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SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2003

OR

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

For the transition period from _______________ to ________________

Commission file number 333-89725

AES Eastern Energy, L.P.
(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code (703) 522-1315

N/A
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 required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the 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]

Registrant is a wholly owned subsidiary of The AES Corporation. Registrant meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is filing this Quarterly Report on Form 10-Q with the reduced disclosure format authorized by General Instruction H.

TABLE OF CONTENTS

PART I

Page

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PART I - FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

AES Eastern Energy, L.P.
Condensed Consolidated Statements of Income
For the three months ending June 30, 2003 and June 30, 2002
(Amounts in Thousands)

The notes are an integral part of the condensed consolidated financial statements.

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Item 1. Condensed Consolidated Financial Statements (Unaudited) (Cont’d)

AES Eastern Energy, L.P.
Condensed Consolidated Statements of Income
For the six months ending June 30, 2003 and June 30, 2002
(Amounts in Thousands)

The notes are an integral part of the condensed consolidated financial statements.

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Item 1. Condensed Consolidated Financial Statements (Unaudited) (Cont’d)

AES Eastern Energy, L.P.
Condensed Consolidated Balance Sheets
June 30, 2003 and December 31, 2002
(Amounts in thousands)

The notes are an integral part of the condensed consolidated financial statements.

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Item 1. Condensed Consolidated Financial Statements (Unaudited) (Cont’d)

AES Eastern Energy, L.P.
Condensed Consolidated Statements of Cash Flows
For the six months ending June 30, 2003 and June 30, 2002
(Amounts in Thousands)

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Item 1. Condensed Consolidated Financial Statements (Unaudited) (Cont’d)

AES Eastern Energy, L.P.
Consolidated Statement of Changes in Partners’ Capital
For the six months ended June 30, 2003
(Amounts in Thousands)

The notes are an integral part of the condensed consolidated financial statements.

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Item 1. Condensed Consolidated Financial Statements (Unaudited) (Cont’d)

Notes to the Unaudited Condensed Consolidated Financial Statements

Note 1. Unaudited Condensed Consolidated Financial Statements

The accompanying unaudited condensed consolidated financial statements of AES Eastern Energy, L.P. (the Partnership) reflect all adjustments which are necessary, in the opinion of management, for a fair presentation of the Partnership’s consolidated results for the interim periods. All such adjustments are of a normal recurring nature. The unaudited condensed consolidated financial statements should be read in conjunction with the Partnership’s consolidated financial statements and notes contained therein, as of December 31, 2002 and the year then ended, which are set forth in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2002.

Note 2. Commitments and Contingencies

Coal Purchases – In connection with the acquisition of the Partnership’s four coal–fired electric generating stations (the Plants), the Partnership assumed from New York State Electric & Gas Corporation (NYSEG) an agreement to purchase the coal required by the Somerset and Cayuga Plants. Each year either party can request renegotiation of the price of one-third of the coal supplied pursuant to this agreement. The supplier requested renegotiation during 2001 for the 2002 lot but the parties failed to reach agreement. The supplier requested renegotiation during 2002 for the 2003 lot plus the 2002 lot for which agreement was not reached. On September 11, 2002, the Partnership and the supplier reached agreement on both of the lots. Therefore, the commitment of the Partnership for 2003 is three lots for the Somerset Plant plus 70% of the anticipated coal usage for the Cayuga Plant. The termination date for the contract is December 31, 2003. The parties were required to meet no later than June 30, 2003, to determine whether the agreement would be extended under mutually agreeable terms and conditions. It has been determined that the agreement will not be extended. The Partnership can provide no assurances that it will be able to enter into other agreements on terms and conditions that are as favorable as the current contract.

As of the acquisition date of the Plants, the contract prices for the coal purchased through 2002 were above the market price, and the Partnership recorded a purchase accounting liability for approximately $15.7 million related to the fulfillment of its obligation to purchase coal under this agreement. The purchase accounting liability was amortized as a reduction to coal expense over the life of the underlying contracts. As of December 31, 2002, the underlying contracts were fully amortized.

Based on the coal purchase commitments for the year ended December 31, 2003, the Partnership has expected coal purchases ranging between $93.7 and $100.0 million. Currently, the Partnership has expected coal purchase commitments ranging between $70.1 and $77.5 million for 2004.

As of June 30, 2003, the remaining anticipated coal purchase commitments for the year ending December 31, 2003 were between $44.3 and $50.6 million.

Transmission Agreements — On August 3, 1998, AES NY, L.L.C., the general partner of the Partnership (the General Partner), entered into an agreement with NYSEG for the purpose of transferring certain rights and obligations from NYSEG to the General Partner under an existing transmission agreement among Niagara Mohawk Power Corporation (NIMO), the New York Power Authority, NYSEG and Rochester Gas & Electric Corporation, and an existing transmission agreement between NYSEG and NIMO. This agreement provides for the assignment of rights to transmit energy from the Somerset Plant and other sources to remote load areas and other delivery points, and was assumed by the Partnership on the date of acquisition of the Plants. In accordance with its plan, as of the acquisition date, the Partnership discontinued using this service. The Partnership did not transmit over these lines but was required to pay the monthly fees until the effective cancellation date, November 19, 1999. These fees aggregated approximately $3.4 million over the six months ended December 31, 1999, and were recorded as a purchase accounting liability. Because the Partnership did not use the lines during this period, the Partnership received no economic benefit subsequent to the acquisition.

The Partnership was informed by NIMO that the Partnership would be responsible for the monthly fees of $500,640 under the existing transmission agreement to the originally scheduled termination date of October 1, 2004. On October 5, 1999, the Partnership filed a complaint against NIMO alleging that the Partnership has a right to non-firm transmission service upon six months prior notice without payment of $500,640 in monthly fees subsequent to the cancellation date of November 19, 1999.

On March 9, 2000, a settlement was reached between the Partnership and NIMO, which was approved by the Federal Energy Regulatory Commission (FERC) on May 10, 2000. According to the settlement, the Partnership will continue to pay NIMO a fixed rate of $500,640 per month during the period of November 20, 1999 to October 1, 2004, and, in turn, will receive a form of transmission service commencing on May 1, 2000, which the Partnership believes will provide an economic benefit over the period of May 1, 2000 to October 1, 2004.

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The Partnership shall have the right under a Remote Load Wheeling Agreement (RLWA) to transmit 298 Megawatts (MW) over firm transmission lines from the Somerset Plant. The Partnership shall have the right to designate alternate points of delivery on NIMO’s transmission system provided that the Partnership shall not be entitled to receive any transmission service charge credit on the NIMO system.

The transmission congestion contract is accounted for as a derivative under SFAS No. 133. The transmission congestion contract was entered into because it provided a reasonable settlement for resolving a FERC issue. The agreement is essentially a swap between the congestion component of the locational prices posted daily by the New York Independent System Operator (NYISO) in western New York and the more heavily populated areas in eastern New York. The agreement is a financially settled contract since there is no requirement to flow power under this agreement. The agreement generates gains or losses from exposure to shifts or changes in market prices. The Partnership recorded a loss of approximately $6.4 million versus income of approximately $19.0 million in the first six months of 2003 and 2002, respectively, related to this contract.

On June 25, 2003, the Somerset plant filed a complaint against NIMO with the FERC. The complaint involves outstanding station service charges for the period April 2000 to May 2003. The Plant has calculated the outstanding charges owed to be $290,000, while NIMO has calculated the outstanding charges to be $3.4 million. The Partnership is awaiting the FERC decision and had accrued $1.2 million for these charges.

