**UNITED STATES SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

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**FORM 10-K**

**ANNUALREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE**

**SECURITIESEXCHANGE ACT OF 1934**

 

**For thefiscal year ended December 31, 2003**

**Commissionfile number 333-89725**

 

**AES Eastern Energy, L.P.**

(Exactname of registrant as specified in its charter)

 

| **Delaware**                                                               |   | **54-1920088**                              |
|----------------------------------------------------------------------------|--------|---------------------------------------------|
| (State or other  jurisdiction of  incorporation or organization)           |   | (I.R.S.  Employer  Identification No.) |
|                                                                       |   |                                        |
| **1001 North 19th Street  Arlington, Virginia**                            |   | **22209**                                   |
| (Address of principal  executive offices)                                  |   | (Zip Code)                                  |
|                                                                       |
| Registrant’s telephone  number, including area code: **703-522-1315** |
|                                                                       |
| Securities registered  pursuant to Section 12(b) of the Act: **None**      |
| Securities registered  pursuant to Section 12(g) of the Act: **None**      |

 

(Title of each class)

 

Indicate by check markwhether the registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements for thepast 90 days.

 

Yes  ý  No  o

 

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

 

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

 

Yes  o  No  ý

 

State the aggregate marketvalue of the voting and non-voting common equity held by non-affiliatescomputed by reference to the price at which common equity was last sold, or theaverage bid and asked price of such common equity was sold, or the lastbusiness day of the registrant’s most recently completed second fiscal quarter:$0

 

Registrant is a whollyowned subsidiary of The AES Corporation. Registrant meets the conditions setforth in General Instruction I(1)(a) and (b) of Form 10-K and is filing thisAnnual Report on Form 10-K with the reduced disclosure format authorized byGeneral Instruction I.

 

DOCUMENTS INCORPORATED BYREFERENCE

 

None

 

 

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TABLE OF CONTENTS

 
| PART I     |
|------------|
|       |   |   |
| Item 1     | Business |   |
|       |   |   |
| Item 2     | Properties |   |
|       |   |   |
| Item 3     | Legal  Proceedings |   |
|       |   |   |
| Item 4     | Submission  of Matters to a Vote of Security Holders |   |
|       |   |   |
| PART II    |
|       |   |   |
| Item 5     | Market  for the Registrant’s Common Equity and Related Stockholder Matters |   |
|       |   |   |
| Item 6     | Selected  Financial Data |   |
|       |   |   |
| Item 7     | Management’s  Discussion and Analysis of Financial Condition and Results of Operation |   |
|       |   |   |
| Item 7A    | Quantitative  and Qualitative Disclosures About Market Risk |   |
|       |   |   |
| Item 8     | Consolidated  Financial Statements and Supplementary Data |   |
|       |   |   |
| Item 9     | Changes  in and Disagreements With Accountants on Accounting and Financial Disclosure |   |
|       |   |   |
| Item 9A    | Controls  and Procedures |   |
|       |   |   |
| PART III   |
|       |   |   |
| Item 10    | Directors  and Officers of Our Company |   |
|       |   |   |
| Item 11    | Executive  Compensation |   |
|       |   |   |
| Item 12    | Security  Ownership of Certain Beneficial Owners and Management |   |
|       |   |   |
| Item 13    | Certain  Relationships and Related Transactions |   |
|       |   |   |
| Item 14    | Principal  Accounting Fees and Services |   |
|       |   |   |
| PART IV    |
|       |   |   |
| Item 15    | Exhibits,  Financial Statement Schedules, and Reports on Form 8-K |   |
|       |   |   |
| Signatures |

 

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**Item 1****.  Business**

 

(a) General Development ofBusiness

 

Our company is a Delaware limited partnership. Our company was formedon December 2, 1998 as an indirect wholly owned subsidiary of The AESCorporation to take part in the acquisition by subsidiaries of The AESCorporation of six coal-fired electricity generating stations and relatedassets located in the western and west central part of New York State.  AES NY, L.L.C. is the sole generalpartner of our company and AES NY2, L.L.C. is the sole limited partner ofour company. The AES Corporation owns indirectly all of the member interests inboth AES NY, L.L.C. and AES NY2, L.L.C. The mailing address of ourprincipal executive offices is 1001 North 19th Street, Arlington, Virginia22209, telephone no. (703) 522-1315.

 

New York State Electric& Gas Corporation and its affiliate NGE Generation, Inc. (whom we refer tocollectively as “NYSEG”) sold these six electricity generating stations andrelated assets as part of NYSEG’s overall plan to divest itself of itscoal-fired electricity generating assets. On May 14, 1999, twelve specialpurpose business trusts formed by three institutional investors that are notaffiliated with us or with The AES Corporation acquired from NYSEG and leasedto us the assets constituting the Somerset Generating Station(“Somerset”)(formerly known as the Kintigh Generating Station) and the CayugaGenerating Station (“Cayuga”)(formerly known as the Milliken GeneratingStation), excluding the real property on which they are located. On that date,we acquired from NYSEG the real property on which Somerset and Cayuga arelocated and two additional coal-fired electricity generating stations, theWestover Generating Station (“Westover”)(formerly known as the GoudeyGenerating Station) and the Greenidge Generating Station (“Greenidge”)(togetherwith the real property upon which they are located). We leased a portion of thereal property on which Somerset and Cayuga are located and a selective catalyticreduction system (“SCR”), which reduces emissions of nitrogen oxides, that wasthen being installed at Somerset to the special purpose business trusts, whichsubleased them back to us. As part of the transaction, AES NY3, L.L.C., anindirect 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 transportcoal. AES Creative Resources, L.P.(“ACR”), an indirect wholly owned subsidiaryof The AES Corporation that we do not control, acquired the balance of theassets that were purchased from NYSEG, consisting of two older, coal-firedelectricity generating stations, the Jennison Generating Station(“Jennison”)and the Hickling Generating Station (“Hickling”).

 

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

 

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

 

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

 

•                                          Wewill be required to make substantial payments under our leases and othercontracts and we may have difficulty responding to unforeseen requirements.

 

•                                          Wemay have difficulty meeting our payment obligations if our operations are notas successful as we have projected.

 

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•                                          Operationof our electricity generating stations might be disrupted by: interruptions infuel supply; disruptions in electrical transmission; facility shutdown due tobreakdowns or failures of equipment or processes, violations of permitrequirements, operator error or terrorist activity or other catastrophicevents; or labor disputes.

 

•                                          Ourelectricity generating stations are not new and will require carefulmaintenance if they are to operate efficiently.

 

•                                          Wemay have trouble meeting our obligations if our electricity generating stationsare not dispatched nearly continually.

 

•                                          Theperception of the public and government officials in the markets we serve andin other deregulated markets that deregulated prices for electric energy arehigher than expected may result in some degree of re-regulation of the marketsin which we sell our electric energy, unforced capacity and ancillaryservices.  This re-regulation might takethe form, for example, of lowering of caps on wholesale electric energy pricesduring periods of peak demand.

 

•                                          Theaddition of new generating capacity in the New York region in excess of the amountrequired to meet increased demand could result in the reduction of marketclearing prices in periods of peak demand, which would reduce the profitabilityof our operations.

 

•                                          Weoperate in an industry where there are a limited number of vendors for supplieswhich are critical to the operation of our business. If one of our vendorsshould have production problems, a shortage in these commodities could affectour ability to operate or cause prices to rise for these commodities that maynegatively affect our operating results.

 

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

 

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

 

•                                          Wehave responsibility for environmental liabilities that existed prior to ourownership of our electricity generating stations and we will incur expenses asa result. These expenses may exceed our estimates.

 

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

 

•                                          Underthe Asset Purchase Agreement with NYSEG relating to the acquisition of ourelectricity generating stations, we have assumed liabilities of NYSEG thatcould result in unexpected expenses and we have given up the right to makeclaims for problems we may discover later.

 

•                                          Weare controlled by The AES Corporation and The AES Corporation may pursue itsown interests to the detriment of our creditors and holders of pass throughtrust certificates issued to finance the acquisition of Somerset and Cayuga.

 

•                                          TheAES Corporation is not obligated to provide further funding to us if we areunable to pay our obligations.

 

•                                          Inthe future we might compete with other electricity generating stations owned byThe AES Corporation.

 

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(b) FinancialInformation About Industry Segments

 

We operate inonly one business segment, electrical generation.

 

(c) NarrativeDescription of Business

 

A diagram ofthe corporate structure of The AES Corporation as it relates to our company isincluded below:

 

We were formedon December 2, 1998 to acquire, lease and, through our wholly ownedsubsidiaries, operate and improve our electricity generating stations.  The special purpose business trusts and weacquired our electricity generating stations on May 14, 1999 for a purchaseprice of $914 million.  In order to fundthe acquisition of our electricity generating stations (including someadjustments and plus improvement costs, working capital and transaction costs)and pay transaction expenses relating to the acquisition and the leasetransactions.  The AES Corporation madean equity contribution of $354 million to us (net of costs advanced by the AESCorporation for which we will reimburse it), the institutional investors madean equity contribution of $116 million through the special purpose businesstrusts and $550 million we raised for purchase of the Somerset GeneratingStation and the Cayuga Generating station from the sale of pass through trustcertifications.

 

The AESCorporation

 

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

 

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New York Power Market

 

The New York IndependentSystem Operator (“NYISO”) commenced operations in November 1999 and consists ofthe NYISO and the New York State Reliability Council. The NYISO is a non-profitNew York corporation under the Federal Energy Regulatory Commission’sjurisdiction. It is governed by a board of directors with 10 members and threecommittees; the management committee, the operating committee, and the businessissues committee, which are composed of representatives from all marketparticipants, including buyers of power, sellers of power, consumer groups andtransmission owners. The New York State Reliability Council has the primaryresponsibility to preserve the reliability of electricity service on the bulkpower system within New York State and sets the reliability standards to beused by the NYISO. The NYISO operates a two-settlement system for calculatingLocation-Based Marginal Prices (“LBMP”) of electric energy.  The first settlement system is a financiallybinding market for delivery of electric energy on the following day and thesecond settlement system is the balancing market for immediate delivery ofelectric energy. LBMP is the incremental cost to supply load at a specificlocation in the grid. Locational energy price differentials represent theopportunity cost for transmission between specific locations in the grid.

 

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

 

The NYISO’scurrent market design has many of the proposed characteristics that areincluded in the July 31, 2002 Standard Market Design Notice of PublicRulemaking. FERC has not set a date for issuance of the standard market designfinal notice of proposed rule making. We cannot predict the outcome or actualimplementation date of this final rule proceeding or the total effect it willhave on the markets in which we do business.

 

The New Yorkpower market is interconnected with ISO New England to the northeast, HydroQuebec and Ontario Hydro to the north, and Pennsylvania-New Jersey-MarylandInterconnection (PJM) to the south.

 

The transmission of electricity between states and between regionswithin New York State is constrained by physical limits on transmissioncapacity and limits on the amount of electricity that may be imported into apower pool imposed by power pools to enhance reliability. Therefore, thegenerating assets in any given region have a competitive advantage in thatregion over generators not in the region. There is an existing natural marketfor the unforced capacity and the electric energy of our electricity generatingstations in Western New York, which includes the retail service territories ofNYSEG, Niagara Mohawk Power Corporation and Rochester Gas & ElectricCorporation. The existing transmission infrastructure also permits us to accessneighboring markets. However, our ability to sell electric energy intoneighboring markets is limited by constraints imposed by transmission capacitylimitations and limits on imported electricity imposed by power pools in thosemarkets for reliability considerations. Our ability to sell electric energyinto neighboring markets is also limited because we have entered into bilateralcontracts for the sale of a substantial portion of our unforced capacity toload serving entities, i.e., an entity selling electric energy to consumers of electricenergy, including regulated distribution utilities, municipalities and energysupply companies, in New York. See “Unforced Capacity Market.”

 

In November2000, we entered into a three-year agreement for energy marketing services withAES Odyssey, L.L.C. (“Odyssey”), a direct wholly-owned subsidiary of The AESCorporation. In March 2002, a new five-year agreement was reached, throughFebruary 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 March2002 agreement. Odyssey will also manage our coal and environmental emissioncredit positions for an additional fee of $100,000 per month. Odyssey acts asagent on behalf of us in the over-the-counter and NYISO markets.

 

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

 

Odysseyprovides data management for us by maintaining databases of pricing, load,transmission, weather and generation data to aid in analysis to optimize thevalue of our assets.

 

Odysseymaintains a transaction management system to manage day-ahead commitments withthe NYISO and swap and physical values with counterparties and to provide dailyfinancial reporting and end of day budget variance, forward mark-to-market andcommercially accepted risk analysis.

 

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

 

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

 

In December 2003, the NYISO adopted changes to its creditpolicy. Previously, the working capital fund was collected from the loadside of the marketplace. The recent change now collects the fund from boththe load and supply side based on a 50/50% ratio. Actual working capitalobligation is based on a participant’s net market activity per the totalactivity of the market. This obligation is eligible to receive interest and isadjusted each year based on a participant’s net activity from the previousyear. Further, if a participant leaves the marketplace, it is reimbursedits working capital contribution. Our working capital contribution is estimatedto be approximately $1.5 million and will be deducted from monies owned us inthe first six months of the year.

 

In general, wesell the electric energy generated by our electricity generating stationsdirectly into the NYISO market. However, on occasion, we enter into bilateraland physical sales contracts.

 

Unforced Capacity Market. A market in whichelectricity generators can sell commitments of their unforced generatingcapacity has been established to ensure there is enough generation capacityavailable to produce sufficient electric energy to meet retail demand andancillary service requirements. Any load serving entity is required to procurecapacity commitments sufficient to meet its capacity requirements based on itsforecasted annual electric energy requirements at times of maximum usage plus areserve requirement. On May 20, 2003, FERC issued an order approving the NYISOproposal to replace its then existing, administratively set, vertical installedcapacity (ICAP) market structure with a sloped demand curve structure known asthe ICAP Demand Curve. The FERC determined that capacity beyond the minimuminstalled requirement provides both incremental reliability benefits andsignificant benefits to the competitive energy market. Under the initial ICAPmarket structure, load serving entities were only required to purchase enoughcapacity to meet the Minimum Requirement determined by the New York StateReliability Council.  The StatewideMinimum 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 maximumamount of capacity offered into the market up to a maximum level determined onthe demand curve. The demand curve structure more realistically

 

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reflects the economic value of capacity reserves with capacity pricesthat decrease as more supply is offered into the capacity market. Previously,each load serving entity was required to purchase unforced capacity commitmentsequal to approximately 112% of its forecasted annual maximum usage. The loadserving entity could have secured these capacity commitments through abilateral contract or through unforced capacity auctions. Any capacitycommitment 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 marketdesign in the New York control area that employs unforced capacity as themeasure of the capacity of a generator rather than the old measure of installedcapacity. Unforced capacity factors in the probability that agenerator will be available to serve load.  Unforced capacity isthe demonstrated maximum output of a generator (installed capacity) with aformula applied that takes into account a generator’s forced outage rate over adefined period of time.

 

Suppliers of unforced capacity are notrequired to supply the associated electric energy to the load serving entitywith whom they have a contract to provide unforced capacity. Forreliability reasons, the NYISO requires that electricity generators that sellunforced capacity into New York must make their electric energy available inthe event of a system emergency. This prevents generators from entering intofirm contracts to sell electric energy into one market and unforced capacityinto another. If theunforced capacity supplier’s offer in the electric energy market for deliveryon the following day is not accepted, the unforced capacity supplier, for thenext day, will be free either to offer to sell its electric energy in themarket for delivery on an immediate basis or to sell electric energy to anycustomer, including out-of-state customers.

 

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

 

Ancillary Services Market.The NYISO will procure various ancillary services required for reliability fromgenerators as needed. Services to be procured on a market basis includeoperating reserves and regulation and frequency support. Generators arecompensated for other services, including voltage support and black startcapability, on a cost basis.

 

OTC Swap Market. A fairly liquidover-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 adefined portion of the New York electric system that encompasses a set of loadand generation buses. Each zone has an associated zonal price that iscalculated as a weighted average price. Currently New York State is dividedinto eleven zones, corresponding to ten major transmission interfaces that canbecome congested. The swaps settle against the Day Ahead LBMP for Zone A. Ourelectricity generating station prices are highly correlated to the Zone A priceand the swaps are highly effective products for managing our price risk.

 

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

 

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

 

The western region is dominated by low costnuclear, coal and hydro facilities which, together with non-utility generatorsthat must be permitted to run under their power purchase agreements with localutilities, form 83% of installed capacity. The eastern region has apredominance of facilities which are economically viable only at periods ofpeak demand, which form 80% of its installed capacity. Even though the westernregion has only 40% of the New York power market’s generation capacity, powernormally flows from the west into the east. The flow of power from the lower pricedwestern region to the higher priced eastern region is limited to approximately5,000MW by transmission limits and reliability considerations. When this limitis reached, higher cost units in the New York City area are directed to runeven when lower cost units in the western region are available.

 

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

 

Fuel Supply

 

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

 

Coal mines inthe Pittsburgh Seam coal formation near our electricity generating stationsinclude some of the lowest cost coal supply sources producing at volume.Although more expensive low-sulfur coals are available for units without FGDsystems, the high sulfur content of the coals from the Pittsburgh Seam havehistorically made coal-fired generating stations equipped with FGD systems theprimary market for Pittsburgh Seam producers. Since both Somerset and Cayugahave installed FGD systems and are capable of burning higher sulfur coals, weexpect 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 ofEnvironmental Conservation(“NYSDEC”) to burn petroleum coke as asupplemental fuel through a modification of the Prevention SignificantDeterioration and Title V air permits.

 

The Electricity Generating Stations

 

We believe that our two principal coal-firedelectricity generating stations, Somerset and Cayuga, are among the lowestvariable cost facilities in the New York power market. We expect them to befully dispatched when available in the deregulated and competitive New Yorkpower market. We also intend to make appropriate investments of capital tomaintain our electricity generating stations. Somerset, Cayuga, Westover andGreenidge have an aggregate net generating capacity of 1,268MW.

 

The SomersetGenerating Station

 

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

 

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Somerset isbelieved to be among the lowest variable cost facilities in the New York powermarket. It can be run economically even at times of minimum demand for electricenergy. Somerset also is capable of burning low cost medium- and high-sulfurcoal as a result of being equipped with a FGD system to control SO2 emissionsand a selective catalytic reduction (“SCR”) system to control nitrogenoxide(“NOx”) emissions. When Somerset is not being dispatched at maximum load,its periodic load can be varied to meet both system load demand and providetransmission system support and the plant can provide both operating reservesthat are available immediately or on ten minutes notice. The plant is alsoequipped with Automatic Generation Controls enabling it to provide regulationand frequency support.

 

The CayugaGenerating Station

 

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

 

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

 

Westover GeneratingStation

 

Westover islocated alongside the Susquehanna River near Johnson City, New York, and begangenerating electricity in the early 1900’s. Units 1 through 6 have been retiredand physically removed. Westover presently consists of two units, Unit 7 andUnit 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 iscapable of providing both operating reserves that are available immediately oron ten minutes notice. The station is equipped with Automatic GenerationControls, which connect it to the NYISO power control center and enable it toprovide regulation, frequency support, and when directed by the NYISO, voltagesupport.

 

Greenidge GeneratingStation

 

Greenidge islocated 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. Greenidgepresently consists of two units, Unit 3 and Unit 4, with a combined maximum netgenerating capacity of 161MW.

 

Greenidge iscapable of providing both operating reserves available immediately and on tenminutes notice. The station is equipped with Automatic Generating Controls,which connect it to the NYISO power control center and enable it to provideregulation, frequency support, and, when directed by the NYISO, voltagesupport.

 

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

 

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**Regulation**

** **

**EnergyRegulatory Matters**

 

General

 

We and our ownership and operation of ourelectricity generating stations are regulated under numerous federal, state andlocal statutes and regulations. Among other aspects of electric generation,these statutes and regulations govern the rates that we may charge for theoutput of our electricity generating stations, establish in certain instancesthe operating parameters of our electricity generating stations and definestandards for ownership of our electricity generating stations. While thereexists interest at both the federal and state level to deregulate certainaspects of the electric generation industry, we currently remain subject toextensive regulation.

 

**FederalEnergy Regulation**

 

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

 

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

 

Public Utility Holding Company Act. ThePublic Utility Holding Company Act (“PUHCA”) provides that any corporation,partnership or other entity or organized group that owns, controls or holdspower to vote 10% or more of the outstanding voting securities of a “publicutility company” or a company that is a “holding company” of a public utilitycompany is subject to regulation under PUHCA, unless an exemption isestablished or an order is issued by the SEC declaring it not to be a holdingcompany. Registered holding companies under PUHCA are required to limit theirutility operations to a single integrated utility system and to divest anyother operations not functionally related to the operation of the utilitysystem. In addition, a public utility company that is a subsidiary of aregistered holding company under PUHCA is subject to financial andorganizational regulation, including approval by the SEC of certain of itsfinancing transactions. However, under the Energy Policy Act of 1992, a companyengaged exclusively in the business of owning and/or operating a facility usedfor the generation of electric energy exclusively for sale at wholesale may beexempted from PUHCA regulation as an “exempt wholesale generator.” On February5, 1999, we received exempt wholesale generator status from FERC for ourownership and operation of generation and associated facilities. If, afterhaving received this status, there is a “material change” in facts that mightaffect our continued eligibility for exempt wholesale generator status, within60 days of this material change, we must (a) file a written explanation of whythe material change does not affect our exempt wholesale generator status, (b)file a new application for exempt wholesale generator status or (c) notify FERCthat we no longer wish to maintain exempt wholesale generator status. However,if we should lose exempt wholesale generator status, then we would either haveto restructure ourselves or risk subjecting ourselves and our affiliates toPUHCA regulation.

 

State Regulation. In New York State,legislation has significantly deregulated the rate setting aspects of theindustry. However, significant risks remain, including, but not limited to, thepotential that the state deregulation initiatives could be reversed ornullified. We obtained authorization from the New York State Public ServiceCommission for the issuance of the pass through trust certificates and theincurrence of debt pursuant to the terminated working capital credit facilitywith Union Bank of California, N.A. In April 2001, we received approval of ourcurrent working capital facility.

 

Lease Transactions Filings and Approvals. Webelieve that the special purpose business trusts have obtained allenergy-related approvals required to be obtained by them. The special purposebusiness trusts have been included in the approval by FERC of the transfer ofjurisdictional facilities and the acquisition and leaseback ofFERC-jurisdictional facilities, and FERC has granted a disclaimer ofjurisdiction over each of the institutional investors and the special purposebusiness trusts and the trustees of those trusts as public utilities under PartII or III of the Federal Power Act. The special purpose business trusts havereceived determinations from FERC that they are exempt wholesale generators.The special

 

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purpose business trusts obtained a no-action letter from the SEC staffthat no enforcement action would be recommended against them under PUHCA ifthey proceeded with the lease transactions prior to obtaining exempt wholesalegeneration determinations from FERC.

 

**EnvironmentalRegulatory Matters**

 

General

 

As is typical for electric generators, ourelectricity generating stations are required to comply with federal, state andlocal environmental statutes and regulations relating to the safety and healthof 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 toxicmaterials associated with our electricity generating stations;

 

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

 

•                  environmental protectionrequirements, including standards and limitations relating to the discharge ofair and water pollutants.

 

Failure to comply with any of these statutesor regulations could have material adverse effects on us, including theimposition of criminal or civil liability by regulatory agencies or civil finesand liability to private parties, and the required expenditure of funds tobring 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 theconsequences of NYSEG’s handling, storage or emission of hazardous and toxicmaterials on any of the sites of our electricity generating stations and theLockwood and Weber off-site ash disposal site and for NYSEG’s pastnon-compliance, if any, with environmental requirements.

 

It is likely that the stringency ofenvironmental statutes and regulations affecting us and our operations willincrease in the future. In the meantime, we will monitor potential legislativeand regulatory developments that may impact our operations and we willparticipate as appropriate.

 

Expenditures. Compliance with environmentalstandards will continue to be reflected in our capital expenditures andoperating costs. Based on the current status of regulatory requirements, otherthan the expenditures for the SCRs at Somerset and Cayuga Unit 1 including theconstruction of new landfill space to manage ash from Somerset’s SCR systemoperations, expenditures for possible installation of a SCR system on CayugaUnit 2, the U.S. Department of Energy Power Plant Improvement project onGreenidge Unit 4 and expenditures for studies, and capital and operatingexpenses to bring the electricity generating stations into compliance with thenew federal cooling water intake standards, we do not anticipate that anycapital expenditures or operating expenses associated with our compliance withcurrent laws and regulations will have a material effect on our operations orour financial condition.  See “AirEmissions—Nitrogen Oxides.”

 

Air Emissions

 

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

 

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

 

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

 

FGD systems are operated at both Somerset and Cayuga to reduce totalSO2 emissions from these plants to quantities substantially below the Title IVSO2 “allowance” allocations for the units at these plants. An allowance is afreely 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 otherelectricity generating stations, banked for future use or sold to provideliquidity to us. We may need to purchase SO2 allowances to cover SO2 emissionsfor Greenidge and Westover. Market prices for SO2 allowances currently rangefrom about $230 to $270 per ton. We were self sufficient with respect to SO2allowances in 2001, however we had a shortfall of approximately 6,600 and10,000 SO2 allowances in 2002 and 2003, respectively. The majority of the 2002SO2 allowance shortfall was covered with allowances purchased from theelectricity generating stations owned by ACR, which are on long-term coldstandby. The allowances were purchased at quoted market prices. The 2003shortfall was covered by purchasing SO2 allowances at market price fromunrelated companies in the open market.

 

Based on current market pricing of electricity and SO2 allowanceforwards for the years 2004 and 2005, respectively, we forecast that we willhave a shortfall of approximately 16,000 and 8,000 SO2 allowances in 2004 and2005, respectively. Based on current prices the shortfall could cost between$4.2 million to $3.4 million and $2.1 million to $1.6 million for the years2004 and 2005, respectively.  Theshortfall will be covered by purchasing SO2 allowances at market price fromunrelated companies in the open market or by reduced operations of ournon-reheat units and/or purchasing lower sulfur coal to reduce our emissionrates.

 

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

 

In January2004, NYSDEC determined the amount of SO2 emissions allowances that would beallocated to our electricity generating stations. The allocation is severalthousand tons short of our average historical SO2 emissions for our electricitygenerating stations. Our compliance plan cannot be finalized until theanticipated New York SO2 allowance market prices are more conclusivelydetermined.

 

Nitrogen Oxides (NOx).  New York State and the other states in theMid-Atlantic and Northeast region are classified as the Ozone Transport Regionin the federal Clean Air Act, which designates the Ozone Transport Region asnot being in compliance with the ozone National Ambient Air Quality Standard.The states in the Ozone Transport Region have agreed to implement a three-phaseprocess to reduce NOx emissions in the region in order to comply with thefederal Clean Air Act Title I requirements for ozone non-compliance areas.

 

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

 

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

 

Implementation of thePhase III emission rules commenced on May 1, 2003. The Phase III NOx regulationsset forth a NOx allowance allocation program which gives us 2,317 NOx emissionallowances for 2004.

 

To comply with thestricter emissions regulations beginning in 1999, we installed a SCR system atSomerset, which became operational in June 1999. During 2001, we installed aSCR 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 onWestover Unit 8.

 

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

 

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season. Our compliance strategy involves potential installation ofadditional NOx control technology at our electricity generating stations,reduced operations of our non-reheat units during the ozone season, reducingemission rates and/or the selling/buying or trading of NOx allowances. Thisincludes trades between our electricity generating stations as needed to offsetNOx emissions. During 2002 and 2001, we were a net seller of NOx allowances. In2003, we were short approximately 1,200 NOx allowances. The 2003 shortfall wascovered by purchasing 70 NOx allowances from AES Ironwood, an indirect whollyowned subsidiary of the AES Corporation at market prices and the remainder ofNOx allowances were purchased from unrelated companies in the open market atmarket price.

