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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

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.

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

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

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PART 1 — FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

AES Eastern Energy, L.P.
Condensed Consolidated Statements of Income
For the three months ending March 31, 2003 and March 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 Balance Sheets
March 31, 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 three months ending March 31, 2003 and March 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.
Consolidated Statement of Changes in Partners’ Capital
For the three months ended March 31, 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. No later than June 30, 2003, the parties shall meet to determine if the agreement is to be extended under mutually agreeable terms and conditions. If the agreement is not extended, the Partnership would seek a new coal supplier. The partnership can provide no assurances that it will be able to enter into an agreement 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, 2003, 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 $70.0 and $100.0 million. Currently, the Partnership does not have any coal purchase commitments for 2004.

As of March 31, 2003, the remaining anticipated coal purchases for the year ending December 31, 2003 were between $45.0 and $75.0 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 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.

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.

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The transmission contract is accounted for as a derivative under SFAS No. 133. The transmission 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 ISO (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 $3.9 million versus income of approximately $6.3 million in the first three months of 2003 and 2002, respectively, related to this contract.

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 facility. As of March 31, 2003, lenders have committed to provide only $15 million of the $35 million secured revolving working capital and letter of credit facility. The Partnership is attempting to obtain commitments for the remaining $20 million. Its financial flexibility may be limited if the Partnership is unable to obtain these commitments or substitute other sources of credit. Under this agreement, the Partnership 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. (Please refer to Note 7 for an update on the commitments to the working capital and letter of credit facility.) As of March 31, 2003, of the $15 million committed, the Partnership had obtained letters of credit of $7.5 million which have been provided as additional margin to 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 for the years of 2003 and 2004, respectively. As of March 31, 2003, the Partnership has letters of credit in the amount of $14 million 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 New York State Department of Environmental Conservation (DEC) seeking similar operating and maintenance history from the 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.

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 (NOV) 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.

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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 commences 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 7,000 to 8,000 SO2 allowances and approximately 700 to 900 NOx allowances in 2003 assuming the units are operated at forecasted capacities. At current market prices, the cost could range from $1.1 million to $1.3 million and from $4.9 million to $6.3 million to purchase sufficient SO2 and NOx allowances for 2003, respectively.

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 the 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 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 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 NYDEC 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 NYSDEC 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 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.

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”. In the years prior to the adoption of SFAS No. 133, the Partnership did not have any items of other comprehensive income (loss). The Partnership utilizes derivative financial instruments to hedge commodity price risk. The Partnership utilizes electric derivative instruments, including swaps

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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 three months ended March 31, 2003.

Gains and losses on derivatives reported in accumulated other comprehensive income are reclassified into earnings when the hedged forecasted sale occurs. Approximately, $27.5 million of other comprehensive income is expected to be recognized as an addition to earnings over the next twelve months. Amounts recorded in other comprehensive income (loss) during the three months ended March 31, 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 is 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 a new liability is recorded in 2003, the entity will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is 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 entity settles the obligation for its recorded amount or incurs 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, 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 three months ending March 31, 2003 were 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, this Statement 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.  The expanded disclosures required by SFAS No. 148 are included in the Partnership’s quarterly financial reports in the first quarter of 2003 (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.

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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) process 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 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 its 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 VIEs. The sales – leaseback rules required 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. Therefore the adoption of this Interpretation 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 March 31, 2003 is approximately $18,000.

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

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 signed an amendment to 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 May 12, 2003, of the $35 million committed, the Partnership has obtained letters of credit of $10.5 million which have been provided as additional margin to counterparties.

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

AES NY, L.L.C.
Condensed Consolidated Balance Sheets
March 31, 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)

Note 1. Condensed Consolidated Balance Sheets

The consolidated balance sheets include the accounts of the Company, AEE and 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 AES NY, L.L.C. (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 AES Eastern Energy, L.P. (AEE) for the year ended December 31, 2002.

Note 2. Plants Placed on Long-Term Cold Standby

During the fourth quarter of 2000, AES Creative Resources, L.P. (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 is currently evaluating 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. No later than June 30, 2003, the parties shall meet to determine if the agreement is to be extended under mutually agreeable terms and conditions. If the agreement is not extended, AEE would seek a new coal supplier. The Company can provide no assurances that AEE will be able to enter into an agreement on terms and conditions that are as favorable as the current contract.

As of the acquisition date of the Plants by AEE, 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 $70.0 and $100.0 million. Currently, AEE does not have any coal purchase commitments for 2004.

As of March 31, 2003, the remaining anticipated coal purchases for the year ending December 31, 2003 were between $45.0 and $75.0 million.

