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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X] Quarterly report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
[ ] Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934

For the Quarter Ended: June 30, 2003
    
    Commission File No. 333-42638


NRG Northeast Generating LLC
(Exact name of Registrant as specified in its charter)

Delaware
    
    41-1937472(State or other jurisdiction
    
    (I.R.S. Employerof incorporation or organization)
    
    Identification No.)901 Marquette Avenue, Suite 2300Minneapolis, Minnesota
    
    55402(Address of principal executive offices)
    
    (Zip Code)


(612) 373-5300
(Registrants telephone number, including area code)

None
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the Registrant (1) has filed all reports 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 Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.

Yes [X]   No [ ]

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

Yes [ ]   No [X]

Indicate by check mark whether the registrant has filed all documents and
reports required to be filed by Section 12, 13 or 15(d) of the Securities and
Exchange Act of 1934 subsequent to the distribution of securities under a plan
confirmed by a court.

Yes [X]   No [ ]



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TABLE OF CONTENTS



|                                                                                              |                                                           |  |  |  |  |  |  | 
|--------------------------------------------------------------------------------------------- | --------------------------------------------------------- |  |  |  |  |  |  | 
|Part I  FINANCIAL INFORMATION                                                               
|Item I  Consolidated Financial Statements and Notes                                         
|                                                                                              | Consolidated Statements of Operations                    
|                                                                                              | Consolidated Balance Sheets                              
|                                                                                              | Consolidated Statements Of Members Equity               
|                                                                                              | Consolidated Statements Of Cash Flows                    
|Item 2. Managements Discussion and Analysis of Financial Condition and Results
of Operations
|Item 3. Quantitative and Qualitative Disclosures About Market Risk                           
|Item 4. Controls and Procedures                                                              
|Part II  OTHER INFORMATION                                                                  
|Item 1. Legal Proceedings                                                                    
|Item 3. Defaults Upon Senior Securities                                                      
|Item 6. Exhibits and Reports on Form 8-K                                                     
|                                                                                              | Cautionary Statement Regarding Forward-Looking Statements
|SIGNATURES                                                                                   
|EX-31 Section 302 Certifications                                                             
|EX-32 Section 906 Certifications                                                             

TABLE OF CONTENTS

INDEX

Page No.Part IItem 1 Consolidated Financial Statements and NotesConsolidated Statements of Operations
    
    
    3Consolidated Balance Sheets
    
    
    4Consolidated Statements of Members Equity
    
    
    5Consolidated Statements of Cash Flows
    
    
    6Notes to Consolidated Financial Statements
    
    
    7-17Item 2 Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    18-26Item 3 Quantitative and Qualitative Disclosures About Market Risk
    
    
    26-27Item 4 Controls and Procedures
    
    
    27Part IIItem 1 Legal Proceedings
    
    
    28Item 3 Defaults on Senior Securities
    
    
    28Item 6 Exhibits, Financial Statement Schedules, and Reports on Form 8-K
    
    
    28Cautionary Statement Regarding Forward Looking Information
    
    
    28-30SIGNATURES
    
    
    31


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Part I  FINANCIAL INFORMATION




Item I  Consolidated Financial Statements and Notes

NRG Northeast Generating LLC and Subsidiaries




Consolidated Statements of Operations


(UNAUDITED)


Three Months Ended
    
    Six Months EndedJune 30,
    
    June 30,(In thousands)
    
    2003
    
    2002
    
    2003
    
    2002Operating
revenuesRevenues
    
    $
    163,172
    
    
    $
    185,080
    
    
    $
    343,386
    
    
    $
    316,648Operating
costs and expensesOperating costs
    
    
    186,143
    
    
    
    110,518
    
    
    
    355,201
    
    
    
    208,553Depreciation
    
    
    20,434
    
    
    
    13,840
    
    
    
    36,770
    
    
    
    26,151General and administrative expenses
    
    
    6,535
    
    
    
    7,669
    
    
    
    17,347
    
    
    
    11,341Restructuring professional fees and expenses
    
    
    566
    
    
    
    
    
    
    
    566
    
    
    
    Asset impairments and restructuring charges
    
    
    222,540
    
    
    
    
    
    
    
    223,247
    
    
    
    Operating (loss) income
    
    
    (273,046
    )
    
    
    53,053
    
    
    
    (289,745
    )
    
    
    70,603Other
income (expense)Other income, net
    
    
    (58
    )
    
    
    4,811
    
    
    
    4
    
    
    
    5,034Restructuring interest income
    
    
    3
    
    
    
    
    
    
    
    3
    
    
    
    Interest expense
    
    
    (13,108
    )
    
    
    (11,111
    )
    
    
    (25,702
    )
    
    
    (26,744
    )Net (loss) income
    
    $
    (286,209
    )
    
    $
    46,753
    
    
    $
    (315,440
    )
    
    $
    48,893


See accompanying notes to consolidated financial statements.

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NRG Northeast Generating LLC and Subsidiaries




Consolidated Balance Sheets


(UNAUDITED)


June 30,
    
    December 31,(In thousands)
    
    2003
    
    2002AssetsCurrent Assets:Cash and cash equivalents
    
    $
    8,982
    
    
    $
    14,354Accounts receivable, net of allowance for doubtful accounts of $0 and $1,344
    
    
    34,137
    
    
    
    118,153Accounts receivable  affiliate
    
    
    503,974
    
    
    
    Inventory
    
    
    118,947
    
    
    
    123,963Derivative instruments valuation
    
    
    5,473
    
    
    
    23,039Prepaid expenses
    
    
    46,457
    
    
    
    38,309Total current assets
    
    
    717,970
    
    
    
    317,818Property, plant and equipment, net of accumulated depreciation of $149,822 and $157,534
    
    
    1,076,448
    
    
    
    1,333,928Deferred finance costs, net of accumulated amortization of $2,285 and $1,161
    
    
    15,408
    
    
    
    8,995Derivative instruments valuation
    
    
    
    
    
    
    9,601Other assets, net of accumulated amortization of $3,764 and $2,605
    
    
    29,591
    
    
    
    23,395Total assets
    
    $
    1,839,417
    
    
    $
    1,693,737Liabilities and Members EquityLiabilities:Current portion of long-term debt
    
    $
    
    
    
    $
    556,500Note payable  affiliate
    
    
    
    
    
    
    30,000Accounts payable
    
    
    223
    
    
    
    14,607Accounts payable-affiliates
    
    
    
    
    
    
    11,476Accrued fuel and purchased power expense
    
    
    1,468
    
    
    
    37,168Accrued interest
    
    
    2,137
    
    
    
    4,198Other accrued liabilities
    
    
    810
    
    
    
    11,713Derivative instruments valuation
    
    
    2,535
    
    
    
    13,017Total current liabilities
    
    
    7,173
    
    
    
    678,679Derivative instruments valuation
    
    
    
    
    
    
    7,559Other long-term obligations
    
    
    337
    
    
    
    27,936Total liabilities not subject to compromise
    
    
    7,510
    
    
    
    714,174Liabilities subject to compromise:Notes payable
    
    
    586,500
    
    
    
    Accounts payable  trade
    
    
    7,473
    
    
    
    Accounts payable  affiliate
    
    
    533,686
    
    
    
    Accrued liabilities
    
    
    50,440
    
    
    
    Other liabilities
    
    
    18,520
    
    
    
    Total liabilities subject to compromise
    
    
    1,196,619
    
    
    
    Commitments and contingenciesMembers equity
    
    
    635,288
    
    
    
    979,563Total liabilities and members equity
    
    $
    1,839,417
    
    
    $
    1,693,737


See accompanying notes to consolidated financial statements.

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NRG Northeast Generating LLC and Subsidiaries




Consolidated Statements of Members Equity


(UNAUDITED)


For the three months ended June 30, 2003 and 2002

AccumulatedMember
    
    
    
    
    
    Other
    
    TotalContributions/
    
    Accumulated
    
    Comprehensive
    
    Members (In thousands)
    
    Distributions
    
    Net Income (Loss)
    
    Income (Loss)
    
    EquityBalances at March 31, 2002
    
    $
    788,315
    
    
    $
    160,668
    
    
    $
    87,871
    
    
    $
    1,036,854Net income
    
    
    
    
    
    
    46,753
    
    
    
    
    
    
    
    46,753Impact of SFAS No. 133 for the
three months ended June 30,
2002
    
    
    
    
    
    
    
    
    
    
    (21,099
    )
    
    
    (21,099
    )Comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    25,654Balances at June 30, 2002
    
    $
    788,315
    
    
    $
    207,421
    
    
    $
    66,772
    
    
    $
    1,062,508Balances at March 31, 2003
    
    $
    788,315
    
    
    $
    133,182
    
    
    $
    12,311
    
    
    $
    933,808Net loss
    
    
    
    
    
    
    (286,209
    )
    
    
    
    
    
    
    (286,209
    )Impact of SFAS No. 133 for the
three months ended June 30,
2003
    
    
    
    
    
    
    
    
    
    
    (12,311
    )
    
    
    (12,311
    )Comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (298,520
    )Balances at June 30, 2003
    
    $
    788,315
    
    
    $
    (153,027
    )
    
    $
    
    
    
    $
    635,288


For the six months ended June 30, 2003 and 2002

AccumulatedMember
    
    
    
    
    
    Other
    
    TotalContributions/
    
    Accumulated
    
    Comprehensive
    
    Members (In thousands)
    
    Distributions
    
    Net Income (Loss)
    
    Income (Loss)
    
    EquityBalances at December 31, 2001
    
    $
    788,315
    
    
    $
    158,528
    
    
    $
    107,741
    
    
    $
    1,054,584Net income
    
    
    
    
    
    
    48,893
    
    
    
    
    
    
    
    48,893Impact of SFAS No. 133 for the
six months ended June 30, 2002
    
    
    
    
    
    
    
    
    
    
    (40,969
    )
    
    
    (40,969
    )Comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    7,924Balances at June 30, 2002
    
    $
    788,315
    
    
    $
    207,421
    
    
    $
    66,772
    
    
    $
    1,062,508Balances at December 31, 2002
    
    $
    788,315
    
    
    $
    162,413
    
    
    $
    28,835
    
    
    $
    979,563Net loss
    
    
    
    
    
    
    (315,440
    )
    
    
    
    
    
    
    (315,440
    )Impact of SFAS No. 133 for the
six months ended June 30, 2003
    
    
    
    
    
    
    
    
    
    
    (28,835
    )
    
    
    (28,835
    )Comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (344,275
    )Balances at June 30, 2003
    
    $
    788,315
    
    
    $
    (153,027
    )
    
    $
    
    
    
    $
    635,288


See accompanying notes to consolidated financial statements.

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NRG Northeast Generating LLC and Subsidiaries




Consolidated Statements of Cash Flows


(UNAUDITED)


Six Months
    
    Six MonthsEnded June 30,
    
    Ended June 30,(In thousands)
    
    2003
    
    2002Cash flows from operating activities:Net (loss)/income
    
    $
    (315,440
    )
    
    $
    48,893Adjustments to reconcile net (loss)/income to net cash
provided (used) by operating activitiesDepreciation
    
    
    38,000
    
    
    
    26,151Unrealized gain on energy contracts
    
    
    (19,709
    )
    
    
    (44,157
    )Amortization of other assets
    
    
    
    
    
    
    434Amortization of deferred financing costs
    
    
    1,124
    
    
    
    208Asset impairment
    
    
    221,521
    
    
    
    Allowance for doubtful accounts
    
    
    1,344
    
    
    
    Gain on disposal of property and equipment
    
    
    (1,230
    )
    
    
    Changes in assets and liabilities:Accounts receivable, net
    
    
    82,672
    
    
    
    (22,575
    )Inventory
    
    
    5,016
    
    
    
    25,894Prepaid expenses
    
    
    (8,148
    )
    
    
    (7,639
    )Accounts payable
    
    
    (6,911
    )
    
    
    (2,278
    )Accounts receivable/payable  affiliates, net
    
    
    18,236
    
    
    
    32,307Accrued interest
    
    
    137
    
    
    
    1,364Accrued fuel and purchased power expense
    
    
    681
    
    
    
    (14,034
    )Other accrued liabilities
    
    
    19,478
    
    
    
    57Other assets and liabilities
    
    
    (33,988
    )
    
    
    (264
    )Net cash provided by operating activities
    
    
    2,783
    
    
    
    44,361Cash flows from investing activities:Capital expenditures
    
    
    (5,494
    )
    
    
    (23,667
    )Proceeds from disposition of property and equipment
    
    
    4,876
    
    
    
    972Net cash used by investing activities
    
    
    (618
    )
    
    
    (22,695
    )Cash flows from financing activities:Deferred financing costs
    
    
    (7,537
    )
    
    
    Proceeds from note payable affiliate
    
    
    
    
    
    
    30,000Bank overdraft
    
    
    
    
    
    
    1,464Principal payments on long-term debt
    
    
    
    
    
    
    (53,500
    )Net cash used by financing activities
    
    
    (7,537
    )
    
    
    (22,036
    )Net decrease  in cash and cash equivalents
    
    
    (5,372
    )
    
    
    (370
    )Cash and cash equivalents at beginning of period
    
    
    14,354
    
    
    
    370Cash and cash equivalents at end of period
    
    $
    8,982
    
    
    $
    


See accompanying notes to consolidated financial statements.

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NRG Northeast Generating LLC and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

NRG Northeast Generating LLC (the Company or NRG Northeast), a
wholly-owned indirect subsidiary of NRG Energy, Inc. (NRG Energy), owns
electric power generation plants in the northeastern region of the United
States. The Company was formed for the purpose of financing, acquiring, owning,
operating and maintaining, through its subsidiaries and affiliates; facilities
owned by Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Connecticut Jet
Power LLC, Devon Power LLC, Dunkirk Power LLC, Huntley Power LLC, Middletown
Power LLC, Montville Power LLC, Norwalk Power LLC, Oswego Power LLC and
Somerset Power LLC.

In
connection with its restructuring efforts, on May 14, 2003 NRG Energy and
26 of its U.S. affiliates (the Debtors) including the Company and its subsidiaries filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in
the United States Bankruptcy Court for the Southern District of New York (the
Bankruptcy Court). It is possible that additional subsidiaries will file petitions for reorganization under Chapter 11.
International operations and certain other subsidiaries were not included in the filing. NRG Energy expects operations to continue as normal during
the restructuring process, while it operates its business as a
debtor-in-possession under the jurisdiction of the Bankruptcy Court and in
accordance with the applicable provisions of the Bankruptcy Code and orders of
the Bankruptcy Court. For more information about NRG Energys restructuring
process, refer to the Form 10-K filed by NRG Energy on March 31, 2003 and Form
10-Q filed by NRG Energy on May 20, 2003.

