AES EASTERN ENERGY LP - 10-K Annual Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

Commission file number 333-89725

AES Eastern Energy, L.P.

(Exact name of registrant as specified in its charter)

Delaware		54-1920088
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1001 North 19th Street Arlington, Virginia		22209
(Address of principal executive offices)		(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None

(Title of each class)

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 ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. []

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

Yes o No ý

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which common equity was last sold, or the average bid and asked price of such common equity was sold, or the last business day of the registrant’s most recently completed second fiscal quarter: $0

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

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

PART I

Item 1	Business

Item 2	Properties

Item 3	Legal Proceedings

Item 4	Submission of Matters to a Vote of Security Holders

PART II

Item 5	Market for the Registrant’s Common Equity and Related Stockholder Matters

Item 6	Selected Financial Data

Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operation

Item 7A	Quantitative and Qualitative Disclosures About Market Risk

Item 8	Consolidated Financial Statements and Supplementary Data

Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

Item 9A	Controls and Procedures

PART III

Item 10	Directors and Officers of Our Company

Item 11	Executive Compensation

Item 12	Security Ownership of Certain Beneficial Owners and Management

Item 13	Certain Relationships and Related Transactions

Item 14	Principal Accounting Fees and Services

PART IV

Item 15	Exhibits, Financial Statement Schedules, and Reports on Form 8-K

Signatures

Item 1. Business

(a) General Development of Business

Our company is a Delaware limited partnership. Our company was formed on December 2, 1998 as an indirect wholly owned subsidiary of The AES Corporation to take part in the acquisition by subsidiaries of The AES Corporation of six coal-fired electricity generating stations and related assets located in the western and west central part of New York State. AES NY, L.L.C. is the sole general partner of our company and AES NY2, L.L.C. is the sole limited partner of our company. The AES Corporation owns indirectly all of the member interests in both AES NY, L.L.C. and AES NY2, L.L.C. The mailing address of our principal executive offices is 1001 North 19th Street, Arlington, Virginia 22209, telephone no. (703) 522-1315.

New York State Electric & Gas Corporation and its affiliate NGE Generation, Inc. (whom we refer to collectively as “NYSEG”) sold these six electricity generating stations and related assets as part of NYSEG’s overall plan to divest itself of its coal-fired electricity generating assets. On May 14, 1999, twelve special purpose business trusts formed by three institutional investors that are not affiliated with us or with The AES Corporation acquired from NYSEG and leased to us the assets constituting the Somerset Generating Station (“Somerset”)(formerly known as the Kintigh Generating Station) and the Cayuga Generating Station (“Cayuga”)(formerly known as the Milliken Generating Station), excluding the real property on which they are located. On that date, we acquired from NYSEG the real property on which Somerset and Cayuga are located and two additional coal-fired electricity generating stations, the Westover Generating Station (“Westover”)(formerly known as the Goudey Generating Station) and the Greenidge Generating Station (“Greenidge”)(together with the real property upon which they are located). We leased a portion of the real property on which Somerset and Cayuga are located and a selective catalytic reduction system (“SCR”), which reduces emissions of nitrogen oxides, that was then being installed at Somerset to the special purpose business trusts, which subleased them back to us. As part of the transaction, AES NY3, L.L.C., an indirect wholly owned subsidiary of The AES Corporation that we do not control, acquired the stock of the Somerset Railroad Corporation (“Somerset Railroad”), which owns short line railroad assets used to transport coal to Somerset. Somerset Railroad entered into a coal hauling agreement with us to transport coal. AES Creative Resources, L.P.(“ACR”), an indirect wholly owned subsidiary of The AES Corporation that we do not control, acquired the balance of the assets that were purchased from NYSEG, consisting of two older, coal-fired electricity generating stations, the Jennison Generating Station (“Jennison”)and the Hickling Generating Station (“Hickling”).

We operate our electricity generating stations through our wholly owned subsidiaries. Westover and Greenidge are owned by our wholly owned subsidiary, AEE2, L.L.C. Our other subsidiaries do not own any of our electricity generating stations but operate them pursuant to operations and maintenance agreements with us.

On February 19, 2002, The AES Corporation announced that it intended to reposition itself in the electric business by fully contracting or divesting its merchant generation businesses. The AES Corporation said that it made this decision to reduce earnings volatility and strengthen its balance sheet. We are one of The AES Corporation’s merchant generating businesses. Subsequently, The AES Corporation has determined that our business will remain part of its portfolio, based on recent and expected performance.

We wish to caution readers that our business and operations involve risks and uncertainties, including the following important factors. These factors should be considered when reviewing our business, financial condition, results of operations and future prospects, and are relied upon by us in issuing any forward-looking statements. Such factors could affect our actual operating results and cause such results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, us. Some or all of these factors may apply to our business as currently conducted or as we intend to conduct it.

• We will be required to make substantial payments under our leases and other contracts and we may have difficulty responding to unforeseen requirements.

• We may have difficulty meeting our payment obligations if our operations are not as successful as we have projected.

• Operation of our electricity generating stations might be disrupted by: interruptions in fuel supply; disruptions in electrical transmission; facility shutdown due to breakdowns or failures of equipment or processes, violations of permit requirements, operator error or terrorist activity or other catastrophic events; or labor disputes.

• Our electricity generating stations are not new and will require careful maintenance if they are to operate efficiently.

• We may have trouble meeting our obligations if our electricity generating stations are not dispatched nearly continually.

• The perception of the public and government officials in the markets we serve and in other deregulated markets that deregulated prices for electric energy are higher than expected may result in some degree of re-regulation of the markets in which we sell our electric energy, unforced capacity and ancillary services. This re-regulation might take the form, for example, of lowering of caps on wholesale electric energy prices during periods of peak demand.

• The addition of new generating capacity in the New York region in excess of the amount required to meet increased demand could result in the reduction of market clearing prices in periods of peak demand, which would reduce the profitability of our operations.

• We operate in an industry where there are a limited number of vendors for supplies which are critical to the operation of our business. If one of our vendors should have production problems, a shortage in these commodities could affect our ability to operate or cause prices to rise for these commodities that may negatively affect our operating results.

• An increase in the real price of coal may negatively affect our operating results.

• Our business is extensively regulated and new regulations may impose requirements that we are unable to meet or that require us to make additional expenditures.

• We have responsibility for environmental liabilities that existed prior to our ownership of our electricity generating stations and we will incur expenses as a result. These expenses may exceed our estimates.

• We may be subject to significant new restrictions on emissions which may force us to restrict our operations or incur significant expenses.

• Under the Asset Purchase Agreement with NYSEG relating to the acquisition of our electricity generating stations, we have assumed liabilities of NYSEG that could result in unexpected expenses and we have given up the right to make claims for problems we may discover later.

• We are controlled by The AES Corporation and The AES Corporation may pursue its own interests to the detriment of our creditors and holders of pass through trust certificates issued to finance the acquisition of Somerset and Cayuga.

• The AES Corporation is not obligated to provide further funding to us if we are unable to pay our obligations.

• In the future we might compete with other electricity generating stations owned by The AES Corporation.

(b) Financial Information About Industry Segments

We operate in only one business segment, electrical generation.

A diagram of the corporate structure of The AES Corporation as it relates to our company is included below:

We were formed on December 2, 1998 to acquire, lease and, through our wholly owned subsidiaries, operate and improve our electricity generating stations. The special purpose business trusts and we acquired our electricity generating stations on May 14, 1999 for a purchase price of $914 million. In order to fund the acquisition of our electricity generating stations (including some adjustments and plus improvement costs, working capital and transaction costs) and pay transaction expenses relating to the acquisition and the lease transactions. The AES Corporation made an equity contribution of $354 million to us (net of costs advanced by the AES Corporation for which we will reimburse it), the institutional investors made an equity contribution of $116 million through the special purpose business trusts and $550 million we raised for purchase of the Somerset Generating Station and the Cayuga Generating station from the sale of pass through trust certifications.

The AES Corporation

The AES Corporation is a leading global power company, with 2003 sales of $8.4 billion. AES delivers 45,000 megawatts of electricity to customers in 27 countries through 116 power facilities and 17 distribution companies. Its 30,000 people are committed to operational excellence and meeting the world’s growing power needs. Approximately 26% of AES’s revenues come from businesses in North America, 18% from the Caribbean, 39% from South America, 11% from Europe and Africa, and 6% from Asia.

New York Power Market

The New York Independent System Operator (“NYISO”) commenced operations in November 1999 and consists of the NYISO and the New York State Reliability Council. The NYISO is a non-profit New York corporation under the Federal Energy Regulatory Commission’s jurisdiction. It is governed by a board of directors with 10 members and three committees; the management committee, the operating committee, and the business issues committee, which are composed of representatives from all market participants, including buyers of power, sellers of power, consumer groups and transmission owners. The New York State Reliability Council has the primary responsibility to preserve the reliability of electricity service on the bulk power system within New York State and sets the reliability standards to be used by the NYISO. The NYISO operates a two-settlement system for calculating Location-Based Marginal Prices (“LBMP”) of electric energy. The first settlement system is a financially binding market for delivery of electric energy on the following day and the second settlement system is the balancing market for immediate delivery of electric energy. LBMP is the incremental cost to supply load at a specific location in the grid. Locational energy price differentials represent the opportunity cost for transmission between specific locations in the grid.

On July 31, 2002, Federal Energy Regulatory Commission(“FERC”) issued a Standard Market Design Notice of Proposed Rulemaking. It proposed among other things to establish a single flexible transmission service, Network Access Service, with a single open access transmission tariff that applies to all transmission customers - wholesale, unbundled retail and bundled retail and a standard market design for wholesale electric markets. In 2003, FERC issued a white paper on the proposed standard market design.

The NYISO’s current market design has many of the proposed characteristics that are included in the July 31, 2002 Standard Market Design Notice of Public Rulemaking. FERC has not set a date for issuance of the standard market design final notice of proposed rule making. We cannot predict the outcome or actual implementation date of this final rule proceeding or the total effect it will have on the markets in which we do business.

The New York power market is interconnected with ISO New England to the northeast, Hydro Quebec and Ontario Hydro to the north, and Pennsylvania-New Jersey-Maryland Interconnection (PJM) to the south.

The transmission of electricity between states and between regions within New York State is constrained by physical limits on transmission capacity and limits on the amount of electricity that may be imported into a power pool imposed by power pools to enhance reliability. Therefore, the generating assets in any given region have a competitive advantage in that region over generators not in the region. There is an existing natural market for the unforced capacity and the electric energy of our electricity generating stations in Western New York, which includes the retail service territories of NYSEG, Niagara Mohawk Power Corporation and Rochester Gas & Electric Corporation. The existing transmission infrastructure also permits us to access neighboring markets. However, our ability to sell electric energy into neighboring markets is limited by constraints imposed by transmission capacity limitations and limits on imported electricity imposed by power pools in those markets for reliability considerations. Our ability to sell electric energy into neighboring markets is also limited because we have entered into bilateral contracts for the sale of a substantial portion of our unforced capacity to load serving entities, i.e., an entity selling electric energy to consumers of electric energy, including regulated distribution utilities, municipalities and energy supply companies, in New York. See “Unforced Capacity Market.”

In November 2000, we entered into a three-year agreement for energy marketing services with AES Odyssey, L.L.C. (“Odyssey”), a direct wholly-owned subsidiary of The AES Corporation. In March 2002, a new five-year agreement was reached, through February 28, 2007, pursuant to which Odyssey provides data management, marketing, scheduling, invoicing and risk management services for a fee of $300,000 per month. On September 4, 2003, we signed an amendment to our March 2002 agreement. Odyssey will also manage our coal and environmental emission credit positions for an additional fee of $100,000 per month. Odyssey acts as agent on behalf of us in the over-the-counter and NYISO markets.

As agent, Odyssey manages all energy transactions under our name including (i) preparing confirmations for us and approving confirmations with counterparties, (ii) conducting monthly check-outs with counterparties as appropriate before the preparation of invoices, (iii) invoicing counter-parties for the term of the transactions and (iv) otherwise managing and executing the terms of the transactions in accordance with their provisions.

Odyssey provides data management for us by maintaining databases of pricing, load, transmission, weather and generation data to aid in analysis to optimize the value of our assets.

Odyssey maintains a transaction management system to manage day-ahead commitments with the NYISO and swap and physical values with counterparties and to provide daily financial reporting and end of day budget variance, forward mark-to-market and commercially accepted risk analysis.

New York Wholesale Electric Energy Market. Electric energy generators may sell electric energy, unforced capacity and ancillary services at the wholesale level to regulated distribution utilities, municipalities and energy supply companies. Electric energy generators may also sell electric energy, unforced capacity and ancillary services in the centralized wholesale market coordinated by the NYISO. Competition in wholesale and retail markets has led to unbundling of and distinct markets for electric energy, unforced capacity and ancillary services.

Electric Energy Markets. Any generator in New York State can sell its output of electric energy to any wholesale customer statewide including utilities, municipalities, and energy supply companies. Generators can sell electric energy under bilateral contracts, with pricing and other provisions determined by two-party negotiation, or they can bid into either or both of two centralized settlement systems for electric energy, a market for delivery on the following day or a market for delivery on an immediate basis, which is intended primarily to balance actual loads and resources. The system pricing is based upon market clearing price, which is the price at which sufficient electric energy is supplied to satisfy all demand for which bids have been submitted. If a generator’s bid is equal to or less than the market clearing price, the generator will be paid the market clearing price, rather than its bid price, at the point it supplies electric energy to the system and the purchaser will pay the market clearing price at the point it receives electric energy from the system. If a generator’s bid exceeds the market clearing price, the generator will not be dispatched.

In December 2003, the NYISO adopted changes to its credit policy. Previously, the working capital fund was collected from the load side of the marketplace. The recent change now collects the fund from both the load and supply side based on a 50/50% ratio. Actual working capital obligation is based on a participant’s net market activity per the total activity of the market. This obligation is eligible to receive interest and is adjusted each year based on a participant’s net activity from the previous year. Further, if a participant leaves the marketplace, it is reimbursed its working capital contribution. Our working capital contribution is estimated to be approximately $1.5 million and will be deducted from monies owned us in the first six months of the year.

In general, we sell the electric energy generated by our electricity generating stations directly into the NYISO market. However, on occasion, we enter into bilateral and physical sales contracts.

Unforced Capacity Market. A market in which electricity generators can sell commitments of their unforced generating capacity has been established to ensure there is enough generation capacity available to produce sufficient electric energy to meet retail demand and ancillary service requirements. Any load serving entity is required to procure capacity commitments sufficient to meet its capacity requirements based on its forecasted annual electric energy requirements at times of maximum usage plus a reserve requirement. On May 20, 2003, FERC issued an order approving the NYISO proposal to replace its then existing, administratively set, vertical installed capacity (ICAP) market structure with a sloped demand curve structure known as the ICAP Demand Curve. The FERC determined that capacity beyond the minimum installed requirement provides both incremental reliability benefits and significant benefits to the competitive energy market. Under the initial ICAP market structure, load serving entities were only required to purchase enough capacity to meet the Minimum Requirement determined by the New York State Reliability Council. The Statewide Minimum Requirement was set at 118%. The ICAP Demand Curve introduced the concept of a sloped demand curve. Load serving entities are required to purchase capacity equal to the maximum amount of capacity offered into the market up to a maximum level determined on the demand curve. The demand curve structure more realistically

reflects the economic value of capacity reserves with capacity prices that decrease as more supply is offered into the capacity market. Previously, each load serving entity was required to purchase unforced capacity commitments equal to approximately 112% of its forecasted annual maximum usage. The load serving entity could have secured these capacity commitments through a bilateral contract or through unforced capacity auctions. Any capacity commitment which is not procured locally needs to satisfy the requirement that, as an import, it does not violate transmission constraints.

Starting with the 2001 – 2002 Winter Capability Period, the NYISO implemented a revised capacity market design in the New York control area that employs unforced capacity as the measure of the capacity of a generator rather than the old measure of installed capacity. Unforced capacity factors in the probability that a generator will be available to serve load. Unforced capacity is the demonstrated maximum output of a generator (installed capacity) with a formula applied that takes into account a generator’s forced outage rate over a defined period of time.

Suppliers of unforced capacity are not required to supply the associated electric energy to the load serving entity with whom they have a contract to provide unforced capacity. For reliability reasons, the NYISO requires that electricity generators that sell unforced capacity into New York must make their electric energy available in the event of a system emergency. This prevents generators from entering into firm contracts to sell electric energy into one market and unforced capacity into another. If the unforced capacity supplier’s offer in the electric energy market for delivery on the following day is not accepted, the unforced capacity supplier, for the next day, will be free either to offer to sell its electric energy in the market for delivery on an immediate basis or to sell electric energy to any customer, including out-of-state customers.

AES NY, L.L.C. and NYSEG entered into a New York Transition Agreement, dated as of August 3, 1998, to ease the transition of NYSEG’s native load customers’ installed capacity requirements. Under this agreement, NYSEG agreed to purchase, and AES NY, L.L.C. agreed to sell, installed capacity in the amount of 1,424MW (which is the aggregate capacity of all of the generating assets included in the assets acquired from NYSEG) for the term of the agreement. AES NY, L.L.C. assigned this agreement to us insofar as it related to our electricity generating stations. The parties performance under the agreement commenced on May 14, 1999 and terminated on April 30, 2001. Since this agreement terminated, we have entered into bilateral contracts with a number of parties for a substantial portion of our unforced capacity and utilize the existing capacity auction processes for the remainder in marketing our capacity.

Ancillary Services Market. The NYISO will procure various ancillary services required for reliability from generators as needed. Services to be procured on a market basis include operating reserves and regulation and frequency support. Generators are compensated for other services, including voltage support and black start capability, on a cost basis.

OTC Swap Market. A fairly liquid over-the-counter swap market has developed in several of the NYISO Zones, (1) West or Zone A, (2) East or Zone G and (3) New York City or Zone J. A zone is a defined portion of the New York electric system that encompasses a set of load and generation buses. Each zone has an associated zonal price that is calculated as a weighted average price. Currently New York State is divided into eleven zones, corresponding to ten major transmission interfaces that can become congested. The swaps settle against the Day Ahead LBMP for Zone A. Our electricity generating station prices are highly correlated to the Zone A price and the swaps are highly effective products for managing our price risk.

Transmission System Market. Transmission lines in New York are controlled by the NYISO. Transmission access is available to all market participants on a comparable and non-discriminatory basis. A party transmitting electric energy through or out of New York State pays the NYISO a transmission service charge to cover the revenue requirements of the transmission owner. Electric energy sold under a bilateral contract is subject to a congestion charge. The congestion charge reflects the differences between the LBMP at the source and destination on the transmission system. Parties can hedge their exposure to congestion charges through transmission congestion contracts which are auctioned biannually.

Regions. New York State has regional transmission constraints which divide the state’s power market into distinct regions. The most significant transmission constraints impede the transmission of electricity going west to east. As a result, the most significant regional differences in the power market are between the western and eastern regions. The eastern region includes the service areas of the Long Island Power Authority, Key Span Energy Corporation, Consolidated Edison Company of New York, Inc., Orange & Rockland Utilities, Inc. and Central Hudson Gas & Electric Corporation. The western region includes service areas of Niagara Mohawk Power Corporation, Rochester Gas & Electric Corporation, the New York Power Authority and most of NYSEG.

The western region is dominated by low cost nuclear, coal and hydro facilities which, together with non-utility generators that must be permitted to run under their power purchase agreements with local utilities, form 83% of installed capacity. The eastern region has a predominance of facilities which are economically viable only at periods of peak demand, which form 80% of its installed capacity. Even though the western region has only 40% of the New York power market’s generation capacity, power normally flows from the west into the east. The flow of power from the lower priced western region to the higher priced eastern region is limited to approximately 5,000MW by transmission limits and reliability considerations. When this limit is reached, higher cost units in the New York City area are directed to run even when lower cost units in the western region are available.

Interconnection. Western and central New York are relatively unattractive markets for the transmission of imported power due to the low generation costs of existing facilities and low on-peak electric energy prices relative to the area’s adjacent markets, ISO New England, PJM (Pennsylvania-New Jersey-Maryland) Interconnection and eastern New York. The existing transmission infrastructure permits us to access these neighboring markets, subject to constraints imposed by capacity limitations and reliability considerations and subject to our obligation to offer to sell our electric energy in the New York market for the delivery of electric energy on the following day to the extent that we have sold our unforced capacity to a load serving entity in New York in accordance with the rules of the NYISO.

Fuel Supply

Our electricity generating stations are located in close proximity to important coal producers. In addition, both Somerset and Cayuga are equipped with flue gas desulfurization (“FGD”) systems that allow the plants to burn less expensive medium- and high-sulfur coal while staying within sulfur dioxide (“SO2”) emission regulation requirements.

Coal mines in the Pittsburgh Seam coal formation near our electricity generating stations include some of the lowest cost coal supply sources producing at volume. Although more expensive low-sulfur coals are available for units without FGD systems, the high sulfur content of the coals from the Pittsburgh Seam have historically made coal-fired generating stations equipped with FGD systems the primary market for Pittsburgh Seam producers. Since both Somerset and Cayuga have installed FGD systems and are capable of burning higher sulfur coals, we expect to maintain a fuel cost advantage over competitors without FGD systems.

On July 23, 2003, Somerset was granted approval by the New York State Department of Environmental Conservation(“NYSDEC”) to burn petroleum coke as a supplemental fuel through a modification of the Prevention Significant Deterioration and Title V air permits.

The Electricity Generating Stations

We believe that our two principal coal-fired electricity generating stations, Somerset and Cayuga, are among the lowest variable cost facilities in the New York power market. We expect them to be fully dispatched when available in the deregulated and competitive New York power market. We also intend to make appropriate investments of capital to maintain our electricity generating stations. Somerset, Cayuga, Westover and Greenidge have an aggregate net generating capacity of 1,268MW.

The Somerset Generating Station

Somerset is the largest and newest of our electricity generating stations and is located northeast of Niagara Falls, alongside the southern shore of Lake Ontario near Barker, New York. There is a single operating unit, which began generating electricity in 1984. The maximum net generating capacity of Somerset is 675MW.

Somerset is believed to be among the lowest variable cost facilities in the New York power market. It can be run economically even at times of minimum demand for electric energy. Somerset also is capable of burning low cost medium- and high-sulfur coal as a result of being equipped with a FGD system to control SO2 emissions and a selective catalytic reduction (“SCR”) system to control nitrogen oxide(“NOx”) emissions. When Somerset is not being dispatched at maximum load, its periodic load can be varied to meet both system load demand and provide transmission system support and the plant can provide both operating reserves that are available immediately or on ten minutes notice. The plant is also equipped with Automatic Generation Controls enabling it to provide regulation and frequency support.

The Cayuga Generating Station

Cayuga is located alongside the east shore of Cayuga Lake, near the town of Lansing, New York. There are two operating units at Cayuga, Unit 1 and Unit 2, which began generating electricity in 1955 and 1958, respectively. The maximum aggregate net generating capacity of the two units is 306MW. Cayuga Unit 1 currently has a net generating capacity of 150MW. Unit 2 currently has a net generating capacity of 156MW.

Cayuga is believed to be among the lowest variable cost facilities in the New York power market. It can be run economically even at times of minimum demand for electric energy. Cayuga also is capable of burning low cost medium- and high-sulfur coal as a result of being equipped with a FGD system to control SO2 emissions. When Cayuga is not being dispatched at maximum load, its periodic load can be varied to meet both system load demand and provide transmission system support, and the plant can provide both operating reserves that are available immediately or on ten minutes notice. The plant is also equipped with Automatic Generation Controls enabling it to provide regulation and frequency support. We installed a SCR system to control NOx emissions on Unit 1, which became operational on June 7, 2001.

Westover Generating Station

Westover is located alongside the Susquehanna River near Johnson City, New York, and began generating electricity in the early 1900’s. Units 1 through 6 have been retired and physically removed. Westover presently consists of two units, Unit 7 and Unit 8, with a combined maximum net generating capacity of 126MW. During 2003, Westover installed an overfire air system on Unit 8 to control NOx emissions.

Westover is capable of providing both operating reserves that are available immediately or on ten minutes notice. The station is equipped with Automatic Generation Controls, which connect it to the NYISO power control center and enable it to provide regulation, frequency support, and when directed by the NYISO, voltage support.

Greenidge Generating Station

Greenidge is located on the west shore of Seneca Lake adjacent to the village of Dresden, New York, and began generating electricity in 1938. Units 1 and 2 have been retired and physically removed. Greenidge presently consists of two units, Unit 3 and Unit 4, with a combined maximum net generating capacity of 161MW.

Greenidge is capable of providing both operating reserves available immediately and on ten minutes notice. The station is equipped with Automatic Generating Controls, which connect it to the NYISO power control center and enable it to provide regulation, frequency support, and, when directed by the NYISO, voltage support.

On October 16, 2001, Greenidge was awarded a Federal Clean Coal Grant that, if accepted, will fund 50% of the capital costs for backend technology and 30% of the operations and maintenance costs for a test and demonstration period. This technology will include a single bed, in-duct SCR unit in combination with low-NOx combustion technology, on Greenidge Unit 4 firing on coal and biomass. It will also include a Circulating Dry Scrubber for SO2, mercury and acid gas removal. Greenidge has submitted a written request to the Department of Energy, which administers the Clean Coal program, for a 12 to 18 month delay in starting the grant. This request was made in light of the current difficult electricity and credit markets and the uncertain state regulatory environment.