Transmission Agreements – On August 3, 1998, the Company entered into an agreement 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 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. 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.

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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 contract is accounted for as a derivative under SFAS No.133. The transmission 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 ISO (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 $3.9 million versus income of approximately $6.3 million in the first three months of 2003 and 2002, respectively, related to this contract.

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 facility. As of March 31, 2003, lenders had committed to provide only $15 million of the $35 million secured revolving working capital and letter of credit facility. AEE is attempting to obtain commitments for the remaining $20 million. Its financial flexibility may be limited if AEE is unable to obtain these commitments or substitute other sources of credit. Under this agreement, AEE 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. (Please refer to Note 7 for an update on the commitments to the working capital and letter of credit facility) As of March 31, 2003, of the $15 million committed, AEE had obtained letters of credit of $7.5 million which have been provided as additional margin to 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 for the years of 2003 and 2004, respectively. As of March 31, 2003, AEE has letters of credit in the amount of $14 million 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 Plants by AEE. 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 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.

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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 (NOV) 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 commences 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 7,000 to 8,000 SO2 allowances and approximately 700 to 900 NOx allowances in 2003 assuming the units are operated at forecasted capacities. At current market prices, the cost could range from $1.1 million to $1.4 million and $4.9 million to $6.3 million to purchase sufficient SO2 and NOx allowances for 2003, respectively.

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 the 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 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 SCR at the Somerset Plant was activated to reduce NOx emissions. Emission data indicates that the system had already returned to a complaint 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 NYDEC 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. AEE is unable to predict any potential actions or fines the NYSDEC 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 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. AEE has not determined the effects of these regulations on its financial condition.

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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. ACR has notified the NYSDEC and anticipates determining what remediation is needed if any. 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 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 three months ended March 31, 2003.

Gains and losses on derivatives reported in accumulated other comprehensive income are reclassified into earnings when the hedged forecasted sale occurs. Approximately, $27.6 million of other comprehensive income is expected to be recognized as an addition to earnings over the next twelve months. Amounts recorded in other comprehensive income (loss) during the three months ended March 31, 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 Pronoucements

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143, which is 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 a new liability is recorded beginning in 2003, the entity will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is 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, an entity settles the obligation for its recorded amount or incurs 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 will record a liability of approximately $9.7 million, a net asset of approximately $3.4 million, 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 three months ending March 31, 2003 were 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, this Statement 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.  The expanded disclosures required by SFAS No. 148 are included in AEE’s quarterly financial reports beginning in the first

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quarter of 2003 (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. 

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) process 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.

AEE 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. AEE will apply the initial recognition and measurement provisions on a prospective basis for all guarantees issued after December 31, 2002. In general, AEE 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 AEE’s historical financial statements as existing guarantees are not subject to the measurement provisions of FIN 45. AEE does not expect adoption of the liability recognition provisions of FIN 45 to have a material impact on its 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 required that the leases be treated as financing leases for purposes of the Company’s financial statements, which they have been from the inception of AEE. Therefore the adoption of this Interpretation 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 quarter ended March 31, 2003 is $18,000.

Note 7. Subsequent Events

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 May 12, 2003, of the $35 million committed, AEE had obtained letters of credit of $10.5 million which have been provided as additional margin to counterparties.

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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 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 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. A significant overabundance of supply and a sustained, significant decline in market prices to below our variable cost could cause a decrease in the estimated useful lives of our electric generation assets. If the useful life of any of our property, plant and equipment is changed, the new life would be based on engineering studies and expected usage. The estimated average remaining useful life of our property, plant and equipment is approximately 23 years. If the estimated average remaining life were to decrease five years, annual depreciation would increase by $7.7 million. 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 will result 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 ISO (NYISO) 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 three months ended March 31, 2003 and 2002, we recognized $3.9 million of loss and $6.3 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 March 31, 2003

Results of Operations

Energy Revenues for the three months ended March 31, 2003 were $102.3 million, compared to $69.1 million for the comparable period of the prior calendar year, an increase of 48.0%. The increase in energy revenues is primarily due to higher market prices and demand. Market prices for peak and off-peak electricity were 156.1% and 150.2% higher than the comparable period of the prior calendar year. Demand for peak and offpeak electricity was 4.4% and 6.1% 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 March 31, 2003 were $8.6 million, compared to $5.5 million for the comparable period of the prior calendar year, an increase of 56.4%. The increase in capacity revenue is primarily due to a slightly higher price for capacity sales on the open market for the winter capacity period (November – May) versus the comparable period of the prior calendar year.

