AES EASTERN ENERGY LP - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

---------------

FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002
Commission file number 333-89725

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

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

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

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

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

(Title of each class)

---------------

Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

Yes X No
----- -----

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

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

Yes No X
----- -----

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

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

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

Page

PART I

Item 1 Business 2

Item 2 Properties 22

Item 3 Legal Proceedings 23

Item 4 Submission of Matters to a Vote of Security Holders 23

PART II

Item 5 Market for the Registrant's Common Equity and Related
Stockholder Matters 24

Item 6 Selected Financial Data 24

Item 7 Management's Discussion and Analysis of Financial Conditions
and Results of Operation 25

Item 7A Quantitative and Qualitative Disclosures About Market Risks 36

Item 8 Consolidated Financial Statements and Supplementary Data 37

Item 9 Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure 37

PART III

Item 10 Directors and Officers of the Registrants 38

Item 11 Executive Compensation 39

Item 12 Security Ownership of Certain Beneficial Owners And Management 40

Item 13 Certain Relationships and Related Transactions 40

Item 14 Controls and Procedures 40

PART IV

Item 15 Exhibits, Financial Statement Schedules, and Reports on Form 8-K 42

Item 1. Business

(a) General Development of Business

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

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

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

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

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

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

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

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

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

(6) the coverage ratios for each of the two semiannual rent payment
periods immediately preceding the rent payment date (based on actual
operating history) must be equal to or greater than the required
coverage ratio and the pro forma coverage ratios for each of the four
semiannual periods immediately succeeding this rent payment date must
be equal to or greater than the required coverage ratio;

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

On February 19, 2002, The AES Corporation announced that it intends to
reposition itself in the electric business by fully contracting or divesting
its merchant generation businesses. The AES Corporation said that it made this
decision to reduce earnings volatility and strengthen its balance sheet. We are
one of AES Corporation's merchant generating businesses. Our business could be
fully contracted if we were to sign one or more long-term power sales
agreements for the output of our electricity generating stations. We stated in
our Annual Report on Form 10-K for the year ended December 31, 2001 that we
were adopting a policy of not commenting on proposed transactions and we
disclaim any obligation to provide information with respect to proposed
transactions until a definitive agreement has been reached.

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

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

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

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

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

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

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

3

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

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

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

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

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

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

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

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

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

o On November 20, 2002, we signed an agreement with Union Bank of
California, N.A. for a one-year extension to January 2, 2004 of
the secured revolving working capital and letter of credit
facility . Currently, lenders have committed to provide only $15
million of the $35 million secured revolving working capital and
letter of credit facility. We are attempting to obtain
commitments for the remaining $20 million. Our financial
flexibility may be limited if we are unable to obtain these
commitments or substitute sources of credit.

o We expect that two senior members of our management team, Dan
Rothaupt and John Ruggerillo, will devote a portion of their
time to other projects for The AES Corporation.

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

4

(b) Financial Information About Industry Segments

We operate in only one business segment, electrical generation.

(c) Narrative Description of Business

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

The AES Corporation-------------
| |
AES New York AES Odyssey, L.L.C.
Funding, L.L.C.
|
AES NY Holdings, L.L.C.
|
----------------------------------------------------------------
| | |
| | |
AES NY2, L.L.C. AES NY, L.L.C. AES, NY3,
(Limited Partner) (General Partner) L.L.C.
| | |
| | |
------------------------------------------------- |
| | |
| | |
| | |
AES Eastern AES Creative Somerset
Energy, L.P. Resources, L.P. Railroad
| | Corp.
| |
-------------------------------- ----------------
| | | | |
| | | | |
AES AES AEE 2, AES AES
Somerset, Cayuga, L.L.C. Jennison, Hickling,
L.L.C. L.L.C. | L.L.C. L.L.C.
(Somerset) (Cayuga) |
-------------
| |
| |
AES AES
Westover, Greenidge,
L.L.C. L.L.C.
(Westover) (Greenidge)

The AES Corporation

The AES Corporation is a leading global power company committed to
supplying electricity in a socially responsible way. The AES Corporation is a
public company and is subject to the informational requirements of the
Securities Exchange Act of 1934 and, in accordance therewith, files reports,
proxy statements and other information, including financial reports, with the
SEC, which are not incorporated into and do not form a part of this Form 10-K.

5

New York Power Market

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

In July 2001, the Federal Energy Regulatory Commission directed the
NYISO and adjacent power market operators to engage in a 45-day mediation
process to form one regional transmission organization for the northeastern
region. The participants released a business plan on September 17, 2001. On
January 28, 2002 the NYISO and ISO New England(ISO-NE) entered into an
agreement to develop a plan to establish a common market design for a regional
transmission organization. On November 22, 2002, the Boards of Directors for
the ISO-NE and the NYISO withdrew their joint petition to the Federal Energy
Regulatory Commission(FERC) proposing the creation of a Northeast Regional
Transmission Organization for the seven-state northeast region. We cannot
predict if a regional transmission organization will be created or what effect
the creation of such an organization might have on the markets in which we do
business.

On July 31, 2002, FERC issued Standard Market Design Notice of
Proposed Rulemaking. It proposes among other things to establish a single
flexible transmission service, Network Access Service, with a single open
access transmission tariff that applies to all transmission customer-
wholesale, unbundled retail and bundled retail and a standard market design for
wholesale electric markets. On January 13, 2003, FERC announced that it will
issue a white paper on the proposed standard market design in April 2003. FERC
has not set a date for issuance of the standard market design final notice of
proposed rule making. We cannot predict the outcome or actual implementation
date of this final rule proceeding or the effect it will have on the markets in
which we do business.

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

The transmission of electricity between states and between regions
within New York State is constrained by physical limits on transmission
capacity and limits on the amount of electricity that may be imported into a
power pool imposed by power pools to enhance reliability. Therefore, the
generating assets in any given region have a competitive advantage in that
region over generators not in the region. There is an existing natural market
for the unforced capacity and the electric energy of our electricity generating
stations in Western New York, which includes the retail service territories of
NYSEG, Niagara Mohawk Power Corporation and Rochester Gas & Electric
Corporation. The existing transmission infrastructure also permits us to access
neighboring markets. However, our ability to sell electric energy into
neighboring markets is limited by constraints imposed by transmission capacity
limitations and limits on imported electricity imposed by power pools in those
markets for reliability considerations. Until April 30, 2003, our ability to
sell electric energy into neighboring markets is also limited because we have
entered into bilateral contracts for the sale of a substantial portion of our
unforced capacity to load serving entities, i.e., an entity selling electric
energy to consumers of electric energy, including regulated distribution
utilities, municipalities and energy supply companies, in New York.

6

We entered into an arrangement with AES Odyssey, L.L.C. ("Odyssey"), a
direct wholly-owned subsidiary of The AES Corporation, for power marketing
services. This agreement commenced on November 27, 2000 . The initial term of
the agreement was for a term of three years. In March 2002, a new agreement was
reached, for a term of five years through February 28, 2007 pursuant to which
Odyssey provides data management, marketing, scheduling, invoicing and risk
management services for a fee of $300,000 per month. Odyssey acts as agent on
behalf of us in the over-the-counter and NYISO markets.

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

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

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

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

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

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

7

Unforced Capacity Market. A market in which electricity generators can
sell commitments of their unforced generating capacity has been established to
ensure there is enough generation capacity available to produce sufficient
electric energy to meet retail demand and ancillary service requirements. Any
load serving entity is required to procure capacity commitments sufficient to
meet its capacity requirements based on its forecasted annual electric energy
requirements at times of maximum usage plus a reserve requirement. Currently,
each load serving entity is required to purchase unforced capacity commitments
equal to approximately 112% of its forecasted annual maximum usage. The load
serving entity can secure these capacity commitments through a bilateral
contract or through unforced capacity auctions. Any capacity commitment which
is not procured locally needs to satisfy the requirement that, as an import, it
does not violate transmission constraints. Starting with the 2001 - 2002 Winter
Capability Period, the NYISO implemented a revised capacity market design in
the New York control area that employs unforced capacity as the measure of the
capacity of a generator rather than the old measure of installed capacity.
Unforced capacity factors in the probability that a generator will be available
to serve load. Unforced capacity is the demonstrated maximum output of a
generator(installed capacity) with a formula applied that takes into account a
generator's forced outage rate over a defined period of time.

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

AES NY, L.L.C. and NYSEG entered into a New York Transition Agreement,
dated as of August 3, 1998, to ease the transition of NYSEG's native load
customers' installed capacity requirements. Under this agreement, NYSEG agreed
to purchase, and AES NY, L.L.C. agreed to sell, installed capacity in the
amount of 1,424MW (which is the aggregate capacity of all of the generating
assets included in the assets acquired from NYSEG) for the term of the
agreement. AES NY, L.L.C. assigned this agreement to us insofar as it related
to our electricity generating stations. The parties performance under the
agreement commenced on May 14, 1999 and terminated on April 30, 2001. Since
this agreement terminated, we have entered into bilateral contracts with a
number of parties for the substantial portion of our unforced capacity through
April 30, 2003.

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

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

Transmission System Market. Transmission lines in New York are
controlled by the NYISO. Transmission access is available to all market
participants on a comparable and non-discriminatory basis. A party transmitting
electric energy through or out of New York State pays the NYISO a transmission
service charge to cover the revenue requirements of the transmission owner.
Electric energy sold under

8

a bilateral contract is subject to a congestion charge. The congestion charge
reflects the differences between the LBMP at the source and destination on the
transmission system. Parties can hedge their exposure to congestion charges
through transmission congestion contracts which are auctioned biannually.

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

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

9

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

Fuel Supply

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

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

The Electricity Generating Stations

We believe that our two principal coal-fired electricity generating
stations, Somerset and Cayuga, are among the lowest variable cost facilities in
the New York power market. We expect them to be fully dispatched when available
in the deregulated and competitive New York power market. As a means of further
enhancing the competitive position of our electricity generating stations in
the New York power market, we expect to use expertise of The AES Corporation as
a major operator of coal-fired facilities on a worldwide basis. We also intend
to make appropriate investments of capital to maintain our electricity
generating stations. Somerset, Cayuga, Westover and Greenidge have an aggregate
net generating capacity of 1,268MW.

The Somerset Generating Station

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

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

The Cayuga Generating Station

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

10

currently has a net generating capacity of 150MW. Unit 2 currently has a net
generating capacity of 156MW.

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

Westover Generating Station

Westover is located alongside the Susquehanna River near Johnson City,
New York, and began generating electricity in the early 1900's. Units 1 through
6 have been retired and physically removed. Westover presently consists of two
units, Unit 7 and Unit 8, with a combined maximum net generating capacity of
126MW.

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

Greenidge Generating Station

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

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

Regulation

Energy Regulatory Matters

General

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

11

Federal Energy Regulation

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

Pursuant to the Federal Power Act, all public utilities subject to
FERC's jurisdiction are required to obtain FERC's acceptance of their rate
schedules in connection with the wholesale sale of electricity.

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

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

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

Lease Transactions Filings and Approvals. As conditions to completion
of the lease transactions relating to Somerset and Cayuga, we and the
appropriate financial participants in the lease transactions were required to
obtain certain approvals from FERC. We obtained all of our approvals, including
authorization to sell wholesale electric energy under our market-based rate
schedule and related waivers and blanket authorization. We believe that the
special purpose business trusts have obtained all energy-related approvals
required to be obtained by them. The special purpose business trusts have been
included in the approval by FERC of the transfer of jurisdictional facilities
and the acquisition and leaseback of FERC-jurisdictional facilities, and FERC
has granted a disclaimer of jurisdiction over each of the institutional
investors and the special purpose business trusts and the trustees of those
trusts as public utilities under Part II or III of the Federal Power Act. The
special purpose business trusts have received determinations from FERC that
they are exempt wholesale generators. The special purpose business trusts

12

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

13

Environmental Regulatory Matters

General

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

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

o limits on noise emissions from our electricity generating
stations;

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

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

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

It is likely that the stringency of environmental regulations
affecting us and our operations will increase in the future. In the meantime,
we will monitor potential regulatory developments that may impact our
operations and we will participate in rulemaking proceedings applicable to our
operations when we consider it advisable to do so. We do not expect any
proposed regulations to have a material adverse effect on our operations or our
financial condition.

On February 14, 2002, the Bush Administration issued its
multi-pollutant proposal called "Clear Skies". This proposal would regulate the
emission of SO2, NOx and mercury. We have not determined the effect of the
Clear Skies or any other pending regulation or legislation.

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

Air Emissions

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

Sulfur Dioxide (SO2). SO2 emissions are regulated under Title IV of
the federal Clean Air Act Amendments and by the New York Acid Deposition
Control Act. One of the primary goals of Title IV of the Amendments was to
reduce SO2 emissions

14

by 10 million tons from 1980 levels. The SO2 emission reduction requirements
generally apply to almost all fossil-fuel fired electric generating units
producing electricity for sale. Power plants subject to Title IV are required
to obtain acid rain permits, to hold sufficient emission allowances to cover
their SO2 emissions, and to comply with various monitoring and record-keeping
requirements. The federal SO2 requirements were implemented in two
phases--Phase I applies to the 110 plants listed in section 404 of the Act and
Phase II generally affects all other fossil-fuel fired electric generating
plants selling over 25MW to the electricity distribution grid. Phase I of the
federal Clean Air Act Amendments SO2 program went into effect January 1, 1995,
with Cayuga Unit 1 and Unit 2 and Greenidge Unit 4 falling under the program.
Phase II went into effect January 1, 2000 and affects all the units.

FGD systems are operated at both Somerset and Cayuga to reduce total
SO2 emissions from these plants to quantities substantially below the Title IV
SO2 "allowance" allocations for the units at these plants. An allowance is a
freely transferable right to emit one ton of a substance, in this case, SO2.
The excess allowances are accumulated and can either be used for our other
electricity generating stations or sold to provide liquidity to us. We may sell
SO2 allowances rather than save them for Phase II of Title IV of the federal
Clean Air Act Amendments. During Phase II, we may need to purchase SO2
allowances to cover SO2 emissions for Greenidge and Westover. Market prices for
SO2 allowances currently range from about $140 to $160 per ton. We were self
sufficient with respect to SO2 allowances in 2001, however we had a shortfall
of approximately 6,000 SO2 allowances in 2002. The majority of the SO2
allowance shortfall was covered with allowances purchased from the electricity
generating stations owned by our affiliate , AES Creative Resources, L.P.
(ACR), which are on long-term cold standby. The allowances were purchased at
quoted market prices.

On October 14, 1999, New York Governor Pataki announced a new
initiative which directs the New York State Department of Environmental
Conservation ("NYSDEC")to issue regulations requiring electric generators to
reduce SO2 emissions by another 50% below Phase II standards. The NYSDEC issued
final regulations in March 2003. The final regulations call for the new SO2
reduction regulations to be phased in starting on January 1, 2005 with
implementation completed by January 1, 2008. If adopted, the final regulations
will require further SO2 reductions at our electric generating stations and may
necessitate that either additional SO2 emission controls be installed, lower
sulfur coal be utilized, operations of our non-reheat units be reduced or
surplus SO2 allowances be purchased. We are not currently in a position to
quantify the potential costs of complying with the proposed regulations;
however, the costs of compliance could be substantial. The final regulations
are set to be voted upon by the New York State Environmental Board on March 26,
2003.

In addition, we received an information request letter dated October
12, 1999 from the New York Attorney General which sought detailed operating and
maintenance history for Westover and Greenidge. On January 13, 2000, we
received a subpoena from the NYSDEC seeking similar operating and maintenance
history for all four of our electricity generating stations. We have provided
materials responding to the requests from the Attorney General and the NYSDEC.
This information was sought in connection with the Attorney General's and the
NYSDEC's investigations of several electric generation stations in New York
which are suspected of undertaking modifications in the past (from as far back
as 1977) without undergoing an air permitting review.

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

15

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

We are currently in negotiation with both the EPA and NYSDEC. If our
current proposal is rejected, the EPA and the NYSDEC could issue a notice or
notices of violation (NOV) to us for violations of the Clean Air Act and the
Environmental Conservation Law. If the Attorney General, the DEC or the EPA
does file an enforcement action against our Somerset, Cayuga, Westover, or
Greenidge Plants, then penalties may be imposed and further emission reductions
might be necessary at these Plants which could require us to make substantial
expenditures. We are unable to estimate the effect of such a NOV on our
financial condition or results of future operations.

We voluntarily disclosed to the NYDEC in January 2003 that Cayuga had
inadvertently burned synfuel (coal with a latex binder applied), which it is
not permitted to burn. Cayuga had entered into an agreement with a supplier to
purchase coal. It received approximately one 9000-ton train per month from
April 24, 2001 to December 27, 2002. In January 2003, we became aware that the
product we were receiving was synfuel. We have suspended all shipments from
that supplier until a resolution is reached. We have reviewed the emission and
operation data which showed there was no adverse effect to air quality
attributable to burning the material and the plant's emmissions were in
compliance with applicable permit emissions limits. We are unable to predict
any potential actions or fines the NYSDEC may require, if any.

Nitrogen Oxides (NOx). New York State and the other states in the
Mid-Atlantic and Northeast region are classified as the Ozone Transport Region
in the federal Clean Air Act, which designates the Ozone Transport Region as
not being in compliance with the ozone National Ambient Air Quality Standard.
The states in the Ozone Transport Region have agreed to implement a three-phase
process to reduce NOx emissions in the region in order to comply with the
federal Clean Air Act Title I requirements for ozone non-compliance areas.
NYSEG complied with Phase I through operational modifications to reduce NOx
emissions, reduction of electric output from selected generating units to
reduce emissions to cap levels, and installation of NOx reduction equipment on
selected generating units.

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

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

Implementation of the Phase III emission rules will commences on May
1, 2003. The Phase III NOx regulations set forth a NOx allowance allocation
program which gives us 2,516 NOx emission allowances for 2003.

To comply with the stricter emissions regulations beginning in 1999,
we installed a SCR system at Somerset which became operational in June 1999.
During 2001, we installed a SCR system on Unit 1 of Cayuga, which became
operational on June 7, 2001.

16

Somerset generated excess allowances in 2002, 2001 and 2000. Cayuga
generated excess allowances on Unit 1 during the 2002 and 2001 ozone seasons.
We expect that Somerset and Cayuga will accumulate excess allowances during the
2003 ozone season at a lower rate due to the reduced allocation of allowances
under Phase III of the NOx reduction program. Our compliance strategy involves
potential installation of additional NOx control technology at our electricity
generating stations, reduced operations of our non-reheat units during the
ozone season, reducing emission rates and/or the selling/buying or trading of
NOx allowances. This includes trades between our electricity generating
stations as needed to offset NOx emissions. During 2002 and 2001, we were a net
seller of NOx allowances.

New York Governor Pataki's October 14, 1999 initiative also directs
the NYSDEC to issue regulations requiring electric generators to impose
stringent NOx reduction requirements during the seven months not covered by the
summertime ozone season. The NYSDEC issued final regulations in March 2003. The
final regulations call for implementation the new NOx regulations to be in
effect starting on October 1, 2004. The final regulations are set to be voted
upon by the New York State Enviromental Board on March 26, 2003. If adopted,
the final regulations have the potential to require further NOx emission
reductions at our electricity generating stations and may necessitate the
installation of additional NOx emission controls be installed, operations of
our non-reheat units be reduced or surplus New York State NOx allowances be
purchased. We are not currently in a position to quantify the potential costs
of complying with the NOx requirements of the proposed regulations; however,
the costs of compliance could be substantial.