Line of Credit Agreement – On November 20, 2002, the Partnership signed an agreement with Union Bank of California, N.A. for a one-year extension of its current working capital and letter of credit facility. On April 16, 2003, the Partnership signed an amendment to its November 20, 2002 credit agreement with Union Bank of California, N.A. The amendment includes another one-year extension of the current facility; the maturity date of the working capital and letter of credit facility is now January 2, 2005. The amendment also increases Union Bank of California’s commitment from $15 million to $20 million. On April 25, 2003, the Partnership further amended its November 20, 2002 credit agreement with Union Bank of California, N.A. The amendment includes a commitment from Citibank, N.A. for the remaining $15 million of the facility. As of June 30, 2003, of the $35 million committed, the Partnership has obtained letters of credit of $12.5 million which have been provided as additional margin to ongoing hedging activities with a number of counterparties.

The AES Corporation on January 6, 2003 and February 25, 2003 authorized the Partnership to issue letters of credit to counterparties on its $350 million senior secured revolving credit facility to the amount of $25 million and $35 million for the years of 2003 and 2004, respectively. As of June 30, 2003, the Partnership has obtained letters of credit of $10 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

Environmental — The Partnership has recorded a liability for environmental remediation associated with the acquisition of the Plants. On an ongoing basis, the Partnership monitors its compliance with environmental laws. Because of the uncertainties associated with environmental compliance and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued.

The Partnership received an information request letter dated October 12, 1999 from the New York Attorney General, which sought detailed operating and maintenance history for the Westover and Greenidge Plants. On January 13, 2000, the Partnership received a subpoena from the New York State Department of Environmental Conservation (DEC) seeking similar operating and maintenance history from the Westover and Greenidge Plants. The Partnership has provided materials responding to the request from the Attorney General and the DEC. This information was sought in connection with the Attorney General’s and the DEC’s investigations of several electricity generating stations in New York that are suspected of undertaking modifications in the past without undergoing an air permitting review.

On April 14, 2000, the Partnership received a request for information pursuant to Section 114 of the Clean Air Act from the U.S. Environmental Protection Agency (EPA) seeking detailed operating and maintenance history data for the Cayuga and Somerset Plants. The EPA has commenced an industry-wide investigation of coal-fired electric power generators to determine compliance with environmental requirements under the Clean Air Act associated with repairs, maintenance, modifications and operational changes made to coal-fired facilities over the years. The EPA’s focus is on whether the changes were subject to new source review or new source performance standards, and whether best available control technology was or should have been used. The Partnership has provided the requested documentation.

By letter dated May 25, 2000, the DEC issued a Notice of Violation (NOV) to NYSEG for violations of the Clean Air Act and the Environmental Conservation Law at the Greenidge and Westover Plants related to NYSEG’s alleged failure to obtain an air permitting review for repairs and improvements made during the 1980s and 1990s, which was prior to the acquisition of the Plants by the Partnership. Pursuant to the purchase agreement relating to the acquisition of the Plants from NYSEG, the Partnership agreed to assume responsibility for environmental liabilities that arose while NYSEG owned the Plants. On September 12, 2000, the Partnership agreed with NYSEG that the Partnership will assume the defense of and responsibility for the NOV, subject to a reservation of its right to assert applicable exceptions to its contractual undertaking to assume preexisting environmental liabilities.

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The Partnership is currently in negotiation with both the EPA and DEC. If the parties are unable to reach an agreement, the EPA and DEC could issue a notice or notices of violations to the Partnership for violations of the Clean Air Act and New York Environmental Conservation Law. If the Attorney General, DEC or the EPA does file an enforcement action against the Somerset, Cayuga, Westover or Greenidge Plants, then penalties may be imposed and further emissions reductions might be necessary at these Plants which could require the Partnership to make substantial expenditures. The Partnership is unable to estimate the effect of such a NOV on its financial condition or results of future operations.

Nitrogen Oxide and Sulfur Dioxide Emission Allowances — The Plants emit nitrogen oxide (NOx) and sulfur dioxide (SO2) as a result of burning coal to produce electricity.

The Plants have been allocated allowances by the DEC to emit NOx during the ozone season, which runs from May 1 to September 30. Each NOx allowance authorizes the emission of one ton of NOx during the ozone season. New York State and the other states in the Mid-Atlantic and Northeast region are classified as the Ozone Transport Region in the federal Clean Air Act, which designates the Ozone Transport Region as not being in compliance with the ozone National Ambient Air Quality Standard. The states in the Ozone Transport Region have agreed to implement a three-phase process to reduce NOx emissions in the region in order to comply with the federal Clean Air Act Title I requirements for ozone non-compliance areas. Implementation of the Phase III emission rules commenced on May 1, 2003. The Phase III NOx regulations set forth a NOx allowance allocation program which gives the Partnership 2,516 NOx emission allowances for 2003.

The Plants are also subject to SO2 emission allowance requirements imposed by the EPA. Each SO2 allowance authorizes the emission of one ton of SO2 during the calendar year. All of the Plants are currently subject to SO2 allowance requirements, and are required to hold sufficient allowances to emit SO2.

Both NOx and SO2 allowances may be bought, sold or traded. If NOx and/or SO2 emissions exceed the allowance amounts allocated to the Plants, then the Partnership may need to purchase additional allowances on the open market or otherwise reduce its production of electricity to stay within the allocated amounts. It is expected that the Partnership may have a shortfall of approximately 8,000 to 9,000 SO2 allowances and approxiately 800 to 900 NOx allowances assuming the units are operated at forecasted capacities. At current market prices, the cost could range from $4.3 million to $5.8 million to purchase sufficent SO2 and NOx allowances for 2003.

In October 1999, New York State Governor Pataki announced an executive order mandating additional emission reductions from New York State power plants. The Governor’s initiative requires non-ozone season NOx emission reductions based on 0.15 lbs/Mmbtu starting in 2004, and a 50% reduction from the power plants’ Title IV SO2 emissions being phased in from 2005 to 2008. The program will be implemented through a market-based mechanism. The rules implementing the Governor’s initiative (NYCRR Parts 237 and 238) were adopted in March 2003. The impact of the rules on the Partnership cannot be determined until New York State makes its determination as to how many emission allowances will be allocated to each of the Plants. This is not scheduled to occur until September 2003 for NOx allocations and January 2004 for SO2 allocations.

The Partnership voluntarily disclosed to the DEC and EPA on November 27, 2002 that NOx exceedances appear to have occurred on October 30 and 31 and November 1-8 and 10 of 2002. The exceedances were discovered through an audit by plant personnel of the Plants’ NOx Reasonably Available Control Technology (RACT) tracking system. The Plants have taken all reasonable, good faith efforts to assess and correct the exceedances. Immediately upon the discovery of the calculation error, the Selective Catalytic Reduction System (SCR) at the Somerset Plant was activated to reduce NOx emissions. Emission data indicates that the system had already returned to a compliant operation by the time the error was discovered. The EPA has decided to defer to the DEC for review of the self-disclosure letter and technical issues. The Partnership is unable to predict any potential actions or fines the DEC may require, if any.

The Partnership voluntarily disclosed to the DEC in January 2003 that the Cayuga Plant had inadvertently burned synfuel (coal with a latex binder applied), which it is not permitted to burn. The Cayuga Plant had entered into an agreement with a supplier to purchase coal. The Cayuga Plant received approximately one 9,000-ton train per month from April 24, 2001 to December 27, 2002. In January 2003, the Plant became aware that the product it had been receiving was synfuel. The Plants have suspended all shipments from that supplier until a resolution is reached. The Cayuga Plant has reviewed the emission and operation data that showed there was no adverse effect to air quality attributable to burning the material. The Partnership is unable to predict any potential actions or fines the DEC may require, if any.