The accompanying unaudited consolidated financial statements have been
prepared in accordance with the Securities and Exchange Commission (SEC)
regulations for interim financial information and with the instructions to Form
10-Q. Accordingly, they do not include all of the information and footnotes
required by generally accepted accounting principles for complete financial
statements. The accounting policies followed by the Company are set forth in
Item 15  Note 2 to the Companys financial statements in its annual report on
Form 10-K for the year ended December 31, 2002 (Form 10-K). The following notes
should be read in conjunction with such policies and other disclosures in the
Form 10-K. Interim results are not necessarily indicative of results for a full
year.

The Financial Statements have been prepared on a going concern basis in
accordance with GAAP. The going concern basis of presentation assumes that
the Company will continue in operation for the foreseeable future and will be
able to realize its assets and discharge its liabilities in the normal course
of business. Because of the Chapter 11 Cases and the circumstances leading to
the filing thereof, the Companys ability to continue as a going concern is
subject to substantial doubt and is dependent upon, among other things,
confirmation of a plan of reorganization, the Companys ability to comply with
the terms of, and if necessary renew at its expiry in May 2004, the Debtor in
Possession Credit Facility, and the Companys ability to generate sufficient
cash flows from operations, asset sales and financing arrangements to meet its
obligations. There can be no assurances that this can be accomplished and if
it were not, the Companys ability to realize the carrying value of its assets
and discharge its liabilities would be subject to substantial uncertainty.
Therefore, if the going concern basis were not used for the Financial
Statements, then significant adjustments could be necessary to the carrying
value of assets and liabilities, the revenues and expenses reported, and the
balance sheet classifications used.

The Financial Statements also have been prepared in accordance with The
American Institute of Certified Public Accountants Statement of
Position 90-7 (SOP 90-7),
Financial Reporting by Entities in Reorganization under the Bankruptcy Code.
Accordingly, all pre-petition liabilities believed to be subject to compromise
have been segregated in the Consolidated Balance Sheet and classified as
liabilities subject to compromise, at the estimated amount of allowable claims.
Liabilities not believed to be subject to compromise are separately classified
as current and non-current. Interest expense is reported only to the extent
that it will be paid or that it is probable that it will be an allowed claim.

During the Chapter 11 Cases, the Debtors may, subject
to any necessary Bankruptcy Court and lender approvals, sell assets and settle liabilities for amounts other than
those reflected in the financial statements. The administrative and reorganization expenses resulting from
Chapter 11 Cases will unfavorably affect the Debtors results of operations. Future results of operations may also
be adversely affected by other factors related to Chapter 11 Cases.

The Company is in the process of reconciling recorded prepetition liabilities with
claims filed by creditors with the Bankruptcy Court. Differences resulting from that reconciliation process will be recorded
as adjustments to prepetition liabilities. The Company recently began this process and has not yet determined the reorganization
adjustments.

In the opinion of management, the accompanying unaudited interim
consolidated financial statements contain all material adjustments necessary to
present fairly the consolidated financial position of the Company as of June
30, 2003 and December 31, 2002, the results of its operations and members
equity for the three and six months ended June 30, 2003 and 2002, and its cash
flows for the six months ended June 30, 2003 and 2002.

Certain prior year amounts have been reclassified for comparative
purposes. These reclassifications had no effect on net income or total members
equity as previously reported.

1. Restructuring Activities

In December 2001, Moodys Investor Service (Moodys) placed NRG Energys
long-term senior unsecured debt rating on review for possible downgrade. In
response, Xcel Energy and NRG Energy put into effect a plan to preserve NRG
Energys investment grade rating and improve its financial condition. This plan
included financial support to NRG Energy from Xcel Energy; marketing certain
NRG Energy assets for sale; canceling and deferring capital spending; and
reducing corporate expenses.

In response to a possible downgrade during 2002, Xcel Energy contributed
$500 million to NRG Energy, and NRG Energy and its subsidiaries sold assets and
businesses that provided NRG Energy in excess of $286 million in cash and
eliminated approximately $432 million in debt. NRG Energy also cancelled or
deferred construction of approximately 3,900 MW of new generation projects. On
July 26, 2002, Standard & Poors (S&P) downgraded NRG Energys senior unsecured
bonds to below investment grade, and three days later Moodys also downgraded
NRG Energys senior unsecured debt rating to below investment grade. Since July
2002, NRG Energy senior unsecured debt, as well as the secured NRG Northeast
Generating LLC bonds and the secured NRG South Central Generating LLC bonds and
secured LSP Energy (Batesville) bonds were downgraded multiple times. After NRG
Energy failed to make payments due under certain unsecured bond obligations on
September 16, 2002, both Moodys and S&P once again lowered their ratings on
NRG Energys unsecured bonds and its subsidiaries secured bonds. Currently,
NRG Energys unsecured bonds carry a rating of D at S&P and Ca Moodys. NRG
Northeast secured bonds currently carry a rating of D at S&P and Caa1 at
Moodys.

As a result of the downgrade of NRG Energys credit rating, declining
power prices, increasing fuel prices, the overall down-turn in the energy
industry, and the overall down-turn in the economy, NRG Energy has experienced
severe financial difficulties. These difficulties have caused NRG Energy to,
among other things, miss scheduled principal and interest payments due to its
corporate lenders and bondholders, prepay for fuel and other related delivery
and transportation services and provide performance collateral in certain
instances. NRG Energy has also recorded asset impairment charges of
approximately $3.1 billion as of December 31, 2002, related to various
operating projects as well as for projects that were under construction which
NRG Energy has stopped funding.

NRG Energy and certain wholly owned subsidiaries have failed to timely
make several interest and/or principal payments on indebtedness. These missed
payments have resulted in cross-defaults of numerous other non-recourse and
limited recourse debt instruments of NRG Energy and have caused the
acceleration of multiple debt instruments of NRG Energy, rendering such debt
immediately due and payable.

Since March 31, 2003 NRG Energy failed to make a first-quarter payment of
$19.1 million due on March 31, 2003 relating to interest and fees on the $1.0
billion unsecured 364-day revolving credit facility; a $13.6 million interest
payment due on April 1, 2003 on the $350 million of 7.75% senior unsecured
notes maturing 2011; a $21.6 million interest payment due on April 1, 2003 on
the $500 million of 8.625% senior unsecured notes maturing 2031; and a $9.6
million interest payment due on May 1, 2003 on the $240 million of 8.0% senior
unsecured notes maturing 2013. On May 13, 2003, XL Capital Assurance, as
controlling party, accelerated the approximately $319 million

7



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of debt issued by NRG Peaker Finance Company LLC. Accordingly, these
facilities are in default.

NRG Energy failed to make a second quarter payment of $18 million due on
June 30, 2003, relating to interest and fees on the $1.0 billion unsecured,
364-day revolving credit facility; a $11.3 million interest payment due June 1,
2003, on the $300 million of 7.5% senior unsecured notes maturing in 2009; and
a $9.4 million interest payment due on June 15, 2003, on the $250 million of
7.5% senior unsecured notes due in 2007.

Prior to the downgrades, many corporate guarantees and commitments of NRG
Energy and its subsidiaries required that they be supported or replaced with
letters of credit or cash collateral within 5 to 30 days of a ratings downgrade
below Baa3 or BBB- by Moodys or Standard & Poors, respectively. As a result
of the downgrades on July 26, 2002 and July 29, 2002, NRG Energy received
demands to post collateral aggregating approximately $1.2 billion. NRG Energy
is presently working with various secured project lender groups with respect to
working towards establishing a comprehensive plan of restructuring.

In August 2002, NRG Energy retained financial and legal restructuring
advisors to assist its management in the preparation of a comprehensive
financial and operational restructuring. In November 2002, NRG Energy and Xcel
Energy presented a comprehensive plan of restructuring to an ad hoc committee
of its bondholders and a steering committee of its bank lenders (the Ad Hoc
Creditors Committees). The restructuring plan served as a basis for continuing
negotiations between the Ad Hoc Creditors Committees, NRG Energy and Xcel
Energy related to a consensual plan of reorganization for NRG Energy.

On November 22, 2002, five former NRG Energy executives filed an
involuntary Chapter 11 petition against NRG Energy in U.S. Bankruptcy Court for
the District of Minnesota (the Minnesota Bankruptcy Court). On February 19,
2003, NRG Energy announced that it had reached a settlement with the
petitioners. On May 12, 2003, the Minnesota Bankruptcy Court issued an order
abstaining from exercising jurisdiction over any aspect of the case and
dismissed the case.

On March 26, 2003, Xcel Energy announced that its board of directors had
approved a tentative settlement agreement with holders of most of NRG Energys
long-term notes and the steering committee representing NRG Energys bank
lenders. The settlement was subject to certain conditions, including the
approval of at least a majority in dollar amount of the NRG Energy bank lenders
and long-term noteholders and definitive documentation. There can be no
assurance that such approvals will be obtained. The terms of the settlement
called for Xcel Energy to make payments to NRG Energy over the next 10 months
totaling up to $752 million for the benefit of NRG Energys creditors in
consideration for their waiver of any existing and potential claims against
Xcel Energy. Under the settlement, Xcel Energy would make the following
payments: (i) $350 million at or shortly following the consummation of a
restructuring of NRG Energys debt. It is expected this payment would be made
prior to year-end 2003; (ii) $50 million on January 1, 2004. At Xcel Energys
option, it may fill this requirement with either cash or Xcel Energy common
stock or any combination thereof; and (iii) $352 million in April 2004. Since
the announcement on March 26, 2003, representatives of NRG Energy, Xcel Energy,
the bank lenders and noteholders have continued to meet to draft the definitive
documentation necessary to fully implement the terms and conditions of the
tentative settlement agreement.

On May 14, 2003, NRG Energy and certain of its U.S. affiliates (including
the Company and its subsidiaries) filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code in the United States
Bankruptcy Court for the Southern District of New York (the Bankruptcy Court),
In re: NRG ENERGY, INC., et. al., Case No. 03-13204 (PCB). NRG Energy expects
operations to continue as normal during the restructuring process, while it
operates its business as a debtor-in possession under the jurisdiction of the
Bankruptcy Court and in accordance with the applicable provisions of the
Bankruptcy Code and orders of the Bankruptcy Court. In connection with its
Chapter 11 filing, NRG Energy also announced a $250 million
debtor-in-possession (DIP) financing facility from GE Capital Corporation,
subject to Bankruptcy Court approval, to be utilized by the Company and some of
the Companys subsidiaries. NRG Energy anticipates that the DIP, together with
its cash reserves and its ongoing revenue stream, will be sufficient to fund
its operations, including payment of employee wages and benefits, during the
reorganization process.

On May 15, 2003, NRG Energy announced that it had been notified that the
New York Stock Exchange (NYSE) has suspended trading in NRG Energys corporate
units that trade under the ticker symbol NRZ and that an application to the
Securities and Exchange Commission to delist the Units is pending the
completion of applicable procedures, including appeal by NRG Energy of the NYSE
staffs decision. NRG Energy does not plan to make such an appeal. The NYSE
took this action following NRG Energys announcement that it and certain of its
U.S. affiliates had filed voluntary petitions for reorganization under Chapter
11 of the Bankruptcy Code.

In
addition, on May 15, 2003, NRG Energy, NRG Power Marketing,
Inc., NRG Finance Company I, LLC, NRGenerating Holdings (No. 23) B.V.
and NRG Capital LLC (collectively, the Plan Debtors), filed their Disclosure Statement for Reorganizing Debtors Joint
Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy
Code (as subsequently amended, the Disclosure Statement). The Bankruptcy
Court held a hearing on the Disclosure Statement on June 30, 2003, and
instructed the Plan Debtors to include certain additional disclosure.
The Plan Debtors
amended the Disclosure Statement and obtained Bankruptcy Court approval for the
Third Amended Disclosure Statement for Debtors Second Amended Joint Plan of
Reorganization Pursuant to Chapter 11 of the Bankruptcy Code (respectively, the
Amended Disclosure Statement, the Plan).

8



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The Plan must be approved by the SEC prior to its becoming effective. As
subsidiaries of a registered holding company (Xcel Energy) under the Public
Utility Holding Company Act of 1935 (PUHCA), any reorganization plan for NRG
Energy or NRG Energys subsidiaries must be approved by the SEC prior to such
plan becoming effective. Furthermore, each solicitation of any consent in
respect of any reorganization plan must be accompanied or preceded by a copy of
a report on the plan made by the SEC, or an abstract thereof made or approved
by the SEC. The Plan and Amended Disclosure Statement were submitted to the
SEC for review on Monday July 28, 2003. The Plan Debtors will
not be able to solicit acceptances or rejections in connection with
the Plan prior to obtaining the required SEC approval. As a result,
no deadlines or dates have been set regarding voting or confirmation.

On
June 5, 2003, NRG Nelson Turbines LLC and LSP-Nelson Energy LLC
(both wholly owned subsidiaries of NRG Energy) filed
voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code
in the United States Bankruptcy Court for the Southern District of New York.

2. Debtors Statements

As stated above, NRG Energy and certain of its subsidiaries (including
NRG Northeast and its subsidiaries) filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy
Code on May 14, 2003. As of the bankruptcy filing date, the Debtors financial records were closed for the
prepetition period. As required by SOP 90-7 Financial Reporting by Entities in Reorganization under the
Bankruptcy Code, below are the condensed combined financial statements of the Debtors since the date of the bankruptcy
filings (the Debtors Statements). The Debtors Statements have been prepared on the same basis as NRG
Northeasts Consolidated Financial Statements. All entities of NRG Northeast are included in the bankruptcy filing; therefore the condensed
combined balance sheet is not required under SOP 90-7.