The capital cost of the Somerset SCR was $31 million. We expect that
the system will operate for 20 years. We will need to replace the catalyst
approximately every three years at an estimated cost of approximately $4.5
million in 1999 dollars. The capital cost of the Cayuga SCR on Unit 1 was $11.2
million and it was operational on June 7, 2001. We expect that the system will
operate for 20 years. We will need to replace the catalyst approximately every
four years at an estimated cost of approximately $325,000 in 2001 dollars.

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

A one-time violation of the facility-wide NOx emission cap in May
1998. We believe that, under the Asset Purchase Agreement with NYSEG, any
penalty assessed for that exceedence would be the responsibility of NGE
Generation, Inc.

We voluntarily disclosed to the NYSDEC and EPA on November 27, 2002
that NOx exceedances appear to have occurred on October 30 and 31 and November
1-8 and 10 of 2002. The exceedances were discovered through an audit by plant
personnel of the electricity generating stations' NOx RACT tracking system. The
plants have taken all reasonable, good faith efforts to assess and correct the
exceedances. Immediately upon discovery of the calculation error, the SCR at
Somerset was activated to reduce NOx emissions. Emission data indicates that
the system had already returned to a compliant operation by the time the error
was discovered. The EPA has decided to defer to the NYSDEC for review of the
self-disclosure letter and technical issues. We are unable to predict any
potential actions or fines the NYSDEC may require, if any.

On October 16, 2001, Greenidge was awarded a Federal Clean Coal Grant
that, if accepted, will fund 50% of the capital costs for backend technology
and 30% of the operations and maintenance costs for a test and demonstration
period. This technology will include a single bed, in-duct Selective Catalytic
Reduction (SCR) unit in combination with low-NOX combustion technology, on
Greenidge Unit 4 firing on coal and biomass. It will also include a Circulating
Dry Scrubber (CDS) for SO2, mercury and acid gas removal. Greenidge's share of
the project's costs will be approximately $9.8 million. Greenidge has submitted
a written request to the Department of Energy, which administers the Clean Coal
program, for a 12 to 18 month delay in starting the grant. This request was
made in light of the current difficult electricity and credit markets and the
uncertain state regulatory environment. Westover is also in the process of
installing overfire air to control NOx.

17

Particulates and Opacity. Each of our electricity generating stations
is currently in compliance with particulate emission limits.

Each of our electricity generating stations is required to meet an
opacity limit. In the past, several of the plants exceeded these limits. This
was a common problem at coal-fired electricity generating stations, and the
NYSDEC has initiated an enforcement action against several utilities, including
NYSEG. Potential fines and required actions cannot be divulged to the public
until a final settlement is reached. Nevertheless, we expect that any consent
order will likely require continued operation at the current level of opacity
compliance that has been achieved over the past year.

In January 2000, we received a draft consent order from the NYSDEC
that alleges violations of the opacity emission limitations in the air permits
for Cayuga, Westover, and Greenidge occurring since our electricity generating
stations were purchased from NYSEG. The draft consent order would require us to
prepare an opacity compliance plan and would impose penalties for opacity
violations occurring after May 14, 1999, the date of the acquisition. We expect
to enter a final consent order with the NYSDEC in 2003. AES NY, L.L.C. also
received notice from NYSEG that NYSEG has received a draft consent order from
the NYSDEC seeking penalties primarily for opacity violations occurring prior
to May 14, 1999. In the notice, NYSEG asserts that it will seek indemnification
from AES NY, L.L.C. for any penalties, attorney fees, and related costs that it
incurs in connection with the consent order. We and AES NY, L.L.C. have denied
liability for the pre-closing violations and intend to vigorously defend this
claim if NYSEG pursues litigation or arbitration.

Mercury. In 2000, the EPA determined that regulation of mercury
emissions from the nation's coal-fired power plants is necessary. The
regulations will be developed over the coming years, with a final rule
scheduled to be promulgated in December 2004, and compliance under the new rule
expected for December 2007. At this point we cannot determine what the costs
would be to comply with mercury control regulations.

Carbon Dioxide (CO2). Environmental concerns related to the impacts of
greenhouse gases (e.g., carbon dioxide, "CO2") led to the adoption in 1992 of
the United Nations-sponsored Framework Convention, which was ratified by over
150 countries, including the United States. In 1993, President Clinton
committed the United States to limit CO2 and other climate-altering gas
emissions to their 1990 levels by the year 2000. However, it became apparent
that this goal was unlikely to be met by most industrialized nations. The Kyoto
Conference was called in December 1997 to expedite a global climate treaty
supported by the United States. If adopted by the participating nations, any
legally binding global climate treaty will have significant economic
consequences for all U.S. industries, including the electricity generating
industry.

The Bush Administration has indicated that the United States will not
implement the Kyoto Protocol. On February 14, 2002, President Bush announced
his Global Climate Change Initiative which calls on U.S. industry to commit to
voluntary greenhouse gas emission reductions and directs the U.S. Department of
Energy to implement an improved verifiability system for the existing voluntary
emission reductions registry and to develop transferable credits for verifiable
reductions.

Water Issues

The federal Clean Water Act prohibits the discharge of any
pollutant (including heat), except in compliance with a discharge permit issued
by the states or the federal Environmental Protection Agency for a term of no
more than five years. There is potential uncertainty with permitting issues in
the future, but much of the uncertainty on these issues is industry-wide
because of new regulatory requirements for cooling water discharges under the
National Pollutant Discharge Elimination System program. In April 2002, the EPA
proposed to establish location, design, construction and capacity standards for
cooling water intake structures at existing power plants. The EPA is developing
these regulations under the terms of an Amended Consent Decree in Riverkeeper,
Inc vs. Whitman, US District Court, Southern

18

District of New York. It has been repeated that the issuance of the final for
existing facilities has been extended by six months to February 16, 2004. These
new rules will impose new compliance requirements, with potentially significant
costs, on operating plants across the nation. Cost items include various
environmental and engineering studies, and potential capital and maintenance
costs. We have not determined the effects of these regulations on our financial
condition.

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

Hazardous Material and Wastes

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

We have budgeted $9.8 million for the cost for environmental
liabilities at our electricity generating stations (excluding closure and
post-closure costs for the Weber and Lockwood ash disposal sites), based on
estimates of environmental consultants retained by NYSEG and The AES
Corporation. We have budgeted approximately $6 million for closure and
post-closure (monitoring and maintenance) expenses for the Lockwood ash
disposal site, based solely on amounts previously budgeted for these activities
by NYSEG. AES Creative Resources, L.P.("ACR") assumed responsibility for the
Weber ash disposal site. Our subsidiary, AEE2, L.L.C., has contributed one-half
of the closure costs for the Weber ash disposal site based on the amount of ash
disposed at the site from Westover and Greenidge, which are owned by AEE2,
L.L.C., compared to the amount disposed from the Hickling Generating
Station("Hickling") and the Jennison Generating Station("Jennison"), which were
acquired by ACR.

In October 1999, ACR entered into a consent order with the NYSDEC to
resolve alleged violations of the water quality standards in the groundwater
downgradient of the Weber ash disposal site. The consent order included a
suspended $5,000 civil penalty and a requirement to submit a work plan to
initiate closure of the landfill by October 8, 2000. The consent order also
called for a site investigation, which was conducted and indicated that there
is a possibility that some groundwater remediation at the site may be required.
Further compliance with this order included a Closure Investigation Report
which was submitted to the NYSDEC in the spring of 2000, and a Closure Plan
which was submitted to the NYSDEC in January 2001. The Closure Plan was
implemented in December 2001 when capping of the site was completed. AEE2,
L.L.C. contributed one-half of the costs to close the landfill, which were
approximately $2 million, and it will contribute additional costs for long-term
groundwater monitoring. Nevertheless, if a groundwater remediation is required,
AEE2, L.L.C. may be responsible for a portion of such costs.

We expect to develop a new area, Area 3, of the on-site landfill
located at Somerset to contain ammonia-contaminated fly ash produced during
operation of the SCR system and stabilized sludge produced during simultaneous
operation of the FGD

19

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

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

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

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

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

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

Exceedences of state groundwater standards at Cayuga were reported in
the vicinity of the coal pile area, the coal pile runoff pond, and the ash
disposal site. In 1997, a new liner was installed under the coal pile, which
brought Cayuga within state groundwater standards.

20

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

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

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

Noise

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

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

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

People

As of December 2002, we employed 288 people who operate our
electricity generating stations. The International Brotherhood of Electrical
Workers (the "IBEW") represents hourly labor at Somerset, Cayuga, Westover and
Greenidge. The IBEW represents approximately 240 workers. We have negotiated
collective bargaining agreements with respect to each electricity generating
station, on an individual electricity generating station basis. This gives us
continuing labor harmony and encourages the adoption of The AES Corporation's
culture by emphasizing individual businesses with responsibility and ownership
of local issues. We believe that relations with the people employed at our
electricity generating stations are satisfactory.

21

Item 2. Properties

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

Electricity
Generating Station Location Capacity Owned or Leased Expiration of
Lease
- ------------------ ---------------- ---------- --------------- -------------------

Somerset Barker, NY 675MW Leased* February 13, 2033

Cayuga Lansing, NY 306MW Leased* November 13, 2027

Westover Johnson City, NY 126MW Owned Not Applicable

Greenidge Dresden, NY 161MW Owned Not Applicable

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

Item 3. Legal Proceedings

We received an information request letter dated October 12, 1999 from
the New York Attorney General which sought detailed operating and maintenance
history for Westover and Greenidge. On January 13, 2000, we received a subpoena
from the NYSDEC seeking similar operating and maintenance history for all four
of our electricity generating stations. We have provided materials responding
to the requests from the Attorney General and the Department of Environmental
Conservation. This information was sought in connection with the Attorney
General's and the Department of Environmental Conservation's investigations of
several electricity generating stations in New York which are suspected of
undertaking modifications in the past (from as far back as 1977) without
undergoing an air permitting review.

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

By letter dated May 25, 2000, the NYSDEC issued a Notice of Violation
(NOV) to NYSEG for violations of the Clean Air Act and the Environmental
Conservation Law at Greenidge and Westover related to NYSEG's alleged failure
to obtain an air permitting review for repairs and improvements made during the
1980s and 1990s, which was prior to the acquisition of the electricity
generating stations by us. Pursuant to the Asset Purchase Agreement relating to
the acquisition of the electricity generating stations from NYSEG, we agreed to
assume responsibility for environmental liabilities that arose while NYSEG
owned the electricity generating stations. On September 12, 2000, we agreed
with NYSEG that we will assume the defense of and responsibility for the NOV,
subject to a reservation of our right to assert applicable exceptions to our
contractual undertaking to assume preexisting environmental liabilities. The
financial and operational effect of this NOV is still being discussed with the
NYSDEC.

22

We are currently in negotiation with the both EPA and NYSDEC. If our
current proposal is rejected, 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
New York Environmental Conservation Law. If the Attorney General, the DEC or
the EPA does file an enforcement action against our Somerset, Cayuga, Westover,
or Greenidge Plants, then penalties may be imposed and further emission
reductions might be necessary at these Plants which could require us to make
substantial expenditures. We are unable to estimate the effect of such a NOV on
our financial condition or results of future operations.

In January 2000, we received a draft consent order from the NYSDEC
that alleges violations of the opacity emission limitations in the air permits
for Cayuga, Westover, and Greenidge occurring since we acquired our electricity
generating stations from NYSEG. The draft consent order would require us to
prepare an opacity compliance plan and would impose penalties for opacity
violations occurring after May 14, 1999, the date of the acquisition. We expect
to enter a final consent order with the NYSDEC in 2003. AES NY, L.L.C. also
received notice from NYSEG that NYSEG has received a draft consent order from
the NYSDEC seeking penalties primarily for opacity violations occurring prior
to May 14, 1999. In the notice, NYSEG asserts that it will seek indemnification
from AES NY, L.L.C. for any penalties, attorney fees, and related costs that it
incurs in connection with the consent order. We and AES NY, L.L.C. have denied
liability for the pre-closing violations and intend to vigorously defend this
claim if NYSEG pursues litigation or arbitration.

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

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

Not applicable.

23

PART II

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

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

Item 6. Selected Financial Data

As of December 31, 2002 2001 2000 1999
- ----------------------------------------- -------- -------- --------- --------

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

- ----------------------------------------------------------------------------------------

For the period ending December 31, 2002 2001 2000 1999
- ----------------------------------------- -------- -------- ---------- ---------
Statement of Income Data (in millions)
Operating revenue $ 363 $ 378 $ 388 $ 185
Operating income $ 114 $ 106 $ 151 $ 57
Net income $ 59 $ 52 $ 98 $ 24

SELECTED QUARTERLY FINANCIAL DATA

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

First Second Third Fourth
Quarter Quarter Quarter Quarter
-------- -------- -------- ----------

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

YEAR ENDED DECEMBER 31, 2001:
Operating revenue $111,405 $ 69,681 $ 88,657 $108,605
Operating income 49,391 12,294 25,083 19,671
Net income 35,455 (1,406) 11,822 5,994

YEAR ENDED DECEMBER 31, 2000:
Operating revenue $ 80,096 $ 89,613 $ 97,219 $120,638
Operating income 27,183 30,745 35,403 57,958
Net income 12,115 15,903 24,552 45,667

PERIOD FROM MAY 14, 1999 (INCEPTION)
TO DECEMBER 31, 1999:
Operating revenue N/A $ 17,225 $103,618 $ 63,725
Operating income N/A 3,141 43,628 10,269
Net income N/A 578 27,730 (3,893)

24

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

General

The information in this Management's Discussion and Analysis should be
read in conjunction with the accompanying consolidated financial statements,
the related Notes to the Financial Statements and the selected financial data.
Forward looking statements in this Management's Discussion and Analysis are
qualified by the cautionary statement in the Forward Looking Statements section
of the Management's Discussion and Analysis.

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

On February 19, 2002, The AES Corporation announced that it intends to
reposition itself in the electric business by fully contracting or divesting
its merchant generation businesses. The AES Corporation stated that it made
this decision to reduce earnings volatility and strengthen its balance sheet.
We are one of the merchant generating businesses. Our business could be fully
contracted if we were to sign one or more long-term power sales agreements for
the output of our electricity generating stations. We stated in our Annual
Report on Form 10-K for the year ended December 31, 2001 that we were adopting
a policy of not commenting on proposed transactions and we disclaim any
obligation to provide information with respect to proposed transactions until a
definitive agreement has been reached.

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

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

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

Our electricity generating stations have historically been available
to run a high percentage of the time due to the regulated utility-grade nature
of their design and construction. In 2002, 2001 and 2000, the stations had a
weighted average (based on capacity) equivalent availability factor of 96%, 96%
and 94%, respectively (excluding the outage at Cayuga from April to June 2001).
Based upon the historical experience of The AES Corporation, we believe that we
can maintain or improve the availability of our electricity generating
stations.

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

25

permitted to sell unforced capacity through bilateral contracts or through
unforced capacity auctions or into other markets. See "Business--New York Power
Market."

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

If NYSEG is successful in obtaining substantial refunds of prior real
estate taxes, our potential savings may be to some extent nullified because the
local governments may be forced to raise real estate tax rates to bring
revenues into balance with expenditures. It is too early to tell what impact,
if any, this will have on our financial condition and results of operations.

Critical Accounting Policies

General

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

Revenue Recognition

Revenues from the sale of electricity are recorded based upon output
delivered and rates specified under contract terms. Revenues generated from the
hedging of future sales using commodity forwards, swaps and options are
recorded based on settlement accounting with the net amount received recognized
as revenue. Revenues for ancillary and other services are recorded when the
services are rendered. The Transmission Congestion Contract is not deemed to be
a hedge based on the definitions in SFAS 133. Therefore, this contract is
marked to market at the end of every period. The mark-to-market value is
computed based on a regression of historical eastern and western locational
prices. This regression is used with forecasted eastern and western locational
prices to calculate the forward congestion for the remainder of the contract
term. This accounting treatment contributes to the income statement volatility
of this contract.

Property, Plant and Equipment

Electric generation assets that existed at the date of acquisition
(see Note 3) were recorded at fair market value. Somerset and Cayuga, which
represent $650 million of the electric generation assets, are subject to a
leasing arrangement accounted for as a financing (see Note 6). Additions or
improvements thereafter are recorded at cost. Depreciation is computed using
the straight-line method over the 34-year and 28.5-year lease terms for
Somerset and Cayuga, respectively, and over the estimated useful lives for the
other fixed assets, which range from 7 to 35 years. A significant overabundance
of supply and a sustained, significant decline in market prices to below our
variable cost could cause a decrease in the estimated useful lives of our
electric generation assets. If the useful life of any of our property, plant
and equipment is changed, the new life would be based on engineering studies
and expected usage. The estimated average remaining useful life of our
property, plant and equipment is approximately 23 years. If the estimated
average remaining life of our property, plant and equipment were to decrease
by five years, annual depreciation would increase by $7.7 million. Maintenance
and repairs are charged to expenses as incurred.

Contingencies

We accrue for loss contingencies when the amount of the loss is
probable and estimable. We are subject to various environmental regulations,
and we are involved in certain legal proceedings. If our actual environmental
and/or legal obligations are

26

materially different from our estimates, the recognition of the actual amounts
may have a material impact on our operating results and financial condition.

Derivatives

On January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," which, as amended, established
new accounting and reporting standards for derivative instruments and hedging
activities. SFAS 133 requires that all derivatives (including derivatives
embedded in other contracts) be recorded as either assets or liabilities at
fair value on the balance sheet. Changes in the derivative's fair value are to
be recognized in earnings in the period of change, unless hedge accounting
criteria are met. Hedge accounting allows the derivative's gains or losses in
fair value to offset the related results of the hedged item. We utilize
derivative financial instruments to manage commodity price risk. Although the
majority of our derivative instruments qualify for hedge accounting, the
adoption of SFAS No. 133 may result in more variation to our results of
operations from changes in commodity prices. We have chosen to use the
hypothetical derivative methodology for testing whether our hedges meet the
criteria to qualify for hedge accounting treatment. A historical regression is
performed between the plants, delivery points into the NYISO and the NYISO zones
in which the hedges are settled. Comparing the results of the historical
regression and the actual changes in the market value of the hedges determines
if the hedges qualify for hedge accounting criteria treatment. For the years
ended December 31, 2002, 2001 and 2000 we recognized income of $8.9 million, a
loss of $29.5 million and income of $24.9 million, respectively, pursuant to
SFAS No. 133 related to derivatives which did not qualify for hedge accounting.
See Note 7 to the consolidated financial statements for a more complete
discussion of the accounting for derivatives under SFAS No. 133.