In April 2002, the EPA proposed to establish location, design, construction and capacity standards for cooling water intake structures at existing power plants. The EPA is developing these regulations under the terms of an Amended Consent Decree in Riverkeeper, Inc vs. Whitman, US District Court, Southern District of New York. It has been reported that the EPA reached an agreement in principle with the plaintiffs to propose changes to the 316(b) rulemaking schedule. The new scheduled finalization of the rules for existing facilities has been extended by six months to February 16, 2004. These new rules will impose new compliance requirements, with potentially significant costs, on operating plants across the nation. Cost items include various environmental and engineering studies, and potential capital and maintenance costs. The Partnership has not determined the effects of these regulations on its financial condition.

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Note 3. Price Risk Management

Comprehensive Income (Loss) – The Partnership accounts for its derivative instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. The Partnership utilizes derivative financial instruments to hedge commodity price risk. The Partnership utilizes electric derivative instruments, including swaps and forwards, to hedge the risk related to forecasted electricity sales over the next four years. The majority of the Partnership’s electric derivatives are designated and qualify as cash flow hedges. No significant amounts of hedge ineffectiveness were recognized in earnings during the six months ended June 30, 2003.

Gains and losses on derivatives reported in accumulated other comprehensive income are reclassified into earnings when the hedged forecasted sale occurs. Amounts recorded in other comprehensive income (loss) during the six months ended June 30, 2003, were as follows (in millions):

In addition to the electric derivatives classified as cash flow hedge contracts, the Partnership has a Transmission Congestion Contract that is a derivative under the definition of SFAS No. 133, but does not qualify for hedge accounting.  This contract is recorded at fair value on the balance sheet with changes in the fair value recognized through earnings. 

Note 4. New Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143, which became effective January 1, 2003, requires entities to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. When the new liability was recorded in 2003, the Partnership capitalized the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is being accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Partnership will settle the obligation for its recorded amount or incur a gain or loss upon settlement. The Partnership adopted SFAS No. 143 effective January 1, 2003.

The Partnership has completed a detailed assessment of the specific applicability and implications of SFAS No. 143. The scope of SFAS No. 143 includes primarily active ash landfills and water treatment basins. Upon adoption of SFAS No. 143, the Partnership recorded a liability of $9.2 million and a net asset of approximately $3.3 million, which are included in the electric generation assets, and reversed a $4.2 million environmental remediation liability it had previously recorded. The difference of the amounts previously recorded and the net SFAS No. 143 liability is a loss recorded as the cumulative effect of a change in accounting principle of $1.7 million. Reconciliation of asset retirement obligation liability for the six months ending June 30, 2003 was as follows (in millions):

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure”. SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Partnership expects to use the prospective method to transition to the fair value based method of accounting for stock-based employee compensation.  All employee awards granted, modified or settled after January 1, 2003, were recorded using the fair value based method of accounting. (See Note 5). The Partnership’s adoption of the prospective method of accounting for stock-based employee compensation did not have any material impact on its financial position or results of operations.

On April 30, 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by FASB and the Derivatives Implementation Group (DIG) in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and

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for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The Partnership is evaluating SFAS No. 149 and has not yet determined the impact of adopting its provisions.

The Partnership adopted the disclosure provisions of FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Direct Guarantees of Indebtedness of Others,” in the fourth quarter of 2002. The Partnership will apply the initial recognition and measurement provisions on a prospective basis for all guarantees issued after December 31, 2002. In general, the Partnership enters into various agreements providing financial performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees, letters of credit and surety bonds. FIN 45 does not encompass guarantees issued either between parents and their subsidiaries or between corporations under common control, a parent’s guarantee of its subsidiary’s debt to a third party (whether the parent is a corporation or an individual), a subsidiary’s guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent, nor guarantees of a company’s own future performance. Adoption of FIN 45 had no impact on the Partnership’s historical financial statements, as existing guarantees are not subject to the measurement provisions of FIN 45. The adoption of the liability recognition provisions of FIN 45 did not have a material impact on the Partnership’s financial position or results of operations.

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities”. This is an interpretation of Accounting Research Bulletin No. 51, “Consolidation of Variable Interest Entities”. FIN 46 requires certain variable interest entities (VIEs) to be consolidated by the primary beneficiary if the entity does not effectively disperse risks among the parties involved. The provisions of FIN 46 are effective immediately for those VIEs created after January 31, 2003. The provisions are effective for the first period beginning after June 15, 2003 for those variable interests held prior to February 1, 2003. The sales – leaseback transaction under which the Somerset and Cayuga Plants were acquired qualifies as a VIE. The sales – leaseback rules require that the leases be treated as financing leases for purposes of the Partnership’s financial statements, which they have been from the inception of the Partnership. The adoption of FIN 46 will not have a material impact on the Partnership’s financial position or results of operations.

Note 5. Long-term Incentive Program

Stock Option Plan – Employees of the Partnership participate in the AES Stock Option Plan (the SOP) that provides for grants of stock options to eligible participants. Prior to 2003, the Partnership accounted for the SOP under the recognition and measurement provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. No stock-based employee compensation cost is reflected in 2002 net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2003, the Partnership adopted the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation”, prospectively to all employee awards granted, modified or settled after January 1, 2003. Awards under the SOP vest over periods ranging from two to five years. Therefore, the cost related to stock-based employee compensation included in the determination of net income for 2003 is less than that which would have been recognized if the fair value based method had been applied to all awards from the inception of the Partnership. The expense recognized under the prospective method for the quarter ended June 30, 2003 is approximately $65,000.

Note 6. Reclassifications

Certain 2002 amounts have been reclassified on the condensed consolidated financial statements to conform with the 2003 presentation.

Note 7. Subsequent Events

Cash flow from the Partnership’s operations during the first half of 2003 was sufficient to cover the aggregate rental payments under the leases on the Somerset Plant and the Cayuga Plant due July 2, 2003. On this date, rental payments were made in the amount of $28.8 million.

Cash flow from operations in excess of the aggregate rental payments under the Partnership’s leases may be distributed to the Partners of the Partnership if certain criteria are met. On July 7, 2003, the Partnership made a distribution payment of $75.9 million.

The Partnership borrowed $9.7 million on July 9, 2003, for working capital purposes under the $35 million secured revolving working capital and letter of credit facility with Union Bank of California, N.A. The borrowing was at an interest rate of 5.5%. The Partnership repaid the entire $9.7 million on July 25, 2003.

On July 24, 2003, Governor Pataki announced that ten Northeastern U.S. states (including New York) have agreed to work to develop a regional market-based emissions trading system to reduce power plants’ CO2 emissions. The goal is to reach an agreement by April 2005 on a cap and trade program. Until such time as the rules are developed to implement such a program, the Partnership cannot determine what its impact would be on the Partnership’s financial position or results of operations.

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Item 1. Condensed Consolidated Financial Statements (Unaudited)

AES NY, L.L.C.
Condensed Consolidated Balance Sheets
June 30, 2003 and December 31, 2002
(Amounts in Thousands)

The notes are an integral part of the condensed consolidated financial statements.

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Item 1. Condensed Consolidated Financial Statements (Unaudited)

Note 1. Condensed Consolidated Balance Sheets

The consolidated balance sheets include the accounts of AES NY, L.L.C. (the Company), AES Eastern Energy, L.P. (AEE) and AES Creative Resources, L.P.(ACR) (including all subsidiaries). The balance sheets are presented on a consolidated basis because the Company, as general partner, controls the operations of AEE and ACR. The 99% limited partner ownerships of AEE and ACR are presented as minority interest.

The accompanying unaudited condensed consolidated balance sheets of the Company reflect all adjustments which are necessary, in the opinion of management, for a fair presentation of the Company’s consolidated financial position for the interim periods. All such adjustments are of a normal recurring nature. The unaudited condensed consolidated balance sheets should be read in conjunction with the Company’s consolidated balance sheet and notes contained therein, as of December 31, 2002, which are set forth in the Annual Report on Form 10-K of AEE for the year ended December 31, 2002.

