increase at PSEG, related to higher levels of debt outstanding.
Preferred Securities Dividends
For the quarter and six months ended June 30, 2003, Preferred Securities Dividends increased approximately $4 million and $8 million, respectively, as compared to the same periods in 2002, primarily due to the issuance of preferred securities in September 2002 and December 2002.
Income Taxes
For the quarter and six months ended June 30, 2003, Income Taxes increased $191 million and $261 million, respectively, as compared to the same periods in 2002, primarily due to higher pre-tax income.
Losses From Discontinued Operations
Operating results of Energy Technologies' heating, ventilating and air conditioning (HVAC)/mechanical operating companies, less certain allocated costs from Energy Holdings, have been reclassified into Discontinued Operations in the Consolidated Statements of Operations. The results of operations of these discontinued operations for the quarter ended June 30, 2003 and 2002 yielded after-tax losses of $2 million and $5 million, respectively. The results of operations of these discontinued operations for the six months ended June 30, 2003 and 2002 yielded after-tax losses of $8 million and $9 million, respectively. Due to market conditions, Energy Holdings re-evaluated the carrying value of Energy Technologies and has determined that additional adjustments to fair value less cost to sell were required in the first quarter
of 2003 and, for the six months ended June 30, 2003, Energy Technologies recorded an after-tax loss of $9 million.
In addition, Tanir Bavi, a 220 MW barge mounted, combined-cycle generating facility in India which was sold in the fourth quarter of 2002, met the criteria for classification as a component of discontinued operations. The operating results of Tanir Bavi for the quarter and six months ended June 30, 2002 yielded after-tax income of $2 million and $5 million, respectively. For additional information, see Note 5. Discontinued Operations of the Notes.
Extraordinary Item
As discussed above, the oral decision issued by the BPU in connection with the Electric Base Rate Case included a $30 million refund related to revenues collected through the SBC for nuclear decommissioning. Because this amount reflects the final accounting for PSEG's generation-related business pursuant to the four-year transition plan mandated by PSE&G's Final Order received from the BPU in 1999 relating to EDECA, it has been recorded as an $18 million, after-tax, Extraordinary Item as required under APB 30. For additional information, see Note 16. Subsequent Events of the Notes.
Cumulative Effect of a Change in Accounting Principle
For the six months ended June 30, 2003, Power recorded a $370 million after-tax benefit to Net Income relating to the adoption of SFAS 143 as detailed further below under Power. For the six months ended June 30, 2002, Energy Holdings recorded a $120 million after-tax charge to Net Income due to goodwill impairments relating to the adoption of SFAS 142 as detailed further below under Energy Holdings.
PSE&G
Operating Revenues
PSE&G's Operating Revenues increased by $112 million or 9% for the quarter ended June 30, 2003 as compared to the quarter ended June 30, 2002. The primary reason for the increase was a $172 million or 56% increase in gas revenues, which was offset by a decrease of $60 million in electric revenues.
52
Total gas sales volumes increased by 17% for the quarter ended June 30, 2003 due primarily to favorable weather conditions resulting in added revenues of $68 million. Higher commodity prices added $99 million to revenues for the quarter. The price of gas for commercial and industrial customers, which varies monthly with market changes, increased $54 million. Gas price changes for residential customers, which must be approved by the BPU, increased by $39 million. In addition, revenues increased $5 million due to an SBC clause increase in November 2002 to recover additional DSM program charges which are offset in Operation and Maintenance expense.
Electric revenues decreased primarily due to the impact of the final rate decrease, effective August 2002, which reduced revenues by $44 million, and is offset by lower Energy Costs, discussed below. Also contributing to the decrease was the MTC overcollection adjustment of $18 million resulting from the Electric Base Rate Case settlement and decreases in sales volumes which resulted in a $15 million decrease in revenues. Offsetting the decreases were increased revenues from sales of NUG power of $15 million, primarily due to higher locational marginal pricing in PJM.
PSE&G's Operating Revenues increased by $601 million or 21% for the six months ended June 30, 2003 as compared to the six months ended June 30, 2002. The increase was driven by a $631 million increase in gas revenues offset by lower electric revenues of $30 million.
Total gas sales volumes increased by 23% for the six months ended June 30, 2003 due primarily to favorable weather conditions resulting in added revenues of $278 million. Increases in commodity prices added $356 million to revenues for the six months ended June 30, 2003. The price of gas for commercial and industrial customers, which varies monthly with market changes, increased $243 million. Gas price changes for residential customers, which must be approved by the BPU, increased by $95 million. In addition, revenues increased $18 million due to an SBC clause increase in November 2002 to recover additional DSM program charges which are offset in Operation and Maintenance expense.
Electric revenues decreased by $30 million for the six months ended, June 30, 2003. The impact of the 4.9% rate decrease, effective August 2002, which reduced revenues by $88 million, was the primary driver of the decrease, offset by lower Energy Costs, discussed below. The Electric Base Rate Case settlement MTC over-collection adjustment of $18 million also contributed to the decrease. Offsetting the decreases were higher electric sales volumes of 2.6%, primarily due to favorable weather conditions, which resulted in an increase of approximately $43 million and an increase of $34 million for revenues from sales of NUG power, primarily due to increased market prices.
Operating Expenses
Energy Costs
Energy
  Costs increased by $161 million, or 21% for the quarter ended June 30, 2003
  as compared to the same period in 2002. This was primarily due to an increase
  in gas costs of $140 million for the second quarter of 2003 as compared to the
  second quarter of 2002. The cost of gas purchased increased $51 million due
  to a 19% increase in the price of gas and $52 million due to an increase in
  commodity sales volume due primarily to favorable weather conditions. Additionally,
  gas costs increased by $35 million for the current deferral of BGSS-RSG costs
  to match current commodity revenues. In addition, electric costs increased $21
  million. BGS purchases increased $55 million due to a 13% increase in prices
  effective August 1, 2002 and decreased by $12 million due to lower sales volumes.
  Net MTC payments to Power increased by $14 million. The MTC payment to Power
  includes an increase of $52 million due to higher amortization of the excess
  depreciation reserve offset by the impact of the rate reduction. The impact
  of the amortization of the excess depreciation reserve was offset in amortization
  and tax expenses on the Consolidated Statements of Operations. In addition,
  electric costs decreased by $37 million due to the deferral of energy costs
  in excess of the amount included in revenues.
Energy Costs increased $609 million, or 34% for the six months ended June 30, 2003, as compared to the six months ended June 30, 2002. This was primarily due to an increase in gas costs of $526 million. The cost of gas purchased increased $223 million due to a 23% increase in the price of gas and $182 million due to an increase in commodity sales volume due primarily to favorable weather conditions this year. Additionally, gas costs increased by $110 million for the current deferral of BGSS-RSG costs to match current commodity revenues and $10 million for amortization of previous deferrals.
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Also, electric costs increased $83 million.
  BGS purchases increased $122 million due to a 14% increase in prices effective
  August 1, 2002 and increased by $19 million due to higher sales volumes. Net
  MTC payments to Power increased by $20 million. The MTC payment to Power includes
  an increase of $103 million due to higher amortization of the excess depreciation
  reserve offset by the impact of the rate reduction. The impact of the amortization
  of the excess depreciation reserve was offset in amortization and tax expenses
  on the Consolidated Statements of Operations. NUG energy purchases decreased
  by $3 million as a result of a $21 million decrease in volumes purchased offset
  by a higher average price of $18 million. In addition, electric costs decreased
  by $74 million due to the deferral of energy costs in excess of the amount included
  in revenues.
Operation and Maintenance
Operation and Maintenance expense decreased $15 million or 6% for the second quarter of 2003 as compared to the second quarter of 2002. The primary reason for the decrease was a reduction in real estate tax expense of $18 million and the reversal of a $10 million reserve against a regulatory asset that is now being recovered. Partially offsetting the decrease was a $7 million increase in DSM program amortization driven by higher sales and a rate increase for gas DSM recovery in November 2002. The gas increase is included in the delivery volume revenue increase discussed above. DSM costs are deferred when incurred and amortized to Operations and Maintenance expense when recovered in revenues. Also offsetting the decreases were higher labor related costs of $6 million, almost half of which was attributable to higher pension
costs.
Operation and Maintenance expense increased $17 million or 3% for the six months ended June 30, 2003 as compared to the six months ended June 30, 2002. The primary reason for the change was a $25 million increase in DSM program amortization, as discussed above. Other contributors to the Operation and Maintenance expense increase were higher labor related costs of $22 million, almost half of which was attributable to higher pension costs. Offsetting these increases was $28 million relating to a reduction in real estate tax expense and the reversal of a reserve, discussed above.
Depreciation and Amortization
Depreciation and Amortization decreased $34 million or 35% for the second quarter of 2003 as compared to the second quarter of 2002. The primary reason for the decrease is a reduction of $37 million, which relates to increased amortization of an excess electric distribution depreciation reserve. Based on the Final Order, approximately $148 million was amortized on a straight-line basis during 2002 and approximately $171 million is being amortized on a straight-line basis from January 1, 2003 to July 31, 2003, the end of the transition period under EDECA. Offsetting this decrease was a $3 million increase in depreciation expense due to increased plant in service.
Depreciation and Amortization decreased $63 million or 33% for the six months ended June 30, 2003 as compared to the six months ended June 30, 2002. The primary reason for the decrease is a reduction of $73 million relating to the amortization of an excess electric distribution depreciation reserve. Offsetting this decrease was a $6 million increase in depreciation expense due to increased plant in service and a $6 million increase in the amortization of the regulatory asset related to securitization, which was caused primarily by an increase in Securitization Transition Charge (STC) revenues.
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes increased $2 million or 8% and $8 million or 13% for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002. The increases were the result of higher TEFA due to higher taxable sales in 2003. Legislation enacted in January 2002 freezes the TEFA unit rate surcharges at the 2001 levels through 2004 and then reduces the rates over the next three years, phasing out the TEFA by 2007.
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Other Income
Other Income increased $1 million or 50% for the second quarter of 2003 as compared to the second quarter of 2002, due primarily to gains from short-term investments.
Other Income increased $11 million for the six months ended June 30, 2003 as compared to the six months ended June 30, 2002, due primarily to gains on the disposal of various electric transmission properties and gains from short-term investments.
Interest Expense
Interest Expense decreased by $6 million or 6% for the quarter ended June 30, 2003 as compared to the same period in 2002. Interest on long-term debt decreased $7 million, due to various maturities and issuances of Medium-Term Notes subsequent to the second quarter of 2002, and $2 million due to the payment of Securitization Bonds subsequent to the second quarter of 2002. The decreases were partially offset by $4 million of increased interest on restructuring costs as a result of the settlement of the Electric Base Rate Case.
Interest Expense decreased by $12 million or 6% for the six months ended June 30, 2003 as compared to the same period in 2002. Interest on long-term debt decreased $13 million, due to various maturities and issuances of Medium-Term Notes subsequent to the second quarter of 2002, and $4 million due to the payment of Securitization Bonds subsequent to the second quarter of 2002. The decreases were partially offset by $4 million of increased interest on restructuring costs as a result of the settlement of the Electric Base Rate Case.
Income Taxes
Income
  Taxes decreased by $8 million for the quarter ended June 30, 2003, as compared
  to the same period in 2002, due primarily to increased amortization of the excess
  depreciation reserve for financial statement purposes on which full deferred
  taxes are not provided, offset by an increase in pre-tax income.
Income
  Taxes increased by $6 million for the six months ended June 30, 2003, as compared
  to the same period in 2002, due primarily to an increase in pre-tax income offset
  by increased amortization of the excess depreciation reserve for financial statement
  purposes on which full deferred taxes are not provided.
Extraordinary Item
As discussed above, the oral decision issued by the BPU in connection with the Electric Base Rate Case included a $30 million refund related to revenues collected through the SBC for nuclear decommissioning. Because this amount reflects the final accounting for PSEG's generation-related business pursuant to the four-year transition plan mandated by PSE&G's Final Order received from the BPU in 1999 relating to EDECA, it has been recorded as an $18 million, after-tax, Extraordinary Item as required under APB 30. For additional information, see Note 16. Subsequent Events of the Notes.
Power
Operating Revenues
For the quarter and six months ended June 30, 2003, Operating Revenues increased $563 million and $1.8 billion, respectively, as compared to the quarter and six months ended June 30, 2002.
For the quarter and six months ended June 30, 2003, generation revenues increased $305 million and $653 million, respectively, compared to the same periods in 2002. The primary drivers contributing to the increase in generation revenues were the increased supply of generation under the load contracts with third party suppliers of BGS, which went into effect on August 1, 2002 and the participation in the New England Power Market mainly as the result of the acquisition of two Connecticut facilities in December 2002. As a result, Power experienced an increase in generation revenues of $289 million and $668 million for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002. Also contributing to the increase in generation revenues were additional MTC revenues of $14 million
and $18 million for the quarter and six months ended June 30, 2003, respectively, as
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compared to the same periods in 2002. Offsetting these increases for the six months ended June 30, 2003, were unrealized losses on financial instruments of $33 million primarily related to asset-backed financial transactions.
For the quarter and six months ended June 30, 2003, gas revenues increased $251 million and $1.2 billion, respectively, as compared to the same periods in 2002. The increases primarily relate to the fact that the BGSS contract with PSE&G did not commence until May 2002, therefore, Power did not have an operational gas business for the first four months of 2002. Gas revenues for April 2003, and for the first four months of 2003, totaled $167 million, and $1.1 billion, respectively. Gas revenues for the months of May and June of 2003 increased by approximately $84 million, compared to the prior months in 2002 due primarily to cooler temperatures resulting in higher sales volumes and higher gas prices.
Power seeks to trade around its owned assets and supply obligations using various financial instruments in order to maximize its generation and gas businesses. For the quarter and six months ended June 30, 2003, revenues from trading activities increased $7 million and $5 million, respectively, compared to same periods in 2002. Favorable market conditions led to higher trading volumes.
Operating Expenses
Energy Costs
For the quarter and six months ended June 30, 2003, Energy Costs increased $504 million and $1.7 billion, respectively, as compared to the same periods in 2002. Energy costs represent the cost of generation, which includes fuel purchases for generation, as well as purchased energy in the spot market and gas purchases to meet Power's obligation under its BGSS contract with PSE&G.
The increased Energy Costs were primarily due to higher gas costs relating to Power's BGSS contract with PSE&G combined with higher fuel expenses for generation which contributed approximately $273 million and $1.2 billion to the increase for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002. This increase was due primarily to the fact that Power did not have an operational gas business for the first four months of 2002 prior to the transfer of the gas contracts from PSE&G combined with higher gas sales volumes and prices and higher gas, oil and coal costs for generation. Additionally, the increase in Energy Costs was due to increased purchases on the spot market in order to meet the increased obligations under the new load contracts, which went into effect
on August 1, 2002 which amounted to approximately $155 million and $335 million for the quarter and six months ended June 30, 2003, respectively. Also, beginning August 1, 2002, Power began paying network transmission charges, which amounted to approximately $64 million and $135 million for the quarter and six months ended June 30, 2003, respectively.
Operation and Maintenance
Operation and Maintenance expense increased $39 million or 21% and $55 million or 15% for the quarter and six months ended June 30, 2003, respectively, from the comparable periods in 2002. This was primarily due to the acquisition of the generating facilities in Connecticut in December 2002, which increased Operation and Maintenance expenses by $13 million and $24 million for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002 combined with non-cash accretion expense of $6 million and $12 million for the quarter and six months ended June 30, 2003, respectively, associated with the implementation of SFAS 143. Also contributing to the increases were higher pension expenses, higher nuclear refueling outage costs and higher real estate tax expenses for the quarter and six
months ended June 30, 2003, as compared to the same periods in 2002.
Depreciation and Amortization
Depreciation and Amortization expense decreased $3 million for the quarter and six months ended June 30, 2003 from the comparable periods in 2002. Power had higher depreciation expense of approximately $12 million for the six month period ended June 30, 2003 due primarily to the acquisition of the generating facilities in Connecticut in December 2002 and a higher asset base, however this was
56
more than offset by the absence of decommissioning charges, which are no longer recorded as a result of the implementation of SFAS 143.
Other Income
Other Income increased $27 million and $74 million for the quarter and six months ended June 30, 2003, respectively, from the comparable periods in 2002, due primarily to the recording of realized gains and income on the NDT Fund.
Other Deductions
Other Deductions increased $12 million and $45 million for the quarter and six months ended June 30, 2003, respectively, from the comparable periods in 2002, due primarily to the recording of realized losses on the NDT Fund.
Interest Expense
Interest Expense remained flat for the quarter and six months ended June 30, 2003 from the comparable periods in 2002. Although Power incurred additional interest charges of $16 million for the six months ended June 30, 2003 due primarily to the new financing of $600 million in June 2002, this increase was offset by capitalized interest relating to various construction projects.
Income Taxes
Income Taxes increased $12 million or 19% and $55 million or 39% for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002, due primarily to increases in pre-tax income.
