AES CORPORATION - 10-K Annual Report

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000

Delaware (State or other jurisdiction of incorporation or organization)		54-1163725 (I.R.S. Employer Identification No.)
1001 North 19^th Street, Arlington, Virginia (Address of principal executive offices)		22209 (Zip Code)

Title of Each Class
Common Stock, par value $0.01 per share

Name of Each Exchange on Which Registered
New York Stock Exchange

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. / /

The aggregate market value of Registrant's voting stock held by non-affiliates of Registrant, at March 2, 2001, was $21,998,399,015. The number of shares outstanding of Registrant's Common Stock, par value $0.01 per share, at March 2, 2001, was 490,226,393.

The Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 19, 2001 is hereby incorporated by reference. Certain information therein is incorporated by reference into Part III hereof.

The AES Corporation (including its subsidiaries and affiliates, and collectively referred to herein as "AES" or the "Company" or "we") is a global power company committed to serving the world's needs for electricity and other services in a socially responsible way. AES participates primarily in two related lines of business: electricity generation and distribution. The Company's electricity generation business is characterized by sales from its power plants to nonaffiliated wholesale customers (generally electric utilities, regional electric companies, electricity marketers and traders or wholesale commodity markets known as "power pools") for further resale to end users. AES's distribution business is characterized by sales of electricity directly to end users such as commercial, industrial, governmental and residential customers.

In its generation business, AES now operates and owns (entirely or in part) a diverse portfolio of electric power plants (including those within the integrated distribution companies discussed below) with a total capacity (as of December 31, 2000) of 42,133 megawatts (MW) (the Company's Ekibastuz plant currently operates at approximately 35% of its 4,000 MW nameplate capacity). Of that total, 38% are fueled by coal or petroleum coke, 18% are fueled by natural gas, 33% are hydroelectric facilities, 4% are fueled by oil, and the remaining 7% are capable of using multiple fossil fuels. These MWs are distributed 7,740 in North America, 15,231 in South America, 7,449 in Europe and 11,713 in Asia.

AES has majority ownership in three distribution companies in Argentina and individual distribution companies in the United States, Brazil, El Salvador, Venezuela, Dominican Republic, and The Republic of Georgia. The Company also has assumed management control of a heat and electricity distribution business in Kazakhstan. In addition the Company has less than majority ownership in three additional distribution companies in Brazil and one in India. These distribution companies serve a total of over 18 million customers with annual sales exceeding 126,000 gigawatt hours. On a net equity basis, AES's ownership in distribution businesses represents approximately 6.2 million customers and annual sales exceeding over 48,000 gigawatt hours. The Company also has three subsidiaries in the United States that serve retail customers in those states that have introduced a competitive market for the sale of electricity to end-users. The Company is using its distribution infrastructure and knowledge of certain markets to develop the ability to provide wholesale and/or retail telecommunications services. For instance, a subsidiary is currently constructing a national broadband telecommunications network attached to the existing national transmission grid in Brazil.

AES is also currently in the process of adding approximately 7,591 MW to its operating portfolio through its construction of new plants (known as "greenfield" development). These include a 454 MW natural gas-fired plant, a 705 MW natural gas-fired plant, a 720 MW natural-gas-fired plant, an 832 MW natural gas-fired plant and a 47 MW coal-fired plant in the United States, a 2,100 MW coal-fired plant in China, an 845 MW natural gas-fired plant and a 123 MW hydroelectric facility in Argentina, a 360 MW coal-fired plant in England, two natural gas-fired plants totaling 810 MW in Bangladesh, a 310 MW natural gas-fired plant and liquefied natural gas plant in the Dominican Republic, a 165 MW natural gas-fired plant in Sri Lanka and a 120 MW hydroelectric facility in Panama.

AES's total MW of the 141 power plants in operation or under construction is approximately 49,724 MW and net equity ownership (total MW adjusted for the Company's ownership percentage) represents approximately 31,751 MW.

AES continually considers business development opportunities, including significant acquisition opportunities throughout the world. The Company has been actively involved in the acquisition and operation of electricity assets in countries that are restructuring and deregulating the electricity industry. Some of these acquisitions have been made from other electricity companies that are exiting

the electricity generation business. In these situations, sellers generally seek to complete competitive solicitations in less than one year, which is much faster than the time incurred to complete greenfield developments, and require payment in full on transfer. The Company also actively considers acquisition opportunities in non-competitive bidding situations, including unsolicited acquisition proposals. In the event that the Company makes an unsolicited offer to acquire another company, management of the target company may oppose the offer and not provide the Company with access to financial and operational information that could be obtained if management supported the offer. AES believes that its experience in competitive markets and its worldwide-integrated group structure (with its significant geographic coverage and presence) enable it to react quickly and creatively in such situations.

In May 2000, a subsidiary of the Company won a bid to purchase a controlling interest in the 1,580 MW Mohave Generating Station ("Mohave") in Laughlin, Nevada from Southern California Edison Company ("Edison"), Los Angeles Department of Water and Power ("LADWP") and Nevada Power Company for $667 million. Mohave provides power to markets in Phoenix, Arizona, Las Vegas, Nevada and Southern California. The approval to permit AES to purchase the 56% interest currently held by Edison was denied by the California Public Utility Commission. In addition, another party has exercised its right of first refusal to acquire the 20% interest held by LADWP. AES continues to pursue the purchase but there can be no assurance that the Company will be successful in acquiring the ownership interest on the terms determined in the original competitive bid.

In February 2001, a subsidiary of the Company entered into an agreement to acquire Thermo Ecotek Corporation ("Thermo Ecotek"), a wholly owned subsidiary of Thermo Electron Corporation. The purchase price for the transaction is approximately $195 million in cash, plus additional closing adjustments to reimburse the seller for project development expenses incurred between September 30, 2000, and the closing date of the transaction. Thermo Ecotek is a developer and operator of gas-fired, biomass-fired (agricultural and wood waste) and coal-fired power plants. The portfolio of assets to be acquired by AES includes 516 gross MW of operating power assets in the United States, the Czech Republic, and Germany, a natural gas storage project in the United States, and over 1,250 MW of advanced development power projects in the United States. The transaction is subject to a number of closing conditions, including anti-trust and other state and federal regulatory approvals, as well as customary conditions. The closings will be structured in two phases, both of which are expected to close by the end of 2001.

The Company, a corporation organized under the laws of Delaware, was formed in 1981. AES has its principal offices located at 1001 North 19th Street, Suite 2000, Arlington, Virginia 22209. Its telephone number is (703) 522-1315, and its web address is http:www.aesc.com.

The Company wishes to caution readers that the following important factors, among others, indicate areas affecting the Company, which involve risk and uncertainty. These factors should be considered when reviewing the Company's business, and are relied upon by AES in issuing any forward-looking statements. Such factors could affect AES's actual results and cause such results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, AES. Some or all of these factors may apply to the Company's businesses as currently maintained or to be maintained.

The Company operates in two business segments: generation and distribution. See Note 15 to the Consolidated Financial Statements included in Item 8 herein for financial information about those segments.

The Company attempts to participate in competitive power markets through either greenfield development or by acquiring and operating existing facilities. The Company operates electric generating facilities that utilize natural gas, coal, oil, hydropower, or combinations thereof. In addition, the Company participates in the distribution business, which includes retail energy supply and the development of the ability to provide wholesale and retail telecommunication services in certain markets. Elements of the Company's strategy include:

The Company also strives for operating excellence as a key element of its strategy, which it believes it accomplishes by minimizing organizational layers and maximizing company-wide participation in decision-making. AES has attempted to create an operating environment that results in safe, clean and reliable electricity generation and distribution. Because of this emphasis, the Company prefers to operate all facilities which it develops or acquires; however, there can be no assurance that the Company will have operating control of all of its facilities.

The Company's primary focus is the wholesale generation and retail distribution of electricity. References to power sales agreements, fuel supply agreements and plants generally mean those related to the generation business. Concession (or service) contracts, supply contracts and networks are generally associated with the distribution businesses.

Traditionally, most of AES's generation plants have sold electricity under long-term power sales agreements to electric utilities or state-owned power companies. Generated electricity is sold under a two part pricing method, representing the two main products, capacity and energy, produced by electric generating facilities. Energy refers to the sale of the actual electricity produced by the plant and capacity refers to the amount of generation reserved for a particular customer, irrespective of the amount of energy actually purchased. A significant portion of the Company's generating businesses are structured so that each power plant generally relies on one power sales contract or hedging arrangement with a single electric customer for the majority, if not all, of its revenues. Several of AES's generation plants do not make all or a significant portion of their electricity sales pursuant to long-term contracts but rather pursuant to short-term contracts or into spot electricity markets. The prices paid for electricity in the spot markets can be, and from time to time have been, unpredictable and volatile.

To the extent possible, the Company attempts to structure a generation plant's fuel supply contract so that fuel costs are indexed in a manner similar to the energy payments a project receives under the power sales contract. In this way, project revenues are partially hedged against fluctuations in fuel costs.

AES has also hedged a substantial portion of its projects against the risk of fluctuations in interest rates. In each project with fixed capacity payments, AES has attempted to hedge all or a significant portion of its risk of interest rate fluctuations by arranging for fixed-rate financing or variable-rate financing with interest rate swaps or other hedging mechanisms.

The Company attempts to finance each domestic and foreign project primarily under loan agreements and related documents which, except as noted below, require the loans to be repaid solely from the project's revenues and provide that the repayment of the loans (and interest thereon) is secured solely by the capital stock, physical assets, contracts and cash flow of that project subsidiary or affiliate. This type of financing is usually referred to as non-recourse debt or "project financing." The lenders under these project financing structures generally do not have recourse to AES or its other projects for repayment, unless such entity explicitly agrees to undertake liability. AES has explicitly agreed to undertake certain limited obligations and contingent liabilities, most of which by their terms will only be effective or will be terminated upon the occurrence of future events. These obligations and liabilities take the form of guarantees, indemnities, letter of credit reimbursement agreements, and agreements to pay, in certain circumstances, to project lenders or other parties. To the extent AES becomes liable under guarantees and letter of credit reimbursement agreements, distributions received by AES from other projects are subject to the possibility of being utilized by AES to satisfy these obligations. To the extent of these obligations, the lenders to a project effectively have recourse to AES and to the distributions to AES from other projects. The aggregate contractual liability of AES is, in each case, usually a small portion of the aggregate project debt, and thus the project financing structures are generally described herein as being "substantially non-recourse" to AES and its other projects.

A core part of AES's corporate culture is a commitment to "shared principles." These principles describe how AES people endeavor to commit themselves to the Company's mission of serving the world by providing safe, clean, reliable and low-cost electricity while adhering to AES's principles. The principles are:

Integrity—AES strives to act with integrity, or "wholeness." AES people seek to keep the same moral code at work as at home.

Fairness—AES wants to treat fairly its people, its customers, its suppliers, its stockholders, governments and the communities in which it operates.

Fun—AES desires that people employed by the Company and those people with whom the Company interacts have fun in their work. The Company believes that making decisions and being

accountable is fun, and has structured its organization to maximize the opportunity for fun for as many people as possible.

Social Responsibility—Primarily, the Company believes that doing a good job at fulfilling its mission is socially responsible. But the Company also believes that it has a responsibility to be involved in projects that provide other social benefits, and consequently has instituted programs such as corporate matching of individual charitable gifts.

AES recognizes that most companies have standards and ethics by which they operate and that business decisions are based, at least in part, on such principles. The Company believes that an explicit commitment to a particular set of standards is a useful way to encourage ownership of those values among its people. While the people at AES acknowledge that they won't always live up to these standards, they believe that being held accountable to these shared values will help them behave more consistently with such principles.

AES makes an effort to support these principles in ways that acknowledge a strong corporate commitment and encourage people to act accordingly. For example, AES conducts annual surveys, both company-wide and at each business location, designed to measure how well its people are doing in supporting these principles-through interactions within the Company and with people outside the Company. These surveys are perhaps most useful in revealing failures, and helping to deal with those failures. AES's principles are relevant because they help explain how AES people approach the Company's business. The Company seeks to adhere to these principles, not as a means to achieve economic success but because adherence is a worthwhile goal in and of itself.

In order to create a fun working environment for its people and implement its strategy of operational excellence, AES has adopted decentralized organizational principles and practices. For example, AES works to minimize the number of supervisory layers in its organization. Most of the Company's plants operate without shift supervisors. The project subsidiaries are responsible for all major facility-specific business functions, including financing and capital expenditures. Criteria for hiring new AES people include a person's willingness to accept responsibility and AES's principles as well as a person's experience and expertise. The Company has generally organized itself into multi-skilled teams to develop projects, rather than forming "staff" groups (such as a human resources department or an engineering staff) to carry out specialized functions.

The following tables set forth information regarding the Company's businesses that are in operation or under construction at December 31, 2000. For a description of risk factors and additional factors that may apply to the Company's businesses, see also the information contained under the caption "Cautionary Statements and Risk Factors" in Item 1 above, and Item 7, "Discussion and Analysis of Financial Condition and Results of Operations" herein

Generation Facilities in Operation	Fuel	Year of Acquisition or Commencement of Commercial Operations*	Approximate Capacity in Megawatts (MWS)	Geographic Location	AES Equity Interest (Percent)
North America
Deepwater	Pet coke	1986	143	Texas, U.S.	100
Beaver Valley	Coal	1987	125	Pennsylvania, U.S.	100
Placerita	Gas	1989	120	California, U.S.	100
Thames	Coal	1990	181	Connecticut, U.S.	100
Shady Point	Coal	1991	320	Oklahoma, U.S.	100
Hawaii	Coal	1992	180	Hawaii, U.S.	100
Kingston	Gas	1997	110	Canada	50
Alamitos	Gas	1998	2,083	California, U.S.	100
Redondo Beach	Gas	1998	1,310	California, U.S.	100
Huntington Beach	Gas	1998	563	California, U.S.	100
Cayuga	Coal	1999	306	New York, U.S.	100
Greenidge	Coal	1999	161	New York, U.S.	100
Somerset	Coal	1999	675	New York, U.S.	100
Westover	Coal	1999	126	New York, U.S.	100
Warrior Run	Coal	1999	180	Maryland, U.S.	100
Duck Creek	Coal	1999	366	Illinois, U.S.	100
Edwards	Coal	1999	772	Illinois, U.S.	100
Indian Trails Co-Gen	Gas	1999	19	Illinois, U.S.	100
Central and South America
San Nicolas	Multiple	1993	650	Argentina	69
Rio Juramento (2 plants)	Hydro	1995	112	Argentina	98
San Juan (2 plants)	Hydro/Gas	1996	78	Argentina	98
Light (4 plants)	Hydro	1996	788	Brazil	18
CEMIG (37 plants)	Hydro	1997	5,668	Brazil	22
Los Mina	Oil	1997	210	Dominican Republic	100
Quebrada de Ullum	Hydro	1998	45	Argentina	100
EGE Bayano (2 plants)	Hydro	1999	192	Panama	49
EGE Chiriqui	Hydro	1999	85	Panama	49
AES Tiete (10 plants)	Hydro	1999	2,650	Brazil	44
AES Ururguaina	Gas	2000	600	Brazil	100
EDC	Thermal/Hydro	2000	2,265	Venezuela	87
Alicura	Hydro	2000	1,000	Argentina	98
Mamonal	Gas	2000	90	Columbia	62
TermoCandelaria	Gas	2000	314	Columbia	100
Merida III	Gas/Oil	2000	484	Mexico	55

Distribution Facilities	Year of Acquisition	Approximate Number of Customers Served	Approximate Gigawatt Hours	Geographic Location	AES Equity Interest (Percent)
Light	1996	2,800,000	19,981	Rio de Janeiro, Brazil	21
EDEN	1997	277,533	2,570	Buenos Aires, Argentina	60
EDES	1997	138,528	898	Buenos Aires, Argentina	60
CEMIG	1997	4,680,000	32,179	Minas Gerais, Brazil	22
Tau Power/Altai	1997	150,000	2,000	Kazakhstan	70
Sul	1997	900,160	5,772	Rio Grande do Sul, Brazil	96
CLESA	1998	206,000	530	Santa Ana, El Salvador	64
Eletropaulo	1998	4,319,000	34,789	Sao Paulo, Brazil	50
EDELAP	1998	286,768	1,939	Buenos Aires, Argentina	60
Telasi	1998	370,000	2,200	Tbilisi, Georgia	75
CILCO	1999	193,000	6,000	Illinois, U.S.	100
EDE ESTE	1999	400,000	2,990	Dom. Republic	50
East Kazakhstan and Semipalatinsk	1999	469,513	2,572	Kazakstan	NA
CESCO	1999	600,000	2,102	India	48
EDC	2000	1,159,261	9,799	Caracas, Venezuela	87
CAESS, EEO & DEUSEM	2000	604,978	2,055	San Salvador, El Salvador	33

Totals		17,554,741	128,376

Over the past decade, regulations and laws affecting U.S. and world electricity generation and distribution businesses have moved toward more competition and less government control. The timing of this transition and the nature of the new regulatory rules varies greatly among states and countries.

In the U.S., the movement toward competitive markets has been slowed by the recent events in California. In the last 5 years, several states (including California) passed legislation that allows electricity customers to choose their electricity supplier in a restructured electricity market (so-called "retail access" or "customer choice" laws). While these "customer choice" plans differ in detail, they share some important elements: (1) they allow certain customers to choose their electricity supplies by a certain date (the dates in existing or proposed legislation vary between 1998 and 2007); and (2) they allow utilities to recover so-called "stranded costs"—the remaining costs of uneconomic generating or regulatory assets (including Qualifying Facility ("QF") contracts). However, in some markets—particularly California's —"deregulation" has resulted in only partial deregulation. Retail prices in California (and some other states) were required to be capped at a level designed to be higher than wholesale price levels. But because of a supply shortage, wholesale prices in California have substantially exceeded the capped retail prices—causing a structural imbalance between the wholesale and retail markets. While it is uncertain whether this imbalance will be repeated in other states, this structural flaw (partial deregulation) is capable of creating supply shortages and high power prices in other States. To the extent that other jurisdictions adopt similar partial deregulation, the problems currently experienced in California may be repeated elsewhere.

The events in California have generally caused lawmakers and politicians to slow the transition to deregulation —or even in some cases to propose a return to a regulated electric market. For example, New Mexico recently postponed the date for "customer choice" in that state from 2003 to 2007 (while encouraging the development of new supply in the interim). Nevada has also announced that it will indefinitely postpone its plans for deregulation.

AES owns approximately 4,000 MW of gas-fired generation in the Los Angeles area (AES Southland), but has sold the electricity output of those plants to a third party in exchange for substantially fixed long-term payments under a tolling agreement. Most AES generation businesses—AES Hawaii, Shady Point, Thames, Warrior Run, and Beaver Valley, for example—have long term

revenue contracts that substantially reduce their exposure to wholesale price fluctuations. Some U.S. plants—specifically Placerita, the New York plants (Westover, Greenidge, Somerset and Cayuga) and Deepwater—do not have long-term revenue contracts and therefore are more exposed to volatility in wholesale electric prices.

In addition to State restructuring legislation, there continues to be a number of Federal bills under consideration. Electricity markets in the United States are still heavily regulated. United States laws and regulations still govern to some extent wholesale electricity transactions, the type of fuel utilized, the type of energy produced, and power plant ownership. State regulatory commissions have jurisdiction over retail electricity transactions. United States power projects also are subject to laws and regulations controlling emissions and other substances produced by a plant and governing the siting of plants. These laws and regulations generally require that a wide variety of permits and other approvals be obtained before the construction or operation of a power plant commences, and that the facility operate in compliance with these permits thereafter.

AES must obtain exemptions from, or become subject to regulation by, the Securities and Exchange Commission under the Public Utility Holding Company Act ("PUHCA") in regard to both its domestic and foreign utility company holdings. There are a number of exemptions from PUHCA that are available for both domestic and foreign utility company owners, including those for QFs, Exempt Wholesale Generators and Foreign Utility Companies. In August 1999, in connection with its acquisition of CILCORP, AES obtained an order from the U.S. Securities and Exchange Commission (the "SEC") approving the Company's application to be classified as an exempt holding company under Section 3(a)(5) of PUHCA.

In August 2000, AES announced it had reached a definitive merger agreement with IPALCO Enterprises, Inc. ("IPALCO") for approximately $2.15 billion, plus the assumption of $890 million of debt and preferred stock. IPALCO is a utility holding company whose primary subsidiary, Indianapolis Power & Light, is an integrated utility. Under current SEC guidelines and interpretations of PUHCA, AES is not permitted to control both the transmission and distribution assets of both CILCORP and IPALCO, even with the current exemption under Section 3(a)(5) of PUHCA. The business combination has now been completed, and as a condition of the SEC Order granting the PUHCA exemption, the Company is required to divest the utility assets of CILCORP within two years.

The electricity industry in Brazil is regulated by the Brazilian federal government, acting through the Ministry of Mines and Energy, which has exclusive authority over the electricity sector through regulatory powers assigned to it. This sector is currently in a state of rapid change in Brazil. For example, pursuant to a federal law enacted in 1996, regulatory policy for the sector, which was implemented by the Departmento Nacional de Aguas e Energia Eletrica ("DNAEE"), is now implemented by a new autonomous national electric energy agency (Agencia Nacional de Energia Eletrica or "ANEEL"). ANEEL is an independent regulatory agency and delegates certain functions to agencies based in certain states of Brazil. However, ANEEL cannot delegate any authority regarding tariffs to state agencies.

ANEEL is responsible for (i) granting and supervising concessions for electricity generation, transmission and distribution, including approval of applications for the setting of electricity tariffs; (ii) supervising and performing financial examinations of the concessionary companies; (iii) issuing regulations for the electricity sector; and (iv) planning, coordinating and executing water resource studies and granting and supervising concessions for the use of water resources. Due to electricity tariffs' significant weight in the measurement of national inflation, tariff increases have been controlled by the Ministry of Finance, although it is not its official responsibility.

ANEEL also has the following responsibilities: (i) to implement and regulate the exploitation of electric energy and the use of hydroelectric power pursuant to the Power Sector Law; (ii) to promote the bidding process for the granting of new concessions; (iii) to solve administrative disputes among utilities, IPP companies, self-producers and customers; and (iv) to determine the criteria for the establishment of the cost of the transmission of energy pursuant to the Power Sector Law.

The electricity industry in the UK is subject to regulation under, among other things, the Electricity Act of 1989 (as amended principally by the Competition and Service (Utilities) Act 1992 and the Utilities Act 2000). Under the Electricity Act, a license is generally required to generate, transmit or supply electricity. Under the present electricity regime, electricity is traded between generators and suppliers through a day-ahead market in England and Wales (the "Pool"), which is administered by The National Grid Company plc. The Pool is used to determine which generating assets are called to satisfy demand at any particular time and what price is received by them. The price is set by the marginal price for sales of electricity. The electricity generated at the power stations is delivered through the high voltage transmission system owned and operated by The National Grid. It is then transformed for delivery on to the local distribution networks owned and operated by holders of public electricity supply licenses.

The current pool system is scheduled to be replaced on March 27, 2001 by the New Energy Trading Arrangements ("NETA"). NETA will establish bilateral trading between generators, suppliers and other traders. Under NETA, the present pooling and settlement agreement governing the operation of the electricity pool will be replaced. The new arrangements provide mechanisms for near real-time clearing and settlement of differences between contractual and physical positions of those buying, selling, producing and consuming electricity. A balancing mechanism will enable the system operator, National Grid, to change levels of generation and demand to near real-time; and a mechanism for imbalance settlement will provide for the settling of the differences between net physical and net contractual positions of parties. Since NETA has not been implemented, there can be no assurance either that the new arrangements will achieve their objectives or that there will not be material disruptions in the electricity trading system as a result of the implementation of the new arrangements.

AES Drax entered into a 15 year hedging agreement with a subsidiary of Texas Utilities, Inc. ("TXU") at the closing of the acquisition of the Drax power station to protect a significant portion of AES Drax's revenues from price fluctuations in the electricity market. The hedging contract originally was a financial instrument settled against the pool purchase price ("PPP"). As discussed above, NETA is scheduled to replace the pool system on March 27, 2001 with a physically settled market based on bilateral contracts. Consequently, a single clearing price such as the PPP may no longer exist. In February 2000, AES Drax and TXU agreed to changes to the hedging contract, effective upon the implementation of NETA, which are intended to preserve the original commercial intent of the parties. The principal change to the hedging contract was to convert it from a financially settled instrument to physical settlement.

Under the terms of AES Drax's 1.3 billion sterling bank facility, the amendment to the hedging agreement required the prior consent of a majority of the lenders thereunder. In addition, under the terms of the bank facility AES Drax had undertaken to have a trading strategy to be implemented under NETA approved by the majority senior lenders at least five weeks prior to implementation of NETA. AES Drax has obtained a temporary waiver of these requirements through April 6, 2001. AES Drax is currently seeking permanent approval from the senior lenders of the revised terms of the hedging agreement, a proposed trading strategy for the Drax power station under NETA and certain other related matters. There can be no assurance that such approvals will be obtained. In addition, under the terms of AES Drax's outstanding senior secured bonds (200 million pound sterling 9.07%

Senior Secured Bonds due 2025 and $302.4 million 10.41% Senior Secured Bonds due 2020) the amendment to the hedging agreement constitutes an event of default thereunder unless each of ratings agencies reaffirms their ratings of such bonds within 30 days of the effective date of the hedging amendment. AES Drax is currently seeking such rating affirmations. There can be no assurance that such rating affirmations will be obtained.