Note 2. Plants Placed on Long-Term Cold Standby

During the fourth quarter of 2000, ACR placed its AES Hickling and AES Jennison plants (ACR Plants) on long-term cold standby. The long-term cold standby designation means that these plants require more than 14 days to be brought on-line. The Company continues to evaluate the future of these plants.

Note 3. Commitments and Contingencies

Coal Purchases – In connection with the acquisition by AEE of its four coal-fired electric generating stations (the AEE Plants), AEE assumed from New York State Electric & Gas Corporation (NYSEG) an agreement to purchase the coal required by the AEE Somerset and Cayuga plants. Each year either party can request renegotiation of the price of one-third of the coal supplied pursuant to this agreement. The supplier requested renegotiation during 2001 for the 2002 lot but the parties failed to reach agreement. The supplier requested renegotiation during 2002 for the 2003 lot plus the 2002 lot for which agreement was not reached. On September 11, 2002, AEE and the supplier reached agreement on both of the lots. Therefore, the commitment of AEE for 2003 is three lots for the Somerset Plant plus 70% of the anticipated coal usage for the Cayuga Plant. The termination date for the contract is December 31, 2003. The parties were required to meet no later than June 30, 2003, to determine whether the agreement would be extended under mutually agreeable terms and conditions. It has been determined that the agreement will not be extended. The Company can provide no assurances that AEE will be able to enter into other agreements on terms and conditions that are as favorable as the current contract.

As of the acquisition date of the AEE Plants, the contract prices for the coal purchased through 2002 were above the market price, and AEE recorded a purchase accounting liability for approximately $15.7 million related to the fulfillment of its obligation to purchase coal under this agreement. The purchase accounting liability was amortized as a reduction to coal expense over the life of the underlying contracts. As of December 31, 2002, the underlying contracts were fully amortized.

Based on the coal purchase commitments for the year ended December 31, 2003, AEE has expected coal purchases ranging between $93.7 and $100.0 million. Currently, AEE has expected coal purchase commitments ranging between $70.1 and $77.5 million for 2004.

As of June 30, 2003, the remaining anticipated coal purchase commitments for the year ending December 31, 2003 were between $44.3 and $50.6 million.

Transmission Agreements — On August 3, 1998, the Company entered into an agreement with NYSEG for the purpose of transferring certain rights and obligations from NYSEG to the Company under an existing transmission agreement among Niagara Mohawk Power Corporation (NIMO), the New York Power Authority, NYSEG and Rochester Gas & Electric Corporation, and an existing transmission agreement between NYSEG and NIMO. This agreement provides for the assignment of rights to transmit energy from the Somerset Plant and other sources to remote load areas and other delivery points, and was assumed by AEE on the date of acquisition of the AEE Plants. In accordance with its plan, as of the acquisition date, AEE discontinued using this service. AEE did not transmit over these lines but was required to pay the monthly fees until the effective cancellation date, November 19, 1999. These fees aggregated approximately $3.4 million over the six months ended December 31, 1999, and were recorded as a purchase accounting liability. Because AEE did not use the lines during this period, AEE received no economic benefit subsequent to the acquisition.

AEE was informed by NIMO that AEE would be responsible for the monthly fees of $500,640 under the existing transmission agreement to the originally scheduled termination date of October 1, 2004. On October 5, 1999, AEE filed a complaint against NIMO alleging that AEE has a right to non-firm transmission service upon six months prior notice without payment of $500,640 in monthly fees subsequent to the cancellation date of November 19, 1999.

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On March 9, 2000, a settlement was reached between AEE and NIMO, which was approved by the Federal Energy Regulatory Commission (FERC) on May 10, 2000. According to the settlement, AEE will continue to pay NIMO a fixed rate of $500,640 per month during the period of November 20, 1999 to October 1, 2004 and, in turn, will receive a form of transmission service commencing on May 1, 2000, which AEE believes will provide an economic benefit over the period of May 1, 2000 to October 1, 2004. AEE shall have the right under a Remote Load Wheeling Agreement (RLWA) to transmit 298 megawatts (MW) over firm transmission lines from the Somerset Plant. AEE shall have the right to designate alternate points of delivery on NIMO’s transmission system provided that AEE shall not be entitled to receive any transmission service charge credit on the NIMO system.

The transmission congestion contract is accounted for as a derivative under SFAS No.133. The transmission congestion contract was entered into because it provided a reasonable settlement for resolving a FERC issue. The agreement is essentially a swap between the congestion component of the locational prices posted daily by the New York Independent System Operator (NYISO) in western New York and the more heavily populated areas in eastern New York. The agreement is a financially settled contract since there is no requirement to flow power under this agreement. The agreement generates gains or losses from exposure to shifts or changes in market prices. AEE recorded a loss of approximately $6.4 million versus income of approximately $19 million in the first six months of 2003 and 2002, respectively, related to this contract.

On June 25, 2003, the Somerset Plant filed a complaint against NIMO with the FERC. The complaint involves outstanding station service charges for the period April 2000 to May 2003. The Plant has calculated the outstanding charges owed to be $290,000 while NIMO has calculated the outstanding charges to be $3.4 million. AEE is awaiting the FERC decision and had accrued $1.2 million for these charges.

Line of Credit Agreement – On November 20, 2002, AEE signed an agreement with Union Bank of California, N.A. for a one-year extension of its current working capital and letter of credit facility. On April 16, 2003, AEE amended its November 20, 2002 credit agreement with Union Bank of California, N.A. The amendment includes another one-year extension of the current facility; the maturity date of the working capital and letter of credit facility is now January 2, 2005. The amendment also increases Union Bank of California’s commitment from $15 million to $20 million. On April 25, 2003, AEE further amended its November 20, 2002 agreement with Union Bank of California, N.A. The amendment includes a commitment from Citibank, N.A. for the remaining $15 million of the facility. As of June 30, 2003, of the $35 million committed, AEE had obtained letters of credit of $12.5 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

The AES Corporation on January 6, 2003 and February 25, 2003 authorized AEE to issue letters of credit to counterparties on its $350 million senior secured revolving credit facility to the amount of $25 million and $35 million for the years of 2003 and 2004, respectively. As of June 30, 2003, AEE has obtained letters of credit in the amount of $10 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

Environmental — The Company has recorded a liability for environmental remediation associated with the acquisition of the AEE Plants and the ACR Plants. On an ongoing basis, the Company monitors its compliance with environmental laws. Because of the uncertainties associated with environmental compliance and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued.

AEE received an information request letter dated October 12, 1999 from the New York Attorney General, which sought detailed operating and maintenance history for the Westover and Greenidge Plants. On January 13, 2000, the Company received a subpoena from the New York State Department of Environmental Conservation (DEC) seeking similar operating and maintenance history from the AEE and ACR Plants. The Company has provided materials responding to the requests from the Attorney General and the DEC. This information was sought in connection with the Attorney General’s and the DEC’s investigations of several electricity generating stations in New York that are suspected of undertaking modifications in the past without undergoing an air permitting review.

On April 14, 2000, AEE received a request for information pursuant to Section 114 of the Clean Air Act from the U.S. Environmental Protection Agency (EPA) seeking detailed operating and maintenance history data for the Cayuga and Somerset Plants. The EPA has commenced an industry-wide investigation of coal-fired electric power generators to determine compliance with environmental requirements under the Clean Air Act associated with repairs, maintenance, modifications and operational changes made to coal-fired facilities over the years. The EPA’s focus is on whether the changes were subject to new source review or new source performance standards, and whether best available control technology was or should have been used. AEE has provided the requested documentation.