DEBTORS CONDENSED COMBINED STATEMENT OF OPERATIONS

|                                             |  |                   |         |  
|-------------------------------------------- |  | ----------------- | ------- | -
|                                             |  | For the Period    |        
|                                             |  | from May 15, 2003 |        
|(In thousands)                               |  | to June 30, 2003  |        
|                                             |  |                   |        
|Operating revenue                            |  | $                 | 127,919 |  
|Operating costs and expenses                 |  |                   | 144,263 |  
|Restructuring professional fees and expenses |  |                   | 566     |  
|                                             |  |                   |        
|Operating income (loss)                      |  |                   | (16,910 | )
|Restructuring interest income                |  |                   | 3       |  
|Other expense, net                           |  |                   | (7,206  | )
|                                             |  |                   |        
|Net loss                                     |  | $                 | (24,113 | )
|                                             |  |                   |        

DEBTORS CONDENSED COMBINED STATEMENT OF CASH FLOWS

|                                                 |  |                   |         |  
|------------------------------------------------ |  | ----------------- | ------- | -
|                                                 |  | For the Period    |        
|                                                 |  | from May 15, 2003 |        
|(In thousands)                                   |  | to June 30, 2003  |        
|                                                 |  |                   |        
|Net cash used by operating activities            |  | $                 | (8,807  | )
|Net cash used by investing activities            |  |                   | (1,311  | )
|Net cash used by financing activities            |  |                   |        |  
|                                                 |  |                   |        
|Net decrease in cash and cash equivalents        |  |                   | (10,118 | )
|Cash and cash equivalents at beginning of period |  |                   | 19,100  |  
|                                                 |  |                   |        
|Cash and cash equivalents at end of period       |  | $                 | 8,982   |  
|                                                 |  |                   |        

3. Debt

As of June 30, 2003, NRG Energy has failed to make scheduled payments on
interest and/or principal on approximately $4.0 billion of its recourse debt
and is in default under the related debt instruments. These missed payments
also have resulted in cross-defaults of numerous other non-recourse and limited
recourse debt instruments of NRG Energy. In addition to the missed debt
payments, a significant amount of NRG Energys debt and other obligations
contain terms, which require that they be supported with letters of credit or
cash collateral following a ratings downgrade. As a result of the downgrades
that NRG Energy experienced in 2002, NRG Energy estimates that it is
in default of its
obligations to post collateral of approximately $1.2 billion, principally to
fund a $842.5 million equity guarantee associated with its construction
revolver financing facility, to fund debt service reserves and other guarantees
related to NRG Energy projects and to fund trading operations.

Absent an agreement on a comprehensive restructuring plan, NRG Energy will
remain in default under its debt and other obligations, because it does not
have sufficient funds to meet such requirements and obligations. There can be
no assurance that NRG Energys creditors ultimately will accept any consensual
restructuring plan under the bankruptcy process. For discussion of NRG Energys
restructuring activities, refer to Note 1 in the Form 10-Q filed by NRG Energy
for the six months ended June 30, 2003 and Form 8-K filed by NRG Energy on
May 16, 2003.

As a result of NRG Energys bankruptcy filing, NRG Energy has classified
its corporate level debt as a prepetition obligation subject to compromise and
has ceased recording accrued interest as it is not probable of being paid.
The contractual interest requirements for such corporate debt is $40.0 million
for the period May 14, 2003 (date of the bankruptcy petition) to June 30, 2003.

As a result of NRG Energys bankruptcy filing, the Company has classified
its debt as a prepetition obligation subject to compromise. Accrued interest
continues to be recorded as the debt is fully secured.

Debtor-in-Possession Loan

NRG Energy and certain of its subsidiaries have negotiated a Senior
Secured, Super-Priority Debtor-in-Possession Credit Agreement ( the DIP
Agreement) with General Electric Capital Corporation (GECC), which was executed
following the filing of the petition in NRG Energys Chapter 11 bankruptcy
case. Under the DIP Agreement, GECC will make up to $250 million (the DIP
Facility) available for working capital and general corporate needs of the
Debtors that comprise NRGs Northeast generating facilities (the DIP
Borrowers). The DIP Facility will be secured by a first priority lien on
substantially all of the assets of and equity interest in the DIP Borrowers,
plus the assets of Power Marketing, Inc. that relate to the revenues of the DIP
Borrowers.

The DIP Facility bears an interest rate of 2.00% over the prime rate or
3.50% over the LIBOR rate and is currently set to expire on
May 13, 2004. NRG does not currently anticipate the DIP Facility
to be outstanding for one year. However, should the DIP Facility
extend for more than one year, approval of such financing by the New
York Public Service Commission will be required as certain NRG Energy
assets securing the loan are located in New York. Should such
approval be necessary, NRG Energy intends to make a timely application
for the approval.

The amount available under the DIP Facility may vary from time to time,
depending on valuations of the collateral securing the DIP Facility and GECCs
right to set aside certain reserves. The DIP Facility permits the DIP
Borrowers to borrow up to $210 million upon entry of a final order approving
the DIP Facility. The total availability may increase to $250 million upon the
occurrence of certain subsequent events. A final order
approving the DIP Facility was entered by the Bankruptcy Court on July 24,
2003. Such order provides, among other things, that the borrowers may not use
DIP funds or cash collateral to make disbursements to, or for the benefit of
the Connecticut Light and Power Company, unless further agreed to by GECC, the
DIP lender, the Official Committee of Unsecured Creditors of NRG Energy, Inc.
et al. and the informal committee of holders of the three series of Senior
Secured Bonds issued by NRG Northeast Generating LLC, or further order of the
Bankruptcy Court.

9



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As of June 30, 2003, NRG Energy had not drawn down any funds from the DIP
Facility.

4. Inventory

Inventory consists of spare parts, coal, fuel oil and kerosene and is
stated at the lower of weighted average cost or market value:

(In thousands)
    
    June 30, 2003
    
    December 31, 2002Fuel oil
    
    $
    37,548
    
    
    $
    47,052Spare parts
    
    
    58,285
    
    
    
    59,524Coal
    
    
    19,661
    
    
    
    14,378Kerosene
    
    
    3,181
    
    
    
    2,852Other
    
    
    272
    
    
    
    157Total
    
    $
    118,947
    
    
    $
    123,963


5. Property, Plant and Equipment

Property, plant and equipment are stated at cost or recoverable value. Depreciation is computed
on a straight-line basis over the following estimated useful lives:

Facilities, machinery and equipment
    
    7 to 30 yearsOffice furnishings and equipment
    
    3 to 10 years


Property, plant and equipment consisted of:

(In thousands)
    
    June 30, 2003
    
    December 31, 2002Facilities, machinery and equipment
    
    $
    1,151,966
    
    
    $
    1,415,726Land
    
    
    44,417
    
    
    
    46,925Construction in progress
    
    
    28,882
    
    
    
    27,615Office furnishings and equipment
    
    
    1,005
    
    
    
    1,196Accumulated depreciation
    
    
    (149,822
    )
    
    
    (157,534
    )Property, plant and equipment, net
    
    $
    1,076,448
    
    
    $
    1,333,928


In light of economic developments related to the Connecticut assets and
NRG Energys application for cost of service reimbursements, The Company
reassessed the asset lives for the Connecticut facilities. The shorter
depreciable lives resulted in an increase in depreciation of approximately $6.3
million and $13.2 million for the three and six months ended June 30, 2003. In
accordance with SFAS No. 144, the Company has reclassified the accumulated
depreciation recorded on those facilities that were impaired during the six
months ended June 30, 2003.

6. Accounting for Long-Term Contracts

On June 18, 2003, the Company terminated an indemnity agreement between
itself and NRG Power Marketing, Inc. (NRG PMI) a wholly owned subsidiary of NRG
Energy and an affiliate of the Company, effective to May 14, 2003. Upon the effective
termination of this agreement, certain outstanding trade receivables were
transferred from the Company to NRG PMI. This transfer resulted in a balance
sheet reclass of approximately $67.4 million on the Companys financials from
accounts receivable  trade to accounts receivable  affiliate. These
receivables relate to three long-term contracts that were directly affected by
the termination of this indemnity agreement termination. As a result,
the
Company will no longer recognize any revenues or expenses related to these
contracts. The affected contracts were the Standard Offer Service contract with
CL&P, a long- term contract with Ashland and a long- term contract with EUA.
Effective May 14, 2003, NRG PMI will bear the benefits and burdens of these
contracts. During the six months ended June 30, 2003, the
provisions of the standard offer contracts resulted in an actual operating loss for the Companys
Connecticut facilities of approximately $118.7 million.

In
addition, effective with the indemnity agreement termination, the
Company has reclassified certain other accounts receivable  trade balances to
accounts receivable  affiliate to recognize the related party
relationship  between NRG PMI and the Company and its subsidiaries.
As of June 30, 2003, approximately $1.7 million of accounts receivable  trade
was reclassified to accounts receivable  affiliate. The ongoing expense and
revenue recognition related to these transactions will remain consistent with
the Companys past policies and procedures. Included in
operating revenue is approximately $57.3 million of related
party revenue for the three and six month periods ending
June 30, 2003.

7. Derivative Instruments and Hedging Activity

On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities
(SFAS No. 133), as amended by SFAS No. 137 and SFAS No. 138. SFAS No. 133
requires the

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Company to record all derivatives on the balance sheet at fair value.
Changes in the fair value of non-hedge derivatives are immediately recognized
in earnings. Derivatives that have been designated as hedges of assets,
liabilities or firm commitments, are accounted for using the fair value method.
Changes in the fair value of these instruments are recognized in earnings as
offsets to the changes in the fair value of the related hedged assets,
liabilities and firm commitments. Derivatives that have been designated as
hedges of forecasted transactions are accounted for using the cash flow method.
Changes in the fair value of these instruments are deferred and recorded as a
component of accumulated other comprehensive income (OCI) until the hedged
transactions occur and are recognized in earnings. Reclassifications of the
deferred gains and losses are included on the same line of the statement of
operations in which the hedged item is recorded. The ineffective portion of the
change in fair value of a derivative instrument designated as a cash flow hedge
is immediately recognized in earnings. The Company formally assesses both at
inception and at least quarterly thereafter, whether the derivatives used in
hedging transactions are highly effective in offsetting the changes in either
the fair value or cash flows of the hedged item. This assessment includes all
components of each derivatives gain or loss unless otherwise noted. When it is
determined that a derivative ceases to be a highly effective hedge, hedge
accounting is discontinued.

SFAS No. 133 applies to the Companys long-term power sales contracts,
long-term gas purchase contracts and other energy related commodities financial
instruments used to mitigate variability in earnings due to fluctuations in
spot market prices, hedge fuel requirements at generation facilities and
protect investments in fuel inventories. At June 30, 2003, the Company had
derivative contracts extending through June 2004.

Accumulated Other Comprehensive Income

The following table summarizes the effects of SFAS No. 133 on the
Companys OCI balance:

Three Months Ended
    
    Six Months EndedGains/(Losses)
    
    June 30,
    
    June 30,(In thousands)
    
    2003
    
    2002
    
    2003
    
    2002Beginning Balance
    
    $
    12,311
    
    
    $
    87,871
    
    
    $
    28,835
    
    
    $
    107,741Unwound from OCI during period:- due to unwinding of previously deferred amounts
    
    
    (12,311
    )
    
    
    (79
    )
    
    
    (28,835
    )
    
    
    (3,925
    )Mark to market hedge contracts
    
    
    
    
    
    
    (21,020
    )
    
    
    
    
    
    
    (37,044
    )Ending Balance
    
    $
    
    
    
    $
    66,772
    
    
    $
    
    
    
    $
    66,772Gains/(Losses) expected to unwind
from OCI during next 12 months
    
    $
    
    
    
    $
    30,041
    
    
    $
    
    
    
    $
    30,041


Gains of $12.3 million and $28.8 million were reclassified from OCI to
current period earnings during the three and six months ended June 30, 2003 due
to the unwinding of previously deferred amounts. In comparison for the three
and six months ended June 30, 2002 gains of approximately $0 and $3.9 million
were reclassified. These amounts are recorded on the same line item in the
statement of operations in which the hedged items are recorded. During the
three and six months ended June 30, 2003, the Company recorded no amounts and
gains for the three and six months ended June 30, 2002 of $21.0 million and
$37.0 million respectively in OCI, related to changes in the fair values of
derivatives accounted for as hedges. The net balance in OCI relating to SFAS
No. 133 as of June 30, 2003 was $0. The Company expects no deferred net gains
on derivative instruments accumulated in OCI to be recognized as earnings
during the next twelve months.

Statement of Operations

The following table summarizes the effects of SFAS No. 133 on the
Companys statement of operations:

Three Months Ended
    
    Six Months EndedGains/(Losses)
    
    June 30,
    
    June 30,(In thousands)
    
    2003
    
    2002
    
    2003
    
    2002Revenues
    
    $
    23,391
    
    
    $
    30,643
    
    
    $
    21,152
    
    
    $
    34,573Operating costs
    
    
    363
    
    
    
    3,530
    
    
    
    (1,443
    )
    
    
    9,584Total statement of operations impact
    
    $
    23,754
    
    
    $
    34,173
    
    
    $
    19,709
    
    
    $
    44,157


During the three and six months ended June 30, 2003 and 2002, the Company
recognized no gain or loss due to ineffectiveness of

11



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commodity cash flow hedges.

The Companys earnings for the three months ended June 30, 2003 and 2002
were increased by an unrealized gain of $23.8 million and a $34.2 million,
respectively. For the six months ended June 30, 2003 and 2002 the companys
earnings increased by an unrealized gain of $19.7 million and $44.2 million,
respectively, associated with changes in the fair value of energy related
derivative instruments not accounted for as hedges in accordance with SFAS No.
133.

8. Regulatory Issues

NRG Energy is impacted by market rule and tariff changes in the existing
Independent System Operators (ISOs) and Regional Transmission Organizations
(RTOs), On March 1, 2003, ISO-New England implemented its version of Standard
Market Design. This change dramatically modifies the New England market
structure by incorporating Locational Marginal Pricing (pricing by location
rather than on a New England wide basis). On February 26, 2003, NRG Energy
filed a proposed cost of service agreement with the Federal Energy Regulatory Commission (FERC) for the following
Connecticut facilities: Middletown Power LLC, Montville Power LLC, Norwalk
Power LLC and Devon Power LLC units 11-14 (collectively the NRG Subsidiaries).
In the filing, NRG Energy requested that major and minor maintenance expenses
of the NRG Subsidiaries be paid for through a tracking mechanism that would
insure that NRG Energy receives compensation only for actual maintenance
expenses. Under the proposed cost of service agreement, the other NRG Energy
costs would be paid through a monthly cost-based payment. NRG Energy requested
an effective date of February 27, 2003. The cost of service filing was made
notwithstanding the impending implementation of Standard Market Design in New
England, including the adoption of Locational Marginal Pricing. While the
Standard Market Design represents a significant improvement to the existing
market design, NRG Energy still considered the market insufficient to allow NRG
Energy to recover its reasonable costs and earn a reasonable return on
investment.