Results of Operations
---------------------
(Amounts in Millions)
% %
For the Year Ended December 31, 2002 2001 Change 2000 Change
------ ------ ------- ------ -------
Energy Revenue $310.6 $345.4 (10.1) $322.7 7.0

Capacity Revenue 36.6 26.8 36.6 31.6 (15.2)

Transmission Congestion Contract 8.9 - - 24.9 -

Other 6.9 6.2 11.3 8.5 (27.1)

Energy revenues for the year ended December 31, 2002 were $310.6
million, compared to $345.4 million for the year ended December 31, 2001, a
decrease of 10.1%. The decrease in energy revenues is primarily due to lower
market prices and lower demand. Market prices for peak and offpeak electricity
were 12.2% and 6.5% lower than for the year ended December 31, 2001. Demand for
peak and offpeak electricity was 3.2% and 1.7% lower than the year ended
December 31, 2001. Energy revenues for the year ended December 31, 2001 were
$345.4 million, compared to $322.7 million for the year ended December 31,
2000, an increase of 7.0%. The increase in energy revenues from 2000 to 2001 is
primarily due to higher market prices in the first half of the year and higher
operating levels during that time. These were offset by a major maintenance
outage at Cayuga of approximately 45 days for Unit 1 in 2001.

Capacity revenues for the year ended December 31, 2002 were $36.6
million, compared to $26.8 million for the year ended December 31, 2001, an
increase of 36.6%. The increase in capacity revenue is primarily due to higher
prices for capacity sales on the open market for the summer capacity period
(June - October) offset by the expiration of a long-term capacity contract in
April 2001. Capacity sales on the open market for the winter capacity period
(November-May) were at lower rates. Capacity revenues for the year ended
December 31, 2001 were $26.8 million, compared to $31.6 million for the year
the December 31, 2000, a decrease of 15.2%. The decrease in capacity revenue
from 2000 to 2001 is primarily due to the expiration of a long-term capacity
purchase agreement with NYSEG in April 2001. Capacity sales on the open market
for the winter capacity period (November-May) were at lower rates.

The Transmission Congestion Contract is essentially a swap between the
congestion component of the locational prices posted by the NYISO in western
New York and the more populated areas in eastern New York. The Transmission
Congestion Contract became effective on November 1, 2000 and terminates on
October 1, 2004. We entered into this agreement because

27

it provided a reasonable settlement for resolving a FERC dispute between us and
Niagara Mohawk Power Corporation. This contract is not deemed to be a hedge
based on the definitions in SFAS 133. Therefore, this contract is marked to
market at the end of every period. The mark-to-market value is computed based
on a regression of historical eastern and western locational prices. This
regression is used with forecasted eastern and western locational prices to
calculate the forward congestion for the remainder of the contract term. This
accounting treatment contributes to the income statement volatility of this
contract.

Operating Expenses
- -------------------- % %
For the Year Ended December 31, 2002 2001 Change 2000 Change
------ ------ ------- ------ ------
Fuel expense $137.2 $135.6 1.2 $131.7 3.0

Depreciation and amortization 35.5 33.6 5.7 31.7 6.0

Operations and maintenance 17.0 19.6 (13.3) 16.8 16.7

General and administrative 59.1 53.7 10.0 56.1 (4.3)

Transmission Congestion Contract - 29.5 - - -

Fuel Expense for the year ended December 31, 2002 was $137.2 million,
compared to $135.6 million for the year ended December 31, 2001, an increase of
1.2%. The increase in fuel expenses is primarily due to higher coal prices
offset by lower operating levels due to lower demand. Fuel expense for the
year ended December 31, 2001 was $135.6 million, compared to $131.7 million for
the year ended December 31, 2000, an increase of 3.0%. The increase in fuel
expenses is primarily due to higher operating levels in the first half of the
year, which necessitated greater coal usage and greater coal purchases on the
spot market.

Depreciation and amortization expense for the year ended December 31,
2002 was $35.5 million, compared to $33.6 million for the year ended December
31, 2001, an increase of 5.7%. This increase is primarily due to a full year's
depreciation of the SCR system to reduce NOx emissions at Cayuga which was
operational June 7, 2001. Depreciation and amortization expense for the year
ended December 31, 2001 was $33.6 million, compared to $31.7 million for the
year ended December 31, 2000, an increase of 6.0%. This increase is primarily
due to a half year's depreciation of the SCR system to reduce NOx emissions at
Cayuga which was operational June 7, 2001.

Operations and maintenance expense for the year ended December 31,
2002 was $17.0 million, compared to $19.6 million for the year ended December
31, 2001, a decrease of 13.3%. This decrease is primarily due to maintenance
expenses incurred during a scheduled outage at Cayuga in the second quarter of
2001, which are not annually recurring expenses. Operations and maintenance
expense for the year ended December 31, 2001 was $19.6 million, compared to
$16.8 million for the December 31, 2000, an increase of 16.7%. This increase is
primarily due maintenance expenses incurred during a scheduled outage at Cayuga
in the second quarter of 2001.

General and administrative expense for the year ended December 31,
2002 was $59.1 million, compared to $53.7 million for the year ended December
31, 2001, an increase of 10.0%. This increase is primarily due to significant
increases in property taxes and property and medical insurance which were
partially offset by reversal of accruals for potential environmental
liabilities which were resolved at a lower cost than estimated. General and
administrative expense for the year ended December 31, 2001 was $53.7 million,
compared to $56.1 million for the year December 31, 2000, a decrease of 4.3%.

28

The Transmission Congestion Contract is essentially a swap between the
congestion component of the locational prices posted by the NYISO in western
New York and the more populated areas in eastern New York. The Transmission
Congestion Contract became effective on November 1, 2000 and terminates on
October 1, 2004. We entered into this agreement because it provided a
reasonable settlement for resolving a FERC dispute between us and Niagara
Mohawk Power Corporation. This contract is not deemed to be a hedge based on
the definitions in SFAS 133. Therefore, this contract is marked to market at
the end of every period. The mark-to-market value is computed based on a
regression of historical eastern and western locational prices. This regression
is used with forecasted eastern and western locational prices to calculate the
forward congestion for the remainder of the contract term. This accounting
treatment contributes to the income statement volatility of this contract.

Other Expenses
- -------------------- % %
For the Year Ended December 31, 2002 2001 Change 2000 Change
------ ------ ------- ------ ------
Interest expense $57.7 $58.4 (1.2) $57.3 1.9

Interest Income 2.1 3.9 (46.2) 4.3 (9.3)

Other Income/Expenses for the year ended December 31, 2002 were net
expenses of $55.5 million, compared to net expenses of $54.5 million for the
year ended December 31, 2001, an increase of 1.8%. This increase is primarily
due to lower interest income offset by lower interest expense. Other
Income/Expenses for the year ended December 31, 2001 were net expenses of $54.6
million, compared to net expenses of $53.0 million for the year ended December
31, 2000, a decrease of 2.8%. This decrease is primarily due to lower interest
rates and higher interest expense.

Liquidity and Capital Resources

The leases for Somerset and Cayuga require that we make fixed
semiannual payments of rent on each January 2 and July 2 during the terms of
the leases commencing on January 2, 2000 in amounts calculated to be sufficient
(1) to pay principal and interest when due on the secured lease obligation
notes issued by the special purpose business trusts that own and lease to us
Somerset and Cayuga and (2) to pay the economic return of the institutional
investors that formed the special purpose business trusts. Our minimum rent
obligation under the leases is $57.6 million for 2003, $63.5 million for 2004,
$59.5 million for 2005, $61.6 million for 2006, $62.5 for 2007 and a total of
$1,252.1 million for the years thereafter. For purposes of the minimum rent
obligations described in the preceding sentence, we treated the semiannual rent
payments that are due on January 2 of each year as though they would be paid in
the preceding year. You can find information concerning our minimum rental
obligations that treats rent payments as obligations for the years in which
they are due in note 6 of our audited financial statements which are included
in this Annual Report on Form 10-K. Through July 2, 2020 and so long as no
lease event of default exists, we may defer payment of rent obligations under
each lease in excess of the amount required to pay principal and interest on
the secured lease obligation notes until after the final scheduled payment date
of the secured lease obligation notes. As of December 31, 2002, we have not
deferred any portion of our lease obligations. In addition, we are required to
maintain a rent reserve account equal to the maximum semiannual payment with
respect to the sum of basic rent (other than deferrable basic rent) and fixed
charges expected to become due on any one basic rent payment date in the
immediately succeeding three-year period. At December 31, 2002 and 2001, the
amounts deposited in the rent reserve account were $31.7 million for each year.

We will also be obligated to make payments under the coal hauling
agreement with Somerset Railroad in an amount sufficient, when added to funds
available from other sources, to enable Somerset Railroad to pay, when due, all
of its operating expenses and other expenses, including interest on and
principal of outstanding indebtedness. On August 14, 2000, Somerset Railroad
entered into a $26 million credit facility with Fortis Capital Corp. which
replaced in its entirety a credit facility for the same amount previously
provided to Somerset Railroad by an affiliate of CIBC World Markets. The credit
facility provided by Fortis Capital Corp. consists of a 14-year term note
(maturing on May 6, 2014), with principal and interest payments due quarterly.

As a result of these obligations, we must dedicate a substantial
portion of our cash flow from operations to payments of rent under the leases,
payments under our working capital

29

facility and payments under the coal hauling agreement with Somerset Railroad,
which in turn allow Somerset Railroad to pay principal and interest under its
credit facility with Fortis Capital Corp. The principal payments for the $26
million credit facility are $1.9 million per year.

We incurred approximately $7.1 million, $17.1 million and $20.8
million in capital expenditures with regard to our assets for the years ended
December 31, 2002, 2001 and 2000, respectively. These amounts include
approximately $11.2 million for a SCR system to reduce NOx emissions at Cayuga
which was operational June 7, 2001. We will make capital expenditures
thereafter according to the maintenance program for our electricity generating
stations. In addition to capital requirements associated with the ownership and
operation of our electricity generating stations, we will have significant
fixed charge obligations in the future, principally with respect to the leases.

Compliance with environmental standards will continue to be reflected
in our capital expenditures and operating costs. Based on the current status of
regulatory requirements and, other than the expenditures for the SCRs at
Somerset and Cayuga, including the construction of new landfill space to manage
ash from Somerset's SCR system operations, and expenditures for possible
installation of a SCR system on Cayuga Unit 2, the U.S. Department of Energy
Power Plant Improvement project on Greenridge Unit 4 and the Westover Overfire
Air Project, we do not anticipate that any capital expenditures or operating
expenses associated with our compliance with current laws and regulations will
have a material effect on our results of operations or our financial condition.
See "Business--Regulation--Environmental Regulatory Matters."

Our net working capital at December 31, 2002, 2001 and 2000 was $96.5
million, $80.1 million and $84.2 million, respectively. During 2000, we made
one borrowing under a Credit Suisse First Boston working capital credit
facility. The borrowing was from July 18, 2000 to July 25, 2000 in the amount
of $8 million and bore interest at the rate of 8.375% per annum. At March 9,
2001, our $20 million Credit Suisse First Boston working capital credit
facility was terminated. In April 2001, we entered into a $35 million secured
revolving working capital and letter of credit facility with Union Bank of
California, N.A. This facility had a term of approximately twenty-one months.
We can borrow up to $35 million for working capital purposes under this
facility. In addition, we can have letters of credit issued under this facility
up to $25 million, provided that the total amount of working capital borrowings
and letters of credit issuances may not exceed the $35 million limit on the
entire facility. Through November 20, 2002, we made three borrowings under this
facility. The first borrowing was for $7 million on July 13, 2001 at an
interest rate of 8.125% and was repaid in full on July 31, 2001. The second
borrowing was for $8.5 million on January 11, 2002 at an interest rate of
6.125% and was repaid in full on February 28, 2002. The third borrowing was for
$14.0 million on July 9, 2002, at an interest rate of 6.125% and was repaid in
full in two installments: $7.2 million on July 31, 2002 and $6.8 million on
August 28, 2002.

On November 20, 2002, we signed an agreement with Union Bank of
California, N.A. for a one-year extension of our current facility. Currently,
lenders have committed to provide only $15 million of the $35 million secured
revolving working capital and letter of credit facility. We are attempting to
obtain commitments for the remaining $20 million. Our financial flexibility may
be limited if we are unable to obtain these commitments or substitute other
sources of credit. Under this agreement, we borrowed $9.7 million on January
10, 2003 at an interest rate of 5.75%. The $9.7 million was repaid in full on
January 28, 2003. At the date of filing our 2002 annual report on Form 10-K, of
the $15 million committed, we have letters of credit of $7.5 million written
which have been provided as additional margin to counterparties.

As we attempt to obtain the remaining commitments on our current
facility, The AES Corporation on January 6, 2003 authorized us to provide
letters of credit to counterparties on its $350 million senior secured
revolving credit facility to the amount of $25 million. At the date of filing
our annual report on Form 10-K we have obtained letters of credit in the amount
of $14.4 million to support normal ongoing hedging activities with a number of
counterparties.

30

The outage at Cayuga for almost the entire period from March 31, 2001
to June 4, 2001 did not impair our ability to meet our obligations during this
period. Similarly, the outage at Somerset for almost the entire period from May
14, 1999 to June 30, 1999 did not impair our ability to meet our obligations
during this period. Subsequent to these outages, our four electricity
generating stations are all available for service and are being dispatched to
generate electricity when market conditions warrant.

Cash flow from our operations was sufficient to cover aggregate rental
payments under the leases for Somerset and Cayuga on the rent payment dates of
January 2, 2000, July 2, 2000, January 2 2001, July 2, 2001, January 2, 2002,
July 2, 2002 and January 2, 2003. We believe that cash flow from our operations
will be sufficient to cover aggregate rental payments on each rent payment date
thereafter. We also believe that our cash flow from operations, together with
amounts we can borrow under our working capital and letter of credit facility
with Union Bank of California, N.A., will be sufficient to cover expected
capital requirements over the terms of the leases. If we are required to make
unanticipated capital expenditures, our cash flow from operations and operating
income in the period incurred would be reduced.

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

Our ability to make distributions to the partners of our company is
restricted by the terms of the agreements governing the leases for Somerset and
Cayuga. We may make distributions only on or within ten days after a semiannual
rent payment date and only if all rent on the leases has been paid, the reserve
accounts for lease payments that we are required to maintain are fully funded
and other conditions are satisfied. See "Business--General Development of
Business."

The AES Corporation contributed approximately $1.5 million and $9.4
million to us in 2002 and 2001, respectively. The contributions were accounted
for as a partner's contribution were related to the construction of the SCR on
Unit 1 of Cayuga, which became operational on June 7, 2001. The AES Corporation
has no obligation to provide any additional funding to us.

Credit Rating Discussion

Credit ratings affect our ability to execute our commercial strategies
in a cost-effective manner. In determining our credit rating, the rating
agencies consider a number of factors. Quantitative factors that appear to have
significant weight include, among other things, earnings before interest, taxes
and depreciation and amortization ("EBITDA"); operating cash flow; total debt
outstanding; fixed charges such as interest expense and lease payments;
liquidity needs and availability and various ratios calculated from these
factors. Qualitative factors appear to include, among other things,
predictability of cash flows, business strategy, industry position and
contingencies.

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

31

Standard & Poor's limited the rating differential provided by such structural
elements to three notches and stated that our credit ratings cannot be higher
than BB+.

Trigger Events

Our commercial agreements typically include adequate assurance
provisions relating to trade credit and some agreements have credit rating
triggers. These trigger events typically would give counterparties the right to
suspend or terminate credit if our credit ratings were downgraded. Under such
circumstances, we would need to post collateral to continue transacting
risk-management business with many of our counterparties under either adequate
assurance or specific credit rating trigger clauses. The cost of posting
collateral would have a negative effect on our profitability. If such
collateral were not posted, our ability to continue transacting business as
before the downgrade would be impaired. In response to an earlier downgrade of
The AES Corporation, one of our coal suppliers requested credit assurance based
on a clause specific to their contact. After discussions with the supplier, we
negotiated an agreement for a prepayment system with a discounted price. This
agreement expired on December 31 2002 and was not renewed. On October 8, 2002,
one of our counterparties made a $1 million margin call on us because of the
Standard & Poor's downgrade. We provided a letter of credit for $1 millon.

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

Pension Plan

Effective May 14, 1999, the Partnership adopted The Retirement Plan
for Employees of AES NY, L.L.C. (the Plan), a defined benefit pension plan. The
Plan covers people employed both under collectively bargained and
non-collectively bargained arrangements. Certain people formerly employed by
NYSEG (the Transferred Persons) receive credit under the Plan for compensation
and service earned while being employed by NYSEG. The amount of any benefit
payable under the Plan to a Transferred Person will be offset by the amount of
any benefit payable to such Transferred Person under the Retirement Plan for
Employees of NYSEG. Effective May 29, 1999, the ability to commence
participation in the Plan and the accrual of benefits under the Plan ceased
with respect to non-collectively bargained people and the accrued benefits of
any such participant were fixed as of such date. As of December 31, 2002, the
Plan was funded at least to the extent required by Internal Revenue Code (IRC)
Section 412 minimum funding and not more than the requirement of IRC Section
404, maximum contribution limits. We will make at least the required minimum
contribution within the Employee Retirement Income Security Act (ERISA)
guidelines. Pension benefits are based on the number years of credited service,
age of the participant, and average earnings. During 2000, 2001 and 2002
collectively bargained people were offered the opportunity to freeze their
accrued benefit payable under the Plan and opt into the AES Profit Sharing and
Stock Ownership Plans.

The Assets and liabilities of the Plan were valued as of October 31,
2002. This measurement date is a change from the previous practice of utilizing
a December 31 measurement date for 2001 and 2000. The values of the assets and
liabilities as of October 31, 2002 were not materially different than the
values as of December 31, 2002.

Significant assumptions were used in the calculations of the net
benefit cost and projected benefit obligation for the periods ending December
31, 2000, December 31, 2001, and October 31, 2002. In developing our expected
long-term rate of return assumption, we evaluated input from our actuaries,
plan asset manager, consultants, as well as long-term inflation assumptions.
Projected returns are based on a broad range of equity and bond indices. The
best estimate of this range is based on asset class return expectations which
reflect historical data as well as the opinion of the plan manager about the
forecasted returns of each class. Our expected long-term rate of 8% return on
Qualified Plan assets is based on the allocation

32

assumption of 60% equities(50% Growth and 50% Value), with a 10% long term rate
of return and 40% in fixed income investments, with a 5.5% long-term rate of
return. Because of market fluctuation, our actual allocation as of October 31,
2002, was 53% equities and 47% in fixed income investments. However, we believe
that our long-term asset allocation on average will approximate 60% equities
and 40% fixed income investments. We regularly review the asset allocation with
the asset manager and periodically rebalance our investments to our targeted
allocation when appropriate. We continue to believe that the 8% is a reasonable
long-term rate of return on the Plan assets, despite the market downturn. We
will continue to evaluate our actuarial assumptions, including our expected
rate of return, at least annually, and will adjust as necessary.

33

The Plan bases its determination of pension expense or income on the
fair value of assets on the measurement date. As of October 31, 2002, the Plan
has generated cumulative unrecognized net actuarial losses of approximately
$675,000 which remain to be recognized in pension cost. These unrecognized net
actuarial losses result in decreases in future pension income depending on
several factors, including whether such losses at each measurement date exceed
the corridor in accordance with SFAS No. 87, "Employers Accounting for
Pensions".

