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, 2004

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.)

4300 Wilson Boulevard Arlington, Virginia		22203
(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. o

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 the common equity was last sold, or the average bid and asked price of such common equity, as of 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

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 4300 Wilson Boulevard, Arlington, Virginia 22203, 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.

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

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. The Partnership’s working capital contribution of approximately $1.5 million was deducted in the first half of 2004.

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.

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 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 though a modification of its Prevention of 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 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.

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 had 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.

We have started a two prong the process to re-start this project; we have to submitted documents to initiate a process, which concludes in signing a Co-operative agreement with the Department of Energy and we have completed a bidding process to select an EPC contractor. On December 9, 2004, the AES Board of Directors passed a resolution to fund the Greenidge’s $29.9 million share of the project.

Somerset Railroad Corporation

The Somerset Railroad was acquired by AES NY3, L.L.C., an indirect wholly owned subsidiary of AES. The Somerset Railroad owns a short line railroad assets used to transport coal and limestone. We have entered into a contract with Somerset Railroad pursuant to which Somerset Railroad will haul coal and limestone to the Somerset Plant and make its rail cars available to transport coal to the Cayuga Plant. As a result of the adoption of revised Financial Accounting Standards Board (FASB) interpretation No. 46(R)”Consolidation of Variable Interest Entities”, on January 1, 2004, we began consolidating the financial results of Somerset Railroad with our consolidated financial statements. See Note 2 of our audited financial statements, which are included in this Annual Report on Form 10-K, for further discussion.

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. In November 2004, we received approval from the New York State Public Service Commission to increase 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 sites 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, any other costs to bring us in to compliance with the January 11, 2005 Consent Decree discussed below under “Air Emissions” 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.

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 $640 to $750 per ton. We had shortfalls of approximately 6,600, 10,000 and 1,000 SO2 allowances in 2002, 2003 and 2004, respectively. The majority of the 2002 SO2 allowance shortfall was covered with allowances purchased from the electricity generating stations owned by ACR, whi ch are on long-term cold standby. The allowances were purchased at quoted market prices. The 2003 and 2004 shortfalls were 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 2005 and 2006, respectively, we forecast that we will have surplus SO2 allowances.

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 emission rules have been superseded by the transition to the federal NOx SIP Call rule, which imposes NOx ozone season emission reduction requirements through an allowance system similar to the Phase III emission rules. Under the NOx SIP Call rule, electric generating facilities in 21 Northeast and Mid-Atlantic states and the District of Columbia are required to hold allowances sufficient to cover the ozone season NOx emissions emitted by such facilities. Each of our electricity generating stations is subject to the NOx SIP Call rule, and we have been allocated 2,492 NOx allowances for the 2005 ozone season. The NOx SIP Call program commenced on May 31, 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 and 2002. We expect that Somerset and Cayuga will accumulate excess allowances during the 2005 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, we were a net seller of NOx allowances. In 2003 and 2004, we were short approximately 1,200 and 1,020 NOx allowances, respectively. 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 2003 and 2004 shortfall of NOx allowances was covered by purchasing NOx allowances from unrelated companies in the open market at market prices.

Based on current market pricing of electricity and NOx allowance forwards for the years 2005 and 2006, respectively, we forecast that we will have a shortfall of approximately 400 and 310 NOx allowances. The shortfalls 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.

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 are reviewing our options for a catalyst maintenance plan. We have estimated that the current catalyst maintenance which is scheduled for 2006 will cost $280,000.

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 exceedences appear to have occurred on October 30 and 31 and November 1-8 and 10 of 2002. The exceedences 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 exceedences. Immediately upon discovery of the exceedences, 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 exceedences were discovered. The EPA has decided to defer to the NYSDEC for review of the self-disclosure letter and technical issues. Recently, we have learned of a Notice of Violation (“NOV”) issued by the NYSDEC for the NOx RACT exceedences through a review of the November 2004 release of the EPA’s Enforcement and Compliance History “ECHO” database. We have not yet received the NOV from the NYSDEC. We are unable to predict any potential actions or fines the NYSDEC may require, if any.

New York State Air Emission Regulations. 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 and reguire non-ozone season NOx emissions reductions based on 1.15 lbs/Mmbtu. The final regulations (6 NYCRR Parts 237 and 238) were adopted in March 2003. The new NOx regulations became effective October 1, 2004 and the new SO2 regulations will be phased in starting January 1, 2005, with full implementation complete by January 1, 2008.

On May 26, 2004, the New York Supreme Court struck down the Acid Deposition Reduction Program regulations (6 NYCRR Parts 237 and 238). The Court ruled that the regulations had been adopted improperly after the State missed a deadline for publication of a notice to inform the public of proposed changes in the regulations. On July 1, 2004, NYSDEC appealed the Court’s ruling.

On August 17, 2004, the NYSDEC announced the adoption of emergency regulations to implement the Acid Deposition Reduction Program as originally scheduled. A number of entities challenged the adoption of the emergency regulations. On October 19, 2004, a State Supreme Court Judge dismissed the petition challenging New York State’s adoption of emergency regulations to implement the Acid Deposition Reduction Program as originally scheduled.

In January 2004, NYSDEC determined the amount of SO2 emissions allowances that would be allocated to our electricity generating stations. The allocation is approximately our average historical SO2 emissions for our electricity generating stations.

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 strategy involves reduced operations of our non-reheat units,

reducing emission rates and/or the selling/buying or trading of New York State SO2 and NOx allowances. See Item 7 - Management's Discussion and Analysis - Future Issues and Other Matters.

Muti-Pollutant Proposed Regulations. On March 10, 2005, the EPA Acting Adminstrator signed the final Clear Air Interstate Rule that will 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 final rule directs 28 states, including New York, to issue new regulations that will require major SO2 and NOx reductions by 2015. States must achieve the required NOx and SO2 reductions by meeting a state-specific emissions budget through one of two compliance methods: (i) requiring electric generating facilities in the state to participate in an EPA-administered cap and trade regime that caps emissions in two phases with the first phase in 2010 and a second phase commencing in 2015, or (ii) meeting the budget levels through measures selected by a particular state that are approved by the EPA. States are encouraged to use a cap and emission trading approach. At this point, we cannot determine what the costs would be to comply with new federal SO2 and NOx emission reduction requirements.

On November 10, 2004, the Ozone Transport Commission, a multi-state organization created under the Clean Air Act, agreed to develop a multi-pollutant emission control program for power plants for the Northeast/Mid-Atlantic states. A model rule for each state to use is due no later than June 2006. Until these rules are developed, we cannot determined the effects of this rule on our financial condition or results of operations.

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 were 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 NOV to NYSEG for violations of the Clean Air Act and the New York 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 would 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.

On January 11, 2005, three subsidiaries which we control (AEE2, L.L.C., AES Greenidge, L.L.C. and AES Westover, L.L.C.) and two subsidiaries controlled by ACR (“AES Entities”) entered into a consent agreement to settle all outstanding NOVs and civil claims that could have been brought by the State of New York against the AES Entities and NYSEG for the alleged violations of the new source review and new source performance standard provisions of the Clean Air Act and its applicable regulations, similar provisions under the New York Environmental Conservation Law and its applicable regulations, common law, and State Executive Law (the “Consent Decree”). The Consent Decree is expected to be entered by the United States District Court for the Western District of New York after completion of a public comment period and a separate 45 day period in which the Federal Government may submit comments. The Federal Government also has the opportunity to intervene in the case. The Consent Decree will become

effective when it is entered by the Court. Under the terms and conditions of the Consent Decree, upon entering into effect, the State of New York covenants not to sue and releases the participating AES Entities and NYSEG from alleged violations under the above-mentioned air emission laws and regulations and also covenants not to sue or bring any administrative enforcement actions against the participating AES Entities for claims under the above-mentioned air emission laws and regulations associated with work required pursuant to the Consent Decree or other changes at the electricity generating stations commenced after entry of the Consent Decree, but prior to December 31, 2009 and completed by December 31, 2010. Under the Consent Decree, the AES Entities have agreed to pay a $700,000 civil penalty for the violations assessed to NYSEG and will deposit $1,000,000 in an AES Environmental Mitigation Project Account that will be used to carry out one or more projects pertaining to energy efficiency, renewable energy and/or clean air projects that are approved by the NYSDEC and the Office of the Attorney General. The Consent Decree does not address the Somerset and Cayuga electricity generating stations, and it is possible that these two plants may be subject to a separate enforcement action filed either by the United States Environmental Protection Agency, NYSDEC, or the New York State Attorney General.

The Consent Decree sets forth mandated emission reductions and requires the installation of new emission control technologies on certain units or the repowering of or the ceasing of operations of such units. On Greenidge Unit 4, we are obligated to control SO2 and NOx emissions through a multi-pollutant control clean coal project (“MCP Project”). This obligation is subject to the partial funding of the MCP Project by the U.S. Department of Energy and the absence of any force majeure event or material adverse change in circumstances that affects the economic viability of the MCP Project. We are required to commence initial operation of the MCP Project by September 1, 2006 or a date eighteen months after entry of the Consent Decree, whichever is later. We are also obligated to use good faith efforts to meet certain NOx emission rates and achieve a certain SO2 removal efficiency during normal operations on Greenidge Unit 4. If the MCP Project on Greenidge Unit 4 is discontinued, we are required by December 31, 2009 either to (i) install control technology that will meet the Consent Decree emission limits, (ii) repower with a non-coal fuel source or (iii) cease operations.

On Westover Unit 8, we are obligated under the Consent Decree to take one of the following three actions by December 31, 2009 and to notify the NYSDEC of which action we elect to take by June 1, 2007: (i) control NOx and SO2 using technology similar to the MCP Project on Greenidge Unit 4, (ii) repower with a non-coal fuel source or (iii) cease operations. Beginning in 2005 and lasting through 2009, Westover Unit 8 is subject to a declining SO2 emissions cap that starts with a cap in 2005 and declines per year until 2009. Should we elect to install emission control technology on Westover Unit 8 by December 31, 2009, then we are obligated under the Consent Decree to use good faith efforts to meet a certain NOx emissions rate and a certain SO2 removal efficiency.

Under the Consent Decree, Greenidge Unit 3 and Westover Unit 7 are required either to (i) install control technology equivalent to Best Available Control Technology or BACT, (ii) be repowered with a non-coal fuel, or (iii) cease operations, no later than December 31, 2009. During the years 2007, 2008, and 2009, these two units will be subject to an annual operating limit of 1,400 hours with an SO2 emission rate of 3.0 lb/mmBtu. The Consent Decree does allow us to use up to a 30% blend of sub-bituminous (reduced sulfur) coal at either the Greenidge or Westover electricity generating stations.

The Consent Decree also requires the surrender of federal Acid Rain Program SO2 allowances for Greenidge Units 3 and 4 and Westover Units 7 and 8 starting in the year 2012. The amount of allowances that will be surrendered depends on which compliance option we ultimately select for these units.

In the event that we fail to comply with one or more terms of the Consent Decree, we are obligated to pay stipulated penalties that are set forth in the Consent Degree with the exception of noncompliance due to force majeure events or certain material adverse conditions affecting the economic viability of the MCP Project. Upon achieving compliance with the material requirements of the Consent Decree, then the parties to the settlement may petition the court for termination of the Consent Decree. We expect that the emission reduction and control technology requirements set forth in the Consent Decree will be incorporated into each electricity generating stations’s Title V air operating permit.

We have projected that our share of the capital costs to install the MCP Project at Greenidge Unit 4 will be approximately $29 million, however, there can be no assurance that this will be the actual cost since we have not entered into an agreement for engineering, procurement and construction of the MCP Project at Greenidge Unit 4.

At this time, we have not made decisions regarding the options of either installing pollution control technology, repowering or ceasing operations at the other units subject to the terms of the Consent Decree, and thus we are unable to project the potential costs associated with complying with the other provisions of the Consent Decree on our financial condition or the effect on future operations.

The EPA is not a signatory to the Consent Decree, and it is possible that EPA could separately issue us a NOV for alleged violations of the federal Clean Air Act and federally enforceable New York air regulations at the Greenidge and Westover electricity generating stations involving suspected past modifications of plant equipment without undergoing an air permitting review. If EPA does file an enforcement action against Greenidge and Westover, then penalties may be asserted and further emission reductions might be necessary which could require us to make substantial expenditures. We are unable to estimate the effect of any EPA-issued NOV on our financial condition or results of future operations.

Mercury. On March 15, 2005, the EPA Acting Adminstrator signed the final Clear Air Mercury Rule that will regulate mercury emissions from existing and new coal-fired power plants. The final rule requires the reduction of mercury emissions to be achieved through a cap and emission trading program with the first phase commencing in 2010 and the second phase starting in 2018. At this point, we cannot determine what the costs would be to comply with new federal mercury emission reduction requirements.