 

Based on current market pricing of electricity and NOx allowanceforwards for the years 2004 and 2005, respectively, we forecast that we willhave a shortfall of approximately 1,400 and 804 NOx allowances in 2004 and2005, respectively.  Based on currentprices could the shortfall cost between $3.2 million to $2.4 million and $1.8million to $1.7 million for the years 2004 and 2005, respectively.  The shortfall will be covered by purchasingNOx allowances at market price from unrelated companies in the open market orby reduced operations of our non-reheat units and/or reducing emission rates.

 

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

 

In September2003, New York State determined the amount of NOx emissions allowances thatwould be allocated to our electricity generating stations. The allocation isseveral thousand tons short of our average historical NOx emissions for ourelectricity generating stations during the control period. Our compliance plancannot be finalized until the anticipated New York NOx allowance market pricesare more conclusively determined.

 

The capital cost of the Somerset SCR was $31million. We expect that the system will operate for 20 years. Wehave developed a catalyst maintenance plan to insure the SCR’s performance,which consists of changing out one of the three layers of catalyst everyeighteen months. We purchased a layer of regenerated catalyst for $900,000 andinstalled it during our fall 2003 scheduled outage.  During the scheduled outage, we removed a layer, which will beregenerated and stored until our next scheduled outage at a cost of $1 million.Catalyst layers will continue to be rotated and regenerated on an approximately18-month schedule at a cost of approximately $1 million per rotation. The capital cost of the Cayuga SCRon Unit 1 was $11.2 million and it was operational on June 7, 2001. We expectthat the system will operate for 20 years. We will need to replace the catalystapproximately every four years at an estimated cost of approximately $325,000in 2001 dollars.

 

Our electricity generating stations havegenerally achieved continuous compliance with the current NOx reductionrequirements with the exception noted below.

 

We voluntarily disclosedto the NYSDEC and the United States Environmental Protection Agency (“EPA”) onNovember 27, 2002 that NOx exceedances appear to have occurred on October 30and 31 and November 1-8 and 10 of 2002. The exceedances were discovered throughan audit by plant personnel of the electricity generating stations’ NOx RACTtracking system. We believe that we have taken all reasonable, good faithefforts to assess and correct the exceedances. Immediately upon discovery ofthe calculation error, the SCR at Somerset was activated to reduce NOxemissions. Emission data indicates that the system had already returned to acompliant operation by the time the error was discovered. The EPA has decidedto defer to the NYSDEC for review of the self-disclosure letter and technicalissues. We are unable to predict any potential actions or fines the NYSDEC mayrequire, if any.

 

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

 

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

 

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General and the NYSDEC. This information was sought in connection withthe Attorney General’s and the NYSDEC’s investigations of several electricgeneration stations in New York which are suspected of undertakingmodifications in the past (from as far back as 1977) without undergoing an airpermitting review.

 

On April 14, 2000, we received a request forinformation pursuant to Section 114 of the Clean Air Act from the EPA seekingdetailed operating and maintenance history data for Cayuga and Somerset. EPAhas commenced an industry-wide investigation of coal-fired electric powergenerators to determine compliance with environmental requirements under theClean Air Act associated with repairs, maintenance, modifications andoperational changes made to coal-fired facilities over the years. The EPA’sfocus is on whether the changes were subject to new source review or new sourceperformance standards, and whether best available control technology was or shouldhave been used. We have provided the requested documentation.

 

By letter dated May 25, 2000, the NYSDECissued a Notice of Violation (NOV) to NYSEG for violations of the Clean Air Actand the Environmental Conservation Law at Greenidge and Westover related toNYSEG’s alleged failure to obtain an air permitting review for repairs andimprovements made during the 1980s and 1990s, which was prior to theacquisition of the electricity generating stations by us.  Pursuant to the Asset Purchase Agreement relatingto the acquisition of the electricity generating stations from NYSEG, we agreedto assume responsibility for environmental liabilities that arose while NYSEGowned the electricity generating stations. On September 12, 2000, we agreedwith NYSEG that we will assume the defense of and responsibility for the NOV,subject to a reservation of our right to assert applicable exceptions to ourcontractual undertaking to assume preexisting environmental liabilities.

 

We arecurrently in negotiation with both the EPA and NYSDEC. If a settlement is notreached, the EPA and the NYSDEC could issue a notice or notices of violation(NOV) to us for violations of the Clean Air Act and the EnvironmentalConservation Law. If the Attorney General, the DEC or the EPA does file anenforcement action against Somerset, Cayuga, Westover, or Greenidge, thenpenalties may be imposed and further emission reductions might be necessary atthese electricity generating stations which could require us to makesubstantial expenditures.  We are unableto estimate the effect of such a NOV on our financial condition or results offuture operations.

 

Mercury. InJanuary 2004, the EPA proposed the “utility mercury reductions rule” that wouldregulate mercury emissions from existing and new coal-fired power plants. TheEPA proposed two alternative approaches for reducing mercury emissions based ondifferent authority under the Clean Air Act. The EPA’s preferred approach is toimplement a cap and emission trading program with the first phase commencing in2010 and the second phase starting in 2018. If the EPA selects the alternative approach, compliance throughcurrently available pollution controls known as “maximum achievable controltechnologies”(MACT) could be required by December 2007. Pursuant to asettlement agreement with environmental groups, the EPA is required to finalizethe utility mercury reductions rule by December 15, 2004. At this point wecannot determine what the costs would be to comply with mercury controlregulations.

 

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

 

In addition, Northeastern U.S. states (including New York) have agreedto work to develop a regional market-based emissions trading system to reducepower plants’ CO2 emissions. The goal is to reach an agreement by April 2005 ona cap and emissions trading program. Until such time as the rules are developedto implement such a program, we cannot determine what its impact would be onour financial position or results of operations.

 

We voluntarily disclosedto the NYSDEC in January 2003 that Cayuga had inadvertently burned synfuel(coal with a latex binder applied), which it is not permitted to burn.  Cayuga had entered into an agreement with asupplier to purchase coal. It received approximately one 9000-ton trainshipment 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 havesuspended all shipments from that supplier until a resolution is reached. Wehave reviewed the emission and

 

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

 

Particulates and Opacity. Each of ourelectricity generating stations is currently in compliance with particulateemission limits. Each of our electricity generating stations is required tomeet an opacity limit. In the past, several of the electricity generatingstations exceeded these limits. This was a common problem at coal-firedelectricity generating stations, and the NYSDEC has initiated an enforcementaction against several utilities, including NYSEG.

 

In January 2000, we received a draft consentorder from the NYSDEC that alleges violations of the opacity emissionlimitations in the air permits for Cayuga, Westover, and Greenidge occurringsince our electricity generating stations were purchased from NYSEG.  The draft consent order would require us toprepare an opacity compliance plan and would impose penalties for opacityviolations occurring after May 14, 1999, the date of the acquisition. We do notknow when the NYSDEC will issue a final consent order. Potential fines andrequired actions cannot be divulged to the public until a final consent orderis signed. Nevertheless, we expect that any consent order will likely requirecontinued operation at the current level of opacity compliance that has beenachieved over the past year. AES NY, L.L.C. also received notice from NYSEGthat NYSEG has received a draft consent order from the NYSDEC seeking penaltiesprimarily for opacity violations occurring prior to May 14, 1999.  In the notice, NYSEG asserts that it willseek indemnification from AES NY, L.L.C. for any penalties, attorney fees, andrelated costs that it incurs in connection with the consent order. We and AESNY, L.L.C. have denied liability for the pre-closing violations and intend tovigorously defend this claim if NYSEG pursues litigation or arbitration.

 

Water Issues

 

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

 

Our electricity generating stations and theirash disposal sites have been designed and are operated to comply with strictwater and wastewater compliance standards. Groundwater protection measuresinclude coal pile liners at all stations, lined active ash disposal sites, noactive fly ash settling ponds, and a network of groundwater monitoring wells.New York State has not only technology-based effluent limitations for surfacewater discharges, but is one of the first states in the nation to impose morerestrictive limits on wastewater discharges to ensure that very protectivewater quality-based standards are maintained. Our electricity generatingstations have numerous wastewater treatment facilities in order to ensurecompliance with these restrictive discharge limits. In addition, Somersetnormally operates in a zero process wastewater discharge mode, reusingwastewater for various plant processes. Similarly, the ash disposal sites mustcomply with both technology and water quality-based discharge limits. Wherenecessary, a lime treatment is employed to remove metals from ash sitewastewater prior to discharge.

 

Hazardous Material andWastes

 

The electric utility industry typically usesand/or generates in its operations a range of potentially hazardous productsand by-products. We have identified a number of site remediation issues at ourelectricity generating stations. Under the terms of the Asset PurchaseAgreement with NYSEG, NYSEG retained pre-closing off-site environmentalliabilities associated with our electricity generating stations (other thanliabilities arising from the Weber and Lockwood ash disposal sites), but weassumed responsibility for contamination at our electricity generating stationsand at the Lockwood ash disposal site.

 

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We have budgeted $9.9 million for the costfor environmental liabilities at our electricity generating stations (excludingclosure and post-closure costs for the Weber and Lockwood ash disposal sites),based on estimates of environmental consultants retained by NYSEG and The AESCorporation. We have budgeted approximately $6 million for closure andpost-closure (monitoring and maintenance) expenses for the Lockwood ashdisposal site, based solely on amounts previously budgeted for these activitiesby NYSEG. ACR assumed responsibility for the Weber ash disposal site. Oursubsidiary, AEE2, L.L.C., has contributed one-half of the closure costs for theWeber ash disposal site based on the amount of ash disposed at the site fromWestover and Greenidge, which are owned by AEE2, L.L.C., compared to the amountdisposed from Hickling and Jennison, which were acquired by ACR.

 

In October 1999, ACRentered into a consent order with the NYSDEC to resolve alleged violations ofthe water quality standards in the groundwater downgradient of the Weber ashdisposal site. As a result, the site was closed. AEE2, L.L.C. contributedone-half of the costs to close the landfill, which were approximately $2million, and it will contribute additional costs for long-term groundwatermonitoring. 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, ofthe on-site landfill located at Somerset to contain ammonia-contaminated flyash produced during operation of the SCR system and stabilized sludge producedduring simultaneous operation of the FGD system. As designed, Area 3 willcomply with modern landfill design and performance standards. On April 26,1999, the New York State Board on Electric Generation Siting and theEnvironment approved the plan to use Area 3, subject to approval by the NYSDECof more detailed design submissions. The NYSDEC has definednon-ammoniated waste material to contain less than 0.5 parts per million ofammonia.  Most of the fly ash generatedduring operation of the SCR at Somerset qualifies as non-ammoniated. The NYSDEC approved disposal ofnon-ammoniated waste material generated during the operation of the SCR systemin an existing area of the landfill, Area 1. We are working with the NYSDEC tocomplete an approved design for the Area 3 expansion.

 

The Somerset landfill isunder the jurisdiction of the New York Public Service Commission. NYSEG’soriginal compliance filing with the Public Service Commission in 1983 providedthat the landfill would be constructed in a 200 acre section of the site, whichNYSEG divided into three areas (Areas 1, 2, and 3). The landfill was designedto 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 permeabilitymaterial, usually clay. However, the first 17-acre section of Area 1 of thelandfill was lined with compacted soil only. Only Area 1 was used by NYSEG. TheArea 1 landfill has been expanded seven times during the years since 1983. Whena portion of Area 1 reaches the maximum allowable elevation (130 feet), it is“capped” by adding compacted soil and planting ground cover. The entire processis meant to be self-implementing, with little input from the Public ServiceCommission unless there is a problem or a change in design or operation.

 

In the period since the original approval ofthe Somerset landfill, the NYSDEC has modified its solid waste landfillregulations extensively. As a result of these changes, these regulationscurrently allow construction or expansion of landfills only with lowpermeability liners and sophisticated leachate collection systems, and imposehigher standards for capping and closing solid waste facilities.

 

Natural groundwater conditions present at theSomerset site make it very difficult to distinguish between landfill leachateand naturally occurring substances in the groundwater. Substances that aretypically considered indicators of leachate infiltration into groundwater fromash monofill operations, namely sulfates, iron and manganese, are alsonaturally occurring in the groundwater around and beneath Area 1. NYSEGcommissioned independent consultants to perform groundwater testing usingsophisticated geochemical fingerprinting techniques, which distinguish themajor ions of a water sample. NYSEG’s consultants have shown, to thesatisfaction of the Public Service Commission, that there has been no materialrelease of leachate from Area 1 into the groundwater.

 

In April 1999, the NYSDEC and the PublicService Commission negotiated a Memorandum of Understanding that clarifiestheir respective roles with respect to the regulation of the Somerset landfill.According to the Memorandum of Understanding, the Public Service Commission’sdecisions will continue to control all aspects of Areas 1 and 2 of thelandfill, but the Public Service Commission must defer to current and futureNYSDEC regulations, standards and policies with respect to the development, useand closure of Area 3. The Memorandum of Understanding was approved by the NewYork State Board on Electric Generation Siting and the Environment and wasincorporated as part of the April 26, 1999 amendment to

 

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

 

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

 

On December23, 2003, Somerset was granted approval by the New York State Board on ElectricGeneration Siting and the Environment to amend the Certificate of EnvironmentalCompatibility and Public Need to landfill the petroleum coke fly ash andstabilized sludge produced during operation of the SCR and FGD system.

 

The existing Cayuga on-site landfillcurrently complies with modern landfill design and performance standards andwill receive any ammonia-contaminated fly ash or ammoniated sludge producedduring operation of the SCR system on Unit 1. Cayuga has seen concentrations of certainanalytical parameters above established action levels in ground watermonitoring wells down gradient from the ash disposal area. Remedies are beingdiscussed with the NYSDEC. Actions may include operational changes or cappingthe existing landfill, construction of a new landfill cell, or a combination ofthese actions.

 

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

 

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

 

These projectedenvironmental cost estimates are not a guarantee that additional environmentalliabilities will not be incurred, and it is possible that the actual costscould be significantly higher. In addition, it is possible that previouslyunknown environmental conditions will be discovered in the future.

 

**Noise**

 

The Certificate of EnvironmentalCompatibility that was issued to NYSEG in 1978 for the development andoperation of Somerset contains a number of requirements for mitigatingenvironmental impacts from the facility, including noise impacts. Among thenoise requirements was an obligation to obtain noise easements from neighboringlandowners or, as subsequently approved by the Public Service Commission, topurchase their property in a buffer zone where noncompliance with noisestandards was expected to occur. Subsequent analyses predicted that theseexceedances would occur only in connection with ash disposal operations whenArea 2 of the Somerset landfill was constructed. Prior to the acquisition ofour electricity generating stations, NYSEG had purchased neighboring propertiesfor a combined cost totaling approximately $1.5 million and had a standingoffer to purchase the remainder. We obtained an appraisal of the remainingproperties which places their aggregate current value at approximately $3.1million in 1999 dollars. We have not budgeted any amount for the acquisition ofthese properties.

 

The Public ServiceCommission has also required that a noise mitigation plan be developed andsubmitted for Public Service Commission approval at least one year prior tocommencement of Area 2 development.

 

The Public ServiceCommission could require additional noise control measures at that time. We do notexpect that the noise compliance costs we may incur, including as a result oftaking over the land purchase program, will be material.

 

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People

 

As of December 2003, we employedapproximately 300 people who operate our electricity generating stations. TheInternational Brotherhood of Electrical Workers (the “IBEW”) represents hourlylabor at Somerset, Cayuga, Westover and Greenidge.  The IBEW represents approximately 244 workers. We have negotiatedcollective bargaining agreements with respect to each electricity generatingstation, on an individual electricity generating station basis.  This gives us continuing labor harmony andencourages the adoption of The AES Corporation’s culture by emphasizing individualbusinesses with responsibility and ownership of local issues. We believe thatrelations with the people employed at our electricity generating stations aresatisfactory.

 

**Item 2****.  Properties**

 

The following table shows the materialproperties which we or our subsidiaries own or lease. See “Business—TheElectricity 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          |   |

 

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*                 We own all of the land on whichSomerset and Cayuga are located and we lease the portion on which thefacilities of those stations are located to the special purpose business truststhat own those facilities. We lease the facilities of those stations andsublease the land on which they are located from the special purpose businesstrusts.

 

**Item 3****.  Legal Proceedings**

 

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

 

OnMarch 30, 2001, Pozament Corp. filed a Summons and Complaint to be served onAES Westover, LLC, wherein it seeks to recover damages for breach of contract.The plaintiff alleges that it had an exclusive agreement with Westover toremove all of its coal flyash. We believe that the contract in question isunenforceable and void and intend to vigorously defend this claim. We feel thatany award or settlement in this case would not materially affect our financialposition or results of operations.

 

**Item 4****.  Submission ofMatters to a Vote of Security Holders**

 

Not applicable.

 

17

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**PART II**

 

**Item 5****.  Market for ourCompany’s Common Equity and Related Stockholder Matters**

 

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

 

**Item 6****.  Selected FinancialData**

 
| **As of December 31,**                  |   | **2003** |   | **2002** |   | **2001** |   | **2000** |   | **1999** |   |
|-----------------------------------------|--------|----------|--------|----------|--------|----------|--------|----------|--------|----------|--------|
|                                    |   |     |   |     |   |     |   |     |   |     |   |
| Balance  Sheet Data (in millions)       |   |     |   |     |   |     |   |     |   |     |   |
| Total  assets                           |   | $        | 1,118  |     | $      | 1,126    |   | $        | 1,194  |     | $      | 1,185 |   | $ | 1,133 |   |
| Long  term liabilities                  |   | $        | 708    |     | $      | 688      |   | $        | 699    |     | $      | 678 |   | $ | 692 |   |
| Partners’  capital                 |   | $        | 348    |     | $      | 382      |   | $        | 433    |     | $      | 441 |   | $ | 378 |   |
|                                    |   |     |   |     |   |     |   |     |   |     |   |
| **For the period ending December 31,**  |   | **2003** |   | **2002** |   | **2001** |   | **2000** |   | **1999** |   |
|                                    |   |     |   |     |   |     |   |     |   |     |   |
| Statement  of Income Data (in millions) |   |     |   |     |   |     |   |     |   |     |   |
| Operating  revenue                      |   | $        | 421    |     | $      | 363      |   | $        | 378    |     | $      | 388 |   | $ | 185 |   |
| Operating  income                       |   | $        | 148    |     | $      | 114      |   | $        | 106    |     | $      | 151 |   | $ | 57 |   |
| Net  income                             |   | $        | 89     |     | $      | 59       |   | $        | 52     |     | $      | 98 |   | $ | 24 |   |

 

SELECTEDQUARTERLY FINANCIAL DATA

 

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

 
|                                                                   |   | **First****Quarter** |    | **Second****Quarter** |   | **Third****Quarter** |   | **Fourth****Quarter** |    |
|------------------------------------------------------------------------|--------|----------------------|---------|-----------------------|--------|----------------------|--------|-----------------------|---------|
|                                                                   |   |                 |    |                  |   |                 |   |                  |    |
| YEAR ENDED DECEMBER 31, 2003:                                          |   |                 |    |                  |   |                 |   |                  |    |
| Operating revenue                                                      |   | $                    | 107,803 |                  | $      | 97,917               |   | $                     | 118,132 |   | $ | 96,864 |   |
| Operating income                                                       |   | 43,183               |    | 35,897                |   | 47,948               |   | 20,779                |    |
| Net income before cumulative effect of  change in accounting principle |   | 29,248               |    | —                |   | —               |   | —                |    |
| Net income                                                             |   | 27,592               |    | 21,659                |   | 33,490               |   | 6,325                 |    |
|                                                                   |   |                 |    |                  |   |                 |   |                  |    |
| YEAR ENDED DECEMBER 31, 2002:                                          |   |                 |    |                  |   |                 |   |                  |    |
| Operating revenue                                                      |   | $                    | 84,520  |                  | $      | 89,382               |   | $                     | 85,788  |   | $ | 103,324 |   |
| Operating income                                                       |   | 25,700               |    | 31,718                |   | 18,755               |   | 38,035                |    |
| Net income                                                             |   | 11,854               |    | 17,917                |   | 3,279                |   | 25,580                |    |

 

18

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

** **

Overview

 

The information in thisManagement’s Discussion and Analysis should be read in conjunction with theaccompanying consolidated financial statements, the related Notes to theFinancial Statements and the selected financial data. Forward lookingstatements in this Management’s Discussion and Analysis are qualified by thecautionary statement in the Forward Looking Statements section of theManagement’s Discussion and Analysis.

 

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

 

On February19, 2002, The AES Corporation announced that it intended to reposition itselfin the electric business by fully contracting or divesting its merchantgeneration businesses. The AES Corporation stated that it made this decision toreduce earnings volatility and strengthen its balance sheet. We are one of TheAES Corporation’s merchant generating businesses. Subsequently, The AES Corporationhas determined that our business will remain part of its portfolio, based onrecent and expected performance.

 

The economics of any electric power facilityare primarily a function of the price of electricity, the quantity ofelectricity which is purchased and the level of operating expenses. The greaterthe percentage of time a unit is dispatched, the greater the revenuesassociated with that unit.

 

The markets for wholesaleelectric energy, unforced capacity and ancillary services in the New York powermarket were largely deregulated in November 1999. In a competitive market wherethe order in which electricity generating plants are dispatched will be basedon 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 andtherefore those facilities will be dispatched more often than higher marginalcost facilities.

 

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

 

Our electricity generatingstations have historically been available to run a high percentage of the timedue to the regulated utility-grade nature of their design and construction. In2003, 2002 and 2001, the stations had a weighted average (based on capacity)equivalent availability factor of 93%, 96% and 96%, respectively (excluding thescheduled outage at Cayuga from April to June 2001 while an SCR was installedon Unit 1). We believe that we can maintain or improve the availability of ourelectricity generating stations.

 

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

 

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NYSEG has brought aproceeding to obtain a refund of real estate taxes it paid in connection withSomerset while NYSEG owned it. NYSEG had little incentive to contest the taxvaluation of its electricity generating stations while it owned them becausethe real property taxes it paid were included among the expenses it waspermitted to recover through regulated electricity rates and were thereforepassed along to its customers.

 

If NYSEG is successful inobtaining substantial refunds of prior real estate taxes,  local governments may be forced to raisereal 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 ourconsolidated financial statements in accordance with accounting principlesgenerally accepted in the United States of America. As such, we are required tomake certain estimates, judgments and assumptions that we believe arereasonable based upon the information available. These estimates andassumptions affect the reported amounts of assets and liabilities at the dateof the financial statements and the reported amounts of revenues and expensesduring the periods presented. The significant accounting policies which webelieve are most critical to understanding and evaluating our reportedfinancial results include the following: Revenue Recognition; Property, Plantand Equipment, Contingencies and Derivatives.

Revenue Recognition

 

Revenues from the sale ofelectricity are recorded based upon output delivered and rates specified undercontract terms. Gains and losses, generated from the hedging of future salesusing commodity forwards, swaps and options, reported in other comprehensiveincome, are reclassified to earnings in the periods in which earnings areimpacted by the variability of the cash flows of the hedged item. Theineffective portions of the change in fair value of derivatives and the changein the fair value of derivatives not designated as hedges for accountingpurposes are recognized in current period earnings. Revenues for ancillary andother services are recorded when the services are rendered. The TransmissionCongestion Contract is not deemed to be a hedge based on the definitions inStatement of Financial Accounting Standards (“SFAS”) No. 133. Therefore, thiscontract is marked-to-market at the end of every period. The mark-to-marketvalue is computed based on a regression of historical eastern and westernlocational prices. This regression is used with forecasted eastern and westernlocational prices to calculate the forward congestion for the remainder of thecontract term. This accounting treatment contributes to the income statementvolatility of this contract.

 

Property, Plant and Equipment

 

Electric generation assets that existed at the date ofacquisition were recorded at fair market value. Somerset and Cayuga, whichrepresent $650million of the electric generation assets, are subject to a leasing arrangementaccounted for as a financing. Additions or improvements thereafter are recordedat cost. Depreciation is computed using the straight-line method over the34-year and 28.5-year lease terms for Somerset and Cayuga, respectively, andover the estimated useful lives for the other fixed assets, which range from 7to 35 years. A significant overabundance of supply and asustained, significant decline in market prices to below our variable costcould cause a decrease in the estimated useful lives of our electric generationassets. If the useful life of any of our property, plant and equipment ischanged, the new life would be based on engineering studies and expected usage.The estimated average remaining useful life of our property, plant andequipment is approximately 22 years. If the estimated average remaining life ofour property, plant and equipment were to decrease by five years, annualdepreciation would increase by $12.2 million. Maintenanceand repairs are charged to expenses as incurred.

 

Contingencies

 

We accrue for loss contingencies when theamount of the loss is probable and estimable. We are subject to variousenvironmental regulations, and we are involved in certain legal proceedings. Ifour actual environmental and/or legal obligations are materially different fromour estimates, the recognition of the actual amounts may have a material impacton our operating results and financial condition.

 

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Derivatives

 

On January 1, 2001, weadopted SFAS No. 133, “Accounting for Derivative Instruments and HedgingActivities,” which, as amended, established new accounting and reporting standardsfor derivative instruments and hedging activities. SFAS No. 133 requires thatall derivatives (including derivatives embedded in other contracts) be recordedas either assets or liabilities at fair value on the balance sheet. Changes inthe derivative’s fair value are to be recognized in earnings in the period ofchange, unless hedge accounting criteria are met. Hedge accounting allows thederivative’s gains or losses in fair value to offset the related results of thehedged item. We utilize derivative financial instruments to manage commodityprice risk. Although the majority of our derivative instruments qualify forhedge accounting, the adoption of SFAS No. 133 may result in more variation toour results of operations from changes in commodity prices.  We have chosen to use the hypotheticalderivative methodology for testing whether our hedges meet the criteria toqualify for hedge accounting treatment. A historical regression is performedbetween the electricity generating stations delivery points into the NYISO andthe NYISO zones in which the hedges are settled. Comparing the results of thehistorical regression and the actual changes in the market value of the hedgesdetermines if the hedges qualify for hedge accounting criteria treatment.  For the years ended December 31, 2003, 2002and 2001 we recognized a loss of $6.2 million, income of $8.9 million and aloss of $29.5 million, respectively, pursuant to SFAS No. 133 related toderivatives which did not qualify for hedge accounting.  See Note 7 of our audited financialstatements, which are included in this Annual Report on Form 10-K for a morecomplete discussion of the accounting for derivatives under SFAS No. 133.

 
| **Results of Operations  (Amounts in Millions)For the Year Ended December 31,** |   | **2003** |   | **2002** |   | **%  Change** |   | **2001** |   | **%  Change** |   |
|---------------------------------------------------------------------------------|--------|----------|--------|----------|--------|---------------|--------|----------|--------|---------------|--------|
|                                                                            |   |     |   |     |   |          |   |     |   |          |   |
| Energy  Revenue                                                                 |   | $        | 388.9  |     | $      | 310.6         |   | 25.2     |   | $             | 345.4  |   | (10.1 | ) |
|                                                                            |   |     |   |     |   |          |   |     |   |          |   |
| Capacity  Revenue                                                               |   | 29.7     |   | 36.6     |   | (18.9         | )      | 26.8     |   | 36.6          |   |
|                                                                            |   |     |   |     |   |          |   |     |   |          |   |
| Transmission  Congestion Contract                                               |   | —   |   | 8.9      |   | —        |   | —   |   | —        |   |
|                                                                            |   |     |   |     |   |          |   |     |   |          |   |
| Other                                                                           |   | 2.2      |   | 6.9      |   | (68.1         | )      | 6.2      |   | 11.3          |   |
|                                                                                 |        |          |        |          |        |               |        |          |        |               |        |  |  |  |

 

Energyrevenues for the year ended December 31, 2003 were $388.9 million, compared to$310.6 million for the year ended December 31, 2002, an increase of 25.2%. Theincrease in energy revenues is primarily due to higher market prices and stabledemand. 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 offpeakelectricity was flat compared to demand for the year ended December 31, 2002.Energy revenues for the year ended December 31, 2002 were $310.6 million,compared to $345.4 million for the year ended December 31, 2001, a decrease of10.1%. The decrease in energy revenues was primarily due to lower market pricesand lower demand. Market prices for peak and offpeak electricity were 12.2% and6.5% lower than the year ended December 31, 2001. Demand for peak and offpeakelectricity was 3.2% and 1.7% lower than the year ended December 31, 2001. These were offset by a majormaintenance outage at Cayuga of approximately 45 days for Unit 1 in 2001.