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

Lowering the expected long-term rate of return on the plan assets by
0.5% would have increased our 2002 pension cost by approximately $30,000.
Lowering the discount rate by 0.5% and increasing the rate of compensation
expense increase assumption by 0.5% would increase our 2002 pension cost by
$23,000.

The fair value of the Plan's assets has increased from $4.9 million at
December 31, 2001 to $7.2 million at October 31, 2002. The cash contributions
to the plan of approximately $3.0 million were partially offset by investment
performance losses of approximately $500,000 and benefits paid during 2002 of
approximately $200,000. We believe we will continue to be required to make cash
contributions to our plan for at least the next three years.

New Accounting Pronouncements

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

Asset Retirement Obligations. In June 2001, the FASB issued SFAS No.
143, Accounting for Asset Retirement Obligations". SFAS No. 143, which is
effective as of January 1, 2003, requires entities to record the fair value of
a legal liability for an asset retirement obligation in the period in which it
is incurred. When a new liability is recorded beginning in 2003, the entity
will capitalize the costs of the liability by increasing the carrying amount of
the related long-lived asset. The liability is accreted to its present value
each period, and the capitalized cost is depreciated over the useful life of
the related asset. Upon settlement of the liability, an entity settles the
obligation for its recorded amount or incurs a gain or loss upon settlement. We
will adopt SFAS No. 143 effective January 1, 2003.

We have completed a detailed assessment of the specific applicability
and implications of SFAS No. 143. The scope of SFAS No. 143 includes primarily
active ash landfills and water treatment basins. Upon adoption of SFAS No. 143,
we will record a liability of approximately $9.2 million, a net asset of
approximately $3.4 million, and a cumulative effect of a change in accounting
principle of approximately $5.8 million.

In August 2001, the FASB issued SFAS No. 144, "Accounting for
Impairment or Disposal of Long-Lived Assets." The provisions of this statement
are effective for financial statements issued for fiscal years beginning after
December 15, 2001, and address reporting for the impairment or disposal of
long-lived assets. SFAS No. 144 provides guidance for developing estimates of
future cash flows used to test assets for recoverability and requires that
assets to be disposed of be classified as held for sale when certain criteria
are met. The statement also extends the reporting of

34

discontinued operations to all components of an entity and provides guidance
for recognition of a liability for obligations associated with disposal
activity. Our initial adoption of the provisions of SFAS No. 144 did not have
any impact on its financial position or results of operations.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No.4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." This statement eliminates the current requirement that gains and
losses on debt extinguishments must be classified as extraordinary items in the
income statement. Instead, such gains and losses will be classified as
extraordinary items only if they are deemed to be unusual and infrequent, in
accordance with the current GAAP criteria for extraordinary classification. In
addition, SFAS No. 145 eliminates an inconsistency in lease accounting by
requiring that modifications of capital leases that result in reclassification
as operating leases be accounted for consistently with sale-leaseback
accounting rules. The statement also contains other nonsubstantive corrections
to authoritative accounting literature. The changes related to debt
extinguishments will be effective for fiscal years beginning after May 15,
2002, and the changes related to lease accounting will be effective for
transactions occurring after May 15, 2002. The adoption of this standard does
not have a significant impact on our consolidated financial statements.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities," which addresses accounting for
restructuring and similar costs. SFAS No. 146 supersedes previous accounting
guidance, principally Emerging Issues Task Force (EITF) Issue No. 94-3. We will
adopt the provisions of SFAS No. 146 for restructuring activities initiated
after December 31, 2002. SFAS No. 146 requires that the liability for costs
associated with an exit or disposal activity be recognized when the liability
is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized
at the date of a company's commitment to an exit plan. SFAS No. 146 also
establishes that the liability should initially be measured and recorded at
fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing
future restructuring costs as well as the amount recognized. This standard will
be accounted for prospectively.

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

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

35

liability recognition provisions of FIN 45 to have a material impact on our
financial position or results of operations.

Forward-looking Statements

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

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

In 2000, we adopted a value at risk (VaR) approach to assess and
manage risk. VaR measures the potential loss in a portfolio's value due to
market volatility, over a specified time horizon, stated with a specific degree
of probability. The quantification of market risk using VaR provides a
consistent measure of risk across diverse markets and instruments. The VaR
approach was adopted because we feel that statistical models of risk
measurement, such as VaR, provide an objective, independent assessment of our
risk exposure. The use of VaR requires a number of key assumptions, including
the selection of a confidence level for expected losses, the holding period for
liquidation and the treatment of risks outside the VaR methodology, including
liquidity risk and event risk. VaR, therefore, is not necessarily indicative of
actual results that may occur.

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

We perform our VaR calculation using a model based on the
variance/covariance methodology with a delta gamma model for optionality. We
express VaR as a dollar amount of the potential loss in the fair value of our
portfolio based on a 95% confidence level and a one-day holding period. Our
daily VaR for commodity price sensitive instruments as of December 31, 2002,
2001 and 2000 was $4.8 million, $6.2 million and $5.5 million, respectively.
These amounts include the financial instruments that serve as hedges and do not
include the underlying physical assets. During 2002, the daily VaR amount was
greater than the year-end amount at the end of each quarter in 2002. In the
year ended December 31, 2001, the daily VaR amount

36

was greater than the year-end amount on June 29, and September 28, 2001. At no
date during 2000 was the daily VaR amount greater than it was at year-end.

Item 8. Financial Statements and Supplementary Data

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

AES EASTERN ENERGY, L.P.

Independent Auditors' Report

Financial Statements:

Consolidated Balance Sheets as of December 31, 2002 and 2001
Consolidated Statements of Income for the years ended December 31,
2002, 2001 and 2000.
Consolidated Statements of Changes in Partners' Capital for the years
ended December 31, 2002, 2001 and 2000.
Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000.
Notes to Consolidated Financial Statements

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

Independent Auditors' Report

Financial Statements:

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

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

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

Not applicable.

37

PART III

Item 10. Directors and Executive Officers of Our Company

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

The following table sets forth certain information concerning our
management team as of March 28, 2003.

Name Age Position

Dan Rothaupt 51 General Manager
John Ruggirello 52 Assistant General Manager
Richard Santoroski 38 Manager of Marketing
Kevin Pierce 45 Somerset Plant Manager
Jerry Goodenough 38 Cayuga Plant Manager
James Mulligan 54 Westover Plant Manager
Douglas Roll 47 Greenidge Plant Manager

Dan Rothaupt, our management team leader, is a Vice President of The
AES Corporation and is a former plant manager for AES Thames, a coal-fired
facility located in the New England power pool region. Mr. Rothaupt has been
with The AES Corporation for 12 years. In addition to AES Thames, he has
managed a number of complex operations including the startup of The AES
Corporation's business in Hawaii with its coal-fired Barbers Point facility.
Mr. Rothaupt has a proven track record of reducing costs while organizing The
AES Corporation's businesses at various locations in the United States and has
27 years experience working in various aspects of power systems. Mr. Rothaupt
is General Manager of our company. Mr. Rothaupt has a Bachelor of Science
degree in Mechanical Engineering from the United States Coast Guard Academy.

John Ruggirello was named a Chief Operating Officer of The AES
Corporation in February 2003. He was appointed Executive Vice President and
Chief Operating Officer in February 2000, was Senior Vice President until
February 2000 and was appointed Vice President in January 1997. Mr. Ruggirello
has led the AES Enterprise group, with responsibility for project development,
construction and plant operations in the Mid-Atlantic region of the United
States. He has over 23 years of industry experience. Mr. Ruggirello also serves
as a board member of NIGEN, Ltd., a joint venture of The AES Corporation. He
served as President of AES Beaver Valley from 1990 to 1996. Mr. Ruggirello is
Assistant General Manager of our company. He has a Bachelor of Science degree
in Mechanical Engineering from the New Jersey Institute of Technology.

Richard Santoroski worked for NYSEG for 13 years prior to May 14, 1999
primarily in engineering positions in the system protection and control group
(relay) and in field distribution offices. Mr. Santoroski was formerly the lead
engineer in the electric resource planning group. Mr. Santoroski has extensive
experience in power marketing, including trading physical power options, swaps
and forwards, developing and marketing structured products in the New York
power pool, the New England power pool and the Pennsylvania-New Jersey-Maryland
power pool and overseeing NYSEG's trading, risk management and billing. Mr.
Santoroski is the Manager of Power Marketing of our company. Mr. Santoroski has
a Bachelor of Science degree in Electrical Engineering from Pennsylvania State
University and a Master of Science degree in Electrical Engineering and a
Master of Business Administration, both from Syracuse University.

Kevin Pierce has over 22 years experience in power operations and has
worked for The AES Corporation for 14 years. Mr. Pierce was formerly the plant
manager for AES Hawaii, which reliably supplies twenty percent of the electric
demand for the

38

island of Oahu and was involved with the start-up and operations of the AES
Thames plant. Mr. Pierce is the plant manager of Somerset. Mr. Pierce has a
Bachelor of Science degree in Marine Engineering from Maine Maritime Academy.

Jerry Goodenough has over 14 years experience in the power generation
business. Mr. Goodenough was formerly employed by NYSEG in engineering and
supervisory roles in the generation engineering group and at Cayuga. Mr.
Goodenough is the Plant Manager of Cayuga. Mr. Goodenough holds a Bachelor of
Arts degree in Physics from Ithaca College and a Master of Science degree in
Electrical Engineering from the State University of New York at Binghamton.

James Mulligan has over 27 years experience in the power generation
business including design and management of utility plants. Mr. Mulligan was
formerly employed by NYSEG as the plant manager at Cayuga. Prior to that, he
was responsible for NYSEG's four central area plants, which achieved the lowest
production costs and highest availabilities in their operating history during
his tenure. Mr. Mulligan is the plant manager of Westover. Mr. Mulligan has a
Bachelor of Science degree in Mechanical Engineering from the New York
Institute of Technology.

Douglas J. Roll has over 19 years experience in the power generation
business in areas of plant management, engineering, design, construction and
start-up of fossil fuel-fired power plants. Mr. Roll was formerly the Station
Manager at NYSEG's Greenidge Station where he directed the efforts of the
station's staff to the lowest production cost and heat rate and highest
reliability and availability in 25 years. Prior to that, Mr. Roll was the
Manager of Mechanical Engineering in NYSEG's Generation Department, responsible
for directing the engineering, design, construction and start-up of large scale
capital projects at NYSEG's coal fired power plants. Mr. Roll is the Plant
Manager of Greenidge. Mr. Roll holds a Bachelor of Science degree in Mechanical
Engineering from Cornell University and a Bachelor of Arts degree in Biology
from Queens College of the City University of New York. Mr. Roll is a
registered Professional Engineer in the State of New York.

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

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

Dr. Roger F. Naill, 56 years old, was appointed Senior Vice President
of the AES Corporation in February 2001 and has been Vice President for
Planning at The AES Corporation since 1981. Dr. Naill is responsible for
financial forecasts and other corporate issues of The AES Corporation. Prior to
joining The AES Corporation, Dr. Naill was Director of the Office of Analytical
Services at the U.S. Department of Energy. Dr. Naill received a Ph.D in
Engineering from Dartmouth College and a MSM Degree from the A.P. Sloan School
of Business (MIT).

Barry J. Sharp, 43 years old, holds the position of Chief Financial
Officer of the AES Corporation. His responsibilities include overseeing the
finance function at The AES Corporation. He was appointed Executive Vice
President of The AES Corporation in February 2001. Mr. Sharp was appointed
Senior Vice President and Chief Financial Officer of The AES Corporation
effective January 1998 and had been Vice President and Chief Financial Officer
of The AES Corporation since 1987. He also served as Secretary of The AES
Corporation until February 1996. From 1986 to 1987, he served as The AES
Corporation's Director of Finance and Administration. Mr. Sharp is a certified
public accountant.

Item 11. Executive Compensation

Not Applicable.

39

Item 12. Security Ownership of Certain Beneficial Owners and Management

Not Applicable.

Item 13. Certain Relationships and Related Transactions

Not Applicable.

Item 14. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. The principal
executive officer and principal financial officer of our General Partner, after
evaluating the effectiveness of our "disclosure controls and procedures" (as
defined in the Securities Exchange Act of 1934 Rules 13a-14(c) and
240.15d-14(c)) as of a date (the "Evaluation Date) within 90 days of the filing
date of the annual report, have concluded that as of the Evaluation Date, our
disclosure controls and procedures were effective to ensure that material
information relating to us and our consolidated subsidiaries is recorded,
processed, summarized and reported in a timely manner.

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

PART IV

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

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

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

AES EASTERN ENERGY, L.P.

Independent Auditors' Report

Financial Statements:

Consolidated Balance Sheets as of December 31, 2002 and 2001
Consolidated Statements of Income for the years ended
December 31, 2002 and 2001 and 2000 Consolidated Statements
of Changes in Partners' Capital for the years ended
December 31, 2002 and 2001 and 2000
Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000
Notes to Consolidated Financial Statements

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

Independent Auditors' Report

Financial Statements:

Consolidated Balance Sheets as of December 31, 2002 and 2001
Notes to Consolidated Balance Sheets

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

(2) Financial Statement Schedules

Schedules are omitted as the information is either not
applicable,

40

not required or has been furnished in the financial
statements or notes thereto included in this Annual Report on
Form 10-K.

41

(3) Exhibits

Exhibit No. Description
---------- -----------

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

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

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

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

4.3a Pass Through Trust Agreement A, dated as of May
1, 1999, between AES Eastern Energy, L.P. and
Bankers Trust Company, as Pass Through Trustee,
made with respect to the formation of the Pass
Through Trust, Series 1999-A and the issuance of
9.0% Pass Through Certificates, Series 1999-A*

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

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

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

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

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

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

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

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

42

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

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

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

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

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

4.10 [Reserved]

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

4.12 [Reserved]

4.13 [Reserved]

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

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

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

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

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

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

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

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

43

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

10.8 [Reserved]

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

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

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

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

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

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

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

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

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

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

10.15 [Reserved]

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

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

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

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

44

10.20 [Reserved]

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

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

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

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

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

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

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

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

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

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

10.25c Amendment No.2 to Credit Agreement dated as of
November 20, 2002 to Credit agreement dated as
of April 10, 2001 among AEE and Union Bank of
California, N.A., as Agent as amended.

12.1 Statement regarding ratio of earnings to fixed
charges

21.1 Subsidiaries Schedule*

24 Power of Attorney

- ---------

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

** Incorporated herein by reference to similarly numbered exhibit to the
Quarterly Report of AES Eastern Energy, L.P. (Reg. No. 333-89725) for
the quarterly period ended September 30, 2001, filed with the Securities
and Exchange Commission on November 14, 2001.

45

(b) Reports on Form 8-K.

No reports on Form 8-K have been filed during the last quarter of our
fiscal year ended December 31, 2002.

SIGNATURES

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

Date: March 28, 2003

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

By: /s/ Dan Rothaupt
-------------------------
Dan Rothaupt
President

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

Signature Title Date
- ---------------------------- -------------------------- --------------

Principal Executive Officer

/s/ Dan Rothaupt President and Class A March 28, 2003
- --------------------------- Director of AES NY, L.L.C.
Dan Rothaupt

Principal Financial Officer

/s/ Amy Conley Vice President and Treasurer March 28, 2003
- --------------------------- of AES NY, L.L.C.
Amy Conley

* Class A Director of AES March 28, 2003
- --------------------------- NY, L.L.C.
Barry J. Sharp

* Class A Director of March 28, 2003
- --------------------------- AES NY, L.L.C.
Roger F. Naill

*By: /s/ Dan Rothaupt
-----------------------
Co-Attorney-in-Fact

*By: /s/ Amy Conley
-----------------------
Co-Attorney-in-Fact

46

CERTIFICATIONS

I, Daniel J. Rothaupt, certify that:

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

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

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

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

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

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

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and

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

Date: March 28, 2003

/s/ Daniel J. Rothaupt
--------------------------------
Daniel J. Rothaupt
President
(principal executive officer)

47

CERTIFICATIONS

I, Amy Conley, certify that:

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

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

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

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

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

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

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and

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

Date: March 28, 2003

By: /s/ Amy Conley
---------------------------------
Amy Conley
Vice President
(principal financial officer)

Supplemental Information to Be Furnished With Reports Filed Pursuant to Section
15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to
Section 12 of the Act

We did not, and do not intend to, send to security holders an annual
report covering our last fiscal year (other than this Annual Report on Form
10-K) or a proxy statement with respect to an annual or other meeting of
security holders.

48

Index to Financial Statements

AES EASTERN ENERGY, L.P.

Independent Auditors' Report

Financial Statements:

Consolidated Balance Sheets

Consolidated Statements of Income

Consolidated Statements of Changes in Partners' Capital

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

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

Independent Auditors' Report

Financial Statements:

Consolidated Balance Sheets

Notes to Consolidated Balance Sheets

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

49

INDEPENDENT AUDITORS' REPORT

To the Partners of AES Eastern Energy, L.P.

We have audited the accompanying consolidated balance sheets of AES Eastern
Energy, L.P. (an indirect wholly owned subsidiary of The AES Corporation) and
subsidiaries (the Partnership) as of December 31, 2002 and 2001, and the
related consolidated statements of income, changes in partners' capital, and
cash flows for the years ended December 31, 2002, 2001 and 2000. These
financial statements are the responsibility of the Partnership's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of AES Eastern Energy, L.P., and
subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for the years ended December 31, 2002, 2001 and
2000, in conformity with accounting principles generally accepted in the United
States of America.