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 Protocol relating to reduction of greenhouse gas emissions 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 Protocol and the President’s initiatives. On February 16, 2005, the Kyoto Protocol became effective.

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. We had entered into an agreement with a supplier to purchase coal. We 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 suspended all shipments from that supplier until a resolution was reached. We 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 as 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 July 2004, the EPA final rule for regulating existing power plants under Section 316(b) of the Clean Water Act was published in the Federal Register. This rule became effective on September 7, 2004. This new rule imposes new compliance requirements, 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 have not yet determined the effects of this rule on our financial condition or results of operations.

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 plants, 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 had budgeted $7.6 million for the cost for environmental liabilities at our plants (excluding closure and post closure for the Weber and Lockwood ash disposal sites), based on estimates of environmental consultants retained by NYSEG and The AES Corporation. In 2002 and 2003, we reduced our liability by $800,000 and $180,000, respectively as remediation was completed or the more current estimates received were lower than the amounts previously estimated. We have budgeted approximately $6.2 million for closure and post-closure (monitoring and maintenance) expenses for the Weber and Lockwood ash disposal sites, based solely on amounts previously budgeted for these activities by NYSEG. In 2001 and 2002, we reduced this liability by $600,000 and $1.4 million, respectively, as remediation was completed at lower costs than previously estimated. On January 1, 2003, $4.2 million was reclassified into a liability obligation in accordance with SFAS 143.

ACR assumed responsibility for one-half of the closure costs of 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 approximately $2 million which was one-half of the closure costs, 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.

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 modify the slopes and height of Area 1 and allow the landfilling of petroleum coke fly ash and stabilized sludge produced during operation of the SCR and FGD system at Area 1.

On April 28, 2004, the Public Service Commission approved a compliance filing for Area 2 in part. The compliance filing addressed the design and operation of Area 2 which will accept stabilized coal combustion by-products after Area 1 has reached capacity. The Public Service Commission did not permit the landfilling of “ammoniated sludge” until we have submitted a petition to modify the Certificate of Environmental Compatibility and Public Need. We have submitted a petition to clarify and/or amend the Certificate of Environmental Compatibility and Public Need and are expecting the New York State Board on Electric Generation Siting and the Environment to issue an order.

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 and Public Need 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.

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. There can be no guarantee that the currently budgeted amounts will be sufficient to investigate and remediate the site, if needed.

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, or to what extent they 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, which could result in a material cost to us or otherwise adversely impact our financial condition or results of operations.

Noise

The Certificate of Environmental Compatibility and Public Need 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 2004, 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.

On February 5, 2004, Grover Hedgecock filed a Summons and Complaint to be served on AES Westover, LLC, wherein he seeks to recover damages for negligence. The plaintiff, hired by an outside contractor, alleges that Westover was negligent in an accident that the plaintiff had at Westover in November 2002. Our insurance will cover the loss, if any, minus a deductible. We have turned this matter over to our insurance carrier’s attorneys.

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,	2004*		2003		2002		2001		2000
Balance Sheet Data (in millions)
Total assets	$	1,103	$	1,118	$	1,126	$	1,194	$	1,185
Long term liabilities	$	711	$	682	$	688	$	699	$	678
Minority Interest	$	8	—		—		—		—
Partners’ capital	$	227	$	348	$	382	$	433	$	441

For the period ending December 31,	2004		2003		2002		2001		2000
Statement of Income Data (in millions)
Total revenue	$	411	$	426	$	367	$	378	$	388
Operating income	$	114	$	147	$	114	$	106	$	151
Net income	$	57	$	89	$	59	$	52	$	98

*Includes assets and liabilities of Somerset Railroad which is now consolidated in our consolidated financial statements in accordance with revised Financial Accounting Standards Board Interpretation No. 46(R), “Consolidation of Variable Interest Entities”. See Note 2 of our audited financial statements, which are included in this Annual Report on Form 10-K.

SELECTED QUARTERLY FINANCIAL DATA (Unaudited)

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

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
YEAR ENDED DECEMBER 31, 2004:
Operating revenue**	$	104,987	$	98,783	$	103,148	$	103,736
Operating income	32,838		25,067		28,355		27,480
Net income from continuing operations Before minority interest	18,415		10,862		13,933		13,525
Net income	18,484		10,910		14,192		13,713

YEAR ENDED DECEMBER 31, 2003:
Operating revenue**	$	109,064	$	99,228	$	119,324	$	98,414
Operating income	43,220		35,794		47,767		20,337
Net income before cumulative effect of change in accounting principle	29,248		—		—		—
Net income	27,592		21,659		33,492		6,323

**Certain prior period amounts have been reclassified in the quarterly consolidated financial statements to conform with the year-end 2004 presentation.

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.

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 2004, 2003 and 2002, the stations had a weighted average (based on capacity) equivalent availability factor of 96%, 93% and 96%, respectively (excluding the scheduled outages at Cayuga from April to June 2004 for a major scheduled maintenance turbine outage). We believe that we can maintain or improve the availability of our electricity generating stations.

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, expired in October and was not renewed, was not deemed to be a hedge based on the definitions in Statement of Financial Accounting Standards (“SFAS”) No. 133. Therefore, this contract was marked-to-market at the end of every period. The mark-to-market value was computed based on a

regression of historical eastern and western locational prices. This regression was used with forecasted eastern and western locational prices to calculate the forward congestion for the remainder of the contract term. This accounting treatment contributed 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 of electricity 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 21 years. If the estimated average remaining life of our property, plant and equipment were to decrease by five years, annual depreciation would increase by $7.7 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

We account for derivative instruments and hedging activities in accordance with 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, 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, 2004, 2003 and 2002, we recognized losses of $3.8 million and $6.2 million and income of $8.9 million, respectively, pursuant to SFAS No. 133 related to derivatives which did not qualify for hedge accounting. See Note 2 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,	2004		2003		% Change		2002		% Change
Energy Revenue	$	382.7	$	394.2	(2.9	)	$	315.0	25.1

Capacity Revenue	23.1		29.7		(22.2	)	36.6		(18.9	)

Transmission Congestion Contract	—		—		—		8.9		—

Other	4.8		2.2		—		6.9		(68.1	)

Energy revenues for the year ended December 31, 2004 were $382.7 million, compared to $394.2 million for the year ended December 31, 2003, a decrease of 2.9%. The decrease in energy revenues is primarily due to a scheduled major maintenance outage at Cayuga of approximately 63 days for Unit 2 that was offset by higher market prices and demand. Market prices for peak and offpeak electricity were 1.84% and 3.08% higher than the year ended December 31, 2003. Demand for peak and offpeak electricity increased 1.25% compared to the demand for the year ended December 31, 2003. Energy revenues for the year ended December 31, 2003 were $394.2 million, compared to $315 million for the year ended December 31, 2002, an increase of 25.1%. The increase in energy revenues was 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.

Capacity revenues for the year ended December 31, 2004 were $23.1 million, compared to $29.7 million for the year ended December 31, 2003, a decrease of 22.2%. 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, 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 was primarily due to lower prices for capacity sales on the open market for the summer capacity period (June - October) and the winter capacity period (November-May).

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

The Transmission Congestion Contract, which expired in October 2004 and was not renewed, was 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 terminated 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 was not deemed to be a hedge based on the definitions in SFAS 133. Therefore, this contract was marked to market at the end of every period. The mark-to-market value was computed based on a regression of historical eastern and western locational prices. This regression was used with forecasted eastern and western locational prices to calculate the forward congestion for the remainder of the contract term. This accounting treatment contributed to the income statement volatility of this contract.

Operating Expenses

For the Year Ended December 31,	2004		2003		% Change		2002		% Change
Fuel expense	$	156.2	$	148.3	5.3		$	137.2	8.1

Depreciation and amortization	39.4		36.1		9.1		35.5		1.7

Operations and maintenance	30.7		28.6		7.3		21.4		33.6

General and administrative	65.6		59.2		10.8		59.1		0.2

Transmission Congestion Contract	3.8		6.2		(38.7	)	—		—

Fuel expense for the year ended December 31, 2004 was $156.2 million, compared to $148.3 million for the year ended December 31, 2003, an increase of 5.3%. The increase in fuel expense is primarily due to higher contract coal prices and higher allowance prices. 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 was primarily due to higher operating levels, which necessitated greater coal usage and greater coal purchases on the spot market.

Depreciation and amortization expense for the year ended December 31, 2004 was $39.4 million, compared to $36.1 million for the year ended December 31, 2003, an increase of 9.1%. This increase is primary due to the consolidation of Somerset Railroad’s depreciation of $2.4 million. 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 and the overfire air system installed at Westover Unit 8.

Operations and maintenance expense for the year ended December 31, 2004 was $30.7 million, compared to $28.6 million for the year ended December 31, 2003, an increase of 7.3%. This increase was primarily due to maintenance expenses incurred during a scheduled major turbine maintenance outage at Cayuga of approximately 63 days for Unit 2, which are not annually recurring expenses. Operations and maintenance expense for the year ended December 31, 2003 was $28.6 million, compared to $21.4 million for the year ended December 31, 2002, an increase of 33.6%. This increase is primarily due to maintenance expenses incurred during scheduled boiler outages at every electricity generating station during 2003.

General and administrative expense for the year ended December 31, 2004 was $65.6 million, compared to $59.2 million for the year ended December 31, 2003, an increase of 10.8%. This increase was primarily due to significant increases in property taxes and property and medical insurance. 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%.

Other Income/Expenses

For the Year Ended December 31,	2004		2003		% Change	2002		% Change
Interest expense	$	58.9	$	58.5	0.7	$	57.7	1.4

Interest Income	1.9		2.1		9.5	2.1		—

Other Income/Expenses for the year ended December 31, 2004 were net expenses of $57 million, compared to net expenses of $56.4 million for the year ended December 31, 2003, an increase of 1.1%. The interest portions of the payments under the leases for Somerset and Cayuga were set at the issuance and vary from year to year. 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 1.4%. This increase is primarily due to higher interest expense.

Liquidity and Capital Resources

Operating Activities

Net Cash provided by operating activities of $89.8 million for the year ended December 31, 2004 reflects the decrease in net income due to decreased electricity revenues offset in part by the changes in current assets and liabilities.

Investing Activities

Net cash provided by investing activities of $11.1 million for the year ended December 31, 2004 reflects a decrease in our restricted cash accounts of $26.4 million offset by approximately $13.8 million in capital expenditures and the $1.5 million increase in the NYSISO working capital fund.

We incurred approximately $13.8 million, $5.4 million and $7.1 million in capital expenditures with regard to our assets for the years ended December 31, 2004, 2003 and 2002, respectively. These amounts include $1.4 million for the overfire air project to reduce NOx emissions at Westover Unit 8 in 2003. 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 of Somerset and Cayuga.

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, any other costs to bring us into compliance with the January 11, 2005 Consent Decree, 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, 2004 of $100.9 million reflects principal payments on our leases of $9.7 million, payment of a distribution to our partners of $89.9 million and payments for deferred financing of $1.8 million offset by a partner’s contribution of $415,000 and proceeds from other debt of $137,000.

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 debt incurred in connection with the leases for 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 $59.9 million for 2005, $61.6 million for 2006, $62.5 million for 2007, $62.5 million for 2008, $62.5 million for 2009 and a total of $1,127.2 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, 2004, 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, 2004 and 2003, 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. Through this agreement we have, in effect, guaranteed the interest on and principal of Somerset Railroad’s 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 Somerset Railroad’s $26 million credit facility are $1.9 million per year.

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 could 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 included another one-year extension of the facility which extended the maturity date of the working capital and letter of credit facility to January 2, 2005. The

amendment also increased 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 included a commitment from Citibank, N.A. for the remaining $15 million of the facility. There were five 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. The fifth borrowing was for $14.3 million on July 9, 2004 at an interest rate of 5.75%. This borrowing was repaid in full on July 26, 2004.

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 (the “AES Letter of Credit Agreement”), 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 superseded the authorization of AES on February 25, 2003. The agreement limited the letters of credit amounts and cash collateral to the stated amounts and set into place a fee structure and repayment terms.

On October 26, 2004, we and The AES Corporation agreed to terminate the commitment of The AES Corporation to provide letters of credit and cash collateral for our benefit under the AES Letter of Credit Agreement.