The construction and operation of power projects are subject to extensive environmental and land use laws and regulations. In the United States those laws and regulations applicable to AES primarily involve the discharge of effluents into the water, emissions into the air and the use of water, but can also include wetlands preservation, endangered species, waste disposal and noise regulation. These laws and regulations often require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies. If AES violates or fails to comply with such laws, regulations, licenses, permits or approvals, AES could be fined or otherwise sanctioned by regulators. In addition, under certain environmental laws, AES could be responsible for costs relating to contamination at its facilities or at third party waste disposal sites. AES is committed to operating its businesses cleanly, safely and reliably and strives to comply with all environmental laws, regulations, permits and licenses. Despite such efforts, the Company has at times been in non-compliance with such laws, regulations, licenses, permits and approvals, although no such instance has resulted in revocation of any permit or license. AES has incurred and will continue to incur significant capital and other expenditures to comply with environmental laws. Although AES is not aware of any costs of complying with environmental laws and regulations which would result in a material adverse effect on its consolidated financial position or results of operations, there can be no assurance that AES will not be required to incur additional material compliance costs in the future.

Environmental laws and regulations are complex, change frequently and have tended to become more stringent over time. If such laws and regulations are changed and any of AES's facilities are not "grandfathered" (that is, made exempt by the fact that the facility pre-existed the law) or are not otherwise excluded, extensive modifications to a facility's technologies and operations could be required. Should environmental laws or regulations change in the future, there can be no assurance that AES would be able to recover all or any increased costs from its customers or that its consolidated financial position or results of operations would not be materially and adversely affected. In addition, the Company may be required to make significant capital or other expenditures in connection with such changes in environmental laws or regulations, although AES's businesses generally take into account capital expenditures for future environmental compliance. The Company is not aware of any currently planned changes in law, however, that would have a material adverse effect on its consolidated financial position or results of operations.

Clean Air Act. The Clean Air Act of 1970 (the "Clean Air Act of 1970"), as amended in 1990 (the "1990 Amendments"), sets guidelines for emissions standards for major pollutants (in particular, sulfur dioxides ("SO₂") and nitrogen oxides ("NOx") from newly-built sources. Among other things, the 1990 Amendments attempt to reduce acid rain precursor emissions (SO2 and NOx) from existing sources, particularly large, older power plants that were exempted from certain regulations under the Clean Air Act of 1970. Other provisions of the Clean Air Act relate to the reduction of ozone precursor emissions (volatile organic compounds ("VOC") and NOx) and have resulted in the imposition by various states of "reasonably available control technology" to reduce such emissions.

As a result of the shortage of electricity in California this year, the generating facilities of one of the Company's subsidiaries (AES Southland), which has approximately 4,000 megawatts of electric generation capacity, operated at substantially higher than expected capacity factors for most of 2000. These higher than expected capacity factors resulted in AES Southland's generating facility at Alamitos

exceeding its annual inventory of NOx air emission allocations. See Item 3—Litigation for a description of certain litigation.

Global warming continues to be a concern. While it now seems unlikely that the Kyoto Protocol to the United Nations Framework Convention on climate change (which would force U.S. and other signatory countries to make substantial reductions in "greenhouse gas" emissions) will be ratified by each signatory country any time soon, global warming remains a policy issue that is regularly considered for possible government regulation. Although AES believes that any government legislation affecting greenhouse gases (other than voluntary reductions) is unlikely, such legislation could substantially affect both the costs and the operating characteristics of AES's fossil-fuel (coal, oil, gas) businesses.

In 1997, the U.S. Environmental Protection Agency ("EPA") published new standards that tighten ambient air quality standards for ozone and fine particulate matter (PM 2.5). In May 1999, the EPA issued its final guidelines for the revised ground-level ozone and particulate matter, which further delineate the so-called "non attainment regions" and other non-attainment classifications. In October 1999, a federal appeals court overturned the new standards. In February 2001, the U.S. Supreme Court upheld the new standards, but held that the EPA's policy of implementing these standards in non-attainment regions was unlawful. If the EPA develops a reasonable interpretation of these standards as they may be applied in non-attainment regions, consistent with the Supreme Court's decision, AES's plants may be faced with further emission reduction requirements that could necessitate both the installation of additional control technology and a related increase in capital expenditures.

In October 1998, the EPA issued a final rule addressing the regional transport of ground-level ozone across state boundaries to the eastern United States through NOx (a precursor to ozone formation) emissions reduction from various emission sources, including utility sources. The rule focuses on such reductions in the eastern United States, and as amended on August 2000 by a federal appeals court decision, requires twenty-two states and the District of Columbia to submit revised "state implementation plans" "SIPs" by October 2000 and have NOx emission controls in place by May 2004 (the "NOx SIP call"). In March 2000, a federal appeals court upheld the NOx SIP call rule. In a related action, the EPA in December 1999 granted petitions filed by four northeastern states seeking to reduce ozone damage across state boundaries through reductions in NOx emissions from 30 states and the District of Columbia. In granting the petitions, the EPA made a finding that certain large electric utilities, including the AES Beaver Valley plant in Pennsylvania, significantly contribute to air pollution in other states. A number of electric utilities are expected to challenge the EPA's action. If further reductions in NOx emissions are required, AES would be required to make such reductions at some of its facilities.

The 1990 Amendments also regulate certain hazardous air pollutants. Although the hazardous air pollutant provisions of the 1990 Amendments presently exclude electric steam generating facilities such as AES's domestic plants, the 1990 Amendments direct the EPA to prepare a study on hazardous air pollutant ("HAP") emissions from power plants. A separate EPA study on mercury emissions from power plants, the Final Mercury Study Report to Congress, released in December 1997, describes the need for further research in the area of utility mercury emission controls, as current control technology is still in an early stage of development. In February 1998, the EPA released a final report on HAP emissions from power plants that, among other things, concluded that the risk of contracting cancer from exposure to HAPs (other than mercury) from most plants is low (less than one in one million) and that further research on mercury emissions was necessary. In March 1999, the EPA issued a report, which examined hypothetical pollution control options to reduce mercury emissions from power plants. In December 2000, the EPA decided that mercury emissions from coal- and oil fired power plants should be regulated. The EPA expects to propose these regulations by December 2003 and issue final regulations by December 2004. Once these final regulations have been issued, the use of "maximum available control technology" may be required. 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 the facilities over the years. The EPA's focus is on whether the changes were subject to new source review or new performance standards, and whether best available control technology was or should have been used. See Item 3—Litigation for a description of certain litigation.

Hazardous Waste Regulation. Based on a 1988 study, the EPA does not regulate most coal combustion ash as a hazardous waste. In a report to Congress in March 1999, the EPA tentatively concluded that coal combustion ash should remain exempt from regulation. In May 2000, the EPA issued a final regulatory determination which concluded that coal ash is exempt from hazardous waste regulation. It was determined, however, that national non-hazardous waste regulations are needed for coal combustion wastes disposed in surface impoundments and landfills. The Company does not expect costs to comply with these regulations, if and when passed, will have a material adverse effect on its consolidated financial position or results of operations. The Company cannot predict the timing or the outcome of such regulatory actions at this time. If the EPA decides, and is able, to regulate coal ash as a hazardous or special waste, AES could incur additional ash management or disposal costs from its plants.

AES has ownership interests in operating power plants in many countries outside the United States. Each of these countries (and the localities therein) have separate laws and regulations governing the siting, permitting, ownership and power sales from AES's plants that are often different from those in effect in the United States. In addition to such foreign laws and regulations, projects funded by the World Bank are subject to World Bank environmental standards, which may be more stringent than local country standards but are typically not as strict as corresponding standards in the United States. Whenever feasible, AES attempts to use advanced environmental technologies (such as CFB coal technology or advanced gas turbines) in its non-U.S. businesses in order to minimize environmental impacts.

Based on current trends, AES expects that environmental and land use regulations affecting its plants located outside the United States will likely become more stringent over time. This may be due in part to a greater participation by local citizenry in the monitoring and enforcement of environmental laws, better enforcement of applicable environmental laws by the regulatory agencies, and the adoption of more sophisticated environmental requirements. If foreign environmental and land use regulations were to change in the future, the Company may be required to make significant capital or other expenditures. There can be no assurance that AES would be able to recover all or any increased costs from its customers or that its business, financial condition or results of operations would not be materially and adversely affected by future changes in foreign environmental and land use regulations.

At December 31, 2000, AES and its subsidiaries employed approximately 26,606 people.

The following is certain information concerning the present executive officers and significant employees of the Registrant set out in alphabetical order.

Michael N. Armstrong, 43 years old, was appointed Vice President of the Company in January 2001 and has served as the Group Manager for AES Electric since 1999. Mr. Armstrong leads the group responsible for AES's businesses and development activities in England, Spain, Italy and other countries in Western Europe. Prior to assuming the group manager's position, Mr. Armstrong

was a project director and business leader in England and Europe. Prior to joining AES in 1990, Mr. Armstrong was a mettalurgist and engineer for BOC plc.

Dennis W. Bakke, 55 years old, co-founded the Registrant with Roger Sant in 1981 and has been a director of the Registrant since 1986. He has been President of the Registrant since 1987 and Chief Executive Officer since January 1994. From 1987 to 1993, he served as Chief Operating Officer of the Registrant; from 1982 to 1986, he served as Executive Vice President of the Registrant; and from 1985 to 1986 he also served as Treasurer of the Registrant. He served with Mr. Sant as Deputy Assistant Administrator of the Federal Energy Agency ("FEA") from 1974 to 1976 and as Deputy Director of the Energy Productivity Center, an energy research organization affiliated with The Mellon Institute at Carnegie-Mellon University, from 1978 to 1981. He is a trustee of Rivendell School and a member of the Board of Directors of MacroSonix Corporation in Richmond, Virginia.

Richard A. Bulger, 43 years old, was appointed Vice President of the Company in January 2001 and has served as the President of C.A. La Electricidad de Caracas, a Venezuelan subsidiary of the Company since June 2000. Prior to his appointment he served as President of AES Sul from October 1998 to June 2000. Mr. Bulger joined AES in December of 1997 and before that he was a director with Price Waterhouse LLP. Mr. Bulger is a certified public accountant.

Mark S. Fitzpatrick, 50 years old, was appointed Executive Vice President in February 2000, was Senior Vice President until February 2000, and was appointed Vice President of the Registrant in 1987. Mr. Fitzpatrick became Managing Director of Applied Energy Services Electric Limited for the United Kingdom and Western Europe operations in 1990. From 1984 to 1987, he served as a project director of the AES Beaver Valley and AES Thames projects.

Paul T. Hanrahan, 43 years old, was appointed Executive Vice President in February 2000, has been a Senior Vice President since 1997, and was appointed Vice President of the Registrant effective January 1994. Since May 1, 1998, Mr. Hanrahan has been Managing Director of AES Americas South, a business group within AES responsible for all of AES's activities in Argentina, Paraguay, Southern Brazil, Peru and Chile. From February 1995 until becoming Managing Director of AES Americas South he was President and Chief Executive Officer of AES Chigen, where he served as Executive Vice President, Chief Operating Officer and Secretary from December 1993 until February 1995. He was General Manager of AES Transpower, Inc., a subsidiary of the Registrant, from 1990 to 1993.

Naveed Ismail, 39 years old, has been the Group Manager for AES Andes since May 2000. Mr. Ismail leads the group responsible for all of AES's business, including project development and plant operations, in Argentina, Chile and Peru. Prior to his appointment as leader of this group, Mr. Ismail was Plant Manager for AES Ekibastuz, a 4,000 MW coal-fired power plant in Kazakstan.

Lenny M. Lee, 42 years old, was appointed Vice President in February 2000 and has served as Managing Director of AES Transpower since June 1998. As Managing Director of AES Transpower, Mr. Lee leads the AES group responsible for all of AES's business, including project development and plant operations, in Australia, New Zealand, portions of Southeast Asia (Thailand, Indonesia, Malaysia and Vietnam) Hawaii and Southern China. Prior to his appointment, Mr. Lee developed various projects within the same group. Mr. Lee has been with the Company since August 1987.

Garry K. Levesley, 40 years old, was appointed Vice President of the company in January 2001 and has served as President of AES Silk Road since May 1999. Mr Levesley leads the AES group responsible for all of AES's business, including project development and plant operations in all the countries of the former Soviet bloc, Central Asia and Israel. Prior to his appointment as leader of this group he worked as a leader in the Medway Power plant in the UK before moving to lead AES businesses in Hungary and the former Altaienergo Utility in Eastern Kazakhstan. Prior to joining AES in 1994, Mr Levesley was the Utilities Manager at a large Chemical complex in Northern England.

William R. Luraschi, 37 years old, has been Vice President of the Registrant since January 1998, Secretary since February 1996 and General Counsel of the Registrant since January 1994. Prior to that, Mr. Luraschi was an attorney with the law firm of Chadbourne & Parke L.L.P.

Ann D. Murtlow, 40 years old, was appointed Vice President of the Company in January 2001 and has served as Managing Director of AES Horizons since May 1999. Ms. Murtlow leads the AES group responsible for all of AES's business, including project development and plant operations, in Ireland, Wales, and most of Northern, Central and Eastern Europe. Prior to her appointment, Ms. Murtlow served as project director for projects elsewhere in the region and in the U.S. Prior to joining AES in 1987, Ms. Murtlow was with Bechtel Power Corporation.

Dr. Roger F. Naill, 53 years old, was appointed Senior Vice President in February 2001 and has been Vice President for Planning at AES since 1981. Prior to joining the Registrant, Dr. Naill was Director of the Office of Analytical Services at the Department of Energy. Dr. Naill received a Ph.D in Engineering form Dartmouth College.

Shahzad S. Qasim, 46 years old, was appointed Vice President of the Company in February 2000 and has served as Managing Director of AES Oasis since April 1998. As Managing Director of AES Oasis, Mr. Qasim leads the AES group responsible for all of AES's business, including project development and plant operations, in Pakistan, India, portions of South Asia and the Middle East. Prior to his appointment, Mr. Qasim had been developing various projects within the same geographical region for the Company. Mr. Qasim has been with the Company since November 1992; before he joined the Company Mr. Qasim was with the international management consulting firm of McKinsey & Company.

Dan Rothaupt, 49 years old, was appointed Vice President of the Company in January 2001 and has served as President of AES Endeavor since May 1999. Mr. Rothaupt leads the AES group responsible for all of AES's business, including project development, power marketing and plant operations, in New York, New England and Eastern Canada. Prior to his appointment, Mr Rothaupt served as Plant Manager of AES Hawaii and AES Thames facilities. Prior to joining AES in 1988, Mr. Rothaupt was employed by Pfizer Inc and the US Coast Guard in a variety of engineering positions.

William Ruccius, 49 years old, was appointed Vice President of the Company in February 2000 and has served as Managing Director of AES Orient since June 1998. As Managing Director of AES Orient, Mr. Ruccius leads the AES group responsible for all of AES's business, including project development and plant operations, in Northern China and most of North and East Asia including the Philippines. From June 1996 until his appointment as Managing Director, he was President and CEO of AES Lal Pir and AES Pak Gen, the Company's duel Pakistani generating facilities. Prior to that Mr. Ruccius was Plant Manager at AES Hawaii from April 1995 to June 1996 and worked at AES Deepwater from June 1993 to April 1995.

John Ruggirello, 50 years old, was appointed Executive Vice President of the Registrant in February 2000, was Senior Vice President until February 2000 and was appointed Vice President in January 1997. Mr. Ruggirello heads an AES group responsible for project development, construction and plant operations in much of the United States and Canada. He served as President of AES Beaver Valley from 1990 to 1996.

J. Stuart Ryan, 42 years old, was appointed Executive Vice President of the Registrant in February 2000, was Senior Vice President until February 2000 and is Managing Director of the AES Pacific group, which is responsible for the Company's business in the western United States. Between 1994 and 1998, Mr. Ryan lead the AES Transpower group responsible for AES's activities in Asia (excluding China). From 1994 through 1997, he served as Vice President of the Registrant. Prior to 1994, Mr. Ryan served as general manager of a group within AES.

Roger W. Sant, 69 years old, co-founded the Company with Dennis Bakke in 1981. He has been Chairman of the Board and a director of the Registrant since its inception, and he held the office of Chief Executive Officer through December 31, 1993. He currently is Chairman of the Boards of Directors of The Summit Foundation and The World Wildlife Fund U.S., and serves on the Boards of Directors of The World Resources Institute, the World Wide Fund for Nature and Marriott International, Inc. He was Assistant Administrator for Energy Conservation and the Environment of the Federal Energy Agency ("FEA") from 1974 to 1976 and the Director of the Energy Productivity Center, an energy research organization affiliated with The Mellon Institute at Carnegie-Mellon University, from 1977 to 1981.

Barry J. Sharp, 41 years old, was appointed Executive Vice President in February 2001. Mr. Sharp was appointed Senior Vice President and Chief Financial Officer effective January 1998 and had been Vice President and Chief Financial Officer since 1987. He also served as Secretary of the Registrant until February 1996. From 1986 to 1987, he served as the Company's Director of Finance and Administration. Mr. Sharp is a certified public accountant.

Sarah Slusser, 38 years old, was appointed Vice President of the Registrant in January 1999, and was appointed President of AES Aurora, Inc., effective April 1997. AES Aurora is a wholly owned subsidiary of the Company and a group of AES which is responsible for business development, construction and operations of facilities and projects in Mexico, Central America, the Caribbean and the Gulf States in the United States. Prior to that, Ms. Slusser served as Project Director for various AES projects in the same region from 1993 to 1997.

Paul D. Stinson, 44 years old, was appointed Vice President of the Registrant effective January 1998. Since April 1997 Mr. Stinson has been Managing Director of AES Silk Road, Ltd., a wholly owned subsidiary of the Company, which is a group of AES responsible for business development, construction and operations of facilities and projects in Russia, Kazakhstan, Pakistan and other parts of Asia. Mr. Stinson served as Managing Director of Medway Power Ltd. from 1994 until 1997 and was Plant Manager of the Medway Power Station owned by Medway Power Ltd. from 1992 to 1997.

David Luis Travesso, 39 years old, was appointed Vice President in February 2000 and has served as Group Manager of AES Sao Paolo since February 2000. Prior to this appointment, Mr. Travesso served as Chairman of Light-Servicos de Electricade S.A.

Thomas A. Tribone, 48 years old, Executive Vice President since January 1998, and had been Senior Vice President of the Registrant from 1990 to January 1998. Mr. Tribone leads AES Americas, a group responsible for power marketing, project development, construction and plant operations in northern portions of South America including much of Brazil. From 1987 to 1990 he served as Vice President for project development and from 1985 to 1987 he served as project director of the AES Shady Point plant.

Kenneth R. Woodcock, 57 years old, has been Senior Vice President of the Registrant since 1987. Mr. Woodcock is responsible for coordinating AES's relationships with the investment community, and he provides support for AES business development activities worldwide. From 1984 to 1987, he served as a Vice President for Business Development. Prior to the founding of AES he served in the United States federal government in energy and environment departments.

(d) Financial Information About Foreign and Domestic Operations and Export Sales.

See the information contained under the caption "Segments" in Note 15 to the Consolidated Financial Statements included in Item 8 herein.

Offices are maintained by the Registrant in many places around the world, which are generally occupied pursuant to the provisions of long and short-term leases, none of which are material to the Company. With a few exceptions, the Registrant's facilities, which are described in Item 1 hereof, are subject to mortgages or other liens or encumbrances as part of the project's related finance facility. The land interest held by the majority of the facilities is that of a lessee or, in the case of the facilities located in the People's Republic of China, a land use right that is leased or owned by the related joint venture that owns the project. However, in a few instances there exists no accompanying project financing for the facility and in a few of these cases the land interest may not be subject to any encumbrance and is owned by the subsidiary or affiliate owning the facility outright.

In September 1999, an appellate judge in the Minas Gerais, Brazil state court system granted a temporary injunction that suspends the effectiveness of a shareholders' agreement for CEMIG. This appellate ruling suspends the shareholders' agreement while the action to determine the validity of the shareholders' agreement is litigated in the lower court. In early November 1999, the same appellate court judge reversed this decision and reinstated the effectiveness of the shareholders' agreement, but did not restore the super majority voting rights that benefited the Company. In March 2000, a state court in Minas Gerais again ruled that the shareholders' agreement was invalid. The Company has appealed this decision. AES must exhaust all state-level appeals before the matter is heard before the Brazilian federal court. The Company intends to vigorously pursue its legal rights in this matter and to restore all of its rights regarding CEMIG, and does not anticipate that this temporary suspension of the shareholders' agreement will have a significant effect on its financial condition or results of operations. Failure to prevail in this matter would limit the Company's influence on the daily operations of CEMIG. However, the Company would still own approximately 21.6% of the voting common stock of CEMIG.

In November 2000, the Company was named in a purported class action suit along with six other defendants alleging unlawful manipulation of the California wholesale electricity market, resulting in inflated wholesale electricity prices throughout California. Alleged causes of action include violation of the Cartwright Act, the California Unfair Trade Practices Act and the California Consumers Legal Remedies Act. In December 2000, the case was removed from the San Diego County Superior Court to the U.S. District Court for the Southern District of California. The Company believes it has meritorious defenses to this action and expects that it will defend itself vigorously against the allegations.

The crisis in the California wholesale power market has directly or indirectly resulted in several administrative and legal actions involving the Company's businesses in California. Each of the Company's businesses in California (AES Southland, AES Placerita and AES New Energy) are subject to overlapping state investigations by the California Attorney General's Office, the Market Oversight and Monitoring Committee of the California Independent System Operator ("ISO"), and the California Public Utility Commission. Each of these investigations are currently in the document gathering stage, and the businesses have responded to multiple requests for the production of documents and data surrounding the operation and bidding behavior of the plants.

In addition, in August 2000, the Federal Energy Regulatory Commission ("FERC") announced an investigation into the national wholesale power markets, with particular emphasis upon the California wholesale electricity market, in order to determine whether there has been anti-competitive activity by wholesale generators and marketers of electricity. The FERC has requested documents from each of the AES Southland plants. The FERC investigation has focused their attention to date upon the forced and planned maintenance outages taken by the plants in 2000. On March 14, 2001, the FERC issued a

Show Cause Order why AES Southland, (including AES Alamitos L.L.C., AES Huntington Beach L.L.C.), and Williams Marketing & Trading, a wholly owned subsidiary of the Williams Companies, Inc., should not be found in violation of the Federal Power Act with respect to, among other things, outages in April and May 2000. The Order also asked for cause why Williams and/or AES Southland should not be directed to return approximately $10.8 million earned by Williams due to alleged overcharges. Lastly, the FERC announced that it was instituting a formal investigation into the operations and maintenance of, and sales of power from, the AES Alamitos and AES Huntington Beach plants in 2000 and 2001.

In May 2000, the New York State Department of Environmental Conservation ("DEC") issued a Notice of Violation ("NOV") to the New York State Electric & Gases Corporation ("NYSEG") violations of the Federal Clean Air Act and the New York Environmental Conservation Law at the Greenidge and Westover plants related to NYSEG's alleged failure to undergo an air permitting review prior to making repairs and improvements during the 1980s and 1990s. Pursuant to the agreement relating to the acquisition of the plants from NYSEG, AES Eastern Energy agreed with NYSEG that AES Eastern Energy will assume responsibility for the NOV, subject to a reservation of AES Eastern Energy's right to assert any applicable exception to its contractual undertaking to assume pre-existing environmental liabilities. The Company believes it has meritorious defenses to any actions asserted against it and expects to vigorously defend itself against the allegations; however, the NOV issued by the DEC, and any additional enforcement actions that might be brought by the New York State Attorney General, the DEC or the EPA, against the Somerset, Cayuga, Greenidge or Westover plants, might result in the imposition of penalties and might require further emission reductions at those plants.

The EPA has commenced an industry-wide investigation of coal-fired electric power generators to determine compliance with environmental requirements under the Federal Clean Air Act associated with repairs, maintenance, modifications and operational changes made to the facilities over the years. The EPA's focus is on whether the changes were subject to new source review or new performance standards, and whether best available control technology was or should have been used. On August 4, 1999, the EPA issued a NOV to the Company's Beaver Valley plant, generally alleging that the facility failed to obtain the necessary permits in connection with certain changes made to the facility in the mid-to-late 1980s. The Company believes it has meritorious defenses to any actions asserted against it and expects to vigorously defend itself against the allegations.

In the fourth quarter of 2000, AES Alamitos LLC, which owns and operates a 2,083 MW natural-gas fired electric generating facility in southern California, reached an agreement with the South Coast Air Quality Management District ("District") that resolved allegations of certain air emission violations at the Alamitos facility an also provided an abatement plan for AES Alamitos that allows plant operations to go forward. Under the terms of settlement, AES Alamitos agreed to, among other things, commence installing selective catalytic reduction devices on four uncontrolled units at AES Alamitos as soon as the pending permits are issued and to dispatch all generating units in

accordance with "environmental dispatch" until such SCR is installed which would require units with superior emission control technology be operated first. AES Alamitos also agreed to comply with all provisions of the District's emission trading program and pay a $17 million fine.