/s/Deloitte & Touche LLP

McLean, Virginia
January 24, 2003

50

AES EASTERN ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS,
DECEMBER 31, 2002 and DECEMBER 31, 2001

(Amounts in Thousands)
- ------------------------------------------------------------------------------------------
Year ended December 31, 2002 2001
----------- ----------

ASSETS
Current Assets:
Restricted cash:
Operating - cash and cash equivalents $ 4,605 $ 4,193
Revenue account 76,566 71,606
Accounts receivable - trade 35,233 27,590
Accounts receivable - affiliates - 319
Accounts receivable - other 1,235 2,123
Inventory 26,982 29,615
Prepaid expenses 7,617 6,464
----------- ----------
Total current assets 152,238 141,910
----------- ----------
PROPERTY, PLANT, EQUIPMENT, AND RELATED ASSETS:
Land 7,011 6,884
Electric generation assets -net of
accumulated depreciation of $117,222 and $82,205 929,654 957,662
----------- ----------
Total property, plant, equipment and related assets 936,665 964,546
----------- ----------
OTHER ASSETS:
Deferred financing -net of
accumulated amortization of $863 and $359 293 480
Derivative valuation 2,510 55,182
Transmission Congestion Contract 2,416 -
Rent reserve account 31,717 31,719
----------- ----------
TOTAL ASSETS $ 1,125,839 $1,193,837
=========== ==========
LIABILITIES AND PARTNERS' CAPITAL

CURRENT LIABILITIES:
Accounts payable $ 1,195 $ 1,663
Lease financing - current 1,665 6,223
Environmental remediation 20 155
Accrued interest expense 28,078 28,353
Due to The AES Corporation and affiliates 6,945 6,414
Accrued coal and rail expense 8,492 9,652
Accrued expenses and other liabilities 9,311 9,374
----------- ----------
Total current liabilities 55,706 61,834
----------- ----------

LONG-TERM LIABILITIES:
Lease financing - long term 637,660 639,326
Environmental remediation 9,192 11,442
Defined benefit plan obligation 17,439 16,968
Derivative valuation liability 20,996 26,665
Transmission congestion contract - 3,506
Other liabilities 2,600 1,057
----------- ----------
Total long-term liabilities 687,887 698,964
----------- ----------
TOTAL LIABILITIES 743,593 760,798

COMMITMENTS AND CONTINGENCIES (Note 7)

PARTNERS' CAPITAL 382,246 433,039
----------- ----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $ 1,125,839 $1,193,837
=========== ==========

The notes are an integral part of the consolidated financial statements

51

AES EASTERN ENERGY, L.P.
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

(Amounts in Thousands)
- -----------------------------------------------------------------------------------------
Year ended December 31, 2002 2001 2000
-------- -------- --------

OPERATING REVENUES:
Energy $310,616 $345,410 $322,677
Capacity 36,644 26,767 31,572
Transmission Congestion Contract 8,875 - 24,851
Other 6,879 6,171 8,466
-------- -------- --------
Total revenues 363,014 378,348 387,566
-------- -------- --------
OPERATING EXPENSES:
Fuel 137,175 135,562 131,681
Depreciation and amortization 35,538 33,542 31,723
Operating and maintenance 16,954 19,572 16,761
General and administrative 59,112 53,712 56,112
Transmission Congestion Contract - 29,494 -
Derivative valuation 27 27 -
-------- -------- --------
Total operating expenses 248,806 271,909 236,277
-------- -------- --------

OPERATING INCOME 114,208 106,439 151,289
-------- -------- --------

OTHER INCOME (EXPENSE):
Interest expense (57,694) (58,434) (57,314)
Interest income 2,116 3,860 4,262
-------- -------- --------

Total other income (expense) (55,578) (54,574) (53,052)
-------- -------- --------

NET INCOME $ 58,630 $ 51,865 $ 98,237
======== ======== ========

The notes are an integral part of the consolidated financial statements

52

AES EASTERN ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL
YEARS ENDED DECEMBER 31, 2002, 2001 AND, 2000

(Amounts in Thousands)
- --------------------------------------------------------------------------------------------------
Accumulated
Other
General Limited Comprehensive Comprehensive
Partner Partner Total Income Income
------- ------- --------- ------------- -------------

BALANCE, DECEMBER 31, 1999 3,782 374,439 378,221

Net income 982 97,255 98,237

Dividends paid (350) (34,650) (35,000)
------- ------- -------

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 income (47) (46,929) (46,976) (46,976) (46,976)
------- ------- ------- ------- -------
Comprehensive income (18,432) 92,063
======= =======
BALANCE, DECEMBER 31, 2002 4,245 378,001 382,246
======= ======= =======

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

53

AES EASTERN ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

(Amounts in Thousands)
- ---------------------------------------------------------------------------------------------------
Year ended December 31, 2002 2001 2000
----------- ----------- -----------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 58,630 $ 51,865 $ 98,237
Adjustments to reconcile net income to
Net cash used in operating activities:
Depreciation and amortization 35,521 33,542 31,723
Realized (gain)Loss on derivative (5,895) 28,385 (24,851)
Net defined benefit plan cost 3,499 1,389 (2,989)
Payments to pension plan (3,028) (3,202) (2,110)
Changes in current assets and liabilities:
Accounts receivable (6,436) 6,508 (13,466)
Inventory 2,633 (6,307) 4,681
Prepaid expenses (1,153) (312) 37
Accounts payable (468) 231 924
Accrued interest expense (275) (1,119) (8,988)
Due to AES Corporation and affiliates 531 (2,190) 5,354
Accrued coal and rail expense (1,160) (776) 3,311
Other liabilities (905) (5,596) (1,599)
-------- --------- --------
Net cash provided by operating activities 81,494 102,418 90,264
-------- --------- --------

CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for capital additions (7,136) (17,148) (20,763)
Decrease(increase) in restricted cash (5,372) 7,266 (30,428)
Net change in rent reserve account 2 (741) (1,435)
-------- --------- --------
Net cash used in investing activities (12,506) (10,623) (52,626)
-------- --------- --------

CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (63,960) (98,200) (35,000)
Payments for deferred financing (317) (1,154) -
Principal payments on lease obligations (6,224) (1,813) (2,638)
Partner's contribution 1,513 9,372 -
-------- --------- --------
Net cash used in financing activities (68,988) (91,795) (37,638)
-------- --------- --------

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 $ 56,354 $ 56,610 $ 9,637
======== ========= ========

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

54

AES EASTERN ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
===============================================================================

1. GENERAL

AES Eastern Energy, L.P. (the Partnership), a Delaware limited
partnership, was formed on December 2, 1998. The Partnership's wholly
owned subsidiaries are AES Somerset, L.L.C., AES Cayuga, L.L.C., and AEE2,
L.L.C., (which wholly owns AES Westover, L.L.C. and AES Greenidge,
L.L.C.). The Partnership began operations on May 14, 1999 (see Note 3).
Prior to that date, the Partnership had no operations. The Partnership is
an indirect wholly owned subsidiary of The AES Corporation (AES). The
Partnership has adopted December 31 as its fiscal year end.

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

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

The Partnership entered into an arrangement with AES Odyssey,
L.L.C.(Odyssey), a direct wholly owned subsidiary of AES. This agreement
commenced on November 27, 2000. The initial term of the agreement was for
a term of three years. In March 2002, a new agreement was reached, for a
term of five years through February 28, 2007 pursuant to which Odyssey
will provide data management, marketing, scheduling, invoicing and risk
management services for a fee of $300,000 per month (see Note 8).

2. SIGNIFICANT ACCOUNTING POLICIES

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

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

55

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

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

2002 2001
---------- ---------
Coal and other raw materials $ 11,342 $ 13,488
Spare parts, materials, and supplies 15,640 16,127
---------- ---------
Total $ 26,982 $ 29,615
========== =========

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

Property, Plant, Equipment, and Related Assets - Electric generation
assets that existed at the date of acquisition (see Note 3) were recorded
at fair market value. The Somerset (formerly known as Kintigh) and Cayuga
(formerly known as Milliken) Plants, which represent $650 million of the
electric generation assets, are subject to a leasing arrangement accounted
for as a financing (see Note 6). Additions or improvements thereafter are
recorded at cost. Depreciation is computed using the straight-line method
over the 34-year and 28-year lease terms for the Somerset and Cayuga
Plants, respectively, and over the estimated useful lives for the other
fixed assets, which range from 7 to 35 years. Maintenance and repairs are
charged to expense as incurred.

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

2002 2001
---------- ---------
Electric generation assets $1,046,876 $1,039,867
Accumulated depreciation and amortization (117,222) (82,205)
---------- ----------
Total $ 929,654 $ 957,662
========== ==========

Rent Reserve Account - As part of the Partnership's lease obligation (see
Note 6), the Partnership is required to maintain a rent reserve account
equal to the maximum semiannual payment with respect to the sum of basic
rent (other than deferrable payments) and fixed charges expected to become
due on any one basic rent payment date in the immediately succeeding
three-year period. As of December 31, 2002 and 2001, the Partnership had
fulfilled this obligation by entering into a Payment Undertaking
Agreement, dated as of May 1, 1999, among the Partnership, each Owner
Trust (see Note 3) and Morgan Guaranty Trust Company of New York (the
Payment Undertaking Agreement). On May 14, 1999, the Partnership deposited
with Morgan Guaranty Trust Company of New York approximately $28.7 million
pursuant to the Payment Undertaking Agreement. The accreted value of the
Payment Undertaking Agreement at any time includes interest earned
thereunder at an interest rate of 4.79% per annum. Interest earnings as of
December 31, 2002, 2001, and 2000 were approximately $1.5 million, $1.5
million and $1.4 million, respectively, and are included in the rent
reserve account balance. At December 31, 2002 and 2001, the accreted value
of the Payment Undertaking Agreement exceeded the required balance of the
rent reserve account. This amount is being accounted for as a restricted
cash balance and is included within the rent reserve account on the
accompanying balance sheets, as it can only be utilized to satisfy lease
obligations. In the future, the Partnership may fulfill its obligation to
maintain the required balance of the rent reserve account either by
deposits into the rent reserve account or by making amounts available
under the Payment Undertaking Agreement, such that the aggregate amount of
such deposits in the rent reserve account and amounts available to be paid
under the Payment Undertaking Agreement are equal to the required balance
of the rent reserve account.

56

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

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

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

Comprehensive Income - In 1999, the Partnership adopted Statement of
Financial Accounting Standards (SFAS) No. 130, "Reporting Comprehensive
Income", which establishes rules for the reporting of comprehensive income
and its components. As of December 31, 2002, the Partnership has recorded
$18.4 million of other comprehensive loss due to the adoption of SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities". In
the years prior to the adoption of SFAS No. 133, the Partnership did not
have any items of other comprehensive income.

On January 1, 2001, the Partnership adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities", which, as amended,
established new accounting and reporting standards for derivative
instruments and hedging activities. The Statement requires that the
Partnership recognize all derivatives, as defined in the Statement, on the
balance sheet at fair value. Derivatives, or any portion thereof, that are
not effective hedges are adjusted to fair value through income.
Derivatives that are effective hedges are recognized in other
comprehensive income (loss) until the hedged items are recognized in
earnings. The adoption of SFAS No. 133 on January 1, 2001, resulted in a
cumulative reduction of Other Comprehensive Income in Partner's Capital of
$66.3 million.

The Partnership utilizes derivative financial instruments to hedge
commodity price risk. The Partnership utilizes electric derivative
instruments, including swaps and forwards, to hedge the risk related to
forecasted electricity sales over the next four years. The majority of the
Partnership's electric derivatives are designated and qualify as cash flow
hedges. No hedges were derecognized or discontinued during the year ended
December 31, 2002. No significant amounts of hedge ineffectiveness were
recognized in earnings during the year ended December 31, 2002.

Gains and losses on derivatives reported in accumulated other
comprehensive income are reclassified into earnings when the hedged
forecasted sale occurs. Approximately $14.7 million of other comprehensive
income is expected to be recognized as a reduction to earnings over the
next twelve months. Amounts recorded in Other Comprehensive Income during
the year ended December 31, 2002, were as follows (in millions):

Beginning balance on January 1, 2002 $ 28.5
Reclassified to earnings (2.5)
Change in fair value (44.4)
------
Balance, December 31, 2002 $(18.4)
======

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

57

Revenue Recognition - Revenues from the sale of electricity are recorded
based upon output delivered and rates specified under contract terms.
Revenues generated from commodity forwards, swaps and options, which are
entered into for the hedging of forecasted sales, are recorded based on
settlement accounting with the net amount received recognized as revenue
for 2000. Beginning in 2001, such contracts were accounted for in
accordance with SFAS No. 133. Revenues for ancillary and other services
are recorded when the services are rendered.

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

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations". SFAS No. 143, which is effective January 1, 2003,
requires entities to record the fair value of a legal liability for an
asset retirement obligation in the period in which it is incurred. When a
new liability is recorded beginning in 2003, the entity will capitalize
the costs of the liability by increasing the carrying amount of the
related long-lived asset. The liability is accreted to its present value
each period, and the capitalized cost is depreciated over the useful life
of the related asset. Upon settlement of the liability, an entity settles
the obligation for its recorded amount or incurs a gain or loss upon
settlement. The Partnership will adopt SFAS No. 143 effective January 1,
2003.

The Partnership has completed a detailed assessment of the specific
applicability and implications of SFAS No. 143. The scope of SFAS No. 143
includes primarily active ash landfills and water treatment basins. Upon
adoption of SFAS No. 143, the Partnership will record a liability of
approximately $9.2 million, a net asset of approximately $3.4 million, and
a cumulative effect of a change in accounting principle of approximately
$5.8 million, after income taxes.

In August 2001, the FASB issued SFAS No. 144, "Accounting for Impairment
or Disposal of Long-Lived Assets." The provisions of this statement are
effective for financial statements issued for fiscal years beginning after
December 15, 2001, and address reporting for the impairment or disposal of
long-lived assets. SFAS No. 144 provides guidance for developing estimates
of future cash flows used to test assets for recoverability and requires
that assets to be disposed of be classified as held for sale when certain
criteria are met. The statement also extends the reporting of discontinued
operations to all components of an entity and provides guidance for
recognition of a liability for obligations associated with disposal
activity. The Partnership's initial adoption of the provisions of SFAS No.
144 did not have any impact on its financial position or results of
operations.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No.4, 44, and 64, Amendment of FASB Statement No. 13, and
Technical Corrections." This statement eliminates the current requirement
that gains and losses on debt extinguishments must be classified as
extraordinary items in the income statement. Instead, such gains and
losses will be classified as extraordinary items only if they are deemed
to be unusual and infrequent, in accordance with the current GAAP criteria
for extraordinary classification. In addition, SFAS No. 145 eliminates an
inconsistency in lease accounting by requiring that modifications of
capital leases that result in reclassification as operating leases be
accounted for consistently with sale-leaseback accounting rules. The
statement also contains other nonsubstantive corrections to authoritative
accounting literature. The changes related to debt extinguishments will be
effective for fiscal years beginning after May 15, 2002, and the changes
related to lease accounting will be effective for transactions occurring
after May 15, 2002. The adoption of this standard does not have a
significant impact on the Partnership's consolidated financial statements.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities," which addresses accounting
for restructuring and similar costs. SFAS No. 146 supersedes previous
accounting guidance, principally Emerging Issues Task Force (EITF) Issue
No. 94-3. The Partnership will adopt the provisions of SFAS No. 146 for
restructuring activities initiated after December 31, 2002. SFAS No. 146
requires that the liability for costs associated with an exit or disposal
activity be recognized when the liability is incurred. Under EITF No.
94-3, a liability for an exit cost was recognized at the date of a
company's commitment to an exit plan. SFAS No. 146 also establishes that
the liability should initially be measured and recorded at fair value.
Accordingly, SFAS No. 146 may affect the timing of recognizing future
restructuring costs as well as the amount recognized. This standard will
be accounted for prospectively.

In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure." SFAS No. 148 amends
SFAS No. 123, "Accounting for Stock-Based Compensation" to provide
alternative methods of transition for a voluntary change to the fair value
based method of accounting for stock-based employee compensation. In

58

addition, this Statement amends the disclosure requirements of SFAS No.
123 to require prominent disclosures in both annual and interim financial
statements about the method of accounting for stock-based employee
compensation and the effect of the method used on reported results. The
Partnership expects to use the prospective method to transition to the
fair value based method of accounting for stock-based employee
compensation. All employee awards granted, modified, or settled after
January 1, 2003, will be recorded using the fair value based method of
accounting. The expanded disclosures required by SFAS No. 148 will be
included in the Partnership's quarterly financial reports beginning in the
first quarter of 2003. The Partnership's adoption of the prospective
method of accounting for stock-based employee compensation did not have
any material impact on its financial position or results of operations.

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

Reclassifications - Certain prior year and prior period amounts have been
reclassified on the consolidated financial statements to conform with the
2002 presentation.

3. ACQUISITION

On May 14, 1999, the Partnership's four Plants were acquired from NYSEG
for approximately $914 million. The Partnership acquired ownership of two
of the Plants, Westover (formerly known as Goudey) and Greenidge. The
other two Plants, Somerset and Cayuga, were acquired for $650 million by
twelve unrelated third-party owner trusts (collectively, the Owner Trusts)
organized by three unrelated institutional investors. Simultaneously, the
Partnership entered into separate leasing agreements for the Somerset and
Cayuga Plants with the Owner Trusts. The Partnership accounts for these
leases as a financing. (see Note 6).

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

In connection with the acquisition, NYSEG engaged an environmental
consulting firm to perform an environmental analysis of the potential
required remediations for soil and ground water contamination. The
Partnership engaged another environmental consulting firm to evaluate the
costs estimated by NYSEG's consultants. The environmental analysis and the
Partnership's estimate of other environmental remediation costs indicated
that there existed a range of potential remediation costs of between $8.5
million and $19.7 million, with a most probable liability of approximately
$12 million. The Partnership recorded $12 million as an undiscounted
liability under purchase accounting for the projected remediation cost. In
2002, the Partnership reduced its undiscounted liability by 2.2 million as
remediation was completed or more current estimates were received that
were lower than previously estimated. As of December 31, 2002, $20,000 was
classified as a current liability.

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

59

The Partnership received payments for installed capacity under the New
York Transition Agreement while it was in effect (see Note 2). Payments
received while the Somerset Plant was out of service, of approximately
$2.1 million, reduced the total amount of capitalized costs. Total costs
capitalized during construction were approximately $52 million, which
included approximately $5.2 million in capitalized interest.

The purchase agreement with NYSEG relating to the acquisition of the
Plants provided for a post-closing adjustment of the purchase price to
reflect the actual book value of inventories and a pro rata allocation of
various expenses as of the acquisition date. As a result of this
adjustment and to settle other contractual obligations, NYSEG returned
approximately $1.6 million to the Partnership in 2000.

4. PARTNERSHIP AGREEMENT

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

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

5. CAPITALIZATION

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

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

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

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

Collateral for the loan also includes 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.

AES Funding is dependent upon the residual cash flows from the Partnership
received in the form of distributions to service its debt. The loan is
payable on February 28, 2005, and bears interest at a variable rate based
on the terms of the loan agreement, which was 6.2% as of December 31,
2002. The Partnership has no obligation to repay this loan. If AES Funding
were unable to repay this loan, one of the remedies available to the
lenders would be to seek to sell the membership interests in AES New York
Holdings, L.L.C., which would divest AES of control of the Partnership.

60

6. LEASE FINANCING

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

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

2003 $ 1,665 $ 55,885 $ 57,550
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
Thereafter 610,010 642,156 1,252,166
--------- -------- ----------
Total minimum lease payments 639,325 917,341 1,556,666

Less imputed interest (917,341)
----------

Present value of minimum lease payments $ 639,325

Less current portion (1,665)
----------
Lease financing - long term $ 637,660
==========

Through July 2, 2020, and so long as no lease event of default exists, a
portion of the rent payable under each lease may be deferred until after
the final scheduled payment of the debt incurred by the Owner Trusts to
acquire the Somerset and Cayuga Plants. As of December 31, 2002, the
Partnership has not deferred any portion of the lease obligations.

The lease obligations are payable to the Owner Trusts. These obligations
bear imputed interest at 9.252% and 9.024% for the Somerset and Cayuga
Plants, respectively. Total assets under the leases of these two Plants
were $650 million at December 31, 2002. These amounts are included in
electric generation assets. The related accumulated depreciation, combined
for both leased Plants, as of December 31, 2002 and 2001, was
approximately $72.5 million and $52.1 million, respectively. The
agreements governing the leases restrict the Partnership's ability to
incur additional indebtedness, engage in other businesses, sell its
assets, or merge with another entity. The ability of the Partnership to
make distributions to its partners is restricted unless certain covenants,
including the maintenance of certain coverage ratios, are met (see Note
13). In connection with the lease agreements, the Partnership is required
to maintain an additional liquidity account. The required balance in the
additional liquidity account was initially equal to the greater of $65
million less the balance in the rent reserve account on May 14, 1999 (see
Note 2) or $29 million. As of December 31, 2002, the Partnership had
fulfilled its obligation to fund the additional liquidity account by
establishing a letter of credit, issued by Fleet Bank dated May 14, 1999,
in the stated amount of approximately $36 million (the Additional
Liquidity Letter of Credit). This letter of credit was established by AES
for the benefit of the Partnership. However, the Partnership is obligated
to replenish or replace this letter of credit in the event it is drawn
upon or needs to be replaced.