 

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

 

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

 

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The TransmissionCongestion Contract is essentially a swap between the congestion component ofthe locational prices posted by the NYISO in western New York and the morepopulated areas in eastern New York. The Transmission Congestion Contract became effective onNovember 1, 2000 and terminates on October 1, 2004. We entered into thisagreement because it provided a reasonable settlement for resolving a FERCdispute between us and Niagara Mohawk Power Corporation. This contract is notdeemed to be a hedge based on the definitions in SFAS 133. Therefore, thiscontract is marked to market at the end of every period.  The mark-to-market value is computed basedon a regression of historical eastern and western locational prices. Thisregression is used with forecasted eastern and western locational prices tocalculate the forward congestion for the remainder of the contract term. Thisaccounting treatment contributes to the income statement volatility of thiscontract.

 
| **Operating Expenses  For the Year Ended December 31,** |   | **2003** |   | **2002** |   | **%  Change** |   | **2001** |   | **%  Change** |   |
|---------------------------------------------------------|--------|----------|--------|----------|--------|---------------|--------|----------|--------|---------------|--------|
|                                                    |   |     |   |     |   |          |   |     |   |          |   |
| Fuel  expense                                           |   | $        | 148.3  |     | $      | 137.2         |   | 8.1      |   | $             | 135.6  |   | 1.2 |   |
|                                                    |   |     |   |     |   |          |   |     |   |          |   |
| Depreciation  and amortization                          |   | 36.1     |   | 35.5     |   | 1.7           |   | 33.6     |   | 5.7           |   |
|                                                    |   |     |   |     |   |          |   |     |   |          |   |
| Operations  and maintenance                             |   | 23.3     |   | 17.0     |   | 37.1          |   | 19.6     |   | (13.3         | )      |
|                                                    |   |     |   |     |   |          |   |     |   |          |   |
| General  and administrative                             |   | 59.2     |   | 59.1     |   | 0.2           |   | 53.7     |   | 10.1          |   |
|                                                    |   |     |   |     |   |          |   |     |   |          |   |
| Transmission  Congestion Contract                       |   | 6.2      |   | —   |   | —        |   | 29.5     |   | —        |   |
|                                                         |        |          |        |          |        |               |        |          |        |               |        |  |  |  |

 

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

 

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

 

Operations andmaintenance expense for the year ended December 31, 2003 was $23.3 million,compared to $17 million for the year ended December 31, 2002, an increase of37.1%. This increase is primarily due to maintenance expenses incurred duringscheduled outages at every electricity generating station during 2003.Operations and maintenance expense for the year ended December 31, 2002 was $17million, compared to $19.6 million for the year ended December 31, 2001, adecrease of 13.3%. This decrease was primarily due to maintenance expensesincurred during a scheduled outage at Cayuga in the second quarter of 2001,which are not annually recurring expenses.

 

General andadministrative 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 of0.2%. General and administrative expense for the year ended December 31, 2002was $59.1 million, compared to $53.7 million for the year ended December 31,2001, an increase of 10.1%. This increase was primarily due to significantincreases in property taxes and property and medical insurance which werepartially offset by reversal of accruals for potential environmentalliabilities which were resolved at a lower cost than estimated.

 

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| **Other Income/Expenses  For the Year Ended December 31,** |   | **2003** |   | **2002** |   | **%  Change** |   | **2001** |   | **%  Change** |   |
|------------------------------------------------------------|--------|----------|--------|----------|--------|---------------|--------|----------|--------|---------------|--------|
|                                                       |   |     |   |     |   |          |   |     |   |          |   |
| Interest  expense                                          |   | $        | 59.1   |     | $      | 57.7          |   | 2.4      |   | $             | 58.4   |   | (1.2 | ) |
|                                                       |   |     |   |     |   |          |   |     |   |          |   |
| Interest  Income                                           |   | 2.1      |   | 2.1      |   | —        |   | 3.9      |   | (46.2         | )      |
|                                                            |        |          |        |          |        |               |        |          |        |               |        |  |  |  |

 

OtherIncome/Expenses for the year ended December 31, 2003 were net expenses of $57million, compared to net expenses of $55.6 million for the year ended December31, 2002, an increase of 2.5%. This increase is primarily due to higherinterest expense. The interest expense on the lease obligations were set at theissuance and our established amortization schedule does not follow a typicalschedule. Other Income/Expenses for the year ended December 31, 2002 were netexpenses of $55.6 million, compared to net expenses of $54.5 million for theyear ended December 31, 2001, a decrease of 2.0%. This decrease is primarilydue to lower cash balances and lower market interest rates.

 

Liquidity and Capital Resources

 

Operating Activities

 

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

 

Investing Activities

 

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

 

We incurred approximately$5.4 million, $7.1 million and $17.1 million in capital expenditures withregard to our assets for the years ended December 31, 2003, 2002 and 2001,respectively. These amounts include $1.4 million for the overfireair project to reduce NOx emissions at Westover Unit 8 in 2003 and approximately $11.2 million for aSCR system to reduce NOx emissions at Cayuga Unit 1 which was operational June7, 2001.  We will make capitalexpenditures thereafter according to the maintenance program for ourelectricity generating stations. In addition to capital requirements associatedwith the ownership and operation of our electricity generating stations, wewill have significant fixed charge obligations in the future, principally withrespect to the leases.

 

Compliance with environmental standards willcontinue to be reflected in our capital expenditures and operating costs. Basedon the current status of regulatory requirements, other than the expendituresfor the SCRs at Somerset and Cayuga including the construction of new landfillspace to manage ash from Somerset’s SCR system operations, expenditures forpossible installation of a SCR system on Cayuga Unit 2, the U.S. Department ofEnergy Power Plant Improvement project on Greenidge Unit 4 and expenditures forstudies, and capital and operating expenses to bring the electricity generatingstations into compliance with the new federal cooling water intake standards,we do not anticipate that any capital expenditures or operating expensesassociated with our compliance with current laws and regulations will have amaterial effect on our operations or our financial condition. See“Business—Regulation—Environmental Regulatory Matters.”

 

Financing Activities

 

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

 

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

 

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the leases is $63.5 million for 2004, $59.5 million for 2005, $61.6million for 2006, $62.5 for 2007, $62.5 for 2008 and a total of $1,189.7million for the years thereafter.  Forpurposes of the minimum rent obligations described in the preceding sentence,we treated the semiannual rent payments that are due on January 2 of each yearas though they would be paid in the preceding year. You can find informationconcerning our minimum rental obligations that treats rent payments asobligations for the years in which they are due in Note 6 of our auditedfinancial 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 maydefer payment of rent obligations under each lease in excess of the amountrequired to pay principal and interest on the secured lease obligation notesuntil after the final scheduled payment date of the secured lease obligationnotes.  As of December 31, 2003, we havenot deferred any portion of our lease obligations. In addition, we are requiredto maintain a rent reserve account equal to the maximum semiannual payment withrespect to the sum of basic rent (other than deferrable basic rent) and fixedcharges expected to become due on any one basic rent payment date in theimmediately succeeding three-year period. At December 31, 2003 and 2002, theamounts deposited in the rent reserve account were $31.7 million and 31.7million, respectively.

 

We are also obligated tomake payments under the coal hauling agreement with Somerset Railroad in anamount sufficient, when added to funds available from other sources, to enableSomerset Railroad to pay, when due, all of its operating expenses and otherexpenses, including interest on and principal of outstanding indebtedness. OnAugust 14, 2000, Somerset Railroad entered into a $26 million credit facilitywith Fortis Capital Corp. which replaced in its entirety a credit facility forthe same amount previously provided to Somerset Railroad by an affiliate ofCIBC World Markets.  The credit facilityprovided by Fortis Capital Corp. consists of a 14-year term note (maturing onMay 6, 2014), with principal and interest payments due quarterly.

 

As a result of theseobligations, we must dedicate a substantial portion of our cash flow fromoperations to payments of rent under the leases, payments under our workingcapital facility and payments under the coal hauling agreement with SomersetRailroad, which in turn allow Somerset Railroad to pay principal and interestunder its credit facility with Fortis Capital Corp. The principal payments forthe $26 million credit facility are $1.9 million per year.

 

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

 

On November 20, 2002, we signed an agreement with Union Bank ofCalifornia, N.A. for a one-year extension of the working capital and letter ofcredit facility. On April 16, 2003, we signed an amendment to our November 20,2002 credit agreement with Union Bank of California, N.A. The amendmentincludes another one-year extension of the current facility; the maturity dateof the working capital and letter of credit facility is now January 2, 2005.The amendment also increases Union Bank of California’s commitment from $15million to $20 million. On April 25, 2003, we further amended our November 20,2002 credit agreement with Union Bank of California, N.A. The amendmentincludes a commitment from Citibank, N.A. for the remaining $15 million of thefacility. There have been four borrowings under this facility. The firstborrowing was for $9.7 million on January 10, 2003 at an interest rate of5.75%. This borrowing was repaid in full on January 28, 2003. The secondborrowing 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 borrowingwas 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 onFebruary 20, 2004 at an interest rate of 5.5%. This borrowing was repaid infull on February 26, 2004. At the date of filing of our Annual Report on Form10-K, of the $35 million committed, we had obtained letters of credit of $24.9million, which have been provided as

 

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additional margin to supportnormal, ongoing hedging activities with a number of counterparties.

 

The AESCorporation on January 6, 2003 and February 25, 2003 authorized us to issueletters of credit to counterparties on its $350 million senior securedrevolving credit facility to the amount of $25 million and $35 million for theyears of 2003 and 2004, respectively.

 

On February12, 2004, we signed a two-year agreement, effective January 1, 2004,  with The AES Corporation to obtain up to $35million and $25 million of letters of credit or cash collateral for 2004 and2005, respectively. This agreement supercedes the authorization of The AESCorporation on February 25, 2003. The agreement limits the letters of creditamounts and cash collateral to the stated amounts and set into place a feestructure and repayment terms. At the date of filing of our Annual Report onForm 10-K, we have obtained letters of credit in the amount of $33 million,which have been provided as additional margin to support normal, ongoinghedging activities with a number of counterparties.

 

Our future ability to obtain additional debtfinancing for working capital, capital expenditures or other purposes islimited by financial covenants restricting our ability to incur debt and lienscontained in the agreements governing the leases of Somerset and Cayuga.  With certain exceptions, these agreementslimit 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 fromour operations was sufficient to cover aggregate rental payments under theleases for Somerset and Cayuga on the rent payment dates of January 2, 2001,July 2, 2001, January 2, 2002, July 2, 2002, January 2, 2003, July 2, 2003 andJanuary 2, 2004. We believe that cash flow from our operations will besufficient to cover aggregate rental payments on each rent payment datethereafter. We also believe that our cash flow from operations, together withamounts we can borrow under our $35 million working capital and letter ofcredit facility with Union Bank of California, N.A., will be sufficient tocover expected capital requirements over the terms of the leases. If we arerequired to make unanticipated capital expenditures, our cash flow fromoperations and operating income in the period incurred would be reduced.

 

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

 

The agreements governingthe leases of Somerset and Cayuga and our working capital credit facilityimpose severe restrictions on our ability to make distributions of cash orother assets to our owners and on the ability of our owners to withdraw cash orother assets from us. These restrictions are intended to assure that we havepaid all of our operating and maintenance expenses and all of our obligationsunder our leases and under our working capital credit facility before anyassets are distributed to or withdrawn by our owners.  We may make a distribution to our owners on or within tenbusiness days after a rent payment date for the Somerset and Cayuga leases so longas the following conditions are satisfied:

 

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

 

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

 

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

 

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

 

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

 

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

 

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be equal to or greater than the required coverage ratio and the proforma coverage ratios for each of the four semiannual periods immediatelysucceeding this rent payment date must be equal to or greater than the requiredcoverage ratio;

 

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

 

The AESCorporation contributed approximately $162,000, $1.5 million and $9.4 millionto us in 2003, 2002 and 2001, respectively. The contributions which wereaccounted for as a partner’s contribution, related to stock option compensationexpense in 2003 and the construction of the SCR on Unit 1 of Cayuga, whichbecame operational on June 7, 2001.

 

Credit Rating Discussion

 

Credit ratings affect our ability to executeour commercial strategies in a cost-effective manner. In determining our creditrating, the rating agencies consider a number of factors. Quantitative factorsthat appear to have significant weight include, among other things, earningsbefore interest, taxes and depreciation and amortization (“EBITDA”); operatingcash flow; total debt outstanding; fixed charges such as interest expense andlease payments; liquidity needs and availability and various ratios calculatedfrom these factors. Qualitative factors appear to include, among other things,predictability of cash flows, business strategy, industry position andcontingencies.

 

On October 3, 2002,Standard & Poor’s lowered its rating on our $550 million pass though trustcertificates issued to finance the acquisition of Somerset and Cayuga and $35million working capital and letter of credit facility to BB+ from BBB- solelydue to our rating linkage to The AES Corporation. The rating was also placed onCreditWatch with negative implications. In a press release announcing theratings 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 ratingof the parent.  Even though we believethat the provisions of our financing arrangements render us bankruptcy remotefrom The AES Corporation, Standard & Poor’s stated that it did not viewthese provisions as 100% preventative of the risk of substantive consolidationin the event of a bankruptcy of The AES Corporation. Therefore, Standard &Poor’s limited the rating differential provided by such structural elements tothree notches and stated that our credit ratings cannot be higher than BB+.

 

Trigger Events

 

Our commercial agreementstypically include adequate assurance provisions relating to trade credit andsome agreements have credit rating triggers. These trigger events typicallywould give counterparties the right to suspend or terminate credit if ourcredit ratings were downgraded. Under such circumstances, we would need to postcollateral to continue transacting risk-management business with many of ourcounterparties under either adequate assurance or specific credit ratingtrigger clauses. The cost of posting collateral would have a negative effect onour profitability. If such collateral were not posted, our ability to continuetransacting business as before the downgrade would be impaired. In response toan earlier downgrade of The AES Corporation, one of our coal suppliersrequested credit assurance based on a clause specific to their contact. Afterdiscussions with the supplier, we negotiated an agreement for a prepaymentsystem with a discounted price. This agreement expired on December 31, 2002 andwas not renewed. On October 8, 2002, one of our counterparties made a $1million margin call on us because of the Standard & Poor’s downgrade. Weprovided a letter of credit for $1 million.

 

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

 

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Pension Plan

 

Effective May 14, 1999, weadopted The Retirement Plan for Employees of AES NY, L.L.C. (the Plan), adefined benefit pension plan. The Plan covers people employed both undercollectively bargained and non-collectively bargained arrangements. Certainpeople formerly employed by NYSEG (the Transferred Persons) receive creditunder the Plan for compensation and service earned while being employed byNYSEG. The amount of any benefit payable under the Plan to a Transferred Personwill be offset by the amount of any benefit payable to such Transferred Person underthe Retirement Plan for Employees of NYSEG. Effective May 29, 1999, the abilityto commence participation in the Plan and the accrual of benefits under thePlan ceased with respect to non-collectively bargained people and the accruedbenefits 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 RevenueCode (IRC) Section 412 minimum funding and not more than the requirement of IRCSection 404, maximum contribution limits. We will make at least the requiredminimum contribution within the Employee Retirement Income Security Act (ERISA)guidelines. Pension benefits are based on the number of years of creditedservice, age of the participant, and average earnings. During 2003, 2002, and2001, collectively bargained people were offered the opportunity to freezetheir accrued benefit payable under the Plan and opt into the AES ProfitSharing and Stock Ownership Plans.

 

The assets and liabilitiesof the Plan were valued as of October 31, 2003 and 2002.  This measurement date is a change from theprevious practice of utilizing a December 31 measurement date for 2001. Thevalues of the assets and liabilities as of October 31, 2003 and 2002 were notmaterially different than the values as of December 31, 2003 and 2002.

 

Significant assumptionswere used in the calculations of the net benefit cost and projected benefitobligation for the periods ending October 31, 2003 and 2002 and December 31,2001. In developing our expected long-term rate of return assumption, weevaluated input from our actuaries and plan asset manager. Projected returnsare based on a broad range of equity and bond indices. Our expected 8%long-term rate of return on Qualified Plan assets is based on the allocationassumption of 60% equities (50% Growth and 50% Value), with a 10% long termrate of return and 40% in fixed income investments, with a 5.5% long-term rateof return. Because of market fluctuation, our actual allocation was 58% and 52%equities and 42% and 48% in fixed income investments as of October 31, 2003 and2002, respectively. However, we believe that our long-term asset allocation onaverage will approximate 60% equities and 40% fixed income investments. Weregularly review the asset allocation with the asset manager and periodicallyrebalance the Plan’s investments to its targeted allocation when appropriate.We continue to believe that 8% is a reasonable long-term rate of return on ourqualified plan assets. We will continue to evaluate our actuarial assumptions,including the expected rate of return, at least annually, and will adjust asnecessary.

 

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

 

The discount rate that weutilize for determining future pension obligations is based on the rates atwhich we would expect insurance companies to settle future liabilities. Thediscount rate has remained at 6.25% since 2001. Future actual pension expensewill depend on future investment performance, changes in future discount ratesand various other factors related to the populations participating in ourpension plans.

 

The fair value of the Plan’s assets has increased from $7.2 million atOctober 31, 2002 to $9.4 million at October 31, 2003. The 2003 cashcontributions to the Plan of approximately $2.2 million and investmentperformance gains of approximately $933,000, were partially offset by benefitspaid during 2003 of approximately $830,000. We believe we will continue to berequired to make cash contributions to the Plan for at least the next threeyears.

 

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New AccountingPronouncements

 

Asset Retirement Obligations. In June 2001, the Financial AccountingStandards Board (“FASB”) issued Statement of Financial Accounting Standards(“SFAS”) No. 143, “Accounting for Asset Retirement Obligations”. SFASNo. 143, which was effective as of January 1, 2003, requires entitiesto record the fair value of a legal liability for an asset retirementobligation in the period in which it is incurred. When a new liability wasrecorded in the first quarter of 2003, the entity was required to capitalizethe costs of the liability by increasing the carrying amount of the relatedlong-lived asset. The liability is accreted to its present value each period,and the capitalized cost is depreciated over the useful life of the relatedasset. Upon settlement of the liability, the entity will settle the obligationfor its recorded amount or incur a gain or loss upon settlement.  We adopted SFAS No. 143 effectiveJanuary 1, 2003.

 

We have completed a detailed assessment of the specific applicabilityand implications of SFAS No. 143. The scope of SFAS No. 143 includesprimarily active ash landfills and water treatment basins. Upon adoption ofSFAS No. 143, we recorded a liability of approximately $9.2 millionand a net asset of approximately $3.3 million, which are included in theelectric generation assets, and reversed an approximately $4.2 millionenvironmental remediation liability we had previously recorded. (See Note 3 of our auditedfinancial statements, which are included in this Annual Report on Form 10-K).The difference between the amounts previously recorded and the net SFAS No. 143liability is a loss recorded as the cumulative effect of this change inaccounting principle of approximately $1.7 million. Reconciliation of the assetretirement obligation liability for the year ended December 31, 2003 was asfollows (in millions):

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

 

In December 2002, the FASB issued SFAS No. 148, “Accounting forStock-Based Compensation – Transition and Disclosure.” SFAS No. 148 amendsSFAS No. 123, “Accounting for Stock-Based Compensation” to provide alternativemethods of transition for a voluntary change to the fair value based method ofaccounting for stock-based employee compensation. In addition, this Statementamends the disclosure requirements of SFAS No. 123 to require prominentdisclosures in both annual and interim financial statements about the method ofaccounting for stock-based employee compensation and the effect of the methodused on reported results.  We expect to use the prospective method to transitionto the fair value based method of accounting for stock-based employee compensation. Allemployee awards granted, modified, or settled after January 1, 2003 will be recordedusing the fair value based method of accounting.  The expanded disclosuresrequired by SFAS No. 148 were included in our quarterly financial reportsbeginning in the first quarter of 2003. Our adoption of the prospectivemethod of accounting for stock-based employee compensation should not have anymaterial impact on our financial position or results of operations.

 

On April 30, 2003, the FASB issued SFAS No. 149, “Amendment ofStatement 133 on Derivative Instruments and Hedging Activities”. SFAS No. 149amends and clarifies financial accounting and reporting for derivativeinstruments and for hedging activities under SFAS No. 133. The amendmentreflects decisions made by the FASB and the Derivatives Implementation Group(DIG) in connection with issues raised about the application of SFAS No. 133.Generally, the provisions of SFAS No. 149 will be applied prospectively forcontracts entered into or modified after June 30, 2003 and for hedgingrelationships designated after June 30, 2003. SFAS No. 149 provisions thatresulted from the DIG process that became effective in quarters beginningbefore June 15, 2003 will continue to be applied based upon their originaleffective dates. The adoption of SFAS No. 149 did not have a material impact onour financial position or results of operations.

 

We adopted the disclosure provisions of FASB Interpretation No. (“FIN”)45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees,Including Direct Guarantees of Indebtedness of Others,” in the fourth quarterof 2002. We will apply the initial recognition and measurement provisions on aprospective basis for all guarantees issued after December 31, 2002. Ingeneral, we enter into various agreements providing financial performanceassurance to third parties on behalf of certain subsidiaries. Such agreementsinclude guarantees, letters of credit and surety bonds. FIN 45 does notencompass guarantees issued either between parents and their subsidiaries orbetween corporations under common control, a parent’s guarantee of itssubsidiary’s debt to a third party (whether the parent is a corporation or an

 

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individual), a subsidiary’sguarantee of the debt owed to a third party by either its parent or anothersubsidiary of that parent, nor does it apply to guarantees of a company’s ownfuture performance. Adoption of FIN 45 had no impact to our historicalfinancial statements as existing guarantees are not subject to the measurementprovisions of FIN 45. The adoption of the liability recognition provisions ofFIN 45 did not have a material impact on our financial position or results ofoperations.

 

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

 

Ingeneral, a VIE is an entity that lacks sufficient equity or its equity holderslack adequate decision making ability. If either of these characteristics ispresent, the entity is subject to a variable interests consolidation model, andconsolidation is based on variable interests, not on ownership of the entity’soutstanding voting stock. Variable interests are defined as contractual,ownership, or other money interests in an entity that change with fluctuationsin the entity’s net asset value. The primary beneficiary consolidates the VIE;the primary beneficiary is defined as the enterprise that absorbs a majority ofexpected losses or receives a majority of residual returns (if the losses orreturns occur), or both.

 

The sales – leaseback transaction under which Somerset and Cayuga wereacquired qualifies as a VIE. The sales — leaseback rules require that theleases be treated as financing leases for purposes of our financial statements,which they have been from our inception. We are considering theapplicability of consolidating Somerset Railroad. If we did so our consolidatedBalance Sheet as of December 31, 2003, would reflect additional assets ofapproximately $28.4 million and liabilities of approximately $19.6 million.

 

In May 2003,the FASB adopted SFAS No. 150, “Accounting for Certain Financial Instrumentswith Characteristics of Both Liabilities and Equity”. This Statementestablishes standards for how an issuer classifies and measures certainfinancial instruments with characteristics of both liabilities and equity. ThisStatement is effective for financial instruments entered into or modified afterMay 31, 2003, and otherwise is effective at the beginning of the first interimperiod beginning after June 15, 2003. The adoption of this pronouncement willnot have a material effect on our financial position or results of operations.

 

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

 

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ContractualObligations

 

Below is asummary of certain obligations that will require significant capital(inthousands):

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

 

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(1) CapitalLease Obligations includes imputed interest.

 

Future Issues and OtherMatters

 

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

 

Forward-looking Statements

 

Certain statementscontained in this Annual Report on Form 10-K are forward-looking statements asthat 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-lookingterminology such as “believes,” “expects,” “may,” “intends,” “will,” “should”or “anticipates” or the negative forms or other variations of these terms orcomparable terminology, or by discussions of strategy. Future results coveredby the forward-looking statements may not be achieved. Forward-lookingstatements are subject to risks, uncertainties and other factors which couldcause actual results to differ materially from future results expressed orimplied 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.

 

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**Item 7A****.  Quantitative andQualitative Disclosures About Market Risk**

 

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

 

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

 

We adopted a value at risk (VaR) approach to assess and managerisk.  VaR measures the potential lossin 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 consistentmeasure of risk across diverse markets and instruments. The VaR approach wasadopted because we feel that statistical models of risk measurement, such asVaR, provide an objective, independent assessment of our risk exposure. The useof VaR requires a number of key assumptions, including the selection of aconfidence level for expected losses, the holding period for liquidation andthe treatment of risks outside the VaR methodology, including liquidity riskand event risk.  VaR, therefore, is notnecessarily indicative of actual results that may occur.

 

The use of VaR allows us to compare risk on a consistent basis andidentify the drivers of risk.  Becauseof the inherent limitations of VaR, including those specific to thevariance/covariance approach, specifically the assumption that values orreturns are normally distributed, we rely on VaR as only one component in ourrisk assessment process.  In addition tousing VaR measures, we perform Cash Flow at Risk, stress and scenario analysesto estimate the economic impact of market changes on the value of ourportfolios.  These results are used tosupplement the VaR methodology.

 

We perform our VaR calculation using a model based on thevariance/covariance methodology with a delta gamma model for optionality.  We express VaR as a dollar amount of thepotential loss in the fair value of our portfolio based on a 95% confidencelevel and a one-day holding period. Our daily VaR for commodity price sensitiveinstruments as of December 31, 2003, 2002 and 2001 was $5.8 million, $4.8million and $6.2 million, respectively. These amounts include the financial instruments that serve as hedges anddo not include the underlying physical assets. In the year ended December 31,2003, the daily VaR amount was greater than the year-end amount on March 31,and June 30, 2003. During 2002, the daily VaR amount was greater than theyear-end amount at the end of each quarter in 2002. In the year ended December31, 2001, the daily VaR amount was greater than the year-end amount on June 29,and September 28, 2001.

 

**Item 8****.  FinancialStatements and Supplementary Data**

 

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

 

AES EASTERN ENERGY, L.P.

 

Independent Auditors’ Report

 

Financial Statements:

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

 

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

 

Independent Auditors’ Report

 

Financial Statements:

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

 

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

 

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

 

Not applicable.

 

**Item 9A****. Controls and Procedures**

 

Evaluation ofDisclosure Controls and Procedures. The principal executive officer andprincipal financial officer of our General Partner, based on the evaluation ofour “disclosure controls and procedures” (as defined in the Securities ExchangeAct of 1934 Rules 13a-15(e) or 15d-15(e)) as required by paragraph (b) ofExchange Act Rules 13a-15 or 15d-15, have concluded that as of December 31,2003, our disclosure controls and procedures were effective and designed toensure that information required to be disclosed by us and our consolidatedsubsidiaries in the reports that we file under the Exchange Act is recorded,processed, summarized and reported within the time periods specified in theSecurities and Exchange Commission’s rules and forms.

 

Changes in Internal Control Over Financial Reporting.  There have been no changes in our internalcontrol over financial reporting identified in connection with the evaluationrequired by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that occurredduring our last fiscal quarter that materially affected, or are reasonablylikely to materially affect, our internal control over financial reporting.

 

**PART III**

 

**Item 10****.  Directors andExecutive Officers of Our Company**

 

We are a Delaware limited partnership. Underthe Delaware Revised Uniform Limited Partnership Act and our Agreement ofLimited 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 totime 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 totime. The AES Corporation indirectly owns all member interests in and controlsAES NY, L.L.C.

 

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

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

 

Dan Rothaupt, has servedas Vice President of The AES Corporation responsible for North America — EastOperations since May 2003. Previously, he was President and Group Manager forAES Endeavor, covering AES business activities in the Northeast US and Canadaand has been our general manager since May 1999. Prior to that he was thePresident and Plant Manager of AES Thames from 1995 to 1999. Mr. Rothaupt has aBachelor of Science degree in Mechanical Engineering from the United StatesCoast Guard Academy.

 

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Kevin Pierce has served asAEE Business Leader and President and Plant Manager of Somerset since August2003, and prior to that as President and Plant Manager of Somerset sinceSeptember 2001. Previously, he was President and Plant Manager of AES Hawaiifrom June 1998 until September 2001. Mr. Pierce has a Bachelor of Sciencedegree in Marine Engineering from Maine Maritime Academy.