On March 25, 2003, FERC issued an order (the March Order) approving the
NRG Subsidiaries spring 2003 maintenance expenses, subject to refund and
authorized an effective date of February 27, 2003. In the March Order, FERC
also permitted ISO New England, viaan escrow account, to start collecting the
amount of the maintenance expenses in order to ensure the availability of the
NRG Energy units for the summer 2003 peak season. To the extent that the Company incurs maintenance related expenses and submitted
such expenses to the ISO for reimbursement, the Company will recognize the expense in the period incurred. Upon reimbursement
from the ISO for maintenance related expenses, the Company will recognize revenue. FERC did not rule on the
remainder of the issues to allow further time to consider protests.

On April 25, 2003, the FERC issued an order (the April Order) rejecting
the remaining part of the proposed cost of service agreements including the
monthly cost-based payment. Rather, FERC instructed ISO New England to
establish temporary bidding rules that would permit selected peaking units
(units with capacity factors of 10 percent or less during 2002), operating
within designated congestion areas (such as Connecticut) to raise their bids
to allow them the opportunity to recover their fixed and variable costs through
the market. This temporary bidding rule would remain in place until ISO New
England implements locational installed capacity requirements, which should
be no later than June 1, 2004. In the July 24 Order on Rehearing (the July
Order), FERC clarified that the capacity factor of 10 percent or less applies
to units rather than complexes. On a unit basis, all the NRG Energy
facilities qualify to bid under the temporary rules except Middletown 2 and 3.
For additional information regarding the impact that the FERCs Order had on
NRG Energys financial position and results of operations, see Note 10.

9. Commitments and Contingencies

Litigation

The New York Voluntary Bankruptcy Case

On May 14, 2003 NRG Energy and certain of its U.S. affiliates (including
the Company and its subsidiaries) filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in
the United States Bankruptcy Court for the Southern District of New York (the
Bankruptcy Court), In re: NRG ENERGY, INC., et. al., Case No. 03-13024 (PCB).
NRG Energy expects operations to continue as normal during the restructuring
process, while it operates its business as a debtor-in-possession under the
jurisdiction of the Bankruptcy Court and in accordance with the applicable
provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Fortistar Capital Inc. v. NRG Energy, Inc., Hennepin County District Court

On July 12, 1999, Fortistar Capital Inc. sued NRG Energy in Minnesota
state court. The complaint sought injunctive relief and damages of over $50
million resulting from NRG Energys alleged breach of a letter agreement with
Fortistar relating to the Oswego Steam Station. NRG Energy asserted
counterclaims. After considerable litigation, the parties entered into a
conditional, confidential settlement agreement, which was subject to necessary
board and lender approvals. NRG Energy was unable to obtain necessary
approvals. Fortistar has moved the court to enforce the settlement, seeking
damages in excess of $35 million plus interest and attorneys fees. NRG Energy
is opposing Fortistars motion on the grounds that conditions to contract
performance have not been satisfied. No decision has been made on the pending
motion, and NRG Energy cannot predict the outcome of this dispute.

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Connecticut Light & Power Company v. NRG Power Marketing Inc., Docket No.
3:01-CV-2373 (A WT), pending in the United States District Court, District of
Connecticut

This matter involves a claim by The Connecticut Light & Power Company (CL&P)
for recovery of amounts it claims are owing for congestion charges under the
terms of a Standard Offer Services contract between the parties, dated October
29, 1999. CL&P has served and filed its motion for summary judgment to which
NRG Power Marketing Inc. (NRG PMI) filed a response on March 21, 2003. CL&P has
offset approximately $30 million from amounts owed to NRG PMI, claiming that it
has the right to offset those amounts under the contract. NRG PMI has
counterclaimed seeking to recover those amounts, arguing among other things
that CL&P has no rights under the contract to offset them. On May 14, 2003, NRG
PMI provided notice to CL&P of termination of the contract effective May 19,
2003. Pursuant to the request of the Attorney General of Connecticut and the
Connecticut Department of Public Utility Control (DPUC), on May 16, 2003, the
FERC issued an Order directing NRG PMI to continue to provide service to CL&P
under the contract, pending further order by FERC. On May 19, 2003, NRG PMI
withdrew its notice of termination of the contract. On June 25, 2003, FERC
issued an Order directing NRG PMI to continue to provide service to CL&P under
the contract, pending further notice by FERC. NRG PMI cannot estimate at this
time the likelihood of an unfavorable outcome in this matter, or the overall
exposure for congestion charges for the full term of the contract. Although the
outcome of this litigation may have an affect on NRG Northeast, NRG Northeast
is not a party to this litigation.

Connecticut Light & Power  Related Proceedings at the Federal Energy
Regulatory Commission, the United States District Court for the Southern
District of New York, and the United States Court of Appeals for the D.C.
Circuit and the Second Circuit.

In May, 2003, when NRG PMI took steps to terminate or reject in bankruptcy
the subject Standard Offer Services contract with CL&P (CL&P Contract), the
Connecticut Attorney General and the (DPUC) sought and obtained from FERC its
above-referenced May 16, 2003 Order temporarily requiring NRG PMI to continue
to comply with the terms of the CL&P Contract, pending further notice from
FERC. Thereafter, On June 2, 2003, the United States Bankruptcy Court for the
Southern District of New York issued its Order specifically authorizing NRG
PMIs rejection of the CL&P Contract, and by Order dated June 12, 2003, the
United States District Court for the Southern District of New York granted NRG
PMIs motion for a temporary restraining order staying all actions by CL&P, the
Connecticut Attorney General and the DPUC to enforce or apply the
above-referenced FERC Order and affording NRG PMI leave to cease its
performance under the CL&P Contract, effective retroactive to June 2, 2003.
FERC then issued an order on June 25, 2003, that again commanded NRG PMIs
continued performance regardless of any contrary ruling by the Bankruptcy Court
and the District Courts temporary restraining order. By order dated June 30,
2003, the District Court dismissed NRG PMIs motion for preliminary injunction
for lack of subject matter jurisdiction. On July 1, 2003, PMI resumed
performance under the CL&P Contract. On July 3, 2003, NRG PMI requested of
FERC a stay of the June 25 order which request was denied. On July 8, 2003,
PMI requested an emergency stay of FERCs June 25 order pending petition for
review from the United States Court of Appeals for the District of Columbia
Circuit. On July 16, 2003, the D.C. Circuit denied NRG PMIs request for a
stay of the June 25 order. On July 17, 2003, NRG PMI appealed to the Second
Circuit respecting the District Courts refusal to enjoin FERC and maintain the
restraining order. On July 18, 2003, NRG PMI requested emergency injunctive
relief with respect to performance under the CL&P Contract and an expedited
briefing schedule on the appeal. NRG Energy awaits the Second Circuits
decision on the above appeal as well as a permanent order by FERC with respect
to NRG PMIs continued performance under the CL&P Contract. Should NRG PMI
have to perform for the duration of the CL&P Contract, this could have an
adverse financial consequence approaching $100 million.

The State of New York and Erin M. Crotty, as Commissioner of the New York State
Department of Environmental Conservation v. Niagara Mohawk Power Corporation et
al.,United States District Court for the Western District of New York, Civil
Action No. 02-CV-002S

In January, 2002, NRG Energy and Niagara Mohawk Power Corporation (NiMo)
were sued by the New York Department of Environmental Conservation in federal
court in New York. The complaint asserted that projects undertaken at NRG
Energys Huntley and Dunkirk plants by NiMo, the former owner of the
facilities, required preconstruction permits pursuant to the Clean Air Act and
that the failure to obtain these permits violated federal and state laws. In
July, 2002, NRG Energy filed a motion to dismiss. On March 27, 2003 the court
dismissed the complaint against NRG Energy with prejudice as to the federal
claims and without prejudice as to the state claims. It is possible the state
will appeal this dismissal to the Second Circuit Court of Appeals. In the
meantime, on April 25, 2003, the state provided to NRG Energy notice of intent
to again sue the Company and various affiliates by filing a second amended
complaint in this same action in the federal court in New York, asserting
against the NRG Defendants violations of operating permits and deficient
operating permits at the Huntley and Dunkirk plants. If the case ultimately is
litigated to a judgment and there is an unfavorable outcome that could not be
addressed through use of compliant fuels and/or a plantwide applicability
limit, NRG Energy has estimated that the total investment that would be
required to install pollution control devices could be as high as $300 million
over a ten to twelve-year period, and NRG Energy may be responsible for payment
of certain penalties and fines.

Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power, LLC, and
Dunkirk Power, LLC,Supreme Court, State of New York, County of Onondaga, Case
No. 2001-4372

NRG Energy has asserted that NiMo is obligated to indemnify it for any
related compliance costs associated with resolution of the

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enforcement action. NiMo has filed suit in state court in New York seeking
a declaratory judgment with respect to its obligations to indemnify NRG Energy
under the asset sales agreement. NRG Energy has pending a summary judgment
motion on its entitlement to be reimbursed by NiMo for the attorneys fees NRG
Energy has incurred in the enforcement action, and that motion should be heard
within the next 60 days.

Huntley Power LLC, Dunkirk Power LLC and Oswego Power LLC

All three of these facilities have been issued Notices of Violation with
respect to opacity exceedances. NRG Energy has been engaged in consent order
negotiations with the New York State Department of Environmental Conservation
(DEC) relative to opacity issues affecting all three facilities periodically
since 1999. One proposed consent order was forwarded by DEC under cover of a
letter dated January 22, 2002, which makes reference to 7,890 violations at the
three facilities and contains a proposed payable penalty for such violations of
$900,000. On February 5, 2003, DEC sent to NRG Energy a proposed Schedule of
Compliance and asserted that it is to be used in conjunction with newly-drafted
consent orders. NRG Energy has not yet received the consent orders although NRG
Energy has been told by DEC that DEC is now seeking a penalty in excess of that
cited in its January 22, 2002 letter. NRG Energy expects to continue
negotiations with DEC regarding the proposed consent orders, including the
Schedule of Compliance and the penalty amount. NRG Energy cannot predict
whether those discussions with the DEC will result in a settlement and, if they
do, what sanctions will be imposed. In the event that the consent order
negotiations are unsuccessful, NRG Energy does not know what relief DEC will
seek through an enforcement action and what the result of such action will be.

Huntley Power LLC

On April 30, 2003, the Huntley Station submitted a self-disclosure letter
to the (DEC) reporting violations of applicable sulfur in fuel limits which had
occurred during 6 days in March, 2003 at the chimney stack serving Huntley
Units 63-66. The Huntley Station self-disclosed that the average sulfur
emissions rates for those days had been 1.8 lbs/mm BTU, rather than the maximum
allowance of 1.7 lbs/mm BTU. NRG Huntley Operations discontinued use of Unit
65 (the only unit utilizing the subject stack at the time) and has kept the
remaining 3 units off line until adherence with the applicable standard is
assured. On May 19, 2003, the DEC issued Huntley Power LLC a Notice of
Violation. NRG Energy has met with the DEC to discuss the circumstances
surrounding the event and the appropriate means of resolving the matter. NRG
Energy does not know what relief the DEC will seek through an enforcement
action. Under applicable provisions of the Environmental Conservation Law, the
DEC asserts that it may impose a civil penalty up to $10,000, plus an
additional penalty not to exceed $10,000 for each day that a violation
continues and may enjoin continuing violations.

Niagara Mohawk Power Corporation v. Dunkirk Power LLC, et al., Supreme Court,
Erie County, Index No. 1-2000-8681

On October 2, 2000, plaintiff Niagara Mohawk Power Corporation commenced
this action against NRG Energy to recover damages plus late fees, less payments
received through the date of judgment, as well as any additional amounts due
and owing, for electric service provided to the Dunkirk Plant after September
18, 2000. Plaintiff NiMo claims that NRG Energy has failed to pay retail tariff
amounts for utility services commencing on or about June 11, 1999 and
continuing to September 18, 2000 and thereafter. Plaintiff has alleged breach
of contract, suit on account, violation of statutory duty, and unjust
enrichment claims. On or about October 23, 2000, NRG Energy served an answer
denying liability and asserting affirmative defenses.

After proceeding through discovery, and prior to trial, the parties and
the court entered into a stipulation and order filed August 9, 2002
consolidating this action with two other actions against The Companys Huntley
and Oswego subsidiaries, both of which cases assert the same claims and legal
theories for failure to pay retail tariffs for utility services.

On October 8, 2002, a Stipulation and Order was filed in the Erie County
Clerks Office staying this action pending submission of some or all of the
disputes in the action to the FERC. NRG Energy cannot make an evaluation of the
likelihood of an unfavorable outcome. The cumulative potential loss could
exceed $35 million.

Niagara Mohawk Power Corporation v. Huntley Power LLC, NRG Huntley Operations,
Inc., NRG Dunkirk Operations, Inc., Dunkirk Power LLC, Oswego Harbor Power LLC,
and NRG Oswego Operations, Inc., Case Filed November 26, 2002 in Federal Energy
Regulatory Commission Docket No. EL 03-27-000.

This is the companion action filed by NiMo at FERC, similarly asserting
that NiMo is entitled to receive retail tariff amounts for electric service
provided to the Huntley, Dunkirk and Oswego plants. The parties are currently
engaged in settlement negotiations in an attempt to resolve both this FERC
action and the above-referenced state court proceedings respecting amounts
owing for electrical service provided to these three plants. At this stage of
the proceedings, NRG Energy cannot estimate the likelihood of an adverse
determination. As noted above, the cumulative potential loss could exceed $35
million.

NRG Energy Credit Defaults

NRG Energy and various of its subsidiaries are in default under various of
their credit facilities, financial instruments, construction

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agreements and other contracts, which have given rise to liens, claims and
contingencies against them and may in the future give rise to additional liens,
claims and contingencies against them. In addition, NRG Energy and various of
its subsidiaries have entered into various guarantees, equity contribution
agreements, and other financial support agreements with respect to the
obligations of their affiliates, which have given rise to liens, claims and
contingencies against them and may in the future give rise to additional liens,
claims and contingencies against the party or parties providing the financial
support. NRG Energy cannot at this time predict the outcome or financial impact
of these matters.