The Company is involved in certain other legal proceedings in the normal course of business. It is the opinion of the Company that none of the pending litigation will have a material adverse effect on its financial position or cash flows.

No matters were submitted to a vote of security holders during the fourth quarter of 2000.

ITEM 5—MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

The common stock of the Company is currently traded on the New York Stock Exchange (NYSE) under the symbol "AES". The following tables set forth the high and low sale prices for the common stock as reported by the NYSE for the periods indicated.

2000	High		Low		1999	High		Low
First Quarter	$44	²³/32	$34	¹/4	First Quarter	$24	⁵/8	$16	¹³/32
Second Quarter	49	⁵/8	35	⁹/16	Second Quarter	29	⁷/8	18	³/8
Third Quarter	70	¹/4	45	¹/8	Third Quarter	33	¹¹/32	26	¹⁷/32
Fourth Quarter	72	¹³/16	45		Fourth Quarter	38	³/16	25	⁷/32

As of March 2, 2001, there were 1,364 record holders of the Company's Common Stock, par value $0.01 per share.

Under the terms of the Company's corporate revolving loan and letters of credit facility of $850 million entered into with a commercial bank syndicate, the Company is currently prohibited from paying cash dividends. In addition, the Company is precluded from paying cash dividends on its Common Stock under the terms of a guaranty to the utility customer in connection with the AES Thames project in the event certain net worth and liquidity tests of the Company are not met. The Company has met these tests at all times since making the guaranty.

The ability of the Company's project subsidiaries to declare and pay cash dividends to the Company is subject to certain limitations in the project loans, governmental provisions and other agreements entered into by such project subsidiaries. Such limitations permit the payment of cash dividends out of current cash flow for quarterly, semiannual or annual periods only at the end of such periods and only after payment of principal and interest on project loans due at the end of such periods, and in certain cases after providing for debt service reserves.

ITEM 7—DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Existing Operations. The AES Corporation (including its subsidiaries and affiliates and collectively referenced as "we" or "AES" or the "Company") is a global power company committed to serving the world's needs for electricity and other services in a socially responsible way. AES participates primarily in two related lines of business: electricity generation and distribution. The Company's electricity generation business is characterized by sales from our power plants to nonaffiliated wholesale customers (generally electric utilities, regional electric companies, electricity marketers and traders or wholesale commodity markets known as "power pools") for further resale to end-users. AES's distribution business is characterized by sales of electricity directly to end users such as commercial, industrial, governmental and residential customers.

AES's generation business represented 53% of total revenues in 2000 compared to 60% for 1999. Generation revenues are derived from sales made under contracts of varying lengths and provisions, as well as directly into power pools or daily spot markets, also referred to as "merchant" power sales. The Company builds and owns new plants constructed for such purposes ("greenfield" plants) and has purchased other existing power plants through competitive bids, negotiated purchases and acquisitions.

In its generation business, AES, at December 31, 2000, operates and owns (entirely or in part) a diverse portfolio of electric power plants (including those within the integrated distribution companies), which are geographically distributed throughout the world with a total capacity of 42,133 megawatts ("MW"). Those MWs are distributed 7,740 in North America, 15,231 in South America, 7,449 in Europe and 11,713 in Asia. Of that total, 38% are fueled by coal or petroleum coke, 18% are fueled by natural gas, 33% are hydroelectric facilities, 4% are fueled by oil, and the remaining 7% are capable of using multiple fossil fuels.

AES's distribution business represented 47% of total revenues for 2000 compared to 40% for 1999. Distribution revenues are generally derived from sales made pursuant to the provisions of long-term electricity sale concessions granted by the appropriate governmental authorities, or in some locations, under existing regulatory laws and provisions. Some of our distribution businesses are "integrated", in that they also own electric power plants for the purpose of generating a portion of the electricity they sell.

AES has majority ownership in distribution companies in Argentina, the United States, Brazil, El Salvador, the Dominican Republic, Venezuela and the Republic of Georgia. The Company also has assumed managerial control of a heat and electricity distribution business in Kazakhstan. In addition, the Company has less than majority ownership in three additional distribution companies in Brazil and one in India. These distribution companies serve a total of over 18 million customers with annual sales exceeding 126,000 gigawatt hours. On a net equity basis, AES's ownership represents approximately 6.2 million customers and annual sales exceeding over 48,000 gigawatt hours. The Company also has three subsidiaries in the United States that serve retail customers in certain states that have introduced a competitive market for the sale of electricity to end users.

Construction, Business Development and Acquisition Activities. AES also is currently in the process of adding approximately 7,591 MW to its operating portfolio through its construction of greenfield plants. These include a 454 MW natural gas-fired plant, a 705 MW natural gas-fired plant, a 720 MW natural gas-fired plant, an 832 MW natural gas-fired plant and a 47 MW coal-fired plant in the United States, a 2,100 MW coal-fired plant in China, an 845 MW natural gas-fired plant and a 123 MW hydroelectric facility in Argentina, a 120 MW hydroelectric facility in Panama, two natural gas-fired plants totaling 810 MW in Bangladesh, a 310 MW natural gas-fired plant in the Dominican Republic, a 165 MW natural gas-fired plant in Sri Lanka and a 360 MW coal-fired plant in England.

As a result, in the 141 power plants in operation or under construction AES's total MW is approximately 49,724 and net equity ownership (total MW adjusted for the Company's ownership percentage) represents approximately 31,751 MW. After considering pending acquisitions and plants in advanced stages of development, AES's total MW is approximately 64,418.

Because of the significant complexities associated with building new electric generating plants, construction periods often range from two to five years, depending on the technology and location. AES currently expects that projects now under construction will reach commercial operation and begin to sell electricity at various dates through the year 2004. The timely completion of each plant is generally supported by a guarantee from the plant's construction contractor, although in certain cases, AES has assumed the risk of successfully completing construction. Changes in economic, political, technological, regulatory or logistical circumstances may substantially delay, or in some cases even prevent, completion and commercial operation. In addition, a Brazilian subsidiary, Eletronet, is in the process of constructing a national broadband telecommunications network attached to the existing national transmission grid in Brazil.

Certain subsidiaries and affiliates of the Company (domestic and non-U.S.) are in various stages of developing and constructing greenfield power plants, some but not all of which have signed long-term contracts or made similar arrangements for the sale of electricity. Successful completion depends upon overcoming substantial risks, including, but not limited to, risks relating to failures of siting, financing,

construction, permitting, governmental approvals or the potential for termination of the power sales contract as a result of a failure to meet certain milestones. As of December 31, 2000, capitalized costs for projects under development and in early stage construction were approximately $114 million. The Company believes that these costs are recoverable; however, no assurance can be given that individual projects will be completed and reach commercial operation.

AES is also pursuing several potential greenfield development projects and acquisitions in many countries. Several of these, if consummated, would require the Company to obtain substantial additional financing, including both debt and equity financing.

The Company has been actively involved in the acquisition and operation of electricity assets in countries that are restructuring and deregulating their electricity industries. Some of these acquisitions have also been made from other electricity companies that have chosen to exit the electricity generation business. In these types of situations, the sellers often seek to initiate and complete competitive solicitations in less than one year and require payment in full upon transfer. Such an accelerated process allows for significantly less time than required to develop, finance and construct greenfield power plants. We believe that our experience in competitive markets and our integrated group structure (with significant geographic coverage and presence) enable us to react quickly and creatively in such situations. The Company strives for operating excellence as a key element of its strategy, which it believes it accomplishes by minimizing organizational layers and maximizing company-wide participation in decision-making. In meeting these goals, the Company also believes that control of its businesses is an important requirement for implementing the Company's philosophy and business strategy, and it will actively seek to acquire control or divest of its interest in those businesses it does not control. To the extent the Company decides to divest its interest in businesses, such transactions may result in a gain or loss. The Company continues to evaluate its strategy as it relates to certain businesses in the United States, South America and Asia.

The financing for such acquisitions, in contrast to that for greenfield development, often must be arranged quickly and therefore may preclude the Company from arranging non-recourse project financing (the Company's historically preferred financing method, which is discussed further under "Capital Resources and Liquidity and Market Risk"). Moreover, acquisitions that are large, that occur simultaneously with one another or those occurring simultaneously with the start of construction on several greenfield developments have in the past, and may in the future, require the Company to obtain substantial additional financing, including both debt and equity. As a result, and in order to enhance its financial capabilities to respond to these more accelerated opportunities, the Company maintains an $850 million revolving line and letter of credit facility (the "Revolver"). AES also maintains a "universal shelf" registration statement with the SEC which allows for the public issuance of various additional debt and preferred or common equity securities, either individually or in combination, and which at December 31, 2000 represents approximately $2.3 billion in unused potential proceeds from the issuance of public securities. There can be no assurance that sufficient financing will be available to the Company on acceptable terms to complete the asset purchases, business acquisitions or other funding requirements that may be pending.

Generation. Although the specific terms of individual contracts may vary significantly, electricity sales contracts or other similar agreements for the sale of electricity (including tolling agreements or financially settled hedging agreements) generally contain pricing provisions that reflect the two principal products produced by electric generating facilities, energy and capacity. Energy refers to the sale of the actual electricity produced by the plant and capacity refers to the amount of generation reserved for potential use by a particular customer, irrespective of the amount of energy actually purchased. A significant portion of the Company's generating businesses are structured so that each power plant generally relies on one power sales contract with a single electric customer for the majority, if not all,

of its revenues. The prolonged failure of any significant customer to fulfill its contractual payment obligations in the future could have a substantial negative impact on AES's results of operations and financial condition. The Company has sought to reduce this risk, where possible, by entering into power sales contracts with customers who have their debt or preferred securities rated "investment grade," or by obtaining sovereign government guarantees of the purchaser's obligations, as well as by locating its plants in different geographic areas in order to mitigate the effects of regional economic downturns.

However, AES does not limit its business solely to the most developed countries or economies, nor even to those countries with investment grade sovereign credit ratings. In certain locations, particularly in developing countries or countries that are in a transition from centrally planned to market-oriented economies, the electricity purchasers, both wholesale and retail, may be unable or unwilling to honor all of their contractual payment obligations. Moreover collection of receivables may be hindered in some countries due to ineffective systems for adjudicating contract disputes.

Because of the market structures or purchasing trends in some wholly or partially deregulated electricity markets, several of AES's generation plants do not sell all or even a majority of their output pursuant to long-term contracts with pre-determined pricing provisions, but rather they sell into short-term contract or spot electricity markets or pursuant to long-term contracts with variable price or quantity provisions. The prices paid for electricity in such markets can be, and from time to time, have been unpredictable and volatile. Electricity price volatility often exists in those regions in the United States and other parts of the world that are introducing competitive energy markets and where periods of temporary or longer-term shortages or excess supplies of electricity occur. This volatility is influenced by peak demand requirements, weather conditions, competition, electricity transmission and environmental emission constraints, the availability or prices of emission credits and fuel prices, as well as plant availability and other relevant factors. The majority of the electricity generated at the New York plants and a significant portion of that generated by the Drax plant and the generation businesses in Argentina are all sold into power pools or under short-term contracts (or in case of the Drax plant, partially subject to the provisions of contractual instruments that have the effect of hedging a portion of the plant's output from price volatility). As a result, the sales revenues (as determined by both volume and price considerations) and resulting profitability from these businesses are significantly less predictable and subject to potentially greater variability from period to period than those businesses selling under long-term sales contracts with pre-determined pricing.

Distribution. In the United States, the Company participates in certain competitive retail electricity supply markets, where state laws permit, by selling electricity to consumers. In these markets, the Company typically enters into multi-year electricity supply contracts with its customers. These contracts may be structured as shared savings arrangements, fixed savings arrangements or fixed price supply contracts. In certain of its fixed savings arrangements and fixed price supply contracts, the cost to supply electricity to the customer may be greater than the price the customer is required to pay the Company. The Company also engages in wholesale purchases and sales of electricity to support its electricity sales to consumers.

AES also owns and operates an integrated distribution company, CILCORP that serves approximately 193,000 electric and 202,000 gas customers in central Illinois under existing state regulatory provisions that provide for the transition to a competitive market. Under these provisions, CILCORP's return on equity is subject to regulation by the Illinois state regulatory authorities. The Company has also acquired IPALCO Enterprises, Inc. ("IPALCO") under the terms of a share exchange for approximately $2.15 billion, plus the assumption of $890 million of debt and preferred stock. IPALCO is an integrated electric utility that owns and operates 3,000 MW of coal-fired generation and provides retail electric service to 433,000 customers in the greater Indianapolis area. The provisions of a regulatory approval require AES to relinquish control or dispose of a portion of its regulated assets or businesses in the United States, in particular certain transmission and distribution assets owned by CILCO, a subsidiary of CILCORP within two years. Any ultimate gain or loss of such

potential disposal cannot be currently estimated. The Company expects that the consummation of the IPALCO transaction may cause the Company to incur substantial non-recurring charges relating to severance and transaction costs.

Outside of the United States, retail electricity sales by AES's distribution businesses are generally made pursuant to provisions of long-term electricity sales concession agreements ranging in remaining length from 16 to 91 years. Each business is generally authorized to charge its customers a tariff for electric services that consists of two components: an energy expense pass-through component and an operating cost component. Both components are established as part of the original grant of the concession for certain initial periods (ranging from three to seven years remaining). Beginning subsequent to the initial periods, and at regular intervals thereafter, the concession grantor has the authority to review the costs of the relevant business to determine the inflation adjustment (or other similar adjustment factor), if any, to the operating cost component (the "Adjustment Escalator") for the subsequent regular interval. This review can result in an Adjustment Escalator that has a positive, zero or negative value. This electricity market structure is often referred to as "price-cap" regulation, because the price of electricity is regulated as opposed to regulation of the investors' rate of return on its equity (referred to as "rate of return" regulation). To date, the Company has not reached the end of the initial tariff periods in any of its distribution businesses. As a result, there can be no assurance as to the effects, if any, on its future results of operations of potential changes to the Adjustment Escalator.

As stated above, the electricity sales concessions provide for an annual adjustment to the tariff, resulting in adjustments based on several factors, including inflation increases as measured by different agreed upon indices. In certain situations, although not including Brazil, there is also an explicit linkage through the pricing provisions of the contract to a portion of the tariff that reflects changes, either entirely or in part, in exchange rates between the local currency and the U.S. Dollar. Such adjustments are made in arrears at various regular intervals, and in certain cases, requests for interim adjustments are permitted. From time to time, governments or regulatory authorities may choose not to grant tariff increases that, in the Company's view, are required according to the contractual terms of the concession agreement. In such event, the Company may contest the action through the various regulatory and judicial agencies within such country.

If a foreign currency experiences a sudden or severe devaluation relative to the U.S. Dollar (the Company's reporting currency), such as occurred to the Brazilian Real in January 1999, because of the lack of direct adjustment to the then-current exchange rate, the in arrears nature of the respective adjustment in the tariff or the potential delays or magnitude of the resulting local currency inflation of the tariff, the future results of operations of AES's distribution companies in that country could be adversely affected. Depending on the duration or severity of such devaluation, the future results of operations of AES may also be adversely affected. During 1999, the Brazilian Real experienced a significant devaluation relative to the U.S. Dollar, declining from 1.21 Brazilian Reais to the Dollar at December 31, 1998 to 1.81 Reais to the Dollar at December 31, 1999 and to 1.96 Reais to the Dollar at December 31, 2000.

In Brazil, AES has interests in four distribution companies or integrated utilities (the "Brazilian Businesses"). These companies have long-term concession agreements, which although varying in term, have similar clauses providing for tariff adjustments based on certain specific events or circumstances. These adjustments occur annually (at different times) for each Brazilian Business and, in certain instances, in response to specific requests for adjustment. Adjustments to the tariff rates during the annual proceedings are designed to reflect, among others, (i) increases in the inflation rate as represented by a Brazilian inflation index ("IGPM"), and (ii) increases in specified operating costs (including purchased power costs), in each case as measured over the preceding twelve months. The specific tariff adjustment mechanism provides each Brazilian Business the option to request additional rate adjustments arising from significant events, such as the increase in cost of purchased power due to

exchange rate variations, which disrupt the economic and financial equilibrium of such business. Other normal, or recurring, events are also included as a specific tariff increase and may include normal increases in purchased power costs, taxes on revenue generated or local inflation. The Brazilian Business requesting relief has the burden to prove the impact on its financial or economic equilibrium, however, there can be no assurance that such adjustments will be granted. Each Brazilian Business intends to recover the specific rate adjustments provided for in the concession agreements, and $50 million and $167 million of these costs (representing the Company's portion of such costs) that are expected to be recovered through future tariff increases were deferred at December 31, 1999 and 2000, respectively. Of the total at December 31, 2000, $75 million of such costs have been included in subsequent approved tariff increases and $92 million remains subject to requested or yet to be filed approval requests. No significant amounts related to requests for approval of such purchased power costs have been denied to date. AES also has a controlling interest in an integrated electric utility in Venezuela. The basic tariff rates were set pursuant to the 1999 Resolution, which provides for annual tariff rate increases. These basic tariff rates are also adjusted semiannually to reflect fluctuations in inflation and the currency exchange rate, and monthly to reflect fluctuations in the prices of energy and combustible fuels used to generate electricity. This resolution expires January 1, 2003, and subsequent tariffs are expected to be determined by the Ministry of Energy and Mines of Venezuela, pursuant to new economic regulations for the electric sector to be issued and the concession contract required to be entered into with the Ministry of Energy and Mines as required by the 1999 Electricity Service Law.

Although the Company's operations are diversified, the results of operations in any particular period may be significantly influenced by changes in conditions, particularly in geographic areas where we have larger businesses or significant investments. For example, in the United Kingdom, a portion of our Drax business is not contracted and as a result, revenues are subject to changes in spot electricity prices. Fluctuations in the United Kingdom electricity pool prices will impact the Company's contribution from Drax. Furthermore, in Brazil, most of the Company's earnings are derived from our distribution businesses. The Company's results of operations will, therefore, be impacted by changes in the overall volume of electricity consumption in Brazil, which can be significantly influenced by price levels determined under electricity sales concessions, weather and other general economic conditions. The Company's results of operations in Brazil are also sensitive to changes in the exchange rate between the Brazilian Real and the U.S. Dollar. Similarly, in Venezuela, EDC's results of operations will also be impacted by the level of electricity tariffs, weather and the general economic conditions in Venezuela, which is sensitive to the price of oil. The contribution from our generation assets in New York is influenced significantly by the short- and intermediate-term electricity prices in the Northeastern part of the United States.

Accounting for Derivatives. 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. 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. The Company utilizes derivative financial instruments to manage interest rate risk, foreign exchange risk and commodity price risk. Although the majority of the Company's derivative instruments qualify for hedge accounting, the adoption of SFAS No. 133 will result in more variation to the Company's results of operations from changes in interest rates, foreign exchange rates and commodity prices. Note 17 to the consolidated financial statements provides a more complete discussion of the accounting for derivatives under SFAS No. 133.

Revenues. Revenues increased $3.4 billion, or 103%, to $6.7 billion in 2000 from $3.3 billion in 1999. The increase in revenues is due primarily to the acquisition of both new generation and distribution businesses.

Generation revenues increased $1.5 billion, or 75%, to $3.5 billion in 2000 and accounted for 44% of the Company's total increase in revenues in 2000. Drax, Tietê and the New York plants contributed significantly to the overall increase in generation revenues. Drax and Tietê were acquired in the fourth quarter of 1999, and the New York plants were acquired in the second quarter of 1999.

Distribution revenues increased $1.9 billion, or 146%, to $3.2 billion in 2000 and accounted for 56% of the Company's total increase in revenues in 2000. CILCORP, EDC, NewEnergy and EDE Este contributed significantly to the overall increase in distribution revenues. EDC was acquired in June 2000, and CILCORP, NewEnergy and EDE Este were acquired in the latter half of 1999.

Gross Margin. Gross margin, which represents total revenues reduced by cost of sales, increased $704 million, or 71%, to $1.7 billion in 2000 from $996 million in 1999. Gross margin as a percentage of revenues decreased to 25% in 2000 from 31% in 1999. The decrease in gross margin as a percentage of revenues is because a higher percentage of the Company's operations are in distribution businesses in 2000 than in 1999, and our distribution businesses generally, experience lower gross margin percentages because of the retail oriented nature of the businesses.

The generation gross margin increased $557 million, or 70%, to $1.3 billion in 2000. The generation gross margin as a percentage of revenues remained fairly constant at 37% in 2000 and 38% in 1999. Acquisitions during 2000 did not contribute significantly to the generation gross margin during 2000. The overall increase in gross margin is due primarily to generation businesses acquired during 1999, which contributed a full year of operations in 2000. The gross margin of generation businesses in existence prior to 1999 also increased but to a lesser extent.

The distribution gross margin increased $147 million, or 72%, to $350 million in 2000 from $203 million in 1999. The distribution gross margin as a percentage of revenues decreased to 11% in 2000 from 16% in 1999. The overall decrease in gross margin as a percentage of revenues is due primarily to losses at EDE Este, NewEnergy, Power Direct and CESCO. EDE Este, New Energy and CESCO were all acquired during 1999, and Power Direct began operations in 1999. The acquisition of EDC in 2000 contributed significantly to the overall increase in distribution gross margin. The gross margin of distribution businesses in existence prior to 1999 decreased slightly in 2000.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $14 million, or 20%, to $85 million in 2000 from $71 million in 1999. Selling, general and administrative expenses as a percentage of revenues remained fairly constant at 1% in 2000 and 2% in 1999. The increase is due primarily to an increase in business development activities.

Interest Expense. Interest expense increased $659 million, or 103%, to $1.3 billion in 2000 from $641 million in 1999. Interest expense as a percentage of revenues remained fairly constant at 19% in 2000 and 20% in 1999. Interest expense increased primarily due to the interest costs at new businesses, including Drax, Tietê, CILCORP, and EDC, as well as additional corporate interest costs resulting from the senior debt and convertible securities issued within the past two years.

Interest and Other Income. Interest and other income increased $159 million, or 185%, to $245 million in 2000 from $86 million in 1999. The $159 million increase includes an increase of $140 million from interest income and an increase of $32 million from other income, offset by a decrease of $13 million from increased foreign currency transaction losses at consolidated businesses. Interest income accounts for 87% of interest and other income. Interest income as a percentage of revenues remained fairly constant at 3% in 2000 and 2% in 1999. The increase in interest income is

due primarily to interest income at new businesses, as well as the interest recorded on the contract receivable at Thames. The slight increase in other income is due primarily to gains from the sale of investments. The slight increase in foreign currency transaction losses is due primarily to the decline in value of the Pakistani Rupee.

Environmental Fine. The Company recorded a $17 million environmental fine in 2000 related to excess nitrogen oxide air emissions at certain of its generating facilities in California. As a result of the shortage of electricity in California in 2000, our generating facilities in California operated at higher than expected capacity factors. The Company does not intend to operate its facilities in California unless it has nitrogen oxide air emission credits or allocations.

Equity in Earnings of Affiliates. Equity in earnings of affiliates (before income taxes) increased $454 million to $475 million in 2000 from $21 million in 1999. Equity in earnings of affiliates includes foreign currency transaction losses of $64 million and $203 million in 2000 and 1999, respectively. The increase in equity in earnings of affiliates resulted from the increase in equity in earnings of distribution investments offset by a slight decrease in equity in earnings of generation investments.

Equity in earnings of generation affiliates decreased $3 million to $49 million in 2000 from $52 million in 1999. The decrease in equity in earnings of generation affiliates is due primarily to the Company's acquisition of a controlling interest in Nigen which was previously reported as an equity investment, as well as a slight decrease in the contributions from Elsta and OPGC.

Equity in earnings of distribution affiliates increased $457 million to $426 million in 2000 from a loss of $31 million in 1999. The significant increase in equity in earnings of distribution affiliates is due to an additional ownership interest in Eletropaulo, as well as improved economic conditions in Brazil, which resulted in much greater contributions from Eletropaulo and CEMIG. Foreign currency transaction losses decreased $139 million in 2000 at our distribution affiliates in Brazil.

Income Taxes. Income taxes (including income taxes on equity in earnings and minority interests) increased $141 million, or 127%, to $252 million in 2000 from $111 million in 1999. The Company's effective tax rate decreased to 28% in 2000 from 31% in 1999 due to an increase in earnings of certain foreign businesses which are taxed at a lower rate than the U.S. income tax rate. The net increase in income taxes is due to an increase of $170 million from the year over year increase in income before taxes, offset by a $29 million decrease due to a reduction in the effective tax rate.

Minority Interest. Minority interest (before income taxes) increased $55 million, or 86%, to $119 million in 2000 from $64 million in 1999. The overall increase in minority interest is due to increases in minority interest from both generation and distribution businesses.

Generation minority interest increased $27 million, or 64%, to $69 million in 2000 from $42 million in 1999. The increase in generation minority interest is due primarily to increased contributions from generation businesses in South America.

Distribution minority interest increased $28 million, or 127%, to $50 million in 2000 from $22 million in 1999. The overall increase in distribution minority interest is due primarily to increased contributions from EDC and CEMIG, offset by lower contributions from EDE Este and CESCO.