 

Jerry Goodenough hasserved 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. FromJanuary 1998 to March 2001, he was employed by NYSEG in a variety ofengineering supervisory roles. Mr. Goodenough holds a Bachelor of Arts degreein Physics from Ithaca College and a Master of Science degree in ElectricalEngineering from the State University of New York at Binghamton.

 

James Mulligan has servedas President and Plant Manager of Westover since May 1999. Previously, Mr.Mulligan was employed as the Milliken Station Manager under NYSEG from January1997 to May 1999. Mr. Mulligan has a Bachelor of Science degree in MechanicalEngineering from the New York Institute of Technology.

 

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

 

Amy Conley has served asthe Chief Financial Officer for AES Eastern Energy and AES NY, L.L.C. sinceJune 2001. Previously, Ms. Conley was employed as the Somerset Plant Accountantfrom 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 FisherCollege and a Master of Business Administration degree from Rochester Instituteof Technology.

 

Management of AES NY, L.L.C., the GeneralPartner of Our Company

 

AES NY, L.L.C., the general partner of ourcompany, is a Delaware limited liability company managed by managers who aredesignated as directors. The Board of Directors of AES NY, L.L.C. comprises twoclasses of directors, the Class A Directors and the Class B Director. There arethree Class A Directors, Edward Convery, Kevin Pierce and Dan Rothaupt, eachelected by the members of the limited liability company. The business andaffairs of AES NY, L.L.C. are managed by the Class A Directors. The Class BDirector’s only participation in the management of AES NY, L.L.C. is in mattersof bankruptcy or related matters. Mr. Rothaupt is also the President of AES NY,L.L.C.

 

Edward Convery has 24 yearsexperience in the power and chemicals industries, and has worked for The AESCorporation for 11 years. Mr. Convery is the Business Leader for the AES WarriorRun and the AES Beaver Valley facilities which supply power to AlleghenyEnergy. Mr. Convery was responsible for the start-up and operations of the AESWarrior Run facility. Mr. Convery has a Bachelor of Science degree in ChemicalEngineering from the University of Delaware.

 

**Item 11****.  ExecutiveCompensation**

 

Not Applicable.

 

**Item 12****.  Security Ownershipof Certain Beneficial Owners and Management**

 

Not Applicable.

 

**Item 13****.  CertainRelationships and Related Transactions**

 

Not Applicable.

 

**Item14****. PrincipalAccounting Fees and Services**

 

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

 

33

----

 

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

 

There were no other feespaid to the principal accountant for the years ended December 31, 2003 and2002.

 

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

 

**PART IV**

 

**Item 15****.  Exhibits, FinancialStatement Schedules and Reports on Form 8-K**

 

(a)                                  Financial Statements, FinancialStatement Schedules and Exhibits.

 

(1)                                  The following financial statementsare attached to this Annual Report on Form 10-K following the signature pageand certifications:

 

AES EASTERN ENERGY, L.P.

 

Independent Auditors’ Report

 

Financial Statements:

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

 

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

 

Independent Auditors’ Report

 

Financial Statements:

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

 

----

*                 The Consolidated Balance Sheets ofAES NY, L.L.C. contained in this Annual Report on Form 10-K should beconsidered only in connection with its status as the general partner of AESEastern Energy, L.P.

 

(2)                                  Financial Statement Schedules

 

Schedules are omitted as the information iseither not applicable, not required or has been furnished in the financialstatements 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 |

 

34

----

 
|   |   | 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*                                                                                                                                                                                |

 

35

----

 
| 4.10   |   | [Reserved]                                                                                                                                                                                                                                                                                                                                                                                     |
|--------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 4.11   |   | Registration Rights  Agreement, between AES Eastern Energy, L.P., and Morgan Stanley & Co.  Inc., Credit Suisse First Boston Corp. and CIBC World Markets Corp., dated as  of May 11, 1999*                                                                                                                                                                                                |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 4.12   |   | [Reserved]                                                                                                                                                                                                                                                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 4.13   |   | [Reserved]                                                                                                                                                                                                                                                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.1   |   | Asset Purchase  Agreement, among NGE Generation, Inc., New York State Electric & Gas  Corporation (“NYSEG”), and AES NY, L.L.C. (“AES NY”), dated as of August 3,  1998, (incorporated herein by reference to exhibit 10.2 of the Annual Report  on Form 10-K of Energy East Corp. for the year ended December 31, 1998 filed  on March 29, 1999, SEC file #001-14766) |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.2a  |   | Milliken Operating  Agreement, between AES NY and NYSEG, dated as of August 3, 1998*                                                                                                                                                                                                                                                                                                           |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.2b  |   | Amendment No. 1 to the  Milliken Operating Agreement, dated as of May 6, 1999*                                                                                                                                                                                                                                                                                                                 |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.3a  |   | Interconnection  Agreement, between AES NY and NYSEG, dated as of August 3, 1998*                                                                                                                                                                                                                                                                                                              |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.3b  |   | Amendment No. 1 to the  Interconnection Agreement, dated as of May 6, 1999*                                                                                                                                                                                                                                                                                                                    |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.4   |   | Interconnection  Implementation Agreement, between NYSEG and AES NY, dated as of May 6, 1999*                                                                                                                                                                                                                                                                                                  |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.5   |   | Standard Bilateral Power  Sales Agreement and Transaction Agreement, between AES Eastern Energy and  NYSEG Solutions, Inc., dated as of May 14, 1999*                                                                                                                                                                                                                                          |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.6   |   | Scheduling and  Settlement Agreement, among NYSEG, AES Creative Resources, L.P., AES Eastern  Energy and EME Homer City Generation, dated as of March 18, 1999*                                                                                                                                                                                                                                |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.7   |   | Agreement to Assign  Transmission Rights and Obligations, between AES NY and NYSEG, dated as of August  3, 1998*                                                                                                                                                                                                                                                                               |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.8   |   | [Reserved]                                                                                                                                                                                                                                                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.9a  |   | Reciprocal Easement  Agreement (Kintigh Station), between AES NY and NYSEG, dated as of August 3,  1998*                                                                                                                                                                                                                                                                                       |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.9b  |   | Reciprocal Easement  Agreement (Milliken Station), between AES NY and NYSEG, dated as of August 3,  1998*                                                                                                                                                                                                                                                                                      |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.9c  |   | Reciprocal Easement  Agreement (Greenidge Station), between AES NY and NYSEG, dated as of August  3, 1998*                                                                                                                                                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.9d  |   | Reciprocal Easement  Agreement (Goudey Station), between AES NY and NYSEG, dated as of August 3,  1998*                                                                                                                                                                                                                                                                                        |

 

36

----

 
| 10.10  |   | Coal Sales Agreement,  among NYSEG, Consolidation Coal Company, CONSOL Pennsylvania Coal Company,  Nineveh Coal Company, Greenon Coal Company, McElroy Coal Company and Quarto  Mining Company, dated as of November 1, 1983*                                         |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                  |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.11a |   | Coal Supply Agreement,  between NYSEG and United Eastern Coal Sales Corporation, dated as of January  12, 1998*                                                                                                                                                       |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.11b |   | Amendment No. 1 to Coal  Sales Agreement, dated as of February 20, 1998*                                                                                                                                                                                              |
|   |   |                                                                                                                                                                                                                                                                  |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.12  |   | Coal Supply Agreement,  between NYSEG and Eastern Associated Coal Corporation, dated as of July 1,  1994*                                                                                                                                                             |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.13  |   | Coal Hauling Agreement,  among Somerset Railroad Corporation, AES NY3, L.L.C., and AES Eastern Energy  L.P., dated as of May 6, 1999*                                                                                                                                 |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.14  |   | Scheduling and  Settlement Agreement, among CSX Transportation, Inc., Norfolk Southern  Corporation, Norfolk Southern Railway Company and NYSEG, dated as of February  20, 1998*                                                                                      |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.15  |   | [Reserved]                                                                                                                                                                                                                                                            |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.16  |   | Kintigh Turbine  Agreement among NGE, NYSEG and AES Eastern Energy L.P. dated April 13, 1999*                                                                                                                                                                         |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.17  |   | Omnibus Agreement,  between NYSEG and AES NY, dated as of May 7, 1999*                                                                                                                                                                                                |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.18  |   | Assignment and  Assumption Agreement, among NGE, NYSEG and AES NY, dated as of May 14, 1999*                                                                                                                                                                          |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.19  |   | Amended and Restated Deposit and Disbursement Agreement among AEE,  Union Bank of California, N.A., as Agent under the Working Capital Facility,  as Working Capital Provider, and Bankers Trust Company, as Depositary Agent,  et al., dated as of April 10, 2001.** |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.20  |   | [Reserved]                                                                                                                                                                                                                                                            |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.21a |   | Omnibus Amendment to  Kintigh A-1 Transaction Documents dated as of December 1, 2000                                                                                                                                                                                  |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.21b |   | Schedule identifying  substantially identical agreements to Omnibus Agreement constituting Exhibit  10.21a hereto                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.22a |   | Omnibus Amendment to  Milliken A-1 Transaction Documents dated as of December 1, 2000                                                                                                                                                                                 |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.22b |   | Schedule identifying  substantially identical agreements to Omnibus Agreement constituting Exhibit  10.22a hereto                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.23a |   | Agreement and Appendix A dated as of April 10, 2001**                                                                                                                                                                                                                 |
|   |   |                                                                                                                                                                                                                                                                  |
| 10.23b |   | Schedule identifying substantially identical agreements to Second  Amendment constituting Exhibit 10.23a hereto**                                                                                                                                                     |

 

37

----

 
| 10.24a |   | Second Amendment to Milliken A-1 Participation Agreement and Appendix  A dated as of April 10, 2001**                                                                                                                                                                                                                                                                                                                    |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 10.24b |   | Schedule identifying substantially identical agreements to Second  Amendment constituting Exhibit 10.24a hereto**                                                                                                                                                                                                                                                                                                        |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 10.25a |   | $35,000,000 Credit Agreement dated as of April 10, 2001 among AEE and  Union Bank of California, N.A., as Agent**                                                                                                                                                                                                                                                                                                        |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 10.25b |   | Amendment No. 1 and Waiver dated as of August 31, 2001 to $35,000,000  Credit Agreement dated as of April 10, 2001 among AEE and Union Bank of  California, N.A., as Agent**                                                                                                                                                                                                                                             |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 10.25c |   | Amendment No.2 to Credit Agreement dated as of November 20, 2002 to  Credit agreement dated as of April 10, 2001 among AEE and Union Bank of  California, N.A., as Agent, as amended (incorporated herein by reference to  Exhibit 25c to the Annual Report of AES Eastern Energy, L.P.(Reg. No.  333-89725)for the year ended December 31, 2002, filed with the Securities and  Exchange Commission on March 28, 2003). |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 10.25d |   | Amendment No.3 to Credit Agreement dated as of April 16, 2003 to  Credit agreement dated as of April 10, 2001 among AEE and Union Bank of  California, N.A., as Agent, as amended***                                                                                                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 10.25e |   | Amendment No.4 to Credit Agreement dated as of April 16, 2003 to  Credit agreement dated as of April 10, 2001 among AEE and Union Bank of  California, N.A., as Agent, as amended***                                                                                                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 10.25f |   | Accession and Admendment  dated April 25, 2003 to Credit Agreement dated as of April 10,  2001 among AEE and Union Bank of California, N.A., as Agent as Amended***                                                                                                                                                                                                                                                      |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 12.1   |   | Statement regarding  ratio of earnings to fixed charges                                                                                                                                                                                                                                                                                                                                                                  |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 21.1   |   | Subsidiaries Schedule*                                                                                                                                                                                                                                                                                                                                                                                                   |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 24.1   |   | Power of Attorney                                                                                                                                                                                                                                                                                                                                                                                                        |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 31.1   |   | Certification by Chief  Executive Officer Required by Rule 13a-14(a) or 15d-14(a) of the Securities  Exchange Act of 1934.                                                                                                                                                                                                                                                                                               |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 31.2   |   | Certification by Chief  Financial Officer Required by Rule 13a-14(a) or 15d-14(a) of the Securities  Exchange Act of 1934.                                                                                                                                                                                                                                                                                               |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 32     |   | Certification Required  by Rule 13a-14(b) or 15d-14(b) of the Securities Exchange Act of 1934.                                                                                                                                                                                                                                                                                                                           |

 

----

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

 

**                                                                                  Incorporatedherein by reference to similarly numbered exhibit to the

 

38

----

 

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

 

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

 

(b)                                 Reports on Form 8-K.

 

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

 

39

----

 

**SIGNATURES**

 

Pursuant to the requirements of Section 13 or15(d) of the Securities Exchange Act of 1934, as amended, AES Eastern Energy,L.P. has duly caused this report to be signed on its behalf by the undersigned,thereunto duly authorized.

 

Date:  March 16, 2004

 
|   | AES EASTERN ENERGY, L.P.                |
|--------|-----------------------------------------|
|   | By:  AES NY, L.L.C., as General Partner |
|   |                                    |
|   | By:                                     | /s/ Dan Rothaupt |   |
|   |                                    | Dan Rothaupt |
|   |                                    | President |

 

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

 
| **Signature**      |   | **Title**                                        |   | **Date**       |   |
|--------------------|--------|--------------------------------------------------|--------|----------------|--------|
|               |   |                                             |   |           |   |
| /s/ Dan Rothaupt   |   | President (chief  executive officer)             |   | March 16, 2004 |   |
| Dan Rothaupt       |   | and Class A Director of  AES NY, L.L.C.          |   |           |   |
|               |   |                                             |   |           |   |
| /s/ Kevin Pierce   |   | Class A Director of AES  NY, L.L.C.              |   | March 16, 2004 |   |
| Kevin Pierce       |   |                                             |   |           |   |
|               |   |                                             |   |           |   |
| /s/ Edward Convery |   | Class A Director of AES  NY, L.L.C.              |   | March 16, 2004 |   |
| Edward Convery     |   |                                             |   |           |   |
|               |   |                                             |   |           |   |
| /s/ Amy Conley     |   | Vice President and  Treasurer                    |   | March 16, 2004 |   |
| Amy Conley         |   | (principal financial  officer) of AES NY, L.L.C. |   |           |   |

 

40

----

 

**Index to Financial Statements**

 

AES EASTERN ENERGY, L.P.

 
| Independent Auditors’ Report                              |   |
|----------------------------------------------------------------|--------|
|                                                           |   |
| Financial Statements:                                          |   |
|                                                           |   |
| Consolidated Balance Sheets                                    |   |
|                                                           |   |
| Consolidated Statements of Income                              |   |
|                                                           |   |
| Consolidated Statements of Changes in  Partners’ Capital  |   |
|                                                           |   |
| Consolidated Statements of Cash Flows                          |   |
|                                                           |   |
| Notes to Consolidated Financial Statements                     |   |
|                                                           |   |
| AES NY, L.L.C. (General  Partner of AES Eastern Energy, L.P.)* |   |
|                                                           |   |
| Independent Auditors’ Report                              |   |
|                                                           |   |
| Financial Statements:                                          |   |
|                                                           |   |
| Consolidated Balance Sheets                                    |   |
|                                                           |   |
| Notes to Consolidated Balance Sheets                           |   |

 

----

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

 

41

----

 

INDEPENDENT AUDITORS’ REPORT

 

To the Partners of

AES Eastern Energy, L.P.

 

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

 

We conducted our audits inaccordance with auditing standards generally accepted in the United States ofAmerica. Those standards require that we plan and perform our audits to obtainreasonable assurance about whether the financial statements are free ofmaterial misstatement. An audit includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements. An auditalso includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financialstatement presentation. We believe that our audits provide a reasonable basisfor our opinion.

 

In our opinion, suchconsolidated financial statements present fairly, in all material respects, thefinancial position of AES Eastern Energy, L.P., and subsidiaries as of December31, 2003 and 2002, and the results of their operations and their cash flows forthe years ended December 31, 2003, 2002 and 2001, in conformity with accountingprinciples generally accepted in the United States of America.

 

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

 
| /s/Deloitte & Touche  LLP |   |
|-------------------------------|--------|

 

 

McLean, Virginia

February 26, 2004

 

42

----

 

**AES EASTERN ENERGY, L.P.**

**CONSOLIDATED BALANCE SHEETS,**

**DECEMBER 31, 2003 and DECEMBER 31, 2002**

*** ***

***(Amounts in Thousands*****)**

 
| **December 31,**                                                                      |   | **2003** |      | **2002** |   |
|---------------------------------------------------------------------------------------|--------|----------|-----------|----------|--------|
| **ASSETS**                                                                            |   |     |      |     |   |
| Current  Assets:                                                                      |   |     |      |     |   |
| Restricted  cash:                                                                     |   |     |      |     |   |
| Operating  - cash and cash equivalents                                                |   | $        | 2,540     |     | $      | 4,605 |   |
| Revenue  account                                                                      |   | 85,231   |      | 76,566   |   |
| Accounts  receivable - trade                                                          |   | 34,883   |      | 35,233   |   |
| Accounts  receivable - affiliates                                                     |   | 203      |      | —   |   |
| Accounts  receivable - other                                                          |   | 1,264    |      | 1,235    |   |
| Inventory                                                                             |   | 27,700   |      | 26,982   |   |
| Prepaid  expenses                                                                     |   | 8,019    |      | 7,617    |   |
| Total current assets                                                                  |   | 159,840  |      | 152,238  |   |
| PROPERTY,  PLANT, EQUIPMENT, AND RELATED ASSETS:                                      |   |     |      |     |   |
| Land                                                                                  |   | 7,054    |      | 7,011    |   |
| Electric  generation assets -net of accumulated depreciation of $156,259 and $117,222 |   | 902,662  |      | 929,654  |   |
| Total  property, plant, equipment and related assets                                  |   | 909,716  |      | 936,665  |   |
| OTHER  ASSETS:                                                                        |   |     |      |     |   |
| Deferred  financing -net of accumulated amortization of $328 and $863                 |   | 303      |      | 293      |   |
| Derivative  valuation                                                                 |   | 16,143   |      | 2,510    |   |
| Transmission  congestion contract                                                     |   | —   |      | 2,416    |   |
| Rent  reserve account                                                                 |   | 31,717   |      | 31,717   |   |
| TOTAL  ASSETS                                                                         |   | $        | 1,117,719 |     | $      | 1,125,839 |   |
|                                                                                  |   |     |      |     |   |
| LIABILITIES AND PARTNERS’ CAPITAL                                                |   |     |      |     |   |
|                                                                                  |   |     |      |     |   |
| CURRENT  LIABILITIES:                                                                 |   |     |      |     |   |
| Accounts  payable                                                                     |   | $        | 830       |     | $      | 1,195 |   |
| Lease  financing – current                                                       |   | 7,846    |      | 1,665    |   |
| Environmental  remediation                                                            |   | —   |      | 20       |   |
| Accrued  interest expense                                                             |   | 28,004   |      | 28,078   |   |
| Due  to The AES Corporation and affiliates                                            |   | 8,930    |      | 6,945    |   |
| Accrued  coal and rail expense                                                        |   | 6,456    |      | 8,492    |   |
| Other  accrued expenses and liabilities                                               |   | 9,971    |      | 9,311    |   |
| Total  current liabilities                                                            |   | 62,037   |      | 55,706   |   |
|                                                                                  |   |     |      |     |   |
| LONG-TERM  LIABILITIES:                                                               |   |     |      |     |   |
| Lease  financing - long term                                                          |   | 629,815  |      | 637,660  |   |
| Environmental  remediation                                                            |   | 5,051    |      | 9,192    |   |
| Defined  benefit plan obligation                                                      |   | 16,558   |      | 17,439   |   |
| Derivative  valuation liability                                                       |   | 43,624   |      | 20,996   |   |
| Asset  retirement obligation                                                          |   | 9,900    |      | —   |   |
| Transmission  congestion contract                                                     |   | 359      |      | —   |   |
| Other  liabilities                                                                    |   | 2,688    |      | 2,600    |   |
| Total  long-term liabilities                                                          |   | 707,995  |      | 687,887  |   |
| TOTAL  LIABILITIES                                                                    |   | 770,032  |      | 743,593  |   |
|                                                                                  |   |     |      |     |   |
| COMMITMENTS  AND CONTINGENCIES (Note 7)                                               |   |     |      |     |   |
|                                                                                  |   |     |      |     |   |
| PARTNERS’  CAPITAL                                                               |   | 347,687  |      | 382,246  |   |
| TOTAL  LIABILITIES AND PARTNERS’ CAPITAL                                         |   | $        | 1,117,719 |     | $      | 1,125,839 |   |

 

The notes are an integralpart of the consolidated financial statements

 

43

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**AES EASTERN ENERGY, L.P.**

**CONSOLIDATED STATEMENTS OF INCOME**

**YEARSENDED DECEMBER 31, 2003, 2002 AND 2001**

*** ***

***(Amounts in Thousands*****)**

 
| **Year ended December 31,**                                            |   | **2003** |    | **2002** |   | **2001** |   |
|------------------------------------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
| OPERATING  REVENUES:                                                   |   |     |    |     |   |     |   |
| Energy                                                                 |   | $        | 388,913 |     | $      | 310,616  |   | $ | 345,410 |   |
| Capacity                                                               |   | 29,653   |    | 36,644   |   | 26,767   |   |
| Transmission  congestion contract                                      |   | —   |    | 8,875    |   | —   |   |
| Other                                                                  |   | 2,150    |    | 6,879    |   | 6,171    |   |
|                                                                   |   |     |    |     |   |     |   |
| Total  revenues                                                        |   | 420,716  |    | 363,014  |   | 378,348  |   |
| OPERATING  EXPENSES:                                                   |   |     |    |     |   |     |   |
| Fuel                                                                   |   | 148,339  |    | 137,175  |   | 135,562  |   |
| Depreciation  and amortization                                         |   | 36,076   |    | 35,538   |   | 33,542   |   |
| Operating  and maintenance                                             |   | 23,267   |    | 16,954   |   | 19,572   |   |
| General  and administrative                                            |   | 59,194   |    | 59,112   |   | 53,712   |   |
| Transmission  congestion contract                                      |   | 6,226    |    | —   |   | 29,494   |   |
| Derivative  valuation                                                  |   | (193     | )       | 27       |   | 27       |   |
|                                                                   |   |     |    |     |   |     |   |
| Total  operating expenses                                              |   | 272,909  |    | 248,806  |   | 271,909  |   |
|                                                                   |   |     |    |     |   |     |   |
| OPERATING  INCOME                                                      |   | 147,807  |    | 114,208  |   | 106,439  |   |
|                                                                   |   |     |    |     |   |     |   |
| OTHER  INCOME (EXPENSE):                                               |   |     |    |     |   |     |   |
| Interest  expense                                                      |   | (59,144  | )       | (57,694  | )      | (58,434  | )      |
| Interest  income                                                       |   | 2,059    |    | 2,116    |   | 3,860    |   |
|                                                                   |   |     |    |     |   |     |   |
| Total  other expense                                                   |   | (57,085  | )       | (55,578  | )      | (54,574  | )      |
| Net  income before cumulative effect of change in accounting principle |   | 90,722   |    | 58,630   |   | 51,865   |   |
|                                                                   |   |     |    |     |   |     |   |
| Cumulative  effect of change in accounting principle                   |   | (1,656   | )       | —   |   | —   |   |
|                                                                   |   |     |    |     |   |     |   |
| NET  INCOME                                                            |   | $        | 89,066  |     | $      | 58,630   |   | $ | 51,865 |   |

 

The notes are an integralpart of the consolidated financial statements

 

44

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**AES EASTERN ENERGY, L.P.**

**CONSOLIDATED STATEMENTS OF CHANGES INPARTNERS’ CAPITAL**

## **YEARS ENDED DECEMBER 31, 2003, 2002 AND, 2001**

 

**(*Amountsin Thousands)***

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

 

The notes are an integralpart of the consolidated financial statements.

 

45

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**AES EASTERN ENERGY, L.P.**

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

**YEARSENDED DECEMBER 31, 2003, 2002 AND 2001**

 

*(Amounts in Thousands)*

 
| **Year ended December 31,**                                                    |   | **2003** |   | **2002** |   | **2001** |   |
|--------------------------------------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| CASH  FLOWS FROM OPERATING ACTIVITIES:                                         |   |     |   |     |   |     |   |
| Net  income                                                                    |   | $        | 89,066 |     | $      | 58,630   |   | $ | 51,865 |   |
| Adjustments  to reconcile net income to Net cash used in operating activities: |   |     |   |     |   |     |   |
| Cumulative  effect of change in accounting principle                           |   | 1,656    |   | —   |   | —   |   |
| Asset  obligation accretion                                                    |   | 689      |   | —   |   | —   |   |
| Depreciation  and amortization                                                 |   | 36,076   |   | 35,521   |   | 33,542   |   |
| Realized  loss(gain) on derivative                                             |   | 2,583    |   | (5,895   | )      | 28,385   |   |
| Write  off of deferred financing                                               |   | 21       |   | —   |   | —   |   |
| Net  defined benefit plan cost                                                 |   | (881     | )      | 471      |   | (1,813   | )      |
| Changes  in current assets and liabilities:                                    |   |     |   |     |   |     |   |
| Accounts  receivable                                                           |   | 118      |   | (6,436   | )      | 6,508    |   |
| Inventory                                                                      |   | (718     | )      | 2,633    |   | (6,307   | )      |
| Prepaid  expenses                                                              |   | (402     | )      | (1,153   | )      | (312     | )      |
| Accounts  payable                                                              |   | (365     | )      | (468     | )      | 231      |   |
| Accrued  interest expense                                                      |   | (74      | )      | (275     | )      | (1,119   | )      |
| Due  to AES Corporation and affiliates                                         |   | 1,985    |   | 531      |   | (2,190   | )      |
| Other  liabilities                                                             |   | (1,296   | )      | (2,065   | )      | (6,372   | )      |
|                                                                           |   |     |   |     |   |     |   |
| Net  cash provided by operating activities                                     |   | 128,458  |   | 81,494   |   | 102,418  |   |
|                                                                           |   |     |   |     |   |     |   |
| CASH  FLOWS FROM INVESTING ACTIVITIES:                                         |   |     |   |     |   |     |   |
| Payments  for capital additions                                                |   | (5,421   | )      | (7,136   | )      | (17,148  | )      |
| Decrease(increase)  in restricted cash                                         |   | (6,600   | )      | (5,372   | )      | 7,266    |   |
| Net  change in rent reserve account                                            |   | —   |   | 2        |   | (741     | )      |
|                                                                           |   |     |   |     |   |     |   |
| Net  cash used in investing activities                                         |   | (12,021  | )      | (12,506  | )      | (10,623  | )      |
|                                                                           |   |     |   |     |   |     |   |
| CASH  FLOWS FROM FINANCING ACTIVITIES:                                         |   |     |   |     |   |     |   |
| Dividends  paid                                                                |   | (114,600 | )      | (63,960  | )      | (98,200  | )      |
| Payments  for deferred financing                                               |   | (335     | )      | (317     | )      | (1,154   | )      |
| Principal  payments on lease obligations                                       |   | (1,664   | )      | (6,224   | )      | (1,813   | )      |
| Partner’s  contribution                                                   |   | 162      |   | 1,513    |   | 9,372    |   |
|                                                                           |   |     |   |     |   |     |   |
| Net  cash used in financing activities                                         |   | (116,437 | )      | (68,988  | )      | (91,795  | )      |
|                                                                           |   |     |   |     |   |     |   |
| CHANGE  IN CASH AND CASH EQUIVALENTS                                           |   | —   |   | —   |   | —   |   |
| CASH  AND CASH EQUIVALENTS, BEGINNING OF PERIOD                                |   | —   |   | —   |   | —   |   |
|                                                                           |   |     |   |     |   |     |   |
| CASH  AND CASH EQUIVALENTS, END OF PERIOD                                      |   | $        | — |     | $      | —   |   | $ | — |   |
|                                                                           |   |     |   |     |   |     |   |
| Supplemental  Disclosure of Cash Flow Information:                             |   |     |   |     |   |     |   |
|                                                                           |   |     |   |     |   |     |   |
| Interest  paid                                                                 |   | $        | 55,885 |     | $      | 56,354   |   | $ | 56,610 |   |
|                                                                           |   |     |   |     |   |     |   |
| Supplemental  Disclosure of Non-cash Flow Information:                         |   |     |   |     |   |     |   |
|                                                                           |   |     |   |     |   |     |   |
| Adoption  of SFAS No. 143                                                      |   | $        | 3,396  |     | $      | —   |   | $ | — |   |

 

The notes are an integralpart of the consolidated financial statements.