Guarantees

The Company is directly liable for the obligations of certain of its
subsidiaries pursuant to guarantees relating to certain of their operating
obligations. In addition, in connection with the purchase and sale of fuel,
emission credits and power generation products to and from third parties with
respect to the operation of some of the Companys generation facilities in the
United States, the Company may be required to guarantee a portion of the
obligations of certain of its subsidiaries. As of June 30, 2003, the Companys
obligations pursuant to its guarantees of the performance of its subsidiaries
totaled approximately $42.3 million.

10. Asset Impairments and Restructuring Charges

As a result of the changing operational, regulatory and financial
conditions impacting the Company on an ongoing basis, the Company reviews the
recoverability of its long-lived assets in accordance with the guidelines of
SFAS No. 144. As a result of this review, the Company recorded asset impairment
charges of $221.5 million for the three and six months ended June 30, 2003, as
shown in the table below.

To determine whether an asset was impaired, NRG Northeast compared asset
carrying values to total future estimated undiscounted cash flows. Separate
analyses were completed for assets or groups of assets at the lowest level for
which identifiable cash flows were largely independent of the cash flows of
other assets and liabilities. The estimates of future cash flows included only
future cash flows, net of associated cash outflows, directly associated with
and expected to arise as a result of the Companys assumed use and eventual
disposition of the asset. Cash flow estimates associated with assets in service
were based on the assets existing service potential. The cash flow estimates
may include probability weightings to consider possible alternative courses of
action and outcomes, given the uncertainty of available information and
prospective market conditions.

If an asset was determined to be impaired based on the cash flow testing
performed, an impairment loss was recorded to write down the asset to its fair
value. Estimates of fair value were based on prices for similar assets and
present value techniques. Fair values determined by similar asset prices
reflect the Companys current estimate of recoverability from expected
marketing of project assets. For fair values determined by projected cash
flows, the fair value represents a discounted cash flow amount over the
remaining life of each project that reflects project-specific assumptions for
long-term power pool prices, escalated future project operating costs, and
expected plant operation given assumed market conditions.

Asset impairments and restructuring charges from continuing operations included in operating expenses
in the Consolidated Statements of Operations include the following:

(In thousands)
    
    Three Months
    
    Three Months
    
    Six Months
    
    Six MonthsEnded June 30, 2003
    
    Ended June 30, 2002
    
    Ended June 30, 2003
    
    Ended June 30, 2002Asset impairments
    
    $
    221,521
    
    
    $
    
    
    
    $
    221,521
    
    
    $
    Severance and other charges
    
    
    1,019
    
    
    
    
    
    
    
    1,726
    
    
    
    Total special charges
    
    $
    222,540
    
    
    $
    
    
    
    $
    223,247
    
    
    $
    


Asset impairments for the three and
six months ended June 30, 2003:

Pre-taxProject Name
    
    Project Status
    
    Charge
    
    Fair Value Basis(In thousands)Devon Power LLC
    
    Operating at a loss
    
    $
    64,198
    
    
    Projected cash flowsMiddletown Power LLC
    
    Operating at a loss
    
    
    157,323
    
    
    Projected cash flowsTotal Asset Impairment
Charges
    
    
    
    $
    221,521


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Connecticut
Facilities NRG Energy reviewed cash flow models for its
Connecticut generating facilities at December 31, 2002. No impairment
was required based on the pricing and cost recovery assumptions at
December 31, 2002. On February 26, 2003 NRG Energy filed a proposed
cost of service agreement for the following Connecticut facilities
with the Federal Energy Regulatory Commission (FERC) Devon 11-14,
Middletown station, Montville station, Norwalk Harbor station. On
April 25, 2003, the FERC issued an order that rejected NRG
Energys proposed fixed monthly charges, citing certain policy
determinations regarding cost-of-service agreements. FERC instead
directed NRG Energy to recover its fixed and variable costs under
interim bidding rules for generators located in constrained areas,
the so-called Peaking Unit Safe Harbor (PUSH) mechanism. The PUSH
bidding rules would apply to all of NRG Energys Connecticut
facilities that filed the proposed cost of service agreements, with
the exception of Middletown Units 2 and 3, until June 1, 2004. The
following quick start facilities, located in Connecticut also have
the option of submitting PUSH bids: Cos Cob, Franklin Drive and
Torrington. FERC also ordered that the regional power agencies
overseeing the energy markets in Connecticut, the Independent System
Operator for New England (ISO-NE) and the New England Power Pool
(NEPOOL), modify the New England market rules to establish and
implement locational capacity or deliverability requirements no later
than June 1, 2004. In late May and June 2003, ISO-NE revised its
market pricing rules to facilitate FERCs mandated PUSH
mechanism, but has not yet proposed the market modifications required
to implement locational capacity or deliverability requirements. In
June 2003 NRG Energy filed for rehearing of several elements of
FERCs April 25, 2003 order. In response, on July 25, 2003, FERC
re-affirmed the PUSH interim pricing mechanism.

The
existing reliability must run agreement (RMR) between ISO-NE and NRG
Energy covering Devon 7 and 8 will terminate on September 30, 2003.
At this point it is not clear what mechanism will replace the RMR
after September 30, 2003. Several parties have filed rehearing
requests concerning the existing RMR and FERC has not yet issued an
order covering these rehearing requests.

As a
result of these regulatory developments and changing circumstances in
the second quarter, NRG Energy deemed it necessary to review the
Connecticut facilities cash flow models incorporate
changes to reflect the impact of the April 25, 2003 FERCs orders on PUSH
pricing, the pending termination of the RMR, and update the estimated
impact of future locational capacity or deliverability requirements.
These revised cash flow models determined that the new estimates of
pricing and cost recovery levels were not projected to return
sufficient revenue to cover the fixed costs at Devon Power LLC and
Middletown Power LLC. As a consequence, during the second quarter of
2003 NRG Energy recorded a $64.2 million and $157.3 million
impairment at Devon Power LLC and Middletown Power LLC, respectively.
NRG Energy accounts for the results of operations of the Connecticut
facilities as part of its power generation segment within North
America.

During the three and six month period ended June 30, 2003, the Company
incurred $1.7 million and $2.3 million, respectively, of restructuring costs
consisting of advisor fees, which includes $0.6 million of restructuring costs
for the period May 14, 2003 (the date of the bankruptcy petition) to June 30,
2003. These costs consist of employee separation costs and advisor fees.

11. Asset Retirement Obligation

Effective
January 1, 2003, the Company adopted SFAS No. 143, Accounting
for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires an
entity to recognize the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. Upon initial recognition of a
liability for an asset retirement obligation, an entity shall capitalize an
asset retirement cost by increasing the carrying amount of the related
long-lived asset by the same amount as the liability. Over time, the liability
is accreted to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Retirement obligations
associated with long-lived assets included within the scope of SFAS No. 143 are
those for which a legal obligation exists under enacted laws, statutes and
written or oral contracts, including obligations arising under the doctrine of
promissory estoppel.

The Company has identified certain retirement obligations at Somerset
Power LLC, a wholly owned subsidiary of the Company, related primarily to
future environmental obligations. The Company has also identified other asset
retirement obligations that could not be calculated because the assets
associated with the retirement obligations were determined to have an
indeterminate life. The adoption of SFAS No. 143 resulted in recording a $0.2
million increase to property, plant and equipment and a $0.3 million increase
to other long-term obligations. The cumulative effect of adopting SFAS No. 143
was approximately a $0.1 million increase to depreciation expense and
approximately a $0.1 million increase to operating expenses.

The following represents the balances of the asset retirement obligation
as of January 1, 2003 and the additions and accretion of the asset retirement
obligation for the six months ended June 30, 2003:

Accretion SixBeginning Balance
      
      Months Ended
      
      Ending Balance(In thousands)
      
      Jan. 1, 2003
      
      June 30, 2003
      
      June 30, 2003Somerset
          Power LLC
      
      $313
      
      $21
      
      $334Total
      
      $313
      
      $21
      
      $334


The following represents the pro-forma effect on the Companys net income
for the three and six months ended June 30, 2002, as if the Company had adopted
SFAS No. 143 as of January 1, 2002:

Three Months EndedJune 30, 2002(In thousands)Net income as reported
    
    $
    46,753Pro-forma adjustment to reflect retroactive adoption ofSFAS No. 143
    
    
    (14
    )Pro-forma net income
    
    $
    46,739


Six Months EndedJune 30, 2002(In thousands)Net income as reported
    
    $
    48,893Pro-forma adjustment to reflect retroactive adoption ofSFAS No. 143
    
    
    (159
    )Pro-forma net income
    
    $
    48,734


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12. Recent Accounting Pronouncements

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections,that supersedes previous guidance for the reporting of gains and
losses from extinguishment of debt and accounting for leases, among other
things. SFAS No. 145 requires that only gains and losses from the
extinguishment of debt that meet the requirements for classification as
Extraordinary Items, as prescribed in Accounting Practices Board Opinion No.
30, should be disclosed as such in the financial statements. Previous guidance
required all gains and losses from the extinguishment of debt to be classified
as Extraordinary Items. This portion of SFAS No. 145 is effective for fiscal
years beginning after May 15, 2002, with restatement of prior periods required.
The Company adopted this standard as of January 1, 2003 and has no
extraordinary gains or losses that will require restatement.

In addition, SFAS No. 145 amends SFAS No. 13, Accounting for Leases,as
it relates to accounting by a lessee for certain lease modifications. Under
SFAS No. 13, if a capital lease is modified in such a way that the change gives
rise to a new agreement classified as an operating lease, the assets and
obligation are removed, a gain or loss is recognized and the new lease is
accounted for as an operating lease. Under SFAS No. 145, capital leases that
are modified so the resulting lease agreement is classified as an operating
lease are to be accounted for under the sale-leaseback provisions of SFAS No.
98, Accounting for Leases.These provisions of SFAS No. 145 were effective
for transactions occurring after May 15, 2002.

In June 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities,(SFAS No. 146). SFAS No. 146
addresses financial accounting and reporting for costs associated with exit or
disposal activities and nullifies EITF Issue No. 94-3, Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring).SFAS No. 146 applies to
costs associated with an exit activity that does not involve an entity newly
acquired in a business combination or with a disposal activity covered by SFAS
No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.The
provisions of SFAS No. 146 are effective for exit or disposal activities that
are initiated after December 31, 2002.

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation
of Variable Interest Entities(FIN No. 46). FIN No. 46 requires an enterprises
consolidated financial statements to include subsidiaries in which the
enterprise has a controlling interest. Historically, that requirement has been
applied to subsidiaries in which an enterprise has a majority voting interest,
but in many circumstances the enterprises consolidated financial statements do
not include the consolidation of variable interest entities with which it has
similar relationships but no majority voting interest. Under FIN No. 46 the
voting interest approach is not effective in identifying controlling financial
interest. The new rule requires that for entities to be consolidated that those
assets be initially recorded at their carrying amounts at the date the
requirements of the new rule first apply. If determining carrying amounts as
required is impractical, then the assets are to be measured at fair value the
first date the new rule applies. Any difference between the net amount of any
previously recognized interest in the newly consolidated entity should be
recognized as the cumulative effect of an accounting change. FIN No. 46 becomes
effective in the third quarter of 2003. FIN No. 46 is not expected to have a
significant impact on the Company.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133
on Derivative Instruments and Hedging Activities, (SFAS No. 149).SFAS No.
149 amends and clarifies financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contracts (collectively referred to as derivatives) and for hedging activities
under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging
Activities.The provisions of SFAS No. 149 are effective for contracts entered
into or modified after June 30, 2003 and for hedging relationships designated
after June 30, 2002. In addition, provisions of SFAS 149 that relate to SFAS
Statement No. 133 Implementation Issues that have been effective for fiscal
quarters that began prior to June 15, 2003, should continue to be applied in
accordance with their respective effective dates. SFAS No. 149 is not expected
to have an impact on the Company.

In May 2003, the FASB issues SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity,
(SFAS No. 150).SFAS No. 150 establishes standards for how an issuer
classifies and measures certain financial instruments with characteristics of
both liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances). Many of those instruments were previously classified as
equity. The provisions of SFAS 150 are effective for financial instruments
entered into or modified after May 31, 2003, and otherwise is effective at the
beginning of the first interim period beginning after June 15, 2003. SFAS No.
150 is not expected to have an impact on the Company.

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Item 2. Managements Discussion and Analysis of Financial Condition and Results
of Operations

Overview

Due to the factors discussed below, as well as other matters discussed
herein, NRG Energys financial condition has deteriorated significantly in the
recent past. See Liquidity  below. As a result, NRG Energy does not
contemplate that it will have sufficient funds to make required principal and
interest payments on its corporate debt, which means that NRG Energy will
remain in default of the various corporate level debt obligations.

On May 14, 2003, NRG Energy and certain of its U.S. affiliates (including
the Company and its subsidiaries) filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in
the United States Bankruptcy Court for the Southern District of New York (the
Bankruptcy Court). On June 5, 2003 NRG Nelson Turbines LLC and LSP-Nelson
Energy LLC filed voluntary petitions for reorganization under Chapter 11 of the
Bankruptcy Code in the United States Bankruptcy Court for the Southern District
of New York.

Industry Dynamics

An unregulated merchant power company in the United States can be
characterized in two ways, as a generator or as an energy merchant, with some
companies having characteristics of both. In the United States, generators are
either outgrowths of regulated utilities, developers or independent aggregators
of plants divested by utilities. Generators have grown through acquisitions or
the construction of new power plants. Energy merchants have emphasized risk
management and trading skills over the ownership of physical assets. Energy
deregulation paved the way for development of these companies, with utilities
in some regions forced to sell off some of their generating capacity and buy
electricity on the wholesale market or through power procurement agreements.