Extraordinary Item. In 2000, the Company recorded a $7 million loss, net of income taxes, from the early extinguishment of recourse debt. In 1999, the Company recorded a $17 million loss, net of income taxes, from the early extinguishment of recourse debt and non-recourse debt at Placerita.

Net Income. Net income increased $413 million, or 181%, to $641 million in 2000 from $228 million in 1999. The increase in net income is due to increases in net income from both generation and distribution businesses. The generation businesses contributing the most to the increase

were the New York plants and Drax. The distribution businesses contributing the most to the increase were EDC, Eletropaulo and CEMIG.

Revenues. Revenues increased $855 million, or 36%, to $3.3 billion in 1999 from $2.4 billion in 1998. The increase in revenues is due primarily to the acquisition of both new generation and distribution businesses, as well as from the commercial operation of greenfield generation projects.

Generation revenues increased $557 million, or 39%, to $2.0 billion in 1999 and accounted for 65% of the Company's total increase in revenues in 1999. New businesses acquired during 1999 that contributed significantly to the overall increase in generation revenues include certain of the New York plants, Drax and Panama. A full year of operations at Southland and Barry, as well as the acquisitions of Tietê in the fourth quarter of 1999 also contributed to the increase in generation revenues.

Distribution revenues increased $298 million, or 30%, to $1.3 billion in 1999 and accounted for 35% of the Company's total increase in revenues in 1999. New businesses acquired during 1999 that contributed significantly to the overall increase in distribution revenues include NewEnergy, CILCORP and EDE Este. A full year of operations at Edelap also contributed to the increase in revenues. Distribution revenues were negatively impacted at Sul due to the effects of the devaluation of the Brazilian Real in early 1999.

Gross Margin. Gross margin, which represents total revenues reduced by cost of sales, increased $207 million, or 26%, to $996 million in 1999 from $789 million in 1998. Gross margin as a percentage of revenues decreased to 31% in 1999 from 33% in 1998. The decrease in gross margin as a percentage of revenues is due to the decrease in the distribution gross margin.

The generation gross margin increased $227 million, or 40%, to $793 million in 1999 from $566 million in 1998. The generation gross margin as a percentage of revenues remained fairly constant at 40% in 1999 and 40% in 1998. In 1999, the generation gross margin was favorably impacted by a settlement with the government of Kazakhstan, which resulted in a decrease in the provision to reduce contract receivables.

The distribution gross margin decreased $20 million, or 9%, to $203 million in 1999 from $223 million in 1998. The distribution gross margin as a percentage of revenues decreased to 16% in 1999 from 23% in 1998. The decrease in gross margin is due primarily to a decline in gross margin at Sul, which was negatively impacted by the devaluation of the Brazilian Real. The overall decrease in gross margin as a percentage of revenues is due primarily to losses at NewEnergy and CESCO, both of which were acquired in 1999.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $15 million, or 27%, to $71 million in 1999 from $56 million in 1998. Selling, general and administrative expenses as a percentage of revenues remained constant at 2% in both 1999 and 1998. The increase is due in equal part to an increase in corporate overhead and an increase in business development activities.

Interest Expense. Interest expense increased $156 million, or 32%, to $641 million in 1999 from $485 million in 1998. Interest expense as a percentage of revenues remained constant at 20% in both 1999 and 1998. Interest expense increased primarily due to the interest at new businesses, as well as additional corporate interest costs arising from the senior debt and convertible securities issued in the two years prior to December 31, 1999.

Interest and Other Income. Interest and other income increased $20 million, or 30%, to $86 million in 1999 from $66 million in 1998. Interest income increased $5 million to $72 million in 1999. Interest income as a percentage of revenues decreased to 2% in 1999 from 3% in 1998. Interest income increased primarily due to an increase in funds available for investment. Other income, which consists of foreign currency transaction gains and the gain on a sale of an investment, increased $15 million to $14 million in 1999. The foreign currency transaction gain in 1999 resulted from the increase in the Brazilian Real subsequent to the Company's acquisition of Tiete in the fourth quarter of 1999 offset by a decline in the value of the Pakistani Rupee. The Company was also negatively impacted by the devaluation of the Brazilian Real during the first nine months of 1999.

Net Gain on Contract Buyout. The Company recorded a $29 million gain (before extraordinary loss) in 1999 from the buyout of its long-term power sales agreement at Placerita. The Company received gross proceeds of $110 million which were offset by transaction-related costs of $19 million and an impairment loss of $62 million to reduce the carrying value of the electric generation assets to their estimated fair value after termination of the contract. The estimated fair value was determined by an independent appraisal. Concurrent with the buyout of the power sales agreement, the Company repaid the related non-recourse debt prior to its scheduled maturity and recorded an extraordinary loss of $11 million, net of income taxes.

Equity in Earnings of Affiliates. Equity in earnings of affiliates (before income taxes) decreased $211 million, or 91%, to $21 million in 1999 from $232 million in 1998. Equity in earnings of affiliates includes foreign currency transaction losses of $203 million and $59 million in 1999 and 1998, respectively. Excluding foreign currency transaction losses, equity in earnings of affiliates decreased 23%. The overall decline in equity in earnings of affiliates resulted from the decrease in equity in earnings of distribution investments offset by an increase in equity in earnings of generation investments.

Equity in earnings of generation affiliates increased $19 million, or 58%, to $52 million in 1999 from $33 million in 1998. The increase is due primarily to the Company's 1999 investment in OPGC.

Equity in earnings of distribution affiliates decreased $230 million to a loss of $31 million in 1999 from earnings of $199 million in 1998. All of the Company's equity investments in distribution businesses are in Brazil, and they were negatively impacted by the devaluation of the Brazilian Real during 1999. The Brazilian Real experienced a significant devaluation relative to the U.S. Dollar, declining from 1.21 Reais to the Dollar at December 31, 1998 to 1.81 Reais at December 31, 1999. The Company recorded $203 million of foreign currency transaction losses on its investments in Brazilian affiliates during 1999. Equity in earnings of affiliates (before income tax) is presented net of the foreign currency transaction losses in the statements of operations.

Income Taxes. Income taxes (including income taxes on equity in earnings and minority interest) decreased $34 million, or 23%, to $111 million in 1999 from $145 million in 1998. The Company's effective tax rate was 31% in 1999 and 32% in 1998.

Minority Interest. Minority interest (before income taxes) decreased $30 million, or 32%, to $64 million in 1999 from $94 million in 1998. The increase in generation minority interest was offset by a larger decrease in distribution minority interest, resulting in the overall decrease.

Generation minority interest increased $14 million, or 50%, to $42 million in 1999 from $28 million in 1998. The increase in minority interest is due primarily to the acquisition of control of two hydroelectric companies in Panama in January 1999.

Distribution minority interest decreased $44 million, or 67%, to $22 million in 1999 from $66 million in 1998. The decrease in minority interest is due primarily to lower contributions from CEMIG and Sul in 1999, both of which were negatively impacted by the devaluation of the Brazilian Real during 1999.

Extraordinary Item. In 1999, the Company recorded a $17 million loss, net of income taxes from the early extinguishment of recourse debt and non-recourse debt at Placerita. In 1998, the Company recorded a $4 million gain, net of income taxes from the early redemption of $18 million of 10.125% notes at Chigen.

Net Income. Net income decreased $83 million, or 27%, to $228 million in 1999 from $311 million in 1998. The decrease in net income is due primarily to the devaluation of the Brazilian Real and the resulting decline in equity in earnings of affiliates in distribution businesses in Brazil. Excluding the $132 million of foreign currency transaction losses, net of income taxes, net income increased $49 million in 1999.

Global electricity markets continue to restructure and shift away from government-owned and government-regulated electricity systems toward deregulated, competitive market structures. Many countries have rewritten their laws and regulations to allow foreign investment and private ownership of electricity generation, transmission or distribution companies. Several countries have or are in the process of "privatizing" their electricity systems by selling all or part of such systems to private investors. In addition, some companies are choosing to divest some or all of their electricity generating assets. This global trend of electricity market restructuring provides significant new business opportunities for companies like AES.

In the United States, the federal government and some of the state government regulatory agencies have also embraced the global trend encouraging liberalized electricity markets. In particular, the federal government has adopted regulations encouraging the establishment of wholesale electricity markets by permitting generating facilities that sell their electricity solely to wholesale customers to avoid regulation by state utility commissions and sell their output at market-based rates. The federal government has also adopted regulations requiring utilities to transport electricity generated by competitors on the same terms and conditions that they apply to their own generation.

As a result, many regulated United States public utilities have begun to sell or auction their generation capacity. Substantially all of the transmission and distribution services in the U.S. continue to be regulated under a combined state and federal framework. As a result, the Company is subject in the United States to a complex set of federal and state regulation, both directly through regulations affecting the electricity business and indirectly through environmental and other regulations that have an effect upon the business of generating and distributing electricity.

In addition, in those states and regions where the Company owns generating assets that sell electricity directly into power pools, the Company is subject to a changing regulatory environment which may affect or influence the orderly development of the applicable power pool. In some of these power pools the oversight bodies have not adopted and/or finalized regulations governing the operation

of these markets, thus new laws and regulations may become applicable to AES that may have an effect on our business or results of operations.

During 2000, the wholesale electricity markets in California experienced a significant imbalance in the supply of, and demand for electricity, which resulted in significant electricity price increases and volatility. The imbalance was a result of many factors, including, among other things, growing demand, regional supply shortages due to weather conditions, minimal additions of new generating capacity over the previous decade, the cost and availability of NOx emissions credits and natural gas, and the state regulatory requirement that the regulated utilities purchase nearly all of their electricity supply from spot markets. As a result there is significant pressure to change the current market structure. Such proposals range from returning to statewide cost-based regulation to allowing for full competitive market pricing to end use consumers.

AES has approximately 4,100 megawatts of generation capacity in California, and also sells electricity to commercial and industrial end users through AES NewEnergy. Of the generation total, approximately 3,956 megawatts (Alamitos, Huntington Beach and Redondo Beach) are subject to a long-term tolling agreement with a third party. Under this agreement, AES's subsidiaries receive predetermined capacity and operating and maintenance payments in return for operating the plant for the benefit of the third party. As a result, the revenues of such subsidiaries do not reflect in material amounts the electricity price increases or volatility experienced during 2000. However, because of the significance of the impacts of these price movements on the regulated utilities, consumers and other market participants in the state, the ultimate resolution or composition of potentially significant market or regulatory changes cannot currently be determined or predicted.

The current market structure requires California's two largest utilities purchase wholesale power and sell at retail to end users at fixed prices. Because the cost of wholesale power has exceeded the price the utilities can charge their retail customers, these utilities are facing severe financial difficulties. There can be no assurances that such utilities can, or will choose to, honor their financial commitments. In the event that such utilities become insolvent or otherwise chose not to honor their commitments, creditors, including certain of the Company's subsidiaries, may seek to exercise whatever remedies may be available, including, among other things, placing the utilities into involuntary bankruptcy. There can be no assurances that amounts owing directly or indirectly from such utilities will be recovered. In addition, the California Independent System Operator has sought a temporary restraining order over some of the generators including AES subsidiaries, arguing that in times of declared emergencies, generators are required to provide electricity to the market even if there is no credit-worthy purchaser for the electricity. The bulk of the Company's revenues in California are not subject to this credit risk because they are generated under the tolling agreement entered into by AES Southland. But the Company's other subsidiaries have some exposure to this risk. At December 31, 2000, the Company had receivables of $27 million that are subject to this credit risk. In addition, because these utilities have defaulted on amounts due in the state-sanctioned markets, the markets have sought to recover those amounts pro rata from other market participants, including certain of the Company's subsidiaries.

AES also has pending a purchase of 3 of 4 undivided interests totaling 90% in a 1,580 MW coal-fired power plant located in Nevada ("Mohave"). One of the approvals required to permit AES to purchase the 56% interest in Mohave currently held by Southern California Edison ("SCE") has not been obtained from the California Public Utilty Commission. As a result, the asset sale and purchase agreement between AES and SCE can be terminated by either party. No such action has been taken by either party at this time. Furthermore, a recently enacted state law prohibits the sale by SCE of its interest in Mohave. AES continues to pursue the purchase of Mohave, but there can be no assurance that the Company will be successful in acquiring any or all of the four ownership interests.

Many states have passed or are considering new legislation that would permit utility customers to choose their electricity supplier in a competitive electricity market (so-called "retail access" or

"customer choice" laws). While each state's plan differs in details, there are certain consistent elements, including allowing customers to choose their electricity suppliers by a certain date (the dates in the existing or proposed legislation vary between 1999 and 2003), allowing utilities to recover "stranded assets" (the remaining costs of uneconomic generating or regulatory assets) and a reaffirmation of the validity of contracts like the Company's United States contracts.

In addition to the potential for state restructuring legislation, several competing bills have been proposed in the Congress to encourage customer choice and recovery of stranded assets. Federal legislation might be needed to avoid the conflicting effect of each state acting separately to pass restructuring legislation (with the likely result of uneven market structures in neighboring states). While it is uncertain whether or when federal legislation dealing with electricity restructuring might be passed, the Company believes that such legislation would not likely have a negative effect on the Company's United States business.

The Company's generation activities in the United States are subject to the provisions of various laws and regulations, including the Federal Power Act, the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA") and the Public Utility Holding Company Act of 1935, as amended ("PUHCA"). There is legislation currently before the U.S. Congress to repeal part or all of the current provisions of PURPA and PUHCA. The Company believes that if such legislation is adopted, competition in the U.S. for new generation capacity from vertically integrated utilities would increase. However, independent power producers like AES would also be free to acquire such utilities.

As consumers, regulators and suppliers continue the debate about how or whether to further decrease the regulatory aspects of providing electricity services, the Company believes in and is encouraging the continued orderly transition to a more competitive electricity market. Inherent in any significant transition to competitive markets are risks associated with the competitiveness of existing regulated enterprises, and as a result, their ability to perform under long-term contracts such as the Company's power sales agreements. Although AES strongly believes that its contracts will be honored, there can be no assurance that each of its customers, in a restructured and competitive environment, will be capable in all circumstances of fulfilling their financial and legal obligations.

AES's investments and involvement in the development of new projects and the acquisition of existing power plants and distribution companies in locations outside the United States are increasing. The financing, development and operation of such businesses may entail significant political and financial uncertainties and other structuring issues (including uncertainties associated with the legal environments, including tax regulations, with first-time privatization efforts in the countries involved, currency exchange rate fluctuations, currency repatriation restrictions, currency inconvertibility, political instability, civil unrest and, in severe cases, possible expropriation). Although AES attempts to minimize these risks, these issues have the potential to cause substantial delays or material impairment to the value of the project being developed or business being operated.

It is also possible that as more of the world's markets move toward competition, an increasing proportion of the Company's revenues may be dependent on prices determined in electricity spot markets. In order to capture a portion of the market share in competitive generation markets, AES has, in certain instances, acquired or invested in "merchant" plants (plants without long-term electricity sale contracts) in those markets. Such an investment may require the Company (as well as its competitors) to make larger equity contributions (as a percentage of the total capital or acquisition cost) than the more traditional long-term contract-based investments. Moreover, in some of these electricity markets, such as in the United Kingdom, the regulatory authorities have proposed changes that, if enacted, could restructure the way electricity is bought and sold and, as a result, could adversely effect the Company's results of operations and financial position.

The Company has also entered the retail supply market, in some cases as extensions of its generation or distribution businesses. The Company's retail businesses operate in a new and developing

market environment, hence there is considerable uncertainty as to how quickly and significantly these markets will develop.

AES's business activities are subject to stringent environmental regulation by relevant authorities at each location. Particularly in the United States, owners and operators of coal-fired generating facilities are under increasing scrutiny from state and federal environmental authorities. If environmental laws or regulations were to change in the future, or if the regulatory agencies with oversight authority were to adopt new enforcement priorities under existing laws, there can be no assurance that AES would be able to recover all or any increased costs from its customers or that its business and financial condition would not be materially and adversely affected. In addition, the Company or its subsidiaries and affiliates may be required to make significant capital expenditures in connection with environmental matters. AES is committed to operating its businesses cleanly, safely and reliably and strives to comply with all environmental laws, regulations, permits and licenses but, despite such efforts, at times has been in non-compliance, although no such instance has resulted in revocation of any permit or license.

At December 31, 2000, AES had consolidated net working capital of $691 million as compared to $17 million at the end of 1999. Cash and short-term investments were $2.2 billion at December 31, 2000 and included $848 million of cash, which had been raised through the issuance of debt and equity for the purchase of Gener. Amounts raised for the acquisition of Gener are included as restricted cash in short-term investments in the balance sheet. Included in the net working capital is approximately $2.5 billion from the current portion of long-term debt, which the Company expects to refinance for longer periods during 2001. The increase in net working capital was due primarily to an increase in receivables including the Thames contract prepayment receivable, combined with a decrease in the current portion of recourse debt. Accounts receivable increased primarily from the acquisitions during 2000. The current portion of recourse debt decreased because the current portion of the Revolver was refinanced with long-term financing during 2000.

Property, plant and equipment, net of accumulated depreciation, accounts for 58% of the Company's total assets and was $17.8 billion at December 31, 2000. Net property, plant and equipment increased $4.4 billion, or 33%, during 2000. The increase was due primarily to acquisitions completed during 2000. The continuation of construction activities at the Company's greenfield projects contributed to a much lesser extent.

In total, the Company's consolidated debt increased $6.1 billion, or 51%, to $18.2 billion at December 31, 2000. The increase is due primarily to borrowings associated with the Company's 2000 acquisitions. Borrowing used to fund the construction of the Company's greenfield projects contributed to a much lesser extent.

At December 31, 2000, the Company had $881 million of cash and cash equivalents. Cash and cash equivalents increased $212 million due primarily to the $459 million provided by operating activities, which were partially reduced by cash used to fund investing activities, net of financing activities. The $5.5 billion of cash raised by financing activities was used to fund the $5.7 billion of investing activities.

Cash flows provided by operating activities totaled $459 million during 2000. The increase in cash provided by operating activities during 2000 is due primarily to the increase in net income during 2000. Net cash used in investing activities totaled $5.7 billion during 2000. The cash used in investing activities includes $1.8 billion for acquisitions, $2.2 billion for property additions and $1.1 billion from the increase in restricted cash, the majority of which is for the Gener acquisition. Net cash provided by financing activities was $5.5 billion during 2000. The cash provided by financing activities includes $4.3 billion provided by net borrowings and $1.4 billion provided by the sale of common stock offset by payments on long-term liabilities of approximately $200 million.

Parent EBITDA, cash flow to the parent net of parent overhead charges, amounted to approximately $871 million for the year ended December 31, 2000. The parent fixed charge ratio was approximately 4.03x for the year ended December 31, 2000.

AES's business is capital intensive and requires significant investments to develop or acquire new operations. Occasionally, AES will also seek to refinance certain outstanding debt. Continued access to capital on competitive and acceptable terms is therefore a significant factor in the Company's ability to expand further. AES has, to the extent practicable, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire its electric power plants, distribution companies and related assets. Non-recourse borrowings are substantially non-recourse to other subsidiaries and affiliates and to AES as the parent company, and are generally secured by the capital stock, physical assets, contracts and cash flow of the related subsidiary or affiliate.

The Company intends to continue to seek, where possible, such non-recourse debt financing in connection with the assets or businesses that the Company or its affiliates may develop, construct or acquire. However, depending on market conditions and the unique characteristics of individual businesses, the Company's providers of non-recourse debt financing, particularly multinational commercial banks or public market bond investors, may seek higher borrowing spreads and increased equity contributions.

Furthermore, because of the reluctance of commercial lending institutions to provide non-recourse debt financing (including financial guarantees) for businesses in certain less-developed economies, the Company, in such locations, has and will continue to seek direct or indirect (through credit support or guarantees) debt financing from a limited number of government-sponsored, multilateral or bilateral international financial institutions or agencies. As a pre-condition to making such non-recourse financing available, these institutions may also require governmental guarantees of certain project and sovereign-related risks. Depending on the policies of specific governments, such guarantees may not be offered, and as a result, AES may determine that sufficient financing will ultimately not be available to fund the related business, and may cease development or acquisition of such business, or alternatively AES may choose to develop or acquire such business with higher levels of corporate support than it has historically provided.

In addition to the non-recourse debt, if available, AES as the parent company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition. These investments have generally taken the form of equity investments or loans, which are subordinated to the project's non-recourse loans. The funds for these investments have been provided by cash flows from operations and by the proceeds from issuances of debt, common stock and other securities issued by the Company. Similarly, in certain of its businesses, the Company may provide financial guarantees or other credit support for the benefit of counter-parties who have entered into contracts for the purchase or sale of electricity with the Company's subsidiaries. In such circumstances, were a subsidiary to default on a payment or supply obligation, the Company would be responsible for its subsidiary's obligations up to the amount provided for in the relevant guarantee or other credit support.

Interim needs for shorter-term and working capital financing at the parent company have been met with borrowings under AES's revolving credit facility (the "Revolver"). The Company currently maintains an $850 million credit line under the Revolver. The Revolver and other borrowings contain certain restrictive covenants. The covenants provide for, among other items, maintenance of certain reserves, and require that minimum levels of working capital, net worth, and certain financial ratio tests are met. The most restrictive of these covenants include limitations on incurring additional debt and on the payment of dividends to stockholders. At December 31, 2000, cash borrowings and letters of credit

outstanding under the Revolver amounted to $140 million and $345 million, respectively. Letters of credit outstanding outside the Revolver amounted to $258 million. The Company may also seek, from time to time, to meet some of its short-term and interim funding needs with additional commitments from banks and other financial institutions at the parent or subsidiary level. For instance, from time to time, the Company has contributed shares of its common stock to subsidiaries to serve as collateral for certain loans. The Company has $1.3 billion aggregate principal amount of such loans currently outstanding.

The ability of AES's subsidiaries and affiliates to declare and pay dividends to AES is restricted under the terms of existing non-recourse debt agreements. (See Note 6 to the consolidated financial statements for additional information.) In connection with its non-recourse financings and related contracts, AES has expressly undertaken certain limited obligations and contingent liabilities, most of which will only be effective or will be terminated upon the occurrence of future events. AES's obligations and contingent liabilities in certain cases take the form of, or are supported by, letters of credit. These obligations and contingent liabilities, excluding future commitments to invest and those collateralized with letter of credit obligations, were limited by their terms as of December 31, 2000, to an aggregate of approximately $659 million. The Company is obligated under other contingent liabilities, which are limited to amounts, or percentages of amounts, received by AES as distributions from its project subsidiaries. These contingent liabilities aggregated $71 million as of December 31, 2000. In addition, AES has expressly undertaken certain other contingent obligations which the Company does not expect to have a material adverse effect on its results of operations or financial position, but which by their terms are not capped at a dollar amount. Because each of the Company's businesses are distinct entities and geographically diverse and because the obligations related to a single business are based on contingencies of varying types, the Company believes it is unlikely that it will be called upon to perform under several of such obligations at any one time.

At December 31, 2000, the Company and its subsidiaries have future commitments of $111 million to fund investments in its projects under construction and in development, excluding those collateralized with letter of credit obligations. The remaining future capital commitments are expected to be funded by internally generated cash flows and by external financings as may be necessary.

AES is exposed to market risks associated with interest rates, foreign exchange rates and commodity prices. AES often utilizes financial instrument contracts to hedge against such fluctuations. AES utilizes financial and commodity derivatives solely for the purpose of hedging exposures to market risk. AES does not enter into derivative instruments for speculative purposes.

Interest Rate Risk. AES is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt, fixed-rate debt, term-convertible securities and trust-preferred securities, as well as interest rate swap and option agreements. Depending on whether a plant's capacity payments or revenue stream is fixed or varies with inflation, AES partially hedges against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, AES executes interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing.

Foreign Exchange Rate Risk. AES is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk is that some of our foreign subsidiaries and affiliates utilize currencies other than AES's consolidated reporting currency, the U.S. Dollar. Additionally, certain of AES's foreign subsidiaries and affiliates have entered into monetary obligations in U.S. Dollars or currencies other than their own functional currencies. Primarily, AES is exposed to changes in the U.S. Dollar/United Kingdom Pound Sterling

exchange rate, the U.S. Dollar/Brazilian Real exchange rate and the U.S. Dollar/ Dutch Guilder exchange rate. Whenever possible, these subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. AES also uses foreign currency forward and swap agreements, where possible, to manage our risk related to certain foreign currency fluctuations.

Commodity Price Risk. AES is exposed to the impact of market fluctuations in the price of electricity, natural gas and coal. Although AES primarily consists of businesses with long-term contracts or retail sales concessions, an increasing proportion of AES's current and expected future revenues are derived from businesses without significant long-term revenue or supply contracts. These non-contract businesses subject our results of operations to the volatility of electricity and natural gas prices in competitive markets. AES's businesses hedge certain aspects of their "net open" positions in the U.S. 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, futures, swaps and options.

Value at Risk. In 2000, AES adopted a value at risk ("VaR") approach to assess and manage risk across the Company and its subsidiaries. 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 the Company feels that statistical models of risk measurement, such as VaR, provide an objective, independent assessment of risk exposure to the Company. 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 AES to aggregate risks across all AES businesses, 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, AES relies on VaR as only one component in its risk assessment process. In addition to using VaR measures, AES performs 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.