Regulation

Energy Regulatory Matters

General

We and our ownership and operation of our electricity generating stations are regulated under numerous federal, state and local statutes and regulations. Among other aspects of electric generation, these statutes and regulations govern the rates that we may charge for the output of our electricity generating stations, establish in certain instances the operating parameters of our electricity generating stations and define standards for ownership of our electricity generating stations. While there exists interest at both the federal and state level to deregulate certain aspects of the electric generation industry, we currently remain subject to extensive regulation.

Federal Energy Regulation

Federal Power Act. Under the Federal Power Act, the FERC possesses exclusive rate-making jurisdiction over wholesale sales of electricity and transmission in interstate commerce. FERC regulates the owners of facilities used for the wholesale sale of electricity and transmission in interstate commerce as “public utilities” under the Federal Power Act.

Our rate schedule was approved by FERC, as required under the act, as a market-based rate schedule and, accordingly, FERC granted us waivers of the principal accounting, record-keeping and reporting requirements that otherwise are imposed on utilities with a cost-based rate schedule.

Public Utility Holding Company Act. The Public Utility Holding Company Act (“PUHCA”) provides that any corporation, partnership or other entity or organized group that owns, controls or holds power to vote 10% or more of the outstanding voting securities of a “public utility company” or a company that is a “holding company” of a public utility company is subject to regulation under PUHCA, unless an exemption is established or an order is issued by the SEC declaring it not to be a holding company. Registered holding companies under PUHCA are required to limit their utility operations to a single integrated utility system and to divest any other operations not functionally related to the operation of the utility system. In addition, a public utility company that is a subsidiary of a registered holding company under PUHCA is subject to financial and organizational regulation, including approval by the SEC of certain of its financing transactions. However, under the Energy Policy Act of 1992, a company engaged exclusively in the business of owning and/or operating a facility used for the generation of electric energy exclusively for sale at wholesale may be exempted from PUHCA regulation as an “exempt wholesale generator.” On February 5, 1999, we received exempt wholesale generator status from FERC for our ownership and operation of generation and associated facilities. If, after having received this status, there is a “material change” in facts that might affect our continued eligibility for exempt wholesale generator status, within 60 days of this material change, we must (a) file a written explanation of why the material change does not affect our exempt wholesale generator status, (b) file a new application for exempt wholesale generator status or (c) notify FERC that we no longer wish to maintain exempt wholesale generator status. However, if we should lose exempt wholesale generator status, then we would either have to restructure ourselves or risk subjecting ourselves and our affiliates to PUHCA regulation.

State Regulation. In New York State, legislation has significantly deregulated the rate setting aspects of the industry. However, significant risks remain, including, but not limited to, the potential that the state deregulation initiatives could be reversed or nullified. We obtained authorization from the New York State Public Service Commission for the issuance of the pass through trust certificates and the incurrence of debt pursuant to the terminated working capital credit facility with Union Bank of California, N.A. In April 2001, we received approval of our current working capital facility.

Lease Transactions Filings and Approvals. We believe that the special purpose business trusts have obtained all energy-related approvals required to be obtained by them. The special purpose business trusts have been included in the approval by FERC of the transfer of jurisdictional facilities and the acquisition and leaseback of FERC-jurisdictional facilities, and FERC has granted a disclaimer of jurisdiction over each of the institutional investors and the special purpose business trusts and the trustees of those trusts as public utilities under Part II or III of the Federal Power Act. The special purpose business trusts have received determinations from FERC that they are exempt wholesale generators. The special

purpose business trusts obtained a no-action letter from the SEC staff that no enforcement action would be recommended against them under PUHCA if they proceeded with the lease transactions prior to obtaining exempt wholesale generation determinations from FERC.

Environmental Regulatory Matters

General

As is typical for electric generators, our electricity generating stations are required to comply with federal, state and local environmental statutes and regulations relating to the safety and health of personnel and the public, including

• the identification, generation, storage, handling, transportation, disposal, record-keeping, labeling, reporting of and emergency response in connection with hazardous and toxic materials associated with our electricity generating stations;

• safety and health standards, practices and procedures applicable to the operation of our electricity generating stations; and

• environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants.

Failure to comply with any of these statutes or regulations could have material adverse effects on us, including the imposition of criminal or civil liability by regulatory agencies or civil fines and liability to private parties, and the required expenditure of funds to bring our electricity generating stations into compliance. In addition, pursuant to the Asset Purchase Agreement with NYSEG, we (as assignee of AES NY, L.L.C.) have, with a few exceptions, agreed to indemnify NYSEG against the consequences of NYSEG’s handling, storage or emission of hazardous and toxic materials on any of the sites of our electricity generating stations and the Lockwood and Weber off-site ash disposal site and for NYSEG’s past non-compliance, if any, with environmental requirements.

It is likely that the stringency of environmental statutes and regulations affecting us and our operations will increase in the future. In the meantime, we will monitor potential legislative and regulatory developments that may impact our operations and we will participate as appropriate.

Expenditures. Compliance with environmental standards will continue to be reflected in our capital expenditures and operating costs. Based on the current status of regulatory requirements, other than the expenditures for the SCRs at Somerset and Cayuga Unit 1 including the construction of new landfill space to manage ash from Somerset’s SCR system operations, 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 expenditures for studies, and capital and operating expenses to bring the electricity generating stations into compliance with the new federal cooling water intake standards, we do not anticipate that any capital expenditures or operating expenses associated with our compliance with current laws and regulations will have a material effect on our operations or our financial condition. See “Air Emissions—Nitrogen Oxides.”

Air Emissions

The federal Clean Air Act and many state laws, including the laws of the State of New York, require significant reductions in utility sulfur dioxide and nitrogen oxides emissions that result from burning fossil fuels in order to reduce acid rain and ground-level ozone (smog).

Sulfur Dioxide (SO2). SO2 emissions are regulated under Title IV of the federal Clean Air Act Amendments and by the New York Acid Deposition Control Act. The SO2 emission reduction requirements under Title IV generally apply to almost all fossil-fuel fired electric generating units producing electricity for sale. Power plants subject to Title IV are required to obtain acid rain permits, to hold sufficient emission allowances to cover their SO2 emissions, and to comply with various monitoring and record-keeping requirements. The federal SO2 requirements were implemented in two phases—Phase I applies to the 110 plants listed in section 404 of the Act and Phase II generally affects all other fossil-fuel fired electric generating plants selling over 25MW to the electricity distribution grid. Phase I of the federal Clean Air Act Amendments SO2 program went into effect January 1, 1995,

with Cayuga Unit 1 and Unit 2 and Greenidge Unit 4 falling under the program. Phase II went into effect January 1, 2000 and affects all the units.

FGD systems are operated at both Somerset and Cayuga to reduce total SO2 emissions from these plants to quantities substantially below the Title IV SO2 “allowance” allocations for the units at these plants. An allowance is a freely transferable right to emit one ton of a substance, in this case, SO2. The excess allowances are accumulated and can either be used for our other electricity generating stations, banked for future use or sold to provide liquidity to us. We may need to purchase SO2 allowances to cover SO2 emissions for Greenidge and Westover. Market prices for SO2 allowances currently range from about $230 to $270 per ton. We were self sufficient with respect to SO2 allowances in 2001, however we had a shortfall of approximately 6,600 and 10,000 SO2 allowances in 2002 and 2003, respectively. The majority of the 2002 SO2 allowance shortfall was covered with allowances purchased from the electricity generating stations owned by ACR, which are on long-term cold standby. The allowances were purchased at quoted market prices. The 2003 shortfall was covered by purchasing SO2 allowances at market price from unrelated companies in the open market.

Based on current market pricing of electricity and SO2 allowance forwards for the years 2004 and 2005, respectively, we forecast that we will have a shortfall of approximately 16,000 and 8,000 SO2 allowances in 2004 and 2005, respectively. Based on current prices the shortfall could cost between $4.2 million to $3.4 million and $2.1 million to $1.6 million for the years 2004 and 2005, respectively. The shortfall will be covered by purchasing SO2 allowances at market price from unrelated companies in the open market or by reduced operations of our non-reheat units and/or purchasing lower sulfur coal to reduce our emission rates.

In October 1999, New York Governor Pataki announced a new initiative which directed NYSDEC to issue regulations requiring electric generators to reduce SO2 emissions by another 50% below Phase II standards. The final regulations (6 NYCRR Part 238) were adopted in March 2003. The new regulations will be phased in starting January 1, 2005, with full implementation complete by January 1, 2008. A number of entities have started legal actions to attempt to overturn these rules.

In January 2004, NYSDEC determined the amount of SO2 emissions allowances that would be allocated to our electricity generating stations. The allocation is several thousand tons short of our average historical SO2 emissions for our electricity generating stations. Our compliance plan cannot be finalized until the anticipated New York SO2 allowance market prices are more conclusively determined.

Nitrogen Oxides (NOx). 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.

The Phase I regulations require facilities in New York State to implement NOx control requirements based on reasonably available control technology (“RACT”). Somerset, Cayuga, Greenidge and Westover operate under a common averaging plan, whereby the stations that emit well below the system-wide limit reduce the overall average for electricity generating stations that emit in excess of the system-wide limit known as a RACT Rate.

Implementation of the Phase II emission rules commenced on May 1, 1999. The Phase II NOx regulations set forth a NOx allowance allocation program which gave us 6,292 NOx emission allowances annually through 2002. Each allowance authorized us to emit one ton of NOx during the ozone season (May 1 to September 30), beginning in 1999.

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 us 2,317 NOx emission allowances for 2004.

To comply with the stricter emissions regulations beginning in 1999, we installed a SCR system at Somerset, which became operational in June 1999. During 2001, we installed a SCR system on Unit 1 of Cayuga, which became operational on June 7, 2001. During 2003, we installed an overfire air system to control NOx emissions on Westover Unit 8.

Somerset and Cayuga’s Unit 1 generated excess NOx allowances in 2003, 2002 and 2001. We expect that Somerset and Cayuga will accumulate excess allowances during the 2004 ozone

season. Our compliance strategy involves potential installation of additional NOx control technology at our electricity generating stations, reduced operations of our non-reheat units during the ozone season, reducing emission rates and/or the selling/buying or trading of NOx allowances. This includes trades between our electricity generating stations as needed to offset NOx emissions. During 2002 and 2001, we were a net seller of NOx allowances. In 2003, we were short approximately 1,200 NOx allowances. The 2003 shortfall was covered by purchasing 70 NOx allowances from AES Ironwood, an indirect wholly owned subsidiary of the AES Corporation at market prices and the remainder of NOx allowances were purchased from unrelated companies in the open market at market price.

Based on current market pricing of electricity and NOx allowance forwards for the years 2004 and 2005, respectively, we forecast that we will have a shortfall of approximately 1,400 and 804 NOx allowances in 2004 and 2005, respectively. Based on current prices could the shortfall cost between $3.2 million to $2.4 million and $1.8 million to $1.7 million for the years 2004 and 2005, respectively. The shortfall will be covered by purchasing NOx allowances at market price from unrelated companies in the open market or by reduced operations of our non-reheat units and/or reducing emission rates.

New York Governor Pataki’s October 14, 1999 initiative also directed the NYSDEC to issue regulations requiring stringent NOx reduction. The final regulations (6 NYCRR Part 237) were adopted in March 2003. The regulations require non-ozone season emission reductions based on an emission rate of 0.15 lbs/Mmbtu starting on October 1, 2004. A number of entities have started legal actions to attempt to overturn these rules.

In September 2003, New York State determined the amount of NOx emissions allowances that would be allocated to our electricity generating stations. The allocation is several thousand tons short of our average historical NOx emissions for our electricity generating stations during the control period. Our compliance plan cannot be finalized until the anticipated New York NOx allowance market prices are more conclusively determined.

The capital cost of the Somerset SCR was $31 million. We expect that the system will operate for 20 years. We have developed a catalyst maintenance plan to insure the SCR’s performance, which consists of changing out one of the three layers of catalyst every eighteen months. We purchased a layer of regenerated catalyst for $900,000 and installed it during our fall 2003 scheduled outage. During the scheduled outage, we removed a layer, which will be regenerated and stored until our next scheduled outage at a cost of $1 million. Catalyst layers will continue to be rotated and regenerated on an approximately 18-month schedule at a cost of approximately $1 million per rotation. The capital cost of the Cayuga SCR on Unit 1 was $11.2 million and it was operational on June 7, 2001. We expect that the system will operate for 20 years. We will need to replace the catalyst approximately every four years at an estimated cost of approximately $325,000 in 2001 dollars.

Our electricity generating stations have generally achieved continuous compliance with the current NOx reduction requirements with the exception noted below.

We voluntarily disclosed to the NYSDEC and the United States Environmental Protection Agency (“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 electricity generating stations’ NOx RACT tracking system. We believe that we have taken all reasonable, good faith efforts to assess and correct the exceedances. Immediately upon discovery of the calculation error, the SCR at Somerset 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 NYSDEC for review of the self-disclosure letter and technical issues. We are unable to predict any potential actions or fines the NYSDEC may require, if any.

In January 2004, the EPA proposed an “interstate air quality rule” that would require further emission reductions in NOx and SO2 emitted from power plants and other sources that significantly contribute to fine particulate (“PM2.5”) and ozone pollution in downwind states. NOx and SO2 are precursors of PM2.5, and NOx is a precursor of ozone. The proposed rule directs 29 states, including New York, to issue new regulations that will require major SO2 and NOx reductions by 2010 and further reductions by 2015. States are encouraged to use a cap and emission trading approach. A final rule is expected to be issued in 2005. At this point, we cannot determine what the costs would be to comply with new federal SO2 and NOx emission reduction requirements.

New Source Review (NSR). We received an information request letter dated October 12, 1999 from the New York Attorney General which sought detailed operating and maintenance history for Westover and Greenidge. On January 13, 2000, we received a subpoena from the NYSDEC seeking similar operating and maintenance history for all four of our electricity generating stations. We have provided materials responding to the requests from the Attorney

General and the NYSDEC. This information was sought in connection with the Attorney General’s and the NYSDEC’s investigations of several electric generation stations in New York which are suspected of undertaking modifications in the past (from as far back as 1977) without undergoing an air permitting review.

On April 14, 2000, we received a request for information pursuant to Section 114 of the Clean Air Act from the EPA seeking detailed operating and maintenance history data for Cayuga and Somerset. 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. We have provided the requested documentation.

By letter dated May 25, 2000, the NYSDEC issued a Notice of Violation (NOV) to NYSEG for violations of the Clean Air Act and the Environmental Conservation Law at Greenidge and Westover 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 electricity generating stations by us. Pursuant to the Asset Purchase Agreement relating to the acquisition of the electricity generating stations from NYSEG, we agreed to assume responsibility for environmental liabilities that arose while NYSEG owned the electricity generating stations. On September 12, 2000, we agreed with NYSEG that we will assume the defense of and responsibility for the NOV, subject to a reservation of our right to assert applicable exceptions to our contractual undertaking to assume preexisting environmental liabilities.

We are currently in negotiation with both the EPA and NYSDEC. If a settlement is not reached, the EPA and the NYSDEC could issue a notice or notices of violation (NOV) to us for violations of the Clean Air Act and the Environmental Conservation Law. If the Attorney General, the DEC or the EPA does file an enforcement action against Somerset, Cayuga, Westover, or Greenidge, then penalties may be imposed and further emission reductions might be necessary at these electricity generating stations which could require us to make substantial expenditures. We are unable to estimate the effect of such a NOV on our financial condition or results of future operations.

Mercury. In January 2004, the EPA proposed the “utility mercury reductions rule” that would regulate mercury emissions from existing and new coal-fired power plants. The EPA proposed two alternative approaches for reducing mercury emissions based on different authority under the Clean Air Act. The EPA’s preferred approach is to implement a cap and emission trading program with the first phase commencing in 2010 and the second phase starting in 2018. If the EPA selects the alternative approach, compliance through currently available pollution controls known as “maximum achievable control technologies”(MACT) could be required by December 2007. Pursuant to a settlement agreement with environmental groups, the EPA is required to finalize the utility mercury reductions rule by December 15, 2004. At this point we cannot determine what the costs would be to comply with mercury control regulations.

Carbon Dioxide (CO2). Future initiatives regarding the impacts of greenhouse gases (e.g., carbon dioxide, “CO2”) emissions and global warming continue to be the subject of intense debate. The Kyoto treaty relating to reduction of greenhouse gas emission was signed by the United States but has since been rejected by President Bush, who instead has asked U.S. industry to achieve an 18% decrease in carbon intensity on a voluntary basis. We will monitor any future initiatives on this issue and the ultimate effects of the Kyoto treaty and the President’s initiatives.

In addition, 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 emissions trading program. Until such time as the rules are developed to implement such a program, we cannot determine what its impact would be on our financial position or results of operations.

We voluntarily disclosed to the NYSDEC in January 2003 that Cayuga had inadvertently burned synfuel (coal with a latex binder applied), which it is not permitted to burn. Cayuga had entered into an agreement with a supplier to purchase coal. It received approximately one 9000-ton train shipment per month from April 24, 2001 to December 27, 2002. In January 2003, we became aware that the product we were receiving was synfuel. We have suspended all shipments from that supplier until a resolution is reached. We have reviewed the emission and

operation data which showed there was no adverse effect to air quality with respect to applicable permit emissions limits attributable to burning the material. We are unable to predict any potential actions or fines the NYSDEC may require, if any. In July 2003, we reached an agreement with the supplier to resume shipments of coal in order to satisfy contractual obligations. As part of this agreement, the supplier has provided a written guarantee stating that all fuel shipments will be coal.

Particulates and Opacity. Each of our electricity generating stations is currently in compliance with particulate emission limits. Each of our electricity generating stations is required to meet an opacity limit. In the past, several of the electricity generating stations exceeded these limits. This was a common problem at coal-fired electricity generating stations, and the NYSDEC has initiated an enforcement action against several utilities, including NYSEG.

In January 2000, we received a draft consent order from the NYSDEC that alleges violations of the opacity emission limitations in the air permits for Cayuga, Westover, and Greenidge occurring since our electricity generating stations were purchased from NYSEG. The draft consent order would require us to prepare an opacity compliance plan and would impose penalties for opacity violations occurring after May 14, 1999, the date of the acquisition. We do not know when the NYSDEC will issue a final consent order. Potential fines and required actions cannot be divulged to the public until a final consent order is signed. Nevertheless, we expect that any consent order will likely require continued operation at the current level of opacity compliance that has been achieved over the past year. AES NY, L.L.C. also received notice from NYSEG that NYSEG has received a draft consent order from the NYSDEC seeking penalties primarily for opacity violations occurring prior to May 14, 1999. In the notice, NYSEG asserts that it will seek indemnification from AES NY, L.L.C. for any penalties, attorney fees, and related costs that it incurs in connection with the consent order. We and AES NY, L.L.C. have denied liability for the pre-closing violations and intend to vigorously defend this claim if NYSEG pursues litigation or arbitration.

Water Issues

In April 2002, the EPA proposed to establish location, design, construction and capacity standards for cooling water intake structures at existing power plants withdrawing more than 50 million gallons per day from rivers, lakes or other bodies of water. The final rule was released by the EPA on February 16, 2004. These new rules will impose new compliance requirements on the withdrawal of water, with potentially significant costs, on operating plants across the nation with cooling water intake structures. Cost items include various environmental and engineering studies and potential capital and maintenance costs. We are evaluating the potential applicability of the rule and we have not yet determined the effects, if any, of these regulations on our financial position or results of operations. If applicable, the new rule requirements will be addressed when the electricity generating stations’ wastewater discharge permits are renewed.

Our electricity generating stations and their ash disposal sites have been designed and are operated to comply with strict water and wastewater compliance standards. Groundwater protection measures include coal pile liners at all stations, lined active ash disposal sites, no active fly ash settling ponds, and a network of groundwater monitoring wells. New York State has not only technology-based effluent limitations for surface water discharges, but is one of the first states in the nation to impose more restrictive limits on wastewater discharges to ensure that very protective water quality-based standards are maintained. Our electricity generating stations have numerous wastewater treatment facilities in order to ensure compliance with these restrictive discharge limits. In addition, Somerset normally operates in a zero process wastewater discharge mode, reusing wastewater for various plant processes. Similarly, the ash disposal sites must comply with both technology and water quality-based discharge limits. Where necessary, a lime treatment is employed to remove metals from ash site wastewater prior to discharge.

Hazardous Material and Wastes

The electric utility industry typically uses and/or generates in its operations a range of potentially hazardous products and by-products. We have identified a number of site remediation issues at our electricity generating stations. Under the terms of the Asset Purchase Agreement with NYSEG, NYSEG retained pre-closing off-site environmental liabilities associated with our electricity generating stations (other than liabilities arising from the Weber and Lockwood ash disposal sites), but we assumed responsibility for contamination at our electricity generating stations and at the Lockwood ash disposal site.

We have budgeted $9.9 million for the cost for environmental liabilities at our electricity generating stations (excluding closure and post-closure costs for the Weber and Lockwood ash disposal sites), based on estimates of environmental consultants retained by NYSEG and The AES Corporation. We have budgeted approximately $6 million for closure and post-closure (monitoring and maintenance) expenses for the Lockwood ash disposal site, based solely on amounts previously budgeted for these activities by NYSEG. ACR assumed responsibility for the Weber ash disposal site. Our subsidiary, AEE2, L.L.C., has contributed one-half of the closure costs for the Weber ash disposal site based on the amount of ash disposed at the site from Westover and Greenidge, which are owned by AEE2, L.L.C., compared to the amount disposed from Hickling and Jennison, which were acquired by ACR.

In October 1999, ACR entered into a consent order with the NYSDEC to resolve alleged violations of the water quality standards in the groundwater downgradient of the Weber ash disposal site. As a result, the site was closed. AEE2, L.L.C. contributed one-half of the costs to close the landfill, which were approximately $2 million, and it will contribute additional costs for long-term groundwater monitoring. Nevertheless, if a groundwater remediation is required, AEE2, L.L.C. may be responsible for a portion of such costs.

We expect to develop a new area, Area 3, of the on-site landfill located at Somerset to contain ammonia-contaminated fly ash produced during operation of the SCR system and stabilized sludge produced during simultaneous operation of the FGD system. As designed, Area 3 will comply with modern landfill design and performance standards. On April 26, 1999, the New York State Board on Electric Generation Siting and the Environment approved the plan to use Area 3, subject to approval by the NYSDEC of more detailed design submissions. The NYSDEC has defined non-ammoniated waste material to contain less than 0.5 parts per million of ammonia. Most of the fly ash generated during operation of the SCR at Somerset qualifies as non-ammoniated. The NYSDEC approved disposal of non-ammoniated waste material generated during the operation of the SCR system in an existing area of the landfill, Area 1. We are working with the NYSDEC to complete an approved design for the Area 3 expansion.

The Somerset landfill is under the jurisdiction of the New York Public Service Commission. NYSEG’s original compliance filing with the Public Service Commission in 1983 provided that the landfill would be constructed in a 200 acre section of the site, which NYSEG divided into three areas (Areas 1, 2, and 3). The landfill was designed to comply with the then-existing solid waste landfill standards of the NYSDEC. Each area was to receive a separate landfill unit lined with a low permeability material, usually clay. However, the first 17-acre section of Area 1 of the landfill was lined with compacted soil only. Only Area 1 was used by NYSEG. The Area 1 landfill has been expanded seven times during the years since 1983. When a portion of Area 1 reaches the maximum allowable elevation (130 feet), it is “capped” by adding compacted soil and planting ground cover. The entire process is meant to be self-implementing, with little input from the Public Service Commission unless there is a problem or a change in design or operation.

In the period since the original approval of the Somerset landfill, the NYSDEC has modified its solid waste landfill regulations extensively. As a result of these changes, these regulations currently allow construction or expansion of landfills only with low permeability liners and sophisticated leachate collection systems, and impose higher standards for capping and closing solid waste facilities.

Natural groundwater conditions present at the Somerset site make it very difficult to distinguish between landfill leachate and naturally occurring substances in the groundwater. Substances that are typically considered indicators of leachate infiltration into groundwater from ash monofill operations, namely sulfates, iron and manganese, are also naturally occurring in the groundwater around and beneath Area 1. NYSEG commissioned independent consultants to perform groundwater testing using sophisticated geochemical fingerprinting techniques, which distinguish the major ions of a water sample. NYSEG’s consultants have shown, to the satisfaction of the Public Service Commission, that there has been no material release of leachate from Area 1 into the groundwater.

In April 1999, the NYSDEC and the Public Service Commission negotiated a Memorandum of Understanding that clarifies their respective roles with respect to the regulation of the Somerset landfill. According to the Memorandum of Understanding, the Public Service Commission’s decisions will continue to control all aspects of Areas 1 and 2 of the landfill, but the Public Service Commission must defer to current and future NYSDEC regulations, standards and policies with respect to the development, use and closure of Area 3. The Memorandum of Understanding was approved by the New York State Board on Electric Generation Siting and the Environment and was incorporated as part of the April 26, 1999 amendment to

the Certificate of Environmental Compatibility for Somerset that we received in connection with installation of the SCR.

Factors which could cause actual costs of disposal in Areas 1, 2 and 3 to vary include, but are not limited to, adoption of more stringent solid waste landfill regulations by the NYSDEC, the discovery of groundwater contamination from Area 1, and escalation of the costs of landfill development.