 

46

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**AES EASTERN ENERGY, L.P.**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTSYEARS ENDED DECEMBER 31, 2003, 2002 AND 2001**

 

1.                             GENERAL

 

AES Eastern Energy, L.P.(the Partnership), a Delaware limited partnership, was formed on December 2,1998. The Partnership’s wholly owned subsidiaries are AES Somerset, L.L.C., AESCayuga, L.L.C., and AEE2, L.L.C., (which wholly owns AES Westover, L.L.C. andAES 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 anindirect wholly owned subsidiary of The AES Corporation (AES).

 

The Partnership wasestablished for the purpose of owning or leasing and operating four coal-firedelectric generating stations (the Plants) with a total combined capacity of1,268 MW. The partners of the Partnership are comprised of AES NY, L.L.C. (theGeneral Partner) and AES NY2, L.L.C. (the Limited Partner), both of which areindirect wholly owned subsidiaries of AES. The Plants are owned or leased bythe Partnership (see Note 3 and Note 6) and are operated by the Partnership’swholly owned subsidiaries in the State of New York, pursuant to operation andmaintenance agreements with the Partnership.

 

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

 

In November 2000, thePartnership entered into a three-year agreement for energy marketing serviceswith AES Odyssey, L.L.C.(Odyssey), a direct wholly owned subsidiary of AES. InMarch 2002, a new agreement was reached, for a term of five years throughFebruary 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 amendmentto its March 2002 agreement. Odyssey will also manage the Partnership’s coaland environmental emission credit positions for an additional fee of $100,000per month. Odyssey acts as agent on behalf of the Partnership in theover-the-counter and NYISO markets.(see Note 8).

 

2.                             SIGNIFICANT ACCOUNTING POLICIES

 

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

 

Restricted Cash - Underthe terms of the deposit and disbursement agreement entered into in connectionwith the lease of two Plants (see Note 6), all revenues of the Partnership andits subsidiaries are deposited into a revenue account administered by DeutscheBank (formerly Bankers Trust Company), as depositary agent. On request of thePartnership and in accordance with the terms of the deposit and disbursementagreement, funds are transferred from the revenue account to other operatingaccounts administered by the depositary agent for payment of operating andmaintenance costs, lease obligations, debt service, reserve requirements, anddistributions. Payment of operating and maintenance costs (other than actualfuel costs) in excess of 125% of the annual operating budget is not permittedunder the terms of the lease documents. Amendments, modifications orreallocations of the annual operating budget that result in changes of 25%(positive or negative) in the amounts set forth in the annual operating budgetrequire confirmation from an independent engineer that such payment is based onreasonable assumptions.

 

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

 

Inventory, as of December31 consisted of the following (in thousands):

 
|                                  |   | **2003** |   | **2002** |   |
|---------------------------------------|--------|----------|--------|----------|--------|
| Coal  and other raw materials         |   | $        | 12,329 |     | $      | 11,342 |   |
| Spare  parts, materials, and supplies |   | 15,371   |   | 15,640   |   |
|                                  |   |     |   |     |   |
| Total                                 |   | $        | 27,700 |     | $      | 26,982 |   |

 

47

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The coal inventory for theyear ending December 31, 2002, included $3.3 million of coal which was underspecial terms in which title had not transferred as of December 31, 2002 fromone of the Partnership’s existing suppliers.

 

Property, Plant,Equipment, and Related Assets - Electric generation assets that existed at thedate of acquisition (see Note 3) are recorded at fair market value. TheSomerset (formerly known as Kintigh) and Cayuga (formerly known as Milliken)Plants, which represent $650 million of the electric generation assets, aresubject to a leasing arrangement accounted for as a financing (see Note 6).Additions or improvements thereafter are recorded at cost. Depreciation iscomputed using the straight-line method over the 34-year and 28.5-year leaseterms for the Somerset and Cayuga Plants, respectively, and over the estimateduseful lives for the other fixed assets, which range from 7 to 35 years.Maintenance and repairs are charged to expense as incurred.

 

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

 
|                                       |   | **2003** |      | **2002** |   |
|--------------------------------------------|--------|----------|-----------|----------|--------|
| Electric  generation assets                |   | $        | 1,058,921 |     | $      | 1,046,876 |   |
| Accumulated  depreciation and amortization |   | (156,259 | )         | (117,222 | )      |
|                                       |   |     |      |     |   |
| Total                                      |   | $        | 902,662   |     | $      | 929,654 |   |

 

Rent Reserve Account - Aspart of the Partnership’s lease obligation (see Note 6), the Partnership isrequired to maintain a rent reserve account equal to the maximum semiannualpayment 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 inthe immediately succeeding three-year period. As of December 31, 2003 and 2002,the Partnership had fulfilled this obligation by entering into a PaymentUndertaking Agreement, dated as of May 1, 1999, among the Partnership, eachOwner Trust (see Note 3) and Morgan Guaranty Trust Company of New York (thePayment Undertaking Agreement). On May 14, 1999, the Partnership deposited withMorgan Guaranty Trust Company of New York approximately $28.7 million pursuantto the Payment Undertaking Agreement. The accreted value of the PaymentUndertaking Agreement at any time includes interest earned thereunder at aninterest rate of 4.79% per annum. Interest earnings as of December 31, 2003,2002, and 2001 were approximately $1.5 million for each year, respectively, andare included in the rent reserve account balance. At December 31, 2003 and2002, the accreted value of the Payment Undertaking Agreement exceeded therequired balance of the rent reserve account. This amount is being accountedfor as a restricted cash balance and is included within the rent reserveaccount on the accompanying balance sheets, as it can only be utilized tosatisfy lease obligations. In the future, the Partnership may fulfill itsobligation to maintain the required balance of the rent reserve account eitherby deposits into the rent reserve account or by making amounts available underthe Payment Undertaking Agreement, such that the aggregate amount of suchdeposits in the rent reserve account and amounts available to be paid under thePayment Undertaking Agreement are equal to the required balance of the rentreserve account.

 

New York TransitionAgreement - As the NYISO system represents a deregulated environment, the NYISOattempts to ensure stability of the power grid in New York by requiring eachentity engaged in retail sales of electricity to obtain unforced capacity(referred to as installed capacity prior to the winter of 2001 – 2002)commitments from generators in an amount equal to the entity’s forecasted peakload plus a reserve margin. This requirement is intended to ensure that anadequate supply of electricity is always available. In 1999, the GeneralPartner entered into a two-year transition agreement with New York StateElectric & Gas Corporation (NYSEG) pursuant to which the Partnership soldits installed capacity to NYSEG in order to permit NYSEG to comply with NYISOstandards for system stability. The transition agreement was assumed by thePartnership on the date of acquisition of the Plants. The Partnershiprecognized revenue under this contract as it was earned, which was $68 per MWper day for installed capacity made available. This agreement expired on April30, 2001.

 

Income Taxes - A provisionfor Federal and state income taxes has not been made in the accompanyingfinancial statements since the Partnership does not pay income taxes but ratherallocates its revenues and expenses to the individual partners.

 

Use of Estimates - Thepreparation of financial statements in conformity with accounting principlesgenerally accepted in the United States of America requires the Partnership tomake estimates and assumptions that affect reported amounts of assets andliabilities and disclosures of contingent assets and liabilities at the date ofthe financial statements, as well as the reported amounts of revenues andexpenses during the reporting period. Actual results could differ from thoseestimates.  

 

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

 

48

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ThePartnership adopted SFAS No. 133, “Accounting for Derivative Instruments andHedging Activities”, which, as amended, established new accounting andreporting standards for derivative instruments and hedging activities. TheStatement requires that the Partnership recognize all derivatives, as defined inthe Statement, on the balance sheet at fair value. Derivatives that areeffective cash flow hedges are recognized in other comprehensive income (loss)until the hedged items are recognized in earnings. Derivatives, or any portionthereof, that are not effective cash flow hedges are adjusted to fair valuethrough income. As of December 31, 2003, the Partnership has recorded $27.6million of other comprehensive loss due to hedging activities.

 

The Partnership utilizes derivative financial instruments to hedgecommodity price risk. The Partnership utilizes electric derivative instruments,including swaps and forwards, to hedge the risk related to forecastedelectricity sales over the next two years. The majority of the Partnership’selectric derivatives are designated and qualify as cash flow hedges. ThePartnership haschosen to use the hypothetical derivative methodology for testing whether itshedges meet the criteriato qualify for cash flow hedge accounting treatment. A historical regression isperformed between theelectricity generating stations' delivery points into the NYISO and the NYISOzones in which thehedges are settled. Comparing the results of the historical regression and theactual changes in themarket value of the hedges determines if the hedges qualify for cash flow hedge accounting criteria treatment.  No hedges were derecognized or discontinuedand no significant amounts of hedge ineffectiveness were recognized in earningsduring the years ended December 31, 2003, 2002 and 2001, respectively.

 

Approximately $18.7 million of other comprehensive income is expectedto be recognized as a reduction to earnings over the next twelve months.Amounts recorded in Other Comprehensive Income during the year ended December31, 2003, were as follows (in millions):

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

 

 

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

 

Revenue Recognition -Revenues from the sale of electricity are recorded based upon output deliveredand rates specified under contract terms. Gains and losses, generated from thehedging of future sales using commodity forwards, swaps and options, reportedin other comprehensive income, are reclassified to earnings in the periods inwhich earnings are impacted by the variability of the cash flows of the hedgeditem. The ineffective portions of the change in fair value of derivatives andthe change in the fair value of derivatives not designated as hedges foraccounting purposes are recognized in current period earnings. Revenues forancillary and other services are recorded when the services are rendered.

 

In June 2001, the Financial Accounting Standards Board (FASB) issuedSFAS No. 142, “Goodwill and Other Intangible Assets”. This standard eliminatesthe amortization of goodwill, and requires goodwill to be reviewed periodicallyfor impairment.  This standard alsorequires the useful lives of previously recognized assets to be adjustedaccordingly. This standard is effective for fiscal years beginning afterDecember 15, 2001, for all goodwill and other intangible assets recognized onthe Partnership’s balance sheet at that date, regardless of when the assetswere initially recognized. The initial adoption of SFAS No. 142 did not have asignificant impact on the Partnership’s financial position and results ofoperations.

 

In June 2001, the FASB issued SFAS No. 143, “Accounting for AssetRetirement Obligations”. SFAS No. 143, which became effectiveJanuary 1, 2003, requires entities to record the fair value of a legalliability for an asset retirement obligation in the period in which it isincurred.  The new liability wasrecorded in the first quarter of 2003. The Partnership capitalized the costs ofthe liability by increasing the carrying amount of the related long-livedasset. The liability is accreted to its present value each period, and thecapitalized cost is depreciated over the useful life of the related asset.  Upon settlement of the liability, thePartnership will settle the obligation for its recorded amount or incur a gainor loss upon settlement. The Partnership adopted SFAS No. 143 effectiveJanuary 1, 2003.

 

The Partnership has completed a detailed assessment of the specificapplicability and implications of SFAS No. 143.  The scope of SFAS No. 143 as it applies to the Partnership,includes primarily active ash landfills and water treatment basins. Uponadoption of SFAS No. 143, the Partnership recorded a liability ofapproximately $9.2 million and a net asset of approximately $3.3 million,which are included in the electric generation assets, and reversed a $4.2million environmental remediation liability it had previously recorded (seeNote 3). The difference between the amounts previously recorded and the netSFAS No. 143 liability is a loss recorded as the cumulative effect of a changein accounting principle of $1.7 million. Reconciliation of the asset retirementobligation liability for the year ended December 31, 2003 was as follows (inmillions):

 

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

 

In December 2002, the FASB issued SFAS No. 148, “Accounting forStock-Based Compensation – Transition and Disclosure.” SFAS No. 148 amendsSFAS No. 123, “Accounting for Stock-Based Compensation” to provide alternativemethods of transition for a voluntary change to the fair value based method ofaccounting for stock-based employee compensation. In addition, this Statementamends the disclosure requirements of SFAS No. 123 to require prominentdisclosures in both annual and interim financial statements about the method ofaccounting for stock-based employee compensation and the effect of the methodused on reported results. The Partnership expects to use the prospectivemethod to transition to the fair value based method of accounting forstock-based employee compensation. All employee awards granted, modified,or settled after January 1, 2003, will be recorded using the fair value basedmethod of accounting (See Note 10). The Partnership’s adoption of theprospective method of accounting for stock-based employee compensation did nothave any material impact on its financial position or results of operations.

 

On April 30, 2003, the FASB issued SFAS No. 149, “Amendment ofStatement 133 on Derivative Instruments and Hedging Activities”. SFAS No. 149amends and clarifies financial accounting and reporting for derivativeinstruments and for hedging activities under SFAS No. 133. The amendmentreflects decisions made by FASB and the Derivatives Implementation Group (DIG)in connection with issues raised about the application of SFAS No. 133.Generally, the provisions of SFAS No. 149 will be applied prospectively forcontracts entered into or modified after June 30, 2003 and for hedgingrelationships designated after June 30, 2003. SFAS No. 149 provisions thatresulted from the DIG process that became effective in quarters beginningbefore June 15, 2003 will continue to be applied based upon their originaleffective dates. The adoption of SFAS No. 149 did not have a material impact onthe Partnership’s financial position or results of operations.

 

The Partnership adopted the disclosureprovisions of FASB Interpretation No. (FIN) 45, “Guarantor’sAccounting and Disclosure Requirements forGuarantees, Including Direct Guarantees of Indebtednessof Others,” in the fourth Quarter of 2002. ThePartnership will apply the initial recognition andmeasurement provisions on a prospective basis forall guarantees issued after December 31, 2002. Ingeneral, the Partnership enters into variousagreements providing financial performance assuranceto third parties on behalf of certainsubsidiaries. Such agreements include guarantees, letters ofcredit and surety bonds. FIN 45 does not encompassguarantees issued either between parents and their subsidiaries orbetween corporations under common control, a parent’s guarantee of itssubsidiary’s debt to a third party (whether the parent is a corporation or anindividual), a subsidiary’s guarantee of the debt owed to a third party byeither its parent or another subsidiary of that parent, nor guarantees of acompany’s own future performance. Adoptionof FIN45 had no impact on thePartnership’s historical financial statements, as existing guarantees arenot subject to the measurement provisions ofFIN 45. The adoption of the liability recognition provisions of FIN 45did not have a material impact on the Partnership’s financial position orresults of operations.

 

InJanuary 2003, (the FASB) issued Interpretation No. 46,  “Consolidation of Variable InterestEntities” which provides guidance on how to identify a variable interest entity(VIE), and when the assets, liabilities, noncontrolling interests and resultsof operations of a VIE need to be included in a company’s consolidatedfinancial statements. This interpretation was revised in December 2003 with theissuance of Interpretation No. 46(R), “Consolidation of Variable InterestEntities” (FIN 46(R)).

 

Ingeneral, a VIE is an entity that lacks sufficient equity or its equity holderslack adequate decision making ability. If either of these characteristics ispresent, the entity is subject to a variable interests consolidation model, andconsolidation is based on variable interests, not on ownership of the entity’soutstanding voting stock. Variable interests are defined as contractual,ownership, or other money interests in an entity that change with fluctuationsin the entity’s net asset value. The primary beneficiary consolidates the VIE;the primary beneficiary is defined as the enterprise that absorbs a majority ofexpected losses or receives a majority of residual returns (if the losses orreturns occur), or both.

 

The sales – leaseback transaction under which Somerset and Cayuga wereacquired qualifies as a VIE. The sales – leaseback rules require that theleases be treated as financing leases for purposes of the Partnership'sfinancial statements, which they have been from the Partnership's inception.The Partnership is considering the applicability of consolidating SomersetRailroad Corporation. If it does so the Partnership’s consolidated BalanceSheet as of December 31, 2003 would reflect additional assets of approximately$28.4 million and liabilities of approximately $19.6 million.

 

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

 

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

 

Reclassifications - Certain prior year and prior period amounts havebeen reclassified on the consolidated financial statements to conform with the2003 presentation.

 

3.                             ACQUISITION

 

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

 

The acquisition wasfinanced by capital contributions from the General Partner and the LimitedPartner in an aggregate amount equal to the purchase price for the Plants,certain associated costs and expenses, and certain amounts for working capitalless the net proceeds from the leasing transactions with respect to theSomerset and Cayuga Plants described above. The acquisition has been accountedfor as an asset purchase.

 

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

 

4.                             PARTNERSHIP AGREEMENT

 

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

 

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

 

5.                             CAPITALIZATION

 

The Partnership isindirectly owned by AES New York Funding, L.L.C. (AES Funding), which is aspecial purpose financing vehicle established to raise a portion of the capitalcontributed to

 

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the Partnership throughthe General Partner and the Limited Partner. AES Funding is a direct whollyowned subsidiary of AES.

 

On May 11, 1999, AESFunding entered into a three-year loan agreement with a syndicate of banks,with Morgan Guaranty Trust Company of New York as Agent, in the amount of $300million. AES Funding contributed 1% of this amount to the General Partner and99% of this amount to the Limited Partner which, in turn, made an aggregatecapital contribution of $300 million to the Partnership. AES also contributedcapital in the amount of approximately $54 million through AES Funding, whichsubsequently contributed this amount to the General Partner and the LimitedPartner which, in turn, made a capital contribution of approximately $54million to the Partnership.

 

On November 30, 2001, AESFunding entered into a thirty-nine month loan agreement with asyndicate 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 underthe Loan Agreement dated May 11, 1999. Collateral for the loan includes apledge of AES common stock.

 

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

 

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

 

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

 

6.                             LEASE FINANCING

 

The Partnership’s leasesfor the Somerset and Cayuga Plants are accounted for as a financing (see Note3). Minimum lease payments and the present value of the lease obligations areas follows (in thousands):

 

 
| **Fiscal Years ending  December 31,**    |   | **Principal  Portion** |   | **Interest  Imputed** |   | **Lease  Payments** |    |
|------------------------------------------|--------|------------------------|--------|-----------------------|--------|---------------------|---------|
|                                     |   |                   |   |                  |   |                |    |
| 2004                                     |   | $                      | 7,846  |                  | $      | 55,604              |    | $ | 63,450 |   |
| 2005                                     |   | 4,411                  |   | 55,039                |   | 59,450              |    |
| 2006                                     |   | 6,898                  |   | 54,652                |   | 61,550              |    |
| 2007                                     |   | 8,495                  |   | 54,005                |   | 62,500              |    |
| 2008                                     |   | 9,256                  |   | 53,244                |   | 62,500              |    |
| Thereafter                               |   | 600,755                |   | 588,911               |   | 1,189,666           |    |
| Total  minimum lease payments            |   | 637,661                |   | 861,455               |   | 1,499,116           |    |
|                                     |   |                   |   |                  |   |                |    |
| Less  imputed interest                   |   |                   |   |                  |   | (861,455            | )       |
|                                     |   |                   |   |                  |   |                |    |
| Present  value of minimum lease payments |   |                   |   |                  |   | $                   | 637,661 |   |
|                                     |   |                   |   |                  |   |                |    |
| Less  current portion                    |   |                   |   |                  |   | (7,846              | )       |
| Lease  financing – long term        |   |                   |   |                  |   | $                   | 629,815 |   |
|                                          |        |                        |        |                       |        |                     |         |  |  |  |

 

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

 

The lease obligations arepayable to the Owner Trusts. These obligations bear imputed interest at 9.252%and 9.024% for the Somerset and Cayuga Plants, respectively. Total assets underthe leases of these two Plants were $650 million at December 31, 2003. Theseamounts are included in electric generation assets.  The related accumulated depreciation, combined for both leasedPlants, as of December 31, 2003 and 2002, was approximately $92.9 million and$72.5 million, respectively. The agreements governing the leases restrict thePartnership’s ability to incur additional indebtedness, engage in otherbusinesses, sell its assets, or merge with another entity. The ability of thePartnership to make distributions to its partners is restricted unless

 

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

 

An aggregate amount inexcess of $65 million is available to be drawn under the Payment UndertakingAgreement (see Note 2) and the Additional Liquidity Letter of Credit for makingrental payments. In the event sufficient amounts to make rental payments arenot available from other sources, a withdrawal from the additional liquidityaccount (which may include making a drawing under the Additional LiquidityLetter of Credit) and from the rent reserve account (which may include making ademand under the Payment Undertaking Agreement) may be made for rental payments.

 

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

 

7.                             COMMITMENTS AND CONTINGENCIES

 

Coal Purchases – In connection with the acquisition of the Plants, thePartnership assumed from NYSEG an agreement to purchase the coal required bythe Somerset and Cayuga Plants. Each year, either party can requestrenegotiation of the price of one-third of the coal supplied pursuant to thisagreement. The supplier requested renegotiation during 2001 for the 2002 lotbut the parties failed to reach agreement. The supplier requested renegotiationduring 2002 for the 2003 lot plus the 2002 lot for which agreement was notreached. On September 11, 2002, the Partnership and the supplier reachedagreement on both of the lots. Therefore, the commitment of the Partnership for2003 was three lots for the Somerset Plant plus 70% of the anticipated coalusage for the Cayuga Plant. The termination date for the contract was December31, 2003. The agreement was not extended.

 

As of the acquisition date of the Plants, the contract prices for thecoal purchased through 2002 were above the market price, and the Partnershiprecorded a purchase accounting liability for approximately $15.7 millionrelated to the fulfillment of its obligation to purchase coal under thisagreement. The purchase accounting liability was amortized as a reduction tocoal expense over the life of the contract. As of December 31, 2002, theunderlying contracts were fully amortized.

 

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

 

Transmission Agreements -On August 3, 1998, the General Partner entered into an agreement for thepurpose of transferring certain rights and obligations from NYSEG to theGeneral Partner under an existing transmission agreement among Niagara MohawkPower Corporation (NIMO), the New York Power Authority, NYSEG, and RochesterGas & Electric Corporation, and an existing transmission agreement betweenNYSEG and NIMO. This agreement provides for the assignment of rights totransmit energy from the Somerset Plant and other sources to remote load areasand other delivery points, and was assumed by the Partnership on the date ofacquisition of the Plants. In accordance with its plan, as of the acquisitiondate, the Partnership discontinued using this service. The Partnership did notintend to transmit over these lines and was required to pay the current feesuntil the effective cancellation date, November 19, 1999.

 

The Partnership wasinformed by NIMO that the Partnership would be responsible for the monthly feesof $500,640 under the existing transmission agreement to the originallyscheduled termination date of October 1, 2004. On October 5, 1999, thePartnership filed a complaint against NIMO alleging that the Partnership has aright to non-firm transmission service upon six months prior notice withoutpayment of $500,640 in monthly fees subsequent to the cancellation date ofNovember 19, 1999. On March 9, 2000, a settlement was reached between thePartnership and NIMO, which was subsequently approved by the Federal EnergyRegulatory Commission (FERC). According to the settlement, the Partnership willcontinue to pay NIMO a fixed rate of $500,640 per month during the period ofNovember 20, 1999 to October 1, 2004, and in turn, will receive a form oftransmission service commencing on May 1, 2000, which the Partnership believes willprovide an economic benefit over the period of May 1, 2000 to October 1, 2004.The Partnership has the right under a Remote Load WheelingAgreement (RLWA) to transmit 298 MW over firm transmission lines from theSomerset Plant. The Partnership has the right to designate alternate points ofdelivery on NIMO’s transmission system provided that the Partnership is notentitled to receive any transmission service charge credit on the NIMO system.

 

The contract is accounted for as a derivative under SFAS No. 133. Thetransmission contract was entered into because it provided a reasonablesettlement for resolving a FERC issue. The agreement is essentially a swapbetween the congestion component of the locational prices posted daily by theNYISO in western New York and the more heavily populated areas in eastern NewYork. The

 

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agreement is a financially settled contract since there is norequirement to flow power under this agreement. The agreement generates gainsor losses from exposure to shifts or changes in market prices. The Partnershiprecorded a loss of approximately $6.2 million, a gain of 8.9 million and a lossof $29.5 million for the years ended December 31, 2003, 2002 and 2001,respectively, related to this contract.

 

On June 25, 2003, AESSomerset L.L.C. filed a complaint against NIMO with the FERC. The complaintinvolves outstanding station service charges for the period April 2000 to May2003. The Plant has calculated that the outstanding charges owed are $290,000,while NIMO has calculated that the outstanding charges are $3.6 million. InDecember 2003, FERC reiterated its 2001 ruling that independent power plantscan net station service power, in the Somerset and Nine Mile orders. NIMO isappealing the ruling. As of December 31, 2003, AES Somerset has accruedapproximately $1.6 million for these charges.

 

Line of Credit Agreement –On May 14, 1999, the Partnership established a three-year revolving workingcapital credit facility of up to $50 million for the purpose of making fundsavailable to pay for certain operating and maintenance costs. This facility wasterminated as of March 9, 2001. In April 2001, the Partnership entered into a$35 million secured revolving working capital and letter of credit facilitywith Union Bank of California, N.A. This facility had a term of approximatelytwenty-one months. The Partnership could borrow up to $35 million for workingcapital purposes under this facility. In addition, the Partnership could haveletters of credit issued under this facility up to $25 million, provided thatthe total amount of working capital borrowings and letters of credit issuancesmay not exceed the $35 million limit on the entire facility. Through December31, 2003, there were three borrowings under this facility. The first borrowingwas for $7 million on July 13, 2001 at an interest rate of 8.125%. Theborrowing 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 borrowingwas repaid in full on February 28, 2002. The third borrowing was for $14.0million on July 9, 2002, at an interest rate of 6.125%. The Partnership repaidthe borrowing in two installments: $7.2 million on July 31, 2002 and $6.8million on August 28, 2002.

 

On November 20, 2002, the Partnership signed an agreement with UnionBank of California, N.A. for a one-year extension of the working capital andletter of credit facility. On April 16, 2003, the partnership signed anamendment to its November 20, 2002 credit agreement with Union Bank ofCalifornia, N.A. The amendment includes another one-year extension of thecurrent facility; the maturity date of the working capital and letter of creditfacility is now January 2, 2005. The amendment also increases Union Bank ofCalifornia’s commitment from $15 million to $20 million. On April 25, 2003, thePartnership further amended its November 20, 2002 credit agreement with UnionBank of California, N.A. The amendment includes a commitment from Citibank,N.A. for the remaining $15 million of the facility. There have been twoborrowings under this facility. The first borrowing was for $9.7 million onJanuary 10, 2003 at an interest rate of 5.75%. This borrowing was repaid infull on January 28, 2003. The second borrowing was for $9.7 million on July 9,2003 at an interest rate of 5.5%. This borrowing was repaid in full on July 25,2003. As of December 31, 2003, of the $35 million committed, the Partnershiphad obtained letters of credit of $18.5 million, which have been provided asadditional margin to support normal, ongoing hedging activities with a numberof counterparties.

 

AES on January 6, 2003 and February 25, 2003 authorized the Partnershipto issue letters of credit to counterparties on its $350 million senior securedrevolving credit facility to the amount of $25 million and $35 million for theyears of 2003 and 2004, respectively.

 

On February 12, 2004, the Partnership signed a two-year agreement,effective January 1, 2004, with AES to obtain up to $35 million and $25 milliondollars of letters of credit or cash collateral for 2004 and 2005,respectively. This agreement supercedes the authorization of AES on February25, 2003. The agreement limits the letters of credit amounts and cash collateralto the stated amounts and set into place a fee structure and repayment terms.As of December 31, 2003, the Partnership has obtained letters of credit in theamount of $4.6 million, which have been provided as additional margin tosupport normal, ongoing hedging activities with a number of counterparties.

 

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

 

Environmental - ThePartnership has recorded a liability for environmental remediation associatedwith the acquisition of the Plants (see Note 3). On an ongoing basis, thePartnership monitors its compliance with environmental laws. Because of theuncertainties associated with environmental compliance and remediationactivities, future costs of compliance or remediation could be higher or lowerthan the amount currently accrued.