Transmission Congestion Contract loss for the three months ended March 31, 2003 was $3.9 million compared to income of $6.3 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.

Fuel Expense for the three months ended March 31, 2003 was $36.7 million, compared to $34.5 million for the comparable period of the prior calendar year, an increase of 6.4%. The increase in Fuel Expense is primarily due to higher operating levels.

Operations and maintenance expense for the three months ended March 31, 2003 was $4.9 million, compared to $3.1 million for the comparable period of the prior calendar year, an increase of 58.1%. This increase is primarily due to maintenance expenses incurred during scheduled outages at the Somerset, Cayuga and Greenidge Plants.

General and administrative expense for the three months ended March 31, 2003 was $14.1 million, compared to $12.5 million for the comparable period of the prior calendar year, an increase of 12.8%. 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 three months ended March 31, 2003 was $9.0 million, compared to $8.7 million for the comparable period of the prior calendar year, an increase of 3.4%.

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Other Income/Expenses for the three months ended March 31, 2003 were net expenses of $13.9 million, compared to net expenses of $13.8 million for the comparable period of the prior calendar year.

Liquidity and Capital Resources

Operating Activities

Net cash provided by operating activities of $21 million 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 increase in accounts receivable, seasonal increase in prepaid assets and seasonal decrease in accrued interest expense.

Investing Activities

Net cash provided by investing activities of $18.1 million for the first quarter of 2003 reflects a decrease in our restricted cash accounts of $18.9 million offset by approximately $403,000 in capital expenditures. Net cash provided by investing activities for the first quarter of 2002 was $38.8 million, reflecting a decrease in our restricted cash accounts of $40.3 million offset by capital expenditures of $1.8 million. We will make capital expenditures thereafter according to the maintenance program for our electricity generating stations. In addition to capital requirements associated with the ownership and operation of our electricity generating stations, 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 and, 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 and the Westover Overfire Air Project, 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.

Financing Activities

Net cash used for financing activities reflects principal payments on our leases and payment of a distribution to our partners. 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. On January 8, 2003, we made a distribution payment of $38.7 million.

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 March 31, 2003, we had recorded $1.0 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 is 1.29%. The principal amount of SRC’s outstanding indebtedness under this credit facility was approximately $20.9 million as of March 31, 2003.

On November 20, 2002, we signed an agreement with Union Bank of California, N.A. for a one-year extension of our current 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.

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 May 12, 2003, of the $35 million committed, we had obtained letters of credit of $10.5 million which have been provided as additional margin to 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 repectively. As of May 12, 2003, we have obtained letters of credit in the amount of $10.5 million to support normal ongoing hedging activities with a number of counterparties.

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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.

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 suspend or terminate credit if our credit ratings were downgraded. Under such circumstances, we would need to post collateral to continue transacting risk-management business with many of our counterparties under either adequate assurance or specific credit rating trigger clauses. The cost of posting collateral would have a negative effect on our profitability. If such collateral was 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 is effective as of 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 a new liability is recorded beginning in 2003, the entity will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is 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, an entity settles the obligation for its recorded amount or incurs 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, a net asset of approximately $3.4 million, and reversed $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 AEE’s asset retirement obligation liability, for the three months ending March 31, 2003 were 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, this Statement 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.

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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) process 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 to 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 VIEs. The sales – leaseback rules required that the leases be treated as financing leases for our financial statements, which they have been from our inception. Therefore the adoption of this Interpretation 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, after evaluating the effectiveness of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-14(c) and 240.15d-14(c)) as of a date (the “Evaluation Date) within 90 days of the filing date of the annual report, have concluded that as of the Evaluation Date, our disclosure controls and procedures were effective to ensure that material information relating to us and our consolidated subsidiaries is recorded, processed, summarized and reported in a timely manner.

Changes in Internal Controls. There were no significant changes in our internal controls or, to our knowledge in other factors that could significantly affect such controls, subsequent to the Evaluation Date.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

          See Note 3 to our Condensed Consolidated Financial Statements in Part I.

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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.

Date:  May 14, 2003

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CERTIFICATIONS

          I, Daniel J. Rothaupt, certify that:

          1. I have reviewed this quarterly report on Form 10-Q of AES Eastern Energy, L.P.;

          2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

          3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

          4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

          5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

          6. The registrant’s other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date:  May 14, 2003

CERTIFICATIONS

          I, Amy Conley, certify that:

          1. I have reviewed this quarterly report on Form 10-Q of AES Eastern Energy, L.P.;

          2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

          3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

          4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

          5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

          6. The registrant’s other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date:  May 14, 2003