On December 23, 2003, Somerset was granted approval by the New York State Board on Electric Generation Siting and the Environment to amend the Certificate of Environmental Compatibility and Public Need to landfill the petroleum coke fly ash and stabilized sludge produced during operation of the SCR and FGD system.

The existing Cayuga on-site landfill currently complies with modern landfill design and performance standards and will receive any ammonia-contaminated fly ash or ammoniated sludge produced during operation of the SCR system on Unit 1. Cayuga has seen concentrations of certain analytical parameters above established action levels in ground water monitoring wells down gradient from the ash disposal area. Remedies are being discussed with the NYSDEC. Actions may include operational changes or capping the existing landfill, construction of a new landfill cell, or a combination of these actions.

In an area adjacent to the Lockwood ash disposal site, our environmental consultant reported that approximately 500 to 700 drums of abrasives were disposed in the early 1970s and covered with ash. We have budgeted $520,000 to conduct a site investigation and remove the drums. In addition, groundwater sampling in this area and around the Lockwood ash disposal site indicates that some monitoring wells have parameters which exceed state regulatory limits. As noted above, we have budgeted $6 million in closure and post-closure (monitoring and maintenance) costs for the Lockwood ash disposal site.

In 2000, the EPA confirmed that ash disposed of in landfills should be regulated as non-hazardous waste. Nevertheless, the EPA determined that additional solid waste regulations will be developed for coal ash disposal in landfills and surface impoundments. At this point, we cannot determine whether such new regulations will have an impact on our ash disposal practices.

These projected environmental cost estimates are not a guarantee that additional environmental liabilities will not be incurred, and it is possible that the actual costs could be significantly higher. In addition, it is possible that previously unknown environmental conditions will be discovered in the future.

Noise

The Certificate of Environmental Compatibility that was issued to NYSEG in 1978 for the development and operation of Somerset contains a number of requirements for mitigating environmental impacts from the facility, including noise impacts. Among the noise requirements was an obligation to obtain noise easements from neighboring landowners or, as subsequently approved by the Public Service Commission, to purchase their property in a buffer zone where noncompliance with noise standards was expected to occur. Subsequent analyses predicted that these exceedances would occur only in connection with ash disposal operations when Area 2 of the Somerset landfill was constructed. Prior to the acquisition of our electricity generating stations, NYSEG had purchased neighboring properties for a combined cost totaling approximately $1.5 million and had a standing offer to purchase the remainder. We obtained an appraisal of the remaining properties which places their aggregate current value at approximately $3.1 million in 1999 dollars. We have not budgeted any amount for the acquisition of these properties.

The Public Service Commission has also required that a noise mitigation plan be developed and submitted for Public Service Commission approval at least one year prior to commencement of Area 2 development.

The Public Service Commission could require additional noise control measures at that time. We do not expect that the noise compliance costs we may incur, including as a result of taking over the land purchase program, will be material.

People

As of December 2003, we employed approximately 300 people who operate our electricity generating stations. The International Brotherhood of Electrical Workers (the “IBEW”) represents hourly labor at Somerset, Cayuga, Westover and Greenidge. The IBEW represents approximately 244 workers. We have negotiated collective bargaining agreements with respect to each electricity generating station, on an individual electricity generating station basis. This gives us continuing labor harmony and encourages the adoption of The AES Corporation’s culture by emphasizing individual businesses with responsibility and ownership of local issues. We believe that relations with the people employed at our electricity generating stations are satisfactory.

Item 2. Properties

The following table shows the material properties which we or our subsidiaries own or lease. See “Business—The Electricity Generating Stations” for more information about these properties.

Electricity Generating Station	Location	Capacity	Owned or Leased	Expiration of Lease

Somerset	Barker, NY	675MW	Leased*	February 13, 2033
Cayuga	Lansing, NY	306MW	Leased*	November 13, 2027
Westover	Johnson City, NY	126MW	Owned	Not Applicable
Greenidge	Dresden, NY	161MW	Owned	Not Applicable

* We own all of the land on which Somerset and Cayuga are located and we lease the portion on which the facilities of those stations are located to the special purpose business trusts that own those facilities. We lease the facilities of those stations and sublease the land on which they are located from the special purpose business trusts.

Item 3. Legal Proceedings

Certain legal proceedings are discussed in “Business – Narrative Description of Business - Environmental Regulatory Matters”.

On March 30, 2001, Pozament Corp. filed a Summons and Complaint to be served on AES Westover, LLC, wherein it seeks to recover damages for breach of contract. The plaintiff alleges that it had an exclusive agreement with Westover to remove all of its coal flyash. We believe that the contract in question is unenforceable and void and intend to vigorously defend this claim. We feel that any award or settlement in this case would not materially affect our financial position or results of operations.

Item 4. Submission of Matters to a Vote of Security Holders

Not applicable.

PART II

Item 5. Market for our Company’s Common Equity and Related Stockholder Matters

All outstanding equity interests in our company are owned indirectly by The AES Corporation.

Item 6. Selected Financial Data

As of December 31,	2003		2002		2001		2000		1999

Balance Sheet Data (in millions)
Total assets	$	1,118	$	1,126	$	1,194	$	1,185	$	1,133
Long term liabilities	$	708	$	688	$	699	$	678	$	692
Partners’ capital	$	348	$	382	$	433	$	441	$	378

For the period ending December 31,	2003		2002		2001		2000		1999

Statement of Income Data (in millions)
Operating revenue	$	421	$	363	$	378	$	388	$	185
Operating income	$	148	$	114	$	106	$	151	$	57
Net income	$	89	$	59	$	52	$	98	$	24

SELECTED QUARTERLY FINANCIAL DATA

The following table summarizes the quarterly consolidated statements of income (in thousands):

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter

YEAR ENDED DECEMBER 31, 2003:
Operating revenue	$	107,803	$	97,917	$	118,132	$	96,864
Operating income	43,183		35,897		47,948		20,779
Net income before cumulative effect of change in accounting principle	29,248		—		—		—
Net income	27,592		21,659		33,490		6,325

YEAR ENDED DECEMBER 31, 2002:
Operating revenue	$	84,520	$	89,382	$	85,788	$	103,324
Operating income	25,700		31,718		18,755		38,035
Net income	11,854		17,917		3,279		25,580

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

The information in this Management’s Discussion and Analysis should be read in conjunction with the accompanying consolidated financial statements, the related Notes to the Financial Statements and the selected financial data. 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.

All four of our electricity generating stations operate as merchant plants, which means that we sell their output in power pool spot market transactions or in transactions negotiated from time to time directly with another party rather than selling the output under a long-term power sales contract. As merchant plants, our electricity generating stations generally will be dispatched, that is, they will supply electricity, whenever the market price of electricity exceeds their variable cost of generating electricity. Our energy revenue will be directly affected by the price of electricity, which is usually highest during the summer and winter peak seasons.

On February 19, 2002, The AES Corporation announced that it intended to reposition itself in the electric business by fully contracting or divesting its merchant generation businesses. The AES Corporation stated that it made this decision to reduce earnings volatility and strengthen its balance sheet. We are one of The AES Corporation’s merchant generating businesses. Subsequently, The AES Corporation has determined that our business will remain part of its portfolio, based on recent and expected performance.

The economics of any electric power facility are primarily a function of the price of electricity, the quantity of electricity which is purchased and the level of operating expenses. The greater the percentage of time a unit is dispatched, the greater the revenues associated with that unit.

The markets for wholesale electric energy, unforced capacity and ancillary services in the New York power market were largely deregulated in November 1999. In a competitive market where the order in which electricity generating plants are dispatched will be based on bids for the sale of electric energy by the generating assets in the region, we expect that the lower marginal cost facilities will bid lower prices and therefore those facilities will be dispatched more often than higher marginal cost facilities.

We believe that our electricity generating stations are among the lowest variable cost facilities in the New York power market. We also believe that our electricity generating stations are among the most efficient coal units in the region. We expect that our electricity generating stations will almost always be dispatched. The efficiency of our electricity generating stations provides several important advantages: a relatively stable pricing structure, the ability to benefit from energy price spikes in the market and relatively little risk that our electricity generating stations will be idle while other generating stations are directed to run.

Our electricity generating stations have historically been available to run a high percentage of the time due to the regulated utility-grade nature of their design and construction. In 2003, 2002 and 2001, the stations had a weighted average (based on capacity) equivalent availability factor of 93%, 96% and 96%, respectively (excluding the scheduled outage at Cayuga from April to June 2001 while an SCR was installed on Unit 1). We believe that we can maintain or improve the availability of our electricity generating stations.

We believe that we will also have opportunities to derive revenue from sales of unforced capacity and ancillary services. Under the terms of the New York Transition Agreement with NYSEG, NYSEG purchased all of our 1,268MW of installed capacity at a price of $68 per MW-day from May 14, 1999 through April 30, 2001. During the term of the New York Transition Agreement, the rules of the NYISO system required us to offer to sell our electric energy in the New York market for delivery of electric energy on the following day. Since termination of the New York Transition Agreement with NYSEG on April 30, 2001, we are permitted to sell unforced capacity through bilateral contracts or through unforced capacity auctions or into other markets. See “Business—New York Power Market.”

NYSEG has brought a proceeding to obtain a refund of real estate taxes it paid in connection with Somerset while NYSEG owned it. NYSEG had little incentive to contest the tax valuation of its electricity generating stations while it owned them because the real property taxes it paid were included among the expenses it was permitted to recover through regulated electricity rates and were therefore passed along to its customers.

If NYSEG is successful in obtaining substantial refunds of prior real estate taxes, local governments may be forced to raise real estate tax rates to bring revenues into balance with expenditures. It is too early to tell what impact, if any, this will have on our 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. Gains and losses, generated from the hedging of future sales using commodity forwards, swaps and options, reported in other comprehensive income, are reclassified to earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portions of the change in fair value of derivatives and the change in the fair value of derivatives not designated as hedges for accounting purposes are recognized in current period earnings. 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 Statement of Financial Accounting Standards (“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. 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 22 years. If the estimated average remaining life of our property, plant and equipment were to decrease by five years, annual depreciation would increase by $12.2 million. Maintenance and repairs are charged to expenses 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 may 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 electricity generating stations delivery points into the 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 criteria treatment. For the years ended December 31, 2003, 2002 and 2001 we recognized a loss of $6.2 million, income of $8.9 million and a loss of $29.5 million, respectively, pursuant to SFAS No. 133 related to derivatives which did not qualify for hedge accounting. See Note 7 of our audited financial statements, which are included in this Annual Report on Form 10-K for a more complete discussion of the accounting for derivatives under SFAS No. 133.

Results of Operations (Amounts in Millions) For the Year Ended December 31,	2003		2002		% Change		2001		% Change

Energy Revenue	$	388.9	$	310.6	25.2		$	345.4	(10.1	)

Capacity Revenue	29.7		36.6		(18.9	)	26.8		36.6

Transmission Congestion Contract	—		8.9		—		—		—

Other	2.2		6.9		(68.1	)	6.2		11.3

Energy revenues for the year ended December 31, 2003 were $388.9 million, compared to $310.6 million for the year ended December 31, 2002, an increase of 25.2%. The increase in energy revenues is primarily due to higher market prices and stable demand. Market prices for peak and offpeak electricity were 41.6% and 40.5% higher than the year ended December 31, 2002. Demand for peak and offpeak electricity was flat compared to demand for the year ended December 31, 2002. Energy revenues for the year ended December 31, 2002 were $310.6 million, compared to $345.4 million for the year ended December 31, 2001, a decrease of 10.1%. The decrease in energy revenues was primarily due to lower market prices and lower demand. Market prices for peak and offpeak electricity were 12.2% and 6.5% lower than the year ended December 31, 2001. Demand for peak and offpeak electricity was 3.2% and 1.7% lower than the year ended December 31, 2001. These were offset by a major maintenance outage at Cayuga of approximately 45 days for Unit 1 in 2001.

Capacity revenues for the year ended December 31, 2003 were $29.7 million, compared to $36.6 million for the year ended December 31, 2002, a decrease of 18.9%. The decrease in capacity revenue is primarily due to lower prices for capacity sales on the open market for both the summer and winter capacity period. Capacity revenues for the year ended December 31, 2002 were $36.6 million, compared to $28.6 million for the year ended December 31, 2001, an increase of 36.6%. The increase in capacity revenue was primarily due to higher prices for capacity sales on the open market for the summer capacity period (June — October) offset by the expiration of a long-term capacity contract in April 2001. Capacity sales on the open market for the winter capacity period (November-May) were at lower rates.

The foregoing market price and demand data were based on statistics obtained from the NYISO.

The Transmission Congestion Contract 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 Congestion Contract became effective on November 1, 2000 and terminates on October 1, 2004. We entered into this agreement because it provided a reasonable settlement for resolving a FERC dispute between us and Niagara Mohawk Power Corporation. This contract is not deemed to be a hedge based on the definitions in SFAS 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.

Operating Expenses For the Year Ended December 31,	2003		2002		% Change	2001		% Change

Fuel expense	$	148.3	$	137.2	8.1	$	135.6	1.2

Depreciation and amortization	36.1		35.5		1.7	33.6		5.7

Operations and maintenance	23.3		17.0		37.1	19.6		(13.3	)

General and administrative	59.2		59.1		0.2	53.7		10.1

Transmission Congestion Contract	6.2		—		—	29.5		—

Fuel expense for the year ended December 31, 2003 was $148.3 million, compared to $137.2 million for the year ended December 31, 2002, an increase of 8.1%. The increase in fuel expense is primarily due to higher operating levels, which necessitated greater coal usage and greater coal purchases on the spot market. Fuel expense for the year ended December 31, 2002 was $137.2 million, compared to $135.6 million for the year ended December 31, 2001, an increase of 1.2%. The increase in fuel expense was primarily due to higher coal prices offset by lower operating levels due to lower demand.

Depreciation and amortization expense for the year ended December 31, 2003 was $36.1 million, compared to $35.5 million for the year ended December 31, 2002, an increase of 1.7%. This increase is primarily due to the capitalization of a net asset of $3.3 million due to adoption of SFAS No. 143 at January 1, 2003. Depreciation and amortization expense for the year ended December 31, 2002 was $35.5 million, compared to $33.6 million for the year ended December 31, 2001, an increase of 5.7%. This increase was primarily due to a full year’s depreciation of the SCR system to reduce NOx emissions at Cayuga which was operational June 7, 2001.

Operations and maintenance expense for the year ended December 31, 2003 was $23.3 million, compared to $17 million for the year ended December 31, 2002, an increase of 37.1%. This increase is primarily due to maintenance expenses incurred during scheduled outages at every electricity generating station during 2003. Operations and maintenance expense for the year ended December 31, 2002 was $17 million, compared to $19.6 million for the year ended December 31, 2001, a decrease of 13.3%. This decrease was primarily due to maintenance expenses incurred during a scheduled outage at Cayuga in the second quarter of 2001, which are not annually recurring expenses.

General and administrative expense for the year ended December 31, 2003 was $59.2 million, compared to $59.1 million for the year ended December 31, 2002, an increase of 0.2%. General and administrative expense for the year ended December 31, 2002 was $59.1 million, compared to $53.7 million for the year ended December 31, 2001, an increase of 10.1%. This increase was primarily due to significant increases in property taxes and property and medical insurance which were partially offset by reversal of accruals for potential environmental liabilities which were resolved at a lower cost than estimated.

Other Income/Expenses For the Year Ended December 31,	2003		2002		% Change	2001		% Change

Interest expense	$	59.1	$	57.7	2.4	$	58.4	(1.2	)

Interest Income	2.1		2.1		—	3.9		(46.2	)

Other Income/Expenses for the year ended December 31, 2003 were net expenses of $57 million, compared to net expenses of $55.6 million for the year ended December 31, 2002, an increase of 2.5%. This increase is primarily due to higher interest expense. The interest expense on the lease obligations were set at the issuance and our established amortization schedule does not follow a typical schedule. Other Income/Expenses for the year ended December 31, 2002 were net expenses of $55.6 million, compared to net expenses of $54.5 million for the year ended December 31, 2001, a decrease of 2.0%. This decrease is primarily due to lower cash balances and lower market interest rates.

Liquidity and Capital Resources

Operating Activities

Net Cash provided by operating activities of $128.1 million for the year ended December 31, 2003, reflects the increase in net income due to increased electricity prices and increased add back of non-cash expenses offset in part by the changes in current assets and liabilities.

Investing Activities

Net cash used in investing activities of $12 million for the year ended December 31, 2003 reflects an increase in our restricted cash accounts of $6.6 million and approximately $5.4 million in capital expenditures.

We incurred approximately $5.4 million, $7.1 million and $17.1 million in capital expenditures with regard to our assets for the years ended December 31, 2003, 2002 and 2001, respectively. These amounts include $1.4 million for the overfire air project to reduce NOx emissions at Westover Unit 8 in 2003 and approximately $11.2 million for a SCR system to reduce NOx emissions at Cayuga Unit 1 which was operational June 7, 2001. 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 and operating costs. Based on the current status of regulatory requirements, 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, 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 expenditures for studies, and capital and operating expenses to bring the electricity generating stations into compliance with the new federal cooling water intake standards, we do not anticipate that any capital expenditures or operating expenses associated with our compliance with current laws and regulations will have a material effect on our operations or our financial condition. See “Business—Regulation—Environmental Regulatory Matters.”

Financing Activities

Net cash used in financing activities for the year ended December 30, 2003 of $116.4 million reflects principal payments on our leases of $1.6 million, payment of a distribution to our partners of $114.6 million and payments for deferred financing of $335,000 offset by a Partner’s contribution of $162,000.

The leases for Somerset and Cayuga require that we make fixed semiannual payments of rent on each January 2 and July 2 during the terms of the leases commencing on January 2, 2000 in amounts calculated to be sufficient (1) to pay principal and interest when due on the secured lease obligation notes issued by the special purpose business trusts that own and lease to us Somerset and Cayuga and (2) to pay the economic return of the institutional investors that formed the special purpose business trusts. Our minimum rent obligation under

the leases is $63.5 million for 2004, $59.5 million for 2005, $61.6 million for 2006, $62.5 for 2007, $62.5 for 2008 and a total of $1,189.7 million for the years thereafter. For purposes of the minimum rent obligations described in the preceding sentence, we treated the semiannual rent payments that are due on January 2 of each year as though they would be paid in the preceding year. You can find information concerning our minimum rental obligations that treats rent payments as obligations for the years in which they are due in Note 6 of our audited financial statements, which are included in this Annual Report on Form 10-K. Through July 2, 2020, and so long as no lease event of default exists, we may defer payment of rent obligations under each lease in excess of the amount required to pay principal and interest on the secured lease obligation notes until after the final scheduled payment date of the secured lease obligation notes. As of December 31, 2003, we have not deferred any portion of our lease obligations. In addition, we are required to maintain a rent reserve account equal to the maximum semiannual payment with respect to the sum of basic rent (other than deferrable basic rent) and fixed charges expected to become due on any one basic rent payment date in the immediately succeeding three-year period. At December 31, 2003 and 2002, the amounts deposited in the rent reserve account were $31.7 million and 31.7 million, respectively.

We are also obligated to make payments under the coal hauling agreement with Somerset Railroad in an amount sufficient, when added to funds available from other sources, to enable Somerset Railroad to pay, when due, all of its operating expenses and other expenses, including interest on and principal of outstanding indebtedness. On August 14, 2000, Somerset Railroad 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 Somerset Railroad by an affiliate of CIBC World Markets. The 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.

As a result of these obligations, we must dedicate a substantial portion of our cash flow from operations to payments of rent under the leases, payments under our working capital facility and payments under the coal hauling agreement with Somerset Railroad, which in turn allow Somerset Railroad to pay principal and interest under its credit facility with Fortis Capital Corp. The principal payments for the $26 million credit facility are $1.9 million per year.

At March 9, 2001, our $50 million Credit Suisse First Boston working capital credit facility was terminated. In April 2001, we entered into a $35 million secured revolving working capital and letter of credit facility with Union Bank of California, N.A. This facility had a term of approximately twenty-one months. We could borrow up to $35 million for working capital purposes under this facility. In addition, we could have letters of credit issued under this facility up to $25 million, provided that the total amount of working capital borrowings and letters of credit issuances may not exceed the $35 million limit on the entire facility. Through November 20, 2002, we made three borrowings under this facility. The first borrowing was for $7 million on July 13, 2001 at an interest rate of 8.125% and was repaid in full on July 31, 2001. The second borrowing was for $8.5 million on January 11, 2002 at an interest rate of 6.125% and was repaid in full on February 28, 2002. The third borrowing was for $14.0 million on July 9, 2002, at an interest rate of 6.125% and was repaid in full in two installments: $7.2 million on July 31, 2002 and $6.8 million on August 28, 2002.

On November 20, 2002, we signed an agreement with Union Bank of California, N.A. for a one-year extension of the working capital and letter of credit facility. On April 16, 2003, we signed an amendment to our 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, 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 the facility. There have been four borrowings under this facility. The first borrowing was for $9.7 million on January 10, 2003 at an interest rate of 5.75%. This borrowing was repaid in full on January 28, 2003. The second borrowing was for $9.7 million on July 9, 2003 at an interest rate of 5.5%. This borrowing was repaid in full on July 25, 2003. The third borrowing was for $12.9 million on January 9, 2004 at an interest rate of 5.5%. This borrowing was repaid in full in two installments: $6.2 million on January 27, 2004 and $6.7 million on February 26, 2004. The fourth borrowing was for $1 million on February 20, 2004 at an interest rate of 5.5%. This borrowing was repaid in full on February 26, 2004. At the date of filing of our Annual Report on Form 10-K, of the $35 million committed, we had obtained letters of credit of $24.9 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 for the years of 2003 and 2004, respectively.

On February 12, 2004, we signed a two-year agreement, effective January 1, 2004, with The AES Corporation to obtain up to $35 million and $25 million of letters of credit or cash collateral for 2004 and 2005, respectively. This agreement supercedes the authorization of The AES Corporation on February 25, 2003. The agreement limits the letters of credit amounts and cash collateral to the stated amounts and set into place a fee structure and repayment terms. At the date of filing of our Annual Report on Form 10-K, we have obtained letters of credit in the amount of $33 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

Our future ability to obtain additional debt financing for working capital, capital expenditures or other purposes is limited by financial covenants restricting our ability to incur debt and liens contained in the agreements governing the leases of Somerset and Cayuga. With certain exceptions, these agreements limit us to a maximum of $100 million of indebtedness, including no more than $25 million of indebtedness for purposes other than to provide working capital.

Cash flow from our operations was sufficient to cover aggregate rental payments under the leases for Somerset and Cayuga on the rent payment dates of January 2, 2001, July 2, 2001, January 2, 2002, July 2, 2002, January 2, 2003, July 2, 2003 and January 2, 2004. We believe that cash flow from our operations will be sufficient to cover aggregate rental payments on each rent payment date thereafter. We also believe that our cash flow from operations, together with amounts we can borrow under our $35 million working capital and letter of credit facility with Union Bank of California, N.A., will be sufficient to cover expected capital requirements over the terms of the leases. If we are required to make unanticipated capital expenditures, our cash flow from operations and operating income in the period incurred would be reduced.

The outage at Cayuga for almost the entire period from March 31, 2001 to June 4, 2001 did not impair our ability to meet our obligations during this period. Subsequent to this outage, our four electricity generating stations are all available for service and are being dispatched to generate electricity when market conditions warrant.

The agreements governing the leases of Somerset and Cayuga and our working capital credit facility impose severe restrictions on our ability to make distributions of cash or other assets to our owners and on the ability of our owners to withdraw cash or other assets from us. These restrictions are intended to assure that we have paid all of our operating and maintenance expenses and all of our obligations under our leases and under our working capital credit facility before any assets are distributed to or withdrawn by our owners. We may make a distribution to our owners on or within ten business days after a rent payment date for the Somerset and Cayuga leases so long as the following conditions are satisfied:

(1) all rent under the leases for Somerset and Cayuga, including deferrable payments, must have been paid to date;

(2) amounts on deposit or deemed on deposit in the rent reserve account and the additional liquidity account established in connection with the pass through trust certificates issued to finance the acquisition of Somerset and Cayuga must be equal to or greater than the rent reserve account required balance or the additional liquidity required balance, as applicable;

(3) no lease material default, lease event of default or event of default under any permitted indebtedness shall have occurred and be then continuing;

(4) no amounts may be outstanding under the working capital credit facility;

(5) we have no indemnity currently due and payable under specified provisions of the participation agreements relating to the Somerset and Cayuga leases or any other operative document or any obligation to fund the indemnity accounts (as defined in the leases) under the leases;

(6) the coverage ratios for each of the two semiannual rent payment periods immediately preceding the rent payment date (based on actual operating history) must

be equal to or greater than the required coverage ratio and the pro forma coverage ratios for each of the four semiannual periods immediately succeeding this rent payment date must be equal to or greater than the required coverage ratio;

(7) with respect to the Somerset Railroad credit facility or any replacement facility, no event of default shall have occurred and be then continuing under the facilities and the remaining term of the Somerset Railroad credit facility or any replacement facility shall not be less than 30 days.

The AES Corporation contributed approximately $162,000, $1.5 million and $9.4 million to us in 2003, 2002 and 2001, respectively. The contributions which were accounted for as a partner’s contribution, related to stock option compensation expense in 2003 and the construction of the SCR on Unit 1 of Cayuga, which became operational on June 7, 2001.

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.