 

The Partnership receivedan information request letter dated October 12, 1999 from the New York AttorneyGeneral, which seeks detailed operating and maintenance history for theWestover and Greenidge Plants. On January 13, 2000, the Partnership received asubpoena from New York State Department of Environmental Conservation (NYSDEC)seeking similar operating and maintenance history from the Plants. Thisinformation is being sought in connection with the Attorney General’s and theNYSDEC’s investigations of several electricity generating stations in New York

 

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that are suspected ofundertaking modifications in the past without undergoing an air permittingreview.

 

OnApril 14, 2000, the Partnership received a request for information pursuant toSection 114 ofthe CleanAir Act from the U.S. Environmental Protection Agency (EPA) seeking detailedoperating and maintenance historydata for the Cayuga and Somerset Plants. The EPA has commenced an industry-wide investigation of coal-firedelectric power generators to determine compliance with environmental requirements under the Clean AirAct associated with repairs, maintenance, modifications and operational changes made to coal-fired facilities overthe years. The EPA’s focus is onwhether the changes were subject to new source review or new source performancestandards, and whether best availablecontrol technology was or should have been used. The Partnership has provided the requesteddocumentation.

 

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 YorkEnvironmental Conservation Law at the Greenidge and Westover Plants related to NYSEG’s alleged failure to obtainan air permitting review for repairsand improvements made during the 1980s and 1990s, which was prior to theacquisition of the Plants by thePartnership. Pursuant to the purchase agreement relating to the acquisition ofthe Plants from NYSEG, the Partnershipagreed to assume responsibility for environmental liabilities that arose while NYSEG owned thePlants. On September 12, 2000, the Partnership agreed with NYSEG that the Partnership will assumethe defense of and responsibility for the NOV, subject to a reservation of its right to assertapplicable exceptions to its contractual undertaking to assume preexisting environmentalliabilities.

 

The Partnership is currently in negotiation with both the EPA and NYSDEC.If a settlement is not reached, the EPA and the NYSDEC could issue a notice ornotices of violation to the Partnership for violations of the Clean Air Act andthe New York Environmental Conservation Law. If the Attorney General, theNYSDEC or the EPA does file an enforcement action against the Somerset, Cayuga,Westover, or Greenidge Plants, then penalties may be imposed and furtheremission reductions might be necessary at these Plants which could require thePartnership to make substantial expenditures. The Partnership is unable toestimate the effect of such a NOV on its financial condition or results offuture operations.

 

Nitrogen Oxide and SulfurDioxide Emission Allowances - The Plants emit nitrogen oxide (NOx) and sulfurdioxide (SO2) as a result of burning coal to produce electricity.

 

The Plants have been allocated allowances bythe NYSDEC to emit NOx during the ozone season, which runs from May 1 toSeptember 30. Each NOx allowance authorizes the emission of one ton of NOxduring the ozone season. If NOx emissions exceed the allowance amountsallocated to the Plants, then the Partnership may need to purchase additionalallowances on the open market or otherwise reduce its production of electricityto stay within the allocated amounts. New York State and the other states inthe Mid-Atlantic and Northeast region are classified as the Ozone TransportRegion in the federal Clean Air Act, which designates the Ozone TransportRegion as not being in compliance with the ozone National Ambient Air QualityStandard. The states in the Ozone Transport Region have agreed to implement athree phase process to reduce NOx emissions in the region in order to complywith the federal Clean Air Act Title I requirements for ozone non-complianceareas. Implementation of Phase III emission rules commenced on May 1, 2003. ThePhase III NOx regulations set forth a NOx allowance allocation program whichgives the Partnership 2,317 NOx emissions allowances for 2004. ThePlants were net sellers of NOX allowances in 2002 and 2001. The Plants had ashortfall of approximately 1,200 NOx allowances in 2003. The 2003 shortfall wascovered by purchasing 70 NOx allowances from AES Ironwood, an indirect whollyowned subsidiary of the AES Corporation at market prices and the remainder ofNOx allowances were purchased from unrelated companies in the open market atmarket price.

 

The Plants are also subject to SO2 emissionallowance requirements imposed by the EPA. Each SO2 allowance authorizes theemission of one ton of SO2 during the calendar year. SO2 allowances may bebought, sold, or traded. If SO2 emissions exceed the allowance amountsallocated to the Plants, then the Partnership may need to purchase additionalallowances on the open market or otherwise reduce its production of electricityto stay within the allocated amounts. The Plants wereself-sufficient with respect to SO2 allowances in 2001; however, the Plants hada shortfall of approximately 6,600 and approximately 10,000 SO2 allowances in2002 and 2003, respectively. The majority of the 2002 SO2 allowance shortfallwas covered with allowances purchased from the electricity generating stationsowned by an affiliate of the Partnership, AES Creative Resources, L.P. (ACR),which are on long-term cold standby. Those allowances were purchased at quotedmarket prices. The 2003 shortfall was covered by purchasing SO2 allowances atmarket prices from unrelated companies in the open market.

 

In October1999, New York State Governor Pataki announced an executive order mandatingadditional emission reductions from New York State power plants. The Governor’sinitiative requires non-ozone season NOx emission reductions based on anemission rate of 0.15 lbs/Mmbtu starting in 2004, and a 50% reduction from thepower plants’ Title IV SO2 emissions being phased in from 2005 to 2008. Theprogram will be implemented through a market-based mechanism. The rulesimplementing the Governor’s initiative (6 NYCRR Parts 237 and 238) were adoptedin March 2003. A number of entities have started legal actions to attempt tooverturn these rules.

 

In September 2003, New York State determined the amount of NOxemissions allowances that would be allocated to the Plants. The allocation isseveral hundred tons short of the Partnership’s average historical NOx emissionsfor the Plants during the control period. The Partnership’s compliance plancannot be finalized until the anticipated New York NOx allowance market prices

 

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are more conclusively determined.

 

In January 2004, NYSDEC determined the amount of SO2 emissionsallowances that would be allocated to the Plants. The allocation is severalthousand tons short of the Partnership’s average historical SO2 emissions forthe Plants. The Partnership’s compliance plan cannot be finalized until theanticipated New York SO2 allowance market prices are more conclusivelydetermined.

 

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

 

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

 

The Partnership voluntarily disclosed to the NYSDEC and EPA on November27, 2002 that NOx exceedances appear to have occurred on October 30 and 31 andNovember 1-8 and 10 of 2002. The exceedances were discovered through an auditby plant personnel of the Plant’s NOx RACT tracking system. The Partnershipbelieves that it has taken all reasonable, good faith efforts to assess andcorrect the exceedances. Immediately upon the discovery of the calculationerror, the SCR at the Somerset Plant was activated to reduce NOx emissions.Emission data indicates that the system had already returned to a compliantoperation by the time the error was discovered. The EPA has decided to defer tothe NYSDEC for review of the self-disclosure letter and technical issues. ThePartnership is unable to predict any potential actions or fines the NYSDEC mayrequire, if any.

 

The Partnershipvoluntarily disclosed to the NYSDEC in January 2003 that the Cayuga Plant hadinadvertently burned synfuel (coal with a latex binder applied), which it isnot permitted to burn. The Partnership had entered into an agreement with asupplier to purchase coal. It received approximately one 9000-ton trainshipment per month from April 24, 2001 to December 27, 2002. In January 2003,The Partnership became aware that the product the Cayuga Plant was receivingwas synfuel. The Partnership suspended all shipments from that supplier until aresolution was reached. The Partnership reviewed the emission and operationdata which showed there was no adverse effect to air quality with respect toapplicable permit emissions limits attributable to burning the material. ThePartnership is unable to predict any potential actions or fines the NYSDEC mayrequire, if any. InJuly 2003, the Partnership reached an agreement with the supplier to resumeshipment of coal in order to satisfy contractual obligations. As part of thisagreement, the supplier has provided a written guarantee stating that all fuelshipments will be coal.

 

In April 2002, the EPA proposed to establish location, design,construction and capacity standards for cooling water intake structures atexisting power plants withdrawing more than 50 million gallons per day fromrivers, lakes or other bodies of water. The EPA is developing these regulationsunder the terms of an Amended Consent Decree in Riverkeeper, Inc vs. Whitman,US District Court, Southern District of New York. The final rule was releasedby the EPA on February 16, 2004. These new rules will impose new compliance requirementson the withdrawal of water, with potentially significant costs, on operatingplants across the nation with cooling water intake structures. Cost itemsinclude various environmental and engineering studies and potential capital andmaintenance costs. The Partnership is evaluating the potential applicability ofthe rule and it has not yet determined the effects, if any, of theseregulations on its financial position or results of operations. If applicable,the new rule requirements will be addressed when the Plants’ wastewaterdischarge permits are renewed.

 

Northeastern U.S. states (including New York) have agreed to work todevelop a regional market-based emissions trading system to reduce powerplants’ Carbon Dioxide emissions. The goal is to reach an agreement by April2005 on a cap and emissions trading program. Until such time as the rules aredeveloped to implement such a program, the Partnership cannot determine whatits impact would be on the Partnership’s financial position or results fromoperations.

 

8.                             RELATED PARTY TRANSACTIONS

 

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

 

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$4.2 million,respectively, has been recorded by the Partnership as operating expenses andother accrued liabilities under this agreement.

 

On August 14, 2000, SRC entered into a $26 million credit facility withFortis Capital Corp.  which replaced inits entirety a credit facility for the same amount previously provided to SRCby an affiliate of CIBC World Markets. The new credit facility provided byFortis Capital Corp.  consists of a 14-yearterm note (maturing on May 6, 2014), with principal and interest payments duequarterly.

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Starting in 2001, until the sale of AES New Energy in the third quarterof 2002, the Partnership entered into bilateral contract transactions with AESNew Energy, awholly owned subsidiary of AES. These transactions included forwardsales of electric energy and unforced capacity at market based rates. For theyears ended December 31, 2002 and 2001, the Partnership recognized revenues ofapproximately $13.9 million and $11.7 million, respectively, related to thephysical delivery of electricity or unforced capacity and the subsequent changein the market value of these contracts. AES New Energy was sold in the thirdquarter of 2002. As of December 31, 2002 and 2001,  the related account receivable – trade between AES New Energy andthe Partnership was zero and $2.6 million, respectively. The exposure atDecember 31, 2001 and 2002 related to these contract transactions was less than10% of the Partnership’s estimated cash revenues for the respective year.

 

AES contributed approximately $162,000 to the Partnership in 2003,related to the cost of stock options compensation expense. Also, AEScontributed approximately $1.5 million and $9.4 million to the Partnership in2002 and 2001, respectively, related to the construction of the SCR on Unit 1of 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 employedboth under collectively bargained and non-collectively bargained arrangements.Certain people formerly employed by NYSEG (the Transferred Persons) receivecredit under the Plan for compensation and service earned while employed byNYSEG. The amount of any benefit payable under the Plan to a Transferred Personwill be offset by the amount of any benefit payable to such Transferred Personunder the Retirement Plan for Employees of NYSEG. Effective May 29, 1999, theability to commence participation in the Plan and the accrual of benefits underthe Plan ceased with respect to non-collectively bargained people and theaccrued benefits of any such participant were fixed as of such date. As ofDecember 31, 2003, the Plan was funded at least to the extent required byInternal Revenue Code (IRC) Section 412 minimum funding and not more than therequirement of IRC Section 404, maximum contribution limits. The Partnershipwill make at least the required minimum contribution within the EmployeeRetirement Income Security Act (ERISA) guidelines. Pension benefits are basedon years of credited service, age of the participant, and average earnings.During 2003, 2002 and 2001, collectively bargained people were offered theopportunity to freeze their accrued benefit payable under the Plan and opt intothe AES Profit Sharing and Stock Ownership Plans.

 

57

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The assets and liabilitiesof the Plan were valued as of October 31, 2003 and 2002.  This measurement date is a change from theprevious practice of utilizing a December 31 measurement date for 2001. Thevalues of the assets and liabilities as of October 31, 2003 and 2002 were notmaterially different than the values as of December 31, 2003 and 2002.

 
|                                                    |   | **2003** |    | **2002** |   | **2001** |   |
|---------------------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
| Projected  Benefit Obligation                           |   |     |    |     |   |     |   |
| Change  in projected benefit obligation (in thousands): |   |     |    |     |   |     |   |
| Projected  benefit obligation, beginning of period      |   | $        | 25,267  |     | $      | 21,840   |   | $ | 20,801 |   |
| Service  cost                                           |   | 375      |    | 347      |   | 408      |   |
| Interest  cost                                          |   | 1,495    |    | 1,132    |   | 1,293    |   |
| Actuarial  (gain) loss                                  |   | (1,419   | )       | —   |   | (469     | )      |
| Benefits  paid                                          |   | (830     | )       | (189     | )      | (193     | )      |
| Curtailment                                             |   | —   |    | (790     | )      | —   |   |
| Special  Termination Loss                               |   | —   |    | 2,927    |   | —   |   |
|                                                    |   |     |    |     |   |     |   |
| Projected  benefit obligation, end of period            |   | $        | 24,888  |     | $      | 25,267   |   | $ | 21,840 |   |
| Plan  Assets:                                           |   |     |    |     |   |     |   |
| Change  in plan assets (in thousands):                  |   |     |    |     |   |     |   |
| Fair  value of plan assets, beginning of period         |   | $        | 7,153   |     | $      | 4,873    |   | $ | 2,020 |   |
| Actual  return on plan assets                           |   | 933      |    | (512     | )      | (156     | )      |
| Employer  contributions                                 |   | 2,161    |    | 2,981    |   | 3,202    |   |
| Benefits  paid                                          |   | (830     | )       | (189     | )      | (189     | )      |
|                                                    |   |     |    |     |   |     |   |
| Fair  value of plan assets, end of period               |   | $        | 9,417   |     | $      | 7,153    |   | $ | 4,873 |   |
| Funded  status/accrued benefit liability                |   | $        | (15,471 | )        | $      | (18,114  | )      | $ | (16,968 | ) |
| Unrecognized  Net Loss                                  |   | (1,087   | )       | 675      |   | —   |   |
| (Accrued)/Prepaid  Pension Cost, end of period          |   | $        | (16,558 | )        | $      | (17,439  | )      | $ | (16,968 | ) |
|                                                    |   |     |    |     |   |     |   |
| Defined  Benefit Pension Plan Costs:                    |   |     |    |     |   |     |   |
| Components  of net periodic benefit cost (in thousands) |   |     |    |     |   |     |   |
| Service  cost                                           |   | $        | 366     |     | $      | 416      |   | $ | 408 |   |
| Interest  cost                                          |   | 1,522    |    | 1,358    |   | 1,293    |   |
| Expected  return on plan assets                         |   | (607     | )       | (474     | )      | (312     | )      |
|                                                    |   |     |    |     |   |     |   |
| Net  periodic benefit cost                              |   | $        | 1,281   |     | $      | 1,300    |   | $ | 1,389 |   |

 

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

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

 

The projected benefitobligation of the Plan as of May 14, 1999, as actuarially determined, wasrecorded by the Partnership as a purchase accounting liability (see Note 3)under Accounting Principles Board Opinion (APB) No. 16, “BusinessCombinations”. The accumulated benefit obligation was approximately $21.8million, $20.5 million and $16.7 million as of December 31, 2003, 2002 and2001, respectively.

 

Significant assumptionswere used in the calculations of the net benefit cost and projected benefitobligation for the periods ending October 31, 2003 and 2002 and December 31,2001. In developing the Partnership’s expected long-term rate of returnassumption, the Partnership evaluated input from its actuaries and plan assetmanager. Projected returns are based on a broad range of equity and bondindices. The Partnership’s expected 8% long-term rate of return on QualifiedPlan assets is based on the allocation assumption of 60% equities (50% growthand 50% value), with a 10% long term rate of return, and 40% in fixed incomeinvestments, with a 5.5% long-term rate of return. Because of marketfluctuation, its actual allocation was 58% and 52% equities and 42% and 48% infixed income investments as of October 31, 2003 and 2002, respectively.However, the Partnership believes that its long-term asset allocation onaverage will approximate 60% equities and 40% fixed income investments. The

 

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

 

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

 

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

 

Plan Assets

 

The Partnership’s pensionplan weighted-average asset allocations at December 31, 2003, 2002 and 2001 areas follows:

 
| **Asset Category** |   | **2003** |   | **2002** |   | **2001** |   |
|--------------------|--------|----------|--------|----------|--------|----------|--------|
| Equity  securities |   | 60       | %      | 60       | %      | 60       | %      |
| Debt  securities   |   | 40       | %      | 40       | %      | 40       | %      |

 

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

 

All three components are based primarily on historical data, withmodest adjustments to take into account additional relevant information that is currently available. For the inflation and risk- free return components, the most significantadditional information is that provided by the market for nominal andinflation-indexed U.S. Treasury securities.  That market provides impliedforecasts of both the inflation rate and risk-free rate for the period overwhich currently-available securities mature. The historical data on riskpremiums for each asset class is adjusted to reflect any systemic changes thathave occurred in the relevant markets; e.g., the higher current valuations forequities, as a multiple of earnings, relative to the longer-term average forsuch valuations.

 

Cash Flows

 

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

 

Estimated Future Benefits

 

The following benefitpayments, which reflect expected future service, as appropriate, are expectedto be paid:

 
| **Fiscal Years ending  December 31,** |   | **Payments** |   |
|---------------------------------------|--------|--------------|--------|
|                                  |   |         |   |
| 2004                                  |   | $            | 987    |   |
| 2005                                  |   | 1,030        |   |
| 2006                                  |   | 1,102        |   |
| 2007                                  |   | 1,210        |   |
| 2008                                  |   | 1,325        |   |
| Thereafter                            |   | 8,336        |   |
| Total  Estimated Future Benefits      |   | $            | 13,990 |   |

 

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

 

Other Postretirement Benefit Plan

 

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

 

59

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|                                                    |   | **2002** |   |
|---------------------------------------------------------|--------|----------|--------|
| Postretirement  Medical Benefit Costs:                  |   |     |   |
| Postretirement  Benefit Costs:                          |   |     |   |
| Components  of net periodic benefit cost (in thousands) |   |     |   |
| Service  cost                                           |   | $        | 37     |   |
| Interest  cost                                          |   | 76       |   |
| Expected  return on plan assets                         |   | —   |   |
| Amortization  of:                                       |   |     |   |
| Transition  Obligation                                  |   | —   |   |
| Prior  Service Cost                                     |   | 118      |   |
| Net  Loss/Gain                                          |   | —   |   |
| Total                                                   |   | 118      |   |
| Net  Periodic Postretirement Benefit Cost               |   | $        | 231    |   |
| Accumulated  Postretirement Benefit Obligation          |   |     |   |
| Change  in projected benefit obligation (in thousands): |   |     |   |
| Projected  benefit obligation, beginning of year        |   | $        | 1,200  |   |
| Service  cost                                           |   | 36       |   |
| Interest  cost                                          |   | 76       |   |
| Actuarial  (gain) loss                                  |   | (14      | )      |
| Benefits  paid                                          |   | 14       |   |
| Projected  benefit obligation, end of year              |   | $        | 1,312  |   |
| Plan  Assets:                                           |   |     |   |
| Change  in plan assets (in thousands):                  |   |     |   |
| Fair  value of plan assets, beginning of year           |   | $        | — |   |
| Unrecognized  Prior Service Cost                        |   | 1,083    |   |
| Unrecognized  Net Loss/(Gain)                           |   | (14      | )      |
|                                                    |   |     |   |
| Fair  value of plan assets, end of year                 |   | $        | 1,069  |   |
| Funded  status/accrued benefit liability                |   | $        | 243    |   |

 

Weighted average discountrate for expense calculation is 6.25% in 2002. Weighted average discount ratefor accumulated postretirement benefit obligation is 6.25% beginning December31, 2001. The medical care cost trend rate is 13% for 2002, decreasinggradually to 5.0% by the year 2010. The Medicare cost trend rate is 7.0% for2002, decreasing gradually to 5.0% by the year 2006. Increasing the health caretrend rate by 1% would increase the total accumulated postretirement benefitobligation to $1,489,148, or by 15.9%, and the aggregate of the total Serviceand Interest Cost components of the Net Periodic Postretirement Benefit Costwould increase from $113,294, to $134,966, or by 19.1%. Decreasing the healthcare cost trend by 1.0% would decrease the total accumulated postretirementbenefit obligation to $1,119,110, or by 12.9% and the aggregate of the totalService and Interest Cost components of the Net Periodic Postretirement BenefitCost would decrease from $113,294 to $96,187, or by 15.1%.

 

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

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

 

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10.                       LONG-TERM INCENTIVE PROGRAM

 

Stock Option Plan – Employees of the Partnership participate in the AESStock Option Plan (the SOP) that provides for grants of stock options toeligible participants. Prior to 2003, the Partnershipaccounted for the SOP under the recognition and measurement provisions of APBOpinion No. 25, “Accounting forStock Issued to Employees,” and related Interpretations.  No stock-based employee compensation cost isreflected in 2002 and 2001 net income, as all options granted under the SOP in those years had an exercise priceequal to the market value of the underlying common stock on the date of grant. Effective January1, 2003, the Partnership adopted the fair value recognition provisions of SFAS No.123, “Accounting for Stock-BasedCompensation”, prospectively to allemployee awards granted, modified or settled after January 1, 2003.  Awards under the SOP vest over periods ranging from two to fiveyears.  Therefore, the cost related tostock-based employee compensationincluded in the determination of net income for 2003 is less than that whichwould have been recognized if thefair value based method had been applied to all awards from the inception of the Partnership. The expenserecognized under the prospective method for the year ended December 31, 2003 is approximately$162,000.

 

11.                       FAIR VALUE OF FINANCIAL INSTRUMENTS

 

The fair value of thePartnership’s current financial assets and liabilities approximate theircarrying values. The fair value estimates are based on pertinent informationavailable as of December 31, 2003. The Partnership is not aware of any factorsthat would significantly affect the estimated fair value amounts since thatdate.  

 

12.                       SEGMENT INFORMATION

 

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

 

13.                       RESTRICTIONS ON DISTRIBUTIONS TOPARTNERS

 

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

 

14.                       SUBSEQUENTEVENTS

 

Cashflow from the Partnership’s operations during the second half of 2003 wassufficient to coverthe aggregaterental payments under the leases on the Somerset and Cayuga Plants due January2, 2004. On this date, rentalpayments were made in the amount of $31.7 million.

 

Cashflow from operations in excess of the aggregate rentalpayments under the Partnership’s leasesmay be distributed to its partners if certain criteria are met. On January 7,2004, the Partnership made adistribution payment of $48.7 million.

 

The Partnership borrowed $12.9 million on January 9, 2004 and anadditional $1 million on February 20, 2004, for working capital purposes underthe $35 million secured revolving working capital and letter of credit facilitywith Union Bank of California, N.A. The borrowings were at an interest rate of5.50%.  A partial payment of $6.2million was repaid on January 27, 2004 and the remaining balance of $7.7million was repaid on February 26, 2004.

 

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INDEPENDENT AUDITORS’ REPORT

 

 

To the Member of

AES NY, L.L.C.

 

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

 

We conducted our audits inaccordance with auditing standards generally accepted in the United States ofAmerica. Those standards require that we plan and perform our audits to obtainreasonable assurance about whether the financial statements are free ofmaterial misstatement. An audit includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements. An auditalso includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financialstatement presentation. We believe that our audits provide a reasonable basisfor our opinion.

 

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

 

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

 
| /s/Deloitte & Touche  LLP |   |
|-------------------------------|--------|

 

 

McLean, Virginia

February 26, 2004

 

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**AES NY, L.L.C.**

**CONSOLIDATED BALANCE SHEETS,**

**DECEMBER 31, 2003 and DECEMBER 31, 2002**

***(Amounts in Thousands*****)**

 
| **December 31,**                                                                      |   | **2003** |      | **2002** |   |
|---------------------------------------------------------------------------------------|--------|----------|-----------|----------|--------|
| **ASSETS**                                                                            |   |     |      |     |   |
| Current  Assets:                                                                      |   |     |      |     |   |
| Restricted  cash:                                                                     |   |     |      |     |   |
| Operating  - cash and cash equivalents                                                |   | $        | 2,932     |     | $      | 5,116 |   |
| Revenue  account                                                                      |   | 85,231   |      | 76,566   |   |
| Accounts  receivable - trade                                                          |   | 34,883   |      | 35,233   |   |
| Accounts  receivable - affiliates                                                     |   | 2,969    |      | 2,935    |   |
| Accounts  receivable - other                                                          |   | 1,280    |      | 1,264    |   |
| Inventory                                                                             |   | 27,700   |      | 26,982   |   |
| Prepaid  expenses                                                                     |   | 8,117    |      | 7,726    |   |
| Total current assets                                                                  |   | 163,112  |      | 155,822  |   |
| PROPERTY,  PLANT, EQUIPMENT, AND RELATED ASSETS:                                      |   |     |      |     |   |
| Land                                                                                  |   | 7,503    |      | 7,461    |   |
| Electric  generation assets -net of accumulated depreciation of $161,784 and $122,378 |   | 902,663  |      | 929,654  |   |
| Total  property, plant, equipment and related assets                                  |   | 910,166  |      | 937,115  |   |
| OTHER  ASSETS:                                                                        |   |     |      |     |   |
| Deferred  financing -net of accumulated amortization of $328 and $863                 |   | 303      |      | 293      |   |
| Derivative  valuation                                                                 |   | 16,143   |      | 2,510    |   |
| Transmission  congestion contract                                                     |   | —   |      | 2,416    |   |
| Rent  reserve account                                                                 |   | 31,717   |      | 31,717   |   |
| TOTAL  ASSETS                                                                         |   | $        | 1,121,441 |     | $      | 1,129,873 |   |
|                                                                                  |   |     |      |     |   |
| LIABILITIES AND MEMBERS’ CAPITAL                                                 |   |     |      |     |   |
|                                                                                  |   |     |      |     |   |
| CURRENT  LIABILITIES:                                                                 |   |     |      |     |   |
| Accounts  payable                                                                     |   | $        | 833       |     | $      | 1,195 |   |
| Lease  financing - current                                                            |   | 7,846    |      | 1,665    |   |
| Environmental  remediation                                                            |   | —   |      | 35       |   |
| Accrued  interest expense                                                             |   | 28,004   |      | 28,078   |   |
| Due  to The AES Corporation and affiliates                                            |   | 9,096    |      | 7,173    |   |
| Accrued  coal and rail expense                                                        |   | 6,456    |      | 8,492    |   |
| Other  accrued expenses and liabilities                                               |   | 10,134   |      | 11,264   |   |
| Total  current liabilities                                                            |   | 62,369   |      | 57,902   |   |
|                                                                                  |   |     |      |     |   |
| LONG-TERM  LIABILITIES:                                                               |   |     |      |     |   |
| Lease  financing - long term                                                          |   | 629,815  |      | 637,660  |   |
| Environmental  remediation                                                            |   | 6,800    |      | 9,192    |   |
| Defined  benefit plan obligation                                                      |   | 17,238   |      | 18,147   |   |
| Asset  retirement obligation                                                          |   | 10,299   |      | —   |   |
| Derivative  valuation liability                                                       |   | 43,624   |      | 20,996   |   |
| Transmission  congestion contract                                                     |   | 359      |      | —   |   |
| Other  liabilities                                                                    |   | 2,688    |      | 2,600    |   |
| Total  long-term liabilities                                                          |   | 710,823  |      | 688,595  |   |
| TOTAL  LIABILITIES                                                                    |   | 773,192  |      | 746,497  |   |
|                                                                                  |   |     |      |     |   |
| COMMITMENTS  AND CONTINGENCIES (Note 6)                                               |   |     |      |     |   |
|                                                                                  |   |     |      |     |   |
| MINORITY  INTEREST                                                                    |   | 344,767  |      | 379,542  |   |
| MEMBER’S  EQUITY                                                                 |   | 3,482    |      | 3,834    |   |
| TOTAL  LIABILITIES AND MEMBERS’ CAPITAL                                          |   | $        | 1,121,441 |     | $      | 1,129,873 |   |

 

The notes are an integralpart of the consolidated Balance Sheets

 

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AESNY, L.L.C

NOTESTO CONSOLIDATED BALANCE SHEETSYEARS ENDED DECEMBER 31, 2003 AND 2002

 

1.                             GENERAL

 

AES NY, L.L.C. (theCompany), 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 generalpartner of AES Creative Resources, L.P.(ACR), owning a one percent interest inACR. AES NY Holdings, L.L.C. is the sole member of the Company. The Company isan indirect wholly owned subsidiary of The AES Corporation (AES). The Companybegan operations on May 14, 1999. Prior to that date, the Company had no operations.