By letter dated May 25, 2000, the DEC issued a Notice of Violation (NOV) to NYSEG for violations of the Clean Air Act and the Environmental Conservation Law at the Greenidge and Westover Plants related to NYSEG’s alleged failure to obtain an air permitting review for repairs and improvements made during the 1980s and 1990s, which was prior to the acquisition of the AEE Plants. Pursuant to the purchase agreement relating to the acquisition of the Plants from NYSEG, AEE agreed to assume responsibility for environmental liabilities that arose while NYSEG owned

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the Plants. On September 12, 2000, AEE agreed with NYSEG that AEE will assume the defense of and responsibility for the NOV, subject to a reservation of its right to assert applicable exceptions to its contractual undertaking to assume preexisting environmental liabilities.

AEE is currently in negotiation with both the EPA and DEC. If the parties are unable to reach an agreement, the EPA and DEC could issue a notice or notices of violations to AEE for violations of the Clean Air Act and the New York Environmental Conservation Law. If the Attorney General, DEC or the EPA does file an enforcement action against the Somerset, Cayuga, Westover or Greenidge Plants, then penalties may be imposed and further emissions reductions might be necessary at these Plants which could require AEE to make substantial expenditures. AEE is unable to estimate the effect of such a NOV on its financial condition or results of future operations.

Nitrogen Oxide and Sulfur Dioxide Emission Allowances — The Plants emit nitrogen oxide (NOx) and sulfur dioxide (SO2) as a result of burning coal to produce electricity.

The AEE and ACR Plants have been allocated allowances by the DEC to emit NOx during the ozone season, which runs from May 1 to September 30. Each NOx allowance authorizes the emission of one ton of NOx during the ozone season. New York State and the other states in the Mid-Atlantic and Northeast region are classified as the Ozone Transport Region in the federal Clean Air Act, which designates the Ozone Transport Region as not being in compliance with the ozone National Ambient Air Quality Standard. The states in the Ozone Transport Region have agreed to implement a three-phase process to reduce NOx emissions in the region in order to comply with the federal Clean Air Act Title I requirements for ozone non-compliance areas. Implementation of the Phase III emission rules commenced on May 1, 2003. The Phase III NOx regulations set forth a NOx allowance allocation program which gives AEE 2,516 NOx emission allowances for 2003.

The AEE and ACR Plants are also subject to SO2 emission allowance requirements imposed by the EPA. Each SO2 allowance authorizes the emission of one ton of SO2 during the calendar year. All of the Plants are currently subject to SO2 allowance requirements, and are required to hold sufficient allowances to emit SO2.

Both NOx and SO2 allowances may be bought, sold or traded. If NOx and/or SO2 emissions exceed the allowance amounts allocated to the Plants, then AEE may need to purchase additional allowances on the open market or otherwise reduce its production of electricity to stay within the allocated amounts. It is expected that AEE may have a shortfall of approximately 8,000 to 9,000 SO2 allowances and approximately 800 to 900 NOx allowances assuming the units are operated at forecasted capacities. At current market prices, the cost could range from $4.3 million to $5.8 million to purchase sufficient SO2 and NOx allowances for 2003.

In October 1999, New York State Governor Pataki announced an executive order mandating additional emission reductions from New York State power plants. The Governor’s initiative requires non-ozone season NOx emission reductions based on 0.15 lbs/Mmbtu starting in 2004, and a 50% reduction from the power plants’ Title IV SO2 emissions being phased in from 2005 to 2008. The program will be implemented through a market-based mechanism. The rules implementing the Governor’s initiative (NYCRR Parts 237 and 238) were adopted in March 2003. The impact of the rules on AEE cannot be determined until New York State makes its determination as to how many emission allowances will be allocated to each of the Plants. This is not scheduled to occur until September 2003 for NOx allocations and January 2004 for SO2 allocations.

AEE voluntarily disclosed to the DEC and EPA on November 27, 2002 that NOx exceedances appear to have occurred on October 30 and 31 and November 1-8 and 10 of 2002. The exceedances were discovered through an audit by plant personnel of the Plants’ NOx Reasonably Available Control Technology (RACT) tracking system. The Plants have taken all reasonable, good faith efforts to assess and correct the exceedances. Immediately upon the discovery of the calculation error, the Selective Catalytic Reduction System (SCR) at the Somerset Plant was activated to reduce NOx emissions. Emission data indicates that the system had already returned to a compliant operation by the time the error was discovered. The EPA has decided to defer to the DEC for review of the self-disclosure letter and technical issues. AEE is unable to predict any potential actions or fines the DEC may require, if any.

AEE voluntarily disclosed to the DEC in January 2003 that the Cayuga Plant had inadvertently burned synfuel (coal with a latex binder applied), which it is not permitted to burn. The Cayuga Plant had entered into an agreement with a supplier to purchase coal. The Cayuga Plant received approximately one 9,000-ton train per month from April 24, 2001 to December 27, 2002. In January 2003, the Plant became aware that the product it had been receiving was synfuel. The Plants have suspended all shipments from that supplier until a resolution is reached. The Cayuga Plant has reviewed the emission and operation data that showed there was no adverse effect to air quality attributable to burning the material. The Company is unable to predict any potential actions or fines the DEC may require, if any.

In April 2002, the EPA proposed to establish location, design, construction and capacity standards for cooling water intake structures at existing power plants. The EPA is developing these regulations under the terms of an Amended Consent Decree in Riverkeeper, Inc vs. Whitman, US District Court, Southern District of New York. The new rules for existing facilities have been extended by six months to February 16, 2004. These new rules will impose new compliance requirements, with potentially significant costs, on operating plants across the nation. Cost items include various environmental and engineering studies, and potential capital and maintenance costs. AEE has not determined the effects of these regulations on its financial condition or results of operations.

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ACR has recently reported that concentrations of a number of chemicals in a few groundwater wells increased in the year ending December 31, 2001, since the Jennison and Hickling Plants were placed on long-term cold standby. A consultant has been retained to help evaluate the source of the chemicals and suggest potential solutions. ACR has notified the DEC and will meet with the agency to discuss what remediation, if any, will be taken. The Company cannot estimate if this will have a material effect on its financial position or results of operations.

Note 4. Price Risk Management

AEE accounts for its derivative instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. In the years prior to the adoption of SFAS No. 133, AEE did not have any items of other comprehensive income (loss).

AEE utilizes derivative financial instruments to hedge commodity price risk. AEE utilizes electric derivative instruments, including swaps and forwards, to hedge the risk related to forecasted electricity sales over the next four years. The majority of AEE’s electric derivatives are designated and qualify as cash flow hedges. No significant amounts of hedge ineffectiveness were recognized in earnings during the six months ended June 30, 2003.

Gains and losses on derivatives reported in accumulated other comprehensive income are reclassified into earnings when the hedged forecasted sale occurs. Amounts recorded in other comprehensive income (loss) during the six months ended June 30, 2003 were as follows (in millions):

In addition to the electric derivatives classified as cash flow hedge contracts, AEE has a Transmission Congestion Contract that is a derivative under the definition of SFAS No.133, but does not qualify for hedge accounting. This contract is recorded at fair value on the balance sheet with changes in the fair value recognized through earnings. 

Note 5. New Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143, which became effective January 1, 2003, requires entities to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. When the new liability was recorded in 2003, the Company capitalized the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is being accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company will settle the obligation for its recorded amount or incur a gain or loss upon settlement. The Company adopted SFAS No. 143 effective January 1, 2003.