On October 3, 2002, Standard & Poor’s lowered its rating on our $550 million pass though trust certificates issued to finance the acquisition of Somerset and Cayuga and $35 million working capital and letter of credit facility to BB+ from BBB- solely due to our rating linkage to The AES Corporation. The rating was also placed on CreditWatch with negative implications. In a press release announcing the ratings downgrade of our debt, Standard & Poor’s noted that in most circumstances, it will not rate the debt of a wholly owned subsidiary higher than the rating of the parent. Even though we believe that the provisions of our financing arrangements render us bankruptcy remote from The AES Corporation, Standard & Poor’s stated that it did not view these provisions as 100% preventative of the risk of substantive consolidation in the event of a bankruptcy of The AES Corporation. Therefore, Standard & Poor’s limited the rating differential provided by such structural elements to three notches and stated that our credit ratings cannot be higher than BB+.

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 were not posted, our ability to continue transacting business as before the downgrade would be impaired. In response to an earlier downgrade of The AES Corporation, one of our coal suppliers requested credit assurance based on a clause specific to their contact. After discussions with the supplier, we negotiated an agreement for a prepayment system with a discounted price. This agreement expired on December 31, 2002 and was not renewed. On October 8, 2002, one of our counterparties made a $1 million margin call on us because of the Standard & Poor’s downgrade. We provided a letter of credit for $1 million.

As of the date of filing this Annual Report on Form 10-K, the pass through trust certificates issued to finance the acquisition of Somerset and Cayuga carry a non-investment grade rating (BB+) from Standard & Poor’s Ratings Services and Fitch IBCA, Inc. ratings agencies and a non-investment grade rating (Ba1) from Moody’s Investors Service, Inc. rating agency.

Pension Plan

Effective May 14, 1999, we adopted The Retirement Plan for Employees of AES NY, L.L.C. (the Plan), a defined benefit pension plan. The Plan covers people employed both under collectively bargained and non-collectively bargained arrangements. Certain people formerly employed by NYSEG (the Transferred Persons) receive credit under the Plan for compensation and service earned while being employed by NYSEG. The amount of any benefit payable under the Plan to a Transferred Person will be offset by the amount of any benefit payable to such Transferred Person under the Retirement Plan for Employees of NYSEG. Effective May 29, 1999, the ability to commence participation in the Plan and the accrual of benefits under the Plan ceased with respect to non-collectively bargained people and the accrued benefits of any such participant were fixed as of such date. As of December 31, 2003, the Plan was funded at least to the extent required by Internal Revenue Code (IRC) Section 412 minimum funding and not more than the requirement of IRC Section 404, maximum contribution limits. We will make at least the required minimum contribution within the Employee Retirement Income Security Act (ERISA) guidelines. Pension benefits are based on the number of years of credited service, age of the participant, and average earnings. During 2003, 2002, and 2001, collectively bargained people were offered the opportunity to freeze their accrued benefit payable under the Plan and opt into the AES Profit Sharing and Stock Ownership Plans.

The assets and liabilities of the Plan were valued as of October 31, 2003 and 2002. This measurement date is a change from the previous practice of utilizing a December 31 measurement date for 2001. The values of the assets and liabilities as of October 31, 2003 and 2002 were not materially different than the values as of December 31, 2003 and 2002.

Significant assumptions were used in the calculations of the net benefit cost and projected benefit obligation for the periods ending October 31, 2003 and 2002 and December 31, 2001. In developing our expected long-term rate of return assumption, we evaluated input from our actuaries and plan asset manager. Projected returns are based on a broad range of equity and bond indices. Our expected 8% long-term rate of return on Qualified Plan assets is based on the allocation assumption of 60% equities (50% Growth and 50% Value), with a 10% long term rate of return and 40% in fixed income investments, with a 5.5% long-term rate of return. Because of market fluctuation, our actual allocation was 58% and 52% equities and 42% and 48% in fixed income investments as of October 31, 2003 and 2002, respectively. However, we believe that our long-term asset allocation on average will approximate 60% equities and 40% fixed income investments. We regularly review the asset allocation with the asset manager and periodically rebalance the Plan’s investments to its targeted allocation when appropriate. We continue to believe that 8% is a reasonable long-term rate of return on our qualified plan assets. We will continue to evaluate our actuarial assumptions, including the expected rate of return, at least annually, and will adjust as necessary.

The Plan bases its determination of pension expense or income on the fair value of assets on the measurement date. As of October 31, 2003, the Plan has generated cumulative unrecognized net actuarial gains of approximately $1.1 million which remain to be recognized in pension cost. These unrecognized net actuarial gains result in increase in future pension income depending on several factors, including whether such losses at each measurement date exceed the corridor in accordance with SFAS No. 87, “Employers Accounting for Pensions”.

The discount rate that we utilize for determining future pension obligations is based on the rates at which we would expect insurance companies to settle future liabilities. The discount rate has remained at 6.25% since 2001. Future actual pension expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in our pension plans.

The fair value of the Plan’s assets has increased from $7.2 million at October 31, 2002 to $9.4 million at October 31, 2003. The 2003 cash contributions to the Plan of approximately $2.2 million and investment performance gains of approximately $933,000, were partially offset by benefits paid during 2003 of approximately $830,000. We believe we will continue to be required to make cash contributions to the Plan for at least the next three years.

New Accounting Pronouncements

Asset Retirement Obligations. In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143, which was 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 was recorded in the first quarter of 2003, the entity was required to 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 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 $3.3 million, which are included in the electric generation assets, and reversed an approximately $4.2 million environmental remediation liability we had previously recorded. (See Note 3 of our audited financial statements, which are included in this Annual Report on Form 10-K). The difference between the amounts previously recorded and the net SFAS No. 143 liability is a loss recorded as the cumulative effect of this change in accounting principle of approximately $1.7 million. Reconciliation of the asset retirement obligation liability for the year ended December 31, 2003 was as follows (in millions):

Balance as of January 1, 2003	$	9.2
Accretion	$	0.7

Balance, December 31, 2003	$	9.9

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 were 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 should 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 the 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 adoption of SFAS No. 149 did not have a material impact on our financial position or results of operations.

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 Financial Accounting Standards Board (the FASB) issued Interpretation No. 46, “Consolidation of Variable Interest Entities” which provides guidance on how to identify a variable interest entity (VIE), and when the assets, liabilities, noncontrolling interests and results of operations of a VIE need to be included in a company’s consolidated financial statements. This interpretation was revised in December 2003 with the issuance of Interpretation No. 46(R), “Consolidation of Variable Interest Entities” (FIN 46(R)).

In general, a VIE is an entity that lacks sufficient equity or its equity holders lack adequate decision making ability. If either of these characteristics is present, the entity is subject to a variable interests consolidation model, and consolidation is based on variable interests, not on ownership of the entity’s outstanding voting stock. Variable interests are defined as contractual, ownership, or other money interests in an entity that change with fluctuations in the entity’s net asset value. The primary beneficiary consolidates the VIE; the primary beneficiary is defined as the enterprise that absorbs a majority of expected losses or receives a majority of residual returns (if the losses or returns occur), or both.

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 purposes of our financial statements, which they have been from our inception. We are considering the applicability of consolidating Somerset Railroad. If we did so our consolidated Balance Sheet as of December 31, 2003, would reflect additional assets of approximately $28.4 million and liabilities of approximately $19.6 million.

In May 2003, the FASB adopted SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”. This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this pronouncement will not have a material effect on our financial position or results of operations.

In December 2003, the Financial Accounting Standards Board issued SFAS No. 132 (revised 2003), “Employers’ Disclosure About Pensions and Other Postretirement Benefits”, which amends SFAS No. 87, “Employers’ Accounting for Pensions”, SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits”, and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”, and replaces SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (collectively referred to as “SFAS No. 132 (revised)”) .. SFAS No. 132 (revised) expands employers’ disclosures about pension and other post-retirement benefit plans to present more information regarding the economic resources and obligations of such plans in terms of the plans’ assets, obligations, cash flows and net periodic benefit costs. Additionally, SFAS No. 132 (revised) requires interim-period disclosures regarding plan benefit costs and material plan changes. We are required to adopt the new annual disclosure requirements of SFAS No. 132 (revised) effective as of December 31, 2003. The interim-period disclosure requirements will be effective for us as of March 31, 2004. As SFAS No. 132 (revised) does not change the measurement or recognition of pension and other post-retirement benefit plans as required by SFAS No. 87, SFAS No. 88 and SFAS No. 106, adoption of this new standard will have no effect on our consolidated financial statements.

Contractual Obligations

Below is a summary of certain obligations that will require significant capital(in thousands):

Contractual Obligations	Total	Less then 1 year	2-3 years	3-5 years	After 5 years
Debt Obligations	25,150	2,396	4,790	4,790	13,174
Capital Lease Obligations (1)	1,500,942	63,989	122,009	125,278	1,189,677
Operating Lease Obligations	—	—	—	—	—
Purchase “Take-or-Pay” Obligations	140,040	86,951	53,089	—	—
Other Long-term Obligations reflected on Balance Sheet	20,987	7,234	8,209	5,544	—
TOTAL	1,687,119	160,570	188,097	135,612	1,202,851

(1) Capital Lease Obligations includes imputed interest.

Future Issues and Other Matters

Certain Future Issues and Other Matters are discussed in “Business – Narrative Description of Business – Environmental Matters”

Forward-looking Statements

Certain statements contained in this Annual Report on Form 10-K 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 “believes,” “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—General Development of Business” in this Annual Report on Form 10-K, and you are urged to consider carefully such factors.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks associated with commodity prices. We often utilize financial instruments to hedge against such fluctuations. We utilize financial and commodity derivatives for the purpose of hedging exposures to market risk. We do not enter into derivative instruments for trading or speculative purposes.

We are exposed to the impact of market fluctuations in the prices of electricity and coal. Our current and expected future revenues are derived from wholesale energy sales without significant long-term revenue or supply contracts. Our results of operations are subject to the volatility of electricity and coal prices in competitive markets. We hedge certain aspects of our “net open” positions. We have used a hedging strategy, where appropriate, to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of this strategy involves the use of commodity forward contracts, swaps and options.

We adopted a value at risk (VaR) approach to assess and manage risk. VaR measures the potential loss in a portfolio’s value due to market volatility, over a specified time horizon, stated with a specific degree of probability. The quantification of market risk using VaR provides a consistent measure of risk across diverse markets and instruments. The VaR approach was adopted because we feel that statistical models of risk measurement, such as VaR, provide an objective, independent assessment of our risk exposure. The use of VaR requires a number of key assumptions, including the selection of a confidence level for expected losses, the holding period for liquidation and the treatment of risks outside the VaR methodology, including liquidity risk and event risk. VaR, therefore, is not necessarily indicative of actual results that may occur.

The use of VaR allows us to compare risk on a consistent basis and identify the drivers of risk. Because of the inherent limitations of VaR, including those specific to the variance/covariance approach, specifically the assumption that values or returns are normally distributed, we rely on VaR as only one component in our risk assessment process. In addition to using VaR measures, we perform Cash Flow at Risk, stress and scenario analyses to estimate the economic impact of market changes on the value of our portfolios. These results are used to supplement the VaR methodology.

We perform our VaR calculation using a model based on the variance/covariance methodology with a delta gamma model for optionality. We express VaR as a dollar amount of the potential loss in the fair value of our portfolio based on a 95% confidence level and a one-day holding period. Our daily VaR for commodity price sensitive instruments as of December 31, 2003, 2002 and 2001 was $5.8 million, $4.8 million and $6.2 million, respectively. These amounts include the financial instruments that serve as hedges and do not include the underlying physical assets. In the year ended December 31, 2003, the daily VaR amount was greater than the year-end amount on March 31, and June 30, 2003. During 2002, the daily VaR amount was greater than the year-end amount at the end of each quarter in 2002. In the year ended December 31, 2001, the daily VaR amount was greater than the year-end amount on June 29, and September 28, 2001.

Item 8. Financial Statements and Supplementary Data

The following financial statements are attached to this Annual Report on Form 10-K following the signature page:

AES EASTERN ENERGY, L.P.

Independent Auditors’ Report

Financial Statements:

Consolidated Balance Sheets as of December 31, 2003 and 2002
Consolidated Statements of Income for the years ended December 31, 2003, 2002 and 2001.
Consolidated Statements of Changes in Partners’ Capital for the years ended December 31, 2003, 2002 and 2001.
Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001.
Notes to Consolidated Financial Statements

AES NY, L.L.C. (General Partner of AES Eastern Energy, L.P.)*

Independent Auditors’ Report

Financial Statements:

Consolidated Balance Sheets as of December 31, 2003 and 2002
Notes to Consolidated Balance Sheets

* The Consolidated Balance Sheets of AES NY, L.L.C. contained in this Annual Report on Form 10-K should be considered only in connection with its status as the general Partner of AES Eastern Energy, L.P.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. 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 December 31, 2003, our disclosure controls and procedures were effective and designed to ensure that information required to be disclosed by us and our consolidated subsidiaries in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Changes in Internal Control Over Financial Reporting. There have been no 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 materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART III

Item 10. Directors and Executive Officers of Our Company

We are a Delaware limited partnership. Under the Delaware Revised Uniform Limited Partnership Act and our Agreement of Limited Partnership, the general partner of our company, AES NY, L.L.C., manages our business and affairs. Our managers are appointed by AES NY, L.L.C., as general partner of our company. Our managers may be appointed from time to time by AES NY, L.L.C. and hold their positions at the discretion of AES NY, L.L.C. AES NY, L.L.C. may elect to appoint additional managers from time to time. The AES Corporation indirectly owns all member interests in and controls AES NY, L.L.C.

The following table sets forth certain information concerning our management team as of March 15, 2004.

Name	Age	Position

Dan Rothaupt	52	General Manager
Kevin Pierce	46	AEE Business Leader and Somerset Plant Manager
Jerry Goodenough	39	Cayuga Plant Manager
James Mulligan	55	Westover Plant Manager
Douglas Roll	48	Greenidge Plant Manager
Amy Conley	30	Chief Financial Officer

Dan Rothaupt, has served as Vice President of The AES Corporation responsible for North America — East Operations since May 2003. Previously, he was President and Group Manager for AES Endeavor, covering AES business activities in the Northeast US and Canada and has been our general manager since May 1999. Prior to that he was the President and Plant Manager of AES Thames from 1995 to 1999. Mr. Rothaupt has a Bachelor of Science degree in Mechanical Engineering from the United States Coast Guard Academy.

Kevin Pierce has served as AEE Business Leader and President and Plant Manager of Somerset since August 2003, and prior to that as President and Plant Manager of Somerset since September 2001. Previously, he was President and Plant Manager of AES Hawaii from June 1998 until September 2001. Mr. Pierce has a Bachelor of Science degree in Marine Engineering from Maine Maritime Academy.

Jerry Goodenough has served as President and Plant Manager of Cayuga since March 2001. Previously, he was the Cayuga control room team leader from April 1999 to March 2001. From January 1998 to March 2001, he was employed by NYSEG in a variety of engineering supervisory roles. Mr. Goodenough holds a Bachelor of Arts degree in Physics from Ithaca College and a Master of Science degree in Electrical Engineering from the State University of New York at Binghamton.

James Mulligan has served as President and Plant Manager of Westover since May 1999. Previously, Mr. Mulligan was employed as the Milliken Station Manager under NYSEG from January 1997 to May 1999. Mr. Mulligan has a Bachelor of Science degree in Mechanical Engineering from the New York Institute of Technology.

Douglas J. Roll has served as President and Plant Manager of Greenidge since May of 1999. Previously, Mr. Roll was employed as the Greenidge Station Manager under NYSEG from March 1994 to May 1999. Mr. Roll is a registered Professional Engineer in the State of New York. Mr. Roll holds a Bachelor of Science degree in Mechanical Engineering from Cornell University and a Bachelor of Arts degree in Biology from Queens College of the City University of New York.

Amy Conley has served as the Chief Financial Officer for AES Eastern Energy and AES NY, L.L.C. since June 2001. Previously, Ms. Conley was employed as the Somerset Plant Accountant from January 2000 to June 2001. Ms. Conley is a Certified Public Accountant. Ms. Conley holds a Bachelor of Science degree in Accounting from St. John Fisher College and a Master of Business Administration degree from Rochester Institute of Technology.

Management of AES NY, L.L.C., the General Partner of Our Company

AES NY, L.L.C., the general partner of our company, is a Delaware limited liability company managed by managers who are designated as directors. The Board of Directors of AES NY, L.L.C. comprises two classes of directors, the Class A Directors and the Class B Director. There are three Class A Directors, Edward Convery, Kevin Pierce and Dan Rothaupt, each elected by the members of the limited liability company. The business and affairs of AES NY, L.L.C. are managed by the Class A Directors. The Class B Director’s only participation in the management of AES NY, L.L.C. is in matters of bankruptcy or related matters. Mr. Rothaupt is also the President of AES NY, L.L.C.

Edward Convery has 24 years experience in the power and chemicals industries, and has worked for The AES Corporation for 11 years. Mr. Convery is the Business Leader for the AES Warrior Run and the AES Beaver Valley facilities which supply power to Allegheny Energy. Mr. Convery was responsible for the start-up and operations of the AES Warrior Run facility. Mr. Convery has a Bachelor of Science degree in Chemical Engineering from the University of Delaware.

Item 11. Executive Compensation

Not Applicable.

Item 12. Security Ownership of Certain Beneficial Owners and Management

Not Applicable.

Item 13. Certain Relationships and Related Transactions

Not Applicable.

Item 14. Principal Accounting Fees and Services

The aggregate fees billed for each of the last two fiscal years for professional services rendered by the principal accountant for the audit of our annual financial statements and review of the financial statements included in our Form 10-Q (17CRF249.308a) for services that are normally provided by the accountant in connection

with statutory and regulatory filings or engagements for those fiscal years were approximately $335,000 and $329,000 for the years ended December 31, 2003 and 2002, respectively.

There were no other fees paid to the principal accountant for the years ended December 31, 2003 and 2002.

The registrant’s board of directors served as its audit committee. All audit and non-audit services to be provided to the registrant by its principal accountant are approved by the board of directors. No pre-approval policies are in place.

PART IV

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a) Financial Statements, Financial Statement Schedules and Exhibits.

(1) The following financial statements are attached to this Annual Report on Form 10-K following the signature page and certifications:

AES EASTERN ENERGY, L.P.

Independent Auditors’ Report

Financial Statements:

Consolidated Balance Sheets as of December 31, 2003 and 2002
Consolidated Statements of Income for the years ended December 31, 2003, 2002 and 2001
Consolidated Statements of Changes in Partners’ Capital for the years ended December 31, 2003, 2002 and 2001
Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001
Notes to Consolidated Financial Statements

AES NY, L.L.C. (General Partner of AES Eastern Energy, L.P.)*

Independent Auditors’ Report

Financial Statements:

Consolidated Balance Sheets as of December 31, 2003 and 2002
Notes to Consolidated Balance Sheets

(2) Financial Statement Schedules

Schedules are omitted as the information is either not applicable, not required or has been furnished in the financial statements or notes thereto included in this Annual Report on Form 10-K.

(3) Exhibits

Exhibit No.		Description

3.1		Certificate of Limited Partnership of AES Eastern Energy, L.P.*

3.2		Agreement of Limited Partnership of AES Eastern Energy, L.P., dated as of May 4, 1999*

4.1		Form of 9.0% Series 1999-A Pass Through Certificate*

4.2		Form of 9.67% Series 1999-B Pass Through Certificate*

4.3a		Pass Through Trust Agreement A, dated as of May 1, 1999, between AES Eastern Energy, L.P. and

		Bankers Trust Company, as Pass Through Trustee, made with respect to the formation of the Pass Through Trust, Series 1999-A and the issuance of 9.0% Pass Through Certificates, Series 1999-A*

4.3b		Schedule identifying substantially identical agreement to Pass Through Trust Agreement constituting Exhibit 4.3a hereto*

4.4a		Participation Agreement (Kintigh A-1), among AES Eastern Energy, L.P., as Lessee, Kintigh Facility Trust A-1, as Owner Trust, DCC Project Finance Fourteen, Inc., as Owner Participant, Bankers Trust Company, as Indenture Trustee, and Bankers Trust Company, as Pass Through Trustee, dated as of May 1, 1999*

4.4b		Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.4a hereto*

4.5a		Participation Agreement (Milliken A-1), among AES Eastern Energy, L.P., as Lessee, Milliken Facility Trust A-1, as Owner Trust, DCC Project Finance Fourteen, Inc., as Owner Participant, Bankers Trust Company, as Indenture Trustee, and Bankers Trust Company, as Pass Through Trustee, dated as of May 1, 1999*

4.5b		Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.5a hereto*

4.6a		Facility Lease Agreement (Kintigh A-1), between Kintigh Facility Trust A-1, as Lessor, and AES Eastern Energy, L.P., as Lessee, dated as of May 1, 1999*

4.6b		Schedule identifying substantially identical agreements to Facility Lease Agreement constituting Exhibit 4.6a hereto*

4.7a		Facility Lease Agreement (Milliken A-1), between Milliken Facility Trust A-1, as Lessor, and AES Eastern Energy, L.P., as Lessee, dated as of May 1, 1999*

4.7b		Schedule identifying substantially identical agreements to Facility Lease Agreement constituting Exhibit 4.7a hereto*

4.8a		Indenture of Trust and Security Agreement (Kintigh A-1), between Kintigh Facility Trust A-1, as Owner Trust, and Bankers Trust Company, as Indenture Trustee, dated as of May 1, 1999*

4.8b		Schedule identifying substantially identical agreements to Indenture of Trust and Security Agreement constituting Exhibit 4.8a hereto*

4.9a		Indenture of Trust and Security Agreement (Milliken A-1), between Milliken Facility Trust A-1, as Owner Trust, and Bankers Trust Company, as Indenture Trustee, dated as of May 1, 1999*

4.9b		Schedule identifying substantially identical agreements to Indenture of Trust and Security Agreement constituting Exhibit 4.9a hereto*

4.10		[Reserved]

4.11		Registration Rights Agreement, between AES Eastern Energy, L.P., and Morgan Stanley & Co. Inc., Credit Suisse First Boston Corp. and CIBC World Markets Corp., dated as of May 11, 1999*

4.12		[Reserved]

4.13		[Reserved]

10.1		Asset Purchase Agreement, among NGE Generation, Inc., New York State Electric & Gas Corporation (“NYSEG”), and AES NY, L.L.C. (“AES NY”), dated as of August 3, 1998, (incorporated herein by reference to exhibit 10.2 of the Annual Report on Form 10-K of Energy East Corp. for the year ended December 31, 1998 filed on March 29, 1999, SEC file #001-14766)

10.2a		Milliken Operating Agreement, between AES NY and NYSEG, dated as of August 3, 1998*

10.2b		Amendment No. 1 to the Milliken Operating Agreement, dated as of May 6, 1999*

10.3a		Interconnection Agreement, between AES NY and NYSEG, dated as of August 3, 1998*


10.3b		Amendment No. 1 to the Interconnection Agreement, dated as of May 6, 1999*

10.4		Interconnection Implementation Agreement, between NYSEG and AES NY, dated as of May 6, 1999*

10.5		Standard Bilateral Power Sales Agreement and Transaction Agreement, between AES Eastern Energy and NYSEG Solutions, Inc., dated as of May 14, 1999*

10.6		Scheduling and Settlement Agreement, among NYSEG, AES Creative Resources, L.P., AES Eastern Energy and EME Homer City Generation, dated as of March 18, 1999*

10.7		Agreement to Assign Transmission Rights and Obligations, between AES NY and NYSEG, dated as of August 3, 1998*

10.8		[Reserved]

10.9a		Reciprocal Easement Agreement (Kintigh Station), between AES NY and NYSEG, dated as of August 3, 1998*

10.9b		Reciprocal Easement Agreement (Milliken Station), between AES NY and NYSEG, dated as of August 3, 1998*

10.9c		Reciprocal Easement Agreement (Greenidge Station), between AES NY and NYSEG, dated as of August 3, 1998*

10.9d		Reciprocal Easement Agreement (Goudey Station), between AES NY and NYSEG, dated as of August 3, 1998*

10.10		Coal Sales Agreement, among NYSEG, Consolidation Coal Company, CONSOL Pennsylvania Coal Company, Nineveh Coal Company, Greenon Coal Company, McElroy Coal Company and Quarto Mining Company, dated as of November 1, 1983*


10.11a		Coal Supply Agreement, between NYSEG and United Eastern Coal Sales Corporation, dated as of January 12, 1998*

10.11b		Amendment No. 1 to Coal Sales Agreement, dated as of February 20, 1998*


10.12		Coal Supply Agreement, between NYSEG and Eastern Associated Coal Corporation, dated as of July 1, 1994*

10.13		Coal Hauling Agreement, among Somerset Railroad Corporation, AES NY3, L.L.C., and AES Eastern Energy L.P., dated as of May 6, 1999*

10.14		Scheduling and Settlement Agreement, among CSX Transportation, Inc., Norfolk Southern Corporation, Norfolk Southern Railway Company and NYSEG, dated as of February 20, 1998*

10.15		[Reserved]

10.16		Kintigh Turbine Agreement among NGE, NYSEG and AES Eastern Energy L.P. dated April 13, 1999*

10.17		Omnibus Agreement, between NYSEG and AES NY, dated as of May 7, 1999*

10.18		Assignment and Assumption Agreement, among NGE, NYSEG and AES NY, dated as of May 14, 1999*

10.19		Amended and Restated Deposit and Disbursement Agreement among AEE, Union Bank of California, N.A., as Agent under the Working Capital Facility, as Working Capital Provider, and Bankers Trust Company, as Depositary Agent, et al., dated as of April 10, 2001.**

10.20		[Reserved]

10.21a		Omnibus Amendment to Kintigh A-1 Transaction Documents dated as of December 1, 2000

10.21b		Schedule identifying substantially identical agreements to Omnibus Agreement constituting Exhibit 10.21a hereto

10.22a		Omnibus Amendment to Milliken A-1 Transaction Documents dated as of December 1, 2000

10.22b		Schedule identifying substantially identical agreements to Omnibus Agreement constituting Exhibit 10.22a hereto

10.23a		Agreement and Appendix A dated as of April 10, 2001**

10.23b		Schedule identifying substantially identical agreements to Second Amendment constituting Exhibit 10.23a hereto**

10.24a		Second Amendment to Milliken A-1 Participation Agreement and Appendix A dated as of April 10, 2001**

10.24b		Schedule identifying substantially identical agreements to Second Amendment constituting Exhibit 10.24a hereto**

10.25a		$35,000,000 Credit Agreement dated as of April 10, 2001 among AEE and Union Bank of California, N.A., as Agent**

10.25b		Amendment No. 1 and Waiver dated as of August 31, 2001 to $35,000,000 Credit Agreement dated as of April 10, 2001 among AEE and Union Bank of California, N.A., as Agent**

10.25c		Amendment No.2 to Credit Agreement dated as of November 20, 2002 to Credit agreement dated as of April 10, 2001 among AEE and Union Bank of California, N.A., as Agent, as amended (incorporated herein by reference to Exhibit 25c to the Annual Report of AES Eastern Energy, L.P.(Reg. No. 333-89725)for the year ended December 31, 2002, filed with the Securities and Exchange Commission on March 28, 2003).