AES has performed a company-wide VaR analysis of all of its material financial assets, liabilities and derivative instruments. The VaR calculation incorporates numerous variables that could impact the fair value of AES's instruments, including interest rates, foreign exchange rates and commodity prices, as well as correlation within and across these variables. AES performs its VaR calculation using a model based on J.P. Morgan's RiskMetrics approach, which utilizes the variance/covariance method. 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 interest rate-sensitive instruments as of December 31, 2000 and 1999 was $34.8 million and $19.9 million, respectively. These amounts include the financial instruments that serve as hedges and the underlying hedged items. The increase in the daily VaR can be attributed primarily to debt issued and assumed through acquisitions in 2000 and the associated interest rate swaps and options that serve to hedge those instruments. Our daily VaR for foreign exchange rate-sensitive instruments as of December 31, 2000 and 1999 was $4.9 million and $6.1 million, respectively. These amounts include the financial instruments that serve as hedges and the underlying hedged items. Our daily VaR for commodity price-sensitive instruments as of December 31, 2000 and 1999 was $5.5 million and $2.4 million, respectively. These amounts include the financial instruments that serve as hedges and do not include the underlying physical assets. At no date during 2000 or 1999 was the daily VaR amount in each of the three risk categories greater than it was at year-end. AES does not trade or speculate in derivatives.

We have audited the accompanying consolidated balance sheets of The AES Corporation and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of operations, changes in stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2000. Our audits also included the financial statement schedules listed in the Index on page S-1. These financial statements and financial statement schedules are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits. We did not audit the financial statements of C.A. La Electricidad de Caracas and Corporation EDC, C.A. and their subsidiaries ("EDC"), a majority-owned subsidiary, for the year ended December 31, 2000, which statements reflect total assets constituting 11% of consolidated total assets, total revenues constituting 7% of consolidated total revenues and total net income constituting 19% of consolidated net income for that year. These financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for EDC, is based solely on the report of such other auditors.

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 the audit 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, based on our audits and the report of other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of The AES Corporation and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, based on our audits and the report of other auditors, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

The AES Corporation
Consolidated Statements of Operations
Years Ended December 31, 2000, 1999 and 1998

The AES Corporation
Consolidated Statements of Cash Flows
Years Ended December 31, 2000, 1999 and 1998

The AES Corporation
Consolidated Statements of Changes in Stockholders' Equity
Years Ended December 31, 2000, 1999 and 1998

The AES Corporation
Notes To Consolidated Financial Statements
December 31, 2000, 1999 and 1998

The AES Corporation and its subsidiaries and affiliates, (collectively "AES" or "the Company") is a global power company primarily engaged in owning and operating electric power generation and distribution businesses in many countries around the world.

Principles of Consolidation—The consolidated financial statements of the Company include the accounts of The AES Corporation, its subsidiaries, and controlled affiliates. Investments in 50% or less owned affiliates, over which the Company has the ability to exercise significant influence but not control, are accounted for using the equity method. Intercompany transactions and balances have been eliminated.

Cash and Cash Equivalents—The Company considers unrestricted cash on hand, deposits in banks, certificates of deposit, and short-term marketable securities with an original maturity of three months or less to be cash and cash equivalents.

Investments—Securities that the Company has both the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at historical cost. Other investments that the Company does not intend to hold to maturity are classified as available-for-sale or trading. Unrealized gains or losses on available-for-sale investments are recorded as a separate component of stockholders' equity. Investments classified as trading are marked to market on a periodic basis through the statement of operations. Interest and dividends on investments are reported in interest income. Gains and losses on sales of investments are recorded using the specific identification method. Short-term investments consist of investments with original maturities in excess of three months but less than one year. Short-term investments also include $1.2 billion of restricted cash. Debt service reserves and other deposits, which might otherwise be considered cash and cash equivalents, are treated as non-current assets (see Note 5).

Inventory—Inventory, valued at the lower of cost or market (first in, first out method), consists of coal, fuel oil, other raw materials, spare parts and supplies. Inventory consists of the following (in millions):

	December 31,
	2000		1999
Coal, fuel oil, and other raw materials	$	275	$	191
Spare parts and supplies		224		116

Total	$	499	$	307

Property, Plant, and Equipment—Property, plant, and equipment is stated at cost. The cost of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. Depreciation, after consideration of salvage value, is computed using the straight-line method over the estimated composite useful lives of the assets. Depreciation expense stated as a percentage of average cost of depreciable property, plant and equipment was, on a composite basis, 3.68%, 3.76% and 3.33% for the years ended December 31, 2000, 1999 and 1998, respectively. The

components of our electric generation and distribution assets and the related rates of depreciation are as follows.

	Composite Rate	Useful Life
Generation and Distribution Facilities	2.0% – 10.0%	10 – 50 yrs
Other Buildings	2.5% – 5.0%	20 – 40 yrs.
Leasehold Improvements	3.3% – 10.0%	10 – 30 yrs.
Furniture and Fixtures	14.3% – 50.0%	2 – 7 yrs

Maintenance and repairs are charged to expense as incurred. Emergency and rotable spare parts inventories are included in electric generation and distribution assets and are depreciated over the useful life of the related components.

Construction in Progress—Construction progress payments, engineering costs, insurance costs, salaries, interest, and other costs relating to construction in progress are capitalized. Construction in progress balances are transferred to electric generation and distribution assets when each asset is ready for its intended use. Interest capitalized during development and construction totaled $224 million, $104 million, and $79 million in 2000, 1999, and 1998, respectively.

Excess of Cost Over Net Assets Acquired—Excess of cost over net assets acquired is amortized on a straight-line basis over the estimated benefit period which ranges from 10 to 40 years. Excess of cost over net assets acquired at December 31, 2000 and 1999 are shown net of accumulated amortization of $128 million and $70 million, respectively.

Long-Lived Assets—In accordance with Statement of Financial Accounting Standards (SFAS) No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, the Company evaluates the impairment of long-lived assets, as well as excess of cost over net assets acquired, based on the projection of undiscounted cash flows whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded value of the assets, the assets are written down to their estimated fair values (see Note 12) based on discounted cash flow analysis.

Deferred Financing Costs—Financing costs are deferred and amortized over the related financing period using the effective interest method or the straight-line method when it does not differ materially from the effective interest method. Deferred financing costs are shown net of accumulated amortization of $103 million and $87 million as of December 31, 2000 and 1999, respectively.

Project Development Costs—The Company capitalizes the costs of developing new construction projects after achieving certain project-related milestones that indicate that the project is probable of completion. These costs represent amounts incurred for professional services, permits, options, capitalized interest, and other costs directly related to construction. These costs are transferred to property when significant construction activity commences, or expensed at the time the Company determines that development of a particular project is no longer probable. The continued capitalization of such costs is subject to ongoing risks related to successful completion, including those related to government approvals, siting, financing, construction, permitting, and contract compliance.

Income Taxes—The Company follows SFAS No. 109, Accounting for Income Taxes. Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases.

Foreign Currency Translation—Subsidiaries and affiliates whose functional currency is other than the U.S. Dollar translate their assets and liabilities into U.S. Dollars at the current exchange rates in effect at the end of the fiscal period. The revenue and expense accounts of such subsidiaries and affiliates are

translated into U.S. Dollars at the average exchange rates that prevailed during the period. The gains or losses that result from this process, and gains and losses on inter-company foreign currency transactions which are long-term in nature, and which the Company does not intend to settle in the foreseeable future, are shown in accumulated other comprehensive loss in the stockholders' equity section of the balance sheet. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency (except those that are accounted for as hedges) are included in determining net income. Foreign currency transaction gains and losses that are intended to hedge an identifiable foreign currency commitment are deferred and included in the measurement of the related foreign currency transaction. For subsidiaries operating in highly inflationary economies, the U.S. Dollar is considered to be the functional currency, and transaction gains and losses are included in determining net income.

During 1999, the Brazilian Real experienced a significant devaluation relative to the U.S. Dollar, declining from 1.21 Reais to the Dollar at December 31, 1998 to 1.81 Reais at December 31, 1999. The exchange rate was 1.96 Reais to the Dollar at December 31, 2000. This continued devaluation resulted in significant foreign currency translation and transaction losses particularly during 1999. The Company recorded $64 and $203 million before income taxes of non-cash foreign currency transaction losses on its investments in Brazilian equity-method affiliates during 2000 and 1999, respectively.

Revenue Recognition and Concentration—Revenues from the sale of electricity and steam generation are recorded based upon output delivered and capacity provided at rates as specified under contract terms or prevailing market rates. Electricity distribution revenues are recognized when power is provided. Revenues from power sales contracts entered into after 1991 with escalating scheduled rates are recognized based on the output delivered at the lower of the amount billed or the average rate over the contract term. Several of the Company's power plants rely primarily on one power sales contract with a single customer for the majority of revenues (see Note 7). No single customer accounted for at least 10% of revenues in 2000, 1999 or 1998. The prolonged failure of any of the Company's customers to fulfill contractual obligations or make required payments could have a substantial negative impact on AES's revenues and profits.

Regulation—The Company has investments in electric distribution businesses located in the United States and certain foreign countries that are subject to regulation by the applicable regulatory authority. Our distribution businesses operate in markets that are subject to price-cap regulation, which means the price of electricity is regulated as opposed to the investors' rate of return. For the regulated portion of these businesses, the Company capitalizes incurred costs as deferred regulatory assets when there is a probable expectation that future revenue equal to the costs incurred will be billed and collected as a direct result of the inclusion of the costs in an increased tarriff set by the regulator. The deferred regulatory asset is eliminated when the Company collects the related costs through billings to customers. Regulators in the respective jurisdictions typically perform a tariff review for the distribution companies on an annual basis. If a regulator excludes all or part of a cost from recovery, that portion of the deferred regulatory asset is impaired and is accordingly reduced to the extent of the excluded cost. The Company has recorded deferred regulatory assets of $198 million and $54 million at December 31, 2000, and 1999, respectively, that it expects to pass through to its customers in accordance with and subject to regulatory provisions. The regulatory assets include $110 million and $30 million at December 31, 2000, and 1999, respectively, that were recorded by the Company's equity method affiliates in Brazil. The deferred regulatory assets at entities which are controlled and consolidated by the Company are recorded in other assets on the consolidated balance sheets.

Derivatives—The Company enters into various derivative transactions in order to hedge its exposure to certain market risks. The Company currently has outstanding interest rate swap, cap, and floor agreements that hedge against interest rate exposure on floating rate non-recourse debt. These transactions, which are classified as other than trading, are accounted for using settlement accounting,

and any gain or loss is included in interest cost. Any fees are amortized as yield adjustments. Written interest rate options are marked-to-market through earnings.

The Company enters into currency swaps and forwards to hedge against foreign currency risk on certain non-functional currency-denominated liabilities. Gains and losses on each contract are computed by multiplying the foreign currency amount of the contract by the difference between the spot rate at the balance sheet date and the spot rate at the date of inception of the contract and recognized in the statement of operations. Any discount or premium on a currency swap or forward is accounted for separately from gains and losses on the contract and is amortized to net income over the life of the contract.

The Company enters into electric and gas derivative instruments, including swaps, options, forwards and futures contracts to manage its risks related to electric and gas sales and purchases. Gains and losses arising from derivative financial instrument transactions that hedge the impact of fluctuations in energy prices are recognized in income concurrent with the related purchases and sales of the commodity. If a derivative financial instrument is entered into for trading purposes, it is marked-to-market with net gains reported within revenues or net losses reported within cost of sales. If a derivative financial instrument contract is terminated because it is probable that a transaction or forecasted transaction will not occur, any gain or loss as of such date is immediately recognized. If a derivative financial instrument contract is terminated early for other economic reasons, any gain or loss as of the termination date is deferred and recorded concurrently with the related energy purchase or sale.

Earnings Per Share—Basic and diluted earnings per share are based on the weighted average number of shares of common stock and potential common stock outstanding during the period, after giving effect to stock splits (see Note 11). Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive stock options, warrants, deferred compensation arrangements, and convertible securities. The effect of such potential common stock is computed using the treasury stock method or if the converted method, as applicable.

Use of Estimates—The preparation of financial statements in conformity with generally accepted accounting principles 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. Significant items subject to such estimates and assumptions include the carrying value of long-lived assets; valuation allowances for receivables, the recoverability of deferred regulatory assets and the valuation of certain financial instruments, deferred tax assets, environmental liabilities and potential litigation claims and settlements (see Note 7).

Reclassifications—Certain reclassifications have been made to prior-period amounts to conform with the 2000 presentation.

The Company has accounted for the following transactions using the purchase method of accounting as of the effective date of each transaction. Accordingly, the purchase price of each transaction has been allocated based upon the estimated fair value of the assets and the liabilities acquired as of the acquisition date, with the excess reflected as excess of cost over net assets acquired.

In June 2000, pursuant to its tender offer for American Depositary Shares ("ADSs"), a subsidiary of the Company purchased for cash approximately 35 million ADSs, each representing 50 shares, of C.A. La Electricidad de Caracas and Corporacion EDC, C.A. (together, "EDC") at $28.50 per ADS. Also in June, pursuant to its tender offer for all outstanding shares of EDC, a subsidiary of the Company purchased approximately 1.1 billion shares of EDC at $0.57 per share. The purchases brought

the Company's ownership interest in EDC to approximately 81%. Subsequently, the Company's total ownership reached approximately 87% due to a stock buyback program initiated by EDC in July. The total purchase price was $1.7 billion of cash. EDC is the largest private integrated utility in Venezuela, covering the capital region of Caracas. It has interests in distribution businesses in Venezuela, as well as El Salvador-together serving over 1 million customers. EDC also provides 2,265 MW of installed capacity through its generation facilities in Venezuela. The purchase price allocation was as follows (in millions):

Purchase price		$	1,700
Less: Stockholders' equity of Grupo EDC
	Capital stock		(508	)
	Paid-in surplus		(245	)
	Retained earnings		(1,353	)
	Treasury stock		323
Adjustment of assets and liabilities to fair value:
	Property and equipment		(1,578	)
	Contractually obligated losses on assets to be sold		185
	Deferred income tax asset		231
	Employee severance plan		157
	Investment in subsidiaries		36
	Elimination of intangible asset — goodwill		7
	Other net assets		25

Excess of fair value of net assets acquired over purchase price— Negative goodwill		$	(1,020	)

Property and equipment was reduced by the excess of the fair value of the net assets acquired over the purchase price. The cost of the acquisition was allocated on the basis of estimated fair value of the assets acquired and liabilities assumed, primarily based upon an independent appraisal. As of December 31, 2000, the severance plan was completed and the workforce was reduced by approximately 2,500 people. All of the costs associated with the plan were recorded during 2000, and all of the cash payments were made in 2000.

In August 2000, a subsidiary of the Company completed the acquisition of a 59% equity interest in a Hidroelectrica Alicura S.A. ("Alicura") in Argentina from Southern Energy, Inc. and its partners. Alicura operates a 1,000 MW peaking hydro facility located in the province of Neuquen, Argentina. The purchase price of approximately $205 million includes the assumption of existing non-recourse debt. In December, a subsidiary of the Company acquired an additional 39% ownership interest in Alicura, 19.5% ownership interests each from the Federal Government of Argentina and the Province of Neuquen, for approximately $9 million. At December 31, 2000, the Company's ownership interest was 98%. The employees of Alicura own the remaining 2%. All of the purchase price was allocated to property, plant and equipment and is being depreciated over the useful life.

In October 2000, a subsidiary of the Company completed the acquisition of Reliant Energy International's 50% interest in El Salvador Energy Holdings, S.A. ("ESEH") which owns three distribution companies in El Salvador. The purchase price for this interest in ESEH was approximately $175 million. The three distribution companies, Compania de Alumbrado Electrico de San Salvador, S.A. de C.V., Empresa Electrica de Oriente, S.A. de C.V. Distribuidora Electrica de Usulutan, S.A. De C.V. serve 3.5 million people, approximately 60 percent of the population of El Salvador, including the capital city of San Salvador. A subsidiary of the Company had previously acquired a 50% interest in ESEH through its acquisition of EDC. Through the purchase of Reliant Energy International's ownership interest, the Company owns a controlling interest in the three distribution companies. The total purchase price for 100% of the interest in ESEH approximated $302 million, of which

approximately $200 millions was allocated to excess of costs over net assets acquired and is being amortized over 40 years.

In December 2000, the Company acquired all of the outstanding shares of KMR Power Corporation ("KMR"), including the buyout of a minority partner in one of KMR's subsidiaries, for approximately $85 million. The acquisition was financed through the issuance of approximately 949,000 shares of AES common stock and cash. KMR owns a controlling interest in two gas-fired power plants located in Cartagena, Colombia: a 100% interest in the 314 MW TermoCandelaria power plant and a 66% interest in the 100 MW Mamonal plant. Approximately $59 of the purchase price was allocated to excess of cost over net assets acquired and is being amortized over 40 years.

In January 1999, a subsidiary of the Company acquired a 49% interest in AES Panama, an entity resulting from the merger of Empresa de Generacion Electrica Chiriqui and Empresa de Generacion Electrica Bayano, two generation companies in Panama with four facilities representing a total of 283 MW. The acquisition was completed for approximately $91 million, including $46 million of non-recourse debt. AES controls the board of directors of AES Panama, and therefore, consolidates it.

In July 1999, a subsidiary of the Company acquired all of the outstanding shares of NewEnergy Ventures, Inc. ("NewEnergy"), a retail energy distribution company, for approximately $90 million plus assumed liabilities of approximately $183 million. NewEnergy provides electric energy to customers in deregulated energy markets in the United States. The acquisition was financed through a combination of cash, debt and approximately 1.7 million shares of AES common stock. Approximately $152 million of the purchase price was allocated to excess of cost over net assets acquired.

In August 1999, a subsidiary of the Company acquired a controlling 51% interest in Eletronet in Brazil for approximately $155 million. The purchase price is to be paid in annual installments through 2002. The remaining 49% is owned by a subsidiary of Centrais Electricas Brasileiras, S.A. ("Eletrobras"), a Brazilian government-owned utility. Eletronet was created in 1998 by the minority owner to construct a national broadband telecommunications network attached to the existing national transmission grid in Brazil. The business activities of Eletronet currently represent construction activities, preparing the network for its intended use. Therefore, no results of operations have been included in the table below for this acquisition.

In August 1999, a subsidiary of the Company completed the acquisition of 50% of Empresa Distribuidora de Electricidad del Este, S.A. ("EDE Este"), for approximately $109 million. EDE Este is the distribution company providing electricity to approximately 400,000 customers in the eastern portion of the Dominican Republic. Approximately $76 million of the acquisition cost represents the excess of cost over net assets acquired and it is being amortized over 40 years. The Company controls the board of directors, and therefore, consolidates EDE Este.

In November 1999, a subsidiary of the Company acquired a controlling interest in Companhia de Geracao de Energia Eletrica Tietê ("Tietê"), a generating company in the State of Sao Paulo, Brazil, with 2,644 MW of capacity comprised of nine hydroelectric generating facilities, for approximately $498 million. AES acquired approximately 62% of the voting stock and approximately 14% of the preferred stock representing approximately 39% of the total capital stock of Tietê. In December 1999, a subsidiary of the Company acquired an additional 10% of the voting stock of Tietê, representing approximately 5% of total capital, for approximately $50 million. The Company owns approximately 71% of voting stock and approximately 44% of total capital.

In November 1999, a subsidiary of the Company completed its acquisition of CILCORP for approximately $886 million in cash. CILCORP is an integrated electric and gas utility based in Central Illinois that combines three coal-fired generation plants producing an aggregate 1,157 MW of capacity and an extensive transmission and distribution network that serves electricity and gas customers. In August 1999, AES received from the Securities and Exchange Commission an exemption from certain

requirements of the Public Utility Holding Company Act of 1935 allowing it to purchase CILCORP while maintaining its existing ownership interest in its Qualifying Facilities, as defined thereunder. The cost of the acquisition was allocated on the basis of estimated fair value of the assets acquired and liabilities assumed. The liabilities assumed in the transaction consisted of $14 million in merger-related personnel costs. Approximately $573 million of the purchase price represent the excess of cost over net assets acquired and is being amortized over 40 years.

The table below presents supplemental unaudited pro forma operating results as if all of the acquisitions had occurred at the beginning of the periods shown (in millions, except per share amounts). The pro forma amounts include certain adjustments, primarily for depreciation and amortization based on the allocated purchase price and additional interest expense:

Years Ended December 31,	2000		1999
Revenues	$	7,246	$	5,309
Income before extraordinary items		674		445
Net income		667		428
Basic earnings per share	$	1.48	$	1.06
Diluted earnings per share	$	1.42	$	1.02

The pro forma results are based upon assumptions and estimates that the Company believes are reasonable. The pro forma results do not purport to be indicative of the results that actually would have been obtained had the acquisitions occurred at the beginning of the periods shown, nor are they intended to be a projection of future results.

The purchase price allocations for EDC, Alicura, ESEH, Nigen (see Note 4) and KMR have been completed on a preliminary basis, subject to adjustments resulting from engineering, environmental, legal and other analyses during the respective allocation periods. The accompanying consolidated financial statements include the operating results of EDC from June 2000, Alicura from August 2000, ESEH from October 2000, KMR from December 2000, AES Panama from January 1999, NewEnergy from July 1999, Eletronet and EDE Este from August 1999, and CILCORP and Tiete from November 1999.

In January 2001, following the expiration on December 28, 2000 of a Chilean tender offer, Inversiones Cachagua Limitada, a Chilean subsidiary of AES, paid cash for 3,466,600,000 shares of common stock of Gener S.A ("Gener"). Also in January 2001, following the expiration on December 29, 2000, of the simultaneous United States offer to exchange all American Depositary Shares of Gener for AES common stock, AES issued shares of common stock in exchange for Gener ADSs tendered pursuant to the United States offer, which, together with the shares acquired in the Chilean offer, resulted in AES's acquisition of approximately 96.5% of the capital stock of Gener. The purchase price for the acquisition of Gener is approximately $1.4 billion plus the assumption of approximately $700 million of non-recourse debt. At December 31, 2000, $848 million of cash had been raised by AES through the issuance of debt and equity for the purchase of Gener. This amount is recorded as restricted cash in short-term investments in the accompanying December 31, 2000 balance sheet.

In April 2000, a subsidiary of the Company announced its intention to launch a tender offer to acquire all outstanding common and preferred shares of Tiete. This transaction must be approved by the local regulatory authority. The acquisition price has not been determined.

Phoenix, Arizona, Las Vegas, Nevada and Southern California. The approval to permit AES to purchase the 56% interest currently held by Edison was denied by the California Public Utility Commission. AES continues to pursue the purchase but there can be no assurance that the Company will be successful in acquiring the ownership interest on the terms determined in the original competitive bid.

In March 2001, the Company acquired IPALCO Enterprises, Inc. ("IPALCO") for approximately $2.15 billion, plus the assumption of $890 million of debt and preferred stock. IPALCO is a utility holding company headquartered in Indianapolis, Indiana, whose primary subsidiary, Indianapolis Power & Light, is an integrated electric utility that owns and operates 3,000 MW of coal-fired generation and provides retail electric service to 433,000 customers in the greater Indianapolis area. Under the terms of the share exchange agreement, each share of IPALCO common stock will be exchanged for 0.463 shares of the Company's common stock.

In May 1999, a subsidiary of the Company acquired the assets of Ecogen Energy (Ecogen), which consists of two gas-fired power stations in Victoria, Australia, for approximately $100 million. The power stations, Yarra and Jeeralang, have a total installed capacity of 966 MW. They provide peaking capacity for the Australian national electricity market.

Also in May 1999, a subsidiary of the Company completed the acquisition of six electric generating stations from New York State Electric and Gas ("NYSEG") for approximately $962 million. Concurrently, the subsidiary sold two of the plants to an unrelated third party for $650 million and simultaneously entered into a leasing arrangement with the unrelated party (see Note 7). These six coal-fired electric generating plants have a total installed capacity of 1,424 MW.

In November 1999, a subsidiary of the Company completed its acquisition of the Drax Power Station ("Drax") for approximately $3 billion. The Drax station is a 3,960 MW coal-fired power station in northern England. The purchase price was paid in cash and was financed with a mixture of non-recourse senior bank lending, subordinated bridge lending and equity provided by AES. In conjunction with this acquisition, the Company assumed $1.3 billion of liabilities of which $1.1 billion relate to deferred income taxes and the remainder consists of the fair value of assumed liabilities.

The Company is a party to joint venture/consortium agreements through which the Company has equity investments in Companhia Energetica de Minas Gerais ("CEMIG"), Light-Servicos de Eletricidade S.A. ("Light") and Eletropaulo Metropolitana Electricidade de Sao Paulo S.A. ("Eletropaulo"). The joint venture/consortium parties generally share operational control of the investee. The agreements prescribe ownership and voting percentages as well as other matters. The

Company records its share of earnings from its equity investees on a pre-tax basis. The Company's share of the investee's income taxes is recorded in income tax expense.

Effective May 1, 2000, the Company disposed of its investment in Northern/AES Energy. The disposition of the investment did not have a material effect on the Company's financial condition or results of operations.