Cumulative Effect of Change in Accounting Principle
Power has performed a review of its potential obligations under SFAS 143 and believes that its quantifiable obligations are primarily related to the decommissioning of its nuclear power plants. Upon adoption of this standard on January 1, 2003, Power recorded a Cumulative Effect of a Change in Accounting Principle in the amount of $370 million, after-tax. For additional information, see Note 3. Adoption of SFAS 143 of the Notes.
Energy Holdings
Operating Revenues
For the quarter ended June 30, 2003, Energy Holdings' Operating Revenues increased $55 million, or 41%, to $188 million from the comparable period in 2002. This increase was driven by higher electric generation revenues at Global of $62 million, discussed below, and an increase in revenues at Resources of $35 million. This increase was due to lower revenue in 2002 primarily related to the net change in the carrying value of publicly traded and private securities held within Resources' KKR leveraged buyout funds. Partially offsetting the increase was the timing of a partnership withdrawal payment from EPCP received in the first quarter 2003 compared to the second quarter 2002. In 2001, Global withdrew from its interest in EPCP in exchange for a series of payments through 2005, provided certain operating contingencies
are met.
For the six months ended June 30, 2003, Energy Holdings' Operating Revenues increased $128 million, or 48%, to $397 million from the comparable period in 2002. This increase was driven by higher electric generation revenues at Global of $126 million and an increase in revenues at Resources of $28 million. This increase was due to lower revenue in 2002 primarily related to the net change in the carrying value of publicly traded and private securities held within the KKR leveraged buyout funds. This increase was partially offset by lower electric distribution and other electric revenue at Global in 2003 of $23 million, discussed below.
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Global
For the quarter ended June 30, 2003, Operating Revenues increased by $21 million or 21% to $122 million from $101 million for the quarter ended June 30, 2002. The increase in revenue was due to a $24 million increase from Skawina, a generation facility in Poland, in which Global purchased a majority ownership in June 2002, a $20 million increase from Rades, a generation facility in Tunisia which commenced operations in May 2002, and a $10 million increase from Salalah, a generation facility in Oman which began commercial operation in May 2003. Also contributing was a $13 million increase at GWF Energy. In the second half of 2002, Global's ownership of GWF Energy exceeded 75% and under the operating agreement Global gained a controlling interest. Accordingly, Global consolidates GWF Energy as compared to the second quarter
2002 when it was recorded under the equity method. These increases were partially offset by a decrease of $39 million of realized revenue from the partnership withdrawal from EPCP, which was recorded in the first quarter of 2003 as compared to the second quarter of 2002. Also offsetting the increase was a decrease of $6 million from Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), in Argentina, which was fully written off in 2002 and was abandoned in the first quarter of 2003.
For the six months ended June 30, 2003, Operating Revenues increased $100 million or 56% to $279 million from $179 million for the six months ended June 30, 2002. The increase in revenue was due to a $50 million increase from Skawina, a $42 million increase from Rades and a $10 million increase from Salalah. Also contributing was a $22 million increase at GWF Energy. These increases were partially offset by a decrease of $20 million from EDEERSA.
Resources
For the quarter ended June 30, 2003, Operating Revenues increased $35 million or 109% to $67 million from $32 million for the quarter ended June 30, 2002. The increase was primarily related to $38 million of other than temporary impairments of non-publicly traded equity securities held within the KKR leveraged buyout funds recorded in the second quarter of 2002 compared to $6 million in gains in the second quarter of 2003. This increase was partially offset by a decrease of $4 million in income from capital leases due to terminated leases.
For the six months ended June 30, 2003, Operating Revenues increased $28 million or 31% to $118 million from $90 million for the six months ended June 30, 2002. This increase was primarily related to a $33 million net decrease of other than temporary impairments of non-publicly traded equity securities held within the KKR leveraged buyout funds recorded in the first quarter 2003 and second quarter of 2002. Also contributing was a $6 million decrease in income from capital leases due to terminated leases.
Operating Expenses
For the quarter ended June 30, 2003, Operating Expenses decreased $470 million or 81% to $107 million from $577 million for the quarter ended June 30, 2002. This decrease was primarily due to the write-down of project investments in Argentina at Global of $506 million in the second quarter of 2002. Partially offsetting this decrease was an increase in operating expenses of $17 million from Skawina, a $14 million increase from Rades and a $6 million increase from Salalah.
For the six months ended June 30, 2003, Operating Expenses decreased $443 million or 69% to $199 million from $642 million for the six months ended June 30, 2002. This decrease was primarily due to the write-down of project investments in Argentina at Global of $506 million in the second quarter of 2002. Partially offsetting this decrease was an increase in operating expenses of $33 million from Skawina and a $29 million increase from Rades.
Income from Equity Method Investments
For the quarter ended June 30, 2003, Income from Equity Method Investments decreased by $2 million or 6% to $31 million from $33 million for the quarter ended June 30, 2002. These decreases are primarily due to lower earnings in 2003 of $4 million at RGE and lower interest income of $12 million
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from GWF Energy and EPCP. This decrease was partially offset by increased revenue of $7 million from TIE. Also offsetting the decrease was a change in accounting for GWF Energy, which was accounted for under the equity method and reported a loss of $6 million in 2002 and is now recorded as a consolidated entity due to Energy Holdings' increased ownership percentage.
For the six months ended June 30, 2003, Income from Equity Method Investments decreased $15 million or 24% to $48 million from $63 million for the six months ended June 30, 2002. These decreases are primarily due to lower earnings in 2003 of $13 million at RGE and lower interest income of $9 million from GWF Energy and EPCP. This decrease was partially offset by increased revenue of $8 million at TIE. Also offsetting the decrease was changes in accounting for GWF expansion, which was accounted for under the equity method and reported a loss of $5 million in 2002 and is now recorded as a consolidated entity due to Energy Holdings' increased ownership percentage.
Other Deductions
For the quarter ended June 30, 2003, Other Deductions decreased $18 million due primarily to a decrease of $15 million in foreign currency transaction losses, primarily related to losses of $17 million in Argentina in 2002, and a decrease of $3 million in net derivative losses primarily related to the embedded derivative in the Rades PPA.
For the six months ended June 30, 2003, Other Deductions decreased by $57 million to $12 million. The decrease was largely due to $1 million in foreign currency transactions gains for the six months ended June 30, 2003 compared to a $69 million foreign currency transaction loss for the same period in 2002. This decrease was partially offset by an increase of $12 million in net derivative losses of which $8 million is related to the embedded derivative in the Rades PPA.
Interest Expense
For the six months ended June 30, 2003, Interest Expense decreased $4 million or 4% to $104 million from $108 million for the six months ended June 30, 2002. The decrease is primarily due to the maturity of Medium-Term Notes at PSEG Capital Corporation (PSEG Capital) in the second half of 2002 of $130 million and in May 2003 of $252 million, which resulted in a decrease of $9 million in interest expense. Partially offsetting this decrease is interest expense related to Energy Holdings' $350 million of Senior Notes issued in April 2003.
Income Taxes
Income Taxes increased $193 million and $210 million for the quarter and six months ended June 30, 2003, respectively, from a benefit of $177 million from the comparable periods in 2002. This increase is attributed to taxable income for the quarter and six months ended June 30, 2003 compared to tax benefits in the same period in 2002 related to pre-tax losses.
Losses From Discontinued Operations
Operating results of Energy Technologies' HVAC/mechanical operating companies, less certain allocated costs from Energy Holdings, have been reclassified into Discontinued Operations in the Consolidated Statements of Operations. The results of operations of these discontinued operations for the quarter ended June 30, 2003 and 2002 yielded after-tax losses of $2 million and $5 million, respectively. The results of operations of these discontinued operations for the six months ended June 30, 2003 and 2002 yielded after-tax losses of $8 million and $9 million, respectively. Due to market conditions, Energy Holdings re-evaluated the carrying value of Energy Technologies and has determined that an additional adjustments to fair value less cost to sell were required in the first quarter of 2003 and, for the six months ended
June 30, 2003, Energy Technologies recorded an after-tax loss of $9 million.
In addition, Tanir Bavi, which was sold in the fourth quarter of 2002, met the criteria for classification as a component of discontinued operations. The operating results of Tanir Bavi for the
59
quarter and six months ended June 30, 2002 yielded after-tax income of $2 million and $5 million, respectively. For additional information, see Note 5. Discontinued Operations of the Notes.
Cumulative Effect of Change in Accounting Principle
In 2002, Energy Holding finalized the evaluation of the effect of adopting SFAS 142 on the recorded amount of goodwill. The total amount of goodwill impairments was $120 million, net of tax of $66 million and was comprised of write-downs of $36 million (after-tax) at EDEERSA, $34 million (after-tax) at RGE, $32 million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir Bavi. All of the goodwill related to these companies, other than RGE, was fully impaired.
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
PSEG's operating cash flow increased approximately $92 million from $536 million to $628 million for the six months ended June 30, 2003, as compared to the six months ended June 30, 2002, due primarily to increases of $505 million at Power and $79 million at Energy Holdings, largely offset by a $518 million decrease at PSE&G. PSEG expects operating cash flows to be sufficient to fund the majority of capital requirements and future dividend payments.
Dividend payments on common stock for the quarter ended June 30, 2003 were $0.54 per share and totaled approximately $122 million. Dividend payments on common stock for the six months ended June 30, 2003 were $1.08 per share and totaled approximately $244 million. Future dividends declared will be dependent upon PSEG's future earnings, cash flows, financial requirements, alternate investment opportunities and other factors. For additional information on PSEG's dividends, see Overview.
PSE&G
PSE&G's operating cash flow decreased approximately $518 million from $490 million to $(28) million for the six months ended June 30, 2003, as compared to the six months ended June 30, 2002, due primarily to the sale of its entire gas inventory for approximately $415 million in the first half of 2002, including approximately $183 million received from Power for the gas contract transfer in May 2002, combined with the timing of collections from customers as compared to payments under energy contracts. This was partially offset by increased Income from Continuing Operations and increased recoveries of deferred commodity and other costs.
Power
Power's operating cash flow increased approximately $505 million from $75 million to $580 million for the six months ended June 30, 2003, as compared to the six months ended June 30, 2002, due to several factors, including approximately $282 million of lower working capital requirements for the six months ended June 30, 2003, as compared to the same period in 2002, primarily due to the Gas Contract Transfer from PSE&G which occurred in the second quarter of 2002 and positive cash inflow in 2003 mainly from sales under the BGSS contract. Also contributing to the increase was increased Income from Continuing Operations of approximately $83 million.
Energy Holdings
Energy Holdings' operating cash flow increased approximately $79 million from $24 million to $103 million for the six months ended June 30, 2003, as compared to the six months ended June 30, 2002.
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This increase is primarily related to the absence in 2003 of loans made to TIE and GWF Energy in 2002 that were used to provide funding for project level construction prior to permanent project financing.
Debt Covenants
PSEG, PSE&G, Power and Energy Holdings
PSEG's, PSE&G's, Power's and Energy Holdings' respective credit agreements generally contain customary provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower's business or financial condition.
As explained in detail below, some of these credit agreements also contain maximum debt-to-equity ratios, minimum cash flow tests and other restrictive covenants and conditions to borrowing. Compliance with applicable financial covenants will depend upon the future financial position, level of earnings and cash flows of PSEG, PSE&G, Power and Energy Holdings, as to which no assurances can be given. The ratios presented below are for the benefit of the investors of the related securities to which the covenants apply. They are not intended as a financial performance or liquidity measure. The preferred securities of PSEG and PSE&G, which will be presented as Noncurrent Liabilities, effective July 1, 2003 in accordance with SFAS 150, will not be included as debt when calculating these ratios, as provided in the
various credit agreements.
PSEG
Financial covenants contained in PSEG's credit facilities include a ratio of debt (excluding non-recourse project financings and securitization debt and including commercial paper and loans, certain letters of credit and similar instruments) to total capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio not be more than 0.70 to 1. As of June 30, 2003, PSEG's ratio of debt to capitalization (as defined above) was 0.59 to 1.
PSE&G
Financial covenants contained in PSE&G's credit facilities include a ratio of long-term debt (excluding securitization debt and long-term debt maturing within one year) to total capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio will not be more than 0.65 to 1. As of June 30, 2003, PSE&G's ratio of long-term debt to total capitalization was 0.49 to 1.
In addition, under its 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 2:1, and/or against retired Mortgage Bonds. At June 30, 2003, PSE&G's Mortgage coverage ratio was 3:1 and the Mortgage would permit up to approximately $1.5 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 covenant for each specific borrower. Where PSEG is the borrower, the covenant described above in PSEG is applicable. Where Power is the borrower, a debt (excluding non-recourse project financings and including loans, certain letters of credit and similar instruments) to total capitalization, adjusted for the $986 million Basis Adjustment (see Consolidated Balance Sheets), covenant applies. This covenant requires that at the end of any quarterly financial period, such ratio will not be more than 0.65 to 1. As of June 30, 2003, Power's ratio of debt to capitalization (as defined above) was 0.45 to 1.
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Energy Holdings
Financial covenants contained in Energy Holdings' credit facility includes the ratio of cash flow available for debt service (CFADS) to fixed charges. CFADS includes, but is not limited to, operating cash flows before interest and taxes, pre-tax cash distributions from all asset liquidations and equity capital contributions from PSEG to the extent not used to fund investing activity. At the end of any quarterly financial period such ratio is required to be not less than 1.50x for the 12-month period then ending. As a condition of borrowing, the pro forma CFADS to fixed charges ratio is required to be not less than 1.75x as of the quarterly financial period ending immediately following the first anniversary of each borrowing or letter of credit issuance. As of June 30, 2003, Energy Holdings ratio of CFADS to fixed
charges was 5.6x. In addition, the ratio of consolidated recourse indebtedness to recourse capitalization, as of the end of any quarterly financial period, shall not be greater than 0.60 to 1. This ratio is calculated by dividing the total recourse indebtedness of Energy Holdings by the total recourse capitalization. As of June 30, 2003, Energy Holdings' ratio of consolidated recourse indebtedness to recourse capitalization was 0.47 to 1.00.
On April
  16, 2003, Energy Holdings issued $350 million in Senior Notes which contain
  financial covenants that include debt incurrence tests consisting of a debt
  service coverage test and a ratio of consolidated recourse indebtedness to recourse
  capitalization test which require that Energy Holdings will not incur additional
  consolidated recourse indebtedness, unless, on a pro forma basis giving effect
  to the incurrence of the additional consolidated recourse indebtedness, (i)
  the debt service coverage ratio would be at least 2 to 1 and (ii) the ratio
  of consolidated recourse indebtedness to recourse capitalization would not exceed
  0.60 to 1. Certain permitted indebtedness, such as permitted refinancings and
  borrowings under its 5-year credit facility are excluded from this test. The
  provisions of the Senior Notes also restrict Energy Holdings from selling greater
  than 10% of its assets in any four consecutive quarters, unless the proceeds
  are used to reduce debt of Energy Holdings or its subsidiaries or are retained
  by Energy Holdings.
Cross Default Provisions
Certain information reported in the 2002 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 is updated below.
PSEG
  and Energy Holdings
PSEG's
  bank credit agreements and note purchase agreements (Credit Agreements) relating
  to its private placement of institutional debt contain cross default provisions
  under which certain payment defaults by PSE&G, Power or Energy Holdings,
  certain bankruptcy events relating to PSE&G, Power or Energy Holdings, the
  failure by PSE&G, Power or Energy Holdings to satisfy certain final judgments
  or the occurrence of certain events of default under the financing agreements
  of PSE&G, Power or Energy Holdings, would each constitute an event of default
  under the PSEG Credit Agreements. It is also an event of default under the PSEG
  Credit Agreements, if PSE&G, Power or Energy Holdings ceases to be wholly-owned
  by PSEG. Energy Holdings' current credit agreement, which expires in May 2004,
  provides that certain payment or other events of default by PSEG or a failure
  by PSEG to satisfy certain final judgments, maintain ownership of at least 80%
  of the capital stock of Energy Holdings or maintain a specified level of consolidated
  net worth, would each constitute an event of default under Energy Holdings'
  credit agreement.
PSEG's bank credit agreements have been
  amended to eliminate the payment cross-default relating to Energy Holdings as
  a PSEG-level event of default, effective with the termination of the current
  Energy Holdings' credit agreement. PSEG has recently amended its note purchase
  agreements and is in the process of seeking consents from the lenders under
  its bank credit agreements to exclude Energy Holdings from all cross-default
  provisions effective with the termination of the current Energy Holdings' credit
  agreement. PSEG is also in the process of replacing Energy Holdings' credit
  agreement with a new bank credit agreement seeking to eliminate PSEG-level covenants
  other than the maintenance of ownership of at least 80% of the capital stock
  of Energy Holdings.
Ratings Triggers
PSEG, PSE&G, Power and Energy Holdings
The debt indentures and credit agreements of PSEG, PSE&G, Power and Energy Holdings do not contain any material ''ratings triggers'' that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and collateral requirements.
Power
In connection with its energy marketing and trading activities, Power must meet certain credit quality standards required by counterparties. If Power loses its investment grade credit rating, PSEG Energy Resources & Trade LLC (ER&T) would have to provide credit support (letters of credit or
62