10.25d		Amendment No.3 to Credit Agreement dated as of April 16, 2003 to Credit agreement dated as of April 10, 2001 among AEE and Union Bank of California, N.A., as Agent, as amended***

10.25e		Amendment No.4 to Credit Agreement dated as of April 16, 2003 to Credit agreement dated as of April 10, 2001 among AEE and Union Bank of California, N.A., as Agent, as amended***

10.25f		Accession and Admendment dated April 25, 2003 to Credit Agreement dated as of April 10, 2001 among AEE and Union Bank of California, N.A., as Agent as Amended***

12.1		Statement regarding ratio of earnings to fixed charges

21.1		Subsidiaries Schedule*

24.1		Power of Attorney

31.1		Certification by Chief Executive Officer Required by Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.

31.2		Certification by Chief Financial Officer Required by Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.

32		Certification Required by Rule 13a-14(b) or 15d-14(b) of the Securities Exchange Act of 1934.

* Incorporated herein by reference to similarly numbered exhibit to the Registration Statement on Form S-4 of AES Eastern Energy, L.P. (Reg. No. 333-89725), filed with the Securities and Exchange Commission on October 26, 1999.

** Incorporated herein by reference to similarly numbered exhibit to the

Quarterly Report of AES Eastern Energy, L.P. (Reg. No. 333-89725) for the quarterly period ended September 30, 2001, filed with the Securities and Exchange Commission on November 14, 2001.

*** Incorporated herein by reference to similarly numbered exhibit to the Quarterly Report of AES Eastern Energy, L.P. (Reg. No. 333-89725) for the quarterly period ended June 30, 2003, filed with the Securities and Exchange Commission on August 14, 2003.

(b) Reports on Form 8-K.

No reports on Form 8-K have been filed during the last quarter of our fiscal year ended December 31, 2003.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, AES Eastern Energy, L.P. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 16, 2004

	AES EASTERN ENERGY, L.P.
	By: AES NY, L.L.C., as General Partner

	By:	/s/ Dan Rothaupt
		Dan Rothaupt
		President

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons in the capacities and on the dates indicated.

Signature	Title	Date

/s/ Dan Rothaupt	President (chief executive officer)	March 16, 2004
Dan Rothaupt	and Class A Director of AES NY, L.L.C.

/s/ Kevin Pierce	Class A Director of AES NY, L.L.C.	March 16, 2004
Kevin Pierce

/s/ Edward Convery	Class A Director of AES NY, L.L.C.	March 16, 2004
Edward Convery

/s/ Amy Conley	Vice President and Treasurer	March 16, 2004
Amy Conley	(principal financial officer) of AES NY, L.L.C.

Index to Financial Statements

AES EASTERN ENERGY, L.P.

Independent Auditors’ Report

Financial Statements:

Consolidated Balance Sheets

Consolidated Statements of Income

Consolidated Statements of Changes in Partners’ Capital

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

AES NY, L.L.C. (General Partner of AES Eastern Energy, L.P.)*

Independent Auditors’ Report

Financial Statements:

Consolidated Balance Sheets

Notes to Consolidated Balance Sheets

*The Consolidated Balance Sheets of AES NY, L.L.C. contained in this Annual Report on Form 10-K should be considered only in connection with its status as the general partner of AES Eastern Energy, L.P. The pass through trust certificates do not represent an interest in or an obligation of AES NY, L.L.C.

INDEPENDENT AUDITORS’ REPORT

To the Partners of

AES Eastern Energy, L.P.

We have audited the accompanying consolidated balance sheets of AES Eastern Energy, L.P. (an indirect wholly owned subsidiary of The AES Corporation) and subsidiaries (the Partnership) as of December 31, 2003 and 2002, and the related consolidated statements of income, changes in partners’ capital, and cash flows for the years ended December 31, 2003, 2002 and 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform our audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AES Eastern Energy, L.P., and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for the years ended December 31, 2003, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, the Partnership changed its method of accounting for asset retirement obligations effective January 1, 2003 to conform to Statement of Financial Accounting Standard No. 143.

/s/Deloitte & Touche LLP

McLean, Virginia

February 26, 2004

AES EASTERN ENERGY, L.P.

CONSOLIDATED BALANCE SHEETS,

DECEMBER 31, 2003 and DECEMBER 31, 2002

(Amounts in Thousands)

December 31,	2003		2002
ASSETS
Current Assets:
Restricted cash:
Operating - cash and cash equivalents	$	2,540	$	4,605
Revenue account	85,231		76,566
Accounts receivable - trade	34,883		35,233
Accounts receivable - affiliates	203		—
Accounts receivable - other	1,264		1,235
Inventory	27,700		26,982
Prepaid expenses	8,019		7,617
Total current assets	159,840		152,238
PROPERTY, PLANT, EQUIPMENT, AND RELATED ASSETS:
Land	7,054		7,011
Electric generation assets -net of accumulated depreciation of $156,259 and $117,222	902,662		929,654
Total property, plant, equipment and related assets	909,716		936,665
OTHER ASSETS:
Deferred financing -net of accumulated amortization of $328 and $863	303		293
Derivative valuation	16,143		2,510
Transmission congestion contract	—		2,416
Rent reserve account	31,717		31,717
TOTAL ASSETS	$	1,117,719	$	1,125,839

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	830	$	1,195
Lease financing – current	7,846		1,665
Environmental remediation	—		20
Accrued interest expense	28,004		28,078
Due to The AES Corporation and affiliates	8,930		6,945
Accrued coal and rail expense	6,456		8,492
Other accrued expenses and liabilities	9,971		9,311
Total current liabilities	62,037		55,706

LONG-TERM LIABILITIES:
Lease financing - long term	629,815		637,660
Environmental remediation	5,051		9,192
Defined benefit plan obligation	16,558		17,439
Derivative valuation liability	43,624		20,996
Asset retirement obligation	9,900		—
Transmission congestion contract	359		—
Other liabilities	2,688		2,600
Total long-term liabilities	707,995		687,887
TOTAL LIABILITIES	770,032		743,593

COMMITMENTS AND CONTINGENCIES (Note 7)

PARTNERS’ CAPITAL	347,687		382,246
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,117,719	$	1,125,839

The notes are an integral part of the consolidated financial statements

AES EASTERN ENERGY, L.P.

CONSOLIDATED STATEMENTS OF INCOME

YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

(Amounts in Thousands)

Year ended December 31,	2003			2002			2001
OPERATING REVENUES:
Energy	$	388,913		$	310,616		$	345,410
Capacity	29,653			36,644			26,767
Transmission congestion contract	—			8,875			—
Other	2,150			6,879			6,171

Total revenues	420,716			363,014			378,348
OPERATING EXPENSES:
Fuel	148,339			137,175			135,562
Depreciation and amortization	36,076			35,538			33,542
Operating and maintenance	23,267			16,954			19,572
General and administrative	59,194			59,112			53,712
Transmission congestion contract	6,226			—			29,494
Derivative valuation	(193		)	27			27

Total operating expenses	272,909			248,806			271,909

OPERATING INCOME	147,807			114,208			106,439

OTHER INCOME (EXPENSE):
Interest expense	(59,144		)	(57,694		)	(58,434		)
Interest income	2,059			2,116			3,860

Total other expense	(57,085		)	(55,578		)	(54,574		)
Net income before cumulative effect of change in accounting principle	90,722			58,630			51,865

Cumulative effect of change in accounting principle	(1,656		)	—			—

NET INCOME	$	89,066		$	58,630		$	51,865

The notes are an integral part of the consolidated financial statements

AES EASTERN ENERGY, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2003, 2002 AND, 2001

(Amounts in Thousands)

	General Partner			Limited Partner			Total			Accumulated Other Comprehensive Income			Comprehensive Income

BALANCE, DECEMBER 31, 2000	$	4,414		$	437,044		$	441,458		$			$
Partners’ Contribution,(See Note 8)	94			9,278			9,372
Net income	519			51,346			51,865						51,865
Dividends paid	(982		)	(97,218		)	(98,200		)
Transition adjustment on
January 1, 2001	(663		)	(65,671		)	(66,334		)	(66,334		)	(66,334		)
Other comprehensive income	949			93,929			94,878			94,878			94,878
Comprehensive income										28,544			80,409
BALANCE, DECEMBER 31, 2001	4,331			428,708			433,039
Partners’ Contribution,(See Note 8)	15			1,498			1,513
Net income	586			58,044			58,630						58,630
Dividends paid	(640		)	(63,320		)	(63,960		)
Other comprehensive loss	(470		)	(46,506		)	(46,976		)	(46,976		)	(46,976		)
Comprehensive loss										(18,432		)	92,063
BALANCE, DECEMBER 31, 2002	3,822			378,424			382,246
Partners’ Contribution,(See Note 8)	2			160			162
Net income	891			88,175			89,066						89,066
Dividends paid	(1,146		)	(113,454		)	(114,600		)
Other comprehensive loss	(92		)	(9,095		)	(9,187		)	(9,187		)	(9,187		)
Comprehensive loss										$	(27,619	)	$	171,942
BALANCE, DECEMBER 31, 2003	$	3,477		$	344,210		$	347,687

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

AES EASTERN ENERGY, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

(Amounts in Thousands)

Year ended December 31,	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	89,066		$	58,630		$	51,865
Adjustments to reconcile net income to Net cash used in operating activities:
Cumulative effect of change in accounting principle	1,656			—			—
Asset obligation accretion	689			—			—
Depreciation and amortization	36,076			35,521			33,542
Realized loss(gain) on derivative	2,583			(5,895		)	28,385
Write off of deferred financing	21			—			—
Net defined benefit plan cost	(881		)	471			(1,813		)
Changes in current assets and liabilities:
Accounts receivable	118			(6,436		)	6,508
Inventory	(718		)	2,633			(6,307		)
Prepaid expenses	(402		)	(1,153		)	(312		)
Accounts payable	(365		)	(468		)	231
Accrued interest expense	(74		)	(275		)	(1,119		)
Due to AES Corporation and affiliates	1,985			531			(2,190		)
Other liabilities	(1,296		)	(2,065		)	(6,372		)

Net cash provided by operating activities	128,458			81,494			102,418

CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for capital additions	(5,421		)	(7,136		)	(17,148		)
Decrease(increase) in restricted cash	(6,600		)	(5,372		)	7,266
Net change in rent reserve account	—			2			(741		)

Net cash used in investing activities	(12,021		)	(12,506		)	(10,623		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid	(114,600		)	(63,960		)	(98,200		)
Payments for deferred financing	(335		)	(317		)	(1,154		)
Principal payments on lease obligations	(1,664		)	(6,224		)	(1,813		)
Partner’s contribution	162			1,513			9,372

Net cash used in financing activities	(116,437		)	(68,988		)	(91,795		)

CHANGE IN CASH AND CASH EQUIVALENTS	—			—			—
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	—			—			—

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	—		$	—		$	—

Supplemental Disclosure of Cash Flow Information:

Interest paid	$	55,885		$	56,354		$	56,610

Supplemental Disclosure of Non-cash Flow Information:

Adoption of SFAS No. 143	$	3,396		$	—		$	—

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

AES EASTERN ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

1. GENERAL

AES Eastern Energy, L.P. (the Partnership), a Delaware limited partnership, was formed on December 2, 1998. The Partnership’s wholly owned subsidiaries are AES Somerset, L.L.C., AES Cayuga, L.L.C., and AEE2, L.L.C., (which wholly owns AES Westover, L.L.C. and AES Greenidge, L.L.C.). The Partnership began operations on May 14, 1999 (see Note 3). Prior to that date, the Partnership had no operations. The Partnership is an indirect wholly owned subsidiary of The AES Corporation (AES).

The Partnership was established for the purpose of owning or leasing and operating four coal-fired electric generating stations (the Plants) with a total combined capacity of 1,268 MW. The partners of the Partnership are comprised of AES NY, L.L.C. (the General Partner) and AES NY2, L.L.C. (the Limited Partner), both of which are indirect wholly owned subsidiaries of AES. The Plants are owned or leased by the Partnership (see Note 3 and Note 6) and are operated by the Partnership’s wholly owned subsidiaries in the State of New York, pursuant to operation and maintenance agreements with the Partnership.

The Plants sell generated electricity, as well as unforced capacity and ancillary services, directly into the markets operated by the New York Independent System Operator (NYISO) system, PJM (Pennsylvania, New Jersey, Maryland) Interconnection and ISO New England. For Federal regulatory purposes, the Partnership is an exempt wholesale generator (EWG). As an EWG, the Partnership cannot make retail sales of electricity and can only make wholesale sales of electricity, unforced capacity, and ancillary services into wholesale power markets.

In November 2000, the Partnership entered into a three-year agreement for energy marketing services with AES Odyssey, L.L.C.(Odyssey), a direct wholly owned subsidiary of AES. In March 2002, a new agreement was reached, for a term of five years through February 28, 2007 pursuant to which Odyssey provides data management, marketing, scheduling, invoicing and risk management services for a fee of $300,000 per month. On September 4, 2003, the Partnership signed an amendment to its March 2002 agreement. Odyssey will also manage the Partnership’s coal and environmental emission credit positions for an additional fee of $100,000 per month. Odyssey acts as agent on behalf of the Partnership in the over-the-counter and NYISO markets.(see Note 8).

2. SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation - - The consolidated financial statements include the accounts of the Partnership, AES Somerset, L.L.C., AES Cayuga, L.L.C., and AEE2, L.L.C. (which includes its subsidiaries, AES Westover, L.L.C., and AES Greenidge, L.L.C.). All material intercompany transactions have been eliminated.

Restricted Cash - Under the terms of the deposit and disbursement agreement entered into in connection with the lease of two Plants (see Note 6), all revenues of the Partnership and its subsidiaries are deposited into a revenue account administered by Deutsche Bank (formerly Bankers Trust Company), as depositary agent. On request of the Partnership and in accordance with the terms of the deposit and disbursement agreement, funds are transferred from the revenue account to other operating accounts administered by the depositary agent for payment of operating and maintenance costs, lease obligations, debt service, reserve requirements, and distributions. Payment of operating and maintenance costs (other than actual fuel costs) in excess of 125% of the annual operating budget is not permitted under the terms of the lease documents. Amendments, modifications or reallocations of the annual operating budget that result in changes of 25% (positive or negative) in the amounts set forth in the annual operating budget require confirmation from an independent engineer that such payment is based on reasonable assumptions.

Inventory – Inventory is valued at the lower of cost (average cost basis) or market, and consists of coal and other raw materials used in generating electricity, and spare parts, materials, and supplies.

Inventory, as of December 31 consisted of the following (in thousands):

	2003		2002
Coal and other raw materials	$	12,329	$	11,342
Spare parts, materials, and supplies	15,371		15,640

Total	$	27,700	$	26,982

The coal inventory for the year ending December 31, 2002, included $3.3 million of coal which was under special terms in which title had not transferred as of December 31, 2002 from one of the Partnership’s existing suppliers.

Property, Plant, Equipment, and Related Assets - Electric generation assets that existed at the date of acquisition (see Note 3) are recorded at fair market value. The Somerset (formerly known as Kintigh) and Cayuga (formerly known as Milliken) Plants, which represent $650 million of the electric generation assets, are subject to a leasing arrangement accounted for as a financing (see Note 6). 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 the Somerset and Cayuga Plants, 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.

Electric generation assets as of December 31 consisted of the following (in thousands):

	2003			2002
Electric generation assets	$	1,058,921		$	1,046,876
Accumulated depreciation and amortization	(156,259		)	(117,222		)

Total	$	902,662		$	929,654

Rent Reserve Account - As part of the Partnership’s lease obligation (see Note 6), the Partnership is required to maintain a rent reserve account equal to the maximum semiannual payment with respect to the sum of basic rent (other than deferrable payments) and fixed charges expected to become due on any one basic rent payment date in the immediately succeeding three-year period. As of December 31, 2003 and 2002, the Partnership had fulfilled this obligation by entering into a Payment Undertaking Agreement, dated as of May 1, 1999, among the Partnership, each Owner Trust (see Note 3) and Morgan Guaranty Trust Company of New York (the Payment Undertaking Agreement). On May 14, 1999, the Partnership deposited with Morgan Guaranty Trust Company of New York approximately $28.7 million pursuant to the Payment Undertaking Agreement. The accreted value of the Payment Undertaking Agreement at any time includes interest earned thereunder at an interest rate of 4.79% per annum. Interest earnings as of December 31, 2003, 2002, and 2001 were approximately $1.5 million for each year, respectively, and are included in the rent reserve account balance. At December 31, 2003 and 2002, the accreted value of the Payment Undertaking Agreement exceeded the required balance of the rent reserve account. This amount is being accounted for as a restricted cash balance and is included within the rent reserve account on the accompanying balance sheets, as it can only be utilized to satisfy lease obligations. In the future, the Partnership may fulfill its obligation to maintain the required balance of the rent reserve account either by deposits into the rent reserve account or by making amounts available under the Payment Undertaking Agreement, such that the aggregate amount of such deposits in the rent reserve account and amounts available to be paid under the Payment Undertaking Agreement are equal to the required balance of the rent reserve account.

New York Transition Agreement - As the NYISO system represents a deregulated environment, the NYISO attempts to ensure stability of the power grid in New York by requiring each entity engaged in retail sales of electricity to obtain unforced capacity (referred to as installed capacity prior to the winter of 2001 – 2002) commitments from generators in an amount equal to the entity’s forecasted peak load plus a reserve margin. This requirement is intended to ensure that an adequate supply of electricity is always available. In 1999, the General Partner entered into a two-year transition agreement with New York State Electric & Gas Corporation (NYSEG) pursuant to which the Partnership sold its installed capacity to NYSEG in order to permit NYSEG to comply with NYISO standards for system stability. The transition agreement was assumed by the Partnership on the date of acquisition of the Plants. The Partnership recognized revenue under this contract as it was earned, which was $68 per MW per day for installed capacity made available. This agreement expired on April 30, 2001.

Income Taxes - A provision for Federal and state income taxes has not been made in the accompanying financial statements since the Partnership does not pay income taxes but rather allocates its revenues and expenses to the individual partners.

Use of Estimates - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires the Partnership to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Comprehensive Income - The Partnership adopted Statement of Financial Accounting Standards (SFAS) No. 130, “Reporting Comprehensive Income”, which establishes rules for the reporting of comprehensive income and its components. In the years prior to the adoption of SFAS No. 133, the Partnership did not have any items of other comprehensive income.

The Partnership 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. The Statement requires that the Partnership recognize all derivatives, as defined in the Statement, on the balance sheet at fair value. Derivatives that are effective cash flow hedges are recognized in other comprehensive income (loss) until the hedged items are recognized in earnings. Derivatives, or any portion thereof, that are not effective cash flow hedges are adjusted to fair value through income. As of December 31, 2003, the Partnership has recorded $27.6 million of other comprehensive loss due to 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 two years. The majority of the Partnership’s electric derivatives are designated and qualify as cash flow hedges. The Partnership has chosen to use the hypothetical derivative methodology for testing whether its hedges meet the criteria to qualify for cash flow hedge accounting treatment. A historical regression is performed between the electricity generating stations' delivery points into the 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 cash flow hedge accounting criteria treatment. No hedges were derecognized or discontinued and no significant amounts of hedge ineffectiveness were recognized in earnings during the years ended December 31, 2003, 2002 and 2001, respectively.

Approximately $18.7 million of other comprehensive income is expected to be recognized as a reduction to earnings over the next twelve months. Amounts recorded in Other Comprehensive Income during the year ended December 31, 2003, were as follows (in millions):

	2003			2002		2001
Beginning balance on January 1, 2003	$	(18.4	)	28.5		(66.8	)
Reclassified to earnings	(39.1		)	(2.5	)	12.2
Change in fair value	29.9			44.4		82.6
Balance, December 31, 2003	$	(27.6	)	(18.4	)	38.5

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.

Revenue Recognition - Revenues from the sale of electricity are recorded based upon output delivered and rates specified under contract terms. Gains and losses, generated from the hedging of future sales using commodity forwards, swaps and options, reported in other comprehensive income, are reclassified to earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portions of the change in fair value of derivatives and the change in the fair value of derivatives not designated as hedges for accounting purposes are recognized in current period earnings. Revenues for ancillary and other services are recorded when the services are rendered.

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 142, “Goodwill and Other Intangible Assets”. This standard eliminates the amortization of goodwill, and requires goodwill to be reviewed periodically for impairment. This standard also requires the useful lives of previously recognized assets to be adjusted accordingly. This standard is effective for fiscal years beginning after December 15, 2001, for all goodwill and other intangible assets recognized on the Partnership’s balance sheet at that date, regardless of when the assets were initially recognized. The initial adoption of SFAS No. 142 did not have a significant impact on the Partnership’s financial position and results of operations.

In June 2001, the 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. The new liability was recorded in the first quarter of 2003. The Partnership capitalized 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 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 as it applies to the Partnership, includes primarily active ash landfills and water treatment basins. Upon adoption of SFAS No. 143, the Partnership recorded a liability of approximately $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 (see Note 3). The difference between 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 the asset retirement obligation liability for the year ended December 31, 2003 was as follows (in millions):

Balance as of January 1, 2003	$	9.2
Accretion	$	0.7
Balance, December 31, 2003	$	9.9

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, will be recorded using the fair value based method of accounting (See Note 10). 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 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 adoption of SFAS No. 149 did not have a material impact on the Partnership’s financial position or results of operations.

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 Interpretation No. 46, “Consolidation of Variable Interest Entities” which provides guidance on how to identify a variable interest entity (VIE), and when the assets, liabilities, noncontrolling interests and results of operations of a VIE need to be included in a company’s consolidated financial statements. This interpretation was revised in December 2003 with the issuance of Interpretation No. 46(R), “Consolidation of Variable Interest Entities” (FIN 46(R)).

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 purposes of the Partnership's financial statements, which they have been from the Partnership's inception. The Partnership is considering the applicability of consolidating Somerset Railroad Corporation. If it does so the Partnership’s consolidated Balance Sheet as of December 31, 2003 would reflect additional assets of approximately $28.4 million and liabilities of approximately $19.6 million.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”. This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS No. 150 will not have a material effect on the Partnership’s financial position or results of operations.

In December 2003, the (FASB) issued SFAS No. 132 (revised 2003), “Employers’Disclosure About Pensions and Other Postretirement Benefits”, which amends SFAS No. 87, “Employers’ Accounting for Pensions”, SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits”, and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions “, and replaces SFAS No. 132, “Employers’ Disclosures About Pensions and Other Postretirement Benefits” (collectively referred to as “SFAS No. 132 (revised)”) . SFAS No. 132 (revised) expands employers’ disclosures about pension and other post-retirement benefit plans to present more information regarding the economic resources and obligations of such plans in terms of the plans’ assets, obligations, cash flows and net periodic benefit costs. Additionally, SFAS No. 132 (revised) requires interim-period disclosures regarding plan benefit costs and material plan changes. The Partnership is required to adopt the new annual disclosure requirements of SFAS No. 132 (revised) effective as of December 31, 2003. The interim-period disclosure requirements will be effective for the Partnership as of March 31, 2004. As SFAS No. 132 (revised) does not change the measurement or recognition of pension and other post-retirement benefit plans as required by SFAS No. 87, SFAS No. 88 and SFAS No. 106, adoption of this new standard will have no effect on the Partnership’s consolidated financial statements.

Reclassifications - Certain prior year and prior period amounts have been reclassified on the consolidated financial statements to conform with the 2003 presentation.