Pursuant to the AES Letter of Credit Agreement, The AES Corporation had agreed to provide, or cause to be provided, letters of credit and cash collateral to counterparties to support our obligations arising in connection with our sale of electricity. The AES Corporation agreed that the maximum amount of letters of credit and cash collateral that The AES Corporation would provide, or cause to be provided, pursuant to the AES Letter of Credit Agreement would be $95 million from April 28, 2004 until December 31, 2004 and $60 million from January 1, 2005 until December 30, 2005. On October 14, 2004, The AES Corporation Board of Directors passed a resolution regarding extension of authorized credit support for us. The Board of Directors resolved to authorize The AES Corporation to extend us use of $95 million in letter of credit capacity through December 31, 2006. As of December 31, 2004, we had obtained letters of credit in the amount of $58.9 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

The termination of AES’s commitment under the AES Letter of Credit Agreement does not affect outstanding authorizations of letters of credit or cash collateral. We remain obligated to perform our responsibilities under the AES Letter of Credit Agreement with respect to any outstanding letters of credit or cash collateral agreements until the earlier of such time as we replace such outstanding letters of credit or cash collateral agreements or the stated expiration date of such letters of credit or cash collateral agreements shall occur.

The AES Corporation is not obligated to provide any such letters of credit in the future and will review any request for the issuance of an authorization for such letters of credit on a case by case basis and may refuse any request for the issuance of such letters of credit for any reason, or for no reason.

On October 26, 2004, we entered into an Amended and Restated Credit Agreement with Calyon New York Branch and the Banks and the Issuing Banks named therein (the “Calyon Credit Facility”). Also on October 26, 2004, Calyon New York Branch purchased the outstanding loans made under our existing $35,000,000 credit facility, dated as of April 10, 2001, as amended, and the unreimbursed drawings under letters of credit issued under the existing credit facility. In addition, Calyon New York Branch assumed all of the rights and obligations of the banks under the existing credit facility including the commitments of such banks to make loans and issue letters of credit.

Under the Calyon Credit Facility, the Banks have agreed, from time to time until January 28, 2008, to make loans to and issue letters of credit on our behalf. The maximum aggregate principal amount of loans, outstanding letters of credit and unreimbursed drawings under letters of credit issued under the Calyon Credit Facility which may be at any one time outstanding initially was $35 million and was increased to $75 million when subsquent approval by the New

York State Public Service Commission was obtained on November 10, 2004. We may borrow, pay or prepay and reborrow loans.

Loans may, at our option, be made under the Calyon Credit Facility as Base Rate Loans or Eurodollar Rate Loans or any combination thereof. Base Rate Loans bear interest at an interest rate per annum equal to the sum of (1) the higher of (a) the Prime Rate announced by Calyon New York Branch from time to time in effect and (b) the sum of the Federal Funds Rate in effect plus 0.50%, plus (2) an applicable margin of 0.75% until October 26, 2006 and 1% thereafter. Eurodollar Rate Loans bear interest at an interest rate per annum (rounded upwards, if necessary, to the nearest whole multiple of 1/100 of 1%) equal to the sum of (1) the London interbank offered rate for deposits in Dollars two business days prior to the first day of an Interest Period (a period of one, two, three or six months selected by us) for a term comparable to such Interest Period, plus (2) an applicable margin of 1.75% until October 26, 2006 and 2% thereafter. As of December 31, 2004, of the $75 million committed, we had obtained letters of credit of $51.6 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

Our obligations under the Calyon Credit Facility are secured by our pledge of the membership interests in our wholly owned subsidiary, AEE2, L.L.C. (which owns the Westover and Greenidge electric generating plants), as well as AEE2, L.L.C.’s wholly owned subsidiaries, AES Westover, L.L.C. (which operates the Westover electric generating plant) and AES Greenidge, L.L.C. (which operates the Greenidge electric generating plant).

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 each of the rent payment dates from the first payment January 2, 2001 through January 2, 2005. 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 $75 million Calyon Credit Facility, 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 available for the payment of Debt, distributions to partners and operating income in the period incurred would be reduced.

The outage at Cayuga for almost the entire period from March 31, 2004 to June 4, 2004 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 leases 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 $415,000, $162,000 and $1.5 million to us in 2004, 2003 and 2002, respectively. The contributions, which were accounted for as a partner’s contribution, related to stock option compensation expense in 2004 and 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.

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.

New Accounting Pronouncements

Variable Interest Entities

In January 2003, the FASB issued FASB Interpretation No. (“FIN”) 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 FIN 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.

On January 1, 2004, we adopted FIN 46(R) and prospectively charged the method of accounting to consolidate SRC Prior period amounts have not been restated. Our consolidated balance sheet as of December 31, 2004 reflects additional assets of approximately $25.6 million and liabilities of approximately $17.3 million as a result of this consolidation. Since SRC is owned by another affiliate of The AES Corporation, the consolidated balance sheets and consolidated statements of income and cash flow included in our financial statements show such ownership as minority interest.

Share-Based Payment

In December 2004, the FASB issued a revised SFAS No.123 (“SFAS No. 123R”), “Share-Based Payment”, which is a revision of SFAS No. 123. SFAS No. 123R eliminates the intrinsic value method under APB 25 as an alternative method of accounting for stock-based awards by requiring that all share-based payments to employees, including grants of stock options for all outstanding years be recognized in the financial statements based on their fair values. It also revises the fair-value based method of accounting for share-based payment liabilities, forfeitures and modifications of stock-based awards and clarifies SFAS No. 123’s guidance related to measurement of fair value, classifying an award as equity or as a liability and attributing compensation to reporting periods. In addition, SFAS No. 123R amends SFAS No. 95, “Statement of Cash Flows”, to require that excess tax benefits be reported as a financing cash flow rather than as an operating cash flow.

We are required to adopt SFAS No. 123R for the interim period beginning July 1, 2005 using a modified version of prospective application. We may apply a modified retrospective application to periods before the required effective date. We plan to adopt SFAS No. 123R no later than July 1, 2005, but has not determined what method it will use. We are currently evaluating the effect of adoption of SFAS No. 123R, but does not expect the adoption to have a material effect on our financial condition, results of operations or cash flows, as we have previously adopted income statement treatment for compensation related to share-based payments under SFAS No. 123.

Contractual Obligations

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

Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		After 5 years
Debt Obligations	$	18,870	$	2,459	$	4,226	$	3,821	$	8,364
Capital Lease Obligations (1)	$	1,435,673	$	59,450	$	124,050	$	125,000	$	1,127,173
Purchase “Take-or-Pay” Obligations	$	187,931	$	105,099	$	82,832	—		—
Other Long-term Obligations reflected on Balance Sheet	29,772		4,739		5,309		3,170		16,554
TOTAL	1,672,246		171,747		216,417		131,991		1,152,590

(1) Capital Lease Obligations includes imputed interest.

Future Issues and Other Matters

Because of current quoted prices of Federal SO2 allowances, New York SO2 and NOx allowances and coal prices, the older non-reheat units of Greenidge and Westover Plant’s total production costs are at or higher than the current New York Independent System Operator’s dispatch prices as of March 31, 2005. This will limit the dispatch of these units until either energy price increase or there is a reduction in coal or federal and state allowance prices. We are working to minimize the effects to our operating income, with the reduction of coal or environmental credits purchased or selling any excess, therefore we do not think that the reduced capacity factors will have a material impact on our financial positions or results of operations.

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, 2004, 2003 and 2002 was $10.1 million, $5.8 million and $4.8 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, 2004, the daily VaR amount was never greater than the year-end amount. 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.

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.

Report of Independent Registered Public Accounting Firm

Financial Statements:

Consolidated Balance Sheets as of December 31, 2004 and 2003
Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002.
Consolidated Statements of Changes in Partners’ Capital for the years ended December 31, 2004, 2003 and 2002.
Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002.
Notes to Consolidated Financial Statements

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

Report of Independent Registered Public Accounting Firm

Financial Statements:

Consolidated Balance Sheets as of December 31, 2004 and 2003
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. We carried out an evaluation, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our General Partner, of the effectiveness 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 as of December 31, 2004. Our management, including the principal executive officer and principal financial officer of our General Partner, is engaged in a comprehensive effort to review, evaluate and improve our controls; however, management does not expect that our disclosure controls or our internal controls over financial reporting will prevent all errors and all fraud. A control system, no matter how well how designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives would be met.

Based upon the controls evaluation performed, the principal executive officer and principal financial officer of our General Partner have concluded that as of December 31, 2004, our disclosure controls and procedures were effective to provide reasonable assurance that material information relating to us and our consolidated subsidiaries is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Changes in Internal Controls. In the course of our evaluation of disclosure controls and procedures, management considered certain internal control areas in which we have made and are continuing to make changes to improve and enhance controls. Based upon that evaluation, the principal executive officer and principal financial officer of our General Partner concluded that there were no changes in our internal controls 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 the fourth quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Compliance with Section 404 of the Sarbanes Oxley Act of 2002. Beginning with the year ending December 31, 2006, Section 404 of the Sarbanes-Oxley Act of 2002 will require us to include an internal control report of management with our annual report on Form 10-K. The internal control report must contain (1) a statement of management’s responsibility for establishing and maintaining adequate internal controls over our financial reporting, (2) a statement identifying the framework used by management to conduct the required evaluation of the effectiveness of our internal controls over financial reporting, (3) management’s assessment of the effectiveness of our internal controls over financial reporting as of the end of our most recent fiscal year, including a statement as to whether or not our internal controls over financial reporting are effective, and (4) a statement that our independent auditors have issued an attestation report on management’s assessment of our internal controls over financial reporting.

Management will develop a comprehensive plan in order to achieve compliance with Section 404 within the prescribed period and to review, evaluate and improve the design and effectiveness of our controls and procedures on an on-going basis. The comprehensive compliance plan will include (1) documentation and assessment of the adequacy of our internal controls over financial reporting, (2) remediation of control weaknesses, (3) validation through testing that controls are functioning as documented and (4) implementation of a continuous reporting and improvement process for internal controls over financial reporting. As a result of this initiative, we have made and will continue to make changes from time to time in our internal controls over financial reporting.

Item 9B. Other Information

Not applicable.

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, 2005.

Name	Age	Position

Dan Rothaupt	53	General Manager
Kevin Pierce	47	AEE Business Leader and Somerset Plant Manager
Jerry Goodenough	40	Cayuga Plant Manager
James Mulligan	57	Westover Plant Manager
Douglas Roll	49	Greenidge Plant Manager
Amy Conley	31	Chief Financial Officer

Dan Rothaupt, is 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 25 years experience in the power and chemicals industries, and has worked for The AES Corporation for 11 years. Mr Convery is a Vice President at Indiana Power and Light, a subsidiary of The AES Corporation, responsible for the Harding Street and the Eagle Valley electricity generating stations since November 15, 2004. Previously, Mr. Convery was the Business Leader for the AES Warrior Run and the AES Beaver Valley facilities from June 1, 2002 to November 15, 2004. 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 the registrant’s annual financial statements and review of the financial statements included in the registrant’s Form 10-Q (17 CRF 249.308a) or services that or normally provided by the accountant in connection with statutory and regulatory filings or engagements for those fiscal year were approximately $509,000 and $335,000 for the years ended December 31, 2004 and 2003, respectively.

There were no other fees paid to the principal accountant for the years ended December 31, 2004 and 2003, respectively.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(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.

Report of Independent Registered Public Accounting Firm

Financial Statements:

Consolidated Balance Sheets as of December 31, 2004 and 2003
Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002
Consolidated Statements of Changes in Partners’ Capital for the years ended December 31, 2004, 2003 and 2002

Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002
Notes to Consolidated Financial Statements

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

Report of Independent Registered Public Accounting Firm

Financial Statements:

Consolidated Balance Sheets as of December 31, 2004 and 2003
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.

(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*

10.6		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*

10.13		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]

10.17		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, Calyon New York Branch (successor to 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**

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 31, 2005

	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) and Class A Director of AES NY, L.L.C.	March 31, 2005
Dan Rothaupt

/s/ Kevin Pierce	Class A Director of AES NY, L.L.C.	March 31, 2005
Kevin Pierce

/s/ Edward Convery	Class A Director of AES NY, L.L.C.	March 31, 2005
Edward Convery

/s/ Amy Conley	Vice President and Treasurer (principal financial officer) of AES NY, L.L.C.	March 31, 2005
Amy Conley

AES EASTERN ENERGY, L.P.