In May 2000, the Company completed the acquisition of 100% of Tractebel Power Ltd ("TPL") for approximately $67 million and assumed liabilities of approximately $200 million. TPL owned 46% of Nigen. The Company also acquired an additional 6% interest in Nigen from minority stockholders during the year ended December 31, 2000 through the issuance of approximately 99,000 common shares of AES stock valued at approximately $4.9 million. With the completion of these transactions, the Company owns approximately 98% of Nigen's common stock and began consolidating its financial results beginning May 12, 2000. Approximately $100 million of the purchase price was allocated to excess of costs over net assets acquired and is being amortized over 23 years.

In May 2000, a subsidiary of the company acquired an additional 5% of the preferred, non-voting shares of Eletropaulo for approximately $90 million. In January 2000, 59% of the preferred non-voting shares were acquired for approximately $1 billion at auction from BNDES, the National Development Bank of Brazil. The price established at auction was approximately $72.18 per 1,000 shares, to be paid in four annual installments commencing with a payment of 18.5% of the total price upon closing of the transaction and installments of 25.9%, 27.1% and 28.5% of the total price to be paid annually thereafter. At December 31, 2000, the Company had a total economic interest of 49.6% and a voting interest of 17.35% in Eletropaulo. The Company accounts for this investment using the equity-method based on the related consortium agreement that allows the exercise of significant influence.

In August 2000, a subsidiary of the Company acquired a 49% interest in Songas Limited for approximately $40 million. Songas Limited owns the Songo Songo Gas-to-Electricity Project in Tanzania. Under the terms of a project management agreement, the Company has assumed overall project management responsibility. The project consists of the refurbishment and operation of five natural gas wells in coastal Tanzania, the construction and operation of a 65 mmscf/day gas processing plant and related facilities, the construction of a 230 km marine and land pipeline from the gas plant to Dar es Salaam and the conversion and upgrading of an existing 112 MW power station in Dar es Salaam to burn natural gas, with an optional additional unit to be constructed at the plant. Since the project is currently under construction, no revenues or expenses have been incurred, and therefore no results are shown in the following table.

In December 2000, a subsidiary of the Company with EDF International S.A. ("EDF") completed the acquisition of an additional 3.5% interest in Light from two subsidiaries of Reliant Energy for approximately $136 million. Pursuant to the acquisition, the Company acquired 30% of the shares while EDF acquired the remainder. With the completion of this transaction, the Company owns approximately 21.14% of Light.

In December 2000, a subsidiary of the Company entered into an agreement with to jointly acquire an additional 9.2% interest in Light, which is held by a subsidiary of Companhia Siderurgica Nacional ("CSN"). Pursuant to this transaction, the Company acquired an additional 2.75% interest in Light for $114.6 million. This transaction closed in January 2001.

Following the purchase of the Light shares previously owned by CSN, AES and EDF will together be the controlling shareholders of Light and Eletropaulo. AES and EDF have agreed that AES will eventually take operational control of Eletropaulo and the telecom businesses of Light and Eletropaulo, while EDF will eventually take operational control of Light and Eletropaulo's electric workshop business. AES and EDF intend to continue to pursue a further rationalization of their ownership stakes in Light and Eletropaulo, the result of which AES would become the sole controlling shareholder of

Eletropaulo and EDF would become the sole controlling shareholder of Light. Upon consummation of the transaction, AES will begin consolidating Eletropaulo's operating results. The structure and process by which this rationalization may be effected, and the resulting timing, have yet to be determined and will likely be subject to approval by various Brazilian regulatory authorities and other third parties. As a result, there can be no assurance that this rationalization will take place.

In May 1999, a subsidiary of the Company acquired subscription rights from the Brazilian state-controlled Eletrobras, which allowed it to purchase preferred, non-voting shares in Light and Eletropaulo. The aggregate purchase price of the subscription rights and the underlying shares in Light and Eletropaulo was approximately $53 million and $77 million, respectively, and represented 3.7% and 4.4% economic ownership interest in their capital stock, respectively.

The following table presents summarized financial information (in millions) for the Company's investments in 50% or less owned investments accounted for using the equity method:

As of and for the Years ended December 31,	2000		1999		1998
Revenues	$	6,241	$	5,960	$	8,091
Operating Income		1,989		1,839		2,079
Net Income		859		62		1,146
Current Assets		2,423		2,259		2,712
Noncurrent Assets		13,080		15,359		19,025
Current Liabilities		3,370		3,637		4,809
Noncurrent Liabilities		5,927		7,536		7,356
Stockholder's Equity		6,206		6,445		9,572

Relevant equity ownership percentages for these investments are presented below:

Affiliate	Country	2000	1999	1998
CEMIG	Brazil	21.62%	21.62%	21.62%
Elsta	Netherlands	50.00	50.00	50.00
Kingston	Canada	50.00	50.00	50.00
Light	Brazil	21.14	17.68	13.75
Eletropaulo	Brazil	49.60	9.90	4.10
Medway Power, Ltd	United Kingdom	25.00	25.00	25.00
Nigen	United Kingdom	—	46.17	46.51
Northern/AES Energy	United States	—	50.00	45.37
OPGC	India	49.00	49.00	n/a
Chigen Affiliates	China	30.00	30.00	30.00
Songas Limited	Tanzania	49.00	n/a	n/a

In 2000 and 1999, the results of operations and the financial position of the Brazilian affiliates, Light, Eletropaulo and CEMIG, were negatively impacted by the devaluation of the Brazilian Real.

The Company's after tax share of undistributed earnings of affiliates included in consolidated retained earnings was $370 million, $96 million, and $139 million at December 31, 2000, 1999 and 1998, respectively. The Company charged and recognized construction revenues, management fee and interest on advances to its affiliates which aggregated $11 million, $21 million, and $19 million for each of the years ended December 31, 2000, 1999, and 1998, respectively.

The short-term investments and debt service reserves and other deposits were invested as follows (in millions):

			December 31,
			2000		1999
Restricted Cash and Cash Equivalents (1)			$	1,718	$	384

Held-to-Maturity:
	U.S. treasury and government agency securities			—		12
	Certificates of deposit			86		—
	Commercial paper			7		91

		Subtotal		93		103

Available-for-Sale:
	Certificates of deposit			1		—
	Commercial paper			—		5

		Subtotal		1		5

Trading:
	Equity securities			2		—

Total			$	1,814	$	492

The Company's investments are classified as held-to-maturity, available-for-sale or trading. The amortized cost and estimated fair value of the held-to-maturity and available-for-sale investments were approximately the same. The trading investments are recorded at fair value.

Short-term investments classified as held-to-maturity and available-for-sale were $93 million and $1 million, respectively, at December 31, 2000, and short-term investments classified as held-to-maturity and available for-sale were $75 million and $5 million, respectively, at December 31, 1999. Short-term investments classified as trading were $2 million and $0, respectively, at December 31, 2000 and 1999. Also included in short-term investments at December 31, 2000 and 1999 was restricted cash of approximately $1.2 billion and $84 million, respectively.

Non-recourse debt—Non-recourse debt at December 31, 2000, and 1999 consisted of the following (in millions):

Non-recourse debt borrowings are primarily collateralized by the capital stock of the relevant subsidiary and in certain cases the physical assets of, and all significant agreements associated with, such business. Such debt is not a direct obligation of the AES parent corporation. These non-recourse financings include structured project financings, acquisition financings, working capital facilities and all other consolidated debt of the subsidiaries. The Company has issued shares of common stock to consolidated subsidiaries as collateral under various borrowing arrangement (see Note 10).

The Company has interest rate swap and forward interest rate swap agreements in an aggregate notional principal amount of $2.4 billion at December 31, 2000. The swap agreements effectively change the variable interest rates on the portion of the debt covered by the notional amounts to weighted average fixed rates ranging from approximately 5.49% to 9.90%. The agreements expire at various dates from 2002 through 2015. In the event of nonperformance by the counterparties, the Company may be exposed to increased interest rates; however, the Company does not anticipate nonperformance by the counterparties, which are multinational financial institutions.

Certain commercial paper borrowings of subsidiaries are supported by letters of credit or lines of credit issued by various financial institutions. In the event of nonperformance or credit deterioration of the institutions, the Company may be exposed to the risk of higher effective interest rates. The Company does not believe that such nonperformance or credit deterioration is likely.

Recourse debt—Recourse debt obligations are direct borrowings of the AES parent corporation and at December 31, 2000 and 1999, consisted of the following (in millions):

In March 2000, the Company entered into an $850 million revolving credit agreement with a syndicate of banks, which provides for a combination of either loans or letters of credit up to the maximum borrowing capacity. Loans under the facility bear interest at either Prime plus a spread of 0.50% or LIBOR plus a spread of 2%. Such spreads are subject to adjustment based on the Company's credit ratings and the term remaining to maturity. This facility replaced the Company's then existing separate $600 million revolving credit facility and $250 million letter of credit facilities. As of December 31, 2000, $365 million was available.

In December 2000, the Company obtained a $600 million bank commitment with the same terms as the $850 million revolving credit agreement. There were no amounts outstanding under this facility at December 31, 2000. The facility was terminated upon issuance of Senior Notes in February 2001 (see Note 19).

Commitment fees on both facilities at December 31, 2000 are .50% per annum. The Company's recourse debt borrowings are unsecured obligations of the Company.

Future Maturities of Debt—Scheduled maturities of total debt at December 31, 2000, are (in millions):

Covenants—The terms of the Company's revolving bank loan, senior and junior subordinated notes, and non-recourse debt agreements contain certain restrictive covenants. The covenants provide for, among other items, maintenance of certain reserves, and require that minimum levels of working capital, net worth, and certain financial ratio tests are met. The most restrictive of these covenants include limitations on incurring additional debt and on the payment of dividends to stockholders.

As of December 31, 2000, approximately $486 million of restricted cash was maintained in accordance with certain covenants of the debt agreements, and these amounts were included within short-term investments and debt service reserves and other deposits in the consolidated balance sheet.

Various lender and governmental provisions restrict the ability of the Company's subsidiaries to transfer retained earnings to the parent company. Such restricted retained earnings amounted to approximately $5 billion at December 31, 2000.

Operating Leases—As of December 31, 2000, the Company was obligated under long-term non-cancelable operating leases, primarily for office rental and site leases. Rental expense for operating leases, excluding amounts related to the sale/leaseback discussed below, was $13 million, $7 million, and $4 million in the years ended December 31, 2000, 1999 and 1998, respectively. The future minimum lease commitments under these leases are $13 million for 2001, $8 million for 2002, $7 million for 2003, $6 million for 2004, $6 million for 2005, and a total of $66 million for the years thereafter.

Sale/Leaseback—In May 1999, a subsidiary of the Company acquired six electric generating stations from NYSEG (See note 3). Concurrently, the subsidiary sold two of the plants to an unrelated third party for $650 million and simultaneously entered into a leasing arrangement with the unrelated party. This transaction has been accounted for as a sale/leaseback with operating lease treatment. Rental expense was $54 million and $26 million in 2000 and 1999, respectively. Future minimum lease commitments are $58 million for 2001, $63 million for 2002, $58 million for 2003, $63 million for 2004, $59 million for 2005 and a total of $1.4 billion for the years thereafter.

In connection with the lease of the two power plants, the subsidiary is required to maintain a rent reserve account equal to the maximum semi-annual payment with respect to the sum of the basic rent and fixed charges expected to become due in the immediately succeeding three-year period. At December 31, 2000 and 1999, the amount deposited in the rent reserve account approximated $31 million and $30 million, respectively. This amount is included in restricted cash and can only be utilized to satisfy lease obligations.

The agreements governing the leases restrict the subsidiary's ability to incur additional indebtedness, sell its assets or merge with another entity. The ability of the subsidiary to make distributions is restricted unless certain covenants, including the maintenance of certain coverage ratios, are met. The subsidiary is also required to maintain an additional liquidity account initially equal to $65 million less the balance of the rent reserve account. A letter of credit from a bank for $36 million has been obtained to satisfy this requirement.

Contracts—Operating subsidiaries of the Company have entered into "take-or-pay" contracts for the purchase of electricity from third parties. Purchases in 2000 were approximately $189 million. The future commitments under these contracts are $244 million for 2001, $226 million for 2002, $205 million for 2003, $167 million for 2004, $144 million for 2005 and a total of $840 million for the years thereafter.

Operating subsidiaries of the Company have entered into various long-term contracts for the purchase of fuel subject to termination only in certain limited circumstances. Purchases in 2000 were approximately $546 million. The future commitments under contracts are $646 million for 2001, $354 million for 2002, $506 million for 2003, $455 million for 2004, $349 million for 2005, and $1.18 billion thereafter.

In connection with the acquisition of the assets of Ecogen in May 1999, a subsidiary of the Company assumed contingent liabilities related to the plants' performance. If plant availability and contract performance specifications are not met, then a subsidiary of the Company may be required to

make payments of up to $141 million to a third party under the terms of an electricity price hedge agreement.

Several of the Company's power plants rely on power sales contracts with one or a limited number of entities for the majority of, and in some cases all of, the relevant plant's output over the term of the power sales contract. The remaining term of power sales contracts related to the Company's power plants range from 5 to 29 years. However, the operations of such plants are dependent on the continued performance by customers and suppliers of their obligations under the relevant power sales contract, and, in particular, on the credit quality of the purchasers. If a substantial portion of the Company's long-term power sales contract were modified or terminated, the Company would be adversely affected to the extent that it was unable to find other customers at the same level of contract profitability. Some of the Company's long-term power sales agreements are for prices above current spot market prices. The loss of one or more significant power sales contracts or the failure by any of the parties to a power sales contract to fulfill its obligations thereunder could have a material adverse impact on the Company's business, results of operations and financial condition.

During 2000, the wholesale electricity market in California experienced a significant imbalance in the supply of, and demand for electricity, which resulted in significant electricity price increases and volatility. California's two largest utilities are required to purchase wholesale power and to sell it at fixed prices to retail end users. Because the cost of wholesale power has exceeded the price the utilities can charge their retail customers, these utilities are facing severe financial difficulties. There can be no assurances that such utilities can, or will choose to, honor their financial commitments. In the event that such utilities become insolvent or otherwise choose not to honor their commitments, creditors (including certain of the Company's subsidiaries) may seek to exercise whatever remedies may be available, including, among other things, placing the utilities into involuntary bankruptcy. There can be no assurances that amounts owing directly or indirectly from such utilities will be recovered. In addition, the California Independent System Operator has sought a Temporary Restraining Order over some of the generators, including AES subsidiaries, arguing that, in times of declared emergencies, generators are required to continue to provide electricity to the market even if there is no credit-worthy purchaser for the electricity. The bulk of the Company's revenues in California are not subject to this credit risk, because they are generated under the tolling agreement entered into by AES Southland. But the Company's other subsidiaries have some exposure to this risk. At December 31, 2000 the Company had receivables of approximately $27 million that are subject to this credit risk. In addition, because these utilities have defaulted on amounts due in the state sanctioned markets, the markets have sought to recover those amounts pro rata from other market participants, including certain of the Company's subsidiaries.

Environmental—As of December 31, 2000, the Company has recorded cumulative liabilities associated with acquired generation plants of approximately $37 million for projected environmental remediation costs. During 2000, the Company incurred a $17 million environmental fine and will be required to incur capital expenditures related to excess nitrogen oxide air emissions at certain of its generating facilities in California.

In May 2000, the New York State Department of Environmental Conservation ("DEC") issued a Notice of Violation ("NOV") to NYSEG for violations of the Federal Clean Air Act and the New York Environmental Conservation Law at the Greenidge and Westover plants related to NYSEG's alleged failure to undergo an air permitting review prior to making repairs and improvements during the 1980s and 1990s. Pursuant to the agreement relating to the acquisition of the plants from NYSEG, AES Eastern Energy agreed with NYSEG that AES Eastern Energy will assume responsibility for the NOV, subject to a reservation of AES Eastern Energy's right to assert any applicable exception to its contractual undertaking to assume pre-existing environmental liabilities. The Company believes it has meritorious defenses to any actions asserted against it and expects to vigorously defend itself against the allegations; however, the NOV issued by the DEC, and any additional enforcement actions that

might be brought by the New York State Attorney General, the DEC or the EPA, against the Somerset, Cayuga, Greenidge or Westover plants, might result in the imposition of penalties and might require further emission reductions at those plants.

The U.S. Environmental Protection Agency ("EPA") has commenced an industry-wide investigation of coal-fired electric power generators to determine compliance with environmental requirements under the Federal Clean Air Act associated with repairs, maintenance, modifications and operational changes made to the facilities over the years. The EPA's focus is on whether the changes were subject to new source review or new performance standards, and whether best available control technology was or should have been used. On August 4, 1999, the EPA issued a NOV to the Company's Beaver Valley plant, generally alleging that the facility failed to obtain the necessary permits in connection with certain changes made to the facility in the mid-to-late 1980s. The Company believes it has meritorious defenses to any actions asserted against it and expects to vigorously defend itself against the allegations.

The Company's generating plants are subject to emission regulations. The regulations may result in increased operating costs or the purchase of additional pollution control equipment if emission levels are exceeded.

The Company reviews its obligations as it relates to compliance with environmental laws, including site restoration and remediation. Because of the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Based on currently available information, the Company does not believe that any costs incurred in excess of those currently accrued will have a material effect on the financial condition and results of operations of the Company.

Derivatives—Certain subsidiaries and an affiliate of the Company enter into interest rate, foreign currency, electricity and gas derivative contracts with various counterparties, and as a result, the Company is exposed to the risk of nonperformance by it's counterparties. The Company does not anticipate nonperformance by the counterparties.

The Company is exposed to market risks on derivative contracts and on other unmatched commitments to purchase and sell energy on a price and quantity basis. Such market risks are monitored to limit the Company's exposure.

Guarantees—In connection with certain of its project financing, acquisition, and power purchase agreements, AES has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. These obligations and commitments, excluding those collateralized by letter-of-credit obligations discussed below, were limited as of December 31, 2000, by the terms of the agreements, to an aggregate of approximately $659 million. The Company is also obligated under other commitments, which are limited to amounts, or percentages of amounts, received by AES as distributions from its project subsidiaries. These amounts aggregated $71 million as of December 31, 2000. In addition, the Company has commitments to fund its equity in projects currently under development or in construction. At December 31, 2000, such commitments to invest amounted to approximately $111 million.

Letters of Credit—At December 31, 2000, the Company had $603 million in letters of credit outstanding, which operate to guarantee performance relating to certain project development activities and subsidiary operations. The Company pays a letter-of-credit fee ranging from 0.50% to 2.0% per annum on the outstanding amounts. In addition, the Company had $134 million and a subsidiary of the Company had $220 million in surety bonds outstanding at December 31, 2000.

Litigation—In September 1999, an appellate judge in the Minas Gerais, Brazil state court system granted a temporary injunction that suspends the effectiveness of a shareholders' agreement for CEMIG. This appellate ruling suspends the shareholders' agreement while the action to determine the validity of the shareholders' agreement is litigated in the lower court. In early November 1999, the

same appellate court judge reversed this decision and reinstated the effectiveness of the shareholders' agreement, but did not restore the super majority voting rights that benefited the Company. In March 2000, a state court in Minas Gerais again ruled that the shareholders' agreement was invalid. The Company has appealed this decision. AES must exhaust all state-level appeals before the matter is heard before the Brazilian federal court. The Company intends to vigorously pursue its legal rights in this matter and to restore all of its rights regarding CEMIG, and does not anticipate that this temporary suspension of the shareholders' agreement will have a significant effect on its financial condition or results of operations. Failure to prevail in this matter would limit the Company's influence on the daily operations of CEMIG. However, the Company would still own approximately 21.6% of the voting common stock of CEMIG.

In November 2000, the Company was named in a purported class action suit along with six other defendants alleging unlawful manipulation of the California wholesale electricity market, resulting in inflated wholesale electricity prices throughout California. Alleged causes of action include violation of the Cartwright Act, the California Unfair Trade Practices Act and the California Consumers Legal Remedies Act. In December 2000, the case was removed from the San Diego County Superior Court to the U.S. District Court for the Southern District of California. The Company believes it has meritorious defenses to any actions asserted against it and expects that it will defend itself vigorously against the allegations.

In addition, the crisis in the California wholesale power markets has directly or indirectly resulted in several administrative and legal actions involving the Company's businesses in California. Each of the Company's businesses in California (AES Southland, AES Placerita and AES New Energy) are subject to overlapping state investigations by the California Attorney General's Office, the Market Oversight and Monitoring Committee of the California Independent System Operator ("ISO"), and the California Public Utility Commission. Each of these investigations are currently in the document gathering stage, and the businesses have responded to multiple requests for the production of documents and data surrounding the operation and bidding behavior of the plants.

In August 2000, the Federal Energy Regulatory Commission ("FERC") announced an investigation into the national wholesale power markets, with particular emphasis upon the California wholesale electricity market, in order to determine whether there has been anti-competitive activity by wholesale generators and marketers of electricity. The FERC has requested documents from each of the AES Southland plants. Similar to the state investigation, the FERC investigation has focused their attention to date upon the forced and planned maintenance outages taken by the plants in 2000.

AES Drax Inc. ("AES Drax") is currently in arbitration proceedings involving a financial hedge agreement entered into with a subsidiary of Texas Utilities, Inc. ("TXU"), in which TXU pays to AES Drax capacity and variable payments and in turn receives the Pool Purchase Price in respect of the volume of MWs that they request to be delivered. The Pool is due to be replaced by the New Energy Trading Arrangements ("NETA") shortly, and therefore the Pool Purchase Price will no longer be available. AES believes that the hedging agreement contemplates this transition by providing a mechanism for converting the agreement so that it can function for its full 15-year term. TXU disagrees with this position. In December 2000, AES Drax commenced an arbitration seeking an Expert Determination regarding what changes to the agreement must be made to reflect the introduction of NETA. AES believes that the expert panel is empowered to determine such changes, and only such changes, to preserve the commercial intent of the agreement (which is defined in the agreement), but TXU has requested the panel to terminate the hedging agreement. The Company believes that it has meritorious defenses, and expects to vigorously pursue its interest. AES Drax and TXU suspended the arbitration and negotiated mutually acceptable changes to the hedging agreement. AES Drax is required to obtain the approval of its project lenders for such amendment and is currently negotiating a waiver and approval of the amendment from its project lenders.

Risks Related to Regulated and Foreign Operations—AES operates businesses in many regulated and foreign environments. There are certain economic, political, technological and regulatory risks associated with operating in these environments. Investments in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. During 2000 and 1999, the Company's financial position and results of operations were adversely affected by a significant devaluation of the Brazilian Real relative to the U.S. Dollar.

The distribution businesses, which the Company owns or has investments in are subject to regulatory review or approval which could limit electricity tariff rates charged to customers or require the return of amounts previously collected. These regulatory environments are also subject to change, which could impact the results of operations.

In certain locations, particularly developing countries or countries that are in a transition from centrally planned to market-oriented economies, the electricity purchasers, both wholesale and retail, may be unable or unwilling to honor their payment obligations. Collection of receivables may be hindered in these countries due to ineffective systems for adjudicating contract disputes.

In June 1999, a subsidiary of the Company assumed long-term managerial and voting control of two regional electric distribution companies ("RECs") in Kazakhstan as part of a settlement of receivables outstanding from the government of Kazakhstan. The Company's claim against the government was for electricity previously provided. The contractual rights to control the operations of the RECs received in this transaction were valued at approximately $26 million, based on the net present value of incremental cash flows expected to be received as a result of operating the RECs. The value of the contract rights was recorded in the statement of operations in 1999. The two distribution businesses serve approximately 1.8 million people. The Company expects that the government of Kazakhstan will abide by the terms and periods agreed to in the original memorandum of understanding that currently governs the Company's operating control of the RECs. However, the contract is subject to economic, political and regulatory risks associated with operating in Kazakhstan. The Company does not consolidate the RECs because it operates them under a management agreement and does not have a controlling ownership interest in them.

Leveraged Lease Investments—One of the Company's subsidiaries has investments in leveraged leases totaling $141 million. Related deferred tax liabilities total $106 million. The investment includes estimated residual values totaling $88 million. Leveraged lease residual value assumptions are adjusted on a periodic basis, based on independent appraisals.

8. Company-Obligated Convertible Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

During 1997, two wholly owned special purpose business trusts (AES Trust I and AES Trust II) issued Term Convertible Preferred Securities (Tecons). On March 31, 1997, AES Trust I issued 5 million of $2.6875 Tecons (liquidation value $50) for total proceeds of $250 million and concurrently purchased $250 million of 5.375% junior subordinated convertible debentures due 2027 of AES (individually the 5.375% Debentures). On October 29, 1997, AES Trust II issued 6 million of $2.75 Tecons (liquidation value $50) for total proceeds of $300 million and concurrently purchased $300 million of 5.5% junior subordinated convertible debentures due 2012 of AES (individually the 5.5% Debentures). During 2000, the Company called for redemption of AES Trust I and AES Trust II. Substantially all of AES Trust I Tecons were converted into approximately 14 million shares of AES common stock and substantially all of AES Trust II Tecons were converted into approximately 11 million shares of AES common stock.