The Company has completed a detailed assessment of the specific applicability and implications of SFAS No. 143. The scope of SFAS No. 143 includes primarily active ash landfills and water treatment basins. Upon adoption of SFAS No. 143, the Company recorded a liability of approximately $9.6 million and a net asset of approximately $3.3 million, which are included in electrical generation assets, and reversed a $4.2 million environmental remediation liability previously recorded. The difference of the amounts previously recorded and the net SFAS No. 143 liability is a loss recorded as the cumulative effect of a change in accounting principle of $2.2 million. Reconciliation of asset retirement obligation liability for the six months ending June 30, 2003 was as follows (in millions):

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure”.  SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. AEE expects to use the prospective method to transition to the fair value based method of accounting for stock-based employee compensation.  All employee awards granted, modified or settled after January 1, 2003, will be recorded using the fair value based method of accounting.  (See Note 6). AEE’s adoption of the prospective method of accounting for stock-based employee compensation did not have any material impact on its financial position or results of operations. 

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On April 30, 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by FASB and the Derivatives Implementation Group (DIG) in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The Company is evaluating SFAS No. 149 and has not yet determined the impact of adopting its provisions.

The Company adopted the disclosure provisions of FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Direct Guarantees of Indebtedness of Others,” in the fourth quarter of 2002. The Company will apply the initial recognition and measurement provisions on a prospective basis for all guarantees issued after December 31, 2002. In general, the Company enters into various agreements providing financial performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees, letters of credit and surety bonds. FIN 45 does not encompass guarantees issued either between parents and their subsidiaries or between corporations under common control, a parent’s guarantee of its subsidiary’s debt to a third party (whether the parent is a corporation or an individual), a subsidiary’s guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent, nor guarantees of a company’s own future performance. Adoption of FIN 45 had no impact on the Company’s historical financial statements as existing guarantees are not subject to the measurement provisions of FIN 45. The adoption of the liability recognition provisions of FIN 45 did not have a material impact on the Company’s financial position or results of operations.

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities”. This is an interpretation of Accounting Research Bulletin No. 51, “Consolidation of Variable Interest Entities”. FIN 46 requires certain variable interest entities (VIEs) to be consolidated by the primary beneficiary if the entity does not effectively disperse risks among the parties involved. The provisions of FIN 46 are effective immediately for those VIEs created after January 31, 2003. The provisions are effective for the first period beginning after June 15, 2003 for those variable interests held prior to February 1, 2003. The sales – leaseback transaction under which the Somerset and Cayuga Plants were acquired qualifies as a VIE. The sales – leaseback rules require that the leases be treated as financing leases for purposes of the Company’s financial statements, which they have been from the inception of the Company. Therefore the adoption of FIN 46 will not have a material impact on the Company’s financial position or results of operations.

Note 6. Long-term Incentive Program

Stock Option Plan – Employees of the Company participate in the AES Stock Option Plan (the SOP) that provides for grants of stock options to eligible participants. Prior to 2003, the Company accounted for the SOP under the recognition and measurement provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. No stock-based employee compensation cost is reflected in 2002 net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2003, the Company adopted the fair value recognition provisions of SFAS No. 123,“Accounting for Stock-Based Compensation,” prospectively to all employee awards granted, modified or settled after January 1, 2003. Awards under the SOP vest over periods ranging from two to five years. Therefore, the cost related to stock-based employee compensation included in the determination of net income for 2003 is less than that which would have been recognized if the fair value based method had been applied to all awards from the inception of the Company. The expense recognized under the prospective method for the six months ended June 30, 2003 is $65,000.

Note 7. Subsequent Events

Cash flow from AEE’s operations during the first half of 2003 was sufficient to cover the aggregate rental payments under the leases on the Somerset Plant and the Cayuga Plant due July 2, 2003. On this date, rental payments were made in the amount of $28.8 million.

Cash flow from operations in excess of the aggregate rental payments under AEE’s leases may be distributed to the partners of AEE if certain criteria are met. On July 7, 2003, AEE made a distribution payment of $75.9 million.

AEE borrowed $9.7 million on July 9, 2003, for working capital purposes under the $35 million secured revolving working capital and letter of credit facility with Union Bank of California, N.A. The borrowing was at an interest rate of 5.5%. AEE repaid the entire $9.7 million on July 25, 2003.

On July 24, 2003, Governor Pataki announced that ten Northeastern U.S. states (including New York) have agreed to work to develop a regional market-based emissions trading system to reduce power plants’ CO2 emissions. The goal is to reach an agreement by April 2005 on a cap and trade program. Until such time as the rules are developed to implement such a program, the Company cannot determine what its impact would be on the Company’s financial position or results of operations.

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

The information in this Management’s Discussion and Analysis should be read in conjunction with the accompanying condensed consolidated financial statements and the related Notes to the Financial Statements. Forward looking statements in this Management’s Discussion and Analysis are qualified by the cautionary statement in the Forward Looking Statements section of the Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Critical Accounting Policies

     General

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America. As such, we are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. The significant accounting policies which we believe are most critical to understanding and evaluating our reported financial results include the following: Revenue Recognition; Property, Plant and Equipment; Contingencies; and Derivatives.

Revenue Recognition

Revenues from the sale of electricity are recorded based upon output delivered and rates specified under contract terms. Revenues generated from the hedging of future sales using commodity forwards, swaps and options are recorded based on settlement accounting with the net amount received recognized as revenue. Revenues generated from the hedging of future sales using physically delivered forwards are recorded at the gross sales amount. Revenues for ancillary and other services are recorded when the services are rendered. The Transmission Congestion Contract is not deemed to be a hedge based on the definitions in SFAS No. 133. Therefore, this contract is marked to market at the end of every period. The mark-to-market value is computed based on a regression of historical eastern and western locational prices. This regression is used with forecasted eastern and western locational prices to calculate the forward congestion for the remainder of the contract term. This accounting treatment contributes to the income statement volatility of this contract.

Property, Plant and Equipment

Electric generation assets that existed at the date of acquisition were recorded at fair market value. Somerset and Cayuga, which represent $650 million of the electric generation assets, are subject to a leasing arrangement accounted for as a financing lease. Additions or improvements thereafter are recorded at cost. Depreciation is computed using the straight-line method over the 34-year and 28.5-year lease terms for Somerset and Cayuga, respectively, and over the estimated useful lives for the other fixed assets, which range from 7 to 35 years. Maintenance and repairs are charged to expense as incurred.

Contingencies

We accrue for loss contingencies when the amount of the loss is probable and estimable. We are subject to various environmental regulations, and we are involved in certain legal proceedings. If our actual environmental and/or legal obligations are materially different from our estimates, the recognition of the actual amounts may have a material impact on our operating results and financial condition.

Derivatives

On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” which, as amended, established new accounting and reporting standards for derivative instruments and hedging activities. SFAS No. 133 requires that all derivatives (including derivatives embedded in other contracts) be recorded as either assets or liabilities at fair value on the balance sheet. Changes in the derivative’s fair value are to be recognized in earnings in the period of change, unless hedge accounting criteria are met. Hedge accounting allows the derivative’s gains or losses in fair value to offset the related results of the hedged item. We utilize derivative financial instruments to manage commodity price risk. Although the majority of our derivative instruments qualify for hedge accounting, the adoption of SFAS No. 133 results in more variation to our results of operations from changes in commodity prices. We have chosen to use the hypothetical derivative methodology for testing whether our hedges meet the criteria to qualify for hedge accounting treatment. A historical regression is performed between the Plants’ delivery points into the New York Independent System Operator (NYISO) market and the NYISO zones in which the hedges are settled. Comparing the results of the historical regression and the actual changes in the market value of the hedges determines if the hedges qualify for hedge accounting treatment. For the six months ended June 30, 2003 and June 30, 2002, we recognized $6.4 million of loss and $19 million of income, respectively, pursuant to SFAS No. 133 related to derivatives which did not qualify for hedge accounting.