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

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

7. COMMITMENTS AND CONTINGENCIES

Coal Purchases - In connection with the acquisition of the Partnership's
four Plants, the Partnership assumed from NYSEG an agreement to purchase
the coal required by the Somerset and Cayuga Plants. Each year, either
party can request renegotiation of the price of one- third of the coal
supplied pursuant to this agreement. During 2001 the coal suppliers were
committed to sell and the Partnership was committed to purchase all three
lots of coal for the Somerset Plant as well as 70% of the anticipated coal
purchases for the Cayuga Plant. The supplier requested renegotiation
during 2001 for the 2002 lot but the parties failed to reach agreement.
Therefore, the parties had commitments in 2002 with respect to only two
lots for the Somerset Plant and 50% of the anticipated coal purchases at
the Cayuga Plant. The supplier requested renegotiation during 2002 for the
2003 lot plus the 2002 lot for

61

which agreement was not reached. On September 11, 2002, the Partnership
and the supplier reached agreement on both of the lots. Therefore, the
commitment of the Partnership for 2003 is three lots for the Somerset
Plant plus 70% of the anticipated coal usage for the Cayuga Plant. The
termination date for the contract is December 31, 2003. No later than June
30, 2003, the parties shall meet to determine if the agreement is to be
extended under mutually agreeable terms and conditions. If the agreement
were not extended, the Partnership would seek a new coal supplier.

62

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

Based on the coal purchase commitments for 2003, the Partnership has
expected coal purchases ranging between $70.0 million and $100.0 million.
Currently, the Partnership does not have any coal purchase commitments for
2004.

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

The Partnership was informed by NIMO that the Partnership would be
responsible for the monthly fees of $500,640 under the existing
transmission agreement to the originally scheduled termination date of
October 1, 2004. On October 5, 1999, the Partnership filed a complaint
against NIMO alleging that the Partnership has a right to non-firm
transmission service upon six months prior notice without payment of
$500,640 in monthly fees subsequent to the cancellation date of November
19, 1999. On March 9, 2000, a settlement was reached between the
Partnership and NIMO, which was subsequently approved by the Federal
Energy Regulatory Commission (FERC). According to the settlement, the
Partnership will continue to pay NIMO a fixed rate of $500,640 per month
during the period of November 20, 1999 to October 1, 2004, and in turn,
will receive a form of transmission service commencing on May 1, 2000,
which the Partnership believes will provide an economic benefit over the
period of May 1, 2000 to October 1, 2004. The Partnership has the right
under a Remote Load Wheeling Agreement (RLWA) to transmit 298 MW over firm
transmission lines from the Somerset Plant. The Partnership has the right
to designate alternate points of delivery on NIMO's transmission system
provided that the Partnership is not entitled to receive any transmission
service charge credit on the NIMO system.

On November 1, 2000, the effective date of the final settlement, the
transmission contract was classified as an energy-trading contract as
defined in EITF No. 98-10, Accounting for Contracts Involved in Energy
Trading and Risk Management Activities. From January 1, 2001 the contract
was accounted for as a derivative under SFAS No. 133. The transmission
contract was entered into because it provided a reasonable settlement for
resolving a FERC issue. The agreement is essentially a swap between the
congestion component of the locational prices posted daily by the NYISO in
western New York and the more heavily populated areas in eastern New York.
The agreement is a financially settled contract since there is no
requirement to flow power under this agreement. The agreement generates
gains or losses from exposure to shifts or changes in market prices. The
Partnership recorded income of approximately $8.9 million for the year
ended December 31, 2002 related to this contract.

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

63

On November 20, 2002, the Partnership signed an agreement with Union Bank
of California, N.A. for a one-year extension of the current facility to
January 2, 2004. Currently, lenders have committed to provide only $15
million of the $35 million secured revolving working capital and letter of
credit facility. The Partnership is attempting to obtain commitments for
the remaining $20 million. Our financial flexibility may be limited if we
are unable to obtain these commitments or substitute other sources of
credit.

While the Partnership attempts to obtain the remaining commitments on its
current facility, AES on January 6, 2003 authorized the Partnership to
provide letters of credit to counterparties on its $350 million senior
secured revolving credit facility to the amount of $25 million. At the
date of filing this annual report on Form 10-K the Partnership has letters
of credit in the amount of $14.4 million to support normal ongoing hedging
activities with a number of counterparties.

On October 3, 2002, Standard & Poor's lowered its rating on the
Partnership's $550 million pass through trust certificates and $35 million
working capital facility bank loan to BB+ from BBB- solely due to the
Partnership's rating linkage to AES. The rating was also placed on
CreditWatch with negative implications.

Environmental - The Partnership has recorded a liability for environmental
remediation associated with the acquisition of the Plants (see Note 3). On
an ongoing basis, the Partnership monitors its compliance with
environmental laws. Because of the uncertainties associated with
environmental compliance and remediation activities, future costs of
compliance or remediation could be higher or lower than the amount
currently accrued.

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

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

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

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

64

Nitrogen Oxide and Sulfur Dioxide Emission Allowances - The Plants emit
nitrogen oxide (NOx) and sulfur dioxide (SO2) as a result of burning coal
to produce electricity. The Plants have been allocated allowances by the
DEC to emit NOx during the ozone season, which runs from May 1 to
September 30. Each NOx allowance authorizes the emission of one ton of NOx
during the ozone season. The Plants are also subject to SO2 emission
allowance requirements imposed by the EPA. Each SO2 allowance authorizes
the emission of one ton of SO2 during the calendar year. Both NOx and SO2
allowances may be bought, sold, or traded. If NOx and/or SO2 emissions
exceed the allowance amounts allocated to the Plants, then the Partnership
may need to purchase additional allowances on the open market or otherwise
reduce its production of electricity to stay within the allocated amounts.
The Plants were net sellers of NOX allowances in 2002 and 2001. The Plants
were self-sufficient with respect to SO2 allowances in 2001; however, it
is expected that the Plants had a shortfall of approximately 6,600 SO2
allowances in 2002. The majority of the SO2 allowance shortfall was
covered with allowances purchased from the electricity generating stations
owned by an affiliate of the Partnership, AES Creative Resources, L.P.
(ACR), which are on long-term cold standby. The allowances were purchased
at quoted market prices.

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

The Plants voluntarily disclosed to the NYDEC in January 2003 that Cayuga
had inadvertently burned synfuel (coal with a latex binder applied), which
it is not permitted to burn. Cayuga had entered into an agreement with a
supplier to purchase coal. It received approximately one 9000-ton train
per month from April 24, 2001 to December 27, 2002. In January 2003, The
Plants became aware that the product we were receiving was synfuel. The
plants have suspended all shipments from that supplier until a resolution
is reached. The plants have reviewed the emission and operation data
showed there was no adverse effect to air quality attributable to burning
the material with applicable permit emissions limits. The Partnership is
unable to predict any potential actions or fines the NYSDEC may require,
if any.

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

8. RELATED PARTY TRANSACTIONS

The Partnership has entered into a contract with Somerset Railroad
Corporation (SRC), a wholly owned subsidiary of AES NY3, L.L.C., which is
an indirect wholly owned subsidiary of AES, pursuant to which SRC will
haul coal and limestone to the Somerset Plant and make its rail cars
available to transport coal to the Cayuga Plant. The Partnership will pay
amounts sufficient to enable SRC to pay all of its operating and other
expenses, including all out- of-pocket expenses, taxes, interest on and
principal of SRC's outstanding indebtedness, and all capital expenditures
necessary to permit SRC to continue to provide rail service to the
Somerset and Cayuga Plants. As of December 31, 2002, 2001 and 2000, $3.8
million, $4.2 million and $4.6 million, respectively, has been recorded by
the Partnership as operating expenses and other accrued liabilities under
this agreement.

On August 14, 2000, SRC entered into a $26 million credit facility with
Fortis Capital Corp. which replaced in its entirety a credit facility for
the same amount previously provided to SRC by an affiliate of CIBC World
Markets. The new credit facility provided by Fortis Capital Corp. consists
of a 14-year term note (maturing on May 6, 2014), with principal and
interest payments due quarterly. From August 14, 2000 to August 13, 2002,
the interest rate on the loans under this credit facility is equal to a
Base Rate plus 0.625% for the Base Rate loans and LIBOR plus 1.375% for
LIBOR loans. From August 14, 2002 to August 13, 2005, the interest rate on
the loans under this credit facility is equal to a Base Rate plus 0.750%
for the Base Rate loans and LIBOR plus 1.500% for LIBOR loans. From August
14, 2005 to August 13, 2008, the interest rate on the loans under this
credit facility is equal to a Base Rate plus 0.875% for the Base Rate
loans and LIBOR plus 1.625% for LIBOR loans. From August 14, 2012 to
August 13, 2014, the interest rate on the loans under this credit facility
is equal to a Base Rate plus 1.125% for the Base Rate loans and LIBOR plus
1.875% for LIBOR loans. From August 14, 2008 to August 13, 2012, the
interest rate on the loans under this credit facility is equal to a Base
Rate plus 1.375% for the Base Rate loans and LIBOR plus 2.125% for LIBOR
loans. The principal amount of SRC's outstanding indebtedness under this
credit facility was approximately $21.4 million as of December 31, 2002.

65

We entered into an arrangement with AES Odyssey, L.L.C. ("Odyssey"), a
direct wholly-owned subsidiary of The AES Corporation, for power marketing
agreement. This agreement commenced on November 27, 2000 . The initial
term of the agreement was for a term of three years. In March 2002, a new
agreement was reached, for a term of five years through February 28, 2007
pursuant to which Odyssey provides data management, marketing, scheduling,
invoicing and risk management services for a fee of $300,000 per month.
Odyssey acts as agent on behalf of us in the over-the-counter and NYISO
markets.

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

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

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

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

Prior to June 30, 1999, AES paid approximately $3.2 million in costs
related to the acquisition of the NYSEG plants, which are shown in on the
consolidated balance sheets as due to AES Corporation and affiliates. Of
the $3.2 million, approximately $1.1 million was for internal costs
incurred by AES, and was treated as a reduction of contributed capital.

AES contributed approximately $1.5 million and $9.4 million to the
Partnership in 2002 and 2001, respectively, related to the construction of
the SCR on Unit 1 of the Cayuga Plant, which became operational on June 7,
2001.

9. BENEFIT PLANS

Effective May 14, 1999, the Partnership adopted The Retirement Plan for
Employees of AES NY, L.L.C. (the Plan), a defined benefit pension plan.
The Plan covers people employed both under collectively bargained and
non-collectively bargained arrangements. Certain people formerly employed
by NYSEG (the Transferred Persons) receive credit under the Plan for
compensation and service earned while employed by NYSEG. The amount of any
benefit payable under the Plan to a Transferred Person will be offset by
the amount of any benefit payable to such Transferred Person under the
Retirement Plan for Employees of NYSEG. Effective May 29, 1999, the
ability to commence participation in the Plan and the accrual of benefits
under the Plan ceased with respect to non-collectively bargained people
and the accrued benefits of any such participant were fixed as of such
date. As of December 31, 2002, the Plan was funded at least to the extent
required by Internal Revenue Code (IRC) Section 412 minimum funding and
not more than the requirement of IRC Section 404, maximum contribution
limits. The Partnership will make at least the required minimum
contribution within the Employee Retirement Income Security Act (ERISA)
guidelines. Pension benefits are based on years of credited service, age
of the participant, and average earnings. During 2002, 2001 and 2000,
collectively bargained people were offered the opportunity to freeze their
accrued benefit payable under the Plan and opt into the AES Profit Sharing
and Stock Ownership Plans.

Significant assumptions were used in the calculations of the net benefit
cost and projected benefit obligation for the periods ending October 31,
2002 and December 31, 2001 and 2000. In developing the Partnership's
expected long-term rate of return assumption, the Partnership evaluated
input from its actuaries, plan asset manager. Projected returns are based
on a broad range of equity and bond indices. The Partnerships expected 8%
long-term rate of return on Qualified Plan assets is based on the
allocation assumption of 60% equities (50% Growth and 50% Value), with a
10% long term rate of return and 40% in fixed income investments, with a
5.5% long-term rate of return. Because of market fluctuation, its actual
allocation as of October 31, 2002, was 52% equities and 48% in fixed
income investments. However, the Partnership believes that its long-term
asset allocation on

66

average will approximate 60% equities and 40% fixed income investments.
The Partnership regularly reviews the asset allocation with the asset
manager and periodically rebalances its investments to its targeted
allocation when appropriate. The Partnership continues to believe that the
8% is a reasonable long-term rate of return on its qualified plan assets,
despite the market downturn. The Partnership will continue to evaluate its
actuarial assumptions, including its expected rate of return, at least
annually, and will adjust as necessary.

67

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

2002 2001 2000
-------- -------- -------

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

(In Thousands)
Defined Benefit Pension Plan Costs:
Components of net periodic benefit cost (in thousands)
Service cost $ 416 $ 408 $ 851
Interest cost 1,358 1,293 1,487
Expected return on plan assets (474) (312) (56)
Curtailment gain - - (5,271)
------ ------ -------
Net periodic benefit cost $1,300 $1,389 $(2,989)
====== ====== =======

The assets and liabilities of the Plan were valued as of October 31, 2002.
This measurement date is a change from the previous practice of utilizing
a December 31 measurement date for 2001 and 2000. The values of the assets
and liabilities as of October 31, 2002 were not materially different than
the values as of December 31, 2002.

2002 2001 2000
-------- -------- -------

Projected Benefit Obligation
Change in projected benefit obligation (in thousands):
Projected benefit obligation, beginning of period $ 21,840 $ 20,801 $ 23,880
Service cost 347 408 851
Interest cost 1,132 1,293 1,487
Actuarial (gain) loss - (469) 409
Benefits paid (189) (193) (167)
Curtailment (790) - (5,659)
Special Termination Loss 2,927 - -
-------- --------- --------

Projected benefit obligation, end of period $ 25,267 $ 21,840 $ 20,801
======== ========= ========
Plan Assets:
Change in plan assets (in thousands):
Fair value of plan assets, beginning of period $ 4,873 $ 2,020 $ -
Actual return on plan assets (512) (156) 77
Employer contributions 2,981 3,202 2,110
Benefits paid (189) (193) (167)
-------- --------- ---------

Fair value of plan assets, end of period $ 7,153 $ 4,873 $ 2,020
-------- --------- ---------
Funded status/accrued benefit liability $(18,114) $ (16,968) $ (18,781)
Unrecognized Net Loss 675 - -
-------- --------- ---------
(Accrued)/Prepaid Pension Cost, end of period $(17,439) $ (16,968) $ (18,781)
======== ========= =========

The projected benefit obligation of the Plan as of May 14, 1999, as
actuarially determined, was recorded by the Partnership as a purchase
accounting liability (see Note 3) under Accounting Principles Board
Opinion (APB) No. 16, Business Combinations. The accumulated benefit
obligation was approximately $20.5 million, $16.7 million and $15.5
million as of December 31, 2002, 2001 and 2000, respectively.

During 2000, 137 participants of the Plan opted out and either joined an
AES Plan, retired, or became terminated. This resulted in a curtailment
gain to the Plan of approximately $ 5.3 million and is included within
other income in the statement of income. As of December 31, 2002, the Plan
had 85 active participants.

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

68

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

Other Postretirement Benefit Plan

On July 1, 2000, AES Greenidge adopted SFAS No. 106 "Employees' Accounting
for Postretirement Benefit Other Than Pension." Prior years cost were
deemed immaterial for presentation purposes.

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 (in thousands): $ -
Unrecognized Prior Service Cost 1,083
Unrecognized Net Loss/(Gain) (14)
-------
Fair value of plan assets, end of year $ 1,069
-------
Funded status/accrued benefit liability $ 243
=======

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

AES Somerset, AES Cayuga and AES Westover have created Voluntary
Employees' Beneficiary Associations ("VEBA") to fund their retiree medical
expenses. Employer contributions to pay the claims of the employees are
deposited in the VEBA Trusts. Currently, the VEBA Trusts are to pay the
medical claims of the employees who are union members and who retire from
the Partnership and the medical claims of their spouses and dependants.
Some of the VEBA trusts offer supplemental Medicare benefits, the other
Trusts' coverage end when the employee is Medicare eligible. These VEBA
trusts were created in 2002, the funding schedule for the trusts are as
follows: $362,000 for 2003-5, respectively and $203,000 for 2006.

69

10. LONG-TERM INCENTIVE PROGRAM

Stock Option Plan - Employees of the Partnership participate in the AES
Stock Option Plan (the SOP) that provides for grants of stock options to
eligible participants. The following disclosures relate to the Partnership
employees' share of benefits under the SOP. There were no options granted
during 1999 and 2002. Options granted during 2001 and 2000 of 469,899 and
12,756, respectively, had weighted average fair value of approximately
$13.52 and $22.50, respectively, using the Black-Scholes valuation method.
Significant assumptions used in the Black-Scholes valuation method for
shares granted in 2001 and 2000 were: expected stock price volatility of
86% and 48% respectively; expected dividend yield of 0% and 0%,
respectively; risk- free interest rate of 4.8% and 5.1%, respectively; and
an expected life of 8 years and 7 years, respectively.

Generally, outstanding stock options become exercisable on a cumulative
basis commencing two years from the date of grant and expire ten years
after the date of grant. Additionally, some options become exercisable in
as little as one year (100% in one year) or as many as four years (25%
each year). As permitted under SFAS No. 123,"Accounting for Stock-Based
Compensation", AES applies APB Opinion No. 25 in accounting for the SOP.
As the exercise prices of all stock options are equal to their fair market
values at the time the options are granted, the Partnership did not
recognize any compensation expense related to the SOP using the intrinsic
value based method. Had compensation expense been recognized using the
fair value based method under SFAS No. 123, the Partnership's consolidated
earnings would have decreased by $6,117,979 and $273,368 in 2001 and 2000,
respectively. (See new accounting pronouncements in reference to the
effect of SFAS No. 148.)

11. FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of the Partnership's current financial assets and
liabilities approximate their carrying values. The fair value estimates
are based on pertinent information available as of December 31, 2002. The
Partnership is not aware of any factors that would significantly affect
the estimated fair value amounts since that date.

12. SEGMENT INFORMATION

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

13. RESTRICTIONS ON DISTRIBUTIONS TO PARTNERS

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

14. SUBSEQUENT EVENTS

Cash flow from the Partnership's operations during the second half of 2002
was sufficient to cover the aggregate rental payments under the leases on
the Somerset and Cayuga Plants due January 2, 2003. On this date, rental
payments were made in the amount of $28.7 million.

Cash flow from operations in excess of the aggregate rental payments under
the Partnership's leases may be distributed to its partners if certain
criteria are met. On January 8, 2003, the Partnership made a distribution
payment of $38.7 million.