CONSOLIDATED BALANCE SHEETS,

DECEMBER 31, 2004 and DECEMBER 31, 2003

(Amounts in Thousands)

December 31,	2004		2003

ASSETS
Current Assets:
Restricted cash:
Operating - cash and cash equivalents	$	2,364	$	2,540
Revenue account	59,218		85,231
Accounts receivable - trade	42,112		34,883
Accounts receivable - affiliates	394		203
Accounts receivable - other	836		1,264
Derivative valuation asset - current	1,240		8,153
Inventory	38,317		27,700
Prepaid expenses	8,306		8,019
Total current assets	152,787		167,993
PROPERTY, PLANT, EQUIPMENT, AND RELATED ASSETS:
Land	8,298		7,054
Electric generation assets -net of accumulated depreciation of $242,094 and $156,259	904,136		902,662
Total property, plant, equipment and related assets	912,434		909,716
OTHER ASSETS:
Deferred financing -net of accumulated amortization of $892 and $328	2,089		303
Derivative valuation asset - non-current	2,774		7,990
Credit reserves	1,494		—
Rent reserve account	31,717		31,717
TOTAL ASSETS	$	1,103,295	$	1,117,719

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	1,649	$	830
Long-term lease financing - current	4,411		7,846
Other long-term debt - current	2,459		347
Accrued interest expense	27,663		28,004
Derivative valuation liability - current	82,125		26,043
Transmission congestion contract	—		359
Due to The AES Corporation and affiliates	12,864		8,930
Accrued coal and rail expense	7,431		6,456
Environmental remediation	332		—
Loss contingency	1,200		—
Other accrued expenses and liabilities	16,697		9,624
Total current liabilities	156,831		88,439
LONG-TERM LIABILITIES:
Lease financing - long term	625,404		629,815
Other long-term debt - non-current	16,411		744
Environmental remediation	4,778		5,051
Defined benefit plan obligation	13,304		16,558
Derivative valuation liability - non-current	38,151		17,581
Asset retirement obligation	11,525		9,900
Other liabilities	1,907		1,944
Total long-term liabilities	711,480		681,593
TOTAL LIABILITIES	868,311		770,032

COMMITMENTS AND CONTINGENCIES (Note 7)

MINORITY INTEREST	8,229		—

PARTNERS’ CAPITAL	226,755		347,687
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,103,295	$	1,117,719

The notes are an integral part of the consolidated financial statements

AES EASTERN ENERGY, L.P.

CONSOLIDATED STATEMENTS OF INCOME

YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

(Amounts in Thousands)

Year ended December 31,	2004			2003			2002
OPERATING REVENUES:
Energy	$	382,742		$	394,227		$	315,026
Capacity	23,122			29,653			36,644
Transmission congestion contract	—			—			8,875
Other	4,790			2,150			6,879

Total revenues	410,654			426,030			367,424
OPERATING EXPENSES:
Fuel	156,222			148,339			137,175
Depreciation and amortization*	39,383			36,076			35,538
Operating and maintenance	30,690			28,581			21,364
General and administrative	65,632			59,194			59,112
Transmission congestion contract	3,771			6,226			—
Loss on asset disposal	321			—			—
Derivative ineffectiveness	36			(193		)	27
Accretion expense	859			689			—

Total operating expenses	296,914			278,912			253,216

OPERATING INCOME	113,740			147,118			114,208

OTHER INCOME (EXPENSE):
Interest expense	(58,930		)	(58,455		)	(57,694		)
Interest income	1,925			2,059			2,116

Total other expense	(57,005		)	(56,396		)	(55,578		)
Net income from continuing operations before minority interest	56,735			90,722			58,630

Minority interest	564			—			—

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

NET INCOME	$	57,299		$	89,066		$	58,630

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, 2004, 2003 AND, 2002

(Amounts in Thousands)

	General Partner			Limited Partner			Total			Accumulated Other Comprehensive Income/(Loss)			Comprehensive Income

BALANCE, DECEMBER 31, 2001	4,331			428,708			433,039			$	28,544
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 income													11,654
BALANCE, DECEMBER 31, 2002	3,822			378,424			382,246			(18,432		)
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 income													79,879
BALANCE, DECEMBER 31, 2003	3,477			344,210			347,687			(27,619		)
Partners’ Contribution, (See Note 8)	5			410			415
Net income	573			56,726			57,299						57,299
Dividends paid	(899		)	(89,001		)	(89,900		)
Other comprehensive loss	(887		)	(87,859		)	(88,746		)	(88,746		)	(88,746		)
Comprehensive loss													$	(31,447	)
BALANCE, DECEMBER 31, 2004	$	2,269		$	224,486		$	226,755		$	(116,365	)

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, 2004, 2003 AND 2002

(Amounts in Thousands)

Year ended December 31,	2004			2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	57,299		$	89,066		$	58,630
Adjustments to reconcile net income to Net cash used in operating activities:
Minority Interest	(564		)	—			—
Cumulative effect of change in accounting principle	—			1,656			—
Loss on sale of asset	321			—			—
Net Asset retirement obligation accretion	781			689			—
Depreciation and amortization	39,383			36,076			35,521
Realized loss (gain) on derivative	(323		)	2,583			(5,895		)
Write off of deferred financing	—			21			—
Net defined benefit plan cost	(3,254		)	(881		)	471
Changes in current assets and liabilities:
Accounts receivable	(7,535		)	118			(6,436		)
Inventory	(10,617		)	(718		)	2,633
Prepaid expenses	(149		)	(402		)	(1,153		)
Accounts payable	6,959			(365		)	(468		)
Accrued interest expense	(341		)	(74		)	(275		)
Due to AES Corporation and affiliates	4,798			1,985			531
Other liabilities	2,993			(1,296		)	(2,065		)

Net cash provided by operating activities	89,751			128,458			81,494
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for capital additions	(13,757		)	(5,421		)	(7,136		)
Decrease (increase) in restricted cash	26,386			(6,600		)	(5,372		)
Credit reserves	(1,494		)	—			—
Net change in rent reserve account	—			—			2

Net cash used in investing activities	11,135			(12,021		)	(12,506		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid	(89,900		)	(114,600		)	(63,960		)
Payments for deferred financing	(1,834		)	(335		)	(317		)
Principal payments on obligations	(9,704		)	(1,664		)	(6,224		)
Proceeds from other debt	137			—			—
Partner’s contribution	415			162			1,513

Net cash used in financing activities	(100,886		)	(116,437		)	(68,988		)

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	$	55,604		$	55,885		$	56,354

Supplemental Disclosure of Non-cash Flow Information:

Assets of the Somerset Railroad Corporation Consolidated at January 1, 2004	$	28,492		$	—		$	—
Liabilities of the Somerset Railroad Corporation Consolidated at January 1, 2004	$	19,586		$	—		$	—

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

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.

AES NY3, L.L.C., an indirect wholly owned subsidiary of AES acquired the stock of the Somerset Railroad Corporation (SRC), which owns short line railroad assets used to transport coal and limestone. The Partnership has entered into a contract with SRC 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 SRC’s outstanding indebtedness, and all capital expenditures necessary to permit SRC to continue to provide rail service to the Somerset and Cayuga Plants. The Partnership has concluded that under the revised Financial Accounting Standards Board (FASB) interpretation No. 46(R)”Consolidation of Variable Interest Entities”, the Partnership needs to consolidate SRC into its consolidated financial statements as of January 1, 2004. (See Note 2)

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.) and SRC. 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):

	2004		2003
Coal and other raw materials	$	23,613	$	12,329
Spare parts, materials, and supplies	14,704		15,371

Total	$	38,317	$	27,700

Property, Plant, Equipment, and Related Assets - Electric generation assets that existed at the date of acquisition (see Note 3) were 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:

Description of Asset	Depreciable Life	Net Book Value at December 31, 2004		Net Book Value at December 31, 2003
		(in thousands)		(in thousands)
Buildings	35	$	2,488	$	2,612
Landfills	5	7,129		3,095
General Plant	5-35	830,766		859,969
Office Equipment	7	339		183
Leasehold Improvements	5-34	36,878		34,046
Asset Retirement Obligations	3-30	2,962		2,757
SRC Track & Structure	30	18,363		—
SRC Freight Cars	15	5,211		—
		$	904,136	$	902,662

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, 2004 and 2003, 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, 2004, 2003, and 2002 were approximately $1.5 million for each year, respectively, and are included in the rent reserve account balance. At December 31, 2004 and 2003, 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.

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(Loss) - Comprehensive Income is presented in the Consolidated Statement of Changes in Partner’s Capital and includes net income and other comprehensive income/(loss) arising from cash flow hedge accounting under SFAS No. 133. In the years prior to the adoption of SFAS No. 133, the Partnership did not have any items of other comprehensive income.

Accounting for Derivative Instruments and Hedging Activities - The Partnership accounts for derivative instruments and hedging activities in accordance with SFAS No. 133, “Accounting 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. As of December 31, 2004, the Partnership has recorded $116.4 million in accumulated 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 during the year ended December 31, 2004. Hedge ineffectiveness is recognized in current period earnings during the year ended December 31, 2004.

Approximately $80.9 million of other comprehensive income is expected to be recognized as a reduction to earnings over the next twelve months. Amounts recorded in Accumulated Other Comprehensive Income during the year ended December 31, 2004, were as follows (in millions):

Beginning balance on January 1, 2004	$	(27.6	)
Reclassified to earnings	29.3
Change in fair value	(118.1		)
Balance, December 31, 2004	$	(116.4	)

In addition to the electric derivatives classified as cash flow hedge contracts, the Partnership had a Transmission Congestion Contract that was a derivative under the definition of SFAS No. 133, but did not qualify for hedge accounting. This contract, which expired in October 2004 and was not renewed, was recorded at fair value on the balance sheet with changes in the fair value recognized through earnings. (See Note 7 - Transmission Agreements)

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 energy revenues 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.

Asset Retirement Obligation - On January 1, 2003, the Partnership adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143, 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 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’s asset retirement obligations primarly consist of 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 is 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, 2004 was as follows (in millions):

	2004		2003
Balance as of January 1	$	9.9	$	9.2
Accretion	$	0.8	$	0.7
Revision of cash flow	$	0.8	$	—
Balance, December 31	$	11.5	$	9.9

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.

New Accounting Pronouncements

Variable Interest Entities - In January 2003, the FASB issued FASB Interpretation No. (FIN) 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 FIN 46(R), “Consolidation of Variable Interest Entities”.

On January 1, 2004, the Partnership adopted FIN 46(R) and prospectively changed the method of accounting to consolidate SRC. Prior period amounts have not been restated. The Partnership’s consolidated balance sheet as of December 31, 2004 reflects additional assets of approximately $25.6 million and liabilities of approximately $17.3 million as a result of this consolidation. Since SRC is owned by another affiliate of AES, the consolidated balance sheets and consolidated statements of income and cash flow included in the Partnership’s financial statements show such ownership as minority interest.

Share-Based Payment - In December 2004, the FASB issued a revised SFAS No.123 (“SFAS No. 123R”), “Share-Based Payment”, which is a revision of SFAS No. 123. SFAS No. 123R eliminates the intrinsic value method under APB 25 as an alternative method of accounting for stock-based awards by requiring that all share-based payments to employees, including grants of stock options for all outstanding years be recognized in the financial statements based on their fair values. It also revises the fair-value based method of accounting for share-based payment liabilities, forfeitures and modifications of stock-based awards and clarifies SFAS No. 123’s guidance related to measurement of fair value, classifying an award as equity or as a liability and attributing compensation to reporting periods. In addition, SFAS No. 123R amends SFAS No. 95, “Statement of Cash Flows”, to require that excess tax benefits be reported as a financing cash flow rather than as an operating cash flow.

The Partnership is required to adopt SFAS No. 123R for the interim period beginning July 1, 2005 using a modified version of prospective application. The Partnership may apply a modified retrospective application to periods before the required effective date. The Partnership plans to adopt SFAS No. 123R no later than July 1, 2005, but has not determined what method it will use. The Partnership is currently evaluating the effect of adoption of SFAS No. 123R, but does not expect the adoption to have a material effect on our financial condition, results of operations or cash flows, as the Partnership had previously adopted income statement treatment for compensation related to share-based payments under SFAS No. 123.

Reclassifications - Certain prior period amounts have been reclassified on the consolidated financial statements to conform with the 2004 presentation. This includes a reclass of amounts related to the Transmission Congestion and Derivatives from long-term to current liabilities at December 31, 2003.

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. 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 $12.2 million as an undiscounted liability under purchase accounting for the projected remediation cost. In 2001 and 2002, the Partnership reduced its undiscounted liability by approximately $587,000 and $2.2 million, respectively, 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, 2004, $332,000 of the liability which pertains to the opacity consent order with the NYSDEC was classified as a current liability, and the remaining $4.8 million is classified as long-term.