Both generators and energy merchants prospered in the late 1990s.
Starting in 1999, however, a number of factors began to arise which had a
negative effect on the business model for merchant power companies. These
factors included:

California- When California restructured its electricity industry in the
mid-1990s, it required utilities to sell generation assets and buy electricity
on the wholesale spot market, without the stability of long-term contracts. At
the time, California had adequate supplies of power, but the State of
California was experiencing unusually high electricity demand growth while new
capacity additions were not keeping pace. Supply began to lag behind demand,
and previously moderate weather gave way to dryer conditions, reducing
hydroelectric supply. Shortages and blackouts ensued in 1999 and 2000.
Meanwhile, as wholesale electricity prices moved higher, utilities were not
allowed to pass higher costs on to consumers under Californias regulatory
regime. Unable to bear the financial burden, PG&E sought Chapter 11 protection
and California took over the role of procuring electricity for the utilities.
Politicians have criticized the electricity generators and the energy
merchants, accusing them of improperly manipulating supply, demand and prices.
Merchant power companies in California are now embroiled in protracted
litigation with California and private parties, which is discouraging new
investment.

Economy- The United States economy, already headed towards a recession by
mid-2001, suffered a heavy blow on September 11, 2001. This, along with a
decrease in economically driven electricity demand, exacerbated the drop in
stock valuations of the energy merchants. Other regions of the world economy
have suffered problems as well, which has exposed companies with international
assets to losses based on severe currency fluctuations.

Weather- On the whole, both the summer and winter seasons have been
 mild in the United States. This together with an
oversupply of new generation in many markets has driven down energy prices
significantly.

Enron- The bankruptcy of Enron has devastated the merchant power
industry. The public and political perception created by Enron put a stigma on
the industry, drove investors away and increased scrutiny of the industry.
Enron also played a key role in the energy trading markets, providing a widely
used electronic trading platform that accounted for an enormous amount of
trading volume. No other company has stepped in to fill this role, and as a
result the electricity markets have become far less efficient and liquid.

Credit ratings- The credit rating agencies were sharply criticized for
not foreseeing Enrons problems. As a result, the agencies have been quick to
scrutinize the rest of the industry, and have tightened their criteria for
creditworthiness. The agencies have

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downgraded most, if not all, of the industry participants. Many of these
downgrades were severe  ratings at times were dropped several notches at once,
or dropped more than once in a span of weeks. This has resulted in most of the
energy companies, generators and merchants having non-investment grade credit
ratings at this time.

Oversupply- As wholesale electricity prices and market liquidity
increased in the late 1990s the industry went on a building boom. Through 2001
capital was readily available for the industry, encouraging companies to build
new generation facilities. The years 2000 and 2001 saw record megawatt capacity
additions in the United States, and record years were on the horizon for 2002
and 2003. Even with steady economic growth this would have created an
oversupply of generation. Limited economic growth and recession have
exacerbated the oversupply situation.

Results of Operations

For the three and six months ended
June 30, 2003 compared to the three and six months ended June 30, 2002

Operating Revenues

Total operating revenues were $163.2 million and $185.1 million for the
three months ended June 30, 2003 and 2002, respectively, a decrease of $21.9
million or 11.8%. This decrease is primarily due to the termination of an indemnity agreement between the Company and NRG PMI a wholly owned
subsidiary of NRG Energy and an affiliate of the Company, effective to May 14, 2003.
As a result, subsequent to May 14, 2003 the Company ceased to recognize any
revenues or expenses related to certain contracts. The affected contracts were
the Standard Offer Service contract with CL&P, a long term contract with
Ashland and a long term contract with EUA. Effective May 14, 2003, NRG PMI will
bear the benefits and burdens of these contracts. During the six months ended
June 30, 2003, the standard offer contracts resulted in a net
loss recorded at the Companys Connecticut facilities of approximately $118.7
million. In addition, the Company experienced decreased energy revenues due to
decreased generation during the period.

Total operating revenues were $343.4 million and $316.7 million for the
six months ended June 30, 2003 and 2002, respectively, an increase of $26.7
million or 8.4%. This increase is primarily due to increases in generation
revenues. The average price of natural gas more than doubled in the first six
months of 2003 compared to 2002. This resulted in higher power prices overall,
but also resulted in lower generation at the Companys gas fired plants.
Although the MW hours generated decreased, the substantial increase in power
prices increased the price per MW hour generated. As a result of the increased
power prices, there was increased generation at the coal fired plants. This
increase was offset by losses incurred on the Connecticut Standard Offer and
other contract obligations due to increased market prices, which increased the
cost of purchased power used to service the contract load obligations.

Operating Costs

Operating costs primarily consist of expenses for fuel, plant operations
and maintenance, property and other non-income related taxes and unrealized
gains or losses associated with changes in the fair value of energy related
derivative instruments not accounted for as hedges.

Cost of operations was $186.1 million and $355.2 million for the three and
six months ended June 30, 2003 compared to $110.5 million and $208.6 million
for the three and six months ended June 30, 2003. This represents an increase
of $75.6 million and $146.6 million or 68.4% and 70.3% for the three and six
months ended June 30, 2003 compared to the same periods in 2002. This increase
is primarily due to the Companys financial condition, which resulted in
several contract terminations. During the three and six months ended June 30, 2003 various parties have exercised their rights to terminate certain commodity purchase and sale contracts. As a result contract termination expense of approximately
$63 million was recorded during 2003. In addition, although generation declined for the
three and six month periods ended June 30, 2003 compared to the same periods in
2002, the cost of generation increased substantially due to increased fuel oil
and natural gas prices.

Depreciation

Depreciation expense was $20.4 million and $13.8 million for the three
months ended June 30, 2003 and 2002, respectively, an increase of $6.6 million
or 47.6%. In light of economic developments related to the Connecticut assets
and the FERC recently issued order regarding cost of service reimbursements,
The Company reassessed the asset lives for the Connecticut facilities. The
shorter depreciable lives resulted in an increase in depreciation of
approximately $6.3 million for the three months ended June 30, 2003.

Depreciation expense was $36.8 million and $26.2 million for the six months
ended June 30, 2003 and 2002, respectively, an increase of $10.6 million or
40.6%. The increase in depreciation expense is attributable to shorter
depreciable lives on the Connecticut facilities, of approximately $13.2 million
for the six months ended June 30, 2003. Depreciation expense decreased due to

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the reduced asset values based on the impairment analysis for the Somerset
Facility, which was written down to fair market value during the third quarter
of 2002.

General and Administrative Expenses

General and administrative expense was $6.5 million and $7.7 million for
the three months ended June 30, 2003 and 2002, respectively, a decrease of $1.2
million or 15.6%. General and Administrative costs include non-operation labor
and other employee related costs, as well as outside services, insurance,
office expenses and administrative support. This decrease is due to a one time
charge in 2002 related to tax matters totaling about $1.6 million which is
offset by additional expenditures in 2003 for increased insurance premiums and
costs related generally to legal and technical consulting.

General and administrative expense was $17.3 million and $11.3 million for
the six months ended June 30, 2003 and 2002, respectively, an increase of $6.0
million or 52.9%. This increase is due to several factors including costs
related to additional legal and technical consulting, increased insurance
premiums which are running approximately 50% higher than last year and $6.2
million of bad debt expense recorded in the first three months of 2003 for
collectibility issues primarily related to one contract. As offsets to these
increases the Company incurred one time costs in 2002 of approximately $1.6
million and decreased costs related to work force reduction efforts.

Asset Impairments and
Restructuring Charges

Asset
impairment and restructuring charges were $222.5 million and $223.3 for the three and six months
ended June 30, 2003, respectively. There were no charges for the same
periods in 2002. Asset impairment charges were $221.5 million for the
three and six months ended June 30, 2003. Restructuring costs were $1.0
million and $1.7 million for the three and six months ended June 30, 2003, respectively.

Asset impairments for the three and six month
periods ended June 30, 2003 consisted of Devon Power LLC and Middletown Power LLC. On February 26, 2003 NRG
Energy filed a proposed cost of service agreement with the Federal Energy Regulatory Commission (FERC). On April
25, 2003, the FERC issued an order that rejected
the proposed fixed monthly charges, citing certain policy determinations regarding cost-of-service
agreements. Considering those policy concerns, the FERC instead directed NRG Energy to recover its
fixed and variable costs under a new Peaking Unit Safe Harbor (PUSH)
mechanism, rather than
through a fixed monthly charge, for the remainder of 2003 through June 2004. Under
the PUSH rules proscribed by FERC, Middletown 2 and 3 could not submit PUSH bids. FERC also ordered
 that the regional power agencies overseeing the energy markets in Connecticut file with FERC
locational capacity or deliverability requirements by March 2004 for implementation by June 1,
2004. Such agencies have not yet formally responded to FERC with a recommended locational
capacity or deliverability proposal for use after the PUSH mechanism expires on May 31, 2004.

The
existing reliability must run agreement (RMR) between ISO-NE and NRG
Energy covering Devon 7 and 8 will terminate on September 30, 2003. At this point it is not clear what mechanism will replace the RMR after September 30, 2003. Several parties have filed
rehearing requests concerning the existing RMR and FERC has not yet issued an order covering these rehearing requests.

As a result of these and other
regulatory developments and changing circumstances in the second quarter, as discussed further
in Note 4 to the financial statements, NRG Energy deemed it necessary to review the Connecticut
facilities' cash flow models to incorporate changes to reflect the
impact of the April 25, 2003 FERC's orders
on PUSH pricing and update the
estimated impact of future locational pricing. These revised cash flow models determined that
the new estimates of pricing and cost recovery levels were not projected to provide sufficient
revenue to cover the fixed costs at Devon Power LLC and Middletown Power LLC. As a consequence,
during the second quarter, NRG Energy recorded a $221.5 million impairment charge for Devon and Middletown.

During the three and six month periods ended June 30, 2003, the Company incurred $1.7 million and $2.3 million, respectively, of restructuring
costs consisting of advisor fees, which includes $0.6 million of restructuring
costs for the period May 14, 2003 (the date of the bankruptcy petition) to June
30, 2003. These costs consist of employee separation costs and advisor fees.

Regulatory Issues

NRG Energy is impacted by market rule and tariff changes in the existing
Independent System Operators (ISOs) and Regional Transmission Organizations
(RTOs), On March 1, 2003, ISO-New England implemented its version of Standard
Market Design. This change dramatically modifies the New England market
structure by incorporating Locational Marginal Pricing (pricing by location
rather than on a New England wide basis). On February 26, 2003, NRG Energy
filed a proposed cost of service agreement with the Federal Energy Regulatory
Commission (FERC) for the following Connecticut facilities: Middletown Power
LLC, Montville Power LLC, Norwalk Power LLC and Devon Power LLC units 11-14
(collectively the NRG Subsidiaries). In the filing, NRG Energy requested that
major and minor maintenance expenses of the NRG Subsidiaries be paid for
through a tracking mechanism that would insure that NRG Energy receives
compensation only for actual maintenance expenses. Under the proposed cost of
service agreement, the other NRG Energy costs would be paid through a monthly
cost-based payment. NRG Energy requested an effective date of February 27,
2003. The cost of service filing was made notwithstanding the impending
implementation of Standard Market Design in New England, including the adoption
of Locational Marginal Pricing. While the Standard Market Design represents a
significant improvement to the existing market design, NRG Energy still
considered the market insufficient to allow NRG Energy to recover its
reasonable costs and earn a reasonable return on investment.

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On March 25, 2003, FERC issued an order (the March Order) approving the
NRG Subsidiaries spring 2003 maintenance expenses, subject to refund and
authorized an effective date of February 27, 2003. In the March Order, FERC
also permitted ISO New England, viaan escrow account, to start collecting the
amount of the maintenance expenses in order to ensure the availability of the
NRG Energy units for the summer 2003 peak season. To the extent that NRG Energy incurs maintenance related
expenses and submitted such expenses to the ISO for reimbursement, NRG Energy will recognize
the expenses in the period incurred. Upon reimbursement from the ISO for maintenance related expenses, NRG Energy
will recognize revenue. FERC did not rule on the
remainder of the issues to allow further time to consider protests.

On April 25, 2003, the FERC issued an order (the April Order) rejecting
the remaining part of the proposed cost of service agreements including the
monthly cost-based payment. Rather, FERC instructed ISO New England to
establish temporary bidding rules that would permit selected peaking units
(units with capacity factors of 10 percent or less during 2002), operating
within designated congestion areas (such as Connecticut) to raise their bids
to allow them the opportunity to recover their fixed and variable costs through
the market. This temporary bidding rule would remain in place until ISO New
England implements locational installed capacity requirements, which should
be no later than June 1, 2004. In the July 24 Order on Rehearing (the July
Order), FERC clarified that the capacity factor of 10 percent or less applies
to units rather than complexes. On a unit basis, all the NRG Energy
facilities qualify to bid under the temporary rules except Middletown 2 and 3.
For additional information regarding the impact that the April 25, 2003 FERC order and other regulatory developments had on
NRG Energys results of operations, see Note 10.

Interest Expense

Interest expense was $13.1 million and $11.1 million for the three months
ended June 30, 2003 and 2002, respectively, an increase of $2.0 million or
18.0%. Interest expense relates to the amortization of deferred finance costs,
interest on the senior secured bonds issued on February 22, 2000 and an
affiliated note payable issued on June 15, 2002. After the bankruptcy filing
the Company entered into a Senior Secured, Super-Priority (Debtor-in-Possession
Credit Agreement) which costs are being amortized starting May 14, 2003. In
addition, the affiliated note was only in effect a part of 2002 and is being
accrued for the full quarter in 2003.

Interest expense was $25.7 million and $26.7 million for the six months
ended June 30, 2003 and 2002, respectively, a decrease of $1.0 million or 3.9%.
This decrease is due to the decline in the average principle amounts
outstanding on the senior secured indebtedness during the first quarter of
approximately $3.0 million and the offset by additional costs related to the
affiliated note payable and amortization of deferred finance costs related to
the Debtor-in Possession Agreement.

Accounting Policies and Estimates

Managements discussion and analysis of its financial
condition and results of operations are based upon the Companys consolidated
financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States of America. The preparation
of these financial statements and related disclosures in compliance with
generally accepted accounting principles requires the application of
appropriate technical accounting rules and guidance as well as the use of
estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses. These judgments, in and of themselves,
could materially impact the financial statements and disclosures based on
varying assumptions, which may be appropriate to use. In addition, the
financial and operating environment also may have a significant effect, not
only on the operation of the business, but on the results reported through the
application of accounting measures used in preparing the financial statements
and related disclosures, even if the nature of the accounting policies have not
changed.