3. ACQUISITION

On May 14, 1999, the Partnership’s four Plants were acquired from NYSEG for approximately $914 million. The Partnership acquired ownership of two of the Plants, Westover (formerly known as Goudey) and Greenidge. The other two Plants, Somerset and Cayuga, were acquired for $650 million by twelve unrelated third-party owner trusts (collectively, the Owner Trusts) organized by three unrelated institutional investors. The institutional investors made an equity contribution of $116 million and $550 million was raised for purchase of the Somerset and Cayuga plants from the sale of pass through trust certificates. Simultaneously, the Partnership entered into separate leasing agreements for the Somerset and Cayuga Plants with the Owner Trusts. The Partnership accounts for these leases as a financing.(See Note 6).

The acquisition was financed by capital contributions from the General Partner and the Limited Partner in an aggregate amount equal to the purchase price for the Plants, certain associated costs and expenses, and certain amounts for working capital less the net proceeds from the leasing transactions with respect to the Somerset and Cayuga Plants described above. The acquisition has been accounted for as an asset purchase.

In connection with the acquisition, NYSEG engaged an environmental consulting firm to perform an environmental analysis of the potential required remediations for soil and ground water contamination. The Partnership engaged another environmental consulting firm to evaluate the costs estimated by NYSEG’s consultants. The environmental analysis and the Partnership’s estimate of other environmental remediation costs indicated that there existed a range of potential remediation costs of between $8.5 million and $19.7 million, with a most probable liability of approximately $12 million. The Partnership recorded $12 million as an undiscounted liability under purchase accounting for the projected remediation cost. In 2002, the Partnership reduced its undiscounted liability by $2.2 million as remediation was completed or more current estimates were received that were lower than previously estimated. On January 1, 2003, $4.2 million of this environmental remediation liability was reclassified into the asset retirement obligation in accordance with SFAS No. 143 (see Note 2). As of December 31, 2003, none of the liability was classified as a current liability.

4. PARTNERSHIP AGREEMENT

The Partnership was capitalized with an initial contribution of $10 from the General Partner and $990 from the Limited Partner. Subsequently, the General Partner and the Limited Partner contributed $354 million to the Partnership (see Note 5).

The General Partner is responsible for the day-to-day management of the Partnership and its operations and affairs, and is responsible for all liabilities and obligations of the Partnership. Under the terms of the Partnership Agreement, the Limited Partner is not liable for any obligations, liabilities, debts, or contracts of the Partnership and is only responsible to make capital contributions when required under the Partnership Agreement. All distributions, profits, and losses of the Partnership are allocated among the partners based on their ownership interests, currently 1% for the General Partner and 99% for the Limited Partner.

5. CAPITALIZATION

The Partnership is indirectly owned by AES New York Funding, L.L.C. (AES Funding), which is a special purpose financing vehicle established to raise a portion of the capital contributed to

the Partnership through the General Partner and the Limited Partner. AES Funding is a direct wholly owned subsidiary of AES.

On May 11, 1999, AES Funding entered into a three-year loan agreement with a syndicate of banks, with Morgan Guaranty Trust Company of New York as Agent, in the amount of $300 million. AES Funding contributed 1% of this amount to the General Partner and 99% of this amount to the Limited Partner which, in turn, made an aggregate capital contribution of $300 million to the Partnership. AES also contributed capital in the amount of approximately $54 million through AES Funding, which subsequently contributed this amount to the General Partner and the Limited Partner which, in turn, made a capital contribution of approximately $54 million to the Partnership.

On November 30, 2001, AES Funding entered into a thirty-nine month loan agreement with a syndicate of financial institutions and institutional lenders, with Citibank, N.A. as Agent, in the amount of $300 million. The proceeds were used to refinance in full the debt outstanding under the Loan Agreement dated May 11, 1999. Collateral for the loan includes a pledge of AES common stock.

On July 23, 2002, AES announced that AES Funding had amended the thirty-nine month loan agreement in the amount of $300 million. The amendment capped the number of shares of AES common stock required to be pledged to secure the loan. The amendment also provided that the loan would be prepaid in part ($75 million) no later than December 15, 2002. The prepayment was paid on September 9, 2002.

On July 29, 2003, AES amended and restated its senior secured bank credit facilities. As amended and restated, the credit facilities provide for a $250 million revolving loan and letter of credit facility and a $700 million term loan facility. The total amount of credit available under the amended facilities was increased by $135 million. This increase, together with cash on hand, was used to repay in full the outstanding balance of the AES Funding loan, resulting in the release of the unregistered common stock of AES and other collateral that secured such loan.

Collateral for the loan also included a pledge of the membership interests of AES New York Holdings, L.L.C., a direct wholly owned subsidiary of AES Funding, which is the 100% direct owner of both the General Partner and the Limited Partner.

6. LEASE FINANCING

The Partnership’s leases for the Somerset and Cayuga Plants are accounted for as a financing (see Note 3). Minimum lease payments and the present value of the lease obligations are as follows (in thousands):

Fiscal Years ending December 31,	Principal Portion		Interest Imputed		Lease Payments

2004	$	7,846	$	55,604	$	63,450
2005	4,411		55,039		59,450
2006	6,898		54,652		61,550
2007	8,495		54,005		62,500
2008	9,256		53,244		62,500
Thereafter	600,755		588,911		1,189,666
Total minimum lease payments	637,661		861,455		1,499,116

Less imputed interest					(861,455		)

Present value of minimum lease payments					$	637,661

Less current portion					(7,846		)
Lease financing – long term					$	629,815

Through July 2, 2020, and so long as no lease event of default exists, a portion of the rent payable under each lease may be deferred until after the final scheduled payment of the debt incurred by the Owner Trusts to acquire the Somerset and Cayuga Plants. As of December 31, 2003, the Partnership has not deferred any portion of the lease obligations.

certain covenants, including the maintenance of certain coverage ratios, are met (see Note 13). In connection with the lease agreements, the Partnership is required to maintain an additional liquidity account. The required balance in the additional liquidity account was initially equal to the greater of $65 million less the balance in the rent reserve account on May 14, 1999 (see Note 2) or $29 million. As of December 31, 2003, the Partnership had fulfilled its obligation to fund the additional liquidity account by establishing a letter of credit, issued by Fleet Bank dated May 14, 1999, in the stated amount of approximately $36 million (the Additional Liquidity Letter of Credit). This letter of credit was established by AES for the benefit of the Partnership. However, the Partnership is obligated to replenish or replace this letter of credit in the event it is drawn upon or needs to be replaced.

An aggregate amount in excess of $65 million is available to be drawn under the Payment Undertaking Agreement (see Note 2) and the Additional Liquidity Letter of Credit for making rental payments. In the event sufficient amounts to make rental payments are not available from other sources, a withdrawal from the additional liquidity account (which may include making a drawing under the Additional Liquidity Letter of Credit) and from the rent reserve account (which may include making a demand under the Payment Undertaking Agreement) may be made for rental payments.

The Leases for Somerset and Cayuga expire on February 13, 2033 and November 13, 2027, respectively.

7. COMMITMENTS AND CONTINGENCIES

Coal Purchases – In connection with the acquisition of the Plants, the Partnership assumed from 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 was three lots for the Somerset Plant plus 70% of the anticipated coal usage for the Cayuga Plant. The termination date for the contract was December 31, 2003. The agreement was not extended.

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 contract. As of December 31, 2002, the underlying contracts were fully amortized.

The Partnership has expected coal purchases, composed of short and medium term contracts with various mines, ranging between $86 million and $106 million, and $50 million and $70 million for 2004 and 2005, respectively.

Transmission Agreements - On August 3, 1998, 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 intend to transmit over these lines and was required to pay the current fees until the effective cancellation date, November 19, 1999.

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 subsequently approved by the Federal Energy Regulatory Commission (FERC). 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 has the right under a Remote Load Wheeling Agreement (RLWA) to transmit 298 MW over firm transmission lines from the Somerset Plant. The Partnership has the right to designate alternate points of delivery on NIMO’s transmission system provided that the Partnership is not entitled to receive any transmission service charge credit on the NIMO system.

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 $6.2 million, a gain of 8.9 million and a loss of $29.5 million for the years ended December 31, 2003, 2002 and 2001, respectively, related to this contract.

On June 25, 2003, AES Somerset L.L.C. 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 that the outstanding charges owed are $290,000, while NIMO has calculated that the outstanding charges are $3.6 million. In December 2003, FERC reiterated its 2001 ruling that independent power plants can net station service power, in the Somerset and Nine Mile orders. NIMO is appealing the ruling. As of December 31, 2003, AES Somerset has accrued approximately $1.6 million for these charges.

Line of Credit Agreement – On May 14, 1999, the Partnership established a three-year revolving working capital credit facility of up to $50 million for the purpose of making funds available to pay for certain operating and maintenance costs. This facility was terminated as of March 9, 2001. In April 2001, the Partnership entered into a $35 million secured revolving working capital and letter of credit facility with Union Bank of California, N.A. This facility had a term of approximately twenty-one months. The Partnership could borrow up to $35 million for working capital purposes under this facility. In addition, the Partnership could have letters of credit issued under this facility up to $25 million, provided that the total amount of working capital borrowings and letters of credit issuances may not exceed the $35 million limit on the entire facility. Through December 31, 2003, there were three borrowings under this facility. The first borrowing was for $7 million on July 13, 2001 at an interest rate of 8.125%. The borrowing was repaid in full on July 31, 2001. The second borrowing was for $8.5 million on January 11, 2002 at an interest rate of 6.125%. The borrowing was repaid in full on February 28, 2002. The third borrowing was for $14.0 million on July 9, 2002, at an interest rate of 6.125%. The Partnership repaid the borrowing in two installments: $7.2 million on July 31, 2002 and $6.8 million on August 28, 2002.

On November 20, 2002, the Partnership signed an agreement with Union Bank of California, N.A. for a one-year extension of the 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. There have been two borrowings under this facility. The first borrowing was for $9.7 million on January 10, 2003 at an interest rate of 5.75%. This borrowing was repaid in full on January 28, 2003. The second borrowing was for $9.7 million on July 9, 2003 at an interest rate of 5.5%. This borrowing was repaid in full on July 25, 2003. As of December 31, 2003, of the $35 million committed, the Partnership had obtained letters of credit of $18.5 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

AES 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.

On February 12, 2004, the Partnership signed a two-year agreement, effective January 1, 2004, with AES to obtain up to $35 million and $25 million dollars of letters of credit or cash collateral for 2004 and 2005, respectively. This agreement supercedes the authorization of AES on February 25, 2003. The agreement limits the letters of credit amounts and cash collateral to the stated amounts and set into place a fee structure and repayment terms. As of December 31, 2003, the Partnership has obtained letters of credit in the amount of $4.6 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

On October 3, 2002, Standard & Poor’s lowered its rating on the Partnership’s $550 million pass through trust certificates and $35 million working capital and letter of credit facility to BB+ from BBB- solely due to the Partnership’s rating linkage to AES. The rating was also placed on CreditWatch with negative implications. (See Note 2).

Environmental - The Partnership has recorded a liability for environmental remediation associated with the acquisition of the Plants (see Note 3). 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 seeks 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 (NYSDEC) seeking similar operating and maintenance history from the Plants. This information is being sought in connection with the Attorney General’s and the NYSDEC’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 performancestandards, 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 NYSDEC issued a Notice of Violation (NOV) to NYSEG for violations of the Clean Air Act and the New York 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 ofthe 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 NYSDEC. If a settlement is not reached, the EPA and the NYSDEC could issue a notice or notices of violation to the Partnership for violations of the Clean Air Act and the New York Environmental Conservation Law. If the Attorney General, the NYSDEC or the EPA does file an enforcement action against the Somerset, Cayuga, Westover, or Greenidge Plants, then penalties may be imposed and further emission 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 NYSDEC 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. If NOx 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. 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 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 2,317 NOx emissions allowances for 2004. The Plants were net sellers of NOX allowances in 2002 and 2001. The Plants had a shortfall of approximately 1,200 NOx allowances in 2003. The 2003 shortfall was covered by purchasing 70 NOx allowances from AES Ironwood, an indirect wholly owned subsidiary of the AES Corporation at market prices and the remainder of NOx allowances were purchased from unrelated companies in the open market at market price.

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. SO2 allowances may be bought, sold, or traded. If 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. The Plants were self-sufficient with respect to SO2 allowances in 2001; however, the Plants had a shortfall of approximately 6,600 and approximately 10,000 SO2 allowances in 2002 and 2003, respectively. The majority of the 2002 SO2 allowance shortfall was covered with allowances purchased from the electricity generating stations owned by an affiliate of the Partnership, AES Creative Resources, L.P. (ACR), which are on long-term cold standby. Those allowances were purchased at quoted market prices. The 2003 shortfall was covered by purchasing SO2 allowances at market prices from unrelated companies in the open market.

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 an emission rate of 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 (6 NYCRR Parts 237 and 238) were adopted in March 2003. A number of entities have started legal actions to attempt to overturn these rules.

In September 2003, New York State determined the amount of NOx emissions allowances that would be allocated to the Plants. The allocation is several hundred tons short of the Partnership’s average historical NOx emissions for the Plants during the control period. The Partnership’s compliance plan cannot be finalized until the anticipated New York NOx allowance market prices

are more conclusively determined.

In January 2004, NYSDEC determined the amount of SO2 emissions allowances that would be allocated to the Plants. The allocation is several thousand tons short of the Partnership’s average historical SO2 emissions for the Plants. The Partnership’s compliance plan cannot be finalized until the anticipated New York SO2 allowance market prices are more conclusively determined.

In January 2004, the EPA proposed the “utility mercury reductions rule” that would regulate mercury emissions from existing and new coal-fired power plants. The EPA proposed two alternative approaches for reducing mercury emissions based on different authority under the Clean Air Act. The EPA’s preferred approach is to implement a cap and emission trading program with the first phase commencing in 2010 and the second phase starting in 2018. If the EPA selects the alternative approach, compliance could be required by December 2007. Pursuant to a settlement agreement with environmental groups, the EPA is required to finalize the utility mercury reductions rule by December 15, 2004.

The Partnership voluntarily disclosed to the NYSDEC 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 Plant’s NOx RACT tracking system. The Partnership believes that it has 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 NYSDEC for review of the self-disclosure letter and technical issues. The Partnership is unable to predict any potential actions or fines the NYSDEC may require, if any.

The Partnership voluntarily disclosed to the NYSDEC 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 Partnership had entered into an agreement with a supplier to purchase coal. It received approximately one 9000-ton train shipment per month from April 24, 2001 to December 27, 2002. In January 2003, The Partnership became aware that the product the Cayuga Plant was receiving was synfuel. The Partnership suspended all shipments from that supplier until a resolution was reached. The Partnership reviewed the emission and operation data which showed there was no adverse effect to air quality with respect to applicable permit emissions limits attributable to burning the material. The Partnership is unable to predict any potential actions or fines the NYSDEC may require, if any. In July 2003, the Partnership reached an agreement with the supplier to resume shipment of coal in order to satisfy contractual obligations. As part of this agreement, the supplier has provided a written guarantee stating that all fuel shipments will be coal.

In April 2002, the EPA proposed to establish location, design, construction and capacity standards for cooling water intake structures at existing power plants withdrawing more than 50 million gallons per day from rivers, lakes or other bodies of water. 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 final rule was released by the EPA on February 16, 2004. These new rules will impose new compliance requirements on the withdrawal of water, with potentially significant costs, on operating plants across the nation with cooling water intake structures. Cost items include various environmental and engineering studies and potential capital and maintenance costs. The Partnership is evaluating the potential applicability of the rule and it has not yet determined the effects, if any, of these regulations on its financial position or results of operations. If applicable, the new rule requirements will be addressed when the Plants’ wastewater discharge permits are renewed.

Northeastern U.S. states (including New York) have agreed to work to develop a regional market-based emissions trading system to reduce power plants’ Carbon Dioxide emissions. The goal is to reach an agreement by April 2005 on a cap and emissions trading 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 from operations.

8. RELATED PARTY TRANSACTIONS

The Partnership has entered into a contract with Somerset Railroad Corporation (SRC), a wholly owned subsidiary of AES NY3, L.L.C., which is an indirect wholly owned subsidiary of AES, pursuant to which SRC will haul coal and limestone to the Somerset Plant and make its rail cars available to transport coal to the Cayuga Plant. The Partnership will pay amounts sufficient to enable SRC to pay all of its operating and other expenses, including all out-of-pocket expenses, taxes, interest on and principal of SEC's outstanding indebtedness, and all capital expenditures necessary to permit SRC to continue to provide rail service to the Somerset and Cayuga Plants. As of December 31, 2003, 2002 and 2001, $3.1 million, $3.8 million and

$4.2 million, respectively, has been recorded by the Partnership 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.

Period	Base Rate Loans	LIBOR Rate Loans
August 14, 2000 to August 13, 2002	Base Rate plus 0.625%	LIBOR plus 1.375%
August 14, 2002 to August 13, 2005	Base Rate plus 0.750%	LIBOR plus 1.500%
August 14, 2005 to August 13, 2008	Base Rate plus 0.875%	LIBOR plus 1.625%
August 14, 2012 to August 13, 2014	Base Rate plus 1.125%	LIBOR plus 1.875%
August 14, 2008 to August 13, 2012	Base Rate plus 1.375%	LIBOR plus 2.125%

The principal amount of SRC’s outstanding indebtedness under this credit facility was approximately $19.5 million and $21.4 million as of December 31, 2003 and 2002, respectively.

In November 2000, the Partnership entered into a three-year agreement for energy marketing services with Odyssey. In March 2002, a new agreement was reached, for a term of five years through February 28, 2007 pursuant to which Odyssey provides data management, marketing, scheduling, invoicing and risk management services for a fee of $300,000 per month. On September 4, 2003, the Partnership signed an amendment to its March 2002 agreement. Odyssey will also manage the Partnership’s coal and environmental emission credit positions for an additional fee of $100,000 per month. Odyssey acts as agent on behalf of the Partnership in the over-the-counter and NYISO markets.

Odyssey also manages enviornmental emission credit positions for other AES facilities. These allowances were purchased on the open market at market prices. From time to time the allowances will be temporarily placed into a AEE's facility allowance account while awaiting transfer to the purchasing facility. In 2003, allowances were purchased and sold in this matter for AES Deepwater, AES Red Oak and AES Ironwood, all indirect wholly owned subsidiaries of the AES Corporation.

Odyssey purchased for AEE's account 70 NOx allowances at market prices from AES Ironwood, a wholly owned subsidiary of the AES Corporation.

As agent, Odyssey manages all energy transactions under the Partnership’s name including (i) preparing confirmations for the Partnership and approving confirmations with counterparties, (ii) conducting monthly check-outs with counterparties as appropriate before the preparation of invoices, (iii) invoicing counterparties for the term of the transactions and (iv) otherwise managing and executing the terms of the transactions in accordance with their provisions.

Odyssey provides data management for us by maintaining databases of pricing, load, transmission, weather and generation data to aid in analysis to optimize the value of our assets. Odyssey maintains a transaction management system to manage day-ahead commitments with the NYISO and swap and physical values with counterparties and to provide daily financial reporting and end of day budget variance, forward mark-to-market and commercially accepted risk analysis.

Starting in 2001, until the sale of AES New Energy in the third quarter of 2002, the Partnership entered into bilateral contract transactions with AES New Energy, a wholly owned subsidiary of AES. These transactions included forward sales of electric energy and unforced capacity at market based rates. For the years ended December 31, 2002 and 2001, the Partnership recognized revenues of approximately $13.9 million and $11.7 million, respectively, related to the physical delivery of electricity or unforced capacity and the subsequent change in the market value of these contracts. AES New Energy was sold in the third quarter of 2002. As of December 31, 2002 and 2001, the related account receivable – trade between AES New Energy and the Partnership was zero and $2.6 million, respectively. The exposure at December 31, 2001 and 2002 related to these contract transactions was less than 10% of the Partnership’s estimated cash revenues for the respective year.

AES contributed approximately $162,000 to the Partnership in 2003, related to the cost of stock options compensation expense. Also, AES contributed approximately $1.5 million and $9.4 million to the Partnership in 2002 and 2001, respectively, related to the construction of the SCR on Unit 1 of the Cayuga Plant, which became operational on June 7, 2001.

9. BENEFIT PLANS

Effective May 14, 1999, the Partnership adopted The Retirement Plan for Employees of AES NY, L.L.C. (the Plan), a defined benefit pension plan. The Plan covers people employed both under collectively bargained and non-collectively bargained arrangements. Certain people formerly employed by NYSEG (the Transferred Persons) receive credit under the Plan for compensation and service earned while employed by NYSEG. The amount of any benefit payable under the Plan to a Transferred Person will be offset by the amount of any benefit payable to such Transferred Person under the Retirement Plan for Employees of NYSEG. Effective May 29, 1999, the ability to commence participation in the Plan and the accrual of benefits under the Plan ceased with respect to non-collectively bargained people and the accrued benefits of any such participant were fixed as of such date. As of December 31, 2003, the Plan was funded at least to the extent required by Internal Revenue Code (IRC) Section 412 minimum funding and not more than the requirement of IRC Section 404, maximum contribution limits. The Partnership will make at least the required minimum contribution within the Employee Retirement Income Security Act (ERISA) guidelines. Pension benefits are based on years of credited service, age of the participant, and average earnings. During 2003, 2002 and 2001, collectively bargained people were offered the opportunity to freeze their accrued benefit payable under the Plan and opt into the AES Profit Sharing and Stock Ownership Plans.

	2003			2002			2001
Projected Benefit Obligation
Change in projected benefit obligation (in thousands):
Projected benefit obligation, beginning of period	$	25,267		$	21,840		$	20,801
Service cost	375			347			408
Interest cost	1,495			1,132			1,293
Actuarial (gain) loss	(1,419		)	—			(469		)
Benefits paid	(830		)	(189		)	(193		)
Curtailment	—			(790		)	—
Special Termination Loss	—			2,927			—

Projected benefit obligation, end of period	$	24,888		$	25,267		$	21,840
Plan Assets:
Change in plan assets (in thousands):
Fair value of plan assets, beginning of period	$	7,153		$	4,873		$	2,020
Actual return on plan assets	933			(512		)	(156		)
Employer contributions	2,161			2,981			3,202
Benefits paid	(830		)	(189		)	(189		)

Fair value of plan assets, end of period	$	9,417		$	7,153		$	4,873
Funded status/accrued benefit liability	$	(15,471	)	$	(18,114	)	$	(16,968	)
Unrecognized Net Loss	(1,087		)	675			—
(Accrued)/Prepaid Pension Cost, end of period	$	(16,558	)	$	(17,439	)	$	(16,968	)

Defined Benefit Pension Plan Costs:
Components of net periodic benefit cost (in thousands)
Service cost	$	366		$	416		$	408
Interest cost	1,522			1,358			1,293
Expected return on plan assets	(607		)	(474		)	(312		)

Net periodic benefit cost	$	1,281		$	1,300		$	1,389

The discount rate utilized for determining future pension obligations is based on a review of long- term bond rates. The discount rate has remained at 6.25% since 2000. Future actual pension benefit obligations will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Partnership’s pension plans.

	2003		2002		2001
Discount rate	6.25	%	6.25	%	6.25	%
Expected long-term rate of return on plan assets	8.00	%	8.00	%	8.00	%
Rate of compensation increase	4.75	%	4.75	%	4.75	%

The projected benefit obligation of the Plan as of May 14, 1999, as actuarially determined, was recorded by the Partnership as a purchase accounting liability (see Note 3) under Accounting Principles Board Opinion (APB) No. 16, “Business Combinations”. The accumulated benefit obligation was approximately $21.8 million, $20.5 million and $16.7 million as of December 31, 2003, 2002 and 2001, respectively.

Significant assumptions were used in the calculations of the net benefit cost and projected benefit obligation for the periods ending October 31, 2003 and 2002 and December 31, 2001. In developing the Partnership’s expected long-term rate of return assumption, the Partnership evaluated input from its actuaries and plan asset manager. Projected returns are based on a broad range of equity and bond indices. The Partnership’s expected 8% long-term rate of return on Qualified Plan assets is based on the allocation assumption of 60% equities (50% growth and 50% value), with a 10% long term rate of return, and 40% in fixed income investments, with a 5.5% long-term rate of return. Because of market fluctuation, its actual allocation was 58% and 52% equities and 42% and 48% in fixed income investments as of October 31, 2003 and 2002, respectively. However, the Partnership believes that its long-term asset allocation on average will approximate 60% equities and 40% fixed income investments. The

Partnership regularly reviews the asset allocation with the asset manager and periodically rebalances the Plan’s investments to its targeted allocation when appropriate. The Partnership continues to believe that 8% is a reasonable long-term rate of return on its qualified plan assets, despite the market downturn. The Partnership will continue to evaluate its actuarial assumptions, including its expected rate of return, at least annually, and will adjust as necessary.

As of December 31, 2003, the Plan had 265 active participants.

In 2002, the Plan was amended to allow for an early retirement window. In August 2002, early retirement was offered to 56 qualified plan participants. Of the plan participants that were eligible, 27 accepted the early retirement offer and retired from the Partnership effective September 1, 2002.