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 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 original 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. DEBT

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

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
2009	10,086		52,414		62,500
Thereafter	590,669		536,504		1,127,173
Total minimum lease payments	629,815		805,858		1,435,673

Less imputed interest					(805,858		)

Present value of minimum lease payments					$	629,815

Less current portion					(4,411		)
Lease financing - long term					$	625,404

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, 2004, the Partnership 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, 2004. These amounts are included in electric generation assets. The related accumulated depreciation, combined for both leased Plants, as of December 31, 2004 and 2003, was approximately $113.3 million and $92.9 million, respectively. The agreements governing the leases restrict the Partnership’s ability to incur additional indebtedness, engage in other businesses, sell its assets, or merge with another entity. The ability of the Partnership to make distributions to its partners is restricted unless 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, 2004, the Partnership had fulfilled its obligation to fund the additional liquidity account by establishing a letter of credit, issued by Bank of America (formerly 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.

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. (in thousands):

Fiscal Years ending December 31,	Principal Portion

2005	$	1,857
2006	1,857
2007	1,857
2008	1,857
2009	1,857
Thereafter	8,358
Total minimum lease payments	17,643

Less current portion	1,857
Lease financing - long term	$	15,786

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. 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 purchase accounting liability was fully amortized.

The Partnership has expected coal purchases, composed of short and medium term contracts with various mines, ranging between $100.1 million and $110.4 million, and $78.8 million and $86.9 million for 2005 and 2006, 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 paid NIMO a fixed rate of $500,640 per month during the period of November 20, 1999 to October 1, 2004, and in turn, received a form of transmission service commencing on May 1, 2000. The Partnership had the right under a Remote Load Wheeling Agreement (RLWA) to transmit 298 MW over firm transmission lines from the Somerset Plant. The Partnership had the right to designate alternate points of delivery on NIMO’s transmission system provided that the Partnership was not entitled to receive any transmission service charge credit on the NIMO system.

The contract was 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 was 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 was a financially settled contract since there is no requirement to flow power under this agreement. The agreement generated gains or losses from exposure to shifts or changes in market prices. The Partnership recorded losses of approximately $3.8 million and $6.2 million and a gain of $8.9 million for the years ended December 31, 2004, 2003 and 2002, respectively, related to this contract.

On June 25, 2003, AES Somerset L.L.C. filed a complaint against NIMO with the FERC. The complaint involved outstanding station service charges for the period April 2000 to May 2003. The Plant has calculated that the outstanding charges owed were $290,000, while NIMO has calculated that the outstanding charges were $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, 2004, AES Somerset has accrued approximately $1.6 million.

Line of Credit Agreement - 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 could not exceed the $35 million limit on the entire facility.

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 included another one-year extension of the current Facility, which extended the maturity date of the working capital and letter of credit facility to January 2, 2005. The amendment also increased 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 included a commitment from Citibank, N.A. for the remaining $15 million of the facility.

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 (AES Letter of Credit Agreement), with AES to obtain up to $35 million and $25 million of letters of

credit or cash collateral for 2004 and 2005, respectively. This agreement superseded the authorization of AES on February 25, 2003. The agreement limited the letters of credit amounts and cash collateral to the stated amounts and set into place a fee structure and repayment terms.

On October 26, 2004, the Partnership and AES agreed to terminate the commitment of AES to provide letters of credit and cash collateral for the benefit of the Partnership under the AES Letter of Credit Agreement.

Pursuant to the AES Letter of Credit Agreement, AES had agreed to provide, or cause to be provided, to the Partnership letters of credit and cash collateral to counterparties to support the Partnership’s obligations arising in connection with the Partnership’s sale of electricity. AES agreed that the maximum amount of letters of credit and cash collateral that AES would provide, or cause to be provided, pursuant to the Letter of Credit Agreement would be $95 million from April 28, 2004 until December 31, 2004 and $60 million from January 1, 2005 until December 30, 2005. On October 14, 2004, the AES Board of Directors passed a resolution regarding extension of authorized credit support for the Partnership. The Board of Directors resolved to authorize AES to extend the Partnership use of $95 million in letter of credit capacity through December 31, 2006. As of December 31, 2004, the Partnership had obtained letters of credit in the amount of $58.9 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

The termination of AES’s commitment under the AES Letter of Credit Agreement does not affect outstanding authorizations of letters of credit or cash collateral. The Partnership remains obligated to perform its responsibilities under the AES Letter of Credit Agreement with respect to any outstanding letters of credit or cash collateral agreements until the earlier of such time as the Partnership replaces such outstanding letters of credit or cash collateral agreements or the stated expiration date of such letters of credit or cash collateral agreements shall occur.

AES is not obligated to provide any such letters of credit in the future and will review any request for the issuance of an authorization for such letters of credit on a case by case basis and may refuse any request for the issuance of such letters of credit for any reason, or for no reason.

On October 26, 2004, the Partnership entered into an Amended and Restated Credit Agreement with Calyon New York Branch and the Banks and the Issuing Banks named therein (the Calyon Credit Facility). Also on October 26, 2004, Calyon New York Branch purchased the outstanding loans made under the Partnership’s existing $35,000,000 credit facility, dated as of April 10, 2001, as amended, and the unreimbursed drawings under letters of credit issued under the existing credit facility. In addition, Calyon New York Branch assumed all of the rights and obligations of the banks under the existing credit facility including the commitments of such banks to make loans and issue letters of credit.

Under the Calyon Credit Facility, the Banks have agreed, from time to time until January 28, 2008, to make loans to and issue letters of credit on behalf of the Partnership. The maximum aggregate principal amount of loans, outstanding letters of credit and unreimbursed drawings under letters of credit issued under the Calyon Credit Facility which may be at any one time outstanding initially was $35 million and was increased to $75 million when subsequent approval by the New York State Public Service Commission was obtained on November 10, 2004. The Partnership may borrow, pay or prepay and reborrow loans.

Loans may, at the option of the Partnership, be made under the Calyon Credit Facility as Base Rate Loans or Eurodollar Rate Loans or any combination thereof. Base Rate Loans bear interest at an interest rate per annum equal to the sum of (1) the higher of (a) the Prime Rate announced by Calyon New York Branch from time to time in effect and (b) the sum of the Federal Funds Rate in effect plus 0.50%, plus (2) an applicable margin of 0.75% until October 26, 2006 and 1% thereafter. Eurodollar Rate Loans bear interest at an interest rate per annum (rounded upwards, if necessary, to the nearest whole multiple of 1/100 of 1%) equal to the sum of (1) the London interbank offered rate for deposits in Dollars two business days prior to the first day of an Interest Period (a period of one, two, three or six months selected by the Partnership) for a term comparable to such Interest Period, plus (2) an applicable margin of 1.75% until October 26, 2006 and 2% thereafter. As of December 31, 2004, of the $75 million committed, the Partnership had obtained letters of credit of $51.6 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

The obligations of the Partnership under the Calyon Credit Facility are secured by the Partnership’s pledge of the membership interests in the Partnership’s wholly owned subsidiary, AEE2, L.L.C. (which owns the Westover and Greenidge electric generating plants), as well as AEE2, L.L.C.’s wholly owned subsidiaries, AES Westover, L.L.C. (which operates the Westover electric generating plant) and AES Greenidge, L.L.C. (which operates the Greenidge electric generating plant).

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 sought detailed operating and maintenance history for the Westover and Greenidge Plants. On January 13, 2000, the Partnership received a subpoena from New York State Department of Environmental Conservation (NYSDEC) seeking similar operating and maintenance history from the Plants. This information was sought in connection with the Attorney General’s and the NYSDEC’s investigations of several electricity generating stations in New York that were suspected of undertaking modifications in the past without undergoing an air permitting review.

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

By letter dated May 25, 2000, the 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 of the Plants from NYSEG, the Partnership agreed to assume responsibility for environmental liabilities that arose while NYSEG owned the Plants. On September 12, 2000, the Partnership agreed with NYSEG that the Partnership would 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.

On January 11, 2005, three subsidiaries which the Partnership controls and two subsidiaries controlled by ACR (AES Entities) entered into a consent agreement to settle all outstanding NOVs and civil claims that could have been brought by the State of New York against the AES Entities and NYSEG for the alleged violations of the new source review and new source performance standard provisions of the Clean Air Act and its applicable regulations, similar provisions under the New York Environmental Conservation Law and its applicable regulations, common law, and State Executive Law (Consent Decree). The Consent Decree is expected to be entered by the United States District Court for the Western District of New York after completion of a public comment period and a separate 45 day period in which the Federal Government may submit comments. The Federal Government also has the opportunity to intervene in the case. The Consent Decree will become effective when it is entered by the Court. Under the terms and conditions of the Consent Decree, upon entering into effect, the State of New York covenants not to sue and releases the participating subsidiaries and NYSEG from alleged violations under the Clean Air Act and regulations and also covenants not to sue or bring any administrative enforcement actions against the AES Entities for claims under the above-mentioned air emission laws and regulations associated with work required pursuant to the Consent Decree or other changes at the Plants commenced after entry of the Consent Decree, but prior to December 31, 2009 and completed by December 31, 2010. Under the Consent Decree, the AES Entities have agreed to pay a $700,000 civil penalty for the violations assessed to NYSEG and will deposit $1,000,000 in an AES Environmental Mitigation Project Account that will be used to carry out one or more projects pertaining to energy efficiency, renewable energy and/or clean air projects that are approved by the NYSDEC and the Office of the Attorney General. The Consent Decree does not address the Somerset and Cayuga Plants, and it is possible that these two Plants may be subject to a separate enforcement action filed either by the United States Environmental Protection Agency, NYSDEC, or the New York State Attorney General.

The Consent Decree sets forth mandated emission reductions and requires the installation of new emission control technologies on certain units or the repowering of or the ceasing of operations of such units. On Greenidge Unit 4, the AES Entities are obligated to control sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions through a multi-pollutant control clean coal project (“MCP Project”). This obligation is subject to the partial funding of the MCP Project by the U.S. Department of Energy and the absence of any force majeure event or material adverse change in circumstances that affects the economic viability of the MCP Project. The AES Entities are required to commence initial operation of the MCP Project by September 1, 2006 or a date eighteen months after entry of the Consent Decree, whichever is later. The AES Entities are also obligated to use good faith efforts to meet certain NOx emission rates and achieve a certain SO2 removal efficiency during normal operations on Greenidge Unit 4. If the MCP Project on Greenidge Unit 4 is discontinued, the AES Entities are required by December 31, 2009 either to (i) install control technology that will meet the Consent Decree emission limits, (ii) repower with a non-coal fuel source or (iii) cease operations.

On Westover Unit 8, the AES Entities are obligated under the Consent Decree to take one of the following three actions by December 31, 2009 and to notify the NYSDEC of which action they elect to

take by June 1, 2007: (i) control NOx and SO2 using technology similar to the MCP Project on Greenidge Unit 4, (ii) repower with a non-coal fuel source or (iii) cease operations. Beginning in 2005 and lasting through 2009, Westover Unit 8 is subject to a declining SO2 emissions cap that starts with a cap in 2005 and declines per year until 2009. Should the AES Entities elect to install emission control technology on Westover Unit 8 by December 31, 2009, then they are obligated under the Consent Decree to use good faith efforts to meet a certain NOx emissions rate and a certain SO2 removal efficiency.

Under the Consent Decree, Greenidge Unit 3 and Westover Unit 7 are required either to (i) install control technology equivalent to Best Available Control Technology or BACT, (ii) be repowered with a non-coal fuel, or (iii) cease operations, no later than December 31, 2009. During the years 2007, 2008, and 2009, these two units will be subject to an annual operating limit of 1,400 hours with an SO2 emission rate of 3.0 lb/mmBtu. The Consent Decree does allow the AES Entities to use up to a 30% blend of sub-bituminous (reduced sulfur) coal at either the Greenidge or Westover Plants.

In the event that the AES Entities fail to comply with one or more terms of the Consent Decree, the AES Entities are obligated to pay stipulated penalties that are set forth in the Consent Decree with the exception of noncompliance due to force majeure events or certain material adverse conditions affecting the economic viability of the MCP Project. Upon achieving compliance with the material requirements of the Consent Decree, then the parties to the settlement may petition the court for termination of the Consent Decree. The Partnership expects that the emission reduction and control technology requirements set forth in the Consent Decree will be incorporated into each Plant’s Title V air operating permit.

The Partnership has projected that its share of the capital costs to install the MCP Project at Greenidge Unit 4 will be approximately $29 million, however, there can be no assurance that this will be the actual cost since the Partnership has not entered into an agreement for engineering, procurement and construction of the MCP Project at Greenidge Unit 4.

At this time, the Partnership has not made decisions regarding the options of either installing pollution control technology, repowering or ceasing operations at the other units subject to the terms of the Consent Decree, and the Partnership is unable to project the potential costs associated with complying with the other provisions of the Consent Decree on its financial condition or the effect on future operations.