On an ongoing basis, the Company evaluates its estimates utilizing
historic experience, consultation with experts and other methods the Company
considers reasonable. In any case, actual results may differ significantly from
the Companys estimates. Any effects on the Companys business, financial
position or results of operations resulting from revisions to these estimates
are recorded in the period in which the facts that give rise to the revision
become known.

Refer to Item 15 Note 2 of the consolidated financial statements of the
Companys Form 10-K for the year ended December 31, 2002 for additional
discussion regarding the Companys accounting policies and estimates.

Liquidity and Capital Resources

Liquidity Issues of NRG Energy and it Subsidiaries  Current Status and
Chain of Events

In December 2001, Moodys Investor Service (Moodys) placed NRG Energys
long-term senior unsecured debt rating on review for possible downgrade. In
response, Xcel Energy and NRG Energy put into effect a plan to preserve NRG
Energys investment grade rating and improve its financial condition. This plan
included financial support to NRG Energy from Xcel Energy; marketing certain

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NRG Energy assets for sale; canceling and deferring capital spending; and
reducing corporate expenses.

In response to a possible downgrade during 2002, Xcel Energy contributed
$500 million to NRG Energy, and NRG Energy and its subsidiaries sold assets and
businesses that provided NRG Energy in excess of $286 million in cash and
eliminated approximately $432 million in debt. NRG Energy also cancelled or
deferred construction of approximately 3,900 MW of new generation projects. On
July 26, 2002, Standard & Poors (S&P) downgraded NRG Energys senior unsecured
bonds to below investment grade, and three days later Moodys also downgraded
NRG Energys senior unsecured debt rating to below investment grade. Since July
2002, NRG Energy senior unsecured debt, as well as the secured NRG Northeast
Generating LLC bonds and the secured NRG South Central Generating LLC bonds and
secured LSP Energy (Batesville) bonds were downgraded multiple times. After NRG
Energy failed to make payments due under certain unsecured bond obligations on
September 16, 2002, both Moodys and S&P once again lowered their ratings on
NRG Energys unsecured bonds and its subsidiaries secured bonds. Currently,
NRG Energys unsecured bonds carry a rating of D at S&P and between Ca and C at
Moodys, depending on the specific debt issue. NRG Northeast Generating LLC
secured bonds currently carry a rating of D at S&P and B1 at Moodys.

As a result of the downgrade of NRG Energys credit rating, declining
power prices, increasing fuel prices, the overall down-turn in the energy
industry, and the overall down-turn in the economy, NRG Energy has experienced
severe financial difficulties. These difficulties have caused NRG Energy to,
among other things, miss scheduled principal and interest payments due to its
corporate lenders and bondholders, prepay for fuel and other related delivery
and transportation services and provide performance collateral in certain
instances. NRG Energy has also recorded asset impairment charges of
approximately $3.1 billion as of December 31, 2002, related to various
operating projects as well as for projects that were under construction which
NRG Energy has stopped funding.

NRG Energy and certain wholly owned subsidiaries have failed to timely
make several interest and/or principal payments on indebtedness. These missed
payments have resulted in cross-defaults of numerous other non-recourse and
limited recourse debt instruments of NRG Energy and have caused the
acceleration of multiple debt instruments of NRG Energy, rendering such debt
immediately due and payable.

Since March 31, 2003 NRG Energy failed to make a first-quarter payment of
$19.1 million due on March 31, 2003 relating to interest and fees on the $1.0
billion unsecured 364-day revolving credit facility; a $13.6 million interest
payment due on April 1, 2003 on the $350 million of 7.75% senior unsecured
notes maturing 2011; a $21.6 million interest payment due on April 1, 2003 on
the $500 million of 8.625% senior unsecured notes maturing 2031; and a $9.6
million interest payment due on May 1, 2003 on the $240 million of 8.0% senior
unsecured notes maturing 2013. On May 13, 2003, XL Capital Assurance, as
controlling party, accelerated the approximately $319 million of debt issued by
NRG Peaker Finance Company LLC. These facilities are in default.

NRG Energy failed to make a second quarter payment of $18 million due on
June 30, 2003, relating to interest and fees on the $1.0 billion unsecured,
364-day revolving credit facility; a $11.3 million interest payment due June 1,
2003, on the $300 million of 7.5% senior unsecured notes maturing in 2009; and
a $9.4 million interest payment due on June 15, 2003, on the $250 million of
7.5% senior unsecured notes due in 2007.

Prior to the downgrades, many corporate guarantees and commitments of NRG
Energy and its subsidiaries required that they be supported or replaced with
letters of credit or cash collateral within 5 to 30 days of a ratings downgrade
below Baa3 or BBB- by Moodys or Standard & Poors, respectively. As a result
of the downgrades on July 26, 2002 and July 29, 2002, NRG Energy received
demands to post collateral aggregating approximately $1.2 billion. NRG Energy
is presently working with various secured project lender groups with respect to
the issue of posting collateral and is working towards establishing a
comprehensive plan of restructuring.

In August 2002, NRG Energy retained financial and legal restructuring
advisors to assist its management in the preparation of a comprehensive
financial and operational restructuring. In November 2002, NRG Energy and Xcel
Energy presented a comprehensive plan of restructuring to an ad hoc committee
of its bondholders and a steering committee of its bank lenders (the Ad Hoc
Creditors Committees). The restructuring plan served as a basis for continuing
negotiations between the Ad Hoc Creditors Committees, NRG Energy and Xcel
Energy related to a consensual plan of reorganization for NRG Energy.

On November 22, 2002, five former NRG Energy executives filed an
involuntary Chapter 11 petition against NRG Energy in U.S. Bankruptcy Court for
the District of Minnesota (the Minnesota Bankruptcy Court). On February 19,
2003, NRG Energy announced that it had reached a settlement with the
petitioners. On May 12, 2003, the Minnesota Bankruptcy Court issued an order
abstaining from exercising jurisdiction over any aspect of the case and
dismissed the case.

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On March 26, 2003, Xcel Energy announced that its board of directors had
approved a tentative settlement agreement with holders of most of NRG Energys
long-term notes and the steering committee representing NRG Energys bank
lenders. The settlement is subject to certain conditions, including the
approval of at least a majority in dollar amount of the NRG Energy bank lenders
and long-term noteholders and definitive documentation. There can be no
assurance that such approvals will be obtained. The terms of the settlement
call for Xcel Energy to make payments to NRG Energy over the next 10 months
totaling up to $752 million for the benefit of NRG Energys creditors in
consideration for their waiver of any existing and potential claims against
Xcel Energy. Under the settlement, Xcel Energy will make the following
payments: (i) $350 million at or shortly following the consummation of a
restructuring of NRG Energys debt. It is expected this payment would be made
prior to year-end 2003; (ii) $50 million on January 1, 2004. At Xcel Energys
option, it may fill this requirement with either cash or Xcel Energy common
stock or any combination thereof; and (iii) $352 million in April 2004. Since
the announcement on March 26, 2003, representatives of NRG Energy, Xcel Energy,
the bank lenders and noteholders have continued to meet to draft the definitive
documentation necessary to fully implement the terms and conditions of the
tentative settlement agreement.

On May 14, 2003 NRG Energy and certain of its U.S. affiliates (including
NRG Northeast and its subsidiaries) filed voluntary petitions for
reorganization under Chapter 11 of the United States Bankruptcy Code in the
United States Bankruptcy Court for the Southern District of New York (the
Bankruptcy Court), In re: NRG ENERGY, INC., et. al., Case No. 03-13204 (PCB).
NRG Energy expects operations to continue as normal during the restructuring
process, while it operates its business as a debtor-in possession under the
jurisdiction of the Bankruptcy Court and in accordance with the applicable
provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In
connection with its Chapter 11 filing, NRG Energy also announced that a $250
million debtor-in-possession (DIP) financing facility from GE Capital
Corporation, subject to Bankruptcy Court approval, to be utilized by the
Company and some of the Companys subsidiaries. NRG Energy anticipates that the
DIP, together with its cash reserves and its ongoing revenue stream, will be
sufficient to fund its operations, including payment of employee wages and
benefits, during the reorganization process.

On May 15, 2003, NRG Energy announced that it has been notified that the
New York Stock Exchange (NYSE) has suspended trading in NRG Energys corporate
units that trade under the ticker symbol NRZ and that an application to the
Securities and Exchange Commission to delist the Units is pending the
completion of applicable procedures, including appeal by NRG Energy of the NYSE
staffs decision. NRG Energy does not plan to make such an appeal. The NYSE
took this action following NRG Energys announcement that it and certain of its
U.S. affiliates had filed voluntary petitions for reorganization under Chapter
11 of the U.S. Bankruptcy Code.

In addition, on May 15, 2003, NRG Energy,
NRG Power Marketing, Inc., NRG Finance Company I, LLC, NRGenerating Holdings (No. 23) B.V. and NRG
Capital LLC (collectively, the Plan Debtors) filed their Disclosure Statement for Reorganizing Debtors Joint
Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy
Code (as subsequently amended, the Disclosure Statement). The Bankruptcy
Court held a hearing on the Disclosure Statement on June 30, 2003, and
instructed the Plan Debtors to include certain additional disclosure. The Plan Debtors
amended the Disclosure Statement and obtained Bankruptcy Court approval for the
Third Amended Disclosure Statement for Debtors Second Amended Joint Plan of
Reorganization Pursuant to Chapter 11 of the Bankruptcy Code (respectively, the
Amended Disclosure Statement, the Plan).

The Plan must be approved by the SEC prior to its becoming effective. As
subsidiaries of a registered holding company (Xcel Energy) under PUHCA, any
reorganization plan for NRG Energy or NRG Energys subsidiaries must be
approved by the SEC prior to such plan becoming effective. Furthermore, each
solicitation of any consent in respect of any reorganization plan must be
accompanied or preceded by a copy of a report on the plan made by the SEC, or
an abstract thereof made or approved by the SEC. The Plan and Amended
Disclosure Statement were submitted to the SEC for review on Monday July 28, 2003. The Plan Debtors will not be able to solicit acceptances
or rejections in connection with the Plan prior to obtaining the required SEC approval. As a result,
no deadlines or dates have been set regarding voting or confirmation.

On
June 5, 2003, NRG Nelson Turbines LLC and LSP-Nelson Energy LLC
(both wholly owned subsidiaries of NRG Energy) filed
voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code
in the United States Bankruptcy Court for the Southern District of New York.

Cash Flows

For the six months endedJune 30,(In thousands)
    
    2003
    
    2002Net cash provided by operating activities
    
    $
    2,783
    
    
    $
    44,361


Net cash
provided by operating activities was adversely impacted during the six months ended June
30, 2003 as compared to the same period in 2002 due primarily to
unfavorable operating results offset by favorable changes in working capital.

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For the six months endedJune 30,(In thousands)
    
    2003
    
    2002Net
cash used by investing activities
    
    $
    (618
    )
    
    $
    (22,695
    )


Net cash
used by investing activities for the six months ended June
30, 2003, was favorably impacted as compared to the same period in
2002 due to a reduction in capital expenditures offset by cash proceeds received upon sale
of property during 2003.

For the six months endedJune 30,(In thousands)
    
    2003
    
    2002Net cash used by financing activities
    
    $
    (7,537
    )
    
    $
    (22,036
    )


Net cash used by financing activities for the six months ended June 30,
2003 was favorably impacted as compared to the same period in 2002 due to
no principal payments made during
2003, offset in part by a lack of borrowings and additional deferred
financing costs in 2003 in connection with the DIP financing arrangements.

The debt agreements of NRG Energys subsidiaries and project affiliates
generally restrict their ability to pay dividends, make distributions or
otherwise transfer funds to NRG Energy. As of June 30, 2003, the Company is
restricted from making distributions to NRG Energy. On June 30, 2003, the
Company had approximately $9.0 million of cash on hand.

Off Balance-Sheet Arrangements

As of June 30, 2003, The Company does not have any significant
relationships with structured finance or special purpose entities that provide
liquidity, financing or incremental market risk or credit risk.

Contractual obligations and commercial commitments

The Company has a variety of contractual obligations and other commercial
commitments that represent prospective cash requirements in addition to its
capital expenditure program. The following is a summarized table of contractual
obligations. See additional discussion in Item 15 and Notes 6, 7 and 12 to the
Consolidated Financial Statements of the Companys Form 10-K filing for the
year ended December 31, 2002.

Payments Due by Period Subsequent to June 30, 2003Total
    
    Short Term
    
    1-3 Years
    
    4-5 Years
    
    After 5 Years(In thousands)Long term debt
    
    $
    556,500
    
    
    $
    556,500
    
    
    $
    
    
    
    $
    
    
    
    $
    Operating leases
    
    
    6,676
    
    
    
    780
    
    
    
    1,536
    
    
    
    1,048
    
    
    
    3,312Note payable  affiliate
    
    $
    30,000
    
    
    $
    30,000
    
    
    
    
    
    
    
    
    
    
    
    Total contractual cash
obligations
    
    $
    593,176
    
    
    $
    587,280
    
    
    $
    1,536
    
    
    $
    1,048
    
    
    $
    3,312


Amount of Commitment by Expiration Period as of June 30, 2003Total AmountsCommitted
    
    Short Term
    
    1-3 Years
    
    4-5 Years
    
    After 5 Years(In thousands)Guarantees
    
    $
    42,300
    
    
    $
    42,300
    
    
    $
    
    
    
    $
    
    
    
    $
    Total guarantees
    
    $
    42,300
    
    
    $
    42,300
    
    
    $
    
    
    
    $
    
    
    
    $
    


The Company provides performance guarantees to third parties on behalf of
NRG Power Marketing in relation to certain of its sales and supply agreements.

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Derivative Instruments

The tables below disclose the Companys derivative activities that include
non-exchange traded contracts accounted for at fair value. Specifically, these
tables disaggregate realized and unrealized changes in fair value; identifies
changes in fair value attributable to changes in valuation techniques;
disaggregates estimated fair values at the three and six months ended June 30,
2003 based on whether fair values are determined by quoted market prices or
more subjective means; and indicates the maturities of contracts at the three
and six months ended June 30, 2003.