cash), which would significantly impact
  the cost of its energy trading activities. In addition, all Master Agreements
  and other supply contracts, including Power's BGS-related load contracts, contain
  margin and/or other collateral requirements that, as of June 30, 2003,
  could require Power to post additional collateral of approximately $353 million
  if Power were to lose its investment grade credit rating and all counterparties,
  where Power is ''out-of-the money'' under such contracts, were entitled to and
  called for collateral. Providing this credit support would increase Power's
  costs of doing business and could limit Power's ability to successfully conduct
  its energy trading operations.
Energy Holdings
Energy Holdings and Global may have to post letters of credit of approximately $70 million for certain of their equity commitments if one of Energy Holdings' ratings should fall below investment grade. Approximately $61 million of these equity commitments are included in Energy Holdings' anticipated capital expenditures for the remainder of 2003. These letters of credit, if required, would be readily available under Energy Holdings' credit facility.
Credit Ratings
The
  current ratings of securities of PSEG and its subsidiaries are shown below and
  reflect the respective views of the rating agencies, from whom an explanation
  of the significance of their ratings may be obtained. In the ordinary course
  of business, PSEG has regular discussions with each of the rating agencies.
  There is no assurance that these 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. Any downward revision or withdrawal
  may adversely effect the market price of PSEG's, Energy Holdings', Power's and
  PSE&G's securities and serve to increase those companies' cost of capital
  and limit their access to capital.
Moody's