The EPA is not a signatory to the Consent Decree, and it is possible that EPA could separately issue the Partnership a NOV for alleged violations of the federal Clean Air Act and federally enforceable New York air regulations associated with suspected past modifications of plant equipment without undergoing an air permitting review. If EPA does file an enforcement action against Greenidge and Westover, then penalties may be asserted and further emission reductions might be necessary which could require the Partnership to make substantial expenditures. The Partnership is unable to estimate the effect of any EPA-issued NOV on our financial condition or results of future operations.

Nitrogen Oxide and Sulfur Dioxide Emission Allowances - The Plants emit NOx and 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 emission rules have been superseded by the transition to the federal NOx SIP Call rule, which imposes NOx ozone season emission reduction requirements through an allowance system similar to the Phase III emission rules. Under the NOx SIP Call rule, electric generating facilities in 21 Northeast and Mid- Atlantic states and the District of Columbia are required to hold allowances sufficient to cover the ozone season NOx emissions emitted by such facilities. Each of the Partnership’s Plants is subject to the NOx SIP Call rule, and the Partnership has been allocated 2,492 NOx allowances for the 2005 ozone season. The NOx SIP Call program commenced on May 31, 2004. The Plants were net sellers of NOx allowances in 2002. The Plants had a shortfall of approximately 1,020 and 1,200 NOx allowances in 2004 and 2003,respectively. The 2003 shortfall was covered by purchasing 70 NOx allowances from AES Ironwood, an indirect wholly owned subsidiary of AES, at market prices and the remainder of the 2003 and 2004 shortfalls of NOx allowances were covered by purchasing NOx allowances at market prices from unrelated companies in the open market.

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 had shortfalls of approximately 6,600, 10,000 and 1,000 SO2 allowances in 2002, 2003 and 2004, 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 and 2004 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.

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.

In January 2004, NYSDEC determined the amount of SO2 emissions allowances that would be allocated to the Plants. The allocation is approximately the Partnership’s average historical SO2 emissions for the Plants.

On May 26, 2004, the New York Supreme Court struck down the Acid Deposition Reduction Program regulations (6 NYCRR 237 and 238). The Court ruled that the regulations had been adopted improperly after the State missed a deadline for publication of a notice to inform the public of proposed changes in the regulations. On July 1, 2004, NYSDEC appealed the Court’s ruling.

The new NOx regulations became effective October 1, 2004, and the new SO2 regulations will be phased in starting January 1, 2005, with full implementation complete by January 1, 2008. The Partnership’s compliance strategy involves reduced operations from the Plants’ non-reheat units, reducing emission rates and/or the selling/buying or trading of New York State SO2 and NOx allowances.

On March 10, 2005, the EPA Acting Administrator signed the final Clear Air Interstate Rule that will 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 final rule directs 28 states, including New York, to issue new regulations that will require major SO2 and NOx reductions by 2015. States must achieve the required NOx and SO2 reductions by meeting a state-specific emissions budget through one of two compliance methods: (i) requiring electric generating facilities in the state to participate in an EPA-administered cap and trade regime that caps emissions in two phases starting with a first phase in 2010 and a second phase commencing in 2015, or (ii) meeting the budget levels through measures selected by a particular state that are approved by EPA. States are encouraged to use a cap and emission trading approach. At this point, the Partnership cannot determine what the costs would be to comply with new federal SO2 and NOx emission reduction requirements.

On March 15, 2005, the EPA Acting Administrator signed the final Clear Air Mercury Rule that will regulate mercury emissions from existing and new coal-fired power plants. The final rule requires the reduction of mercury emissions to be achieved through a cap and emission trading program with the first phase commencing in 2010 and the second phase starting in 2018. At this point, the Partnership cannot determine what the costs would be to comply with the new federal mercury emission reductions requirements.

The Partnership voluntarily disclosed to the NYSDEC and EPA on November 27, 2002 that NOx exceedences appear to have occurred on October 30 and 31 and November 1-8 and 10 of 2002. The exceedences 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 exceedences. Immediately upon the discovery of the exceedences, 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 exceedences were discovered. The EPA has decided to defer to the NYSDEC for review of the self-disclosure letter and technical issues. Recently, the Partnership learned of a Notice of Violation issued by the NYSDEC for the NOx RACT exceedences through a review of the November 2004 release of the EPA’s Enforcement and Compliance History “ECHO” database. The Partnership has not yet seen the NOV from the NYSDEC. 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 July 2004, the EPA final rule for regulating existing power plants under Section 316(b) of the Clean Water Act was published in the Federal Register. This rule became effective on September 7, 2004. This new rule will impose new compliance requirements, 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 has not yet determined the effects of this rule on its financial condition or results of operations.

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 of 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. Through this agreement, the Partnership has, in effect, guaranteed interest on and principal of SRC’s outstanding indebtedness and will pay amounts sufficient to enable SRC to pay all of its operating and other expenses, including all out-of-pocket expenses, taxes, 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 and 2002, $3.1 million and $3.8 million, respectively, has been recorded by the Partnership as operating expenses and other accrued liabilities under this agreement.

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.

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.

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 the Somerset Plant’s allowance account while awaiting transfer to the purchasing facility. In 2003, allowances were purchased and sold in this manner for AES Deepwater, AES Red Oak and AES Ironwood, all indirect wholly owned subsidiaries of AES.

For the year ended December 31, 2002, the Partnership purchased approximately 6,000 SO2 allowances for approximately $843,000, from the electricity generating stations owned by an affiliate of the Partnership, ACR that are on long-term cold standby. Those allowances were purchased at quoted market prices.

For the year ended December 31, 2003,Odyssey purchased for the Partnership’s account 70 NOx allowances at market prices for approximately $322,000 from AES Ironwood, a wholly owned subsidiary of AES.

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 year ended December 31, 2002, the Partnership recognized revenues of approximately $13.9 million, 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, the related account receivable - trade between AES New Energy and the Partnership was zero. The exposure at December 31, 2002 related to these contract transactions was less than 10% of the Partnership’s estimated cash revenues for the year then ended.

AES contributed approximately $415,000 and $162,000 to the Partnership in 2004 and 2003, respectively, related to the cost of stock options compensation expense. Also, AES contributed approximately $1.5 million to the Partnership in 2002 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, 2004, 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 2004 and 2003, 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, 2004 and 2003. The values of the assets and liabilities as of October 31, 2004 and 2003 were not materially different than the values as of December 31, 2004 and 2003.

	2004			2003
Projected Benefit Obligation
Change in projected benefit obligation (in thousands):
Projected benefit obligation, beginning of period	$	24,888		$	25,267
Service cost	683			375
Interest cost	1,540			1,495
Actuarial (gain) loss	1,443			(1,419		)
Benefits paid	(759		)	(830		)
Curtailment	—			—
Special Termination Loss	—			—

Projected benefit obligation, end of period	$	27,795		$	24,888
Plan Assets:
Change in plan assets (in thousands):
Fair value of plan assets, beginning of period	$	9,417		$	7,153
Actual return on plan assets	103			933
Employer contributions	4,571			2,161
Benefits paid	(759		)	(830		)

Fair value of plan assets, end of period	$	13,332		$	9,417
Funded status/accrued benefit liability	$	(14,463	)	$	(15,471	)
Unrecognized Net Loss	1,159			(1,087		)
(Accrued)/Prepaid Pension Cost, end of period	$	(13,304	)	$	(16,558	)

							2002
Defined Benefit Pension Plan Costs:
Components of net periodic benefit cost (in thousands)
Service cost	$	683		$	366		$	416
Interest cost	1,540			1,522			1,358
Expected return on plan assets	(907		)	(607		)	(474		)

Net periodic benefit cost	$	1,316		$	1,281		$	1,300

The discount rate utilized for determining future pension obligations is based on a review of long- term bond rates. The discount rate was reduced to 5.75% to reflect current long-term rates. 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.

	2004		2003
Discount rate	5.75	%	6.25	%
Expected long-term rate of return on plan assets	8.00	%	8.00	%
Rate of compensation increase	4.75	%	4.75	%

The accumulated benefit obligation was approximately $24.0 million and $21.8 million as of December 31, 2004 and 2003, respectively.

Significant assumptions were used in the calculations of the net benefit cost and projected benefit obligation for the periods ending October 31, 2004 and 2003. 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 54% and 58% equities and 46% and 42% in fixed income investments as of October 31, 2004 and 2003, 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, 2004, the Plan had 260 active participants.

Plan Assets

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 $4.1 million to its pension plan in 2005.

Estimated Future Benefits Payments

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

Fiscal Years ending December 31,	Payments
2005	979
2006	1,075
2007	1,210
2008	1,354
2009	1,511
Thereafter	9,907
Total Estimated Future Benefits	$	16,036

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 $899,000, $885,000 and $809,000 in 2004, 2003 and 2002, 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. The net periodic cost was $231,000 for the year ended December 31, 2002. On July 1, 2003, as part of AES Greenidge’s collective bargaining agreement with the International Brotherhood of Electrical workers, AES Greenidge established a Voluntary Employees’ Beneficiary Association (“VEBA”) to fund their retired union members’, spouses’ and dependents’ medical expenses.

The Plants also 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

2005	534
2006	434
2007	172
2008	172
2009	—
Total funding payments	$	1,312

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 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 was approximately $415,000 and $162,000 in 2004 and 2003, respectively.

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, 2004. The Partnership is not aware of any factors that would significantly affect the estimated fair value amounts since that date. The fair value of the long-term debt (the leasing debt) would not be at the carrying value. The fair value of the long-term debt is $680.6 million.

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 nine distributions to its partners to date: 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; January 8, 2004, in the amount of $48.7 million; and July 8, 2004, in the amount of $41.2 million.

AES NY, L.L.C.

CONSOLIDATED BALANCE SHEETS,

DECEMBER 31, 2004 and DECEMBER 31, 2003

(Amounts in Thousands)

December 31,	2004		2003
ASSETS
Current Assets:
Restricted cash:
Operating - cash and cash equivalents	$	2,431	$	2,932
Revenue account	59,218		85,231
Accounts receivable - trade	42,112		34,883
Accounts receivable - affiliates	3,717		2,969
Accounts receivable - other	872		1,280
Derivative valuation asset - current	1,239		8,153
Inventory	38,317		27,700
Prepaid expenses	8,360		8,117
Total current assets	156,266		171,265
PROPERTY, PLANT, EQUIPMENT, AND RELATED ASSETS:
Land	8,748		7,503
Electric generation assets-net of accumulated depreciation of $247,632 and $161,784	904,218		902,663
Total property, plant, equipment and related assets	912,966		910,166
OTHER ASSETS:
Deferred financing -net of accumulated amortization of $892 and $328	2,090		303
Derivative valuation	2,773		7,990
Credit reserves	1,494		—
Rent reserve account	31,717		31,717
TOTAL ASSETS	$	1,107,306	$	1,121,441
LIABILITIES AND MEMBERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	1,653	$	833
Lease financing - current	4,411		7,846
Other long-term debt - current	2,459		347
Accrued interest expense	27,663		28,004
Derivative valuation liability - current	82,125		26,043
Transmission congestion contract	—		359
Due to The AES Corporation and affiliates	13,092		9,096
Accrued coal and rail expense	7,431		6,456
Environmental remediation	332		—
Loss contingency	1,700		—
Other accrued expenses and liabilities	16,900		9,787
Total current liabilities	157,766		88,771
LONG-TERM LIABILITIES:
Lease financing - long term	625,404		629,815
Other long-term debt - non-current	16,411		744
Environmental remediation	6,528		6,800
Defined benefit plan obligation	13,920		17,238
Derivative valuation liability - non-current	38,151		17,581
Asset retirement obligation	11,845		10,299
Other liabilities	1,907		1,944
Total long-term liabilities	714,166		684,421
TOTAL LIABILITIES	871,932		773,192

COMMITMENTS AND CONTINGENCIES (Note 6)

MINORITY INTEREST	233,020		344,767
MEMBER’S EQUITY	2,354		3,482
TOTAL LIABILITIES AND MEMBERS’ CAPITAL	$	1,107,306	$	1,121,441

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, 2004 AND 2003

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.”