Plan Assets

The Partnership’s pension plan weighted-average asset allocations at December 31, 2003, 2002 and 2001 are as follows:

Asset Category	2003		2002		2001
Equity securities	60	%	60	%	60	%
Debt securities	40	%	40	%	40	%

The overall expected long-term rate-of-return-on-assets assumption is based upon a building-block method, whereby the expected rate of return on each asset class is broken down into three components: (1) inflation, (2) the real risk-free rate of return (i.e., the long-term estimate of future returns on default-free U.S. government securities), and (3) the risk premium for each asset class (i.e., the expected return in excess of the risk-free rate).

All three components are based primarily on historical data, with modest adjustments to take into account additional relevant information that is currently available. For the inflation and risk- free return components, the most significant additional information is that provided by the market for nominal and inflation-indexed U.S. Treasury securities. That market provides implied forecasts of both the inflation rate and risk-free rate for the period over which currently-available securities mature. The historical data on risk premiums for each asset class is adjusted to reflect any systemic changes that have occurred in the relevant markets; e.g., the higher current valuations for equities, as a multiple of earnings, relative to the longer-term average for such valuations.

Cash Flows

The Partnership expects to contribute $6.7 million to its pension plan in 2004.

Estimated Future Benefits

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Fiscal Years ending December 31,	Payments

2004	$	987
2005	1,030
2006	1,102
2007	1,210
2008	1,325
Thereafter	8,336
Total Estimated Future Benefits	$	13,990

Additionally, people of the Partnership and its subsidiaries participate in the AES Profit Sharing and Stock Ownership Plans. The plans provide Partnership matching contributions. Participants are fully vested in their own contributions and the Partnership’s matching contributions. The Partnership contributed to AES Profit Sharing and Stock Ownership Plans approximately $885,198, $809,000 and $781,000 in 2003, 2002 and 2001, respectively.

Other Postretirement Benefit Plan

On July 1, 2000, AES Greenidge adopted SFAS No. 106 “Employees’ Accounting for Postretirement Benefit Other Than Pension.” Prior years cost were deemed immaterial for presentation purposes. On July 1, 2003, as part of AES Greenidge’s collective bargaining agreement with the International Brotherhood of Electrical workers (the “IEEW”), AES Greenidge established a Voluntary Employees’ Beneficiary Association (“VEBA”) to fund their retired union member’s, spouse’s and dependent’s medical expenses.

	2002
Postretirement Medical Benefit Costs:
Postretirement Benefit Costs:
Components of net periodic benefit cost (in thousands)
Service cost	$	37
Interest cost	76
Expected return on plan assets	—
Amortization of:
Transition Obligation	—
Prior Service Cost	118
Net Loss/Gain	—
Total	118
Net Periodic Postretirement Benefit Cost	$	231
Accumulated Postretirement Benefit Obligation
Change in projected benefit obligation (in thousands):
Projected benefit obligation, beginning of year	$	1,200
Service cost	36
Interest cost	76
Actuarial (gain) loss	(14		)
Benefits paid	14
Projected benefit obligation, end of year	$	1,312
Plan Assets:
Change in plan assets (in thousands):
Fair value of plan assets, beginning of year	$	—
Unrecognized Prior Service Cost	1,083
Unrecognized Net Loss/(Gain)	(14		)

Fair value of plan assets, end of year	$	1,069
Funded status/accrued benefit liability	$	243

Weighted average discount rate for expense calculation is 6.25% in 2002. Weighted average discount rate for accumulated postretirement benefit obligation is 6.25% beginning December 31, 2001. The medical care cost trend rate is 13% for 2002, decreasing gradually to 5.0% by the year 2010. The Medicare cost trend rate is 7.0% for 2002, decreasing gradually to 5.0% by the year 2006. Increasing the health care trend rate by 1% would increase the total accumulated postretirement benefit obligation to $1,489,148, or by 15.9%, and the aggregate of the total Service and Interest Cost components of the Net Periodic Postretirement Benefit Cost would increase from $113,294, to $134,966, or by 19.1%. Decreasing the health care cost trend by 1.0% would decrease the total accumulated postretirement benefit obligation to $1,119,110, or by 12.9% and the aggregate of the total Service and Interest Cost components of the Net Periodic Postretirement Benefit Cost would decrease from $113,294 to $96,187, or by 15.1%.

The Plants have created separate VEBAs to fund their retiree medical expenses. Employer contributions to pay the claims of the employees are deposited in the VEBA Trusts. Currently, the VEBA Trusts are to pay the medical claims of the employees who are union members and who retire from the Partnership and the medical claims of their spouses and dependants. Some of the VEBA trusts offer supplemental Medicare benefits, the other Trusts’ coverage end when the employee is Medicare eligible. The AES Somerset, AES Cayuga and AES Westover VEBA trusts were created in 2002, and the AES Greenidge VEBA trust was created in 2003. The funding schedule for the trusts are as follows: (in thousands)

Fiscal Years ending December 31,	Payments
2004	$	534
2005	534
2006	375
2007	172
2008	172
Total funding payments	$	1,787

10. 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 and 2001 net income, as all options granted under the SOP in those years 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 year ended December 31, 2003 is approximately $162,000.

11. FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of the Partnership’s current financial assets and liabilities approximate their carrying values. The fair value estimates are based on pertinent information available as of December 31, 2003. The Partnership is not aware of any factors that would significantly affect the estimated fair value amounts since that date.

12. SEGMENT INFORMATION

Under the provisions of SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information”, the Partnership’s business is expected to be operated as one reportable segment, with operating income or loss being the measure of performance measured by the chief operating decision-maker.

13. RESTRICTIONS ON DISTRIBUTIONS TO PARTNERS

The Partnership’s ability to make distributions to its partners is restricted by the terms of the agreements governing the leases of the Somerset and Cayuga Plants. The Partnership may make a distribution to its partners only on or within ten business days after a semiannual rent payment date (commencing with the rent payment date occurring on July 2, 2000), so long as the conditions as specified in the agreements have been met. The Partnership has made seven distributions to its partners as of December 31, 2003: July 11, 2000, in the amount of $35 million; January 12, 2001, in the amount of $32.5 million; July 12, 2001, in the amount of $65.7 million; January 9, 2002, in the amount of $32.6 million; July 5, 2002, in the amount of $31.4 million; January 8, 2003, in the amount of $38.7 million; and July 7, 2003, in the amount of $75.9 million.

14. SUBSEQUENT EVENTS

Cash flow from the Partnership’s operations during the second half of 2003 was sufficient to cover the aggregate rental payments under the leases on the Somerset and Cayuga Plants due January 2, 2004. On this date, rental payments were made in the amount of $31.7 million.

Cash flow from operations in excess of the aggregate rental payments under the Partnership’s leases may be distributed to its partners if certain criteria are met. On January 7, 2004, the Partnership made a distribution payment of $48.7 million.

The Partnership borrowed $12.9 million on January 9, 2004 and an additional $1 million on February 20, 2004, 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 borrowings were at an interest rate of 5.50%. A partial payment of $6.2 million was repaid on January 27, 2004 and the remaining balance of $7.7 million was repaid on February 26, 2004.

INDEPENDENT AUDITORS’ REPORT

To the Member of

AES NY, L.L.C.

We have audited the accompanying consolidated balance sheets of AES NY, L.L.C. (an indirect wholly owned subsidiary of The AES Corporation) and subsidiaries (the Company) as of December 31, 2003 and 2002. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, such consolidated balance sheets present fairly, in all material respects, the financial position of AES NY, L.L.C. and subsidiaries as of December 31, 2003 and 2002, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003 to conform to Statement of Financial Accounting Standard No. 143.

/s/Deloitte & Touche LLP

McLean, Virginia

February 26, 2004

AES NY, L.L.C.

CONSOLIDATED BALANCE SHEETS,

DECEMBER 31, 2003 and DECEMBER 31, 2002

(Amounts in Thousands)

December 31,	2003		2002
ASSETS
Current Assets:
Restricted cash:
Operating - cash and cash equivalents	$	2,932	$	5,116
Revenue account	85,231		76,566
Accounts receivable - trade	34,883		35,233
Accounts receivable - affiliates	2,969		2,935
Accounts receivable - other	1,280		1,264
Inventory	27,700		26,982
Prepaid expenses	8,117		7,726
Total current assets	163,112		155,822
PROPERTY, PLANT, EQUIPMENT, AND RELATED ASSETS:
Land	7,503		7,461
Electric generation assets -net of accumulated depreciation of $161,784 and $122,378	902,663		929,654
Total property, plant, equipment and related assets	910,166		937,115
OTHER ASSETS:
Deferred financing -net of accumulated amortization of $328 and $863	303		293
Derivative valuation	16,143		2,510
Transmission congestion contract	—		2,416
Rent reserve account	31,717		31,717
TOTAL ASSETS	$	1,121,441	$	1,129,873

LIABILITIES AND MEMBERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	833	$	1,195
Lease financing - current	7,846		1,665
Environmental remediation	—		35
Accrued interest expense	28,004		28,078
Due to The AES Corporation and affiliates	9,096		7,173
Accrued coal and rail expense	6,456		8,492
Other accrued expenses and liabilities	10,134		11,264
Total current liabilities	62,369		57,902

LONG-TERM LIABILITIES:
Lease financing - long term	629,815		637,660
Environmental remediation	6,800		9,192
Defined benefit plan obligation	17,238		18,147
Asset retirement obligation	10,299		—
Derivative valuation liability	43,624		20,996
Transmission congestion contract	359		—
Other liabilities	2,688		2,600
Total long-term liabilities	710,823		688,595
TOTAL LIABILITIES	773,192		746,497

COMMITMENTS AND CONTINGENCIES (Note 6)

MINORITY INTEREST	344,767		379,542
MEMBER’S EQUITY	3,482		3,834
TOTAL LIABILITIES AND MEMBERS’ CAPITAL	$	1,121,441	$	1,129,873

The notes are an integral part of the consolidated Balance Sheets

AES NY, L.L.C

NOTES TO CONSOLIDATED BALANCE SHEETS
YEARS ENDED DECEMBER 31, 2003 AND 2002

1. GENERAL

AES NY, L.L.C. (the Company), a Delaware limited liability company, was formed on December 2, 1998. The Company is the sole general partner of AES Eastern Energy, L.P. (AEE), owning a one percent interest in AEE. The Company is also the sole general partner of AES Creative Resources, L.P.(ACR), owning a one percent interest in ACR. AES NY Holdings, L.L.C. is the sole member of the Company. The Company is an indirect wholly owned subsidiary of The AES Corporation (AES). The Company began operations on May 14, 1999. Prior to that date, the Company had no operations.

The Company was established for the purpose of acting as the general partner of both AEE and ACR. In this capacity, the Company is responsible for the day-to-day management of AEE and ACR and their operations and affairs, and is responsible for all liabilities and obligations of both entities.

AEE, a Delaware limited partnership, was formed on December 2, 1998. AEE’s wholly owned subsidiaries are AES Somerset, L.L.C., AES Cayuga, L.L.C., and AEE2, L.L.C., (which wholly owns AES Westover, L.L.C. and AES Greenidge, L.L.C.). AEE began operations on May 14, 1999. Prior to that date, AEE had no operations. AEE was established for the purpose of owning and operating four coal-fired electric generating stations (the AEE Plants) with a total combined capacity of 1,268 MW. Two of the plants are owned by AEE and two of the plants are leased by AEE (see Note 5), and are operated by AEE’s wholly owned subsidiaries in the State of New York, pursuant to operation and maintenance agreements with AEE. The limited partner of AEE is AES NY 2, L.L.C. (the Limited Partner), which is also an indirect wholly owned subsidiary of AES.

ACR, a Delaware limited partnership, was formed on December 3, 1998. ACR’s wholly owned subsidiaries are AES Jennison, L.L.C. and AES Hickling, L.L.C., which each owns a coal-fired electric generating station (the ACR Plants) with a combined capacity of 156 MW. ACR began operations on May 14, 1999. Prior to that date ACR had no operations. The limited partner of ACR is AES NY 2, L.L.C. The AEE Plants and the ACR Plants are hereinafter referred to collectively as “the Plants.”

In November 2000, AEE entered into a three-year agreement for energy marketing services with AES Odyssey, L.L.C. (“Odyssey”), a direct wholly-owned subsidiary of AES. In March 2002, a new agreement was reached, for a term of five years through February 28, 2007, pursuant to which Odyssey provides data management, marketing, scheduling, invoicing and risk management services for a fee of $300,000 per month. On September 4, 2003, AEE signed an amendment to their March 2002 agreement. Odyssey will manage the AEE coal and environmental emission credit positions for an additional fee of $100,000 per month. Odyssey acts as agent on behalf of AEE in the over-the-counter and NYISO markets. (see note 7)

The AEE Plants sell generated electricity, as well as unforced capacity and ancillary services, directly into the markets operated by the NYISO system, Pennsylvania, New Jersey, Maryland (PJM) Interconnection and ISO New England. For Federal regulatory purposes, AEE and ACR are exempt wholesale generators (EWGs). As EWGs, AEE and ACR cannot make retail sales of electricity, and can only make wholesale sales of electricity, unforced capacity, and ancillary services into wholesale power markets.

During the fourth quarter of 2000, ACR placed the 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.

2. SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation - 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 (Note 1). All material intercompany transactions have been eliminated. The 99% limited partner ownerships of AEE and ACR are presented as minority interest.

The assets of the Company on a stand-alone basis at December 31, 2003 and 2002 (using the equity method of accounting) consist only of the 1% ownership interest in AEE ($4,330,000 and $4,330,000, respectively) and the 1% ownership interest in ACR ($32,000 and $32,000, respectively). The Company had no liabilities as of December 31, 2003 and 2002, other than liabilities of AEE and ACR for which it is responsible as General Partner of AEE and ACR.

Restricted Cash - Under the terms of the deposit and disbursement agreement entered into by AEE in connection with the lease of two AEE plants (see Note 5), all revenues of AEE and its subsidiaries are deposited into a revenue account administered by Deutsche Bank (formerly Bankers Trust Company), as depositary agent. On request of AEE and in accordance with the terms of the deposit and disbursement agreement, funds are transferred from the revenue account to other operating accounts administered by the depositary agent for payment of operating and maintenance costs, lease obligations, debt service, reserve requirements, and distributions. Payment of operating and

maintenance costs (other than actual fuel costs) in excess of 125% of the annual operating budget is not permitted under the terms of the lease documents. Amendments, modifications or reallocations of the annual operating budget that result in changes of 25% (positive or negative) in the amounts set forth in the annual operating budget require confirmation from an independent engineer that such payment is based on reasonable assumptions.

Inventory, as of December 31 consisted of the following (in thousands):

	2003		2002
Coal and other raw materials	$	12,329	$	11,342
Spare parts, materials, and supplies	15,371		15,640

Total	$	27,700	$	26,982

The coal inventory for the year ending December 31, 2002, included $3.3 million of coal which was

under special terms in which title had not transferred as of December 31, 2002 from one of AEE’s existing suppliers.

Property, Plant, Equipment, and Related Assets - Electric generation assets that existed at the date of acquisition (see Note 3) are recorded at fair market value. The Somerset (formerly known as Kintigh) and Cayuga (formerly known as Milliken) Plants, which represent $650 million of the electric generation assets, are subject to a leasing arrangement accounted for as a financing (see Note 5). 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 the Somerset and Cayuga Plants, 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.

The Company is currently evaluating the future of the Jennison and Hickling plants and may dispose or shut down these plants. As such, the electric generation assets of these two plants were depreciated over two years (2001 and 2002) using the straight-line method. Maintenance and repairs are charged to expense as incurred. During the fourth quarter of 2000, ACR placed the 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 ACR Plants continue to generate revenue from the sales of environmental allowances which they receive from regulatory authorities.

Electric generation assets as of December 31 consisted of the following (in thousands):

	2003
	AEE			ACR			Total

Electric generation assets	$	1,058,922		$	5,525		$	1,064,447
Accumulated depreciation and amortization	(156,259		)	(5,525		)	$	(161,784	)
Total	$	902,663		$	—		$	902,663

	2002
	AEE			ACR			Total

Electric generation assets	$	1,046,867		$	5,156		$	1,052,023
Accumulated depreciation and amortization	(117,222		)	(5,156		)	(122,378		)
Total	$	929,654		$	—		$	929,654

Rent Reserve Account - As part of AEE’s lease obligation (see Note 5), AEE is required to maintain a rent reserve account equal to the maximum semiannual payment with respect to the sum of basic rent (other than deferrable payments) and fixed charges expected to become due on any one basic rent payment date in the immediately succeeding three-year period. As of December 31, 2003 and 2002, AEE had fulfilled this obligation by entering into a Payment Undertaking Agreement, dated as of May 1, 1999, among AEE, each Owner Trust (see Note 3) and Morgan Guaranty Trust Company of New York (the Payment Undertaking Agreement). On May 14, 1999, AEE deposited with Morgan Guaranty Trust Company of New York approximately $28.7 million pursuant to the Payment Undertaking Agreement. The accreted value of the Payment Undertaking Agreement at any time includes interest earned thereunder at an interest rate of 4.79% per annum. Interest earnings as of December 31, 2003, 2002, and 2001 were approximately $1.5 million for each year, respectively, and are included in the rent reserve account balance. At December 31, 2003 and 2002, the accreted value of the Payment Undertaking Agreement exceeded the required balance of the rent reserve account. This amount is being accounted for as a restricted cash balance and is included within the rent reserve account on the accompanying balance sheets, as it can only be utilized to satisfy lease obligations. In the future, AEE may fulfill its obligation to maintain the required balance of the rent reserve account either by deposits into the rent reserve account or by making amounts available under the Payment Undertaking Agreement, such that the aggregate amount of such deposits in the rent reserve account and amounts available to be paid under the Payment Undertaking Agreement are equal to the required balance of the rent reserve account.

New York Transition Agreement - As the NYISO system represents a deregulated environment, the NYISO attempts to ensure stability of the power grid in New York by requiring each entity engaged in retail sales of electricity to obtain unforced capacity (referred to as installed capacity prior to the winter of 2001 – 2002) commitments from generators in an amount equal to the entity’s forecasted peak load plus a reserve margin. This requirement is intended to ensure that an adequate supply of electricity is always available. In 1999, the Company entered into a two-year transition agreement with New York State Electric & Gas Corporation (NYSEG) pursuant to which AEE and ACR sold their installed capacity to NYSEG in order to permit NYSEG to comply with NYISO standards for system stability. The transition agreement was assumed by AEE and ACR on the date of acquisition of the Plants. The Company recognized revenue under this contract as it was earned, which was $68 per MW per day for installed capacity made available. This agreement expired on April 30, 2001.

Income Taxes - A provision for Federal and state income taxes has not been made in the accompanying financial statements since the Company, AEE and ACR do not pay income taxes but rather allocate their revenues and expenses to the individual partners.

Use of Estimates - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Comprehensive Income - The Company adopted Statement of Financial Accounting Standards (SFAS) No. 130, “Reporting Comprehensive Income”, which establishes rules for the reporting of comprehensive income and its components. In the years prior to the adoption of SFAS No. 133, the Company did not have any items of other comprehensive income.

The Company 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. The Statement requires that the Company recognize all derivatives, as defined in the Statement, on the balance sheet at fair value. Derivatives that are effective cash flow hedges are recognized in other comprehensive income (loss) until the hedged items are recognized in earnings. Derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. As of December 31, 2003, the Company has recorded $27.6 million of other comprehensive loss due to hedging activities.

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 two years. The majority of AEE’s electric derivatives are designated and qualify as cash flow hedges. AEE has chosen to use the hypothetical derivative methodology for testing whether its hedges meet the criteria to qualify for cash flow hedge accounting treatment. A historical regression is performed between the electricity generating stations, delivery points into the 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 criteria treatment. No hedges were derecognized or discontinued and no significant amounts of hedge ineffectiveness were recognized in earnings during the years ended December 31, 2003, 2002 and 2001, respectively.

Beginning Balance on January 1, 2003	$	(18.4	)
Reclassified to earnings	(39.1		)
Change in fair value	29.9
Balance, December 31, 2003	$	(27.6	)

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.

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 142, “Goodwill and Other Intangible Assets”. This standard eliminates the amortization of goodwill and requires goodwill to be reviewed periodically for impairment. This standard also requires the useful lives of previously recognized assets to be adjusted accordingly. This standard is effective for fiscal years beginning after December 15, 2001, for all goodwill and other intangible assets recognized on the Company’s balance sheet at that date, regardless of when the assets were initially recognized. The initial adoption of SFAS No. 142 did not have a significant impact on the Company’s financial position and results of operations.

In June 2001, the 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. The new liability was recorded in the first quarter of 2003. The Company capitalized 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 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 as it applies to the Company, 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 (see Note 3). The difference of the amounts previously recorded and the net SFAS 143 liability is a loss recorded as the cumulative effect of a change in accounting principle of $2.2 million. Reconciliation of the asset retirement obligation liability for the year ending December 31, 2003 was as follows (in millions):

Balance as of January 1, 2003	$	9.6
Accretion	0.7
Balance, December 31, 2003	$	10.3

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 Company 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 10). The Company’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 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 adoption of SFAS No. 149 did not have a material impact on the Company’s financial position or results of operations.

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 Company 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.

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 purposes of the Company's financial statements, which they have been from the Company's inception. The Company is considering the applicability of consolidating Somerset Railroad Corporation. If it does so the Company's consolidated Balance Sheet as of December 31, 2003, would reflect additional assets of approximately $28.4 million and liabilities of approximately $19.6 million.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”. This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS No. 150 will not have a material effect on the Company’s financial position or results of operations.

referred to as “SFAS No. 132 (revised)”) . SFAS No. 132 (revised) expands employers’ disclosures about pension and other post-retirement benefit plans to present more information regarding the economic resources and obligations of such plans in terms of the plans’ assets, obligations, cash flows and net periodic benefit costs. Additionally, SFAS No. 132 (revised) requires interim-period disclosures regarding plan benefit costs and material plan changes. The Company is required to adopt the new annual disclosure requirements of SFAS No. 132 (revised) effective as of December 31, 2003. The interim-period disclosure requirements will be effective for the Company as of March 31, 2004. As SFAS No. 132 (revised) does not change the measurement or recognition of pension and other post-retirement benefit plans as required by SFAS No. 87, SFAS No. 88 and SFAS No. 106, adoption of this new standard will have no effect on the Company’s consolidated financial statements.

Reclassifications - Certain prior year and prior period amounts have been reclassified on the consolidated financial statements to conform with the 2003 presentation.

3. ACQUISITION

On May 14, 1999, AEE’s four Plants were acquired from NYSEG for approximately $914 million. AEE acquired ownership of two of the Plants, Westover (formerly known as Goudey) and Greenidge. The other two Plants, Somerset and Cayuga, were acquired for $650 million by twelve unrelated third-party owner trusts (collectively, the Owner Trusts) organized by three unrelated institutional investors. The institutional investors made an equity contribution of $116 million and $550 million was raised for purchase of the Somerset and Cayuga plants from the sale of pass through trust certificates. Simultaneously, AEE entered into separate leasing agreements for the Somerset and Cayuga Plants with the Owner Trusts. The Company accounts for these leases as a financing (see Note 5).

The acquisition of the AEE Plants was financed by capital contributions from the Company and the Limited Partner in an aggregate amount equal to the purchase price for the Plants, certain associated costs and expenses, and certain amounts for working capital less the net proceeds from the leasing transactions with respect to the Somerset and Cayuga Plants described above. The acquisition has been accounted for as an asset purchase. In connection with the acquisition of the AEE Plants, NYSEG engaged an environmental consulting firm to perform an environmental analysis of the potential required remediations for soil and ground water contamination. AEE engaged another environmental consulting firm to evaluate the costs estimated by NYSEG’s consultants. The environmental analysis and AEE’s estimate of other environmental remediation costs indicated that there existed a range of potential remediation costs of between $8.5 million and $19.7 million, with a most probable liability of approximately $12 million. AEE recorded $12 million as an undiscounted liability under purchase accounting for the projected remediation cost. In 2002, AEE reduced its undiscounted liability by $2.2 million as remediation was completed or more current estimates were received for lower than the amounts previously estimated. On January 1, 2003, $4.2 million of this environmental remediation liability was reclassified into the asset liability obligation in accordance with SFAS No. 143. As of December 31, 2003, none of the liability was classified as a current liability.

Also, in connection with this transaction, ACR acquired from NYSEG two older coal-fired plants, Jennison and Hickling (Note 1). An environmental liability of $2.6 million was recorded in connection with this acquisition, which represented the most probable liability based on a range calculated by NYSEG’s environmental consultants and reviewed by other environmental consultants hired by ACR. In 2002, ACR reduced its undiscounted liability by $900,000 as remediation was completed. As of December 31, 2003, none of the liability was classified as a current liability.

Also in connection with the acquisition, the Company entered into an agreement for the construction of a selective catalytic reduction (SCR) facility at the Somerset Plant. The SCR facility is designed to reduce significantly the amount of nitrogen oxide emissions from the burning of coal fuel at the Somerset Plant. AEE acquired the SCR work in progress from the Company on May 14, 1999, for approximately $31 million, which was the contract price for the SCR. Construction of this asset began prior to the acquisition of the AEE Plants. On the acquisition date, the Somerset Plant was shut down to complete construction and make other improvements. The outage lasted until late June 1999. All costs associated with the installation of the SCR, including construction and engineering costs, wages of people involved in the construction, and interest expense during the period were capitalized by AEE. The Somerset Plant was placed back in service on June 28, 1999.

4. CAPITALIZATION

The Company is indirectly owned by AES New York Funding, L.L.C. (AES Funding), which is a special purpose financing vehicle established to raise a portion of the capital contributed to AEE and ACR through the Company and the Limited Partner. AES Funding is a direct wholly owned subsidiary of AES.