The Partnership borrowed $9.7 million on January 10, 2003, for working
capital purposes under the $35 million secured revolving working capital
and letter of credit facility with Union Bank of California, N.A. The
borrowing was at an interest rate of 5.75%. The $9.7 million was repaid in
full on January 28,2003.

70

INDEPENDENT AUDITORS' REPORT

To the Member of AES NY, L.L.C.

We have audited the accompanying consolidated balance sheets of AES NY, L.L.C.
(an indirect wholly owned subsidiary of The AES Corporation) and subsidiaries
(the Company) as of December 31, 2002 and 2001. These financial statements are
the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated balance sheets present fairly, in all
material respects, the financial position of AES NY, L.L.C. and subsidiaries as
of December 31, 2002 and 2001, in conformity with accounting principles
generally accepted in the United States of America.

/s/Deloitte & Touche LLP

McLean, Virginia
January 24, 2003

71

AES NY, L.L.C.
CONSOLIDATED BALANCE SHEETS,
DECEMBER 31, 2002 and DECEMBER 31, 2001

(Amounts in Thousands)
- ---------------------------------------------------------------------------------------------
December 31, 2002 2001
---- -----

ASSETS
Current Assets:
Restricted cash:
Operating - cash and cash equivalents $ 5,116 $ 5,805
Revenue account 76,566 71,606
Accounts receivable - trade 35,233 27,590
Accounts receivable - affiliates 2,935 3,254
Accounts receivable - other 1,264 2,316
Inventory 26,982 29,615
Prepaid expenses 7,726 6,539
------------ ------------
Total current assets 155,822 146,725
------------ ------------
PROPERTY, PLANT, EQUIPMENT, AND RELATED ASSETS:
Land 7,461 7,334
Electric generation assets - net of
accumulated depreciation of $122,378 and $86,544 929,654 958,857
------------ ------------
Total property, plant, equipment and related assets 937,115 966,191
------------ ------------
OTHER ASSETS:
Deferred Financing -net of
accumulated amortization of $863 and $359 293 480
Derivative valuation 2,510 55,182
Transmission congestion contract 2,416 -
Rent reserve account 31,717 31,719
------------ ------------
TOTAL ASSETS $ 1,129,873 $ 1,200,297
============ =============

LIABILITIES AND MEMBERS' CAPITAL

CURRENT LIABILITIES:
Accounts payable $ 1,195 $ 1,663
Lease financing - current 1,665 6,223
Environmental remediation 35 155
Accrued interest expense 28,078 28,353
Due to The AES Corporation and affiliates 7,173 6,586
Accrued coal and rail expense 8,492 9,652
Accrued expenses and other liabilities 11,264 9,749
------------ ------------
Total current liabilities 57,902 62,381
------------ ------------

LONG-TERM LIABILITIES:
Lease financing - long term 637,660 639,326
Environmental remediation 9,192 13,420
Defined benefit plan obligation 18,147 16,630
Derivative valuation liability 20,996 26,665
Transmission congestion contract - 3,506
Other liabilities 2,600 1,058
------------ ------------
Total long-term liabilities 688,595 700,605
------------ ------------
TOTAL LIABILITIES 746,497 762,986

COMMITMENTS AND CONTINGENCIES (Note 7)

MINORITY INTEREST 379,542 432,938
MEMBER'S EQUITY 3,834 4,373
------------ ------------
TOTAL LIABILITIES AND MEMBERS' CAPITAL $ 1,129,873 $ 1,200,297
============ ============

The notes are an integral part of the consolidated Balance Sheets

72

AES NY, L.L.C
NOTES TO CONSOLIDATED BALANCE SHEETS
YEARS ENDED DECEMBER 31, 2002 AND 2001
===============================================================================

1. GENERAL

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

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

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

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

AEE and ACR entered into an arrangement with AES Odyssey, L.L.C.
("Odyssey"), a direct wholly-owned subsidiary of The AES Corporation, for
power marketing agreement. This agreement commenced on November 27, 2000 .
The initial term of the agreement was for a term of three years. In March
2002, a new agreement was reached, for a term of five years through
February 28, 2007 pursuant to which Odyssey provides data management,
marketing, scheduling, invoicing and risk management services for a fee of
$300,000 per month. Odyssey acts as agent on behalf of us in the
over-the-counter and NYISO markets. (see note 7)

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

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

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

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

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

2. SIGNIFICANT ACCOUNTING POLICIES

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

73

The assets of the Company on a stand-alone basis at December 31, 2002 and
2001 (using the equity method of accounting) consist only of the 1%
ownership interest in AEE ($4,330,000 and $4,330,000, respectively) and
the 1% ownership interest in ACR ($32,000 and $32,000, respectively). The
Company had no liabilities as of December 31, 2002 and 2001, other than
liabilities of AEE and ACR for which it is responsible as General Partner
of AEE and ACR.

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

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

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

2002 2001
--------- --------
Coal and other raw materials $ 11,342 $ 13,488
Spare parts, materials, and supplies 15,640 16,127
--------- --------

Total $ 26,982 $ 29,615
========= ========

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

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

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

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

2002
---------------------------------
AEE ACR Total

Electric generation assets $1,046,876 $ 5,156 $1,052,032
Accumulated depreciation and amortization (117,222) (5,156) $ (122,378)
---------- ------- ----------
Total $ 929,654 $ - $ 929,654
========== ======= ==========

74

2001
-------------------------------
AEE ACR Total

Electric generation assets $1,039,867 $ 5,534 $1,045,401
Accumulated depreciation and amortization (82,205) (4,339) $ (86,544)
---------- ------- ---------
Total $ 957,662 $ 1,195 $ 958,857
========== ======= ==========

Rent Reserve Account - As part of AEE's lease obligation (see Note 6), AEE
is required to maintain a rent reserve account equal to the maximum
semiannual payment with respect to the sum of basic rent (other than
deferrable payments) and fixed charges expected to become due on any one
basic rent payment date in the immediately succeeding three-year period.
As of December 31, 2002 and 2001, AEE had fulfilled this obligation by
entering into a Payment Undertaking Agreement, dated as of May 1, 1999,
among AEE, each Owner Trust (see Note 3) and Morgan Guaranty Trust Company
of New York (the Payment Undertaking Agreement). On May 14, 1999, AEE
deposited with Morgan Guaranty Trust Company of New York approximately
$28.7 million pursuant to the Payment Undertaking Agreement. The accreted
value of the Payment Undertaking Agreement at any time includes interest
earned there under at an interest rate of 4.79% per annum. Interest
earnings as of December 31, 2002, 2001, and 2000 were approximately $1.5
million, $1.5 million and $1.4 million, respectively, and are included in
the rent reserve account balance. At December 31, 2002 and 2001, the
accreted value of the Payment Undertaking Agreement exceeded the required
balance of the rent reserve account. This amount is being accounted for as
a restricted cash balance and is included within the rent reserve account
on the accompanying balance sheets, as it can only be utilized to satisfy
lease obligations. In the future, AEE may fulfill its obligation to
maintain the required balance of the rent reserve account either by
deposits into the rent reserve account or by making amounts available
under the Payment Undertaking Agreement, such that the aggregate amount of
such deposits in the rent reserve account and amounts available to be paid
under the Payment Undertaking Agreement are equal to the required balance
of the rent reserve account.

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

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

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

Comprehensive Income - In 1999, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income",
which establishes rules for the reporting of comprehensive income and its
components. As of December 31, 2002, the Company has recorded $18.4
million of other comprehensive loss due to the adoption of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities". In the
years prior to the adoption of SFAS No. 133, the Company did not have any
items of other comprehensive income.

On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities", which, as amended,
established new accounting and reporting standards for derivative
instruments and hedging activities. The Statement requires that the
Company recognize all derivatives, as defined in the Statement, on the
balance sheet at fair value. Derivatives, or any portion thereof, that are
not effective hedges are adjusted to fair value through income.
Derivatives that are effective hedges are recognized in other
comprehensive income (loss) until the hedged items are recognized in
earnings. The adoption of SFAS No. 133 on January 1, 2001, resulted in a
cumulative reduction of Other Comprehensive Income in member's equity of
$66.3 million.

AEE utilizes derivative financial instruments to hedge commodity price
risk. AEE utilizes electric derivative instruments, including swaps and
forwards, to hedge the risk related to forecasted electricity sales over
the next three years. The majority of AEE's electric derivatives are
designated and qualify as cash flow hedges. No hedges were derecognized or
discontinued during the year ended December 31, 2002. No significant
amounts of hedge ineffectiveness were recognized in earnings during the
year ended December 31, 2002.

75

Gains and losses on derivatives reported in accumulated other
comprehensive income are reclassified into earnings when the hedged
forecasted sale occurs. Approximately $14.7 million of other comprehensive
income is expected to be recognized as a reduction to earnings over the
next twelve months. Amounts recorded in Other Comprehensive Income during
the year ended December 31, 2002, were as follows (in millions):

Beginning Balance on January 1, 2002 $28.5
Reclassified to earnings (2.5)
Change in fair value (44.4)
-----
Balance, December 31, 2002 $(18.4)
=====

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

Revenue Recognition - Revenues from the sale of electricity are recorded
based upon output delivered and rates specified under contract terms.
Revenues generated from commodity forwards, swaps and options, which are
entered into for the hedging of forecasted sales, are recorded based on
settlement accounting with the net amount received recognized as revenue
for 2000. Beginning in 2001, such contracts were accounted for in
accordance with SFAS No. 133. Revenues for ancillary and other services
are recorded when the services are rendered.

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

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations". SFAS No. 143, which is effective January 1, 2003,
requires entities to record the fair value of a legal liability for an
asset retirement obligation in the period in which it is incurred. When a
new liability is recorded beginning in 2003, the entity will capitalize
the costs of the liability by increasing the carrying amount of the
related long-lived asset. The liability is accreted to its present value
each period, and the capitalized cost is depreciated over the useful life
of the related asset. Upon settlement of the liability, an entity settles
the obligation for its recorded amount or incurs a gain or loss upon
settlement. The Company will adopt SFAS No. 143 effective January 1, 2003.

The Company has completed a detailed assessment of the specific
applicability and implications of SFAS No. 143. The scope of SFAS No. 143
includes primarily active ash landfills and water treatment basins. Upon
adoption of SFAS No. 143, the Company will record a liability of
approximately $9.7 million, a net asset of approximately $3.4 million, and
a cumulative effect of a change in accounting principle of approximately
$6.3 million, after income taxes.

In August 2001, the FASB issued SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets." The provisions of this statement are
effective for financial statements issued for fiscal years beginning after
December 15, 2001, and address reporting for the impairment or disposal of
long-lived assets. SFAS No. 144 provides guidance for developing estimates
of future cash flows used to test assets for recoverability and requires
that assets to be disposed of be classified as held for sale when certain
criteria are met. The statement also extends the reporting of discontinued
operations to all components of an entity and provides guidance for
recognition of a liability for obligations associated with disposal
activity. The Company's initial adoption of the provisions of SFAS No. 144
did not have any impact on its financial position or results of
operations.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No.4, 44, and 64, Amendment of FASB Statement No. 13, and
Technical Corrections." This statement eliminates the current requirement
that gains and losses on debt extinguishments must be classified as
extraordinary items in the income statement. Instead, such gains and
losses will be classified as extraordinary items only if they are deemed
to be unusual and infrequent, in accordance with the current GAAP criteria
for extraordinary classification. In addition, SFAS No. 145 eliminates an
inconsistency in lease accounting by requiring that modifications of
capital leases that result in reclassification as operating leases be
accounted for consistently with sale-leaseback accounting rules. The
statement also contains other nonsubstantive corrections to authoritative
accounting literature. The changes related to debt extinguishments will be
effective for fiscal years beginning after May 15, 2002, and the changes
related to lease accounting will be effective for transactions occurring
after May 15, 2002. The adoption of this standard does not have a
significant impact on the Company's consolidated financial statements.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities," which addresses accounting
for restructuring and similar costs. SFAS No. 146 supersedes previous
accounting guidance, principally Emerging Issues Task Force (EITF) Issue
No. 94-3. The Company will adopt the provisions of SFAS No. 146 for
restructuring activities initiated after December 31, 2002. SFAS No. 146
requires that the liability for costs associated with an exit or disposal
activity be recognized when the liability is incurred. Under EITF No.
94-3, a liability for an exit cost was

76

recognized at the date of a company's commitment to an exit plan. SFAS No.
146 also establishes that the liability should initially be measured and
recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of
recognizing future restructuring costs as well as the amount recognized.
This standard will be accounted for prospectively.

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

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

Reclassifications - Certain prior year and prior period amounts have been
reclassified on the consolidated financial statements to conform with the
2002 presentation.

3. ACQUISITION

On May 14, 1999, AEE's four Plants were acquired from NYSEG for
approximately $914 million. AEE acquired ownership of two of the Plants,
Westover (formerly known as Goudey) and Greenidge. The other two Plants,
Somerset and Cayuga, were acquired for $650 million by twelve unrelated
third-party owner trusts (collectively, the Owner Trusts) organized by
three unrelated institutional investors. Simultaneously, AEE entered into
separate leasing agreements for the Somerset and Cayuga Plants with the
Owner Trusts. The Company accounts for these leases as a financing (see
Note 6).

The acquisition of the AEE Plants was financed by capital contributions
from the Company and the Limited Partner in an aggregate amount equal to
the purchase price for the Plants, certain associated costs and expenses,
and certain amounts for working capital less the net proceeds from the
leasing transactions with respect to the Somerset and Cayuga Plants
described above. The acquisition has been accounted for as an asset
purchase. In connection with the acquisition of the AEE Plants, NYSEG
engaged an environmental consulting firm to perform an environmental
analysis of the potential required remediations for soil and ground water
contamination. AEE engaged another environmental consulting firm to
evaluate the costs estimated by NYSEG's consultants. The environmental
analysis and AEE's estimate of other environmental remediation costs
indicated that there existed a range of potential remediation costs of
between $8.5 million and $19.7 million, with a most probable liability of
approximately $12 million. AEE recorded $12 million as an undiscounted
liability under purchase accounting for the projected remediation cost. In
2002, AEE reduced its undiscounted liability by $2.2 million as
remediation was completed or more current estimates were received for
lower than the amounts previously estimated. As of December 31, 2002,
$20,000 was classified as a current liability.

Also, in connection with this transaction, ACR acquired from NYSEG two
older coal-fired plants, Jennison and Hickling (Note 1). An environmental
liability of $2.6 million was recorded in connection with this
acquisition, which represented the most probable liability based on a
range calculated by NYSEG's environmental consultants and reviewed by
other environmental consultants hired by ACR. As of December 31, 2002,
$15,000 was classified as a current liability.

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

77

costs, wages of people involved in the construction, and interest expense
during the period were capitalized by AEE. The Somerset Plant was placed
back in service on June 28, 1999.

AEE received payments for installed capacity under the New York Transition
Agreement while it was in effect (see Note 2). Payments received while the
Somerset Plant was out of service, of approximately $2.1 million, reduced
the total amount of capitalized costs. Total costs capitalized during
construction were approximately $52 million, which included approximately
$5.2 million in capitalized interest.

The purchase agreement with NYSEG relating to the acquisition of the AEE
Plants provided for a post-closing adjustment of the purchase price to
reflect the actual book value of inventories and a pro rata allocation of
various expenses as of the acquisition date. As a result of this
adjustment and to settle other contractual obligations, NYSEG returned
approximately $1.6 million to AEE in 2000.

4. CAPITALIZATION

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

78

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

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

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

Collateral for the loan also includes 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 Company and the
Limited Partner.

AES Funding is dependent upon the residual cash flows from AEE and ACR
received in the form of distributions to service its debt. The loan is
payable on February 28, 2005, and bears interest at a variable rate based
on the terms of the loan agreement, which was 6.2% as of December 31,
2002. If AES Funding were unable to repay this loan, one of the remedies
available to the lenders would be to seek to sell the membership interests
in AES New York Holdings, L.L.C., which would divest AES of control of the
Company, AEE and ACR.

5. LEASE FINANCING

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

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

2003 $ 1,665 $ 55,885 $ 57,550
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
Thereafter 610,010 642,156 1,252,166
------- -------- ------------
Total minimum lease payments 639,325 917,341 1,556,666

Less imputed interest (917,341)
------------

Present value of minimum lease payments $ 639,325

Less current portion (1,665)
------------
Lease financing - long term $ 637,660
============

Through July 2, 2020, and so long as no lease event of default exists, a
portion of the rent payable under each lease may be deferred until after
the final scheduled payment of the debt incurred by the Owner Trusts to
acquire the Somerset and Cayuga Plants. As of December 31, 2002, AEE has
not deferred any portion of the lease obligations.

79

The lease obligations are payable to the Owner Trusts. These obligations
bear imputed interest at 9.252% and 9.024% for the Somerset and Cayuga
Plants, respectively. Total assets under the leases of these two Plants
were $650 million at December 31, 2002. These amounts are included in
electric generation assets. The related accumulated depreciation, combined
for both leased Plants, as of December 31, 2002 and 2001, was
approximately $72.5 million and $52.1 million, respectively. The
agreements governing the leases restrict AEE's ability to incur additional
indebtedness, engage in other businesses, sell its assets, or merge with
another entity. The ability of AEE to make distributions to its partners
is restricted unless certain covenants, including the maintenance of
certain coverage ratios, are met. In connection with the lease agreements,
AEE is required to maintain an additional liquidity account (see Note 13).
The required balance in the additional liquidity account was initially
equal to the greater of $65 million less the balance in the rent reserve
account on May 14, 1999 (see Note 2) or $29 million. As of December 31,
2002, AEE had fulfilled its obligation to fund the additional liquidity
account by establishing a letter of credit, issued by Fleet Bank dated May
14, 1999, in the stated amount of approximately $36 million (the
Additional Liquidity Letter of Credit). This letter of credit was
established by AES for the benefit of AEE. However, AEE is obligated to
replenish or replace this letter of credit in the event it is drawn upon
or needs to be replaced.

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

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

6. COMMITMENTS AND CONTINGENCIES

Coal Purchases - In connection with the acquisition of AEE's four Plants,
AEE assumed from NYSEG an agreement to purchase the coal required by the
Somerset and Cayuga Plants. Each year, either party can request
renegotiation of the price of one-third of the coal supplied pursuant to
this agreement. During 2001 the coal suppliers were committed to sell and
AEE was committed to purchase all three lots of coal for the Somerset
Plant as well as 70% of the anticipated coal purchases for the Cayuga
Plant. The supplier requested renegotiation during 2001 for the 2002 lot
but the parties failed to reach agreement. Therefore, the parties had
commitments in 2002 with respect to only two lots for the Somerset Plant
and 50% of the anticipated coal purchases at the Cayuga Plant. The
supplier requested renegotiation during 2002 for the 2003 lot plus the
2002 lot for which agreement was not reached. On September 11, 2002, AEE
and the supplier reached agreement on both of the lots. Therefore, the
commitment of AEE for 2003 is three lots for the Somerset Plant plus 70%
of the anticipated coal usage for the Cayuga Plant. The termination date
for the contract is December 31, 2003. No later than June 30, 2003, the
parties shall meet to determine if the agreement is to be extended under
mutually agreeable terms and conditions. If the agreement were not
extended, AEE would seek a new coal supplier.