 

The Company wasestablished for the purpose of acting as the general partner of both AEE andACR. In this capacity, the Company is responsible for the day-to-day managementof AEE and ACR and their operations and affairs, and is responsible for all liabilitiesand obligations of both entities.

 

AEE, a Delaware limitedpartnership, was formed on December 2, 1998. AEE’s wholly owned subsidiariesare AES Somerset, L.L.C., AES Cayuga, L.L.C., and AEE2, L.L.C., (which whollyowns AES Westover, L.L.C. and AES Greenidge, L.L.C.). AEE began operations onMay 14, 1999. Prior to that date, AEE had no operations. AEE was establishedfor the purpose of owning and operating four coal-fired electric generatingstations (the AEE Plants) with a total combined capacity of 1,268 MW. Two ofthe plants are owned by AEE and two of the plants are leased by AEE (see Note5), and are operated by AEE’s wholly owned subsidiaries in the State of NewYork, pursuant to operation and maintenance agreements with AEE. The limited partnerof AEE is AES NY 2, L.L.C. (the Limited Partner), which is also an indirectwholly owned subsidiary of AES.

 

ACR, a Delaware limitedpartnership, was formed on December 3, 1998. ACR’s wholly owned subsidiariesare AES Jennison, L.L.C. and AES Hickling, L.L.C., which each owns a coal-firedelectric generating station (the ACR Plants) with a combined capacity of 156MW. ACR began operations on May 14, 1999. Prior to that date ACR had nooperations. The limited partner of ACR is AES NY 2, L.L.C. The AEE Plants andthe ACR Plants are hereinafter referred to collectively as “the Plants.”

 

In November 2000, AEEentered into a three-year agreement for energy marketing serviceswith 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 throughFebruary 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 theirMarch 2002 agreement. Odyssey will manage the AEE coal and environmentalemission credit positions for an additional fee of $100,000 per month. Odysseyacts as agent on behalf of AEE in the over-the-counter and NYISO markets. (seenote 7)

 

The AEE Plants sellgenerated electricity, as well as unforced capacity and ancillary services,directly into the markets operated by the NYISO system, Pennsylvania, NewJersey, Maryland (PJM) Interconnection and ISO New England. For Federalregulatory purposes, AEE and ACR are exempt wholesale generators (EWGs). AsEWGs, AEE and ACR cannot make retail sales of electricity, and can only makewholesale sales of electricity, unforced capacity, and ancillary services intowholesale power markets.

 

During the fourth quarter of 2000, ACR placed the ACR Plants onlong-term cold standby. The long-term cold standby designation means that thesePlants require more than 14 days to be brought on-line. The Company iscurrently evaluating the future of these Plants.

 

2.                             SIGNIFICANT ACCOUNTING POLICIES

 

Principles ofConsolidation - The consolidated balance sheets include the accounts of theCompany, AEE and ACR (including all subsidiaries). The balance sheets arepresented on a consolidated basis because the Company, as general partner,controls the operations of AEE and ACR (Note 1). All material intercompanytransactions have been eliminated. The 99% limited partner ownerships of AEEand ACR are presented as minority interest.

 

The assets of the Companyon a stand-alone basis at December 31, 2003 and 2002 (using the equity methodof 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, 2003and 2002, other than liabilities of AEE and ACR for which it is responsible asGeneral Partner of AEE and ACR.

 

Restricted Cash - Underthe terms of the deposit and disbursement agreement entered into by AEE inconnection with the lease of two AEE plants (see Note 5), all revenues of AEEand its subsidiaries are deposited into a revenue account administered byDeutsche Bank (formerly Bankers Trust Company), as depositary agent. On requestof AEE and in accordance with the terms of the deposit and disbursementagreement, funds are transferred from the revenue account to other operatingaccounts administered by the depositary agent for payment of operating andmaintenance costs, lease obligations, debt service, reserve requirements, anddistributions. Payment of operating and

 

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maintenance costs (otherthan actual fuel costs) in excess of 125% of the annual operating budget is notpermitted under the terms of the lease documents. Amendments, modifications orreallocations of the annual operating budget that result in changes of 25%(positive or negative) in the amounts set forth in the annual operating budgetrequire confirmation from an independent engineer that such payment is based onreasonable assumptions.

 

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

 

Inventory, as of December31 consisted of the following (in thousands):

 
|                                  |   | **2003** |   | **2002** |   |
|---------------------------------------|--------|----------|--------|----------|--------|
| Coal  and other raw materials         |   | $        | 12,329 |     | $      | 11,342 |   |
| Spare  parts, materials, and supplies |   | 15,371   |   | 15,640   |   |
|                                  |   |     |   |     |   |
| Total                                 |   | $        | 27,700 |     | $      | 26,982 |   |

 

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

under special terms inwhich title had not transferred as of December 31, 2002 from one of AEE’sexisting suppliers.

 

Property, Plant,Equipment, and Related Assets - Electric generation assets that existed at thedate of acquisition (see Note 3) are recorded at fair market value. TheSomerset (formerly known as Kintigh) and Cayuga (formerly known as Milliken)Plants, which represent $650 million of the electric generation assets, aresubject to a leasing arrangement accounted for as a financing (see Note 5).Additions or improvements thereafter are recorded at cost. Depreciation iscomputed using the straight-line method over the 34-year and 28.5-year leaseterms for the Somerset and Cayuga Plants, respectively, and over the estimateduseful lives for the other fixed assets, which range from 7 to 35 years.Maintenance and repairs are charged to expense as incurred.

 

The Company is currently evaluating the future of the Jennison andHickling plants and may dispose or shut down these plants. As such, theelectric generation assets of these two plants were depreciated over two years(2001 and 2002) using the straight-line method. Maintenance and repairs are chargedto expense as incurred. During the fourth quarter of 2000, ACR placedthe ACR Plants on long-term cold standby. The long-term cold standbydesignation means that these plants require more than 14 days to be broughton-line. The ACR Plants continue to generate revenue from the sales ofenvironmental allowances which they receive from regulatory authorities.

 

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

 
|                                       |   | **2003** |      |
|--------------------------------------------|--------|----------|-----------|
|                                       |   | **AEE**  |      | **ACR** |   | **Total** |   |
|                                       |   |     |      |   |   |   |   |
| Electric  generation assets                |   | $        | 1,058,922 |   | $ | 5,525 |   | $ | 1,064,447 |   |
| Accumulated  depreciation and amortization |   | (156,259 | )         | (5,525 | ) | $ | (161,784 | ) |
| Total                                      |   | $        | 902,663   |   | $ | — |   | $ | 902,663 |   |

 
|                                       |   | **2002** |      |
|--------------------------------------------|--------|----------|-----------|
|                                       |   | **AEE**  |      | **ACR** |   | **Total** |   |
|                                       |   |     |      |   |   |   |   |
| Electric  generation assets                |   | $        | 1,046,867 |   | $ | 5,156 |   | $ | 1,052,023 |   |
| Accumulated  depreciation and amortization |   | (117,222 | )         | (5,156 | ) | (122,378 | ) |
| Total                                      |   | $        | 929,654   |   | $ | — |   | $ | 929,654 |   |

 

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Rent Reserve Account - Aspart of AEE’s lease obligation (see Note 5), AEE is required to maintain a rentreserve account equal to the maximum semiannual payment with respect to the sumof basic rent (other than deferrable payments) and fixed charges expected tobecome due on any one basic rent payment date in the immediately succeeding three-yearperiod. As of December 31, 2003 and 2002, AEE had fulfilled this obligation byentering into a Payment Undertaking Agreement, dated as of May 1, 1999, amongAEE, each Owner Trust (see Note 3) and Morgan Guaranty Trust Company of NewYork (the Payment Undertaking Agreement). On May 14, 1999, AEE deposited withMorgan Guaranty Trust Company of New York approximately $28.7 million pursuantto the Payment Undertaking Agreement. The accreted value of the PaymentUndertaking Agreement at any time includes interest earned thereunder at aninterest rate of 4.79% per annum. Interest earnings as of December 31, 2003,2002, and 2001 were approximately $1.5 million for each year, respectively, andare included in the rent reserve account balance. At December 31, 2003 and2002, the accreted value of the Payment Undertaking Agreement exceeded therequired balance of the rent reserve account. This amount is being accountedfor as a restricted cash balance and is included within the rent reserveaccount on the accompanying balance sheets, as it can only be utilized tosatisfy lease obligations. In the future, AEE may fulfill its obligation tomaintain the required balance of the rent reserve account either by depositsinto the rent reserve account or by making amounts available under the PaymentUndertaking Agreement, such that the aggregate amount of such deposits in therent reserve account and amounts available to be paid under the PaymentUndertaking Agreement are equal to the required balance of the rent reserve account.

 

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

 

Income Taxes - A provisionfor Federal and state income taxes has not been made in the accompanyingfinancial statements since the Company, AEE and ACR do not pay income taxes butrather allocate their revenues and expenses to the individual partners.

 

Use of Estimates - Thepreparation of financial statements in conformity with accounting principlesgenerally accepted in the United States of America requires the Company to makeestimates and assumptions that affect reported amounts of assets andliabilities and disclosures of contingent assets and liabilities at the date ofthe financial statements, as well as the reported amounts of revenues andexpenses during the reporting period. Actual results could differ from thoseestimates.

 

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

 

The Company adopted SFAS No. 133, “Accounting for DerivativeInstruments and Hedging Activities”, which, as amended, established new accountingand reporting standards for derivative instruments and hedging activities. TheStatement requires that the Company recognize all derivatives, as defined inthe Statement, on the balance sheet at fair value. Derivatives that areeffective cash flow hedges are recognized in other comprehensive income (loss)until the hedged items are recognized in earnings. Derivatives, or any portionthereof, that are not effective hedges are adjusted to fair value throughincome. As of December 31, 2003, the Company has recorded $27.6 million ofother comprehensive loss due to hedging activities.

 

AEE utilizes derivative financial instruments to hedge commodity pricerisk. AEE utilizes electric derivative instruments, including swaps andforwards, to hedge the risk related to forecasted electricity sales over thenext two years. The majority of AEE’s electric derivatives are designated andqualify as cash flow hedges. AEE has chosen to use the hypothetical derivative methodology for testing whether itshedges meet the criteria to qualify for cash flow hedge accounting treatment. A historicalregression is performed between the electricity generating stations, delivery points into theNYISO and the NYISO zones in which the hedges are settled. Comparing the results of thehistorical regression and the actual changes in the market value of the hedgesdetermines if the hedges qualify for hedge accounting criteria treatment. Nohedges were derecognized or discontinued and no significant amounts of hedgeineffectiveness were recognized in earnings during the years ended December 31,2003, 2002 and 2001, respectively.

 

Approximately $18.7 million of other comprehensive income is expectedto be recognized as a reduction to earnings over the next twelve months.Amounts recorded in Other Comprehensive Income during the year ended December31, 2003, were as follows (in millions):

 

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

 

In addition to the electric derivatives classified as cash flow hedgecontracts, AEE has a Transmission Congestion Contract that is a derivativeunder the definition of SFAS No. 133, but does not qualify for hedgeaccounting. This contract is recorded at fair value on the balance sheetwith changes in the fair value recognized through earnings.

 

Revenue Recognition -Revenues from the sale of electricity are recorded based upon output deliveredand rates specified under contract terms. Gains and losses, generated from thehedging of future sales using commodity forwards, swaps and options, reportedin other comprehensive income, are reclassified to earnings in the periods inwhich earnings are impacted by the variability of the cash flows of the hedgeditem. The ineffective portions of the change in fair value of derivatives andthe change in the fair value of derivatives not designated as hedges foraccounting purposes are recognized in current period earnings. Revenues forancillary and other services are recorded when the services are rendered.

 

In June 2001, the Financial Accounting Standards Board (FASB) issuedSFAS No. 142, “Goodwill and Other Intangible Assets”. This standard eliminatesthe amortization of goodwill and requires goodwill to be reviewed periodicallyfor impairment.  This standard alsorequires the useful lives of previously recognized assets to be adjustedaccordingly. This standard is effective for fiscal years beginning afterDecember 15, 2001, for all goodwill and other intangible assets recognized onthe Company’s balance sheet at that date, regardless of when the assets wereinitially recognized. The initial adoption of SFAS No. 142 did not have asignificant impact on the Company’s financial position and results ofoperations.

 

In June 2001, the FASB issued SFAS No. 143, “Accounting for AssetRetirement Obligations”. SFAS No. 143, which is effective January 1,2003, requires entities to record the fair value of a legal liability for anasset retirement obligation in the period in which it is incurred.  The new liability was recorded in the firstquarter of 2003. The Company capitalized the costs of the liability byincreasing the carrying amount of the related long-lived asset. The liabilityis accreted to its present value each period, and the capitalized cost isdepreciated over the useful life of the related asset. Upon settlement of theliability, the Company will settle the obligation for its recorded amount orincur a gain or loss upon settlement. The Company adopted SFAS No. 143effective January 1, 2003.

 

The Company has completed a detailed assessment of the specificapplicability and implications of SFAS No. 143. The scope of SFAS No.143 as it applies to the Company, includes primarily active ash landfills andwater treatment basins. Upon adoption of SFAS No. 143, the Companyrecorded a liability of approximately $9.6 million and a net asset ofapproximately $3.3 million, which are included in electrical generation assets,and reversed a $4.2 million environmental remediation liability previouslyrecorded (see Note 3). The difference of the amounts previously recorded andthe net SFAS 143 liability is a loss recorded as the cumulative effect of achange in accounting principle of $2.2 million. Reconciliation of the assetretirement obligation liability for the year ending December 31, 2003 was asfollows (in millions):

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

 

In December 2002,the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation -Transition and Disclosure.” SFAS No. 148 amends SFAS No. 123, “Accountingfor Stock-Based Compensation” to provide alternative methods of transition fora voluntary change to the fair value based method of accounting for stock-basedemployee compensation. In addition, this Statement amends the disclosurerequirements of SFAS No.123 to require prominent disclosures in both annual andinterim financial statements about the method of accounting for stock-basedemployee compensation and the effect of the method used on reportedresults. The Company expects to use the prospective method to transitionto the fair value based method of accounting for stock-based employee compensation. Allemployee awards granted, modified, or settled after January 1, 2003, will berecorded using the fair value based method of accounting (see Note 10). TheCompany’s adoption of the prospective method of accounting for stock-basedemployee compensation did not have any material impact on its financialposition or results of operations.

 

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On April 30, 2003, the FASB issued SFAS No. 149, “Amendment ofStatement 133 on Derivative Instruments and Hedging Activities”. SFAS No. 149amends and clarifies financial accounting and reporting for derivativeinstruments and for hedging activities under SFAS No. 133. The amendmentreflects decisions made by FASB and the Derivatives Implementation Group (DIG)in connection with issues raised about the application of SFAS No. 133.Generally, the provisions of SFAS No. 149 will be applied prospectively forcontracts entered into or modified after June 30, 2003 and for hedgingrelationships designated after June 30, 2003. SFAS No. 149 provisions thatresulted from the DIG process that became effective in quarters beginningbefore June 15, 2003 will continue to be applied based upon their originaleffective dates. The adoption of SFAS No. 149 did not have a material impact onthe Company’s financial position or results of operations.

 

The Company adopted the disclosure provisions of FASB InterpretationNo. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements forGuarantees, Including Direct Guarantees of Indebtedness of Others,” in thefourth quarter of 2002.  The Companywill apply the initial recognition and measurement provisions on a prospectivebasis for all guarantees issued after December 31, 2002. In general, theCompany enters into various agreements providing financial performanceassurance to third parties on behalf of certain subsidiaries. Such agreementsinclude guarantees, letters of credit and surety bonds. FIN 45 does notencompass guarantees issued either between parents and their subsidiaries orbetween corporations under common control, a parent’s guarantee of itssubsidiary’s debt to a third party (whether the parent is a corporation or anindividual), a subsidiary’s guarantee of the debt owed to a third party byeither its parent or another subsidiary of that parent, nor guarantees of acompany’s own future performance. Adoption of FIN 45 had no impact on theCompany’s historical financial statements as existing guarantees are notsubject to the measurement provisions of FIN 45. The Company does not expectadoption of the liability recognition provisions of FIN 45 to have a materialimpact on its financial position or results of operations.

 

InJanuary 2003, the Financial Accounting Standards Board (the FASB) issuedInterpretation No. 46, “Consolidation of Variable Interest Entities” whichprovides guidance on how to identify a variable interest entity (VIE), and whenthe assets, liabilities, noncontrolling interests and results of operations ofa VIE need to be included in a company’s consolidated financial statements.This interpretation was revised in December 2003 with the issuance ofInterpretation No. 46(R), “Consolidation of Variable Interest Entities” (FIN46(R)).

 

Ingeneral, a VIE is an entity that lacks sufficient equity or its equity holderslack adequate decision making ability. If either of these characteristics ispresent, the entity is subject to a variable interests consolidation model, andconsolidation is based on variable interests, not on ownership of the entity’soutstanding voting stock. Variable interests are defined as contractual,ownership, or other money interests in an entity that change with fluctuationsin the entity’s net asset value. The primary beneficiary consolidates the VIE;the primary beneficiary is defined as the enterprise that absorbs a majority ofexpected losses or receives a majority of residual returns (if the losses orreturns occur), or both.

 

The sales – leaseback transaction under which Somerset and Cayuga wereacquired qualifies as a VIE. The sales – leaseback rules require that theleases be treated as financing leases for purposes of the Company's financialstatements, which they have been from the Company's  inception. The Company is considering the applicability ofconsolidating Somerset Railroad Corporation. If it does so the Company's consolidated Balance Sheet as of December31, 2003, would reflect additional assets of approximately $28.4 million andliabilities of approximately $19.6 million.

 

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

 

In December 2003, the (FASB) issued SFAS No. 132 (revised 2003),“Employers’ Disclosure About Pensions and Other Postretirement Benefits”, whichamends SFAS No. 87, “Employers’ Accounting for Pensions”, SFAS No. 88,“Employers’ Accounting for Settlements and Curtailments of Defined BenefitPension Plans and for Termination Benefits”, and SFAS No. 106, “Employers’Accounting for Postretirement Benefits Other Than Pensions “, and replaces SFASNo. 132, “Employers’ Disclosures About Pensions and Other PostretirementBenefits” (collectively

 

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referred to as “SFAS No. 132 (revised)”) . SFAS No. 132 (revised)expands employers’ disclosures about pension and other post-retirement benefitplans to present more information regarding the economic resources andobligations of such plans in terms of the plans’ assets, obligations, cashflows and net periodic benefit costs. Additionally, SFAS No. 132 (revised) requiresinterim-period disclosures regarding plan benefit costs and material planchanges. The Company is required to adopt the new annual disclosurerequirements of SFAS No. 132 (revised) effective as of December 31, 2003. Theinterim-period disclosure requirements will be effective for the Company as ofMarch 31, 2004. As SFAS No. 132 (revised) does not change the measurement orrecognition of pension and other post-retirement benefit plans as required bySFAS No. 87, SFAS No. 88 and SFAS No. 106, adoption of this new standard willhave no effect on the Company’s consolidated financial statements.

 

Reclassifications - Certain prior year and prior period amounts havebeen reclassified on the consolidated financial statements to conform with the2003 presentation.

 

3.                             ACQUISITION

 

On May 14, 1999, AEE’sfour Plants were acquired from NYSEG for approximately $914 million. AEEacquired 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, theOwner Trusts) organized by three unrelated institutional investors. Theinstitutional investors made an equity contribution of $116 million and $550million was raised for purchase of the Somerset and Cayuga plants from the saleof pass through trust certificates. Simultaneously, AEE entered into separateleasing 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 AEEPlants was financed by capital contributions from the Company and the LimitedPartner in an aggregate amount equal to the purchase price for the Plants,certain associated costs and expenses, and certain amounts for working capitalless the net proceeds from the leasing transactions with respect to theSomerset and Cayuga Plants described above. The acquisition has been accountedfor as an asset purchase. In connection with the acquisition of the AEE Plants,NYSEG engaged an environmental consulting firm to perform an environmentalanalysis of the potential required remediations for soil and ground watercontamination. AEE engaged another environmental consulting firm to evaluatethe costs estimated by NYSEG’s consultants. The environmental analysis andAEE’s estimate of other environmental remediation costs indicated that thereexisted a range of potential remediation costs of between $8.5 million and$19.7 million, with a most probable liability of approximately $12 million. AEErecorded $12 million as an undiscounted liability under purchase accounting forthe projected remediation cost. In 2002, AEE reduced its undiscounted liabilityby $2.2 million as remediation was completed or more current estimates werereceived for lower than the amounts previously estimated. On January 1, 2003,$4.2 million of this environmental remediation liability was reclassified intothe asset liability obligation in accordance with SFAS No. 143. As of December31, 2003, none of the liability was classified as a current liability.

 

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

 

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

 

4.                           CAPITALIZATION

 

The Company is indirectlyowned by AES New York Funding, L.L.C. (AES Funding), which is a special purposefinancing vehicle established to raise a portion of the capital contributed toAEE and ACR through the Company and the Limited Partner. AES Funding is adirect wholly owned subsidiary of AES.

 

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

 

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

 

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

 

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

 

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

 

Collateral for the loanalso 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.

 

5.                             LEASE FINANCING

 

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

 
| **Fiscal Years ending  December 31,**    |   | **Principal  Portion** |   | **Interest  Imputed** |   | **Lease  Payments** |    |
|------------------------------------------|--------|------------------------|--------|-----------------------|--------|---------------------|---------|
|                                     |   |                   |   |                  |   |                |    |
| 2004                                     |   | $                      | 7,846  |                  | $      | 55,604              |    | $ | 63,450 |   |
| 2005                                     |   | 4,411                  |   | 55,039                |   | 59,450              |    |
| 2006                                     |   | 6,898                  |   | 54,652                |   | 61,550              |    |
| 2007                                     |   | 8,495                  |   | 54,005                |   | 62,500              |    |
| 2008                                     |   | 9,256                  |   | 53,244                |   | 62,500              |    |
| Thereafter                               |   | 600,755                |   | 588,911               |   | 1,189,666           |    |
| Total  minimum lease payments            |   | 637,661                |   | 861,455               |   | 1,499,116           |    |
|                                     |   |                   |   |                  |   |                |    |
| Less  imputed interest                   |   |                   |   |                  |   | (861,455            | )       |
|                                     |   |                   |   |                  |   |                |    |
| Present  value of minimum lease payments |   |                   |   |                  |   | $                   | 637,661 |   |
|                                     |   |                   |   |                  |   |                |    |
| Less  current portion                    |   |                   |   |                  |   | (7,846              | )       |
| Lease  financing – long term        |   |                   |   |                  |   | $                   | 629,815 |   |
|                                          |        |                        |        |                       |        |                     |         |  |  |  |

 

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

 

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

 

An aggregate amount inexcess of $65 million is available to be drawn under the Payment UndertakingAgreement (see Note 2) and the Additional Liquidity Letter of Credit for makingrental payments. In the event sufficient amounts to make rental payments arenot available from other sources, a withdrawal from the additional liquidityaccount (which may include making a drawing under the

 

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Additional LiquidityLetter of Credit) and from the rent reserve account (which may include making ademand under the Payment Undertaking Agreement) may be made for rentalpayments.

 

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

 

6.                             COMMITMENTS AND CONTINGENCIES

 

Coal Purchases – In connection with the acquisition of AEE’s fourPlants, AEE assumed from NYSEG an agreement to purchase the coal required bythe Somerset and Cayuga Plants. Each year, either party can requestrenegotiation of the price of one-third of the coal supplied pursuant to thisagreement. During 2001 the coal suppliers were committed to sell and AEE wascommitted to purchase all three lots of coal for the Somerset Plant as well as70% of the anticipated coal purchases for the Cayuga Plant. The supplierrequested renegotiation during 2001 for the 2002 lot but the parties failed toreach agreement. Therefore, the parties had commitments in 2002 with respect toonly two lots for the Somerset Plant and 50% of the anticipated coal purchasesat the Cayuga Plant. The supplier requested renegotiation during 2002 for the2003 lot plus the 2002 lot for which agreement was not reached. On September11, 2002, AEE and the supplier reached agreement on both of the lots.Therefore, the commitment of AEE for 2003 was three lots for the Somerset Plantplus 70% of the anticipated coal usage for the Cayuga Plant. The terminationdate for the contract was December 31, 2003. The agreement was not extended.

 

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

 

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

 

Transmission Agreements -On August 3, 1998, the Company entered into an agreement for the purpose oftransferring certain rights and obligations from NYSEG to the Company under anexisting transmission agreement among Niagara Mohawk Power Corporation (NIMO),the New York Power Authority, NYSEG, and Rochester Gas & ElectricCorporation, and an existing transmission agreement between NYSEG and NIMO.This agreement provides for the assignment of rights to transmit energy fromthe Somerset Plant and other sources to remote load areas and other deliverypoints, and was assumed by AEE on the date of acquisition of the Plants. Inaccordance with its plan as of the acquisition date, AEE discontinued usingthis service. AEE did not intend to transmit over these lines and was requiredto pay the current fees until the effective cancellation date, November 19,1999.

 

AEE was informed by NIMOthat AEE would be responsible for the monthly fees of $500,640 under theexisting transmission agreement to the originally scheduled termination date ofOctober 1, 2004. On October 5, 1999, AEE filed a complaint against NIMOalleging that AEE has a right to non-firm transmission service upon six monthsprior notice without payment of $500,640 in monthly fees subsequent to thecancellation date of November 19, 1999. On March 9, 2000, a settlement wasreached between AEE and NIMO, which was subsequently approved by the FederalEnergy Regulatory Commission (FERC). According to the settlement, AEE willcontinue to pay NIMO a fixed rate of $500,640 per month during the period ofNovember 20, 1999 to October 1, 2004, and in turn, will receive a form oftransmission service commencing on May 1, 2000, which AEE believes will providean economic benefit over the period of May 1, 2000 to October 1, 2004. AEE hasthe right under a Remote Load Wheeling Agreement (RLWA) to transmit 298 MW overfirm transmission lines from the Somerset Plant. AEE has the right to designate alternate points of delivery onNIMO’s transmission system provided that AEE is not entitled to receiveany transmission service charge credit on the NIMO system.

 

The contract is accounted for as a derivative under SFAS No. 133. Thetransmission contract was entered into because it provided a reasonablesettlement for resolving a FERC issue. The agreement is essentially a swapbetween the congestion component of the locational prices posted daily by theNYISO in western New York and the more heavily populated areas in eastern NewYork. The agreement is a financially settled contract since there is norequirement to flow power under this agreement.  The agreement generates gains or losses from exposure to shiftsor changes in market prices. AEE recorded a loss of approximately $6.2 million,a gain of $8.9 million and a loss of $29.5 million for the years ended December31, 2003, 2002 and 2001, respectively, related to this contract.

 

On June 25, 2003, AESSomerset L.L.C. filed a complaint against NIMO with the FERC. The complaintinvolves outstanding station service charges for the period April 2000 to May2003. The Plant has calculated that the outstanding charges owed are $290,000,while NIMO has calculated that the outstanding charges are $3.6 million. InDecember 2003, FERC reiterated its 2001 ruling that independent power plantscan net station service power, in the Somerset and Nine Mile orders. NIMO isappealing the ruling. As of December 31, 2003, AES Somerset had accruedapproximately $1.6 million for these charges.