During 1999, AES Trust III, a wholly owned special purpose business trust, issued 9 million of $3.375 Tecons (liquidation value $50) for total proceeds of approximately $518 million and concurrently purchased approximately $518 million of 6.75% junior subordinated convertible debentures due 2029 (individually, the 6.75% Debentures).

During 2000, AES Trust VII, a wholly owned special purpose business trust, issued 9.2 million of $3.00 Tecons (liquidation value $50) for total proceeds of approximately $460 million and concurrently purchased approximately $460 million of 6% junior subordinated convertible debentures due 2008 (individually, the 6% Debentures and collectively with the 6.75% Debentures, the Junior Subordinated Debentures). The sole assets of AES Trust III and VII (collectively, the Tecon Trusts) are the Junior Subordinated Debentures.

AES, at its option, can redeem the 6.75% Debentures after October 17, 2002, which would result in the required redemption of the Tecons issued by AES Trust III, for $52.10 per Tecon, reduced annually by $0.422 to a minimum of $50 per Tecon, and can redeem the 6% Debentures after May 18, 2003, which would result in the required redemption of the Tecons issued by AES Trust VII, for $51.88 per Tecons, reduced annually by $0.375 to a minimum of $50 per Tecon. The Tecons must be redeemed upon maturity of the Junior Subordinated Debentures.

The Tecons are convertible into the common stock of AES at each holder's option prior to October 15, 2029 for AES Trust III and May 14, 2008 for AES Trust VII at the rate of 1.4216 and 1.0811, respectively, representing a conversion price of $35.171 and $46.25 per share, respectively.

On November 30, 1999, three wholly owned special purpose business trusts (individually, AES RHINOS Trust I, II, and III, collectively, the Rhinos Trusts and with the Tecon Trusts, collectively the Trusts) issued trust preferred securities (Rhinos). The aggregate amount of Rhinos issued was approximately $250 million. Concurrent with the issuance of the Rhinos, the Rhinos Trusts purchased approximately $258 million of junior subordinated convertible notes due 2007. The Rhinos Trusts may be dissolved and the notes distributed to the holders of the Rhinos at any time at the Company's option. The obligations of the Trusts are fully and unconditionally guaranteed by AES.

Under the terms of a remarketing agreement, the initial purchaser of the Rhinos has the right to cause a remarketing of the Rhinos if they remain outstanding on November 30, 2002, or if certain other conditions are met.

In connection with the issuance of the Rhinos and related notes, the Company has entered into a forward underwriting agreement for the future placement of approximately $250 million of the Company's common stock, preferred stock, notes or trust preferred securities.

Prior to a successful remarketing, the Rhinos are redeemable at par in whole at any time or in part from the proceeds of a qualifying offering under the forward underwriting commitment. The holder can require redemption only at maturity (November 15, 2007).

Prior to February 28, 2003, the Rhinos are not convertible. On and after February 28, 2003, the Rhinos are convertible at any time at the option of the holder into the common stock of AES. The conversion price of the Rhinos depends on whether or not the Trusts have completed a successful remarketing of the Rhinos. Prior to a successful remarketing, the conversion price is equal to the then current market price of the Company's common stock. After a successful remarketing, the conversion price will be equal to the price specified in the winning remarketing bid which cannot be less than the current market price of AES common stock at the time of remarketing.

Dividends on the Tecons and Rhinos are payable quarterly at an annual rate of 6.75% by AES Trust III, 6% by AES Trust VII and LIBOR plus 2.50% by the Rhinos Trusts. Dividend rates for the Rhinos are subject to increase upon a failed remarketing of the Rhinos. The Trusts are each permitted to defer payment of dividends for up to 20 consecutive quarters, provided that the Company has

exercised its right to defer interest payments under the corresponding debentures or notes. During such deferral periods, dividends on the Tecons and Rhinos will accumulate quarterly and accrue interest and the Company may not declare or pay dividends on its common stock.

Interest expense for each of the years ended December 31, 2000, 1999 and 1998, includes approximately $71 million, $38 million and $31 million for 2000, 1999 and 1998, respectively, related to the Tecon Trusts and approximately $21 million and $2 million for 2000 and 1999, respectively, related to the Rhinos Trusts.

Minority interest includes $41 million and $66 million of cumulative preferred stock of a subsidiary at December 31, 2000 and 1999, respectively. During 2000 a subsidiary of the Company retired $25 million of its cumulative preferred stock at par value. The total annual dividend requirement was approximately $2 million at December 31, 2000. $22 million of the preferred stock is subject to mandatory redemption requirements over the period 2003-2008.

Sale of Stock—In May 2000, the Company sold 24.725 million shares of common stock at $37.00 per share. Net proceeds from the offering were $886 million. In November 2000, the Company sold 10 million shares of common stock at $52.50 per share. Net proceeds from the offering were $520 million.

Stock Split and Stock Dividend—On April 17, 2000, the Board of Directors authorized a two-for-one stock split, effected in the form of a stock dividend, payable to stockholders of record on May 1, 2000. Accordingly, all outstanding share, per share and stock option data in all periods presented have been restated to reflect the stock split.

Shares Issued for Acquisitions—During December 2000, the Company issued approximately 949,000 shares, valued at $51 million to fund the acquisition of KMR. Also, during 2000, the Company issued approximately 343,000 shares, valued at $16 million in various other acquisitions.

Stock Options—The Company has granted options to purchase shares of common stock under its stock option plans. Under the terms of the plans, the Company may issue options to purchase shares of the Company's common stock at a price equal to 100% of the market price at the date the option is granted. The options become eligible for exercise under various schedules. At December 31, 2000, there were approximately 1.5 million shares reserved for future grants under the plans.

Additional stock options for 2000 performance were approved in January 2001. The Company will issue all remaining authorized stock options to purchase shares at a price of $55.61 per share. The

Company intends to issue additional options for 2000 performance upon shareholder approval of a new stock option plan.

The following table summarizes information about stock options outstanding at December 31, 2000 (in thousands of shares):

The Company accounts for its stock-based compensation plans under Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, and has adopted SFAS No. 123, Accounting for Stock-Based Compensation, for disclosure purposes. No compensation expense has been recognized in connection with the options, as all options have been granted only to AES people, including Directors, with an exercise price equal to the market price of the Company's common stock on the date of grant. For SFAS No. 123 disclosure purposes, the weighted average fair value of each option grant has been estimated as of the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions:

	For The Years Ended
	2000	1999	1998
Interest rate (risk-free)	5.1%	6.5%	4.7%
Volatility	48%	46%	47%

Using these assumptions, an expected option life of approximately 7 years and a dividend yield of zero, the weighted average fair value of each stock option granted was $22.65, $22.97 and $19.02, for the years ended December 31, 2000, 1999 and 1998, respectively.

Had compensation expense been determined under the provisions of SFAS No. 123, utilizing the assumptions detailed in the preceding paragraph, the Company's net income and earnings per share for the years ended December 31, 2000, 1999 and 1998 would have been reduced to the following pro forma amounts (in millions except per share amounts):

		For The Years Ended December 31,
		2000		1999		1998
Net Income:
	As reported	$	641	$	228	$	311
	Pro forma		602		213		301
Basic Earnings Per Share:
	As reported	$	1.45	$	0.60	$	0.88
	Pro forma		1.36		0.56		0.85
Diluted Earnings Per Share:
	As reported	$	1.40	$	0.58	$	0.85
	Pro forma		1.31		0.54		0.82

The disclosures of such amounts and assumptions are not intended to forecast any possible future appreciation of the Company's stock or change in dividend policy.

As of December 31, 1999, the Company had warrants outstanding to purchase up to 2.6 million shares of common stock at $7.36 a share. These warrants expired in July 2000. Substantially all of the warrants were exercised prior to expiration.

Common Stock held by Subsidiaries—As of December 31, 2000, approximately 81 million shares of the Company's common stock had been issued to consolidated subsidiaries. These shares were issued as collateral under various borrowing agreements and are not considered outstanding. They have been excluded from the calculation of earnings per share.

The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for income before extraordinary item. In the table below, Income represents the numerator (in millions) and Shares represent the denominator (in millions) after giving effect to the two-for-one stock split:

In October 1999, AES Placerita Inc. ("Placerita"), a wholly owned subsidiary of the Company, received proceeds of approximately $110 million to complete the buyout of its long-term power sales agreement. In connection with the buyout, the Company incurred transaction related costs of approximately $19 million and recorded a gain on contract buyout of $91 million. The buyout of the power sales agreement resulted in the loss of a significant customer and required the Company to assess the recoverability of the carrying amount of Placerita's electric generation assets. The Company recorded an impairment loss of approximately $62 million to reduce the carrying value of the electric generation assets to their estimated fair value after termination of the contract. The estimated fair value was determined by an independent appraisal. Concurrent with the buyout of the power sales contract, the Company extinguished certain liabilities under the related project financing debt prior to their scheduled maturity. As a result, the Company has recorded an extraordinary loss of approximately $11 million, net of income tax of approximately $5 million.

In September 1999, AES Thames Inc. ("Thames"), a wholly owned subsidiary of the Company, amended its power sales agreement with Connecticut Light and Power ("CL&P"), its sole customer. The amendment, which was subject to regulatory approval, includes a partial prepayment for certain electricity to be delivered by Thames to CL&P in the years 2001-2014. According to the terms of the amendment, the Company will receive $532 million plus accrued interest in return for a reduction in future electricity rates. Interest accrues on the prepayment at a rate of 8.3% per annum from the date of regulatory approval. In March 2000, the Connecticut Department of Public Utility Control ("DPUC") approved the amendment to the power sales agreement. In July 2000, CL&P requested and subsequently received approval from the DPUC to issue bonds to fund the prepayment. Payment is

expected to be received during 2001. The contractual receivable is recorded in other current assets with a corresponding amount of deferred revenue in other liabilities in the accompanying December 31, 2000 balance sheet. The deferred revenue will be amortized into income on a ratable basis over the contract term based on kilowatt hours provided.

Income Tax Provision—The provision for income taxes consists of the following (in millions):

		For The Years Ended
		2000			1999			1998
Federal:
	Current	$	—		$	11		$	(9	)
	Deferred		14			36			61
State:
	Current		(1	)		3			3
	Deferred		2			11			(5	)
Foreign:
	Current		208			98			82
	Deferred		29			(48	)		13

Total		$	252		$	111		$	145

The Company records its share of earnings of its equity investees on a pre-tax basis. The Company's share of the investees' income taxes is recorded in income tax expense.

Effective and Statutory Rate Reconciliation—A reconciliation of the U.S. statutory Federal income tax rate to the Company's effective tax rate as a percentage of income before taxes (after minority interest) is as follows:

	For The Years Ended
	2000		1999		1998
Statutory Federal tax rate	35	%	35	%	35	%
State taxes, net of Federal tax benefit	—		4		(1	)
Taxes on foreign earnings	(3	)	(6	)	(1	)
Other—net	(4	)	(2	)	(1	)

Effective tax rate	28	%	31	%	32	%

Deferred Income Taxes—Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, and (b) operating loss and tax credit carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered.

As of December 31, 2000, the Company had Federal net operating loss carryforwards for tax purposes of approximately $192 million expiring from 2008 through 2020, Federal general business tax credit carryforwards for tax purposes of approximately $51 million expiring in years 2001 through 2020, and Federal alternative minimum tax credits of approximately $53 million that carryforward without expiration. As of December 31, 2000, the Company had foreign net operating loss carryforwards of approximately $740 million that expire at various times beginning in 2001, and some of which carryforward without expiration, and foreign investment and assets tax credits of approximately $51 million that expire at various times beginning in 2001 through 2005. The Company had state net operating loss carryforwards as of December 31, 2000, of approximately $374 million expiring in years

2000 through 2020, and state tax credit carryforwards of approximately $7 million expiring in years 2001 through 2009.

The valuation allowance increased by $77 million during 2000 to $119 million on December 31, 2000. This increase was the result of certain foreign net operating loss carryforwards and Federal and state tax credits, the ultimate realization of which is not known at this time. The Company believes that it is more likely than not that the remaining deferred tax assets as shown below will be realized.

Undistributed earnings of certain foreign subsidiaries and affiliates aggregated approximately $777 million at December 31, 2000. The Company considers these earnings to be indefinitely reinvested outside of the United States and, accordingly, no U.S. deferred taxes have been recorded with respect to such earnings. Should the earnings be remitted as dividends, the Company may be subject to additional U.S. taxes, net of allowable foreign tax credits. It is not practicable to estimate the amount of any additional taxes which may be payable on the undistributed earnings. A deferred tax asset of $155 million has been recorded as of December 31, 2000 for the cumulative effects of certain foreign currency translation losses.

Income from operations in certain countries is subject to reduced tax rates as a result of satisfying specific commitments regarding employment and capital investment. The reduced tax rates for these operations will be in effect for the life of the related businesses, at the end of which ownership transfers back to the local government. The income tax benefit related to the tax status of these operations are estimated to be $29 million, $27 million and $31 million for the year ended December 31, 2000, 1999 and 1998, respectively.

Income from continuing operations before income taxes and extraordinary items consisted of the following:

	For The Years Ended
	2000		1999		1998
U.S.	$	332	$	164	$	211
Non U.S.		568		192		241

Total	$	900	$	356	$	452

Profit Sharing and Stock Ownership Plans—The Company sponsors two profit sharing and stock ownership plans, qualified under section 401 of the Internal Revenue Code, which are available to

eligible AES people. The plans provide for Company matching contributions, other Company contributions at the discretion of the Compensation Committee of the Board of Directors, and discretionary tax deferred contributions from the participants. Participants are fully vested in their own contributions and the Company's matching contributions. Participants vest in other Company contributions over a five-year period ending on the 5^th anniversary of their hire date. Company contributions to the plans were approximately $11 million, $7 million and $5 million for the years ended December 31, 2000, 1999 and 1998.

Deferred Compensation Plans—The Company sponsors a deferred compensation plan under which directors of the Company may elect to have a portion, or all, of their compensation deferred. The amounts allocated to each participant's deferred compensation account may be converted into common stock units. Upon termination or death of a participant, the Company is required to distribute, under various methods, cash or the number of shares of common stock accumulated within the participant's deferred compensation account. Distribution of stock is to be made from common stock held in treasury or from authorized but previously unissued shares. The plan terminates and full distribution is required to be made to all participants upon any change of control of the Company (as defined in the plan document). No stock associated with distributions was issued during 2000 under such plan.

In addition, the Company sponsors an executive officers' deferred compensation plan. At the election of an executive officer, the Company will establish an unfunded, nonqualified compensation arrangement for each officer who chooses to terminate participation in the Company's profit sharing and employee stock ownership plans. The participant may elect to forego payment of any portion of his or her compensation and have an equal amount allocated to a contribution account. In addition, the Company will credit the participant's account with an amount equal to the Company's contributions (both matching and profit sharing) that would have been made on such officer's behalf if he or she had been a participant in the profit sharing plan. The participant may elect to have all or a portion of the Company's contributions converted into stock units. Dividends paid on common stock are allocated to the participant's account in the form of stock units. The participant's account balances are distributable upon termination of employment or death.

The Company also sponsors a supplemental retirement plan covering certain highly compensated AES people. The plan provides incremental profit sharing and matching contributions to participants that would have been paid to their accounts in the Company's profit sharing plan if it were not for limitations imposed by income tax regulations. All contributions to the plan are vested in the manner provided in the Company's profit sharing plan, and once vested are nonforfeitable. The participant's account balances are distributable upon termination of employment or death.

Defined Benefit Plans—Certain of the Company's subsidiaries have defined benefit pension plans covering substantially all of their respective employees. Pension benefits are based on years of credited service, age of the participant and average earnings.

Significant weighted average assumptions used in the calculation of pension and other postretirement benefits expense and obligation are as follows:

	Pension Benefits
Years Ended December 31,	2000	1999
Discount rates	7%	8%
Rates of compensation increase	3%	4%
Expected long-term rate of return on plan assets	9%	9%

Net benefit cost for the years ended December 31, 2000 and 1999 includes the following components (in millions):

	Pension Benefits
Years Ended December 31,	2000		1999
Service cost	$	8	$	4
Interest cost on projected benefit obligation		34		10
Expected return on plan assets		36		9

Net benefit cost	$	78	$	23

The changes in the benefit obligation of the plans combined for the years ended December 31, 2000 and 1999 are as follows (in millions):

	Pension Benefits
	2000			1999
Change in Benefit Obligation:
Benefit obligation at beginning of year	$	373		$	80
Effect of foreign currency exchange rate change on beginning balance		(10	)		(21	)
Service cost		8			4
Interest cost		34			10
Assumed in acquisitions		71			317
Other		(8	)		(17	)

Benefit obligation as of December 31	$	468		$	373

The changes in the plan assets of the plans combined for the years ended December 31, 2000 and 1999 are as follows (in millions):

	Pension Benefits
	2000			1999
Change in Plan Assets:
Fair value of plan assets at beginning of year	$	403		$	33
Effect of foreign currency exchange rate change on beginning balance		(6	)		(9	)
Actual return on plan assets		(3	)		58
Assumed in acquisitions		—			326
Other		(21	)		(5	)

Fair value of plan assets as of December 31	$	373		$	403

The funded status of the plans combined for the years ended as of December 31, 2000 and 1999 are as follows (in millions):

	Pension Benefits
	2000			1999
Funded status	$	(95	)	$	30
Unrecognized net actuarial (gain) loss		(20	)		(50	)

Accrued benefit (prepaid) cost as of December 31	$	(115	)	$	(20	)

All of the Company's pension plans have been aggregated in the table above. Certain of the Company's plans at December 31, 2000, had benefit obligations exceeding the fair value of the related

plan's assets. As of December 31, 2000, the Company had plans with benefit obligations exceeding the fair value of plan assets by approximately $135 million.

The Company operates in two business segments: generation and distribution. Generation consists of the operation of electric power plants and sales of electricity to nonaffiliated wholesale customers for further resale to end-users. Distribution consists of electricity sales to end-users. Generation and distribution are strategic business areas pursued by the Company. Although the nature of the product is the same, segments are differentiated by the nature of the customers and the operational differences. Within the Company's organizational structure, the business units within each segment are individually managed. Resources are allocated to each segment based on the performance of the business units and the projects within each segment.

The accounting policies of the two business segments are the same as those described in Note 1—General and Summary of Significant Accounting Policies. The Company uses gross margin to evaluate the performance of generation and distribution businesses that it controls and consolidates. Depreciation and amortization at the generation and distribution businesses are included in the calculation of gross margin. Corporate depreciation and amortization is reported within selling, general and administrative expenses in the consolidated statements of operations. Pre-tax equity in earnings is used to evaluate the performance of generation and distribution businesses that are significantly influenced by the Company. Sales between generation and distribution are accounted for at fair value as if the sales were to third parties. All intersegment activity has been eliminated with respect to revenue and gross margin. Information about the Company's operations and assets by segment is as follows (in millions):

Revenues are recorded in the country in which they are earned and assets are recorded in the country in which they are located. Information about the Company's operations and long-lived assets by country are as follows (in millions):

The fair value of current financial assets, current financial liabilities, and debt service reserves and other deposits, are estimated to be equal to their reported carrying amounts. The fair value of non-recourse debt, excluding capital leases, is estimated differently based upon the type of loan. For variable rate loans, carrying value approximates fair value. For fixed rate loans and preferred stock with mandatory redemption, other than securities registered and publicly traded, the fair value is estimated using discounted cash flow analyses based on the Company's current incremental borrowing rates. The fair value of interest rate swap, cap and floor agreements, foreign currency forwards and swaps, and energy derivatives is the estimated net amount that the Company would receive or pay to terminate the agreements as of the balance sheet date. The estimated fair values for certain of the notes and bonds included in non-recourse debt, and certain of the recourse debt and Tecons, which are registered and publicly traded, are based on quoted market prices. The carrying value of Rhinos approximates fair value as they include a rate adjustment feature that is linked to the interbank market for credit.

The estimated fair values of the Company's assets and liabilities have been determined using available market information. The estimates are not necessarily indicative of the amounts the Company could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

The estimated fair values of the Company's debt and derivative financial instruments as of December 31, 2000 and 1999, are as follows (in millions):

The fair value estimates presented herein are based on pertinent information as of December 31, 2000 and 1999. The Company is not aware of any factors that would significantly affect the estimated fair value amounts since December 31, 2000.

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. SFAS No. 133 requires that an entity recognize all derivatives (including derivatives embedded in other contracts) as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the derivative's fair value are to be recognized currently in earnings, unless specific hedge accounting criteria are met. Hedge accounting allows a derivative's gains or losses in fair value to offset related results of the hedged item in the statement of operations and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Prior to the adoption of SFAS No. 133, derivatives that are classified as other than trading are accounted for using settlement accounting, and any gain or loss is included in interest cost.

SFAS No. 133 allows hedge accounting for fair value and cash flow hedges. SFAS No. 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair value hedge as well as the offsetting gain or loss on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge be reported as a component of other comprehensive income in stockholders' equity and be reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The remaining gain or loss on the derivative, if any, must be recognized currently in earnings.

The Company utilizes derivative financial instruments to manage interest rate risk, foreign exchange risk and commodity price risk. The Company utilizes interest rate swap, cap, and floor agreements, to manage interest rate risk on floating rate debt. Currency forward and swap agreements are utilized to manage foreign exchange rate risk which is a result of AES or one of its subsidiaries entering into monetary obligations in currencies other than its own functional currency. The Company utilizes electric and gas derivative instruments, including swaps, options, forwards and futures, to manage the risk related to electricity and gas sales and purchases.

The Company believes its electricity purchase contracts that meet the definition of a derivative under SFAS No. 133, but are settled by physical delivery, qualify for the normal purchases and sales exception and thus are not required to be accounted for as derivatives. The Derivatives Implementation Group ("DIG") of the Financial Accounting Standards Board is currently discussing the accounting treatment under SFAS No. 133 for certain of these contracts, which contain features that may be viewed as options. The DIG may conclude that such contracts are required to be accounted for as derivatives.

The majority of the Company's derivative instruments qualify as fair value or cash flow hedges, as defined by SFAS No. 133. As required by SFAS No. 133 for these instruments the Company has documented the effectiveness of the hedges by performing tests to demonstrate the high correlation between the derivative instruments and the underlying hedged commitments or transactions. These effectiveness tests will be updated quarterly. The Company intends to exclude the change in the time value of option contracts from its assessment of hedge effectiveness. Although the majority of the Company's derivative instruments qualify as fair value or cash flow hedges, adoption of SFAS No. 133 will increase volatility in reported earnings.

Adoption of SFAS No. 133 resulted in the recognition of $81.7 million of derivative assets and $223.3 million of derivative liabilities on the Company's balance sheet as of January 1, 2001. The derivative assets consist primarily of commodity hedges and foreign currency swaps, but also include some interest rate swaps. The derivative liabilities consist primarily of interest rate swaps and commodity hedges. Additionally, adoption of SFAS No. 133 resulted in the recognition of a charge of approximately $1 million, net of deferred income tax effects, which will be included in the first quarter

2001 income statement as a cumulative effect of a change in accounting principle. Adoption of the standard also resulted in a reduction of other comprehensive income in stockholders' equity of approximately $97 million, net of deferred income tax effects, which will be included in the first quarter 2001 balance sheet as a cumulative effect of a change in accounting principle. Approximately $19 million of other comprehensive income related to derivative instruments as of January 1, 2001, is expected to be recognized as income in earnings over the next twelve months. A portion of this amount is expected to be offset by the effects of hedge accounting that will be recognized in 2001.

The Company adopted Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements", during the first quarter of 2000. The adoption of this standard did not impact its financial condition or results of operations.

The Company adopted FASB Interpretation No. 44, "Accounting for Certain Transactions Involving Stock Compensation", during the second quarter of 2000. The adoption of this standard did not impact its financial condition or results of operations.

The following table summarizes the unaudited quarterly statements of operations (in millions, except per share amounts):

On March 27, 2001, the Company completed its acquisition of IPALCO Enterprises, Inc. (see Note 2)

Through February 22, 2001, the Company issued approximately $723 million of senior debt in U.S. dollars and U.K. pounds sterling maturing in 2011. Such debt consisted of $600 million of 8.875% Senior Notes and £85 million of 8.375% Senior Notes.

On February 12, 2001, a subsidiary of the Company entered into an agreement to acquire Thermo Ecotek (see Note 2)

ITEM 9—CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

To the Stockholders and the Board of Directors of
C.A. La Electricidad de Caracas and Corporation EDC, C.A.:

We have audited the accompanying combined balance sheet of C.A. La Electricidad de Caracas and Corporation EDC, C.A. (Venezuelan corporations) and their Subsidiaries, translated into U.S. dollars, as of December 31, 2000, and the related translated combined statements of income, stockholders' equity and cash flows for the period from June 1 through December 31, 2000. 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 audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit 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 we evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

These translated financial statements have been prepared for use in the preparation of the consolidated financial statements of The AES Corporation and, accordingly, they translate the assets, liabilities, stockholders' investment and revenues and expenses of C.A. La Electricidad de Caracas and Corporation EDC, C.A. and their Subsidiaries for that purpose. The translated financial statements have not been prepared for use by other parties and may not be appropriate for such use.