Standard & Poor's

FitchPSEG:Preferred Securities

Baa3

BB+

BBBCommercial Paper

P2

A2

Not RatedPSE&G:Mortgage Bonds

A3

A-

APreferred Securities

Baa2

BB+

BBB+Commercial Paper

P2

A2

F1Power:Senior Notes

Baa1

BBB

BBB+Energy Holdings:Senior Notes

Baa3

BBB-

BBB-On June 16, 2003, Moody's announced that it had placed the ratings of PSEG's Preferred Securities, and Power's and Energy Holdings' Senior Notes under review for possible downgrade and reaffirmed PSE&G's ratings. Moody's stated that it does not expect that the review would result in the ratings of PSEG or Power falling by more than one notch. PSEG, Power and Energy Holdings are continuing their discussions with Moody's to facilitate this process. No assurances can be given as to the final outcome of this matter.

63

Short-Term Liquidity
PSEG, PSE&G, Power and Energy Holdings
As of
  June 30, 2003, PSEG had a total of approximately $2.2 billion of committed credit
  facilities, with approximately $842 million reserved for commercial paper program
  liquidity support and an additional $19 million and $42 million drawn for
  letters of credit at Power and Energy Holdings, respectively. This resulted
  in approximately $1.3 billion of available liquidity. In addition to this amount,
  PSEG, PSE&G and Energy Holdings had access to certain uncommitted credit
  facilities under which PSE&G had $161 million outstanding as of June 30,
  2003. The following table summarizes the various revolving credit facilities
  of PSEG and its subsidiaries and the liquidity available as of June 30,
  2003.
Company

Expiration Date

Total Facility

Primary Purpose

Usage at 06/30/2003

Available Liquidity at 06/30/2003(Millions)PSEG:364-day Credit Facility

March 2004

$
350


CP Support

$
350


$
—5-year Credit Facility

March 2005

$
280


CP Support

$
151


$
1293-year Credit Facility

December 2005

$
350


CP Support/
Funding

$
—


$
350Uncommitted Bilateral            Agreement

N/A


N/A


Funding

$
—



N/APSE&G:364-day Credit Facility

June 2004

$
200


CP Support

$
200


$
—3-year Credit Facility

June 2005

$
200


CP Support

$
141


$
59Uncommitted Bilateral            Agreement

N/A


N/A


Funding

$
161



N/APSEG and Power:364-day Credit Facility(A)