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Results of Operations for the Three Months ended June 30, 2003

Results of Operations

(Amounts in Millions)

Energy revenues for the three months ended June 30, 2003 were $92.1 million, compared to $66.1 million for the comparable period of the prior calendar year, an increase of 39.3%. The increase in energy revenues is primarily due to higher market prices and demand. Market prices for peak and off-peak electricity were approximately 57.6% and 50.4% higher than the comparable period of the prior calendar year. Demand for peak and off-peak electricity was flat and 1.0% higher than the comparable period of the prior calendar year. The market price and demand numbers were based on statistics obtained from the NYISO.

Capacity revenues for the three months ended June 30, 2003 were $7.8 million, compared to $9.7 million for the comparable period of the prior calendar year, a decrease of 19.6%. The decrease in capacity revenue is primarily due to a lower price for capacity sales on the open market for the summer capacity period (April — October) versus the comparable period of the prior calendar year.

Transmission congestion contract loss for the three months ended June 30, 2003 was $2.6 million compared to income of $12.6 million for the comparable period of the prior calendar year. This agreement is essentially a swap between the congestion component of the locational prices posted by the NYISO in western New York and the more populated areas in eastern New York. The transmission contract was entered into because it provided a reasonable settlement for resolving a FERC dispute between the Partnership and Niagara Mohawk Power Corporation.

Operating Expenses

Fuel expense for the three months ended June 30, 2003 was $34.2 million, compared to $29.7 million for the comparable period of the prior calendar year, an increase of 15.2%. The increase in fuel expense is primarily due to higher operating levels, higher NOx allowance, ammonia and limestone pricing.

Operations and maintenance expense for the three months ended June 30, 2003 was $4.9 million, compared to $5.2 million for the comparable period of the prior calendar year, a decrease of 5.8%. The primary reason for the decrease is the timing of the Somerset boiler outage which occurred in the first quarter of 2003 versus the second quarter of 2002.

General and administrative expense for the three months ended June 30, 2003 was $13.8 million, compared to $14.1 million for the comparable period of the prior calendar year, a decrease of 2.1%. The primary reason for the decrease is the timing of the Somerset boiler outage which occurred in the first quarter of 2003 versus the second quarter of 2002.

Depreciation and amortization expense for the three months ended June 30, 2003 was $9.0 million, compared to $8.7 million for the comparable period of the prior calendar year, an increase of 3.4%. The primary reason for the increase is the depreciation of the additional assets recorded under SFAS No. 143, as well as the capital expenditures of the prior year.

Other Expenses

Other Income/Expenses for the three months ended June 30, 2003 were net expenses of $14.3 million, compared to net expenses of $13.8 million for the comparable period of the prior calendar year, an increase of 3.6%.

Results of Operations for the Six Months ended June 30, 2003

Results of Operations

(Amounts in Millions)

Energy revenues for the six months ended June 30, 2003 were $194.4 million, compared to $135.1 million for the comparable period of the prior calendar year, an increase of 43.9%. The increase in energy revenues is primarily due to higher market prices and demand. Market prices for peak and off-peak electricity were 104.1% and 100.1% higher than the comparable period of the prior calendar year. Demand for peak and off-peak electricity was 2.2% and 3.7% higher than the comparable period of the prior calendar year. The market price and demand numbers were based on statistics obtained from the NYISO.

Capacity revenues for the six months ended June 30, 2003 were $16.4 million, compared to $15.1 million for the comparable period of the prior calendar year, an increase of 8.6%. The increase in capacity revenue is primarily due to a higher price for capacity sales on the open market for the winter capacity period (November – May) offset by a lower price for capacity sales on the open market for the summer capacity period (April — October) versus the comparable periods of the prior calendar year.

Transmission congestion contract loss for the six months ended June 30, 2003 was $6.4 million compared to income of $19 million for the comparable period of the prior calendar year. This agreement is essentially a swap between the congestion component of the locational prices posted by the NYISO in western New York and the more populated areas in eastern New York. The transmission contract was entered into because it provided a reasonable settlement for resolving a FERC dispute between the Partnership and Niagara Mohawk Power Corporation.

Operating Expenses

Fuel expense for the six months ended June 30, 2003 was $70.9 million, compared to $64.6 million for the comparable period of the prior calendar year, an increase of 9.8%. The increase in fuel expense is primarily due to higher operating levels and higher NOx allowance, ammonia and limestone pricing.

Operations and maintenance expense for the six months ended June 30, 2003 was $9.8 million, compared to $8.3 million for the comparable period of the prior calendar year, an increase of 18.1%. This increase is primarily due to maintenance expenses incurred during scheduled outages at the Somerset, Cayuga, Greenidge and Westover Plants.

General and administrative expense for the six months ended June 30, 2003 was $27.9 million, compared to $26.2 million for the comparable period of the prior calendar year, an increase of 6.5%. This increase is primarily due to increases in property taxes and property and medical insurance. In addition, in the comparable period of the prior calendar year, general and administrative expenses were partially offset by a reversal of accruals for potential environmental liabilities that were resolved at a lower cost than estimated.

Depreciation and amortization expense for the six months ended June 30, 2003 was $18.0 million, compared to $17.4 million for the comparable period of the prior calendar year, an increase of 3.4%. The primary reason for the increase is the depreciation of the additional assets recorded under SFAS No. 143, as well as the capital expenditures of the prior year.

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Other Expenses

Other Income/Expenses for the six months ended June 30, 2003 were net expenses of $28.2 million, compared to net expenses of $27.7 million for the comparable period of the prior calendar year, an increase of 1.4%.

Liquidity and Capital Resources

Operating Activities

Net cash provided by operating activities of $72.7 million for the six months ended June 30, 2003, reflects the increase in net income due to increased energy prices offset in part by an increase in working capital. The working capital increase is primarily due to increases in accounts receivable and inventory.

Investing Activities

Net cash used in investing activities of $32.4 million for the six months ended June 30, 2003 reflects an increase in our restricted cash accounts of $31.2 million and approximately $1.2 million in capital expenditures. The capital expenditures include the Westover Over-fire Air Project, which was completed in May 2003. Net cash used in investing activities for the six months ended June 30, 2002 was $3.4 million, reflecting a decrease in our restricted cash accounts of $8.5 million offset by capital expenditures of $5.1 million. We make capital expenditures according to the maintenance program for our Plants. In addition to capital requirements associated with the ownership and operation of our Plants, we will have significant fixed charge obligations in the future, principally with respect to the leases.

Compliance with environmental standards will continue to be reflected in our capital expenditures. Based on the current status of regulatory requirements, we do not anticipate that any capital expenditures associated with our compliance with current laws and regulations will have a material effect on our results of operations or our financial condition, other than the expenditures for the SCRs at Somerset and Cayuga, including the construction of new landfill space to manage ash from Somerset’s SCR system operations and expenditures for possible installation of a SCR system on Cayuga Unit 2, the U.S. Department of Energy Power Plant Improvement project on Greenidge Unit 4.

Financing Activities

Net cash used for financing activities for the six months ended June 30, 2003 of $40.3 million reflects principal payments on our leases of $1.3 million, payment of a distribution to our partners of $38.7 million and payments for deferred financing of $335,000 offset by a Partner’s contribution of $65,000. Net cash used in financing activities for the six months ended June 30, 2002 of $33.7 million reflects principal payments on our leases of $2.6 million, payment of a distribution to our partners of $32.6 million offset by a Partner’s contribution of $1.5 million. Cash flow from operations in excess of the aggregate rental payments under our leases is permitted, if certain criteria are met, to be paid in the form of distribution payments to our partners.