 

Line of Credit Agreement – On May 14, 1999, AEE established athree-year revolving working capital credit facility of up to $50 million forthe purpose of making funds available to pay for certain operating andmaintenance costs. This facility was terminated as of March 9, 2001. In April2001, AEE entered into a $35 million secured revolving working capital andletter of credit facility with

 

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Union Bank of California, N.A. This facility had a term ofapproximately twenty-one months. AEE could borrow up to $35 million for workingcapital purposes under this facility. In addition, AEE could have letters ofcredit issued under this facility up to $25 million, provided that the totalamount of working capital borrowings and letters of credit issuances may notexceed the $35 million limit on the entire facility. Through December 31, 2003,there were three borrowings under this facility. The first borrowing was for $7million on July 13, 2001 at an interest rate of 8.125%. The borrowing wasrepaid in full on July 31, 2001. The second borrowing was for $8.5 million onJanuary 11, 2002 at an interest rate of 6.125%. The borrowing was repaid infull 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 ofCalifornia, N.A. for a one- year extension of the working capital and letter ofcredit facility. On April 16, 2003, AEE signed an amendment to its November 20,2002 credit agreement with Union Bank of California, N.A. The amendmentincludes another one-year extension of the current facility; the maturity dateof the working capital and letter of credit facility is now January 2, 2005.The amendment also increases Union Bank of California’s commitment from $15million to $20 million. On April 25, 2003, AEE further amended its November 20,2002 credit agreement with Union Bank of California, N.A. The amendmentincludes a commitment from Citibank, N.A. for the remaining $15 million of thefacility. There have been two borrowings under this facility. The firstborrowing was for $9.7 million on January 10, 2003 at an interest rate of5.75%. This borrowing was repaid in full on January 28, 2003. The secondborrowing was for $9.7 million on July 9, 2003 at an interest rate of 5.5%. Thisborrowing was repaid in full on July 25, 2003. As of December 31, 2003, AEE hasobtained letters of credit of $18.5 million, which have been provided asadditional margin to support normal, ongoing hedging activities with a numberof counterparties.

 

AES on January 6, 2003 and February 25, 2003 authorized AEE to issueletters of credit to counter-parties on its $350 million senior securedrevolving credit facility to the amount of $25 million and $35 million for theyears of 2003 and 2004, respectively.

 

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

 

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

 

Environmental - The Company has recorded a liability for environmental remediation associated withthe acquisition of the Plants (see Note 3). On an ongoing basis, the Companymonitors its compliance with environmental laws. Because of the uncertaintiesassociated with environmental compliance and remediation activities, futurecosts of compliance or remediation could be higher or lower than the amountcurrently accrued.

 

AEE received aninformation request letter dated October 12, 1999 from the New York AttorneyGeneral, which seeks detailed operating and maintenance history for theWestover and Greenidge Plants. On January 13, 2000, AEE received a subpoenafrom New York State Department of Environmental Conservation (NYSDEC) seekingsimilar operating and maintenance history from the Plants. This information isbeing sought in connection with the Attorney General’s and the NYSDEC’sinvestigations of several electricity generating stations in New York that aresuspected of undertaking modifications in the past without undergoing an airpermitting review.

 

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

 

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 YorkEnvironmental Conservation Law at the Greenidge and Westover Plants related to NYSEG’s alleged failure to obtainan air permitting review for repairs and improvements made during the 1980s and1990s, which was prior to the acquisition of the Plants by AEE. Pursuant to thepurchase agreement relating to the acquisition of the Plants from NYSEG, AEEagreed to assume responsibility for environmental liabilities that arose whileNYSEG owned the Plants. On September 12, 2000, AEE agreed with NYSEG that AEEwill assume the defense of and responsibility forthe NOV, subject to a reservation of its right to assert applicable exceptionsto its contractual undertaking to assume preexisting environmental liabilities.

 

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AEEand ACR are currently in negotiation with both the EPA and NYSDEC. If asettlement is not reached, the EPA and the NYSDEC could issue a notice ornotices of violation (NOV) to AEE and ACR for violations of the Clean Air Actand the Environmental Conservation Law. If the Attorney General, the NYSDEC orthe EPA does file an enforcement action against the Somerset, Cayuga, Westover,or Greenidge Plants, then penalties may be imposed and further emissionreductions might be necessary at these Plants which could require AEE to makesubstantial expenditures. The Company is unable to estimate the effect of sucha NOV on its financial condition or results of future operations.

 

Nitrogen Oxide and SulfurDioxide Emission Allowances -The AEE and ACR Plants emit nitrogen oxide (NOx)and sulfur dioxide (SO2) as a result of burning coal to produce electricity.

 

The six Plants have beenallocated allowances by the NYSDEC to emit NOx during the ozone season, whichruns from May 1 to September 30. Each NOx allowance authorizes the emission ofone ton of NOx during the ozone season. If NOx emissions exceed the allowanceamounts allocated to the six Plants, then the Company may need to purchaseadditional allowances on the open market or otherwise reduce its production ofelectricity to stay within the allocated amounts. New York State and the otherstates in the Mid-Atlantic and Northeast region are classified as the OzoneTransport Region in the federal Clean Air Act, which designates the OzoneTransport Region as not being in compliance with the ozone National Ambient AirQuality Standard. The states in the Ozone Transport Region have agreed toimplement a three phase process to reduce NOx emissions in the region in orderto comply with the federal Clean Air Act Title I requirements for ozonenon-compliance areas. Implementation of Phase III emission rules commenced onMay 1, 2003. The Phase III NOx regulations set forth a NOx allowance allocationprogram which gives the Company 2,317 NOx emissions allowances for 2004. Thesix Plants were net sellers of NOX allowances in 2002 and 2001. The six Plantshad a shortfall of approximately 1,200 NOx allowances in 2003. The 2003shortfall was covered by purchasing 70 NOx allowances from AES Ironwood, anindirect wholly owned subsidiary of the AES Corporation at market prices andthe remainder of NOx allowances were purchased from unrelated companies in theopen market at market price.

 

The six Plants are alsosubject to SO2 emission allowance requirements imposed by the EPA. Each SO2allowance authorizes the emission of one ton of SO2 during the calendar year.SO2 allowances may be bought, sold, or traded. If SO2 emissions exceed theallowance amounts allocated to the six Plants, then the Company may need topurchase additional allowances on the open market or otherwise reduce itsproduction of electricity to stay within the allocated amounts. Thesix Plants were self-sufficient with respect to SO2 allowances in 2001;however, the six Plants had a shortfall of approximately 584 and 10,000 SO2allowances in 2002 and 2003, respectively. In 2002, ACR sold approximately6,000 SO2 allowances to the AEE Plants at market prices, then sold the remaining SO2 allowances through2009. The 2003 allowance shortfall was covered by purchasing SO2 allowances atmarket prices from unrelated companies in the open market.

 

In October 1999, New York State Governor Pataki announced an executiveorder mandating additional emission reductions from New York State powerplants. The Governor’s initiative requires non-ozone season NOx emissionreductions based on an emission rate of 0.15 lbs/Mmbtu starting in 2004, and a50% reduction from the power plants’ Title IV SO2 emissions being phased infrom 2005 to 2008. The program will be implemented through a market-basedmechanism. The rules implementing the Governor’s initiative (6 NYCRR Parts 237and 238) were adopted in March 2003. A number of entities have started legalactions to attempt to overturn these rules.

 

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

 

In January 2004, NYSDEC determined the amount of SO2 emissionsallowances that would be allocated to the Plants. The allocation is severalthousand tons shortof the Company’s average historical SO2 emissions for the Plants. The Company’scompliance plan cannot be finalized until the anticipated New York SO2allowance market prices are more conclusively determined.

 

In January 2004, the EPA proposed an “interstate air quality rule” thatwould require further emission reductions in NOx and SO2 emitted from power plants andother sources that significantly contribute to fine particulate (“PM2.5”) andozone pollution in downwind states.  NOx and SO2 are precursors of PM2.5, andNOx is a precursor of ozone. Theproposed rule directs 29 states, including New York, to issue new regulationsthat will require major SO2 and NOx reductions by 2010 and further reductionsby 2015. States are encouraged to use a cap and emission trading approach. Afinal rule is expected to be issued in 2005. At this point, the Company cannotdetermine what the costs would be to comply with new federal SO2 and NOxemission reduction requirements.

 

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

 

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AEE voluntarily disclosed to the NYSDEC and EPA on November 27, 2002that NOx exceedances appear to have occurred on October 30 and 31 and November1-8 and 10 of 2002. The exceedances were discovered through an audit by plantpersonnel of the Plant’s NOx RACT tracking system. AEE believes that it hastaken all reasonable, good faith efforts to assess and correct the exceedances.Immediately upon the discovery of the calculation error, the SCR at theSomerset Plant was activated to reduce NOx emissions. Emission data indicatesthat the system had already returned to a complaint operation by the time theerror was discovered. The EPA has decided to defer to the NYSDEC for review ofthe self-disclosure letter and technical issues. AEE is unable to predict anypotential actions or fines the NYSDEC may require, if any.

 

AEE voluntarily disclosedto the NYSDEC in January 2003 that the Cayuga Plant had inadvertently burnedsynfuel (coal with a latex binder applied), which it is not permitted to burn.The Cayuga Plant had entered into an agreement with a supplier to purchasecoal. It received approximately one 9000-ton train shipment per month fromApril 24, 2001 to December 27, 2002. In January 2003, AEE became aware that theproduct the Cayuga Plant was receiving was synfuel. AEE has suspended allshipments from that supplier until a resolution is reached. AEE has reviewedthe emission and operation data which showed there was no adverse effect to airquality with respect to applicable permit emissions limits attributable toburning the material. AEE is unable to predict any potential actions or finesthe NYSDEC may require, if any. In July 2003, AEE reached an agreement with the supplier to resumeshipment of coal in order to satisfy contractual obligations. As part of thisagreement, the supplier has provided a written guarantee stating that all fuelshipments will be coal.

 

In October1999, ACR entered into a consent order with the NYSDEC to resolve allegedviolations of the water quality standards in the groundwater downgradient of anash disposal site. As a result, the site was closed. AEE2, L.L.C. contributedone-half of the costs to close the landfill, which were approximately $2million, and it will contribute additional costs for long-term groundwatermonitoring. Nevertheless, if a groundwater remediation is required, AEE2,L.L.C. may be responsible for a portion of such costs.

 

ACR reportedthat concentrations of a number of chemicals in a few groundwater wellsincreased in the year ending December 31, 2001, since the Jennison and HicklingPlants were placed on long-term cold standby. A consultant was retained to helpevaluate the source of the chemicals and provide recommendations forremediation. The consultant concluded that the cause of the problem wascoarse bottom ash with pyrites that has been exposed to air since sluicing ofwater to the bottom ash ponds has been terminated. ACR notified NYSDEC that at Jennison, where theelevated concentrations are the highest, that ACR is removing the suspectmaterial and anticipate that over time concentrations will subside.  ACR has asked NYSDEC for approval of a planto add additional monitoring wells at Hickling to allow ACR to assess changesin the groundwater that have occurred since use of its pond was terminated.

 

ACR voluntarily disclosedto the NYSDEC and EPA that the company is conducting aninvestigation based on conflicting reports of suspected materials buried at theHickling Plant. Field and laboratory studies have not indicated any evidence ofwaste disposal that poses a serious risk to potential receptors. ACR hasnotified both the NYSDEC and EPA of these studies and believes that no furtheraction is required.

 

In April 2002, the EPA proposed to establish location, design,construction and capacity standards for cooling water intake structures atexisting power plants withdrawing more than 50 million gallons per day fromrivers, lakes and other bodies of water. The EPA is developing theseregulations under the terms of an Amended Consent Decree in Riverkeeper, Incvs. Whitman, US District Court, Southern District of New York. The final rulewas released by the EPA on February 16, 2004. These new rules will impose newcompliance requirements on the withdrawal of water, with potentiallysignificant costs, on operating plants across the nation with cooling waterintake structures. Cost items include various environmental and engineeringstudies and potential capital and maintenance costs. AEE is evaluating thepotential applicability of the rule and it has not yet determined the effects,if any, of these regulations on its financial position or results ofoperations. If applicable, the new rule requirements will be addressed when thePlants’ wastewater discharge permits are renewed.

 

Northeastern U.S. states (including New York) have agreed to work todevelop a regional market-based emissions trading system to reduce powerplants’ carbon dioxide emissions. The goal is to reach an agreement by April2005 on a cap and emission trading program. Until such time as the rules aredeveloped to implement such a program the Company cannot determine what itsimpact would be on the Company’s financial position or results from operations.

 

7.                             RELATED PARTY TRANSACTIONS

 

AEE has entered into acontract with Somerset Railroad Corporation (SRC), a wholly owned subsidiary ofAES NY3, L.L.C., which is an indirect wholly owned subsidiary of AES, pursuantto which SRC will haul coal and limestone to the Somerset Plant and make itsrail cars available to transport coal to the Cayuga Plant. AEE will pay amountssufficient 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’soutstanding indebtedness and all capital expenditures necessary to permit SRCto continue to provide rail service to the Somerset and Cayuga Plants. As ofDecember 31, 2003, 2002 and 2001,

 

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

 

On August 14, 2000, SRC entered into a $26 million credit facility withFortis Capital Corp. which replaced in its entirety a credit facility for thesame 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-yearterm note (maturing on May 6, 2014), with principal and interest payments duequarterly.

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

 

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

 

In November 2000, AEE entered into a three-year agreement for energymarketing services with Odyssey, a wholly owned subsidiary of AES. In March2002, a new agreement was reached. The new agreement is for a term of fiveyears through February 28, 2007 pursuant to which Odyssey provides datamanagement, marketing, scheduling, invoicing and risk management services for afee of $300,000 per month. On September 4, 2003, AEE signed an amendment to itsMarch 2002 agreement. Odyssey will also manage the AEE coal and environmentalemission credit positions for an additional fee of $100,000 per month. Odysseyacts as agent on behalf of AEE in the over-the-counter and NYISO markets.

 

Odyssey also manages environmental emission credit positions for otherAES facilities. These allowances were purchased on the open market at marketprices. From time to time the allowances will be temporarily placed into aAEE's facility allowance account while awaiting transfer to the purchasingfacility. In 2003, allowances were purchased and sold in this matter for AESDeepwater, AES Red Oak and AES Ironwood, all indirect wholly owned subsidiariesof the AES Corporation.

 

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

 

As agent, Odyssey manages all energy transactions under AEE and ACR’sname including (i) preparing confirmations for AEE and ACR and approvingconfirmations with counterparties, (ii) conducting monthly check-outs withcounterparties as appropriate before the preparation of invoices, (iii)invoicing counterparties for the term of the transactions and (iv) otherwisemanaging and executing the terms of the transactions in accordance with theirprovisions.

 

Odyssey provides data management services for AEE and ACR bymaintaining databases of pricing, load, transmission, weather and generationdata to aid in analysis to optimize the value of AEE and ACR’s assets. Odysseymaintains a transaction management system to manage day-ahead commitments withthe NYISO and swap and physical values with counterparties and to provide dailyfinancial reporting and end of day budget variance, forward mark-to-market andcommercially accepted risk analysis.

 

Starting in 2001, until the sale of AES New Energy in the third quarterof 2002, AEE entered into bilateral contract transactions with AES New Energy, a wholly owned subsidiary of AES.  These transactions included forwardsales of electric energy and unforced capacity at market based rates. For theyears ended December 31, 2002 and 2001, AEE recognized revenues ofapproximately $13.9 million and $11.7 million, respectively, related to thephysical delivery of electricity or unforced capacity and the subsequent changein the market value of these contracts. AES New Energy was sold in the thirdquarter of 2002. As of December 31, 2002 and 2001, the related accountreceivable – trade between AES New Energy and AEE was zero and $2.6 million,respectively. The exposure at December 31, 2001 and 2002 related to thesecontract transactions was less than 10% of AEE’s estimated cash revenues forthe respective year.

 

AES contributed approximately $162,000 to AEE in 2003, related to thecost of stock options compensation expense. Also $1.5 million and $9.4 millionto AEE in 2003, 2002 and 2001, respectively, related to the cost of the stockoption compensation expense. Also, AES contributed approximately $1.5 millionand $9.4 million to AEE related to the construction of the SCR on Unit 1 of theCayuga 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. (thePlan), a defined benefit pension plan. The Plan covers people employed bothunder collectively bargained and non-collectively bargained arrangements.Certain people formerly employed by NYSEG (the Transferred Persons) receivecredit under the Plan for compensation and service earned while employed byNYSEG. The amount of any benefit payable under the Plan to a Transferred Personwill be offset by the amount of any benefit payable to such Transferred Personunder the Retirement Plan for Employees of NYSEG. Effective May 29, 1999, theability to commence participation in the Plan and the accrual of benefits underthe Plan ceased with respect to non-collectively bargained people and theaccrued benefits of any such participant were fixed as of such date. As ofDecember 31, 2003, the Plan was funded at least to the extent required byInternal Revenue Code (IRC) Section 412 minimum funding and not more than therequirement of IRC Section 404, maximum contribution limits. The Company willmake the required minimum contribution within the Employee Retirement IncomeSecurity Act (ERISA) guidelines. Pension benefits are based on years ofcredited service, age of the participant, and average earnings. During 2003,2002 and 2001, collectively bargained people were offered the opportunity tofreeze their accrued benefit payable under the Plan and opt into the AES ProfitSharing and Stock Ownership Plans.

 

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

 
|                                                    |   | **2003** |    | **2002** |   |
|---------------------------------------------------------|--------|----------|---------|----------|--------|
| Projected  Benefit Obligation                           |   |     |    |     |   |
| Change  in projected benefit obligation (in thousands): |   |     |    |     |   |
| Projected  benefit obligation, beginning of period      |   | $        | 26,780  |     | $      | 23,392 |   |
| Service  cost                                           |   | 375      |    | 347      |   |
| Interest  cost                                          |   | 1,585    |    | 1,209    |   |
| Actuarial  (gain) loss                                  |   | (1,410   | )       | —   |   |
| Benefits  paid                                          |   | (955     | )       | (305     | )      |
| Curtailment                                             |   | —   |    | (790     | )      |
| Special  Termination Loss                               |   | —   |    | 2,297    |   |
| Projected  benefit obligation, end of period            |   | $        | 26,374  |     | $      | 26,780 |   |
| Plan  Assets:                                           |   |     |    |     |   |
| Change  in plan assets (in thousands):                  |   |     |    |     |   |
| Fair  value of plan assets (in thousands):              |   | $        | 8,711   |     | $      | 6,762 |   |
| Actual  return on plan assets                           |   | 1,092    |    | (711     | )      |
| Employer  contributions                                 |   | 2,161    |    | 2,965    |   |
| Benefits  paid                                          |   | (955     | )       | (305     | )      |
| Fair  value of plan assets, end of period               |   | $        | 8,711   |     | $      | 8,711 |   |
| Funded  status/accrued benefit liability                |   | $        | (11,009 | )        | $      | (18,069 | ) |
| Unrecognized  Net (Gain)                                |   | 1,873    |    | (78      | )      |
| (Accrued)/Prepaid  Pension Cost, end of period          |   | $        | (17,238 | )        | $      | (18,147 | ) |
|                                                    |   |     |    |     |   |
| Defined  Benefit Pension Plan Costs:                    |   |     |    |     |   |
| Components  of net periodic benefit cost (in thousands) |   |     |    |     |   |
| Service  cost                                           |   | $        | 367     |     | $      | 416 |   |
| Interest  cost                                          |   | 1,611    |    | 1,451    |   |
| Expected  return on plan assets                         |   | (726     | )       | (619     | )      |
| Curtailment  gain                                       |   | —   |    | —   |   |
| Net  periodic benefit cost                              |   | $        | 1,252   |     | $      | 1,248 |   |

 

The discount rate utilizedfor determining future pension obligations is based on a review of long-termbond rates. The discount rate has remained at 6.25% since 2000. Future actualpension obligations will depend on future investment performance, changes infuture discount rates and various other factors related to the populationsparticipating in the Company’s pension plans.

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

 

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

 

Significant assumptionswere used in the calculations of the net benefit cost and projected benefitobligation for the periods ending October 31, 2003 and 2002 and December 31,2001. In developing the Company’s expected long-term rate of return assumption,the Company evaluated input from its actuaries and plan asset manager.Projected returns are based on a broad range of equity and bond indices. TheCompany’s expected 8% long-term rate of return on Qualified Plan assets isbased 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, witha 5.5% long-term rate of return. Because of market fluctuation, its actual, was58% and 52% equities and 42% and 48% in fixed income investments allocation asof October 31, 2003 and 2002, respectively. However, the Company believes thatits long-term asset allocation on average will approximate 60% equities and 40%fixed income investments. The Company regularly reviews the asset allocationwith the asset manager and periodically rebalance the Plan’s investments to itstargeted allocation when appropriate. The Company continues to believe that 8% is a reasonable long-term rateof return on its qualified plan assets, despite the market downturn. TheCompany will continue to evaluate its actuarial 

 

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

 

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

 

In 2002, the Plan wasamended to allow for an early retirement window. In August 2002, earlyretirement was offered to 56 qualified plan participants. Of the planparticipants that were eligible, 27 accepted the early retirement offer andretired from the subsidiaries of the Company effective September 1, 2002.

 

Plan Assets

 

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

 
| **Asset Category** |   | **2003** |   | **2002** |   |
|--------------------|--------|----------|--------|----------|--------|
| Equity  securities |   | 60       | %      | 60       | %      |
| Debt  securities   |   | 40       | %      | 40       | %      |

 

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

 

All three components are based primarily on historical data, withmodest adjustments to take into account additional relevant information that iscurrently available.  For the inflation and risk-free return components,the mostsignificant additional information is that provided by the market for nominaland inflation-indexed U.S. Treasury securities.  That market providesimplied forecasts of both the inflation rate and risk-free rate for the periodover which currently-available securities mature.  The historical data onrisk premiums for each asset class is adjusted to reflect any systemic changesthat have occurred in the relevant markets; e.g., the higher current valuationsfor equities, as a multiple of earnings, relative to the longer-term averagefor such valuations.

 

Cash Flows

 

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

 

Estimated Future Benefits

 

The following benefitpayments, which reflect expected future service, as appropriate, are expectedto be paid:

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

 

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

 

Other Postretirement Benefit Plan

 

On July 1, 2000, AESGreenidge adopted SFAS No. 106 “Employees’ Accounting for PostretirementBenefit Other Than Pension.”  Prioryears costs were deemed immaterial for presentation purposes. On July 1, 2003,as part of AES Greenidge’s collective bargaining agreement with theInternational Brotherhood of Electrical workers (the “IEEW”), AES Greenidgeestablished a Voluntary Employees’ Beneficiary Association(“VEBA”) to fund their retired union member’s, spouse’s and dependents’ medicalexpenses.

 

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|                                                    |   | **2002** |   |
|---------------------------------------------------------|--------|----------|--------|
| Postretirement  Medical Benefit Costs:                  |   |     |   |
| Postretirement  Benefit Costs:                          |   |     |   |
| Components  of net periodic benefit cost (in thousands) |   |     |   |
| Service  cost                                           |   | $        | 37     |   |
| Interest  cost                                          |   | 76       |   |
| Expected  return on plan assets                         |   | —   |   |
| Amortization  of:                                       |   |     |   |
| Transition  Obligation                                  |   | —   |   |
| Prior  Service Cost                                     |   | 118      |   |
| Net  Loss/Gain                                          |   | —   |   |
| Total                                                   |   | 118      |   |
| Net  Periodic Postretirement Benefit Cost               |   | $        | 231    |   |
|                                                    |   |     |   |
| Accumulated  Postretirement Benefit Obligation          |   |     |   |
| Change  in projected benefit obligation (in thousands): |   |     |   |
| Projected  benefit obligation, beginning of year        |   | $        | 1,200  |   |
| Service  cost                                           |   | 36       |   |
| Interest  cost                                          |   | 76       |   |
| Actuarial  (gain) loss                                  |   | (14      | )      |
| Benefits  paid                                          |   | 14       |   |
|                                                    |   |     |   |
| Projected  benefit obligation, end of year              |   | $        | 1,312  |   |
|                                                    |   |     |   |
| Plan  Assets:                                           |   |     |   |
| Change  in plan assets (in thousands):                  |   |     |   |
| Fair  value of plan assets, beginning of year           |   | $        | — |   |
| Unrecognized  Prior Service Cost                        |   | 1,083    |   |
| Unrecognized  Net Loss/(Gain)                           |   | (14      | )      |
|                                                    |   |     |   |
| Fair  value of plan assets, end of year                 |   | $        | 1,069  |   |
| Funded  status/accrued benefit liability                |   | $        | 243    |   |

 

Weighted average discountrate for expense calculation is 6.25% in 2002. Weighted average discount ratefor accumulated postretirement benefit obligation is 6.25% beginning December31, 2001.

 

The medical care costtrend rate is 13% for 2002, decreasing gradually to 5.0% by the year 2010. TheMedicare cost trend rate is 7.0% for 2002, decreasing gradually to 5.0% by theyear 2006. Increasing the health care trend rate by 1% would increase the totalaccumulated postretirement benefit obligation to $1,489,148 or by 15.9% and theaggregate of the total Service and Interest Cost components of the Net PeriodicPostretirement Benefit Cost would increase from $113,294 to $134,966 or by19.1%. Decreasing the health care cost trend by 1.0% would decrease the totalaccumulated postretirement benefit obligation to $1,119,110 or by 12.9% and theaggregate of the total Service and Interest Cost components of the Net PeriodicPostretirement Benefit Cost would decrease from $113,294 to $96,187 or by15.1%.

 

The Plants have created separate VEBAs to fund their retiree medicalexpenses. Employer contributions to pay the claims of the employees are deposited in the VEBATrusts. Currently, the VEBA Trusts are to pay the medical claims of theemployees who are union members and who retire from AEE and the medical claimsof their spouses and dependants. Some of the VEBA trusts offer supplementalMedicare benefits, the other Trusts’ coverage end when the employee is Medicareeligible. The AES Somerset, AES Cayuga and AES Westover VEBA trusts werecreated in 2002, and the AES Greenidge VEBA trust was created in 2003. Thefunding schedule for the trusts are as follows: (in thousands)

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

 

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9.                             LONG-TERM INCENTIVE PROGRAM

 

Stock Option Plan – Employees of the Company participate in the AESStock Option Plan (the SOP) that provides for grants of stock options toeligible participants. Prior to 2003, the Company accounted for the SOP under the recognitionand measurement provisions of APB Opinion No. 25, “Accounting for Stock Issuedto Employees,” and related Interpretations. No stock-based employee compensation cost is reflected in 2002 and 2001net income, as all options granted under the SOP in those years had an exerciseprice equal to the market value of the underlying common stock on the date ofgrant.  Effective January 1, 2003, theCompany adopted the fair value recognition provisions of SFAS No. 123,“Accounting for Stock-Based Compensation”, prospectively to all employee awardsgranted, modified or settled after January 1, 2003. Awards under the SOP vestover periods ranging from two to five years. Therefore, the cost related tostock-based employee compensation included in the determination of net incomefor 2003 is less than that which would have been recognized if the fair valuebased method had been applied to all awards from the inception of the Company.The expense recognized under the prospective method for the year ended December31, 2003 is approximately $162,000.

 

10.                       FAIR VALUE OF FINANCIAL INSTRUMENTS

 

The fair value of theCompany’s current financial assets and liabilities approximate their carryingvalues. The fair value estimates are based on pertinent information availableas of December 31, 2003. The Company is not aware of any factors that wouldsignificantly affect the estimated fair value amounts since that date.

 

11.                       SEGMENT INFORMATION

 

Under the provisions ofSFAS No. 131, “Disclosures About Segments of an Enterprise and RelatedInformation”, the Company’s business is expected to be operated as onereportable segment, with operating income or loss being the measure ofperformance measured by the chief operating decision-maker.

 

12.                       SUBSEQUENTEVENTS

 

Cashflow from AEE’s operations during the second half of 2003 was sufficient tocover the aggregate rental payments under the leases on the Somerset and CayugaPlants due January 2, 2004. On this date, rental payments were made in theamount of $31.7 million.

 

Cash flow from operations inexcess of the aggregate rental payments under the AEE’s leases may be

distributedto its partners if certain criteria are met. On January 7,2004, AEE made a distribution payment of $48.7 million.

 

AEE borrowed $12.9 million on January 9, 2004, and an additional $1million on February 20, 2004, for working capital purposes under the $35million secured revolving working capital and letter of credit facility withUnion Bank of California, N.A. The borrowings were at an interest rate of5.50%.  A partial payment of $6.2 millionwas repaid on January 27, 2004 and the remaining balance of $7.7 million wasrepaid on February 26, 2004.

 

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