AES NY3, L.L.C., an indirect wholly owned subsidiary of AES acquired the stock of the Somerset Railroad Corporation (SRC), which owns short line railroad assets used to transport coal and limestone. AEE has entered into a contract with SRC 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. AEE has concluded that under the revised Financial Accounting Standards Board (FASB) interpretation No. 46(R)”Consolidation of Variable Interest Entities”, AEE needs to consolidate SRC into its consolidated financial statements as of January 1, 2004. (See Note 2)

In November 2000, AEE and ACR 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 and ACR in the over-the-counter and New York Independent System Operator(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, SRC 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, 2004 and 2003 (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, 2004 and 2003, other than liabilities of AEE, SRC 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):

	2004		2003
Coal and other raw materials	$	23,613	$	12,329
Spare parts, materials, and supplies	14,704		15,371

Total	$	38,317	$	27,700

Property, Plant, Equipment, and Related Assets - Electric generation assets that existed at the date of acquisition (see Note 3) were 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 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:

Description of Asset	Depreciable Life	Net Book Value at December 31, 2004		Net Book Value at December 31, 2003
		(in thousands)		(in thousands)
Buildings	35	$	2,488	$	2,612
Landfills	5	7,129		3,095
General Plant	5-35	830,848		859,970
Office Equipment	7	339		183
Leasehold Improvements	5-34	36,878		34,046
Asset Retirement Obligations	3-30	2,962		2,757
SRC Track & Structure	30	18,363		—
SRC Freight Cars	15	5,211		—
		$	904,218	$	902,662

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, 2004 and 2003, 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, 2004, 2003, and 2002 were approximately $1.5 million for each year, respectively, and are included in the rent reserve account balance. At December 31, 2004 and 2003, 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.

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.

Derivative Instruments and Hedging Activities - The Company accounts for derivative instruments and hedging activities in accordance with SFAS No. 133, “Accounting 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. As of December 31, 2004, the Company has recorded $116.4 million in accumulated 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 AEE Plants’ 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 during the year ended December 31, 2004. Hedge ineffectiveness is recognized in current period earnings during the year ended December 31, 2004.

Beginning Balance on January 1, 2004	$	(27.6	)
Reclassified to earnings	29.3
Change in fair value	(118.1		)
Balance, December 31, 2004	$	(116.4	)

In addition to the electric derivatives classified as cash flow hedge contracts, AEE had a Transmission Congestion Contract that was a derivative under the definition of SFAS No. 133, but did not qualify for hedge accounting. This contract, which expired in October 2004 and was not renewed, was recorded at fair value on the balance sheet with changes in the fair value recognized through earnings. (See Note 6 - Transmission Agreements)

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.

Asset Retirement Obligations - On January 1, 2003 the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143, 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 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’s asset retirement obligations’ primarily consist of 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 is 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, 2004 was as follows (in millions):

	2004		2003
Balance as of January 1	$	10.3	$	9.6
Accretion	0.8		0.7
Revision to cash flow	0.8		—
Balance, December 31	$	11.9		10.3

Stock-Based Compensation - 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 9). 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.

New Accounting Pronouncements

On January 1, 2004, AEE adopted FIN 46(R) and concluded that under FIN 46(R) AEE needs to consolidate SRC into its consolidated financial statements. AEE’s consolidated balance sheet as of December 31, 2004 reflects additional assets of approximately $25.6 million and liabilities of approximately $17.3 million as a result of this consolidation. Since SRC is owned by another affiliate of AES, the Company’s consolidated balance sheets show such ownership as minority interest.

The Company is required to adopt SFAS No. 123R for the interim period beginning July 1, 2005 using a modified version of prospective application. The Company may apply a modified retrospective application to periods before the required effective date. The Company plans to adopt SFAS No. 123R no later than July 1, 2005, but has not determined what method it will use. The Company is currently evaluating the effect of adoption of SFAS No. 123R, but does not expect the adoption to have a material effect on our financial condition, results of operations or cash flows, as the Company had previously adopted income statement treatment for compensation related to share-based payments under SFAS No. 123.

Reclassifications - Certain prior period amounts have been reclassified on the consolidated financial statements to conform with the 2004 presentation. This includes a reclass of amounts related to the Transmission Congestion Contract and Derivatives from Long-term to current liabilities at December 31, 2003.

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 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. 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 $12.2 million. AEE recorded $12.2 million as an undiscounted liability under purchase accounting for the projected remediation cost. In 2001 and 2002, AEE reduced its undiscounted liability by approximately $587,000 and $2.2 million, respectively, 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, 2004, $332,000 of the liability which pertains to the pending NYSDEC opacity consent (Note 6) order is classified as a current liability, the remaining $4.8 million is classified as long-term.

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, 2004, none of the liability was classified as a current liability, the remaining $1.7 million is classified as longterm.

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 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. DEBT

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

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
2009	10,086		52,414		62,500
Thereafter	590,669		536,504		1,127,173
Total minimum lease payments	629,815		805,858		1,435,673

Less imputed interest					(805,858		)

Present value of minimum lease payments					$	629,815

Less current portion					(4,411		)
Lease financing - long term					$	625,404

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, 2004, 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, 2004. These amounts are included in electric generation assets. The related accumulated depreciation, combined for both leased Plants, as of December 31, 2004 and 2003, was approximately $113.3 million and $92.9 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, 2004, AEE had fulfilled its obligation to fund the additional liquidity account by establishing a letter of credit, issued by Bank of America (formerly 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.

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

Fiscal Years ending December 31,	Principal Portion

2005	$	1,857
2006	1,857
2007	1,857
2008	1,857
2009	1,857
Thereafter	8,358
Total minimum lease payments	17,643

Less current portion	1,857
Lease financing - long term	$	15,786

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. 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 purchase accounting liability was fully amortized.

AEE has expected coal purchases, composed of short and medium term contracts with various suppliers, ranging between $100.1 million and $110.4 million and $78.8 million and $86.9 million for 2005 and 2006, 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 paid NIMO a fixed rate of $500,640 per month during the period of November 20, 1999 to October 1, 2004, and in turn, received a form of transmission service commencing on May 1, 2000. AEE had the right under a Remote Load Wheeling Agreement (RLWA) to transmit 298 MW over firm transmission lines from the Somerset Plant. AEE had the right to designate alternate points of delivery on NIMO’s transmission system provided that AEE was not entitled to receive any transmission service charge credit on the NIMO system.

The contract was 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 was 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 was a financially settled contract since there was no requirement to flow power under this agreement. The agreement generated gains or losses from exposure to shifts or changes in market prices. AEE recorded losses of approximately $3.8 million and $6.2 million and a gain of $8.9 million for the years ended December 31, 2004, 2003 and 2002, respectively, related to this contract.

On June 25, 2003, AES Somerset L.L.C. filed a complaint against NIMO with the FERC. The complaint involved outstanding station service charges for the period April 2000 to May 2003. The Plant calculated that the outstanding charges owed were $290,000, while NIMO calculated that the outstanding charges were $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, 2004, AES Somerset had accrued approximately $1.6 million for these charges.

Line of Credit Agreement - 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 could 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 included another one-year extension of the current facility, which extended the maturity date of the working capital and letter of credit facility to January 2, 2005. The amendment also increased 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 included a commitment from Citibank, N.A. for the remaining $15 million of the facility. There were 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 and an additional $1 million on January 9, 2004 and February 20, 2004, respectively, at an interest rate of 5.5%. This borrowing was repaid in two payments, $6.2 million on January 27, 2004 and the remaining balance of $7.7 million was repaid on February 26, 2004. The fourth borrowing was for $14.3 million on July 9, 2004 at an interest rate of 5.75%. This borrowing was repaid in full on July 26, 2004.

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 (AES Letter of Credit Agreement), with AES to obtain up to $35 million and $25 million of letters of credit or cash collateral for 2004 and 2005, respectively. This agreement superseded the authorization of AES on February 25, 2003. The agreement limited 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 had 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 26, 2004, AEE and AES agreed to terminate the commitment of AES to provide letters of credit and cash collateral for the benefit of AEE under the AES Letter of Credit Agreement.

Pursuant to the AES Letter of Credit Agreement, AES had agreed to provide, or cause to be provided, to AEE letters of credit and cash collateral to counterparties to support AEE’s obligations arising in connection with AEE’s sale of electricity. AES agreed that the maximum amount of letters of credit and cash collateral that AES would provide, or cause to be provided, pursuant to the AES Letter of Credit Agreement would be $95 million from April 28, 2004 until December 31, 2004 and $60 million from January 1, 2005 until December 30, 2005. On October 14, 2004, the AES Board of Directors passed a resolution regarding extension of authorized credit support for AEE. The Board of Directors resolved to authorize AES to extend AEE use of $95 million in letter of credit capacity through December 31, 2006. As of December 31, 2004, AEE had obtained letters of credit in the amount of $58.9 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

The termination of AES’s commitment under the AES Letter of Credit Agreement does not affect outstanding authorizations of letters of credit or cash collateral. AEE remains obligated to perform its responsibilities under the AES Letter of Credit Agreement with respect to any outstanding letters of credit or cash collateral agreements until the earlier of such time as AEE replaces such outstanding letters of credit or cash collateral agreements or the stated expiration date of such letters of credit or cash collateral agreements shall occur.

On October 26, 2004, AEE entered into an Amended and Restated Credit Agreement with Calyon New York Branch and the Banks and the Issuing Banks named therein (the Calyon Credit Facility). Also on October 26, 2004, Calyon New York Branch purchased the outstanding loans made under AEE’s existing $35,000,000 credit facility, dated as of April 10, 2001, as amended, and the unreimbursed drawings under letters of credit issued under the existing credit facility. In addition, Calyon New York Branch assumed all of the rights and obligations of the banks under the existing credit facility including the commitments of such banks to make loans and issue letters of credit.

Under the Calyon Credit Facility, the Banks have agreed, from time to time until January 28, 2008, to make loans to and issue letters of credit on behalf of AEE. The maximum aggregate principal amount of loans, outstanding letters of credit and unreimbursed drawings under letters of credit issued under the Calyon Credit Facility which may be at any one time outstanding initially was $35 million (and was increased to $75 million when subsequent approval by the New York State Public Service Commission was obtained on November 10, 2004). AEE may borrow, pay or prepay and reborrow loans.

Loans may, at the option of AEE, be made under the Calyon Credit Facility as Base Rate Loans or Eurodollar Rate Loans or any combination thereof. Base Rate Loans bear interest at an interest rate per annum equal to the sum of (1) the higher of (a) the Prime Rate announced by Calyon New York Branch from time to time in effect and (b) the sum of the Federal Funds Rate in effect plus 0.50%, plus (2) an applicable margin of 0.75% until October 26, 2006 and 1% thereafter. Eurodollar Rate Loans bear interest at an interest rate per annum (rounded upwards, if necessary, to the nearest whole multiple of 1/100 of 1%) equal to the sum of (1) the London interbank offered rate for deposits in Dollars two business days prior to the first day of an Interest Period (a period of one, two, three or six months selected by AEE) for a term comparable to such Interest Period, plus

(2) an applicable margin of 1.75% until October 26, 2006 and 2% thereafter. As of December 31, 2004, of the $75 million committed, AEE had obtained letters of credit of $51.6 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

The obligations of AEE under the Calyon Credit Facility are secured by AEE’s pledge of the membership interests in AEE’s wholly owned subsidiary, AEE2, L.L.C. (which owns the Westover and Greenidge Plants), as well as AEE2, L.L.C.’s wholly owned subsidiaries, AES Westover, L.L.C. (which operates the Westover Plant) and AES Greenidge, L.L.C. (which operates the Greenidge plant).

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 sought 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 was sought in connection with the Attorney General’s and the NYSDEC’s investigations of several electricity generating stations in New York that were 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 would 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.

On January 11, 2005, three subsidiaries which AEE controls and two subsidiaries controlled by ACR (AES Entities) entered into a consent agreement to settle all outstanding NOVs and civil claims that could have been brought by the State of New York against the AES Entities and NYSEG for the alleged violations of the new source review and new source performance standard provisions of the Clean Air Act and its applicable regulations, similar provisions under the New York Environmental Conservation Law and its applicable regulations, common law, and State Executive Law (Consent Decree). The Consent Decree is expected to be entered by the United States District Court for the Western District of New York after completion of a public comment period and a separate 45 day period in which the Federal Government may submit comments. The Federal Government also has the opportunity to intervene in the case. The Consent Decree will become effective when it is entered by the Court. Under the terms and conditions of the Consent Decree, upon entering into effect, the State of New York covenants not to sue and releases the AES Entities and NYSEG from alleged violations under the Clean Air Act and regulations and also covenants not to sue or bring any administrative enforcement actions against the participating subsidiaries for claims under the above-mentioned air emission laws and regulations associated with work required pursuant to the Consent Decree or other changes at the Plants commenced after entry of the Consent Decree, but prior to December 31, 2009 and completed by December 31, 2010. Under the Consent Decree, the AES Entities have agreed to pay a $700,000 civil penalty for the violations assessed to NYSEG and will deposit $1,000,000 in an AES Environmental Mitigation Project Account that will be used to carry out one or more projects pertaining to energy efficiency, renewable energy and/or clean air projects that are approved by the NYSDEC and the Office of the Attorney General. The Consent Decree does not address the Somerset and Cayuga Plants, and it is possible that these two Plants may be subject to a separate enforcement action filed either by the United States Environmental Protection Agency, NYSDEC, or the New York State Attorney General.

obligation is subject to the partial funding of the MCP Project by the U.S. Department of Energy and the absence of any force majeure event or material adverse change in circumstances that affects the economic viability of the MCP Project. The AES Entities are required to commence initial operation of the MCP Project by September 1, 2006 or a date eighteen months after entry of the Consent Decree, whichever is later. The AES Entities are also obligated to use good faith efforts to meet certain NOx emission rates and achieve a certain SO2 removal efficiency during normal operations on Greenidge Unit 4. If the MCP Project on Greenidge Unit 4 is discontinued, the AES Entities are required by December 31, 2009 either to (i) install control technology that will meet the Consent Decree emission limits, (ii) repower with a non-coal fuel source or (iii) cease operations.