We are obligated to make payments under the Coal Hauling Agreement with Somerset Railroad Corporation (SRC), an affiliated company, in an amount sufficient, when added with funds available from other sources, to enable SRC to pay, when due, all of its operating expenses and other expenses, including interest on and principal of outstanding indebtedness. As of June 30, 2003, we had recorded $1.9 million as operating expenses and other accrued liabilities under this agreement. On August 14, 2000, SRC entered into a $26 million credit facility with Fortis Capital Corp. which replaced in its entirety a credit facility for the same amount previously provided to SRC by an affiliate of CIBC World Markets. The new credit facility provided by Fortis Capital Corp. consists of a 14-year term note (maturing on May 6, 2014), with principal and interest payments due quarterly. The current interest rate on the loans under this credit facility is equal to a Base Rate plus 0.750% for the Base Rate loans and LIBOR plus 1.500% for LIBOR loans. The Base Rate was 1.50% on June 30, 2003 and LIBOR was 1.10% on that date. The principal amount of SRC’s outstanding indebtedness under this credit facility was approximately $20.4 million as of June 30, 2003.

On November 20, 2002, we signed an agreement with Union Bank of California, N.A. for a one-year extension of our current working capital and letter of credit facility. Under this agreement, we borrowed $9.7 million on January 10, 2003 at an interest rate of 5.75%. The $9.7 million was repaid in full on January 28, 2003.

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On April 16, 2003, we amended our November 20, 2002 credit agreement with Union Bank of California, N.A. The amendment includes another one-year extension of our current facility; the maturity date of our working capital and letter of credit facility is January 2, 2005. The amendment also increases Union Bank of California’s commitment from $15 million to $20 million.

On April 25, 2003, we further amended our November 20, 2002 credit agreement with Union Bank of California, N.A. The amendment includes a commitment from Citibank, N.A. for the remaining $15 million of our facility. As of July 16, 2003, of the $35 million committed, we had obtained letters of credit of $12.5 million, which have been provided as additional margin to support normal ongoing hedging activities with a number of counterparties.

The AES Corporation on January 6, 2003 and February 25, 2003 authorized us to issue letters of credit to counterparties on its $350 million senior secured revolving credit facility to the amount of $25 million and $35 million, respectively. As of July 16, 2003, we have obtained letters of credit in the amount of $10 million, which have been provided as additional margin to support normal ongoing hedging activities with a number of counterparties.

Credit Rating Discussion

Credit ratings affect our ability to execute our commercial strategies in a cost-effective manner. In determining our credit rating, the rating agencies consider a number of factors. Quantitative factors that appear to have significant weight include, among other things, earnings before interest, taxes and depreciation and amortization (EBITDA); operating cash flow; total debt outstanding; fixed charges such as interest expense and lease payments; liquidity needs and availability and various ratios calculated from these factors. Qualitative factors appear to include, among other things, predictability of cash flows, business strategy, industry position and contingencies. In addition, Standard and Poor’s links our credit rating to the credit rating of The AES Corporation in accordance with their standard policy of linking the credit rating of a wholly owned subsidiary to that of its parent. Our Standards and Poor’s credit rating is currently three notches higher than the credit rating of The AES Corporation.

Trigger Events

Our commercial agreements typically include adequate assurance provisions relating to trade credit and some agreements have credit rating triggers. These trigger events typically would give counterparties the right to request additional collateral if our credit ratings were downgraded. Under such circumstances, we would need to post collateral within three days or the counterparties would have the right to suspend or terminate credit. The cost of posting collateral would have a negative effect on our profitability. If such collateral were not posted, our ability to continue transacting business as before the downgrade would be impaired. On October 8, 2002, one of our counterparties made a $1 million margin call on us because of Standard and Poor’s downgrade of our credit rating from BBB- to BB+. We provided a letter of credit for approximately $1 million.

New Accounting Pronouncements

Asset Retirement Obligations. In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143, which became effective January 1, 2003, requires entities to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. When the new liability was recorded in 2003, we capitalized the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is being accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we will settle the obligation for its recorded amount or incur a gain or loss upon settlement. We adopted SFAS No. 143 effective January 1, 2003.

We have completed a detailed assessment of the specific applicability and implications of SFAS No. 143. The scope of SFAS No. 143 includes primarily active ash landfills and water treatment basins. Upon adoption of SFAS No. 143, we recorded a liability of approximately $9.2 million and a net asset of approximately $3.4 million, which are included in electric generation assets, and reversed a $4.2 million environmental remediation liability we had previously recorded. The difference of the amounts previously recorded and the net SFAS No. 143 liability is a loss recorded as the cumulative effect of a change in accounting principle of $1.7 million. Reconciliation of our asset retirement obligation liability, for the three months ending June 30, 2003 was as follows (in millions):

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In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure”.  SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results.  We expect to use the prospective method to transition to the fair value based method of accounting for stock-based employee compensation.  All employee awards granted, modified or settled after January 1, 2003 will be recorded using the fair value based method of accounting.  The expanded disclosures required by SFAS No. 148 are included in our quarterly financial reports beginning in the first quarter of 2003. Our adoption of the prospective method of accounting for stock-based employee compensation did not have any material impact on our financial position or results of operations.

On April 30, 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by FASB and the Derivatives Implementation Group (DIG) in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. We are evaluating SFAS No. 149 and have not yet determined the impact of adopting its provisions.

We adopted the disclosure provisions of FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Direct Guarantees of Indebtedness of Others,” in the fourth quarter of 2002. We will apply the initial recognition and measurement provisions on a prospective basis for all guarantees issued after December 31, 2002. In general, we enter into various agreements providing financial performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees, letters of credit and surety bonds. FIN 45 does not encompass guarantees issued either between parents and their subsidiaries or between corporations under common control, a parent’s guarantee of its subsidiary’s debt to a third party (whether the parent is a corporation or an individual), a subsidiary’s guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent, nor does it apply to guarantees of a company’s own future performance. Adoption of FIN 45 had no impact on our historical financial statements, as existing guarantees are not subject to the measurement provisions of FIN 45. The adoption of the liability recognition provisions of FIN 45 did not have a material impact on our financial position or results of operations.

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities”. This is an interpretation of Accounting Research Bulletin No. 51, “Consolidation of Variable Interest Entities.” FIN 46 requires certain variable interest entities (VIEs) to be consolidated by the primary beneficiary if the entity does not effectively disperse risks among the parties involved. The provisions of FIN 46 are effective immediately for those VIEs created after January 31, 2003. The provisions are effective for the first period beginning after June 15, 2003 for those VIES held prior to February 1, 2003. The sales – leaseback transaction under which Somerset and Cayuga were acquired qualifies as a VIE. The sales – leaseback rules require that the leases be treated as financing leases for our financial statements, which they have been from our inception. Therefore the adoption of FIN 46 will not have a material impact on our financial position or results of operations.

Forward-looking Statements

Certain statements contained in this Form 10-Q are forward-looking statements as that term is defined in the Private Securities Litigation Reform Act of 1995. These forward-looking statements speak only as of the date hereof. Forward-looking statements can be identified by the use of forward-looking terminology such as “believe,” “expects,” “may,” “intends,” “will,” “should” or “anticipates” or the negative forms or other variations of these terms or comparable terminology, or by discussions of strategy. Future results covered by the forward-looking statements may not be achieved. Forward-looking statements are subject to risks, uncertainties and other factors, which could cause actual results to differ materially from future results expressed or implied by such forward-looking statements. The most significant risks, uncertainties and other factors are discussed under the heading “Business (a)General Development of Business” in our Annual Report on Form 10-K, and you are urged to read this section and carefully consider such factors.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. The principal executive officer and principal financial officer of our General Partner, based on the evaluation of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) or 15d-15(e)) as required by paragraph (b) of Exchange Act Rules 13a-15 or 15d-15, have concluded that as of June 30, 2003, our disclosure controls and procedures were effective and designed to ensure that material information relating to us and our consolidated subsidiaries, when applicable, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared.

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Changes in Internal Control over Financial Reporting. There have been no significant changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

          See Note 2 to our Condensed Consolidated Financial Statements in Part I.

Item 6. Exhibits and Reports on Form 8-K

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.

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