March 2004

$
250


CP Support/
Funding

$
—


$
250Power:3-year Credit Facility

August 2005

$
25


Funding

$
19


$
6Energy Holdings:5-year Credit Facility

May 2004

$
495


Funding

$
42


$
453Uncommitted Bilateral            Agreement

N/A


N/A


Funding

$
—



N/A
(A) PSEG/Power co-borrower facility
In order to support its short-term financing requirements, as well as those of Power, PSEG has revolving credit facilities that are used both as a source of short-term funding and to provide backup liquidity for its $1 billion commercial paper program.
PSEG has a $350 million facility expiring in December 2005 that provides liquidity support for its commercial paper program and can also be used as a source of short-term funding and to issue letters of credit. PSEG also has a $350 million facility expiring in March 2004 and a $280 million facility expiring in March 2005, both of which are used to provide liquidity support for its commercial paper program.
The $250 million PSEG/Power joint and several facility provides liquidity support for the PSEG commercial paper program and can be used by either PSEG or Power as a source of short-term funding and to issue letters of credit. Under this facility, either PSEG or Power may borrow and both are joint and severally liable to repay the loans.
64
PSE&G
On June 26, 2003, PSE&G renewed its $200 million 364-day credit facility. In addition, PSE&G has a $200 million 3-year credit facility expiring in June 2005. The purpose of both facilities is to provide liquidity support for PSE&G's $400 million commercial paper program.
Power
Power has access to the $250 million, 364-day joint and several PSEG/Power credit facility and a separate $25 million credit facility, but primarily relies on PSEG for its short-term financing needs. For information regarding affiliate borrowings, see Note 14. Related-Party Transactions of the Notes.
As of June 30, 2003, letters of credit issued by Power were outstanding in the amount of approximately $86 million, including the $19 million drawn against its credit facilities, in support of various contractual obligations, environmental liabilities and to satisfy trading collateral obligations.
Energy Holdings
Energy
  Holdings has a revolving and letter of credit facility totaling $495 million
  that is used both as a source of short-term funding and to issue letters of
  credit. In May 2003, a $200 million facility expired and was not renewed
  as that level of short-term funding was deemed no longer necessary for Energy
  Holdings' financing needs. As of June 30, 2003, in addition to amounts
  outstanding under Energy Holdings' credit facilities shown in the above table,
  subsidiaries of Global had $67 million of non-recourse short-term financing
  at the project level. For information regarding affiliate borrowings, see Note
  14. Related-Party Transactions of the Notes.
External Financings
PSEG
In 2002, PSEG began issuing shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Plan, rather than purchasing them on the open market. For the quarter ended June 30, 2003, PSEG issued approximately 504,000 shares for approximately $21 million pursuant to these plans. For the six months ended June 30, 2003, PSEG issued approximately 1,074,000 shares for approximately $42 million pursuant to these plans.
PSE&G
In January 2003, PSE&G issued $150 million of 5.00% Medium-Term Notes due 2013. The proceeds from this issuance were used to repay $150 million of 6.875% Series MM Mortgage Bonds which matured in January 2003.
Also in January 2003, PSEG contributed $170 million to PSE&G.
In June 2003, $150 million of 8.875% Series DD Mortgage Bonds matured.
During the six months ended June 30, 2003, Transition Funding, a wholly-owned subsidiary of PSE&G, repaid $58 million of securitization bonds as scheduled.
Energy Holdings
During
  January and February of 2003, Sociedad Austral de Electricidad S.A. (SAESA)
  and Empresa Electrica de la Frontera S.A. (Frontel), two distribution companies
  in Chile, refinanced certain short-term obligations through a combination of
  bonds, a syndicated bank facility and equity from Global. SAESA issued two series
  of local bonds in Chile equivalent to $117 million with final maturities in
  2009 and 2023. Frontel executed a syndicated loan facility equivalent to $23
  million with final maturity in 2010. In addition, during January 2003, Global
  made planned equity contributions to SAESA and Frontel totaling $55 million.
Part of the purchase price of Electroandes, a generation facility in Peru, was financed with a $100 million one-year bridge loan with an original maturity date in December 2002 that was subsequently
65
extended to June 2003. In March 2003, Electroandes refinanced the $100 million bridge loan with a $70 million seven-year amortizing facility and two $15 million one-year facilities (each guaranteed by Energy Holdings). Additionally, in June 2003, Electroandes sold $50 million of bonds in the local market. These bonds have a 6.4375% coupon and mature in 2013. The bonds include a 5-year grace period on principal payments. Proceeds from this bond issue were used to repay the two $15 million one-year facilities and $20 million of the $70 million seven-year facility. Electroandes expects to complete the refinancing of the seven-year facility from future bond issues.
In April 2003, Energy Holdings, in a private placement, issued $350 million of its 7.75% Senior Notes due in 2007. The proceeds were used in part to repay PSEG Capital Corporation's (PSEG Capital) remaining $252 million of 6.25% Medium-Term Notes that matured in May 2003. Energy Holdings does not plan to use PSEG Capital as a financing vehicle in the future and is in the process of dissolving PSEG Capital. The remaining proceeds from the sale of the Senior Notes will be used for general corporate purposes and, with cash generated from operations and expected asset sales, to meet Energy Holdings' May 2004 Senior Notes maturity and maintain sufficient liquidity at Energy Holdings. In July 2003, Energy Holdings completed an exchange offer for its outstanding 7.75% Senior Notes due 2007.
In May
  2003, GWF Power Systems, L.P. (GWF) and Hanford L.P. (Hanford), closed on $55
  million in syndicated bank loans along with an additional $7 million letter
  of credit facility. Global and Harbert Power (Harbert) each own 50% of GWF and
  Hanford. GWF and Hanford used the net proceeds from the bank loan to pay back
  investments from Global and Harbert. Global received a cash distribution of
  approximately $27 million in May 2003 and reduced its investment in GWF to $66
  million as of June 30, 2003.
Credit Risk
PSEG, PSE&G, Power and Energy Holdings
Credit risk relates to the risk of loss that PSEG, PSE&G, Power and Energy Holdings would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG, PSE&G, Power and Energy Holdings have established credit policies that they believe significantly mitigate credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which may allow for the netting of positive and negative exposures associated with a single counterparty.
Power
Counterparties expose Power to credit losses in the event of non-performance or non-payment. Power has a credit management process which is used to assess, monitor and mitigate counterparty exposure for Power and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power and its subsidiaries' financial condition, results of operations or net cash flows. As of June 30, 2003, over 95% of the credit exposure (mark-to-market plus net receivables and payables, less cash collateral) for Power's trading operations was with investment grade counterparties. As of June 30, 2003, Power's trading operations had over 150 active counterparties.
In December 2001, Enron Corp. (Enron) and its subsidiaries filed for reorganization under Chapter 11 of the US Bankruptcy Code. Power had entered into a variety of energy trading contracts with Enron and its affiliates as part of its energy trading activities. As of December 31, 2002, Enron had made claims against Power and asserted that payment obligations of Enron Power Marketing to Power may not be offset against this amount. Power paid Enron approximately $36 million in July 2003 under a settlement for these claims.
66

Energy Holdings
Project cash flows at TIE were insufficient to pay the loan installment of approximately $2 million due to Global on March 31, 2003 and Panda Energy International, Inc. (Panda)/Teco Power Services (Teco) failed to fund the 50% of the partnership cash call due from them in support of the March 31, 2003 debt service payment. Consequently, the loan due to Global was in default and the interest rate increased to the default rate of 14%. If the default had continued, Global had the right to foreclose on Panda/Teco's 50% interest in TIE, which has been pledged to secure the loans due to Global. Global received the March 31, 2003 loan repayment, including interest, in June 2003, curing the default. For additional information relating to this loan, see Note 14. Related-Party Transactions of the Notes.
CAPITAL REQUIREMENTS
PSEG, PSE&G, Power and Energy Holdings
It is expected that the majority of PSE&G's, Power's and Energy Holdings' capital requirements will come from 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 presently expect to contribute additional equity to Energy Holdings.
PSE&G
During the six months ended June 30, 2003, PSE&G had net plant additions of $229 million related to improvements in its transmission and distribution system, gas system and common facilities.
Power
During the six months ended June 30, 2003, Power made approximately $330 million of capital expenditures, primarily related to developing the Lawrenceburg, Indiana, Waterford, Ohio and Bethlehem, New York (Albany) sites and adding capacity to the Linden station in New Jersey.
Energy Holdings
During the quarter ended June 30, 2003, Energy Holdings made approximately $169 million of capital expenditures, primarily related to equity investments in SAESA and the Salalah, Oman and the GWF Energy Tracy plants.
ACCOUNTING ISSUES
SFAS No. 143, ''Accounting for Asset Retirement Obligations'' (SFAS 143)
PSEG, PSE&G, Power and Energy Holdings
Effective January 1, 2003, PSEG, PSE&G, Power and Energy Holdings each adopted SFAS 143. SFAS 143 addresses accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract.
Under SFAS 143, a company must initially recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred and concurrently capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. A company is required to subsequently accrete that asset retirement cost to expense over its useful life. In periods subsequent to initial measurement, an entity is required to recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either the timing or the amount of the originally estimated cash flows. Changes in the liability due to accretion will be charged to Operation and Maintenance expense on the Consolidated Statements of Operations, whereas changes due to
the timing or amount of cash flows will be an adjustment to the carrying amount of the related asset. See Note 3. Adoption of SFAS 143 of the Notes for additional information.
67
Financial Interpretation (FIN) No. 46, ''Consolidation of Variable Interest Entities (VIE)'' (FIN 46)
PSEG, PSE&G, Power and Energy Holdings
FIN 46 clarifies the application of Accounting Research Bulletin No. 51, ''Consolidated Financial Statements'', to certain entities in which equity investors do not have the characteristics of a controlling financial interest. Because a controlling financial interest in an entity may be achieved through arrangements that do not involve voting interests, FIN 46 sets forth specific requirements with respect to consolidation, measurement and disclosure of such relationships. Disclosure requirements for existing qualifying entities are effective for financial statements issued after January 31, 2003. All enterprises with VIEs created after February 1, 2003, are required to apply the provisions of FIN 46 no later than the beginning of the first interim period beginning after June 15, 2003. PSEG, PSE&G, Power and Energy
Holdings are still evaluating this guidance.
SFAS No. 149, ''Amendment of Statement 133 on Derivative Instruments and Hedging Activities'' (SFAS 149)
PSEG, PSE&G, Power and Energy Holdings
SFAS 149 amends and clarifies the accounting guidance for derivative instruments (including certain derivative instruments embedded in other contracts) and hedging activities that fall within the scope of SFAS No. 133, ''Accounting for Derivative Instruments and Hedging Activities'' (SFAS 133).
In particular, SFAS 149 clarifies circumstances under which a contract with an initial net investment meets the characteristic of a derivative discussed in SFAS 133, clarifies when a derivative contains a financing component and amends the definition of an underlying to conform it to language used in FIN No. 45, ''Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others''.
Additionally, SFAS 149 amends SFAS 133's criteria for electing the normal purchase and sale exception, which exempts certain derivatives that meet the normal purchase and sales criteria, from fair value reporting. The new guidance allows ''normal'' treatment for a power purchase or sale agreement (whether a forward, an option or combination of both) that is a capacity contract, as defined, even if the contract is closed out before maturity. However, any non-power commodity contract (e.g. gas contracts) and non-capacity power contract subject closed out before maturity will be ineligible for ''normal'' treatment and could result in those contracts being marked to market.
SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. Although PSEG, PSE&G, Power and Energy Holdings do not expect a material impact on their respective financial statements due to the adoption of these rules, no assurances can be given.
SFAS No. 150, ''Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity'' (SFAS 150)
PSEG and PSE&G
SFAS 150, which is effective July 1, 2003, establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. Many of these instruments that were previously presented as equity or as mezzanine instruments (between the liabilities and the equity section) will now be recorded as liabilities. SFAS 150 requires an issuer to classify qualifying instruments issued in the form of shares that are mandatorily redeemable as liabilities. Those items will no longer be presented as mezzanine instruments on the Consolidated Balance Sheets.
68
As of June 30, 2003, the following instruments are included with Preferred Securities on PSEG's and PSE&G's respective Consolidated Balance Sheets between Long-Term Debt and Common Equity.
Shares Outstanding