Derivative Activity

Three Months Ended
    
    Six Months EndedGains/(Losses)  (In thousands)
    
    June 30, 2003
    
    June 30, 2003Fair Value of contracts outstanding at the beginning of the period
    
    $
    (8,505
    )
    
    $
    (3,641
    )Contracts realized or otherwise settled during the period
    
    
    40,487
    
    
    
    34,396Fair value of new contract when entered into during the period
    
    
    
    
    
    
    Changes in fair values attributable to changes in valuation techniques
    
    
    
    
    
    
    Other changes in fair values
    
    
    (29,044
    )
    
    
    (27,817
    )Fair value of contracts outstanding at the end of the period
    
    $
    2,938
    
    
    $
    2,938


Sources of Fair Value Gains/(Losses)

Fair Value of Contracts at Period EndMaturity
    
    
    
    
    
    
    
    
    
    Maturity inLess than 1
    
    Maturity
    
    Maturity
    
    excess of
    
    Total FairMaturity schedule  (In thousands)
    
    Year
    
    1-3 Years
    
    4-5 Years
    
    5 Years
    
    ValuePrices actively quoted
    
    $
    2,938
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    2,938Prices provided by other external sources
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Prices based on models & other valuation
Methods
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    2,938
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    2,938


Recent Accounting Pronouncements

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections,that supersedes previous guidance for the reporting of gains and
losses from extinguishment of debt and accounting for leases, among other
things. SFAS No. 145 requires that only gains and losses from the
extinguishment of debt that meet the requirements for classification as
Extraordinary Items, as prescribed in Accounting Practices Board Opinion No.
30, should be disclosed as such in the financial statements. Previous guidance
required all gains and losses from the extinguishment of debt to be classified
as Extraordinary Items. This portion of SFAS No. 145 is effective for fiscal
years beginning after May 15, 2002, with restatement of prior periods required.
The Company adopted this standard as of January 1, 2003 and has no
extraordinary gains or losses that will require restatement.

In addition, SFAS No. 145 amends SFAS No. 13, Accounting for Leases,as
it relates to accounting by a lessee for certain lease modifications. Under
SFAS No. 13, if a capital lease is modified in such a way that the change gives
rise to a new agreement classified as an operating lease, the assets and
obligation are removed, a gain or loss is recognized and the new lease is
accounted for as an operating lease. Under SFAS No. 145, capital leases that
are modified so the resulting lease agreement is classified as an operating
lease are to be accounted for under the sale-leaseback provisions of SFAS No.
98, Accounting for Leases.These provisions of SFAS No. 145 were effective
for transactions occurring after May 15, 2002.

In June 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities,(SFAS No. 146). SFAS No. 146
addresses financial accounting and reporting for costs associated with exit or
disposal activities and nullifies

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EITF Issue No. 94-3, Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring).SFAS No. 146 applies to costs associated
with an exit activity that does not involve an entity newly acquired in a
business combination or with a disposal activity covered by SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets.The
provisions of SFAS No. 146 are effective for exit or disposal activities that
are initiated after December 31, 2002.

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation
of Variable Interest Entities(FIN No. 46). FIN No. 46 requires an enterprises
consolidated financial statements to include subsidiaries in which the
enterprise has a controlling interest. Historically, that requirement has been
applied to subsidiaries in which an enterprise has a majority voting interest,
but in many circumstances the enterprises consolidated financial statements do
not include the consolidation of variable interest entities with which it has
similar relationships but no majority voting interest. Under FIN No. 46 the
voting interest approach is not effective in identifying controlling financial
interest. The new rule requires that for entities to be consolidated that those
assets be initially recorded at their carrying amounts at the date the
requirements of the new rule first apply. If determining carrying amounts as
required is impractical, then the assets are to be measured at fair value the
first date the new rule applies. Any difference between the net amount of any
previously recognized interest in the newly consolidated entity should be
recognized as the cumulative effect of an accounting change. FIN No. 46 becomes
effective in the third quarter of 2003. FIN No. 46 is not expected to have a
significant impact on the Company.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133
on Derivative Instruments and Hedging Activities, (SFAS No. 149).SFAS No.
149 amends and clarifies financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contracts (collectively referred to as derivatives) and for hedging activities
under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging
Activities.The provisions of SFAS No. 149 are effective for contracts entered
into or modified after June 30, 2003 and for hedging relationships designated
after June 30, 2002. In addition, provisions of SFAS 149 that relate to SFAS
Statement No. 133 Implementation Issues that have been effective for fiscal
quarters that began prior to June 15, 2003, should continue to be applied in
accordance with their respective effective dates. SFAS No. 149 is not expected
to have an impact on the Company.

In May 2003, the FASB issues SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity,
(SFAS No. 150).SFAS No. 150 establishes standards for how an issuer
classifies and measures certain financial instruments with characteristics of
both liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances). Many of those instruments were previously classified as
equity. The provisions of SFAS 150 are effective for financial instruments
entered into or modified after May 31, 2003, and otherwise is effective at the
beginning of the first interim period beginning after June 15, 2003. SFAS No.
150 is not expected to have an impact on the Company.




Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company is exposed to market risks, including changes in commodity
prices and interest rates, and credit risk as disclosed in Managements
Discussion and Analysis in its annual report on Form 10-K for the year ended
December 31, 2002. Except as follows, there have been no material changes as of
June 30, 2003 to the market risk disclosures presented as of December 31, 2002.

Commodity Price Risk

The Company is exposed to commodity price variability in electricity,
emission allowances and natural gas, oil and coal used to meet fuel
requirements. To manage earnings volatility associated with these commodity
price risks, the Company, through its affiliate NRG Power Marketing, may enter
into financial instruments, which may take the form of fixed price, floating
price or indexed sales or purchases, and options, such as puts, calls, basis
transactions and swaps.

Through NRG Power Marketing, the Company utilizes an undiversified
Value-at-Risk (VAR) model to determine the maximum potential three-day loss
in the fair value of the commodity price related financial instruments for the
forward twelve months. The VAR for the Company assumes a 95% confidence
interval and reflects the Companys merchant strategy, the generation assets,
load obligations and the bilateral physical and financial transactions of the
Company. The volatility estimate is based on the implied volatility for at the
money daily call options for forward markets where the Company has exposure.
This model encompasses the ISO-NE and NYISO generating regions.

The estimated maximum potential three-day loss in fair value of the
commodity price related financial instruments, calculated

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using the VAR model, is approximately $146.2 million and $62.3 million as
of June 30, 2003 and 2002, respectively. The average, high and low amounts for
the six months ended June 30, 2003 were $149.4 million, $224.5 million and
$76.8 million, respectively. The average, high and low amounts for the three
months ended June 30, 2002 were $38.3 million, $79.4 million and $26.1 million,
respectively.




Item 4. Controls and Procedures

The Vice President, Treasurer and Controller (the Certifying Officers)
have evaluated the Companys disclosure controls and procedures as defined in
the rules of the SEC as of the end of the period covered by this report and have
determined that, except to the extent indicated otherwise in this paragraph,
disclosure controls and procedures were effective in ensuring that material
information required to be disclosed by the Company in the reports filed under
the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the SECs rules and forms. During
the fourth quarter of 2002, the Certifying Officers determined that there were
certain deficiencies in the internal controls relating to financial reporting
at the Company caused by the Companys pending financial restructuring and
business realignment. During the second half of 2002, there were material
changes and vacancies in senior NRG Northeast management positions and a
diversion of the Companys financial and management resources to restructuring
efforts. These circumstances detracted from the Companys ability through its
internal controls to timely monitor and accurately assess the impact of certain
transactions, as would be expected in an effective financial reporting control
environment. the Company has dedicated and will continue to dedicate in 2003
resources to make corrections to those control deficiencies. Notwithstanding
the foregoing and as indicated in the certification accompanying the signature
page to this report, the Certifying Officers have certified that, to the best
of their knowledge, the financial statements, and other financial information
included in this report on Form 10-Q, fairly present in all material respects
the financial conditions, results of operations and cash flows of the Company
as of, and for the periods presented in this report.

The Companys Certifying Officers are primarily responsible for the
accuracy of the financial information that is represented in this report. To
meet their responsibility for financial reporting, they have established
internal controls and procedures which, subject to the disclosure in the
foregoing paragraph, they believe are adequate to provide reasonable assurance
that the Companys assets are protected from loss. There were no significant
changes in internal controls or in other factors that could significantly
affect these controls subsequent to the date of the Certifying Officers
evaluation.

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Part II  OTHER INFORMATION




Item 1. Legal Proceedings

For a discussion of material legal proceedings in which the Company was
involved through June 30, 2003, see Note 8, Commitments and Contingencies
to NRG Northeasts Consolidated Financial Statements and Footnotes contained in
Part I, Item 1 of this Form 10-Q.




Item 3. Defaults Upon Senior Securities

The Company has identified the following material defaults with respect to
the indebtedness of the Company and its significant subsidiaries:

$320 million of 8.065% Series A Senior Secured Bonds due 2004 issued by
NRG Northeast Generating LLC



| |  | Failure to make $53.5 million principal payment on December 15, 2002
|- |  | --------------------------------------------------------------------



| |  | Failure to make $17.5 million principal payment on June 15, 2003
|- |  | ----------------------------------------------------------------



| |  | Failure to fund debt service reserve account
|- |  | --------------------------------------------

$130 million of 8.824% Series B Senior Secured Bonds due 2015 issued by NRG Northeast Generating LLC



| |  | Failure to fund debt service reserve account
|- |  | --------------------------------------------

$300 million of 9.29% Series C Senior Secured Bonds due 2024 issued by NRG Northeast Generating LLC



| |  | Failure to fund debt service reserve account
|- |  | --------------------------------------------

In addition to the foregoing, there may be additional technical defaults
with respect to these or other NRG Northeast debt instruments. Defaults on or
acceleration of the foregoing debt instruments may result in cross-defaults on
or cross-acceleration of these or other NRG Northeast debt instruments.
However, the Company made a total of $24.8 million of interest payments due
June 15, 2003 on the Series A, B and C Bonds.




Item 6. Exhibits and Reports on Form 8-K



|(a) |  | Exhibits                  
|--- |  | --------------------------
|   
|31  |  | Section 302 Certifications
|   
|32  |  | Section 906 Certification 
|   
|(b) |  | Reports on Form 8-K:      
|   
|    |  | None                      




Cautionary Statement Regarding Forward-Looking Statements

The information presented in this quarterly report includes
forward-looking statements in addition to historical information. These
statements involve known and unknown risks and relate to future events, or
projected business results. In some cases forward-looking statements may be
identified by their use of such words as may, expects, plans,
anticipates, contemplates, believes, and similar terms. Forward-looking
statements are only predictions or expectations and actual results may differ
materially from the expectations expressed in any forward-looking statement.
While the Company believes that the expectations expressed in such
forward-looking statements are reasonable, the Company can give no assurances
that these expectations will prove to have been correct. In addition to any
assumptions and other factors referred to specifically in connection with such
forward-looking statements, factors that could cause actual results to differ
materially from those contemplated in any forward-looking statements include,
among others, the following:



| |  | The impact of NRG Energys or the Companys Chapter 11 bankruptcy filing
in the United States Bankruptcy Court for the
|- |  | ----------------------------------------------------------------------------------------------------------------------

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| |  | Southern District of New York, including the actions and decisions of
creditors of NRG Energy and the Company and/or interested third parties, the
various instructions, orders and decisions of the Bankruptcy Court and the
possibility of a bankruptcy filing by additional NRG Energy subsidiaries.
| |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | NRG Energys ability or the ability of any of its subsidiaries to reach agreements with its lenders, creditors and other
stakeholders regarding a comprehensive restructuring of NRG Energy;
|- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;
|- |  | -------------------------------------------------------------------------------------------------------



| |  | NRG Energys ability to sell assets in the amounts and on the time table assumed;
|- |  | ---------------------------------------------------------------------------------



| |  | General economic conditions including inflation rates and monetary exchange rate fluctuations;
|- |  | ----------------------------------------------------------------------------------------------



| |  | Customer business conditions including demand for their products or services and supply of labor and materials used in
creating their products and services and solvency;
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Supplier financial condition, including solvency and the ability to deliver procured commodities and services as required and
directed.
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------



| |  | Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities
and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Factors affecting power generation operations such as unusual weather conditions; catastrophic weather-related damage;
unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, or gas supply costs or
availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or
electric transmission or gas pipeline system constraints;
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Employee workforce factors including loss or retirement of key executives, collective bargaining agreements with union
employees, or work stoppages;
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Volatility of energy prices in a deregulated market environment:
|- |  | ----------------------------------------------------------------



| |  | Increased competition in the power generation industry;
|- |  | -------------------------------------------------------



| |  | Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;
|- |  | -------------------------------------------------------------------------------------------------------------------------------



| |  | Limitations on the Companys ability to control projects in which NRG Energy has less than 100% interest;
|- |  | ---------------------------------------------------------------------------------------------------------



| |  | Limited operating history at recently acquired or constructed projects provide only a limited basis for management to project
the results of future operations;
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Risks associated with timely completion of projects under construction, including obtaining competitive commercial agreements,
obtaining regulatory and permitting approvals, local opposition, construction delays and other factors beyond the Companys
control;
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Factors associated with various investments including competition, operating risks, dependence on certain suppliers and
customers, and environmental and energy regulations;
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Changes in government regulation or the implementation of new government regulations, including pending changes within or
outside of California as a result of the California energy crisis, or the outcome of litigation pending in California and
other western states, which could adversely affect the continued deregulation of the electric industry;
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Other business or investment considerations that may be disclosed from time to time in the Companys Securities and Exchange
Commission filings or in other publicly disseminated written documents.
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Changes in market design or implementation of rules that affect NRG Energys ability to transmit or sell power in any market,
|- |  | -----------------------------------------------------------------------------------------------------------------------------

29



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| |  | including, without limitation, the failure of market mechanism to allow NRG
Energy to recover all of its fixed costs through the FERC authorized bidding
procedure on certain Connecticut generation facilities.
| |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The Company undertakes no obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or otherwise.
The foregoing review of factors that could cause the Companys actual results
to differ materially from those contemplated in any forward-looking statements
included in this Form 10-Q should not be construed as exhaustive.

30



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SIGNATURES

Pursuant to the requirements 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.

NRG Northeast Generating LLC(Registrant)/s/ Scott J. DavidoScott J. Davido,
Vice President
(Principal Executive Officer)/s/ George P. SchaeferGeorge P. Schaefer, Treasurer
(Principal Financial Officer)/s/ William T. PieperWilliam T. Pieper, Controller
(Principal Accounting Officer)


Date: August 13, 2003

31