On Westover Unit 8, the AES Entities are obligated under the Consent Decree to take one of the following three actions by December 31, 2009 and to notify the NYSDEC of which action they elect to take by June 1, 2007: (i) control NOx and SO2 using technology similar to the MCP Project on Greenidge Unit 4, (ii) repower with a non-coal fuel source or (iii) cease operations. Beginning in 2005 and lasting through 2009, Westover Unit 8 is subject to a declining SO2 emissions cap that starts with a cap in 2005 and declines per year until 2009. Should they elect to install emission control technology on Westover Unit 8 by December 31, 2009, then they are obligated under the Consent Decree to use good faith efforts to meet a certain NOx emissions rate and a certain SO2 removal efficiency.

Under the Consent Decree, Greenidge Unit 3 and Westover Unit 7 are required either to (i) install control technology equivalent to Best Available Control Technology or BACT, (ii) be repowered with a non-coal fuel, or (iii) cease operations, no later than December 31, 2009. During the years 2007, 2008, and 2009, these two units will be subject to an annual operating limit of 1,400 hours with an SO2 emission rate of 3.0 lb/mmBtu. Hickling Units 1 and 2 and Jennison Units 1 and 2 are each required either to (i) install BACT-equivalent control technology, (ii) repower using a non-coal fuel or (iii) cease operations no later than May 1, 2007. The Consent Decree does allow the AES Entities to use up to a 30% blend of sub-bituminous (reduced sulfur) coal at either the Greenidge or Westover Plants.

In the event that the AES Entities fail to comply with one or more terms of the Consent Decree, the AES Entities are obligated to pay stipulated penalties that are set forth in the Consent Decree with the exception of noncompliance due to force majeure events or certain material adverse conditions affecting the economic viability of the MCP Project. Upon achieving compliance with the material requirements of the Consent Decree, then the parties to the settlement may petition the court for termination of the Consent Decree. The Company expects that the emission reduction and control technology requirements set forth in the Consent Decree will be incorporated into each Plant’s Title V air operating permit.

AEE has projected that its share of the capital costs to install the MCP Project at Greenidge Unit 4 will be approximately $29 million, however, there can be no assurance that this will be the actual cost since AEE has not entered into an agreement for engineering, procurement and construction of the MCP Project at Greenidge Unit 4.

At this time, the Company has not made decisions regarding the options of either installing pollution control technology, repowering or ceasing operations at the other units subject to the terms of the Consent Decree, and thus the Company is unable to project the potential costs associated with complying with the other provisions of the Consent Decree its financial condition or the effect on future operations.

The EPA is not a signatory to the Consent Decree, and it is possible that EPA could separately issue us a NOV for alleged violations of the federal Clean Air Act and federally enforceable New York air regulations associated with suspected past modifications of plant equipment without undergoing an air permitting review. If EPA does file an enforcement action against Greenidge, Westover, Hickling or Jennison, then penalties may be asserted and further emission reductions might be necessary which could require us to make substantial expenditures. The Company is unable to estimate the effect of any EPA-issued NOV on its financial condition or results of future operations.

Nitrogen Oxide and Sulfur Dioxide Emission Allowances -The AEE and ACR Plants emit NOx and 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 emission rules have

been superseded by the transition to the federal NOx SIP Call rule, which imposes NOx ozone season emission reduction requirements through an allowance system similar to the Phase III emission rules. Under the NOx SIP Call rule, electric generating facilities in 21 Northeast and Mid-Atlantic states and the District of Columbia are required to hold allowances sufficient to cover the ozone season NOx emissions emitted by such facilities. Each of the Plants is subject to the NOx SIP Call rule, and the six Plants have been allocated 2,492 NOx allowances for the 2005 ozone season. The NOx SIP Call program commenced on May 31, 2004. The six Plants were net sellers of NOx allowances in 2002. The six Plants had shortfalls of approximately 1,020 and 1,200 NOx allowances in 2004 and 2003, respectively. 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 2003 and 2004 shortfall 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 had shortfalls of approximately 600, 10,000 and 1,000 SO2 allowances in 2002, 2003 and 2004, respectively. In 2002, ACR sold approximately 6,000 SO2 allowances to the AEE Plants at market prices, then sold on the open market, the remaining SO2 allowances through 2009. The 2003 and 2004 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 hundred thousand tons short of the Company’s average historical NOx emissions for the Plants during the control period.

In January 2004, NYSDEC determined the amount of SO2 emissions allowances that would be allocated to the Plants. The allocation is approximately the Company’s average historical SO2 emissions for the Plants.

The new NOx regulations became effective October 1, 2004, and the new SO2 regulations will be phased in starting January 1, 2005, with full implementation complete by January 1, 2008. AEE’s compliance strategy involves reduced operations from the Plants’ non-reheat units, reducing emission rates and/or the selling/buying or trading of New York State SO2 and NOx allowances.

On March 10, 2005, the EPA Acting Administrator signed the final Clear Air Interstate Rule that will 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 final rule directs 28 states, including New York, to issue new regulations that will require major SO2 and NOx reductions by 2015. States must achieve the required NOx and SO2 reductions by meeting a state-specific emissions budget through one of two compliance methods: (i) requiring electric generating facilities in the state to participate in an EPA-administered cap and trade regime that caps emissions in two phases starting with a first phase in 2010 and a second phase commencing in 2015, or (ii) meeting the budget levels through measures selected by a particular state that are approved by EPA. States are encouraged to use a cap and emission trading approach. At this point, the Company cannot determine what the costs would be to comply with new federal SO2 and NOx emission reduction requirements.

On March 15, 2005, the EPA Acting Administrator signed the final Clear Air Mercury Rule that will regulate mercury emissions from existing and new coal-fired power plants. The final rule requires the reduction of mercury emissions to be achieved through a cap and emission trading program with the first phase commencing in 2010 and the second phase starting in 2018. At this point, the Company cannot determine what the costs would be to comply with the new federal mercury emission reductions requirements.

AEE voluntarily disclosed to the NYSDEC and EPA on November 27, 2002 that NOx exceedences appear to have occurred on October 30 and 31 and November 1-8 and 10 of 2002. The exceedences were discovered through an audit by plant personnel of the Plant’s NOx RACT tracking system. The Company believes that it has taken all reasonable, good faith efforts to assess and correct the exceedences. Immediately upon the discovery of the exceedences, 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 exceedences were discovered. The EPA has decided to defer to the NYSDEC for review of the self-disclosure letter and technical issues. Recently, the Company learned of a Notice of Violation issued by the NYSDEC for the NOx RACT exceedances through a review of the November 2004 release of the EPA’s Enforcement and Compliance History “ECHO” database. The Company has not yet seen the NOV from the NYSDEC. The Company 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. AEE 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 suspended all shipments from that supplier until a resolution was reached. AEE 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 Company 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 July 2004, the EPA final rule for regulating existing power plants under Section 316(b) of the Clean Water Act was published in the Federal Register. This rule became effective on September 7, 2004. This new rule will impose new compliance requirements, 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 has not yet determined the effects of this rule on its financial condition or results of operations.

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. On March 19, 2004, the NYSDEC approved the plan, the additional wells have been installed and monitoring initiated.

ACR voluntarily disclosed to the NYSDEC and EPA that ACR 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.

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 of 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. Through this agreement, AEE has, in effect, guaranteed interest on and principal of SRC’s outstanding indebtedness, and will pay amounts sufficient to enable SRC to pay all of its operating and other expenses, including all out-of-pocket expenses, taxes, 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 and 2002, $3.1 million and $3.8 million, respectively, has been recorded by AEE as operating expenses and other accrued liabilities under this agreement.

In November 2000, AEE and ACR 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 and ACR signed an amendment to their March 2002 agreement. Odyssey will also manage the AEE and ACR coal and environmental emission credit positions for an additional fee of $100,000 per month. Odyssey acts as agent on behalf of AEE and ACR in the over-the- counter and NYISO markets.

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.

For the year ended December 31, 2002, ACR sold approximately 6,000 SO2 allowances to the AEE Plants for approximately $843,000 at quoted market prices.

For the year ended December 21, 2004, Odyssey purchased for AEE’s account 70 NOx allowances for approximately $322,000 at market prices from AES Ironwood, a wholly owned subsidiary of AES.

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 year ended December 31, 2002, AEE recognized revenues of approximately $13.9 million 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, the related account receivable - trade between AES New Energy and AEE was zero. The exposure at December 31, 2002 related to these contract transactions was less than 10% of AEE’s estimated cash revenues for the year then ended.

AES contributed approximately $415,000 and $162,000 to AEE in 2004 and 2003, respectively, related to the cost of stock options compensation expense. Also, AES contributed approximately $1.5 million to AEE in 2002 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 2004, 2003 and 2002, 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.

	2004			2003
Projected Benefit Obligation
Change in projected benefit obligation (in thousands):
Projected benefit obligation, beginning of period	$	26,375		$	26,780
Service cost	683			375
Interest cost	1,629			1,585
Actuarial (gain) loss	1,530			(1,410		)
Benefits paid	(876		)	(955		)
Curtailment	—			—
Special Termination Loss	—			—
Projected benefit obligation, end of period	$	29,341		$	26,375
Plan Assets:
Change in plan assets (in thousands):
Fair value of plan assets (in thousands):	$	11,009		$	8,711
Actual return on plan assets	502			1,092
Employer contributions	4,571			2,161
Benefits paid	(876		)	(955		)
Fair value of plan assets, end of period	$	15,206		$	11,009
Funded status/accrued benefit liability	$	(14,135	)	$	(15,366	)
Unrecognized Net (Gain)	215			(1,872		)

(Accrued)/Prepaid Pension Cost, end of period	$	(13,920	)	$	(17,238	)

Defined Benefit Pension Plan Costs:
Components of net periodic benefit cost (in thousands)
Service cost	$	683		$	367
Interest cost	1,629			1,611
Expected return on plan assets	(1,059		)	(726		)
Curtailment gain	—			—
Net periodic benefit cost	$	1,253		$	1,252

The discount rate utilized for determining future pension obligations is based on a review of long-term bond rates. The discount rate was reduced to 5.75% to reflect current long-term bond rates. 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.

	2004		2003

Discount rate	5.75	%	6.25	%
Expected long-term rate of return on plan assets	8.00	%	8.00	%
Rate of compensation increase	4.75	%	4.75	%

The accumulated benefit obligation was approximately $25.5 million and $23.3 million as of December 31, 2004 and 2003, respectively.

Significant assumptions were used in the calculations of the net benefit cost and projected benefit obligation for the periods ending October 31, 2004, 2003 and 2002. 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 allocation was 54% and 58% equities and 46% and 42% in fixed income investments as of October 31, 2004 and 2003, 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, 2004, the Plan had 260 active participants.

Plan Assets

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 Company expects to contribute $4.1 million to its pension plan in 2005.

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
2005	$	979
2006	1,075
2007	1,210
2008	1,354
2009	1,511
Thereafter	9,907
Total Estimated Future Benefits	$	16,036

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. The Company contributed to AES Profit Sharing and Stock Ownership Plans approximately $899,000, $885,000 and $809,000 in 2004, 2003 and 2002, respectively.

10.25		Amended and Restated Credit Agreement dated as of October 26, 2004 among AEE, as borrower, Calyon New York Branch, as agent, and the Banks and Issuing Banks named therein.

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. ****

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

Item 9B	Other Information

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 and Financial Statement Schedules

Signatures

/s/Deloitte & Touche LLP


McLean, Virginia
March 31, 2005

/s/Deloitte & Touche LLP


McLean, Virginia
March 31, 2005