On May 11, 1999, AES Funding entered into a three-year loan agreement with a syndicate of banks, with Morgan Guaranty Trust Company of New York as Agent, in the amount of $300 million. AES Funding contributed 1% of this amount to the Company and 99% of this amount to the Limited Partner which, in turn, made an aggregate capital contribution of $300 million to AEE. AES also contributed capital in the amount of approximately $57 million through AES Funding, which subsequently contributed this amount to the Company and the Limited Partner which, in turn, made a capital contribution of approximately $54 million to AEE.

On November 30, 2001, AES Funding entered into a thirty-nine month loan agreement with a syndicate of financial institutions and institutional lenders, with Citibank, N.A. as Agent, in the amount of

$300 million. The proceeds were used to refinance in full the debt outstanding under the Loan Agreement dated May 11, 1999. Collateral for the loan includes a pledge of AES common stock.

On July 23, 2002, AES announced that AES Funding had amended the thirty-nine month loan agreement in the amount of $300 million. The amendment capped the number of shares of AES common stock required to be pledged to secure the loan. The amendment also provides that the loan will be prepaid in part ($75 million) no later than December 15, 2002. The prepayment was paid on September 9, 2002.

5. LEASE FINANCING

AEE’s leases for the Somerset and Cayuga Plants are accounted for as a financing (see Note 3). Minimum lease payments and the present value of the lease obligations are as follows (in thousands):

Fiscal Years ending December 31,	Principal Portion		Interest Imputed		Lease Payments

2004	$	7,846	$	55,604	$	63,450
2005	4,411		55,039		59,450
2006	6,898		54,652		61,550
2007	8,495		54,005		62,500
2008	9,256		53,244		62,500
Thereafter	600,755		588,911		1,189,666
Total minimum lease payments	637,661		861,455		1,499,116

Less imputed interest					(861,455		)

Present value of minimum lease payments					$	637,661

Less current portion					(7,846		)
Lease financing – long term					$	629,815

Through July 2, 2020, and so long as no lease event of default exists, a portion of the rent payable under each lease may be deferred until after the final scheduled payment of the debt incurred by the Owner Trusts to acquire the Somerset and Cayuga Plants. As of December 31, 2003, AEE has not deferred any portion of the lease obligations.

The lease obligations are payable to the Owner Trusts. These obligations bear imputed interest at 9.252% and 9.024% for the Somerset and Cayuga Plants, respectively. Total assets under the leases of these two Plants were $650 million at December 31, 2003. These amounts are included in electric generation assets. The related accumulated depreciation, combined for both leased Plants, as of December 31, 2003 and 2002, was approximately $92.9 million and $72.5 million, respectively. The agreements governing the leases restrict AEE’s ability to incur additional indebtedness, engage in other businesses, sell its assets, or merge with another entity. The ability of AEE to make distributions to its partners is restricted unless certain covenants, including the maintenance of certain coverage ratios, are met. In connection with the lease agreements, AEE is required to maintain an additional liquidity account. The required balance in the additional liquidity account was initially equal to the greater of $65 million less the balance in the rent reserve account on May 14, 1999 (see Note 2) or $29 million. As of December 31, 2003, AEE had fulfilled its obligation to fund the additional liquidity account by establishing a letter of credit, issued by Fleet Bank dated May 14, 1999, in the stated amount of approximately $36 million (the Additional Liquidity Letter of Credit). This letter of credit was established by AES for the benefit of AEE. However, AEE is obligated to replenish or replace this letter of credit in the event it is drawn upon or needs to be replaced.

Additional Liquidity Letter of Credit) and from the rent reserve account (which may include making a demand under the Payment Undertaking Agreement) may be made for rental payments.

The leases for Somerset and Cayuga expire on February 13, 2033 and November 13, 2027, respectively.

6. COMMITMENTS AND CONTINGENCIES

Coal Purchases – In connection with the acquisition of AEE’s four Plants, AEE assumed from 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. During 2001 the coal suppliers were committed to sell and AEE was committed to purchase all three lots of coal for the Somerset Plant as well as 70% of the anticipated coal purchases for the Cayuga Plant. The supplier requested renegotiation during 2001 for the 2002 lot but the parties failed to reach agreement. Therefore, the parties had commitments in 2002 with respect to only two lots for the Somerset Plant and 50% of the anticipated coal purchases at the Cayuga Plant. 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 was three lots for the Somerset Plant plus 70% of the anticipated coal usage for the Cayuga Plant. The termination date for the contract was December 31, 2003. The agreement was not extended.

As of the acquisition date of the 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 contract. As of December 31, 2002, the underlying contracts were fully amortized.

AEE has expected coal purchases, composed of short and medium term contracts with various suppliers, ranging between $80 million and $100 million and $50 million and $70 million for 2004 and 2005, respectively.

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 intend to transmit over these lines and was required to pay the current fees until the effective cancellation date, November 19, 1999.

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 subsequently approved by the Federal Energy Regulatory Commission (FERC). 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 has the right under a Remote Load Wheeling Agreement (RLWA) to transmit 298 MW over firm transmission lines from the Somerset Plant. AEE has the right to designate alternate points of delivery on NIMO’s transmission system provided that AEE is not entitled to receive any transmission service charge credit on the NIMO system.

The 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 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 $6.2 million, a gain of $8.9 million and a loss of $29.5 million for the years ended December 31, 2003, 2002 and 2001, respectively, related to this contract.

On June 25, 2003, AES Somerset L.L.C. 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 that the outstanding charges owed are $290,000, while NIMO has calculated that the outstanding charges are $3.6 million. In December 2003, FERC reiterated its 2001 ruling that independent power plants can net station service power, in the Somerset and Nine Mile orders. NIMO is appealing the ruling. As of December 31, 2003, AES Somerset had accrued approximately $1.6 million for these charges.

Line of Credit Agreement – On May 14, 1999, AEE established a three-year revolving working capital credit facility of up to $50 million for the purpose of making funds available to pay for certain operating and maintenance costs. This facility was terminated as of March 9, 2001. In April 2001, AEE entered into a $35 million secured revolving working capital and letter of credit facility with

Union Bank of California, N.A. This facility had a term of approximately twenty-one months. AEE could borrow up to $35 million for working capital purposes under this facility. In addition, AEE could have letters of credit issued under this facility up to $25 million, provided that the total amount of working capital borrowings and letters of credit issuances may not exceed the $35 million limit on the entire facility. Through December 31, 2003, there were three borrowings under this facility. The first borrowing was for $7 million on July 13, 2001 at an interest rate of 8.125%. The borrowing was repaid in full on July 31, 2001. The second borrowing was for $8.5 million on January 11, 2002 at an interest rate of 6.125%. The borrowing was repaid in full on February 28, 2002. The third borrowing was for $14.0 million on July 9, 2002, at an interest rate of 6.125%. AEE repaid the borrowing in two installments: $7.2 million on July 31, 2002 and $6.8 million on August 28, 2002.

On November 20, 2002, AEE signed an agreement with Union Bank of California, N.A. for a one- year extension of the working capital and letter of credit facility. On April 16, 2003, AEE 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, AEE 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. There have been two borrowings under this facility. The first borrowing was for $9.7 million on January 10, 2003 at an interest rate of 5.75%. This borrowing was repaid in full on January 28, 2003. The second borrowing was for $9.7 million on July 9, 2003 at an interest rate of 5.5%. This borrowing was repaid in full on July 25, 2003. As of December 31, 2003, AEE has obtained letters of credit of $18.5 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

AES on January 6, 2003 and February 25, 2003 authorized AEE to issue letters of credit to counter-parties 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.

On February 12, 2004, AEE signed a two-year agreement, effective January 1, 2004, with The AES Corporation to obtain up to $35 million and $25 million dollars of letters of credit or cash collateral for 2004 and 2005, respectively. This agreement supercedes the authorization of The AES Corporation on February 25, 2003. The agreement limits the letters of credit amounts and cash collateral to the stated amounts and set into place a fee structure and repayment terms. As of December 31, 2003, AEE has obtained letters of credit in the amount of $4.6 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

On October 3, 2002, Standard & Poor’s lowered its rating on AEE’s $550 million pass through trust certificates and $35 million working capital and letter of credit facility to BB+ from BBB- solely due to AEE’s rating linkage to AES. The rating was also placed on CreditWatch with negative implications. (See Note 3).

Environmental - The Company has recorded a liability for environmental remediation associated with the acquisition of the Plants (see Note 3). 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 seeks detailed operating and maintenance history for the Westover and Greenidge Plants. On January 13, 2000, AEE received a subpoena from New York State Department of Environmental Conservation (NYSDEC) seeking similar operating and maintenance history from the Plants. This information is being sought in connection with the Attorney General’s and the NYSDEC’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 NYSDEC issued a Notice of Violation (NOV) to NYSEG for violations of the Clean Air Act and the New York 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.

AEE and ACR are currently in negotiation with both the EPA and NYSDEC. If a settlement is not reached, the EPA and the NYSDEC could issue a notice or notices of violation (NOV) to AEE and ACR for violations of the Clean Air Act and the Environmental Conservation Law. If the Attorney General, the NYSDEC or the EPA does file an enforcement action against the Somerset, Cayuga, Westover, or Greenidge Plants, then penalties may be imposed and further emission reductions might be necessary at these Plants which could require AEE to make substantial expenditures. The Company 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 AEE and ACR Plants emit nitrogen oxide (NOx) and sulfur dioxide (SO2) as a result of burning coal to produce electricity.

The six Plants have been allocated allowances by the NYSDEC 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. If NOx emissions exceed the allowance amounts allocated to the six Plants, then the Company may need to purchase additional allowances on the open market or otherwise reduce its production of electricity to stay within the allocated amounts. 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 Phase III emission rules commenced on May 1, 2003. The Phase III NOx regulations set forth a NOx allowance allocation program which gives the Company 2,317 NOx emissions allowances for 2004. The six Plants were net sellers of NOX allowances in 2002 and 2001. The six Plants had a shortfall of approximately 1,200 NOx allowances in 2003. The 2003 shortfall was covered by purchasing 70 NOx allowances from AES Ironwood, an indirect wholly owned subsidiary of the AES Corporation at market prices and the remainder of NOx allowances were purchased from unrelated companies in the open market at market price.

The six 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. SO2 allowances may be bought, sold, or traded. If SO2 emissions exceed the allowance amounts allocated to the six Plants, then the Company may need to purchase additional allowances on the open market or otherwise reduce its production of electricity to stay within the allocated amounts. The six Plants were self-sufficient with respect to SO2 allowances in 2001; however, the six Plants had a shortfall of approximately 584 and 10,000 SO2 allowances in 2002 and 2003, respectively. In 2002, ACR sold approximately 6,000 SO2 allowances to the AEE Plants at market prices, then sold the remaining SO2 allowances through 2009. The 2003 allowance shortfall was covered by purchasing SO2 allowances at market prices from unrelated companies in the open market.

In September 2003, New York State determined the amount of NOx emissions allowances that would be allocated to the six Plants. The allocation is several hundred tons short of AEE’s average historical NOx emissions for the Plants during the control period. AEE’s compliance plan cannot be finalized until the anticipated New York NOx allowance market prices are more conclusively determined.

In January 2004, NYSDEC determined the amount of SO2 emissions allowances that would be allocated to the Plants. The allocation is several thousand tons short of the Company’s average historical SO2 emissions for the Plants. The Company’s compliance plan cannot be finalized until the anticipated New York SO2 allowance market prices are more conclusively determined.

In January 2004, the EPA proposed an “interstate air quality rule” that would require further emission reductions in NOx and SO2 emitted from power plants and other sources that significantly contribute to fine particulate (“PM2.5”) and ozone pollution in downwind states. NOx and SO2 are precursors of PM2.5, and NOx is a precursor of ozone. The proposed rule directs 29 states, including New York, to issue new regulations that will require major SO2 and NOx reductions by 2010 and further reductions by 2015. States are encouraged to use a cap and emission trading approach. A final rule is expected to be issued in 2005. At this point, the Company cannot determine what the costs would be to comply with new federal SO2 and NOx emission reduction requirements.

AEE voluntarily disclosed to the NYSDEC 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 Plant’s NOx RACT tracking system. AEE believes that it has 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 NYSDEC for review of the self-disclosure letter and technical issues. AEE is unable to predict any potential actions or fines the NYSDEC may require, if any.

AEE voluntarily disclosed to the NYSDEC 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. It received approximately one 9000-ton train shipment per month from April 24, 2001 to December 27, 2002. In January 2003, AEE became aware that the product the Cayuga Plant was receiving was synfuel. AEE has suspended all shipments from that supplier until a resolution is reached. AEE has reviewed the emission and operation data which showed there was no adverse effect to air quality with respect to applicable permit emissions limits attributable to burning the material. AEE is unable to predict any potential actions or fines the NYSDEC may require, if any. In July 2003, AEE reached an agreement with the supplier to resume shipment of coal in order to satisfy contractual obligations. As part of this agreement, the supplier has provided a written guarantee stating that all fuel shipments will be coal.

In October 1999, ACR entered into a consent order with the NYSDEC to resolve alleged violations of the water quality standards in the groundwater downgradient of an ash disposal site. As a result, the site was closed. AEE2, L.L.C. contributed one-half of the costs to close the landfill, which were approximately $2 million, and it will contribute additional costs for long-term groundwater monitoring. Nevertheless, if a groundwater remediation is required, AEE2, L.L.C. may be responsible for a portion of such costs.

ACR 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 was retained to help evaluate the source of the chemicals and provide recommendations for remediation. The consultant concluded that the cause of the problem was coarse bottom ash with pyrites that has been exposed to air since sluicing of water to the bottom ash ponds has been terminated. ACR notified NYSDEC that at Jennison, where the elevated concentrations are the highest, that ACR is removing the suspect material and anticipate that over time concentrations will subside. ACR has asked NYSDEC for approval of a plan to add additional monitoring wells at Hickling to allow ACR to assess changes in the groundwater that have occurred since use of its pond was terminated.

ACR voluntarily disclosed to the NYSDEC and EPA that the company is conducting an investigation based on conflicting reports of suspected materials buried at the Hickling Plant. Field and laboratory studies have not indicated any evidence of waste disposal that poses a serious risk to potential receptors. ACR has notified both the NYSDEC and EPA of these studies and believes that no further action is required.

In April 2002, the EPA proposed to establish location, design, construction and capacity standards for cooling water intake structures at existing power plants withdrawing more than 50 million gallons per day from rivers, lakes and other bodies of water. 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 final rule was released by the EPA on February 16, 2004. These new rules will impose new compliance requirements on the withdrawal of water, with potentially significant costs, on operating plants across the nation with cooling water intake structures. Cost items include various environmental and engineering studies and potential capital and maintenance costs. AEE is evaluating the potential applicability of the rule and it has not yet determined the effects, if any, of these regulations on its financial position or results of operations. If applicable, the new rule requirements will be addressed when the Plants’ wastewater discharge permits are renewed.

Northeastern U.S. states (including New York) have agreed to work to develop a regional market-based emissions trading system to reduce power plants’ carbon dioxide emissions. The goal is to reach an agreement by April 2005 on a cap and emission trading 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 from operations.

7. RELATED PARTY TRANSACTIONS

AEE has entered into a contract with Somerset Railroad Corporation (SRC), a wholly owned subsidiary of AES NY3, L.L.C., which is an indirect wholly owned subsidiary of AES, pursuant to which SRC will haul coal and limestone to the Somerset Plant and make its rail cars available to transport coal to the Cayuga Plant. AEE will pay amounts sufficient to enable SRC to pay all of its operating and other expenses, including all out-of-pocket expenses, taxes, interest on and principal of SRC’s outstanding indebtedness and all capital expenditures necessary to permit SRC to continue to provide rail service to the Somerset and Cayuga Plants. As of December 31, 2003, 2002 and 2001,

$3.1 million, $3.8 million and $4.2 million, respectively, has been recorded by AEE as operating expenses and other accrued liabilities under this agreement.

Period	Base Rate Loans	LIBOR Rate Loans
August 14, 2000 to August 13, 2002	Base Rate plus 0.625%	LIBOR plus 1.375%
August 14, 2002 to August 13, 2005	Base Rate plus 0.750%	LIBOR plus 1.500%
August 14, 2005 to August 13, 2008	Base Rate plus 0.875%	LIBOR plus 1.625%
August 14, 2012 to August 13, 2014	Base Rate plus 1.125%	LIBOR plus 1.875%
August 14, 2008 to August 13, 2012	Base Rate plus 1.375%	LIBOR plus 2.125%

The principal amount of SRC’s outstanding indebtedness under this credit facility was approximately $19.5 million and $21.4 million as of December 31, 2003 and 2002, respectively.

In November 2000, AEE entered into a three-year agreement for energy marketing services with Odyssey, a wholly owned subsidiary of AES. In March 2002, a new agreement was reached. The new agreement is for a term of five years through February 28, 2007 pursuant to which Odyssey provides data management, marketing, scheduling, invoicing and risk management services for a fee of $300,000 per month. On September 4, 2003, AEE signed an amendment to its March 2002 agreement. Odyssey will also manage the AEE coal and environmental emission credit positions for an additional fee of $100,000 per month. Odyssey acts as agent on behalf of AEE in the over-the-counter and NYISO markets.

Odyssey also manages environmental emission credit positions for other AES facilities. These allowances were purchased on the open market at market prices. From time to time the allowances will be temporarily placed into a AEE's facility allowance account while awaiting transfer to the purchasing facility. In 2003, allowances were purchased and sold in this matter for AES Deepwater, AES Red Oak and AES Ironwood, all indirect wholly owned subsidiaries of the AES Corporation.

Odyssey purchased for AEE's account 70 NOx allowances at market prices from AES Ironwood, a wholly owned subsidiary of the AES Corporation.

As agent, Odyssey manages all energy transactions under AEE and ACR’s name including (i) preparing confirmations for AEE and ACR and approving confirmations with counterparties, (ii) conducting monthly check-outs with counterparties as appropriate before the preparation of invoices, (iii) invoicing counterparties for the term of the transactions and (iv) otherwise managing and executing the terms of the transactions in accordance with their provisions.

Odyssey provides data management services for AEE and ACR by maintaining databases of pricing, load, transmission, weather and generation data to aid in analysis to optimize the value of AEE and ACR’s assets. Odyssey maintains a transaction management system to manage day-ahead commitments with the NYISO and swap and physical values with counterparties and to provide daily financial reporting and end of day budget variance, forward mark-to-market and commercially accepted risk analysis.

Starting in 2001, until the sale of AES New Energy in the third quarter of 2002, AEE entered into bilateral contract transactions with AES New Energy, a wholly owned subsidiary of AES. These transactions included forward sales of electric energy and unforced capacity at market based rates. For the years ended December 31, 2002 and 2001, AEE recognized revenues of approximately $13.9 million and $11.7 million, respectively, related to the physical delivery of electricity or unforced capacity and the subsequent change in the market value of these contracts. AES New Energy was sold in the third quarter of 2002. As of December 31, 2002 and 2001, the related account receivable – trade between AES New Energy and AEE was zero and $2.6 million, respectively. The exposure at December 31, 2001 and 2002 related to these contract transactions was less than 10% of AEE’s estimated cash revenues for the respective year.

AES contributed approximately $162,000 to AEE in 2003, related to the cost of stock options compensation expense. Also $1.5 million and $9.4 million to AEE in 2003, 2002 and 2001, respectively, related to the cost of the stock option compensation expense. Also, AES contributed approximately $1.5 million and $9.4 million to AEE related to the construction of the SCR on Unit 1 of the Cayuga Plant, which became operational on June 7, 2001.

8. BENEFIT PLANS

Effective May 14, 1999, the Company adopted The Retirement Plan for Employees of AES NY, L.L.C. (the Plan), a defined benefit pension plan. The Plan covers people employed both under collectively bargained and non-collectively bargained arrangements. Certain people formerly employed by NYSEG (the Transferred Persons) receive credit under the Plan for compensation and service earned while employed by NYSEG. The amount of any benefit payable under the Plan to a Transferred Person will be offset by the amount of any benefit payable to such Transferred Person under the Retirement Plan for Employees of NYSEG. Effective May 29, 1999, the ability to commence participation in the Plan and the accrual of benefits under the Plan ceased with respect to non-collectively bargained people and the accrued benefits of any such participant were fixed as of such date. As of December 31, 2003, the Plan was funded at least to the extent required by Internal Revenue Code (IRC) Section 412 minimum funding and not more than the requirement of IRC Section 404, maximum contribution limits. The Company will make the required minimum contribution within the Employee Retirement Income Security Act (ERISA) guidelines. Pension benefits are based on years of credited service, age of the participant, and average earnings. During 2003, 2002 and 2001, collectively bargained people were offered the opportunity to freeze their accrued benefit payable under the Plan and opt into the AES Profit Sharing and Stock Ownership Plans.

	2003			2002
Projected Benefit Obligation
Change in projected benefit obligation (in thousands):
Projected benefit obligation, beginning of period	$	26,780		$	23,392
Service cost	375			347
Interest cost	1,585			1,209
Actuarial (gain) loss	(1,410		)	—
Benefits paid	(955		)	(305		)
Curtailment	—			(790		)
Special Termination Loss	—			2,297
Projected benefit obligation, end of period	$	26,374		$	26,780
Plan Assets:
Change in plan assets (in thousands):
Fair value of plan assets (in thousands):	$	8,711		$	6,762
Actual return on plan assets	1,092			(711		)
Employer contributions	2,161			2,965
Benefits paid	(955		)	(305		)
Fair value of plan assets, end of period	$	8,711		$	8,711
Funded status/accrued benefit liability	$	(11,009	)	$	(18,069	)
Unrecognized Net (Gain)	1,873			(78		)
(Accrued)/Prepaid Pension Cost, end of period	$	(17,238	)	$	(18,147	)

Defined Benefit Pension Plan Costs:
Components of net periodic benefit cost (in thousands)
Service cost	$	367		$	416
Interest cost	1,611			1,451
Expected return on plan assets	(726		)	(619		)
Curtailment gain	—			—
Net periodic benefit cost	$	1,252		$	1,248

The discount rate utilized for determining future pension obligations is based on a review of long-term bond rates. The discount rate has remained at 6.25% since 2000. Future actual pension obligations will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Company’s pension plans.

	2003		2002

Discount rate	6.25	%	6.25	%
Expected long-term rate of return on plan assets	8.00	%	8.00	%
Rate of compensation increase	4.75	%	4.75	%

The projected benefit obligation of the Plan as of May 14, 1999, as actuarially determined, was recorded by the Company as a purchase accounting liability (see Note 3) under Accounting Principles Board Opinion (APB) No. 16, “Business Combinations”. The accumulated benefit obligation was approximately $23.3 million and $22.1 million as of December 31, 2003 and 2002, respectively.

Significant assumptions were used in the calculations of the net benefit cost and projected benefit obligation for the periods ending October 31, 2003 and 2002 and December 31, 2001. In developing the Company’s expected long-term rate of return assumption, the Company evaluated input from its actuaries and plan asset manager. Projected returns are based on a broad range of equity and bond indices. The Company’s expected 8% long-term rate of return on Qualified Plan assets is based on the allocation assumption of 60% equities (50% growth and 50% value), with a 10% long-term rate of return, and 40% in fixed income investments, with a 5.5% long-term rate of return. Because of market fluctuation, its actual, was 58% and 52% equities and 42% and 48% in fixed income investments allocation as of October 31, 2003 and 2002, respectively. However, the Company believes that its long-term asset allocation on average will approximate 60% equities and 40% fixed income investments. The Company regularly reviews the asset allocation with the asset manager and periodically rebalance the Plan’s investments to its targeted allocation when appropriate. The Company continues to believe that 8% is a reasonable long-term rate of return on its qualified plan assets, despite the market downturn. The Company will continue to evaluate its actuarial

assumptions, including its expected rate of return, at least annually, and will adjust as necessary.

As of December 31, 2003, the Plan had 265 active participants.

Plan Assets

AEE’s pension plan pension plan target asset allocations at December 31, 2003 and 2002, are as follows:

Asset Category	2003		2002
Equity securities	60	%	60	%
Debt securities	40	%	40	%

All three components are based primarily on historical data, with modest adjustments to take into account additional relevant information that is currently available. For the inflation and risk-free return components, the most significant additional information is that provided by the market for nominal and inflation-indexed U.S. Treasury securities. That market provides implied forecasts of both the inflation rate and risk-free rate for the period over which currently-available securities mature. The historical data on risk premiums for each asset class is adjusted to reflect any systemic changes that have occurred in the relevant markets; e.g., the higher current valuations for equities, as a multiple of earnings, relative to the longer-term average for such valuations.

Cash Flows

AEE expects to contribute $6.7 million to it’s pension plan in 2004.

Estimated Future Benefits

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Fiscal Years ending December 31,	Payments
2004	$	987
2004	1,030
2005	1,102
2006	1,210
2007	1,325
Thereafter	8,336
Total Estimated Future Benefits	$	13,990

Additionally, people of the Company and its subsidiaries participate in the AES Profit Sharing and Stock Ownership Plans. The plans provide employer matching contributions. Participants are fully vested in their own contributions and the employer’s matching contributions. AEE contributed to AES Profit Sharing and Stock Ownership Plans approximately $885,198 and $809,000 in 2003 and 2002, respectively.