In our opinion, the translated financial statements referred to above present fairly, in all material respects and for the purpose described in the preceding paragraph, the financial position of C.A. La Electricidad de Caracas and Corporation EDC, C.A. and their Subsidiaries as of December 31, 2000, and the results of their operations and their cash flows for the period from June 1 through December 31, 2000 in conformity with accounting principles generally accepted in the United States.

See the information with respect to the ages of the Registrant's directors in the table and the information contained under the caption "Election of Directors" on pages 1 through 5, inclusive, of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 19, 2001, which information is incorporated herein by reference. See also the information with respect to executive officers of the Registrant under the caption entitled "Executive Officers and Significant Employees of the Registrant" in Item 1 of Part I hereof, which information is incorporated herein by reference.

See the information contained under the captions "Compensation of Executive Officers" and "Compensation of Directors" on pages 6 and 8 through 15, inclusive, of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 19, 2001, which is incorporated herein by reference.

See the information contained under the caption "Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers" contained on page 4 of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 19, 2001 filed by the Company with the Securities and Exchange Commission on March 22, 2001, which information is incorporated herein by reference.

See the information contained under the caption "Security Ownership of Certain Beneficial Owners, Directors, and Executive Officers" contained on page 4 of the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 19, 2001, which information is incorporated herein by reference.

See the information for Mr. Thomas I. Unterberg, a director of the Registrant, and Mr. Phillip Lader, a candidate for election as director, contained under the caption "Election of Directors" contained on pages 2 and 3 the Proxy Statement for the Annual Meeting of Stockholders of the Registrant to be held on April 19, 2001 filed by the Company with the Securities and Exchange Commission on March 22, 2001, which information is incorporated herein by reference.

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

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

THE AES CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

Schedule I-Condensed Financial Information of Registrant		S-2
Schedule II-Valuation and Qualifying Accounts		S-7

Schedules other than those listed above are omitted as the information is either not applicable, not required, or has been furnished in the financial statements or notes thereto included in Item 8 hereof.

THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF UNCONSOLIDATED BALANCE SHEETS (IN MILLIONS)

THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF UNCONSOLIDATED OPERATIONS (IN MILLIONS)

THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF UNCONSOLIDATED CASH FLOWS (IN MILLIONS)

Accounting for Subsidiaries and Affiliates—The AES Corporation ("the Company") has accounted for the earnings of its subsidiaries on the equity method in the unconsolidated condensed financial information.

Revenues—Construction management fees earned by the parent from its consolidated subsidiaries are eliminated.

Income Taxes—The unconsolidated income tax expense or benefit computed for the Company in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, reflects the tax assets and liabilities of the Company on a stand alone basis and the effect of filing a consolidated U.S. income tax return with certain other affiliated companies.

Accounts and Notes Receivable from Subsidiaries—Such amounts have been shown in current or long-term assets based on terms in agreements with subsidiaries, but payment is dependent upon meeting conditions precedent in the subsidiary loan agreements.

Cash dividends received from consolidated subsidiaries and from affiliates accounted for by the equity method were as follows (in millions):

	December 31,
	2000		1999		1998		1997		1996
Total assets	$	31,033	$	20,880	$	10,781	$	8,909	$	3,622
Non-recourse debt (long-term)		12,241		8,651		3,597		3,489		1,558
Recourse debt (long-term)		3,458		2,167		1,644		1,096		450
Mandatorily redeemable preferred stock of subsidiary		22		22		—		—		—
Company-obligated convertible mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of AES		1,228		1,318		550		550		—
Stockholders' equity		4,811		2,637		1,794		1,481		721

				2000			1999
				(Amounts in Millions, Except Shares and Par Value)
ASSETS
Current Assets:
	Cash and cash equivalents			$	881		$	669
	Short-term investments				1,297			164
	Accounts receivable — net of reserves of $201 – 2000; $104 – 1999				1,498			934
	Inventory				499			307
	Receivable from affiliates				27			2
	Deferred income taxes				165			184
	Prepaid expenses and other current assets				1,206			327

		Total current assets			5,573			2,587

Property, Plant and Equipment:
	Land				617			216
	Electric generation and distribution assets				15,743			12,552
	Accumulated depreciation and amortization				(1,304	)		(763	)
		Construction in progress			2,790			1,442

		Property, plant, and equipment — net			17,846			13,447

Other Assets:
	Deferred financing costs — net				375			236
	Project development costs				114			53
	Investments in and advances to affiliates				3,122			1,575
	Debt service reserves and other deposits				517			328
	Excess of cost over net assets acquired — net				2,307			1,851
	Other assets				1,179			803

		Total other assets			7,614			4,846

			Total	$	31,033		$	20,880

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
	Accounts payable			$	708		$	381
	Accrued interest				404			218
	Accrued and other liabilities				1,305			755
	Recourse debt — current portion				—			335
	Non-recourse debt — current portion				2,465			881

		Total current liabilities			4,882			2,570
Long-Term Liabilities:
	Non-recourse debt				12,241			8,651
	Recourse debt				3,458			2,167
	Deferred income taxes				1,632			1,787
	Other long-term liabilities				1,399			602

		Total long-term liabilities			18,730			13,207

Minority Interest					1,382			1,148
Commitments and Contingencies (Note 7)					—			—
Company-Obligated Convertible Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of AES					1,228			1,318
Stockholders' Equity:
	Preferred stock, no par value — 50 million shares authorized; none issued				—			—
	Common stock, $.01 par value — 1,200 million and 1,000 million shares authorized for 2000 and 1999, respectively; shares issued and outstanding, 2000 – 481 million; 1999 – 414 million				5			4
	Additional paid-in capital				4,722			2,615
	Retained earnings				1,761			1,120
	Accumulated other comprehensive loss				(1,677	)		(1,102	)

		Total stockholders' equity			4,811			2,637

			Total	$	31,033		$	20,880

			2000			1999			1998
			(Amounts in Millions)
Operating Activities:
Net income			$	641		$	228		$	311
Adjustments to net income:
Depreciation and amortization				582			278			196
Provision for deferred taxes				45			(1	)		69
Minority interest earnings				119			64			94
Undistributed earnings of affiliates				(320	)		30			(58	)
Other				(38	)		40			(73	)
Changes in operating assets and liabilities:
	Increase in accounts receivable			(255	)		(142	)		(10	)
	Increase in inventory			(84	)		(32	)		(8	)
	Increase decrease in other current assets			(155	)		(95	)		14
	Increase in other assets			(144	)		(45	)		(9	)
	Increase (decrease) in accounts payable			229			(49	)		(11	)
	Increase in accrued interest			127			86			45
	Decrease in other current liabilities			(288	)		(165	)		(32	)

		Net cash provided by operating activities		459			197			528

Investing Activities:
	Property additions			(2,150	)		(834	)		(517	)
	Acquisitions—net of cash acquired			(1,818	)		(5,713	)		(1,623	)
	Proceeds from the sales of assets			72			650			301
	Sale of short-term investments			81			49			98
	Purchase of short-term investments			(96	)		(98	)		(2	)
	Affiliate advances and equity investments			(515	)		(193	)		(69	)
	Increase in short-term investments			(1,110	)		(80	)		(4	)
	Project development costs			(96	)		(84	)		(57	)
	Debt service reserves and other assets			(106	)		(85	)		31

		Net cash used in investing activities		(5,738	)		(6,388	)		(1,842	)

Financing Activities:
	(Repayments) borrowings under the revolver, net			(195	)		102			206
	Issuance of non-recourse debt and other coupon bearing securities			7,051			6,254			1,843
	Repayments of non-recourse debt and other coupon bearing securities			(2,450	)		(1,161	)		(668	)
	Payments for deferred financing costs			(136	)		(119	)		(47	)
	Repayments of other long-term liabilities			(174	)		(44	)		(71	)
	(Distributions to) contributions by minority interests, net			(54	)		32			40
	Proceeds from sale of common stock, net			1,449			1,305			200

		Net cash provided by financing activities		5,491			6,369			1,503

Increase in Cash and Cash Equivalents				212			178			189
Cash and Cash Equivalents, Beginning of year				669			491			302

Cash and Cash Equivalents, End of year			$	881		$	669		$	491

Supplemental Disclosures:
	Cash payments for interest—net of amounts capitalized		$	1,137		$	548		$	415
	Cash payments for income taxes—net of refunds			72			45			24
Schedule of Noncash Investing and Financing Activities:
	Common stock issued for acquisitions			67			48			—
	Liabilities assumed in purchase transactions			2,098			3,570			139
	Conversion of AES Trust I and AES Trust II (see Note 8)			550			—			—

					December 31,
		Interest Rate(1)		Final Maturity	December 31,
		Interest Rate(1)		Final Maturity	2000			1999
Variable Rate:
	Bank loans	9.70	%	2022	$	7,037		$	5,081
	Commercial paper	8.89		2008		637			561
	Debt to (or guaranteed by) multilateral or export credit agencies	7.37		2018		649			564
	Other	16.92		2022		664			673
Fixed Rate:
	Bank loans	5.00		2025		2,003			1,176
	Notes and bonds	9.81		2029		3,539			1,304
	Debt to (or guaranteed by) multilateral or export credit agencies	5.76		2007		164			128
	Other	8.92		2003		13			45

Subtotal						14,706			9,532
	Less: Current maturities					(2,465	)		(881	)

Total					$	12,241		$	8,651

	For The Years Ended December 31,
	2000				1999				1998
	Shares		Weighted- Average Exercise Price		Shares		Weighted- Average Exercise Price		Shares		Weighted- Average Exercise Price
Outstanding—beginning of year	15,609		$	9.18	15,852		$	7.05	17,792		$	6.65
Exercised during the year	(3,602	)		6.01	(2,606	)		5.48	(2,086	)		4.30
Forfeited during the year	(127	)		30.62	(14	)		21.83	(20	)		16.00
Granted during the year	3,134			37.34	2,377			19.38	166			17.18

Outstanding—end of year	15,014		$	15.65	15,609		$	9.18	15,852		$	7.05

Eligible for exercise—end of year	10,893		$	9.29	13,012		$	7.53	13,710		$	6.27

Asia and the Pacific
Cili Misty Mountain	Hydro	1994	26	China	51
Yangchun Sun Spring	Oil	1995	15	China	25
Wuhu Grassy Lake	Coal	1996	250	China	25
Ekibastuz	Coal	1996	4,000	Kazakhstan	100
Chengdu Lotus City	Gas	1997	48	China	35
Altai Power (6 plants)	Coal/Hydro	1997	3,774	Kazakhstan	100
Hefei Prosperity Lake	Oil	1997	115	China	70
Jiaozuo Aluminum Power	Coal	1997	250	China	70
Lal Pir	Oil	1997	351	Pakistan	90
Pak Gen	Oil	1998	344	Pakistan	90
Aixi Heart River	Coal	1998	50	China	70
OPGC	Thermal	1998	420	India	49
Mt. Stuart	Kerosene	1999	288	Australia	100
Yarra	Gas	1999	510	Victoria	100
Jeeralong	Gas	1999	449	Australia	100
Gardabani	Gas/Oil	2000	600	Georgia	100
Kharmi I & II	Hydro	2000	223	Georgia	100
Europe
Kilroot	Coal/Oil	1992	520	United Kingdom	98
Belfast West	Coal	1992	120	United Kingdom	98
Medway	Gas	1995	688	United Kingdom	25
Borsod	Coal	1996	171	Hungary	100
Tisza II	Oil/Gas	1996	860	Hungary	100
Tiszapalkonya	Coal	1996	250	Hungary	100
Indian Queens	Oil	1997	140	United Kingdom	100
Elsta	Gas	1998	405	Netherlands	50
Barry	Gas	1998	230	United Kingdom	100
Drax	Coal	1999	4,065	United Kingdom	100

Totals			42,133
Under Construction
Yangcheng Sun City	Coal	2001	2,100	China	25
Parana	Gas	2001	845	Argentina	67
Fifoots Point	Coal	2001	360	United Kingdom	100
Haripur	Gas	2001	360	Bangladesh	100
Meghnaghat	Gas	2001	450	Bangladesh	100
Medina Valley	Gas	2001	47	Illinois, U.S.	100
Andres	Gas	2002	310	Dominican Republic	100
Ironwood	Gas	2002	705	Pennsylvania, U.S.	100
Caracoles	Hydro	2002	123	Argentina	100
Puerto Rico	Coal	2002	454	Puerto Rico, U.S.	100
Kelanitissa	Diesel	2002	165	Sri Lanka	100
Red Oak	Gas	2002	832	New Jersey, U.S.	100
Granite Ridge	Gas	2002	720	New Hampshire, U.S.	100
Esti	Hydro	2003	120	Panama	49

Totals			7,591

		2000			1999			1998
		(Amounts in Millions, Except Per Share Amounts)

Revenues		$	6,691		$	3,253		$	2,398
Cost of Sales			(4,991	)		(2,257	)		(1,609	)
Selling, General and Administrative Expenses			(85	)		(71	)		(56	)
Interest Expense			(1,299	)		(641	)		(485	)
Interest and Other Income			245			86			66
Gain on Contract Buyout			—			91			—
Impairment Loss			—			(62	)		—
Environmental Fine			(17	)		—			—
Equity in Pre-tax Earnings of Affiliates			475			21			232

Income Before Income Taxes, Minority Interest, and Extraordinary Items			1,019			420			546
Income Taxes			252			111			145
Minority Interest			119			64			94

Income Before Extraordinary Items			648			245			307
Extraordinary items — (loss) gain on early extinguishment of debt — net of applicable income tax			(7	)		(17	)		4

Net Income		$	641		$	228		$	311

Basic Earnings Per Share:
	Before extraordinary items	$	1.47		$	0.64		$	0.87
	Extraordinary items		(0.02	)		(0.04	)		0.01

Basic Earnings Per Share		$	1.45		$	0.60		$	0.88

Diluted Earnings Per Share:
	Before extraordinary items	$	1.42		$	0.62		$	0.84
	Extraordinary items		(0.02	)		(0.04	)		0.01

Diluted Earnings Per Share		$	1.40		$	0.58		$	0.85

	Common Stock
	Common Stock			Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Loss			Treasury Stock			Comprehensive Income (Loss)
	Shares	Amount		Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Loss			Treasury Stock			Comprehensive Income (Loss)
	(Amounts In Millions)
Balance at December 31, 1997	175.0	$	2	$	1,030		$	581	$	(131	)	$	(1	)
Adjust for 2-for-1 stock split	175.0		2		(2	)		—		—			—

Adjusted Balance at December 31, 1997	350.0		4		1,028			581		(131	)		(1	)
Net income	—		—		—			311		—			—		$	311
Foreign currency translation adjustment	—		—		—			—		(212	)		—			(212	)

Comprehensive income															$	99

Issuance of common stock through public offerings	8.6		—		184			—		—			—
Issuance of common stock under benefit plans and exercise of stock options and warrants	2.2		—		16			—		—			1
Tax benefit associated with the exercise of options	—		—		13			—		—			—

Balance at December 31, 1998	360.8		4		1,241			892		(343	)		—

Net income	—		—		—			228		—			—		$	228
Foreign currency translation adjustment	—		—		—			—		(759	)		—			(759	)

Comprehensive loss															$	(531	)

Issuance of common stock through public offerings	48.0		—		1,280			—		—			—
Issuance of common stock pursuant to acquisitions	1.8		—		48			—		—			—
Issuance of common stock under benefit plans and exercise of stock options and warrants	3.0		—		25			—		—			—
Tax benefit associated with the exercise of options	—		—		21			—		—			—

Balance at December 31, 1999	413.6		4		2,615			1,120		(1,102	)		—

Net income	—		—		—			641		—			—		$	641
Foreign currency translation adjustment	—		—		—			—		(575	)		—			(575	)

Comprehensive income															$	66

Issuance of common stock through public offerings and Tecon conversions	59.2		1		1,946			—		—			—
Issuance of common stock pursuant to acquisitions	1.3		—		67			—		—			—
Issuance of common stock under benefit plans and exercise of stock options and warrants	6.4		—		46			—		—			—
Tax benefit associated with the exercise of options	—		—		48			—		—			—

Balance at December 31, 2000	480.5	$	5	$	4,722		$	1,761	$	(1,677	)	$	—

	Interest Rate	Final Maturity	First Call Date	2000			1999
Corporate revolving bank loan	8.70%	2003	2000	$	140		$	335
Senior notes	8.75%	2002	—		300			—
Senior notes	8.00%	2008	2000		200			200
Senior notes	9.50%	2009	—		750			750
Senior notes	9.38%	2010	—		850			—
Senior subordinated notes	10.25%	2006	2001		250			250
Senior subordinated notes	8.38%	2007	2002		325			325
Senior subordinated notes	8.50%	2007	2002		375			375
Senior subordinated debentures	8.88%	2027	2004		125			125
Convertible junior subordinated notes	4.50%	2005	2001		150			150
Unamortized discounts					(7	)		(8	)

Subtotal					3,458			2,502
Less: Current maturities					—			(335	)

Total				$	3,458		$	2,167

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Total Outstanding	Weighted- Average Remaining Life (In Years)	Weighted- Average Exercise Price		Total Exercisable	Weighted- Average Exercise Price
$ 0.78 – $ 3.24	34	.1	$	1.61	34	$	1.61
$ 3.25 – $ 9.88	6,482	3.9		5.12	6,482		5.12
$ 9.89 – $14.40	1,977	5.5		11.39	1,973		11.40
$14.41 – $22.85	3,144	7.5		17.90	2,211		18.21
$22.86 – $58.00	3,368	9.0		36.34	193		26.99
$58.01 – $80.00	9	9.7		62.16	—		—

Total	15,014	6.0	$	15.65	10,893	$	9.29

	December 31, 2000						December 31, 1999						December 31, 1998
	Income		Shares	$ Per Share			Income		Shares	$ Per Share			Income		Shares	$ Per Share
Basic EPS
Income before extraordinary items	$	648	442.0	$	1.47		$	245	382.9	$	0.64		$	307	354.9	$	0.87
Effect of Dilutive Securities:
Stock options and warrants		—	9.5		(0.03	)		—	9.1		(0.02	)		—	8.6		(0.02	)
Stock units allocated to deferred compensation plans		—	0.5		—			—	0.5		—			—	0.5		—
Tecons and other convertible debt, net of tax		22	21.1		(0.02	)		—	—		—			9	13.9		(0.01	)

Diluted Earnings per Share	$	670	473.1	$	1.42		$	245	392.5	$	0.62		$	316	377.9	$	0.84

		December 31,
		2000			1999
Differences between book and tax basis of property and total deferred tax liability		$	2,265		$	2,205

Operating loss carryforwards			(328	)		(180	)
Bad debt and other book provisions			(104	)		(168	)
Retirement costs			(21	)		(11	)
Tax credit carryforwards			(162	)		(96	)
Other deductible temporary differences			(302	)		(189	)

	Total gross deferred tax asset		(917	)		(644	)
Less: Valuation allowance			119			42

Total net deferred tax asset			(798	)		(602	)

Net deferred tax liability		$	1,467		$	1,603

	Revenues(1)		Depreciation and Amortization		Gross Margin		Pre-Tax Equity in Earnings		Total Assets		Investment in and Advances to Affiliates		Property Additions
Year Ended December 31, 2000
Generation	$	3,546	$	329	$	1,350	$	49	$	17,627	$	584	$	1,909
Distribution		3,145		252		350		426		12,195		2,508		241
Corporate		—		1		—		—		1,211		30		—

Total	$	6,691	$	582	$	1,700	$	475	$	31,033	$	3,122	$	2,150

	Revenues(1)		Depreciation and Amortization		Gross Margin		Pre-Tax Equity in Earnings			Total Assets		Investment in and Advances to Affiliates		Property Additions
Year Ended December 31, 1999
Generation	$	1,970	$	180	$	793	$	52		$	14,250	$	524	$	688
Distribution		1,283		97		203		(31	)		6,351		1,051		146
Corporate		—		1		—		—			279		—		—

Total	$	3,253	$	278	$	996	$	21		$	20,880	$	1,575	$	834

	Revenues(1)		Depreciation and Amortization		Gross Margin		Pre-Tax Equity in Earnings		Total Assets		Investment in and Advances to Affiliates		Property Additions
Year Ended December 31, 1998
Generation	$	1,413	$	126	$	566	$	33	$	5,682	$	495	$	369
Distribution		985		70		223		199		4,687		1,438		148
Corporate		—		—		—		—		412		—		—

Total	$	2,398	$	196	$	789	$	232	$	10,781	$	1,933	$	517

2001	$	2,465
2002		2,824
2003		1,563
2004		819
2005		890
Thereafter		9,603

Total	$	18,164

		U.S.		Argentina		Brazil		Hungary		Pakistan		United Kingdom		Other(1)		Total Non-U.S.		Total
Revenues:
	2000	$	2,506	$	482	$	699	$	177	$	232	$	1,110	$	1,485	$	4,185	$	6,691
	1999		1,192		452		376		212		206		207		608		2,061		3,253
	1998		655		423		478		227		213		40		362		1,743		2,398
Long Lived Assets:
	2000	$	5,346	$	1,624	$	2,359	$	91	$	428	$	4,483	$	4,674	$	13,659	$	19,005
	1999		4,221		1,061		2,588		121		492		4,600		1,375		10,237		14,458
	1998		2,329		1,017		848		154		505		224		756		3,504		5,833

	December 31, 2000						December 31, 1999
	Carrying Amount			Fair Value			Carrying Amount		Fair Value
Non-recourse debt	$	14,706		$	14,924		$	9,532	$	9,499
Recourse debt		3,458			3,343			2,502		2,495
Tecons and Rhinos		1,228			1,624			1,318		1,770
Interest rate swaps		(2	)		(138	)		—		(23	)
Interest rate caps and floors, net		(2	)		(7	)		—		13
Foreign currency forwards and swaps, net		10			14			—		—
Preferred stock with mandatory redemption		22			20			22		20
Energy Derivatives, net		25			(2	)		4		4

		Quarter Ended 2000
		Mar 31			Jun 30		Sep 30		Dec 31
Revenues		$	1,476		$	1,538	$	1,761	$	1,916
Gross margin			419			335		453		493
Income before extraordinary items			181			111		134		221
Extraordinary items, net of tax benefit (1)			(7	)		—		—		—
Net income (1)			174			111		134		221
Basic earnings per share:
	Before extraordinary items	$	0.44		$	0.26	$	0.29	$	0.48
	Extraordinary items		(0.02	)		—		—		—

Basic earnings per share		$	0.42		$	0.26	$	0.29	$	0.48

Diluted earnings per share:
	Before extraordinary items	$	0.42		$	0.25	$	0.29	$	0.46
	Extraordinary items		(0.02	)		—		—		—

Diluted earnings per share		$	0.40		$	0.25	$	0.29	$	0.46

		THE AES CORPORATION (Company)
		By:		Name: Dennis W. Bakke Title: President

Name	Title	Date

* (Roger W. Sant)	Chairman of the Board	March 27, 2000
* (Dennis W. Bakke)	President, Chief Executive Officer (principal executive officer) and Director	March 27, 2000
* (Hazel R. O'Leary)	Director	March 27, 2000
* (Dr. Alice F. Emerson)	Director	March 27, 2000
* (Robert F. Hemphill, Jr.)	Director	March 27, 2000
(Frank Jungers)	Director	March 27, 2000
* (John H. McArthur)	Director	March 27, 2000

* (Thomas I. Unterberg)	Director	March 27, 2000
* (Robert H. Waterman, Jr.)	Director	March 27, 2000
* (Barry J. Sharp)	Executive Vice President and Chief Financial Officer (principal financial and accounting officer)	March 27, 2000

				December 31
			First Call Date	December 31
			First Call Date	2000			1999
Revolving Bank Loan:
	Variable rate Corporate revolving bank loan due 2003		2000	$	140		$	335
		Less: Current maturities			—			(335	)

	Total				140			—
Senior Notes Payable:
	8.75% Senior notes due 2002		2002		300
	8.00% Senior notes due 2008		2000		200			200
	9.50% Senior notes due 2009		—		750			750
	9.38% Senior notes due 2010		—		850

Unamortized discount					(1	)		(2	)

Total					2,099			948

Senior Subordinated Notes and Debentures Payable:
10.25% Senior subordinated notes due 2006			2001		250			250
8.38% Senior subordinated notes due 2007			2002		325			325
8.50% Senior subordinated notes due 2007			2002		375			375
8.88% Senior subordinated debentures due 2027			2004		125			125
Unamortized discounts					(6	)		(6	)

Total					1,069			1,069

Junior Subordinated Notes and Debentures Payable:
4.50% Convertible junior subordinated notes due 2005			2001		150			150
6.00% Convertible junior subordinated debentures due 2008			2003		460			—
5.38% Convertible junior subordinated debentures due 2027			2000		—			250
5.50% Convertible junior subordinated debentures due 2012			2000		—			300
6.75% Convertible junior subordinated debentures due 2029			2002		518			518
Variable rate convertible junior subordinated debentures due 2007			1999		258			258

Total					1,386			1,476

		Additions		Deductions
	Balance at Beginning of Period	Charged to Costs and Expenses	Acquisitions	Translation Adjustment		Amounts Written Off		Balance at End of Period
Allowance for accounts receivables
Year ended December 31, 1998	37	22	—	—		—		59
Year ended December 31, 1999	59	8	68	(21	)	(10	)	104
Year ended December 31, 2000	104	72	47	(1	)	(21	)	201