As of
June 30, 2003(Millions)PSEG (Parent)PSEG Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures7.44%


9,000,000


$
225Floating Rate


150,000



1507.25%


6,000,000



1508.75%


7,200,000



180PSEG Participating Units 10.25%


9,200,000



460Total PSEG (Parent)






1,165PSE&GPSE&G 8.00% Monthly Guaranteed Preferred Beneficial Interest in Subordinated Debentures


2,400,000



60PSE&G Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's 8.125% Subordinated            Debentures


3,800,000



95Total PSE&G






155Total PSEG Consolidated





$
1,320Effective July 1, 2003, these instruments will be presented separately in Noncurrent Liabilities on the Consolidated Balance Sheets and dividend payments on these instruments will be recorded as Interest Expense on the Consolidated Statements of Operations and be included in the Interest Paid supplemental disclosure on the Consolidated Statements of Cash Flows.
Other
PSEG, PSE&G, Power and Energy Holdings
In January 2001, PSEG, PSE&G, Power and Energy Holdings each adopted SFAS 133. In accordance with SFAS 133, all derivative instruments are recognized on the balance sheet at their fair values. In relation to this standard, the Financial Accounting Standards Board (FASB) Derivative Implementation Group (DIG) issued certain interpretive guidance, including DIG Issue C-11 that relates to contracts which include broad market indices (e.g., Consumer Price Index). That interpretation sets forth the guidelines under which a contract could qualify as a normal purchase or sale under SFAS 133. In 2003, the FASB issued DIG Issue C-20 to amend the previous interpretation stating that the phrase ''not clearly and closely related to the asset being sold or purchased'' should involve an analysis of both qualitative and quantitative
considerations. PSE&G, Power and Energy Holdings have reviewed their respective contracts and each have determined that there will be no impact resulting from the adoption of this interpretation.
ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
PSEG, PSE&G, Power and Energy Holdings
The market risk inherent in PSEG's, PSE&G's, Power's and Energy Holdings' market risk sensitive instruments and positions is the potential loss arising from adverse changes in foreign currency exchange rates, commodity prices, equity security prices and interest rates as discussed in Note 8. Risk Management of the Notes to the Consolidated Financial Statements. Each of PSEG, PSE&G, Power and Energy Holdings' policy is to use derivatives to manage risk consistent with its respective business plans and prudent practices. PSEG, PSE&G, Power and Energy Holdings use a Risk Management Committee (RMC) comprised of executive officers which utilize an independent risk oversight function
69
to ensure compliance with corporate policies and prudent risk management practices. Except as discussed below, there were no material changes from the disclosures in PSEG, PSE&G, Power and Energy Holdings' Annual Report on Form 10-K for the year ended December 31, 2002 or Quarterly Report on Form 10-Q for the quarter ended March 31, 2003.
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 and other events. To reduce price risk
  caused by market fluctuations, Power enters into supply contracts and derivative
  contracts, including forwards, futures, swaps and options with approved counterparties,
  to hedge its anticipated supply and demand differential. These contracts, in
  conjunction with owned electric generation capacity and demand obligations,
  make up the portfolio.
Power
  uses a value-at-risk (VaR) model to assess the market risk of its commodity
  business. The 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 business.

VaR Model
Power manages its exposure at the portfolio level. Its portfolio consists of owned generation, load-serving contracts (both gas and electric), gas supply contracts and energy derivatives designed to manage the risk around the differential between generation and load.
The RMC of PSEG established a VaR threshold of $50 million for a one-week (5 business days) holding period at a 95% (two-tailed) confidence level. The RMC will be notified if the VaR reaches $40 million and the portfolio will be closely monitored. The Board of Directors of PSEG is notified if a VaR threshold of $75 million is reached.
The current modeling process and methodology has previously been reviewed by a third party consulting firm. This review included analysis and comparison of Power's current VaR process and methodology to other processes and methodologies used in the energy industry. PSEG believes the evaluation indicates that Power's methodology to calculate VaR is reasonable.
The model is an augmented variance/covariance model adjusted for the delta of positions with a 95% two-tailed confidence level for a one-week holding period. The model is augmented to incorporate the non log-normality of energy-related commodity prices, especially emissions and capacity and the non-stationary nature of energy volatility. In many commodities the natural log of prices is normally distributed. This is not true of energy commodities which have a higher frequency of extreme events than would be predicted by a normal distribution. The model also assumes no hedging activity throughout the holding period whereas Power actively manages its portfolio.
As of June 30, 2003, VaR was approximately $19 million, compared to the December 31, 2002, level of $7 million. At present, Power's load obligation is determined by the results of the annual BGS auction. To maintain an actionable VaR, generation and load (based on an assumed success rate in the auction) are both modeled at 100% of their assumed value through May 2004 and at one-third of the assumed value of each from June 2004 through May 2006.
70

For the Quarter Ended June 30, 2003

Total VaR(Millions)95% Confidence Level, Five-Day Holding Period, Two-Tailed:Period End

$
19Average for the Period

$
23High

$
31Low

$
1799% Confidence Level, One-Day Holding Period, Two-Tailed:Period End

$
11Average for the Period

$
14High

$
18Low

$
10For the Six Months Ended June 30, 2003

Total VaR(Millions)95% Confidence Level, Five-Day Holding Period, Two-Tailed:Period End

$
19Average for the Period

$
22High

$
35Low

$
1099% Confidence Level, One-Day Holding Period, Two-Tailed:Period End

$
11Average for the Period

$
13High

$
20Low

$
6
71
Other Supplemental Information on Mark-to-Market
  Activities
PSEG and 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.
Normal Operations and Hedging Activities
Power enters into physical contracts, as well as derivative contracts, including forwards, futures, swaps and options designed to eliminate risk associated with volatile commodity prices. Commodity price risk is associated with market price movements resulting from market generation demand, changes in fuel costs and various other factors.
Power's energy contracts are accounted for under SFAS 133. Most non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133. Changes in the fair value of qualifying hedge contracts are recorded in OCI, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS 133 and the ineffective portion of hedge contracts are recognized in earnings on a current basis.
Trading
Power's objective for its trading activities is to produce net earnings from trading energy-related products around its owned electric generation assets, gas supply contracts and electric and gas supply obligations. These activities are marked-to-market in accordance with SFAS 133, with gains and losses recognized in earnings.
The following table describes the drivers of Power's energy trading and marketing activities and operating revenues included in its Consolidated Statements of Operations for the six months ended
72
June 30, 2003. Normal operations and hedging activities represent the marketing of electricity available from Power's owned or contracted generation sold into the wholesale market. As the information in this table highlights, mark-to-market activities represent a small portion of the total Operating Revenues for Power. Accrual activities, including normal purchases and sales, account for the majority of the revenue. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices.
Operating Revenues
For the Quarter Ended June 30, 2003
Normal Operations and Hedging (A)

Trading

Total(Millions)Mark-to-Market Activities:Unrealized Mark-to-Market Gains (Losses)Due to Changes in Fair Value of Open Positions

$
12


$
19


$
31Due to Origination Unrealized Gain (Loss) at Inception


—



—



—Due to Changes in Valuation Techniques and Assumptions


—



—



—Due to Realization at Settlement of Contracts


(14
)


(18
)


(32
)Total Change in Unrealized Fair Value


(2
)


1



(1
)Realized Net Settlement of Transactions Subject to Mark-to-Market


14



18



32Broker Fees and Other Related Expenses


—



(2
)


(2
)Net Mark-to-Market Gains


12



17



29Accrual ActivitiesAccrual Activities—Revenue, Including Hedge Reclassifications


    1,207



—



    1,207Total Operating Revenues

$
    1,219


$
17


$
    1,236Operating Revenues
For the Six Months Ended June 30, 2003
Normal Operations and Hedging (A)

Trading

Total(Millions)Mark-to-Market Activities:Unrealized Mark-to-Market Gains (Losses)Due to Changes in Fair Value of Open Positions

$
27


$
45


$
72Due to Origination Unrealized Gain (Loss) at Inception


—



—



—Due to Changes in Valuation Techniques and Assumptions


—



—



—Due to Realization at Settlement of Contracts


(35
)


(40
)


(75
)Total Change in Unrealized Fair Value


(8
)


5



(3
)Realized Net Settlement of Transactions Subject to Mark-to-Market


35



40



75Broker Fees and Other Related Expenses


—



(4
)


(4
)Net Mark-to-Market Gains


27



41



68Accrual ActivitiesAccrual Activities—Revenue, Including Hedge Reclassifications


2,997



—



2,997Total Operating Revenues

$
3,024


$
41


$
3,065
(A)

Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply and all asset backed transactions (ABT) and hedging activities, but excludes owned and contracted generation assets.73

The cumulative net unrealized gains as of June 30, 2003 relating to Power's mark-to-market energy trading contracts were $37 million. The following table presents maturity of net fair value of mark-to-market energy trading contracts.
Maturity of Net Fair Value of Mark-to-Market Energy Trading Contracts
As of June 30, 2003
Maturities within2003