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

Based on the coal purchase commitments for 2003, AEE has expected coal
purchases ranging between $70.0 million and $100.0 million. Currently, AEE
does not have any coal purchase agreements for 2004.

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

80

AEE was informed by NIMO that AEE would be responsible for the monthly
fees of $500,640 under the existing transmission agreement to the
originally scheduled termination date of October 1, 2004. On October 5,
1999, AEE filed a complaint against NIMO alleging that AEE has a right to
non-firm transmission service upon six months prior notice without payment
of $500,640 in monthly fees subsequent to the cancellation date of
November 19, 1999. On March 9, 2000, a settlement was reached between AEE
and NIMO, which was subsequently approved by the Federal Energy Regulatory
Commission (FERC). According to the settlement, AEE will continue to pay
NIMO a fixed rate of $500,640 per month during the period of November 20,
1999 to October 1, 2004, and in turn, will receive a form of transmission
service commencing on May 1, 2000, which AEE believes will provide an
economic benefit over the period of May 1, 2000 to October 1, 2004. AEE
has the right under a Remote Load Wheeling Agreement (RLWA) to transmit
298 MW over firm transmission lines from the Somerset Plant. AEE has the
right to designate alternate points of delivery on NIMO's transmission
system provided that AEE is not entitled to receive any transmission
service charge credit on the NIMO system.

On November 1, 2000, the effective date of the final settlement, the
transmission contract was classified as an energy-trading contract as
defined in EITF No. 98-10, Accounting for Contracts Involved in Energy
Trading and Risk Management Activities. From January 1, 2001 the contract
was accounted for as a derivative under SFAS No. 133. The transmission
contract was entered into because it provided a reasonable settlement for
resolving a FERC issue. The agreement is essentially a swap between the
congestion component of the locational prices posted daily by the NYISO in
western New York and the more heavily populated areas in eastern New York.
The agreement is a financially settled contract since there is no
requirement to flow power under this agreement. The agreement generates
gains or losses from exposure to shifts or changes in market prices. AEE
recorded income of approximately $8.9 million for the year ended December
31, 2002 related to this contract.

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

On November 20, 2002, AEE signed an agreement with Union Bank of
California, N.A. for a one-year extension of the current facility to
January 2, 2004. Currently, lenders have committed to provide only $15
million of the $35 million secured revolving working capital and letter of
credit facility. AEE is attempting to obtain commitments for the remaining
$20 million. Our financial flexibility may be limited if we are unable to
obtain these commitments or substitute sources of credit.

As we attempt to obtain the remaining commitments on our current facility,
The AES Corporation on January 6, 2003 authorized us to issue letters of
credit to counterparties on its $350 million senior secured revolving
credit facility to the amount of $25 million. At the date of filing our
annual report on Form 10-K we have letters of credit in the amount of
$14.4 million to support normal ongoing hedging activities with a number
of counterparties.

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

Environmental - The Company has recorded a liability for environmental
remediation associated with the acquisition of the Plants (see Note 3). On
an ongoing basis, the Company monitors its compliance with environmental
laws. Because of the uncertainties associated with environmental
compliance and remediation activities, future costs of compliance or
remediation could be higher or lower than the amount currently accrued.

81

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

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

By letter dated May 25, 2000, the DEC issued a Notice of Violation (NOV)
to NYSEG for violations of the Clean Air Act and the New York
Environmental Conservation Law at the Greenidge and Westover Plants
related to NYSEG's alleged failure to obtain an air permitting review for
repairs and improvements made during the 1980s and 1990s, which was prior
to the acquisition of the Plants by AEE.

Pursuant to the purchase agreement relating to the acquisition of the
Plants from NYSEG, AEE agreed to assume responsibility for environmental
liabilities that arose while NYSEG owned the Plants. On September 12,
2000, AEE agreed with NYSEG that AEE will assume the defense of and
responsibility for the NOV, subject to a reservation of its right to
assert applicable exceptions to its contractual undertaking to assume
preexisting environmental liabilities.

The Company is currently in negotiation with both the EPA and DEC. If the
Company's current proposal is rejected, the EPA and the DEC could issue a
notice or notices of violation (NOV) to AEE for violations of the Clean
Air Act and the Environmental Conservation Law. If the Attorney General,
the DEC or the EPA does file an enforcement action against the Somerset,
Cayuga, Westover, or Greenidge Plants, then penalties may be imposed and
further emission reductions might be necessary at these Plants which could
require AEE to make substantial expenditures. The Company is unable to
estimate the effect of such a NOV on its financial condition or results of
future operations.

Nitrogen Oxide and Sulfur Dioxide Emission Allowances -The AEE and ACR
Plants emit nitrogen oxide (NOx) and sulfur dioxide (SO2) as a result of
burning coal to produce electricity. The six Plants have been allocated
allowances by the DEC to emit NOx during the ozone season, which runs from
May 1 to September 30. Each NOx allowance authorizes the emission of one
ton of NOx during the ozone season. The six Plants are also subject to SO2
emission allowance requirements imposed by the EPA. Each SO2 allowance
authorizes the emission of one ton of SO2 during the calendar year. Both
NOx and SO2 allowances may be bought, sold, or traded. If NOx and/or SO2
emissions exceed the allowance amounts allocated to the six Plants, then
the Company may need to purchase additional allowances on the open market
or otherwise reduce its production of electricity to stay within the
allocated amounts. The six Plants were net sellers of NOX allowances in
2002 and 2001. The six Plants were self-sufficient with respect to SO2
allowances in 2001; however, the Plants had a shortfall of approximately
584 SO2 allowances in 2002.

82

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

AEE voluntarily disclosed to the NYDEC in January 2003 that Cayuga had
inadvertently burned synfuel (coal with a latex binder applied), which it
is not permitted to burn. Cayuga had entered into an agreement with a
supplier to purchase coal. It received approximately one 9000-ton train
per month from April 24, 2001 to December 27, 2002. In January 2003, AEE
became aware that the product we were receiving was synfuel. The plants
have suspended all shipments from that supplier until a resolution is
reached. The plants have reviewed the emission and operation data showed
there was no adverse effect to air quality attributable to burning the
material with applicable permit emissions limits. AEE is unable to predict
any potential actions or fines the NYSDEC may require, if any.

In October 1999, ACR entered into a consent order with the DEC to resolve
alleged violations of the water quality standards in the groundwater
downgradient of an ash disposal site. The consent order included a
suspended $5,000 civil penalty and a requirement to submit a work plan to
initiate closure of the landfill by October 8, 2000. The consent order
also called for a site investigation, which was conducted and indicated
that there is a possibility that some groundwater remediation at the site
may be required. Further compliance with this order included a Closure
Investigation Report which was submitted to the NYSDEC in the spring of
2000, and a Closure Plan which was submitted to the NYSDEC in January
2001. The Closure Plan was implemented in December 2001 when capping of
the site was completed. AEE2, L.L.C. contributed one-half of the costs to
close the landfill, which were approximately $2 million, and it will
contribute additional costs for long-term groundwater monitoring.
Nevertheless, if a groundwater remediation is required, AEE2, L.L.C. may
be responsible for a portion of such costs.

ACR has recently reported that concentrations of a number of chemicals in
a few groundwater wells increased in the year ending December 31, 2001,
since the Jennison and Hickling Plants were placed on long-term cold
standby. ACR and the DEC have agreed that remediation is not needed at
this time. ACR will continue to monitor the groundwater conditions and
include an assessment of the groundwater concentration trends in its 2002
annual report to the DEC.

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

7. RELATED PARTY TRANSACTIONS

AEE has entered into a contract with Somerset Railroad Corporation (SRC),
a wholly owned subsidiary of AES NY3, L.L.C., which is an indirect wholly
owned subsidiary of AES, pursuant to which SRC will haul coal and
limestone to the Somerset Plant and make its rail cars available to
transport coal to the Cayuga Plant. AEE will pay amounts sufficient to
enable SRC to pay all of its operating and other expenses, including all
out-of-pocket expenses, taxes, interest on and principal of SRC's
outstanding indebtedness, and all capital expenditures necessary to permit
SRC to continue to provide rail service to the Somerset and Cayuga Plants.
As of December 31, 2002, 2001 and 2000, $3.8 million, $4.2 million and
$4.6 million, respectively, has been recorded by AEE as operating expenses
and other accrued liabilities under this agreement.

On August 14, 2000, SRC entered into a $26 million credit facility with
Fortis Capital Corp. which replaced in its entirety a credit facility for
the same amount previously provided to SRC by an affiliate of CIBC World
Markets. The new credit facility provided by Fortis Capital Corp. consists
of a 14-year term note (maturing on May 6, 2014), with principal and
interest payments due quarterly. From August 14, 2000 to August 13, 2002,
the interest rate on the loans under this credit facility is equal to a
Base Rate plus 0.625% for the Base Rate loans and LIBOR plus 1.375% for
LIBOR loans. From August 14, 2002 to August 13, 2005, the interest rate on
the loans under this credit facility is equal to a Base Rate plus 0.750%
for the Base Rate loans and LIBOR plus 1.500% for LIBOR loans. From August
14, 2005 to August 13, 2008, the interest rate on the loans under this
credit facility is equal to a Base Rate plus 0.875% for the Base Rate
loans and LIBOR plus 1.625% for LIBOR loans. From August 14, 2012 to
August 13, 2014, the interest rate on the loans under this credit facility
is equal to a Base Rate plus 1.125% for the Base Rate loans and LIBOR plus
1.875% for LIBOR loans. From August 14, 2008 to August 13, 2012, the
interest rate on the loans under this credit facility is equal to a Base
Rate plus 1.375% for the Base Rate loans and LIBOR plus 2.125% for LIBOR
loans. The principal amount of SRC's outstanding indebtedness under this
credit facility was approximately $21.4 million as of December 31, 2002.

In November 2000, AEE entered into a three-year agreement for energy
marketing services with Odyssey, a wholly owned subsidiary of AES. In
March 2002, a new agreement was reached. The new agreement is for a

83

term of five years through February 28, 2007 pursuant to which Odyssey
provides data management, marketing, scheduling, invoicing and risk
management services for a fee of $300,000 per month.

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

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

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

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

Prior to June 30, 1999, AES paid approximately $3.2 million in costs
related to the acquisition of the NYSEG plants, , which are shown in on
the consolidated balance sheets as due to AES Corporation and affiliates.
Of the $3.2 million, approximately $1.1 million was for internal costs
incurred by AES, and was treated as a reduction of contributed capital.

AES contributed approximately $1.5 million and $9.4 million to AEE in 2002
and 2001, respectively, related to the construction of the SCR on Unit 1
of the Cayuga Plant, which became operational on June 7, 2001.

8. BENEFIT PLANS

Effective May 14, 1999, the Company adopted The Retirement Plan for
Employees of AES NY, L.L.C. (the Plan), a defined benefit pension plan.
The Plan covers people employed both under collectively bargained and
non-collectively bargained arrangements. Certain people formerly employed
by NYSEG (the Transferred Persons) receive credit under the Plan for
compensation and service earned while employed by NYSEG. The amount of any
benefit payable under the Plan to a Transferred Person will be offset by
the amount of any benefit payable to such Transferred Person under the
Retirement Plan for Employees of NYSEG. Effective May 29, 1999, the
ability to commence participation in the Plan and the accrual of benefits
under the Plan ceased with respect to non-collectively bargained people
and the accrued benefits of any such participant were fixed as of such
date. As of December 31, 2001, the Plan was funded at least to the extent
required by Internal Revenue Code (IRC) Section 412 minimum funding and
not more than the requirement of IRC Section 404, maximum contribution
limits. The Company will make the required minimum contribution within the
Employee Retirement Income Security Act (ERISA) guidelines. Pension
benefits are based on years of credited service, age of the participant,
and average earnings. During 2002, 2001 and 2000, collectively bargained
people were offered the opportunity to freeze their accrued benefit
payable under the Plan and opt into the AES Profit Sharing and Stock
Ownership Plans.

84

Significant assumptions were used in the calculations of the net benefit
cost and projected benefit obligation for the periods ending October 31,
2002 and December 31, 2001 and 2000. In developing the Company's expected
long-term rate of return assumption, the Company evaluated input from its
actuaries, plan asset manager. Projected returns are based on a broad
range of equity and bond indices. The Company expected 8% long-term rate
of return on Qualified Plan assets is based on the allocation assumption
of 60% equities (50% Growth and 50% Value), with a 10% long-term rate of
return, and 40% in fixed income investments, with a 5.5% long-term rate of
return. Because of market fluctuation, its actual allocation as of October
31, 2002, was 52% equities and 48% in fixed income investments. However,
the Company believes that its long-term asset allocation on average will
approximate 60% equities and 40% fixed income investments. The Company
regularly reviews the asset allocation with the asset manager and
periodically rebalance its investments to its targeted allocation when
appropriate. The Company continues to believe that the 8% is a reasonable
long-term rate of return on its qualified plan assets, despite the market
downturn. The Company will continue to evaluate its actuarial assumptions,
including its expected rate of return, at least annually, and will adjust
as necessary.

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

2002 2001
------- -------

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

(In Thousands)

Defined Benefit Pension Plan Costs:
Components of net periodic benefit cost (in thousands)
Service cost $ 416 $ 408
Interest cost 1,451 1,407
Expected return on plan assets (619) (411)
Curtailment gain - -
------ ------
Net periodic benefit cost $1,248 $1,404
====== ======

The assets and liabilities of the Plan were valued as of October 31, 2002.
This measurement date is a change from the previous practice of utilizing
a December 31 measurement date for 2001 and 2000. The values of the assets
and liabilities as of October 31, 2002 were not materially different than
the values as of December 31, 2002.

85

2002 2001
-------- --------

Projected Benefit Obligation
Change in projected benefit obligation (in thousands):
Projected benefit obligation, beginning of period $ 23,392 $ 22,697
Service cost 347 408
Interest cost 1,209 1,407
Actuarial (gain) loss - (803)
Benefits paid (305) (317)
Curtailment (790) -
Special Termination Loss 2,927 -
-------- --------
Projected benefit obligation, end of period $ 26,780 $ 23,392
======== ========
Plan Assets:
Change in plan assets (in thousands):
Fair value of plan assets (in thousands): $ 6,762 $ 4,105
Actual return on plan assets (711) (225)
Employer contributions 2,965 3,199
Benefits paid (305) (317)
-------- --------
Fair value of plan assets, end of period $ 8,711 $ 6,762
-------- --------
Funded status/accrued benefit liability $(18,069) $(16,630)
Unrecognized Net (Gain) (78) -
-------- --------
(Accrued)/Prepaid Pension Cost, end of year $(18,147) $(16,630)
======== ========

The projected benefit obligation of the Plan as of May 14, 1999, as
actuarially determined, was recorded by the Company as a purchase
accounting liability (see Note 3) under Accounting Principles Board
Opinion (APB) No. 16, Business Combinations. The accumulated benefit
obligation was approximately $22.1 million, $16.7 million and $17.4
million as of December 31, 2002, 2001 and 2000, respectively.

During 2000, 137 participants of the Plan opted out and either joined an
AES Plan, retired, or became terminated. This resulted in a curtailment
gain to the Plan of approximately $ 5.3 million and is included within
other income in the statement of income. As of December 31, 2002, the Plan
had 86 active participants.

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

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

Other Postretirement Benefit Plan

On July 1, 2000, AES Greenidge adopted SFAS No. 106 "Employees' Accounting
for Postretirement Benefit Other Than Pension." Prior years costs were
deemed immaterial for presentation purposes.

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
=====

86

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 (in thousands): $ -
Unrecognized Prior Service Cost 1,083
Unrecognized Net Loss/(Gain) (14)
-------
Fair value of plan assets, end of year $ 1,069
-------
Funded status/accrued benefit liability $ 243
=======

Weighted average discount rate for expense calculation is 6.25% in 2002.
Weighted average discount rate for accumulated postretirement benefit
obligation is 6.25% beginning December 31, 2001.

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

AES Somerset, AES Cayuga and AES Westover have created Voluntary
Employees' Beneficiary Associations (VEBA) to fund their retiree medical
expenses. Employer contributions to pay the claims of the employees are
deposited in the VEBA Trusts. Currently, the VEBA Trusts are to pay the
medical claims of the employees who are union members and who retire from
the Company or a subsidiary and the medical claims of their spouses and
dependants. Some of the VEBA trusts offer supplemental Medicare benefits,
the other Trusts' coverages end when the employee is Medicare eligible.
These VEBA trusts were created in 2002, These VEBA trusts were created in
2002, the funding schedule for the trusts are as follows: $362,000 for
2003-5, respectively and $203,000 for 2006.

9. LONG-TERM INCENTIVE PROGRAM

Stock Option Plan - Employees of the subsidiaries of the Company
participate in the AES Stock Option Plan (the SOP) that provides for
grants of stock options to eligible participants. he following disclosures
relate to the Company's subsidiaries employees' share of benefits under
the SOP. There were no options granted during 1999 and 2002. Options
granted during 2001 and 2000 of 469,899 and 12,756, respectively, had
weighted average fair value of approximately $13.52 and $22.50,
respectively, using the Black-Scholes valuation method. Significant
assumptions used in the Black-Scholes valuation method for shares granted
in 2001 and 2000 were: expected stock price volatility of 86% and 48%
respectively; expected dividend yield of 0% and 0%, respectively;
risk-free interest rate of 4.8% and 5.1%, respectively; and an expected
life of 8 years and 7 years, respectively.

Generally, outstanding stock options become exercisable on a cumulative
basis commencing two years from the date of grant and expire ten years
after the date of grant. Additionally, some options become exercisable in
as little as one year (100% in one year) or as many as four years (25%
each year). As permitted under SFAS No. 123,"Accounting for Stock-Based
Compensation", AES applies APB Opinion No.25 in accounting for the SOP. As
the exercise prices of all stock options are equal to their fair market
values at the time the options are granted, the Company did not recognize
any compensation expense related to the SOP using the intrinsic value
based method. Had compensation expense been recognized using the fair
value based method under SFAS No. 123, the Company's consolidated earnings
would have decreased by $6,117,979 and $273,368 in 2001 and 2000,
respectively. (See new accounting pronouncements in reference to the effect
of SFAS No. 148.))

10. FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of the Company's current financial assets and liabilities
approximate

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their carrying values. The fair value estimates are based on pertinent
information available as of December 31, 2002. The Company is not aware of
any factors that would significantly affect the estimated fair value
amounts since that date.

11. SEGMENT INFORMATION

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

12. SUBSEQUENT EVENTS

Cash flow from AEE's operations during the second half of 2002 was
sufficient to cover the aggregate rental payments under the leases on the
Somerset and Cayuga Plants due January 2, 2003. On this date, rental
payments were made in the amount of $28.7 million.

Cash flow from operations in excess of the aggregate rental payments under
AEE's leases may be distributed to its partners if certain criteria are
met. On January 8, 2003, AEE made a distribution payment of $38.7 million.

AEE borrowed $9.7 million on January 10, 2003, for working capital
purposes under the $35 million secured revolving working capital and
letter of credit facility with Union Bank of California, N.A. The
borrowing was at an interest rate of 5.75%. The $9.7 million was repaid in
full on January 28, 2003.

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