2004

2005

2006-2012

Total(Millions)Trading

$
10


$
10


$
8


$
—


$
29Normal Operations and Hedging


5



4



—



—



8Total Net Unrealized Gains on Mark-to-Market Contracts

$
15


$
14


$
8


$
—


$
37Wherever 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.
The following table identifies cash flow hedges that are currently in Accumulated Other Comprehensive Income, a separate component of equity. The table also provides an estimate of the losses that are expected to be reclassified out of OCI and into earnings over the next twelve months.
Cash Flow Hedges Included in OCI
As of June 30, 2003
Accumulated OCI

Portion Expected
to be Reclassified
in next 12 months(Millions)Cash Flow Hedges Included in OCICommodities

$
(7
)

$
(7
)Interest Rates


(102
)


(25
)Foreign Currency


(4
)


—Total Cash Flow Hedges Included in OCI

$
(113
)

$
    (32
)Credit Risk
Counterparties expose Power to credit losses in the event of non-performance or non-payment. Power has a credit management process which is used to assess, monitor and mitigate counterparty exposure for Power and its subsidiaries. Power's counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Power has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Power's exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty.
The following table provides information on Power's credit exposure, net of collateral, as of June 30, 2003. Credit exposure, in the table below, is defined as net accounts receivable as well as any net ''in-the-money'' forward mark-to-market exposure. 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.
74

Schedule of Credit Risk Exposure on Energy Contracts Net Assets
As of June 30, 2003
Rating

Current Exposure

Securities Held as Collateral

Net Exposure

Number of Counterparties>10%

Net Exposure of
Counterparties>10%(Millions)Investment Grade—External Rating

$
148


$
22


$
126



—



—Non-Investment Grade—External Rating


17



24



1



—



—Investment Grade—No External Rating


2



    —



2



—



—Non-Investment Grade—No External Rating


7



3



6



—



—$
174


$
49


$
135The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more collateral than the outstanding exposure, in which case there would not be exposure.
ITEM 4. CONTROLS AND PROCEDURES
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings have established and maintain disclosure controls and procedures which are designed to provide reasonable assurance that material information relating to each company, including their respective consolidated subsidiaries, is made known to the Chief Executive Officer and Chief Financial Officer of each company by others within those entities. PSEG, PSE&G, Power and Energy Holdings have established a Disclosure Committee, which is made up of several key management employees and reports directly to the Chief Financial Officer and Chief Executive Officer of each company, to monitor and evaluate 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 the end of the reporting period and, based on this evaluation, it was concluded that the disclosure controls and procedures were effective in providing reasonable assurance during the period covered in these quarterly reports. There were no significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of each company's most recent evaluation. It should be noted that the design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote.
75

PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Certain information reported under Item 3 of Part I of the 2002 Annual Report on Form 10-K and under Item 1 of Part II of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 is updated below.
New Matter.(PSE&G) In March 2003, a purported class action lawsuit was filed against PSE&G demanding that it move or protect all gas meters located within 36 inches of a driveway, parking space and/or garage opening and seeking damages. PSE&G filed a motion to dismiss the case or refer it to the BPU. PSE&G cannot predict the outcome of this matter or any potential cost to move or protect such gas meters.
See information on the following proceedings at the pages indicated:

(1)

    Page 28. (PSE&G) PSE&G's
      MGP Remediation Program.(2)

    Page 28. (PSE&G) Investigation and additional
      investigation by the EPA regarding the Passaic River site, Docket No. EX93060255.(3)

    Page 30. (Power) DOE Overcharges, Docket No.
      01-592C.(4)

    Page 30. (Power) DOE not taking possession of
      spent nuclear fuel, Docket No. 01-551C.(5)

    Page 31. (Energy Holdings) AES termination of
      the Stock Purchase Agreement, relating to the sale of certain Argentine
      assets. New York State Supreme Court for New York County (Docket No. 60155/2002)
      PSEG Global, et al vs. The AES Corporation, et al.(6)

    Page 40. (Energy Holdings) Complaint filed by
      Harbinger with the Circuit Court of Shelby, Co., Alabama addressing ownership
      interest in GWF. Harbinger GWF LLC, et al. v. PSEG California Corp., et
      al, Civil Action No. CV-2003-201.(7)

    Pages 43, 47 and 76. (PSE&G) PSE&G's Electric
      Base Rate Case filed with the BPU, OAL No. PUC5744-02; Docket No. ERO2050303.(8)

    Page 77. (Power) Protest filed by Old Dominion
      Electric Cooperative (ODEC) at FERC against Power, Docket No. EL98-6-001.(9)

    Page 80. (Energy Holdings) Criminal charge against
      certain government officials and officers of Luz del Sur (LDS) relating
      to claims made by the Peruvian housing authority (FONAVI), for certain projects.
      First Special Criminal Court of Lima, No. 23-2002.(10)

    Page 80. (Energy Holdings) Peru's Internal Revenue
      Agency's (SUNAT) claim for past-due taxes at LDS, Resolution No. 0150150000030,
      dated July 10, 2003.ITEM 5. OTHER INFORMATION
Certain information reported under the 2002 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2002 Annual Report on Form 10-K. References are to the related pages on the Form 10-K as printed and distributed.
PSE&G
Electric Base Rate Case
2002
  Form 10-K, page 13 and March 31, 2003 Form 10-Q, page 64.On
  July 9, 2003, the BPU issued an oral decision approving the settlement of PSE&G's
  Electric Base Rate Case. On July 31, 2003, the BPU issued a summary written
  order which was substantially consistent with the oral decision. See Item 2.
  Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview
  of Part I.
76

Affiliate Standards
2002 Form 10-K, page 12 and March 31, 2003 Form 10-Q, page 64.On April 4, 2003, the Ratepayer Advocate (RPA) filed a motion formally requesting an extra 60 days to review the competitive services audit reports for gas utilities. A similar motion is expected for the electric utilities competitive services reports. The BPU, in a letter dated April 11, 2003, granted the RPA an extra 30 days for its comment period. The RPA motion(s) also requested the BPU to conduct a discovery process and hearings regarding the competitive services reports. Discovery was received from the RPA and PSE&G filed comments on June 23, 2003 concerning the conclusions raised in the report. In response, the RPA filed comments on June 24, 2003, requesting a ruling by the BPU. PSE&G filed a compliance
plan on July 1, 2003. The BPU is expected to address this matter again at a future meeting.
Deferral Proceeding
2002 Form 10-K, page 14 and March 31, 2003 Form 10-Q, page 65.In August 2002, PSE&G filed a petition proposing changes to two components of its rates, the Societal Benefits Clause (SBC) and the Non-Utility Generation Transition Charge (NTC). The case was transferred to the Office of Administrative Law (OAL) and a hearing was held during the first quarter 2003. On June 6, 2003 a proposed settlement was filed with the Administrative Law Judge (ALJ). On June 10, 2003, the ALJ issued an Initial Decision recommending that the BPU should approve the settlement. On July 9, 2003 the BPU approved the settlement of the Deferral Proceeding resulting in the annual reduction of approximately $238 million through the NTC and SBC.
Investment Tax Credits (ITC)
March 31, 2003 Form 10-Q, page 65.As of June 1999, the Internal Revenue Service (IRS) had issued several private letter rulings that concluded that the refunding of excess deferred tax and ITC balances to utility customers was permitted only over the related assets' regulatory lives, which were terminated upon deregulation. Based on this fact, in 1999, PSEG and PSE&G reversed the excess deferred tax and ITC liabilities relating to its generation assets that were transferred to Power and recorded a $235 million reduction as a component of the extraordinary charge recorded in 1999 due to the deregulation in New Jersey. PSE&G was directed by the BPU to seek a ruling from the IRS to determine if the ITC included in the impairment write-down of generation assets could
be credited to customers without violating the tax normalization rules of the Internal Revenue Code. PSE&G filed for a private letter ruling in 2002, which is still pending.
In January 2003, the IRS proposed for comment regulations that, if adopted, would allow utilities to elect retroactive application to pass these amounts back to customers over periods equivalent to the ones in place prior to deregulation. While PSEG cannot predict the outcome of this matter, a requirement to refund such amounts to customers would have a material impact on PSEG's and PSE&G's financial condition, results of operations and net cash flows.
BGSS Filing
On May 30, 2003, PSE&G filed to increase its Residential BGSS Commodity Charge effective October 1, 2003 to recover approximately $102 million in additional revenues. On June 10, 2003, the case was transferred to the OAL for hearings. On July 16, 2003, PSE&G filed a motion to implement the BGSS increase effective September 1, 2003, instead of October 1, 2003, on a provisional basis. The BPU is expected to rule on the motion in August 2003.
PSE&G and Power
ODEC
2002 Form 10-K, page 159 and March 31, 2003 Form 10-Q, page 23.In 1995, PSE&G entered into a ten-year wholesale power contract with ODEC. The contract was transferred to Power in conjunction with the generation asset transfer in 2000. The contract provides for Power to supply
77

ODEC with capacity and energy for a bundled rate that includes a component to recover multiple transmission charges (referred to as ''pancaked transmission rates'').
In November 1997, the Federal Energy Regulatory Commission (FERC) issued the Pennsylvania-New Jersey-Maryland Power Pool (PJM) Restructuring Order, which required PSE&G to modify its contract with ODEC to remove pancaked transmission rates. While PSE&G sought rehearing of this order, it was nonetheless required to reduce its rate to ODEC by approximately $6 million per year, effective April 1, 1998. On December 19, 2002, based on a court ruling, FERC reversed its November 1997 order, thereby reinstating the original contract terms. This allowed Power to collect amounts for April 1998 through December 2002 pursuant to the original contract. The difference in revenues between the contracted rate and the FERC-ordered reduced rate is approximately $30 million, inclusive of back interest. Power billed ODEC for this
amount in January 2003 and will record this gain when realized. Power has been billing, recording and receiving payment on the higher rate for services provided since January 2003. ODEC is paying these current amounts but has protested both the past due amount, which it has not paid, and current amounts at the higher rates, in a complaint at FERC. On July 1, 2003, Power submitted a letter to FERC requesting that FERC intervene to require ODEC to follow its ruling relating to this contract. ODEC has subsequently submitted a response to the FERC relating to Power's letter. This matter is currently pending.
Other
2002 Form 10-K, page 16.On June 26, 2003, FERC issued a proposal to add six new conditions to all market-based rate tariffs effective currently or in the future. These new conditions would govern unit operation, market manipulation, communications with regulators and other entities, data reporting to publishers of electric or natural gas indices, record retention, and the violation of related tariffs. FERC proposed that it, or affected market participants, could enforce these conditions by seeking disgorgement of profits or revocation of a seller's market-based rate authority. Comments on this proposal are due to FERC by August 8, 2003. The ultimate result of these developments on PSE&G, Power and ER&T is uncertain at this time, as is the date on which FERC will issue
a final order in this matter.
Power
Nuclear Regulatory Commission (NRC)
2002 Form 10-K, page 16.Exelon has informed Power that the application for operating license extension for Peach Bottom 2 and 3 was approved by the NRC on May 7, 2003. The 20-year license extension expires in 2033 for Unit 2 and 2034 for Unit 3.
In August 2002, the NRC issued a bulletin requiring that all operators of pressurized water reactor (PWR) nuclear units submit certain information related to potential degradation of reactor vessel heads. In September 2002, Power provided the requested information for Salem. Bare metal visual inspections for Salem 1 and 2 were completed during 2002 and no degradation of the reactor heads was observed. On February 11, 2003 the NRC issued an order to all operators of PWR units concerning reactor vessel head inspections. The order confirms the previous bulletin's requirements and adds more intrusive and frequent future inspections, which apply to Salem 1 and 2. If repairs are determined to be necessary, it is estimated that the repair would extend the outage by approximately four weeks. Power plans to replace Salem's reactor
heads in 2005 as a preventive maintenance measure, based upon generic industry experience. Power's Hope Creek nuclear unit and the Peach Bottom 2 and 3 are unaffected as they are Boiling Water Reactor nuclear units. Power cannot predict what other actions the NRC may take on this issue.
Permit Renewals
2002 Form 10-K, page 22.In the second quarter of 2003, Power received permits for its Hudson Generating Station, which required modification to the intake structures which Power had proposed in
78

its 316 (b) demonstration, but did not require Power to retrofit the station to operate with closed cycle cooling.
Energy Holdings
Poland
Elektrocieplownia Chorzow Sp. z.o.o. (Elcho)
2002 Form 10-K, page 33.Global owns a 90% stake in Elcho, a company developing combined heat and power plant located in the city of Chorzow, Poland that is expected to be operational by the end of 2003. Elcho also owns an older smaller combined heat and power plant, which will be retired some time after the new plant goes into commercial operation. Elcho has a 20-year power purchase agreement with Polskie Sieci Elektroenergetyczne SA (PSE), the Polish government power grid company. The Polish government has embarked on a process with the intention of terminating all the more than 30 long-term power purchase agreements with PSE. The Polish government has expressed its intention to fully compensate each entity whose contract is terminated with monies raised by the government
by securitizing a charge that will be passed on to the rate payers. Global is in discussions with the Polish government in order to ensure that, if the long-term contract is terminated, it is financially neutral to Elcho. However, no assurances can be given.
Peru
Empresa de Electricidad de los Andes S.A. (Electroandes)
To support the development of the Camisea natural gas field, the Peruvian government-owned company, Electroperu, signed a 15-year take or pay contract with Camisea's developer for the purchase of the gas. Electroperu completed the transfer of this contract to Etevensa, a generating company owned by Spanish group Endesa, who has committed to construct and operate an open-cycle gas-fired plant starting in late 2004. Electroperu will sign a seven-year contract to purchase the plant's output, on a take or pay basis.
These contractual arrangements are likely to exert negative pressure on the spot prices of electricity in Peru, potentially affecting profit margins of Empresa de Electricidad de los Andes S.A. (Electroandes). This potential development was factored into Energy Holdings' initial decision to acquire Electroandes.
In a separate matter, in November 2002, the Peruvian Government created a subsidy in favor of the construction of the Camisea gas pipeline, in the form of a surcharge to the electric transmission tariffs paid by all end users. Two of Electroandes' largest customers (representing about 67% of its contracted capacity) have thus far refused to pay the surcharge, thus preventing Electroandes, in its role as
79

collection agent, from transferring the associated funds to the beneficiaries of the surcharge. This situation has prompted the electric regulator to initiate an investigation aimed at determining the reasons for Electroandes' alleged non-payment. Electroandes firmly believes that its role is limited to collection of the surcharge from its customers and payment to the beneficiaries in a manner proportional to its collections. In the event that a judge or panel of arbitrators determines that Electroandes is liable for payment regardless of current laws, the total impact to Energy Holdings would be approximately $10 million over several years.
LDS
In 1999
  Global acquired an interest in LDS, an electric distribution company based in
  Peru. On May 12, 2003, a criminal charge was filed against certain government
  officials, and utility officials as accomplices, including the Chief Executive
  Officer and Chief Financial Officer of LDS, alleging that certain settlements
  did not provide the government with adequate compensation in a dispute with
  FONAVI. The controversy arises out of a settlement in 2000 relating to amounts
  owed by LDS to FONAVI for electric distribution infrastructure projects. Local
  law required that electricity assets built with FONAVI funds be purchased by
  the local utility and added to rate base. FONAVI financed 194 projects that
  were subsequently transferred to LDS. A dispute arose between FONAVI and LDS
  over the amount of compensation due FONAVI for the projects received by LDS.
  According to FONAVI the total amount owed relating to these projects was approximately
  $36 million. LDS argued that the amount was less and the matter was settled
  with FONAVI for approximately $10 million. Global is currently investigating
  this matter.
March 31, 2003 Form 10-Q, page 66.SUNAT claimed past-due taxes for the period between 1996-1999, plus penalties and interest, resulting from their differing interpretation of the law that allowed LDS to restate its assets to fair market value and take advantage of the resulting higher deductions from depreciation. While LDS prevailed on this issue in arbitration proceedings that ended in December 2001, SUNAT pursued the claim in the local Tax Court. The Tax Court ordered SUNAT to rule according to the arbitration, which was favorable to LDS. The Tax Court did make a reference to Article 8 of the law, which requires consideration of the legitimacy of the business motives leading to a corporate reorganization, such as the one made by LDS and which gave rise to the original
dispute. LDS believes it had legitimate business motives to reorganize when it did and management believed that it acted in accordance with the applicable law and accordingly LDS's position prevailed as SUNAT agreed that Article 8 did not apply.
Further,
  SUNAT stated that the revaluation study, performed in 1996, was not performed
  correctly and invalidates the study as if it never existed. It is LDS's position
  that laws and regulations did not define the methodology to be used in these
  matters and its study was based on generally accepted practices. LDS's total
  potential liability relating to this matter is approximately $55 million, including
  potential penalty and interest. LDS has approximately $18 million recorded as
  a deferred tax liability related to these assets. Global's share of the net
  potential liability related to the claim by SUNAT is estimated at $16 million.
  No assurance can be given to the outcome of this case.
State Regulation—Texas
March 31, 2003 Form 10-Q, page 66.The Public Utility Commission of Texas (PUCT) issued an order in May 2003 directing the Electric Reliability Council of Texas (ERCOT) to develop and adopt, on an expedited basis, the protocol revisions needed to implement the Modified Competitive Solution Method (MCSM) for application to the Balancing Energy Service (BES) market operated by ERCOT to mitigate the affects of potential future price spikes. The MCSM will be used to restrain the market-clearing price of energy when two criteria are met: (1) there is no zonal congestion, so that the MCSM can be applied on an ERCOT-wide basis, and (2) the entire BES market bid stack is deployed by ERCOT. Energy Holdings believes that the new protocols will have minimal financial affect on the TIE
projects.
80

Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA)
2002 Form 10-K, page 132 and March 31, 2003 Form 10-Q, page 67.Energy Holdings completed the process of exiting from the EDEERSA electric distribution company in the Province of Entre Rios, Argentina. In March 2003, PSEG formally and irrevocably renounced, and effectively abandoned, its entire economic and legal interest in EDEERSA. The shares were relinquished, and ownership was assumed by an Argentine trust benefiting current EDEERSA employees, including all of the existing EDEERSA Class C shareholders who received their shares from the Province as part of the initial privatization process. The regulator in the Province has requested that 51% of the EDEERSA shares be transferred from the trust to the Province. The matter is pending in the courts. A representative of the
labor union representing EDEERSA filed a criminal complaint against the transaction alleging that the union should have been allocated more interest in EDEERSA than the trust arrangement currently provides. Energy Holdings believes that it will have no additional exposure to these legal proceedings but no assurances can be given.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) 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
81

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
(B) Reports on Form 8-K:
a. PSEG:Items ReportedItem 5
Item 5
Item 5
Items 5 and 9

Date of ReportApril 15, 2003
June 6, 2003
June 17, 2003
July 22, 2003b. PSE&G:Items ReportedItem 5
Item 5
Item 5

Date of ReportApril 15, 2003
June 6, 2003
July 22, 2003c. Power:Items ReportedItem 5
Item 5
Item 5

Date of ReportApril 15, 2003
June 17, 2003
July 22, 2003d. Energy Holdings:Items ReportedItem 5
Item 5
Item 5

Date of ReportApril 15, 2003
June 17, 2003
July 22, 200382

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/PATRICIAA. RADOPatricia A. Rado
Vice President and Controller
(Principal Accounting Officer)Date: August 1, 2003
83

SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY(Registrant)By:    /s/PATRICIA A. RADO      
      Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)Date: August 1, 2003
84

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: August 1, 2003
85

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 LLC(Registrant)By:   /s/DEREKM. DIRISIODerek M. DiRisio

      Vice President and Controller
      (Principal Accounting Officer)Date: August 1, 2003
86